10-Q

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 MARCH 31, 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 Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common stock, par value $0.01 per share	VST	New York Stock Exchange

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 May 2, 2025
Common stock, par value $0.01 per share	339,331,954

TABLE OF CONTENTS

				PAGE
Glossary of Terms and Abbreviations				i
Forward-Looking Statements				v
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
		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		5
		Notes to Condensed Consolidated Financial Statements		6
			1. Business, Significant Accounting Policies, Significant Events, and Recent Developments	6
			2. Acquisitions	8
			3. Revenue	11
			4. Government Assistance	13
			5. Income Taxes	13
			6. Property, Plant, and Equipment	14
			7. Goodwill and Identifiable Intangible Assets and Liabilities	15
			8. Collateral Financing Agreement with Affiliate	17
			9. Debt, Credit Facilities, and Financings	17
			10. Derivatives	24
			11. Fair Value Measurements	28
			12. Asset Retirement Obligations	32
			13. Commitments and Contingencies	33
			14. Equity	40
			15. Earnings Per Share	41
			16. Segment Information	41
			17. Supplementary Financial Information	43
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations			46
		Significant Activities and Events, and Items Influencing Future Performance		46
		Critical Accounting Policies and Estimates		49
		Results of Operations		49
		Financial Condition		55
		Commitments and Contingencies		60
		Changes in Accounting Standards		60
Item 3.	Quantitative and Qualitative Disclosures About Market Risk			60
Item 4.	Controls and Procedures			62
PART II.	OTHER INFORMATION			63
Item 1.		Legal Proceedings		63
Item 1A.		Risk Factors		63
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds		63
Item 3.		Defaults Upon Senior Securities		63
Item 4.		Mine Safety Disclosures		64
Item 5.		Other Information		64
Item 6.		Exhibits		64
SIGNATURE				67

i

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:
Ambit	Ambit Holdings, LLC, and/or its subsidiaries (d/b/a Ambit), depending on context
BCOP	BCOP Borrower LLC, a subsidiary of Vistra Zero
Dynegy	Dynegy 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 Harbor	Energy 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
Luminant	subsidiaries of Vistra engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management
Parent	Vistra 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
Vistra	Vistra Corp., and/or its subsidiaries, depending on context
Vistra Intermediate	Vistra 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 Vision	Vistra 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:
CAISO	The California Independent System Operator
ERCOT	Electric Reliability Council of Texas, Inc.
ISO-NE	ISO New England Inc.
MISO	Midcontinent Independent System Operator, Inc.
NYISO	New York Independent System Operator, Inc.
PJM	PJM Interconnection, LLC
Authoritative Organizations:
EPA	U.S. Environmental Protection Agency
FERC	U.S. Federal Energy Regulatory Commission
IEPA	Illinois Environmental Protection Agency
IPCB	Illinois Pollution Control Board
IRS	U.S. Internal Revenue Service

ii

MSHA	U.S. Mine Safety and Health Administration
NRC	U.S. Nuclear Regulatory Commission
PUCT	Public Utility Commission of Texas
RCT	Railroad 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
SEC	U.S. Securities and Exchange Commission
TCEQ	Texas Commission on Environmental Quality
Rules and Regulations:
Exchange Act	Securities Exchange Act of 1934, as amended
IRA	Inflation Reduction Act of 2022
Securities Act	Securities 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
ARO	asset 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
CCGT	combined cycle natural gas turbine
CCR	coal combustion residuals
CME	Chicago Mercantile Exchange
CO2	carbon dioxide
EBITDA	earnings (net income) before interest expense, income taxes, depreciation and amortization
ERP	enterprise resource program
ESS	energy storage system
GAAP	generally accepted accounting principles
GHG	greenhouse gas
GWh	gigawatt-hours
Heat Rate	Heat Rate is a measure of the efficiency of converting a fuel source to electricity
ISO	independent system operator
ITC	investment tax credit
load	demand for electricity
LTSA	long-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
MMBtu	million British thermal units
MW	megawatts
MWh	megawatt-hours
NOX	nitrogen oxide
NYMEX	the New York Mercantile Exchange, a commodity derivatives exchange
PTC	production tax credit
REP	retail electric provider
RTO	regional transmission organization
S&P	Standard & Poor's Ratings (a credit rating agency)
Series A Preferred Stock	Vistra'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

iii

Series B Preferred Stock	Vistra'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 Stock	Vistra'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
SOFR	Secured 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

iv

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.

v

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 March 31,
	2025		2024
Operating revenues	$	3,933	$	3,054
Fuel, purchased power costs, and delivery fees	(2,447)		(1,716)
Operating costs	(693)		(498)
Depreciation and amortization	(522)		(403)
Selling, general, and administrative expenses	(391)		(351)
Operating income (loss)	(120)		86
Other income (deductions), net	(5)		87
Interest expense and related charges	(319)		(170)
Impacts of Tax Receivable Agreement	—		(5)
Net loss before income taxes	(444)		(2)
Income tax benefit	176		20
Net income (loss)	$	(268)	$	18
Net income attributable to noncontrolling interest	—		(53)
Net loss attributable to Vistra	$	(268)	$	(35)
Cumulative dividends attributable to preferred stock	(49)		(49)
Net loss attributable to Vistra common stock	$	(317)	$	(84)
Weighted average shares of common stock outstanding:
Basic	339,799,989		348,966,197
Diluted	339,799,989		348,966,197
Net loss per weighted average share of common stock outstanding:
Basic	$	(0.93)	$	(0.24)
Diluted	$	(0.93)	$	(0.24)

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited) (Millions of Dollars)

	Three Months Ended March 31,
	2025		2024
Net income (loss)	$	(268)	$	18
Other comprehensive income, net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax expense of $— and $—)	—		—
Total other comprehensive income	—		—
Comprehensive income (loss)	$	(268)	$	18
Comprehensive income attributable to noncontrolling interest	—		(53)
Comprehensive loss attributable to Vistra	$	(268)	$	(35)

See Notes to Condensed Consolidated Financial Statements

1

VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars, Except Share Data)
	March 31, 2025		December 31, 2024
ASSETS
Current assets:
Cash and cash equivalents	$	561	$	1,188
Restricted cash	29		28
Trade accounts receivable — net	1,924		1,982
Inventories	960		970
Commodity and other derivative contractual assets	3,335		2,587
Margin deposits related to commodity contracts	579		406
Margin deposits posted under affiliate financing agreement	446		435
Prepaid expense and other current assets	596		523
Total current assets	8,430		8,119
Restricted cash	6		6
Investments	4,476		4,512
Property, plant and equipment — net	17,716		18,173
Goodwill	2,810		2,807
Identifiable intangible assets — net	2,321		2,213
Commodity and other derivative contractual assets	769		740
Accumulated deferred income taxes	9		9
Other noncurrent assets	1,691		1,191
Total assets	$	38,228	$	37,770
LIABILITIES AND EQUITY
Current liabilities:
Accounts receivable financing	$	1,082	$	750
Long-term debt due currently	882		880
Forward repurchase obligation due currently	723		703
Trade accounts payable	1,328		1,510
Commodity and other derivative contractual liabilities	4,646		3,351
Margin deposits related to commodity contracts	5		49
Accrued taxes other than income	101		209
Accrued interest	244		193
Asset retirement obligations	136		142
Other current liabilities	606		645
Total current liabilities	9,753		8,432
Margin deposits financing with affiliate	446		435
Long-term debt, less amounts due currently	15,423		15,418
Forward repurchase obligation, less amounts due currently	632		632
Commodity and other derivative contractual liabilities	1,459		1,367
Accumulated deferred income taxes	512		697
Asset retirement obligations	3,937		3,936
Other noncurrent liabilities and deferred credits	1,228		1,270
Total liabilities	33,390		32,187

See Notes to Condensed Consolidated Financial Statements

2

VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars, Except Share Data)
	March 31, 2025		December 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 March 31, 2025 and December 31, 2024, respectively)	2,476		2,476
Common stock (par value $0.01 per share, 1,800,000,000 shares authorized, 340,048,488 and 339,754,307 shares outstanding at March 31, 2025 and December 31, 2024, respectively)	5		5
Treasury stock, at cost (211,435,313 and 208,998,299 shares at March 31, 2025 and December 31, 2024, respectively)	(6,248)		(5,912)
Additional paid-in-capital	9,407		9,435
Accumulated deficit	(835)		(454)
Accumulated other comprehensive income	20		20
Stockholders' equity	4,825		5,570
Noncontrolling interest in subsidiary	13		13
Total equity	4,838		5,583
Total liabilities and equity	$	38,228	$	37,770

See Notes to Condensed Consolidated Financial Statements

3

VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars)
	Three Months Ended March 31,
	2025		2024
Cash flows — operating activities:
Net income (loss)	$	(268)	$	18
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation and amortization	772		555
Deferred income tax benefit, net	(185)		(23)
Unrealized net loss from mark-to-market valuations of commodities	567		176
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps	48		(47)
Unrealized net (gain) loss from nuclear decommissioning trusts	15		(28)
Asset retirement obligation accretion expense	34		19
Bad debt expense	44		36
Stock-based compensation expense	21		21
Other, net	57		(28)
Changes in operating assets and liabilities:
Margin deposits, net	(217)		128
Accrued interest	51		(3)
Accrued taxes	(109)		(111)
Accrued employee incentive	(177)		(169)
Other operating assets and liabilities	(54)		(232)
Cash provided by operating activities	599		312
Cash flows — investing activities:
Capital expenditures, including nuclear fuel purchases and LTSA prepayments	(768)		(465)
Energy Harbor acquisition (net of cash acquired)	—		(3,070)
Proceeds from sales of nuclear decommissioning trust fund securities	2,107		214
Investments in nuclear decommissioning trust fund securities	(2,112)		(220)
Proceeds from sales of environmental allowances	21		17
Purchases of environmental allowances	(307)		(131)
Proceeds from sale of property, plant and equipment, including nuclear fuel	—		127
Other, net	(2)		—
Cash used in investing activities	(1,061)		(3,528)
Cash flows — financing activities:
Issuances of long-term debt	—		700
Repayments/repurchases of debt	(6)		(756)
Net borrowings (repayments) under accounts receivable financing	332		875
Borrowings under Commodity-Linked Facility	—		500
Stock repurchases	(337)		(291)
Dividends paid to common stockholders	(83)		(77)
Dividends paid to preferred stockholders	(21)		—
Tax withholding on stock based compensation	(50)		(12)
TRA Repurchase and tender offer — return of capital	—		(122)
Other, net	1		(24)
Cash (used in) provided by financing activities	(164)		793
Net change in cash, cash equivalents and restricted cash	(626)		(2,423)
Cash, cash equivalents and restricted cash — beginning balance	1,222		3,539
Cash, cash equivalents and restricted cash — ending balance	$	596	$	1,116

See Notes to Condensed Consolidated Financial Statements

4

VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) (Millions of Dollars)
	Preferred Stock		Common Stock		Treasury Stock		Additional Paid-In Capital		Accumulated Deficit		Accumulated Other Comprehensive Income		Total Stockholders' Equity		Noncontrolling Interest in Subsidiary		Total 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 income (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

VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (CONTINUED) (Unaudited) (Millions of Dollars)
	Preferred Stock		Common Stock		Treasury Stock		Additional Paid-In Capital		Accumulated Deficit		Accumulated Other Comprehensive Income (Loss)		Total Stockholders' Equity		Noncontrolling Interest in Subsidiary		Total Equity
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

____________

(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

5

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.

6

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, but the two 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 at some point later this year. 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 March 31, 2025, the net book value of the Moss Landing 100 facility was approximately $170 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). We have recognized expense of approximately $7 million for costs incurred to respond to the Moss Landing Incident through March 31, 2025. As of March 31, 2025, we accrued approximately $70 million in obligations related to the Moss Landing Incident including approximately $30 million for anticipated air and soil monitoring requirements and $40 million for the expected costs of decommissioning the Moss Landing 300 structure, which includes demolition of the structure, removing and disposing of the batteries, and fulfilling land reclamation obligations (see Note 13). Additional costs incurred 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.

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 costs and expenses incurred, in other noncurrent assets on the condensed consolidated balance sheet.

Recent Developments

BCOP Project-level Credit Facilities

On April 1, 2025, term loans under the BCOP project-level Construction/Term Loan Facility of $75 million and $46 million were funded for the Baldwin and Coffeen projects, respectively, pursuant to the BCOP Credit Agreement. On March 31, 2025, BCOP also entered into interest rate swaps that became effective on April 1, 2025 to hedge approximately $108 million of the floating rate term loans funded under the Construction/Term Loan Facility. See Notes 9 and 10 for additional information.

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2.    ACQUISITIONS

Energy Harbor Business Combination

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

The Energy Harbor Merger was accounted for using the acquisition method in accordance with ASC 805, Business Combinations (ASC 805), which requires identifiable assets acquired and liabilities assumed to be recorded at their estimated fair values on the Merger Date. The combined results of operations are reported in the 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 price	4,596
Fair value of noncontrolling interest in Energy Harbor (b)	811
Acquisition date fair value of Energy Harbor	$	5,407

____________

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

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

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

8

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 recorded since March 1, 2024
	(in millions)
Cash and cash equivalents	$	35	$	5
Trade accounts receivables, inventories, prepaid expenses and other current assets	540		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 assets	62		54
Total identifiable assets acquired	8,847		62
Trade accounts payable and other current liabilities	318		55
Long-term debt, including amounts due currently	413		—
Commodity and other derivative contractual liabilities (d)	179		—
Accumulated deferred income taxes	1,314		(50)
Asset retirement obligations (e)	1,368		—
Identifiable intangible liabilities	55		(18)
Other noncurrent liabilities and deferred credits	20		8
Total identifiable liabilities assumed	3,667		(5)
Identifiable net assets acquired	5,180		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.

9

The following unaudited pro forma financial information for the three months ended March 31, 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 March 31, 2024
	(in millions)
Revenues	$	3,777
Net income	$	69

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 $24 million for the three months ended March 31, 2024, 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 represent conditional redemption obligations that required us to reflect the transaction as redeemable noncontrolling interest within the mezzanine section of the consolidated balance sheet as of September 30, 2024. The UPAs were amended prior to close to accelerate principal payments to Avenue and certain Nuveen noncontrolling interest holders. The transaction closed on December 31, 2024, 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 March 31, 2025
	Retail		Texas		East		West		Asset Closure		Eliminations / Corporate and Other		Consolidated
	(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	1,986	$	—	$	—	$	—	$	—	$	—	$	1,986
Retail energy charge in Northeast/Midwest	1,039		—		—		—		—		—		1,039
Wholesale generation revenue from ISO/RTO	—		78		770		26		—		—		874
Capacity revenue from ISO/RTO (a)	—		—		20		—		—		—		20
Revenue from other wholesale contracts	—		129		130		68		4		—		331
Total revenue from contracts with customers	3,025		207		920		94		4		—		4,250
Other revenues:
Transferable PTC revenues (b)	—		2		—		—		—		—		2
Hedging revenues — realized	274		(27)		(78)		26		—		—		195
Hedging revenues — unrealized	(157)		(143)		(250)		36		1		—		(513)
Intangible amortization and other revenues	—		—		(1)		—		—		—		(1)
Intersegment sales (c)	26		171		789		1		(1)		(986)		—
Total other revenues	143		3		460		63		—		(986)		(317)
Total revenues	$	3,168	$	210	$	1,380	$	157	$	4	$	(986)	$	3,933

____________

(a)Includes $73 million of capacity sold offset by $53 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 solar assets during the period.

(c)The Texas and East segments include $883 million and $271 million, respectively, of intersegment unrealized net losses, and West segment includes $1 million of intersegment net gains from mark-to-market valuations of commodity positions with the Retail segment.

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	Three Months Ended March 31, 2024
	Retail		Texas		East (a)		West		Asset Closure		Eliminations / Corporate and Other		Consolidated
	(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	1,702	$	—	$	—	$	—	$	—	$	—	$	1,702
Retail energy charge in Northeast/Midwest (a)	663		—		—		—		—		—		663
Wholesale generation revenue from ISO/RTO	—		68		333		79		9		—		489
Capacity revenue from ISO/RTO (b)	—		—		19		—		—		—		19
Revenue from other wholesale contracts	—		104		125		57		—		—		286
Total revenue from contracts with customers	2,365		172		477		136		9		—		3,159
Other revenues:
Transferable PTC revenues	—		2		—		—		—		—		2
Hedging revenues — realized	278		(110)		74		3		(4)		—		241
Hedging revenues — unrealized	(155)		(132)		(200)		136		4		—		(347)
Intangible amortization and other revenues	—		—		(1)		—		—		—		(1)
Intersegment sales (c)	6		527		506		1		—		(1,040)		—
Total other revenues	129		287		379		140		—		(1,040)		(105)
Total revenues	$	2,494	$	459	$	856	$	276	$	9	$	(1,040)	$	3,054

____________

(a)Includes revenues associated with March 2024 operations acquired in the Energy Harbor Merger.

(b)Represents net capacity sold in each ISO/RTO. The East segment includes $40 million of capacity sold offset by $21 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 $7 million offset by $2 million of capacity sold within the East segment.

(c)Texas and East segments include $490 million and $291 million, respectively, of intersegment unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

Performance Obligations

As of March 31, 2025, we have future fixed fee performance obligations that are unsatisfied, or partially unsatisfied, relating to capacity auction volumes awarded through capacity auctions held by the ISO/RTO or 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		2026		2027		2028		2029		2030 and Thereafter		Total
	(in millions)
Remaining performance obligations	$	934	$	832	$	292	$	122	$	62	$	548	$	2,790

Trade Accounts Receivable

	March 31, 2025		December 31, 2024
	(in millions)
Wholesale and retail trade accounts receivable	$	1,999	$	2,061
Allowance for credit losses	(75)		(79)
Trade accounts receivable — net	$	1,924	$	1,982
Trade accounts receivable from contracts with customers — net	$	1,494	$	1,514
Other trade accounts receivable — net	430		468
Trade accounts receivable — net	$	1,924	$	1,982

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Gross trade accounts receivable as of March 31, 2025 and December 31, 2024 include unbilled retail revenues of $737 million and $802 million, respectively.

Allowance for Credit Losses on Accounts Receivable

	Three Months Ended March 31,
	2025		2024
	(in millions)
Allowance for credit losses on accounts receivable at beginning of period	$	79	$	61
Increase for bad debt expense	44		36
Decrease for account write-offs	(48)		(36)
Allowance for credit losses on accounts receivable at end of period	$	75	$	61

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, 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 as power prices increase above $25 per MWh, to existing nuclear facilities from 2024 through 2032 subject to an annual inflation adjustment. The Company accounts for transferable ITCs and PTCs we expect to receive by analogy to the grant model within International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance.

Sales of Transferable PTCs

In January 2025, we sold $200 million of transferable nuclear PTCs we recognized from qualifying 2024 nuclear production. Cash consideration from the sale will be received in installments through July 2025, with the initial cash installment received in January 2025.

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) Benefit

The components of our income tax (expense) benefit are as follows:

	Three Months Ended March 31,
	2025			2024
	(in millions)
Net loss before income taxes	$	(444)		$	(2)
Income tax benefit	$	176		$	20
Effective tax rate	39.6		%	1,000.0		%

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.

For the three months ended March 31, 2025, the effective tax rate of 39.6% was higher than the U.S. federal statutory rate of 21% due primarily to state income taxes and permanent differences recorded discretely related to stock-based compensation.

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For the three months ended March 31, 2024, the effective tax rate of 1,000.0% was higher than the U.S. federal statutory rate of 21% due primarily to the level of pre-tax earnings during the period and permanent difference recorded discretely related to stock-based compensation, partially offset by mark-to-market losses.

IRA

In August 2022, the U.S. enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases. We do not expect Vistra to be subject to the CAMT in the 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 relevant extensions or expansions of existing tax credits applicable to projects in our immediate development pipeline into account when forecasting cash taxes. See Note 4 for additional information.

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.

	March 31, 2025		December 31, 2024
	(in millions)
Power generation and structures	$	22,303	$	22,783
Office and other equipment	172		160
Land	603		603
Construction work in progress	1,394		1,060
Finance lease right-of-use assets	186		186
Nuclear fuel	2,032		1,843
Property, plant and equipment — gross	26,690		26,635
Less accumulated depreciation	(8,415)		(8,020)
Less finance lease right-of-use assets accumulated amortization	(35)		(33)
Less accumulated amortization on nuclear fuel	(524)		(409)
Property, plant and equipment — net	$	17,716	$	18,173

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 Equipment	Condensed Consolidated Statements of Operations	Three Months Ended March 31,
		2025		2024
		(in millions)
Power generation and structures and office and other equipment	Depreciation and amortization	$	479	$	365
Finance lease right-of-use assets	Depreciation and amortization	2		2
Nuclear fuel	Fuel, purchased power costs, and delivery fees	111		49
Total property, plant, and equipment expense		$	592	$	416

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Retirement of Generation Facilities

Below are our facilities that are retired or have an announced retirement date. Operating results for generation facilities with defined retirement dates are included in our Asset Closure segment at the beginning of the calendar year the retirement 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.

Facility	Location	ISO/RTO	Fuel Type	Net Capacity (MW)	Expected or Actual Retirement Date (a)	Segment
Baldwin	Baldwin, IL	MISO	Coal	1,185	By the end of 2027	East
Coleto Creek (b)	Goliad, TX	ERCOT	Coal	650	By the end of 2027	Texas
Kincaid	Kincaid, IL	PJM	Coal	1,108	By the end of 2027	East
Miami Fort	North Bend, OH	PJM	Coal	1,020	By the end of 2027	East
Newton	Newton, IL	MISO	Coal	615	By the end of 2027	East
Edwards	Bartonville, IL	MISO	Coal	585	Retired January 1, 2023	Asset Closure
Total				5,163

____________

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

(b)The Company intends to repower Coleto Creek as a gas-fueled facility upon its retirement as a coal-fueled facility.

7.    GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

Goodwill

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

	Retail Segment		Texas Segment
	Retail Reporting Unit (a)		Texas Generation Reporting Unit		Goodwill Pending Allocation		Total 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 March 31, 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:

	March 31, 2025						December 31, 2024
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
	(in millions)
Retail customer relationships	$	2,173	$	1,999	$	174	$	2,173	$	1,977	$	196
Software and other technology-related assets	616		312		304		601		293		308
Retail and wholesale contracts	503		373		130		503		353		150
Long-term service agreements	18		5		13		18		5		13
Other identifiable intangible assets (a)	373		14		359		218		13		205
Total identifiable intangible assets subject to amortization	$	3,683	$	2,703	980		$	3,513	$	2,641	872
Retail trade names (not subject to amortization)					1,341						1,341
Total identifiable intangible assets					$	2,321					$	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 Liability	March 31, 2025		December 31, 2024
	(in millions)
Long-term service agreements	$	104	$	108
Wholesale power and fuel purchase contracts	45		47
Total identifiable intangible liabilities	$	149	$	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/Liabilities	Condensed Consolidated Statements of Operations		Three Months Ended March 31,
			2025		2024
		(in millions)
Retail customer relationships	Depreciation and amortization		$	23	$	22
Software and other technology-related assets	Depreciation and amortization		18		13
Retail and wholesale contracts	Operating revenues/Fuel, purchased power costs, and delivery fees		(2)		1
Other identifiable intangible assets (a)	Fuel, purchased power costs, and delivery fees/Depreciation and amortization		136		103
Total intangible asset expense, net			$	175	$	139

___________

(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.

16

Estimated Amortization of Identifiable Intangible Assets

As of March 31, 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.

Year	Estimated Amortization Expense
	(in millions)
2025	$	237
2026	$	177
2027	$	80
2028	$	59
2029	$	41

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 March 31, 2025 and December 31, 2024, the fair value of Eligible Assets held by counterparties to satisfy current and future margin deposit requirements totaled $446 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:

	March 31, 2025		December 31, 2024
	(in millions)
Long-term debt, including amounts due currently:
Project-level debt	$	1,064	$	1,064
Vistra Operations debt	15,399		15,405
Long -term debt before unamortized premiums, discounts and issuance costs	16,463		16,469
Unamortized premiums, discounts and issuance costs	(158)		(171)
Long-term debt including amounts due currently	$	16,305	$	16,298
Accounts receivable financing	$	1,082	$	750
Forward repurchase obligation	$	1,355	$	1,335

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Long-Term Debt

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

	March 31, 2025		December 31, 2024
	(in millions)
Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030	$	2,469	$	2,475
BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026	367		367
Vistra Zero Credit Facility, Term Loan B Facility due April 30, 2031	697		697
Vistra Operations Senior Secured Notes:
5.125% Senior Secured Notes, due May 13, 2025	744		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 Notes	5,144		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 Bonds	431		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 15, 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 Notes	7,300		7,300
Other:
Equipment Financing Agreements	55		55
Total other long-term debt	55		55
Unamortized debt premiums, discounts and issuance costs	(158)		(171)
Total long-term debt including amounts due currently	16,305		16,298
Less amounts due currently	(882)		(880)
Total long-term debt, less amounts due currently	$	15,423	$	15,418

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Long-Term Debt Maturities

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

	March 31, 2025
	(in millions)
Remainder of 2025	$	879
2026	1,792
2027	3,427
2028	27
2029	2,177
Thereafter	8,161
Unamortized premiums, discounts and debt issuance costs	(158)
Total long-term debt, including amounts due currently	$	16,305

Credit Facilities

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

		March 31, 2025
Credit Facilities	Maturity Date	Facility Limit		Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)		Letters of Credit Outstanding		Available Capacity
		(in millions)
Vistra Operations debt:
Revolving Credit Facility	October 11, 2029	$	3,440	$	—	$	1,223	$	2,217
Term Loan B-3 Facility	December 20, 2030	2,469		2,469		—		—
Total Vistra Operations Credit Facilities		$	5,909	$	2,469	$	1,223	$	2,217
Vistra Operations Commodity-Linked Facility	October 1, 2025	1,750		—		—		1,125
Total Vistra Operations debt		$	7,659	$	2,469	$	1,223	$	3,342
Project-level debt:
Tax Credit Bridge Loan	November 1, 2025	106		106		—		—
Tax Credit Bridge Loan	December 3, 2026	261		261		—		—
BCOP Credit Facility		367		367		—		—
Vistra Zero Term Loan B Facility (a)	April 30, 2031	697		697		—		—
Total project-level debt		$	1,064	$	1,064	$	—	$	—
Total credit facilities		$	8,723	$	3,533	$	1,223	$	3,342

___________

(a)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.

Vistra Operations Credit Facilities

As of March 31, 2025, the Vistra Operations Credit Facilities have aggregate commitments of up to $5.909 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 $2.469 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, 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 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 range from 1.25% to 2.00% and are paid quarterly in arrears. Interest and fees on the Revolving Credit Facility are based on ratings of Vistra Operations' senior secured long-term debt securities. As of March 31, 2025, after taking into account sustainability pricing adjustments based on certain sustainability-linked targets and thresholds, the applicable interest rate margins for the Revolving Credit Facility and the fee for undrawn amounts relating to such commitments were 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) on outstanding borrowings of $2.469 billion was 6.07% as of March 31, 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. 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.

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 March 31, 2025, Vistra Operations can distribute approximately $10.2 billion to Parent under the Vistra Operations Credit Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Parent of approximately $425 million and $490 million for the three months ended March 31, 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 March 31, 2025, all of the restricted net assets of Vistra Operations may be distributed to Parent.

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Vistra Operations Commodity-Linked Revolving Credit Facility

As of March 31, 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. As of March 31, 2025, the borrowing base of $1.125 billion 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 March 31, 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.

BCOP Project-level Credit Facilities

In December 2024, BCOP and its subsidiaries entered into the BCOP Credit Agreement to fund the development of the Baldwin and Coffeen solar generation and battery ESS facilities and the Oak Hill and Pulaski solar generation facilities in Illinois and Texas. The BCOP Credit Agreement provides for (i) tax credit bridge loans of $367 million for the Oak Hill and Pulaski projects (Tax Credit Bridge Loans) and (ii) construction/term loan commitments of $528 million (Construction/Term Loan Facility) and debt service reserve letter of credit facility commitments of $29 million (Debt Service Reserve) for all four facilities.

As of March 31, 2025, the Tax Credit 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. Interest is paid on the Tax Credit 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 5.984% as of March 31, 2025. Repayment of the Tax Credit Bridge Loans is guaranteed by Vistra as the beneficiary of the underlying investment tax credits to be generated by the projects.

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. 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. The term loans will amortize over a 20-year period beginning on the term funding date (for Baldwin and Coffeen) or term conversion date (for Oak Hill and Pulaski), as applicable, and debt amortization and interest payments will be funded by 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.

As of March 31, 2025, there were no Construction/Term Loan Facility borrowings outstanding. On April 1, 2025, term loans of $75 million and $46 million were funded for Baldwin and Coffeen, respectively.

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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 6.32% as of March 31, 2025.

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

Letter of Credit Facilities

Vistra Operations Secured Letter of Credit Facilities

Between August 2020 and July 2024, we entered into uncommitted standby letters of credit facilities with various banks (each, a Secured LOC Facility and collectively, the Secured LOC Facilities). The Secured LOC Facilities are secured by a first lien on substantially all of Vistra Operations' (and certain of its subsidiaries') assets (which ranks pari passu with the Vistra Operations Credit Facilities). The Secured LOC Facilities may be renewed annually and are used for general corporate purposes. As of March 31, 2025, $1.091 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 March 31, 2025, the total capacity was $500 million and $500 million of letters of credit were outstanding under the Alternative LOC Facilities. The commitments under the Alternative LOC Facilities terminate in December 2028. There are no financial maintenance covenants in the Alternative LOC Facilities.

Vistra Operations Senior Secured Notes

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.

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.

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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.

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 April 2024, the Receivables Facility was amended to increase the purchase limit from $750 million to $1.0 billion and to add Energy Harbor LLC, a direct, wholly owned subsidiary of Energy Harbor, as an Originator. The Receivables Facility was renewed and amended in July 2024, extending the term of the Receivables Facility to July 2025.

In connection with the Receivables Facility, TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands, Energy Harbor LLC and TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), each sell and/or contribute, subject to certain exclusions, all of its receivables (other than any receivables excluded pursuant to the terms of the Receivables Facility), arising from the sale of electricity to its customers and related rights (Receivables), to RecCo, a consolidated, wholly owned, bankruptcy-remote, direct subsidiary of TXU Energy. RecCo, in turn, is subject to certain conditions, and may draw under the Receivables Facility up to the limit described above to fund its acquisition of the Receivables from the Originators. RecCo has granted a security interest on the Receivables and all related assets for the benefit of the Purchasers under the Receivables Facility and Vistra Operations has agreed to guarantee the performance of the obligations of the Originators and TXU Energy, as the servicer, under the agreements governing the Receivables Facility. Amounts funded by the Purchasers to RecCo are reflected as short-term borrowings in the 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 March 31, 2025, outstanding borrowings under the Receivables Facility totaled $957 million and were supported by $1.346 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 2024, the Repurchase Facility was renewed until July 2025 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.

23

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

Forward Repurchase Obligation

In accordance with the amended UPAs, on December 31, 2024, Vistra closed the acquisition of the Vistra Vision minority interest from Avenue and Nuveen. Vistra paid Avenue for the purchase of their minority interest in Vistra Vision in full upon closing and paid Nuveen an initial payment at closing, with the remaining payments to Nuveen to be paid in multiple installments through December 31, 2026. Vistra Vision Holdings' remaining future payments to Nuveen are guaranteed by Vistra Operations and certain of its subsidiaries that guarantee Vistra Operations' unsecured notes. Payments remaining due to Nuveen are as follows:

	March 31, 2025
	(in millions)
Remainder of 2025	$	781
2026	669
Thereafter	—
Total scheduled payments under the UPAs	$	1,450

The present value of the remaining payment obligations to Nuveen discounted at 6% totaled $1.355 billion and $1.335 billion at March 31, 2025 and December 31, 2024, respectively.

Interest Expense and Related Charges

	Three Months Ended March 31,
	2025		2024
	(in millions)
Interest expense	$	272	$	208
Unrealized mark-to-market net (gains) losses on interest rate swaps	48		(47)
Amortization of debt issuance costs, discounts, and premiums	11		7
Debt extinguishment gain	—		(6)
Capitalized interest	(29)		(12)
Other	17		20
Total interest expense and related charges	$	319	$	170

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 10, was 5.22% and 5.56% as of March 31, 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 March 31, 2025, Vistra has entered into the following interest rate swaps:

	Notional Amount	Expiration Date	Rate Range (d)
	(in millions, except percentages)
Swapped to fixed (a)	$3,000	July 2026	2.89	%	-	2.97%
Swapped to variable (a)	$700	July 2026	1.44	%	-	1.49%
Swapped to fixed (b)	$2,300	December 2030	3.20	%	-	3.76%
Swapped to fixed (c)	$108	March 2045	3.95%

____________

(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, BCOP entered into approximately $108 million notional amount of interest rate swaps effective April 1, 2025 and expiring in March 2045. These swaps will hedge BCOP's exposure on approximately $108 million of floating rate Construction/Term Loan Facility commitments (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.

	March 31, 2025
	Derivative Contract Assets				Derivative Contract Liabilities
	Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total
	(in millions)
Current assets	$	3,306	$	28	$	1	$	—	$	3,335
Noncurrent assets	729		21		19		—		769
Current liabilities	(7)		—		(4,622)		(17)		(4,646)
Noncurrent liabilities	(14)		—		(1,433)		(12)		(1,459)
Net assets (liabilities)	$	4,014	$	49	$	(6,035)	$	(29)	$	(2,001)
Offsetting instruments (a)	(3,381)		(22)		3,381		22		—
Financial collateral (received) pledged (b)	(17)		—		331		—		314
Net amounts	$	616	$	27	$	(2,323)	$	(7)	$	(1,687)

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	December 31, 2024
	Derivative Contract Assets				Derivative Contract Liabilities
	Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total
	(in millions)
Current assets	$	2,551	$	34	$	2	$	—	$	2,587
Noncurrent assets	677		62		1		—		740
Current liabilities	—		—		(3,333)		(18)		(3,351)
Noncurrent liabilities	(2)		—		(1,356)		(9)		(1,367)
Net assets (liabilities)	$	3,226	$	96	$	(4,686)	$	(27)	$	(1,391)
Offsetting instruments (a)	(2,532)		(28)		2,532		28		—
Financial collateral (received) pledged (b)	(50)		—		233		—		183
Net amounts	$	644	$	68	$	(1,921)	$	1	$	(1,208)

____________

(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 months ended March 31, 2025 and 2024:

Derivative (condensed consolidated statements of operations presentation)	Three Months Ended March 31,
	2025		2024
	(in millions)
Reversals of previously recognized unrealized (gain) loss on derivative instruments:
Commodity contracts unrealized (gain) loss in operating revenues (a)	$	212	$	261
Commodity contracts unrealized (gain) loss in fuel, purchased power costs, and delivery fees (a)	(23)		126
Interest rate swaps unrealized (gain) loss in interest expense and related charges	(5)		(11)
Total reversals of previously recognized unrealized (gain) loss on derivative instruments	$	184	$	376
Unrealized net gain (loss) from changes in fair value on derivative instruments:
Commodity contracts unrealized gain (loss) in operating revenues	$	(725)	$	(608)
Commodity contracts unrealized gain (loss) in fuel, purchased power costs, and delivery fees	(31)		45
Interest rate swaps unrealized gain (loss) in interest expense and related charges	(43)		58
Total unrealized net gain (loss) from change in fair value on derivative instruments	$	(799)	$	(505)
Net gain (loss) on derivative instruments	$	(615)	$	(129)

____________

(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:

	March 31, 2025		December 31, 2024
Derivative type	Notional Volume				Unit of Measure
Natural gas	4,563		4,568		Million MMBtu
Electricity	831,426		796,982		GWh
Financial transmission rights / Congestion revenue rights	224,032		248,742		GWh
Coal	27		27		Million U.S. tons
Fuel oil	—		2		Million gallons
Emissions	29		28		Million U.S. tons
Renewable energy certificates	28		31		Million certificates
Interest rate swaps – variable/fixed	$	5,408	$	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:

	March 31, 2025		December 31, 2024
	(in millions)
Fair value of derivative contract liabilities (a)	$	(1,963)	$	(1,587)
Offsetting fair value under netting arrangements (b)	792		724
Cash collateral and letters of credit	563		471
Liquidity exposure	$	(608)	$	(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.

	March 31, 2025
	(in millions, except percentages)
Credit risk exposure to derivative contract counterparties:
Gross exposure	$	4,431
Net exposure (a)	$	689
Largest net exposure from any single counterparty (a)	$	272
Percent of credit risk exposure to derivative contract counterparties related to banking and financial sector
Gross exposure	80		%
Net exposure (a)	23		%

____________

(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:

	March 31, 2025										December 31, 2024
	Level 1		Level 2		Level 3		Reclass (a)		Total		Level 1		Level 2		Level 3		Reclass (a)		Total
	(in millions)
Assets:
Commodity contracts (b)	$	2,683	$	425	$	906	$	41	$	4,055	$	1,923	$	462	$	841	$	5	$	3,231
Interest rate swaps (b)	—		49		—		—		49		—		96		—		—		96
NDTs – equity securities (c)(d)	1,469		—		—				1,469		1,560		—		—				1,560
NDTs – debt securities (c)(e)	99		1,753		—				1,852		83		1,976		—				2,059
Sub-total	$	4,251	$	2,227	$	906	$	41	7,425		$	3,566	$	2,534	$	841	$	5	6,946
Assets measured at net asset value (f):
NDTs – equity securities (c)(d)(f)									783										821
NDTs - debt securities (c)(e)(f)									300										—
Total assets									$	8,508									$	7,767
Liabilities:
Commodity contracts (b)	$	3,002	$	1,183	$	1,850	$	41	$	6,076	$	2,118	$	975	$	1,593	$	5	$	4,691
Interest rate swaps (b)	—		29		—		—		29		—		27		—		—		27
Total liabilities	$	3,002	$	1,212	$	1,850	$	41	$	6,105	$	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 March 31, 2025.

(d)The investment objective for NDT equity securities is to invest tax efficiently and to match the performance of the S&P 500 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 4.24% and 3.99% as of March 31, 2025 and December 31, 2024, respectively, and an average maturity of eight years and seven years as of March 31, 2025 and December 31, 2024, respectively. NDT debt securities held as of March 31, 2025 mature as follows: $825 million in one to five years, $972 million in five to 10 years and $355 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 March 31, 2025 and December 31, 2024:

March 31, 2025
	Fair Value
Contract Type (a)	Assets		Liabilities		Total, Net		Valuation Technique	Significant Unobservable Input	Range (b)			Average (b)
	(in millions)
Electricity purchases and sales	$	689	$	(1,616)	$	(927)	Income Approach	Hourly price curve shape (c)	$—	to	$95	$48
									MWh
								Illiquid delivery periods for hub power prices (d)	$25	to	$145	$85
									MWh
								Market Heat Rates (d)	$45	to	$120	$83
									MWh
Options	7		(181)		(174)		Option Pricing Model	Natural gas to power correlation (e)	—%	to	100%	50%
								Power and natural gas volatility (e)	5%	to	835%	420%
Financial transmission rights/Congestion revenue rights	196		(21)		175		Market Approach (f)	Illiquid price differences between settlement points (g)	$5	to	$25	$15
									MWh
Natural gas	12		(27)		(15)		Income Approach	Natural gas basis (h)	$(1)	to	$12	$5
									MMBtu
								Illiquid delivery periods (i)	$3	to	$5	$4
									MMBtu
Other (j)	2		(5)		(3)
Total	$	906	$	(1,850)	$	(944)

December 31, 2024
	Fair Value
Contract Type (a)	Assets		Liabilities		Total, Net		Valuation Technique	Significant Unobservable Input	Range (b)			Average (b)
	(in millions)
Electricity purchases and sales	$	606	$	(1,399)	$	(793)	Income Approach	Hourly price curve shape (c)	$—	to	$95	$48
									MWh
								Illiquid delivery periods for hub power prices (d)	$25	to	$140	$83
									MWh
								Market Heat Rates (d)	$30	to	$150	$90
									MWh
Options	6		(139)		(133)		Option Pricing Model	Natural gas to power correlation (e)	10%	to	100%	55%
								Power and natural gas volatility (e)	5%	to	710%	358%
Financial transmission rights/Congestion revenue rights	190		(25)		165		Market Approach (f)	Illiquid price differences between settlement points (g)	$(35)	to	$20	$(8)
									MWh
Natural gas	29		(30)		(1)		Income Approach	Natural 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 March 31,
	2025		2024
	(in millions)
Net liability balance at beginning of period	$	(752)	$	(1,044)
Total unrealized valuation (losses)	(243)		(269)
Purchases, issuances and settlements (a):
Purchases	49		70
Issuances	(2)		(3)
Settlements	(7)		99
Transfers into Level 3 (b)	1		3
Transfers out of Level 3 (b)	10		8
Net liabilities assumed in connection with the Energy Harbor Merger	—		(13)
Net change	(192)		(105)
Net liability balance at end of period	$	(944)	$	(1,149)
Unrealized valuation (losses) relating to instruments held at end of period	$	(266)	$	(325)

____________

(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 March 31, 2025, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become observable. For the three months ended March 31, 2024, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of coal and natural gas derivatives where forward pricing inputs have become observable.

Assets and Liabilities Recorded on a Non-Recurring Basis

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

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

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Fair Value of Debt

		March 31, 2025				December 31, 2024
Instrument:	Fair Value Hierarchy	Carrying Amount		Fair Value		Carrying Amount		Fair Value
		(in millions)
Long-term debt under the Vistra Operations Credit Facilities	Level 2	$	2,431	$	2,456	$	2,435	$	2,478
BCOP Credit Facilities Tax Credit Bridge Loan	Level 3	348		367		344		367
Vistra Zero Term Loan B Facility	Level 2	686		670		685		697
Vistra Operations Senior Notes	Level 2	12,371		12,483		12,366		12,428
Energy Harbor Revenue Bonds	Level 2	415		431		414		431
Equipment Financing Agreements	Level 3	54		54		54		53
Forward Repurchase Obligation	Level 3	1,355		1,355		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.

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 three months ended March 31, 2025 and 2024:

	Three Months Ended March 31, 2025						Three Months Ended March 31, 2024
	Nuclear Plant Decommissioning		Land Reclamation, Coal Ash and Other		Total		Nuclear 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)	37		11		48		23		10		33
Adjustment for change in estimates (b)	—		(33)		(33)		—		3		3
Adjustment for obligations assumed through acquisition	—		—		—		1,368		—		1,368
Reductions:
Payments	—		(20)		(20)		—		(17)		(17)
Liability at end of period	3,277		796		4,073		3,133		792		3,925
Less amounts due currently	—		(136)		(136)		—		(119)		(119)
Noncurrent liability at end of period	$	3,277	$	660	$	3,937	$	3,133	$	673	$	3,806

____________

(a)For the three months ended March 31, 2025 and 2024, nuclear plant decommissioning accretion includes $23 million and $9 million, respectively, of accretion expense recognized in operating costs in the condensed consolidated statements of operations and $14 million and $14 million, respectively, reflected as a change in regulatory liability in the condensed consolidated balance sheets.

(b)Includes non-cash adjustments to asset retirement costs included in property, plant, and equipment of $15 million and $1 million for the three months ended March 31, 2025 and 2024, respectively.

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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 March 31, 2025, the carrying value of our ARO related to our Comanche Peak nuclear generation facility decommissioning totaled $1.812 billion, which is lower than the fair value of the assets contained in the Comanche Peak NDT of $2.223 billion. The difference between the carrying value of the ARO and the NDT represents a regulatory liability of $411 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.

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 March 31, 2025, we had outstanding letters of credit totaling $2.814 billion as follows:

•$2.439 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;

•$251 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

•$13 million for other credit support requirements.

Surety Bonds

As of March 31, 2025, we had outstanding surety bonds totaling $1.072 billion to support performance under various contracts and legal obligations in the normal course of business.

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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.

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.

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.

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

Moss Landing 300 Battery Fire

On January 16, 2025, we detected a fire at our Moss Landing 300 MW energy storage facility at the Moss Landing Power Plant site. We are working closely with all local, state, and federal regulatory authorities on the response, and we are investigating the cause of the fire. We are also responding to various regulatory bodies, including the CPUC, the EPA, and others investigating the incident. 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.

We are working closely with the EPA under a Notice of Federal Response Action pursuant to which the EPA is providing control and oversight of clean up and remediation efforts on the site. We are in ongoing discussions to develop an agreed upon order that will govern the clean-up and recovery efforts. As of March 31, 2025, we accrued approximately $70 million in obligations related to the Moss Landing Incident including approximately $30 million for anticipated air and soil monitoring requirements and $40 million for the expected costs of decommissioning the Moss Landing 300 structure, which includes demolition of the structure, removing and disposing of the batteries, and fulfilling land reclamation obligations. Aside from battery removal and disposal, our estimate does not reflect costs associated with removal of other hazardous waste which could be identified as the demolition progresses. 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 executive orders.

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Greenhouse Gas Emissions (GHG)

In May 2023, the EPA released a proposal regulating power plant GHG emissions, while also proposing to repeal the Affordable Clean Energy (ACE) rule that had been finalized by the EPA in July 2019. In May 2024, the EPA published a final GHG rule that repealed the ACE rule and sets limits for (a) new natural gas-fired combustion turbines and (b) existing coal-, oil- and natural gas-fired steam generation units. The standards are based on technologies such as carbon capture and sequestration/storage (CCS) and natural gas co-firing. 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. In February 2025, the D.C. Circuit granted the unopposed motion filed by the Department of Justice on behalf of the EPA, holding the litigation in abeyance for a period of 60 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed.

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

In October 2015, the EPA revised the primary and secondary ozone National Ambient Air Quality Standards (NAAQS) to lower the 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. Nevertheless, 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.

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.

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SO2 Designations for Texas

In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Martin Lake generation plant and our now retired Big Brown and Monticello plants. The final designations require Texas to develop nonattainment plans for these areas. Following legal challenges and additional agency actions, in January 2024, in a split decision, the Fifth Circuit Court denied the petitions for review we and the State of Texas filed over the EPA's 2016 nonattainment designation for SO2 for the area around Martin Lake. As a result of this decision, the EPA's nonattainment designation – originally made in 2016 – remains in place. In February 2024, we filed a petition asking the full Fifth Circuit Court to review the panel decision issued in January 2024, which remains pending before the full Fifth Circuit Court. In addition, in September 2021, the TCEQ considered a proposal for its nonattainment SIP revision for the Martin Lake area and an agreed order to reduce SO2 emissions from the plant. The TCEQ's SIP action was finalized in February 2022 and has been submitted to the EPA for review and approval. 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 of the SIP partial approval and disapproval in a future action. In February 2025, we, along with the State of Texas, filed a challenge to the Finding of Failure in the Fifth Circuit Court. That case is in abeyance until June 2025 so the new EPA can review the rule. If the EPA approves Texas's SIP in full, that would fully resolve this matter.

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.

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.

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.

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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.

The FERC Office of Enforcement opened a formal, non-public investigation into whether market manipulation or other potential violations of the FERC orders, rules, and regulations occurred before or during the PRA.

In July 2019, the FERC issued an order denying complaints and closing the Office of Enforcement's investigation into Dynegy. Upon appeal, in 2021, the D.C. Circuit Court of Appeals remanded the case back to the FERC on a narrow question. In June 2022, the FERC issued an order on remand establishing paper hearing procedures and directing the Office of Enforcement to file a remand report within 90 days providing the Office of Enforcement's assessment of Dynegy's actions with regard to the 2015-2016 PRA. After the close of briefing in the 2022 remand proceeding, 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" that it believes cannot be resolved on the existing record, held the hearing in abeyance for the parties to engage in settlement discussions, and, in October 2024, issued an order dismissing our request for rehearing of the June 2024 order. We will continue to vigorously defend our position.

Other Matters

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

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 $0.2235 and $0.2150 for the three months ended March 31, 2025 and 2024.

In May 2025, the Board declared a quarterly dividend of $0.225 per share of common stock that will be paid in June 2025.

Share Repurchase Program

The Board has authorized a $6.750 billion share repurchase program. Through May 2, 2025, 162,932,192 shares, at an average price of $31.96 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 May 2, 2025:

	$6.750 Billion Board Authorization
	Total Number of Shares Repurchased	Average Price Paid Per Share		Amount Paid for Shares Repurchased		Amount Available for Additional Repurchases at the End of the Period
	(in millions, except share amounts and price paid per share)
Three Months Ended March 31, 2025 (a)	2,437,700	$	137.66	$	336	$	1,673
April 1, 2025 through May 2, 2025	1,138,753	114.95		131
January 1, 2025 through May 2, 2025	3,576,453	$	130.43	$	467	$	1,542

____________

(a)Shares repurchased include 59,503 of unsettled shares for $7 million as of March 31, 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 Series	Issuance Date	Shares Issued	Shares Outstanding	Contractual Rates		Earliest Redemption Date (a)	Date at Which Dividend Rate Becomes Floating	Floating Annual Rates
Series A	October 15, 2021	1,000,000	1,000,000	8.000	%	October 15, 2026	October 15, 2026	5-Year U.S. Treasury rate (subject to floor of 1.07%) plus 6.93%
Series B	December 10, 2021	1,000,000	1,000,000	7.000	%	December 15, 2026	December 15, 2026	5-Year U.S. Treasury rate (subject to floor of 1.26%) plus 5.74%
Series C	December 29, 2023	476,081	476,066	8.875	%	January 15, 2029	January 15, 2029	5-Year U.S. Treasury rate (subject to floor of 3.83%) plus 5.045%

____________

(a)Subject to our right, in limited circumstances, to redeem preferred stock prior to the earliest redemption date.

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

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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 months ended March 31, 2025 and 2024.

	Three Months Ended March 31,
Preferred Stock Series	2025		2024
Series C Preferred Stock	$	44.375	$	—

In February 2025, the Board declared a semi-annual dividend of $40.00 per share of Series A Preferred Stock that was paid in April 2025. In May 2025, the Board declared a semi-annual dividend of $35.00 per share of Series B Preferred Stock that will be paid in June 2025 and a semi-annual dividend of $44.375 per share of Series C Preferred Stock that will be paid in July 2025.

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 March 31,
	2025		2024
	(in millions, except share data)
Net loss attributable to Vistra	$	(268)	$	(35)
Less cumulative dividends attributable to Series A Preferred Stock	(20)		(20)
Less cumulative dividends attributable to Series B Preferred Stock	(18)		(18)
Less cumulative dividends attributable to Series C Preferred Stock	(11)		(11)
Net loss attributable to common stock — basic and diluted	$	(317)	$	(84)
Weighted average shares of common stock outstanding:
Basic	339,799,989		348,966,197
Dilutive securities: Stock-based incentive compensation plan	—		—
Diluted	339,799,989		348,966,197
Net loss per weighted average share of common stock outstanding:
Basic	$	(0.93)	$	(0.24)
Diluted	$	(0.93)	$	(0.24)

Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 8,582,267 and 7,954,878 shares for the three months ended March 31, 2025 and 2024, respectively.

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.

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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, and other expenses not allocated to our operating segments.

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1 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.

	Three Months Ended March 31, 2025
	Retail		Texas		East		West		Asset Closure		Total Reportable Segments		Corporate and Other		Total
	(in millions)
Operating revenues	$	3,168	$	210	$	1,380	$	157	$	4	$	4,919	$	(986)	$	3,933
Fuel, purchased power costs, and delivery fees	(1,712)		(497)		(1,172)		(52)		—		(3,433)		986		(2,447)
Operating costs	(40)		(258)		(327)		(12)		(56)		(693)		—		(693)
Selling, general, and administrative expenses	(243)		(41)		(58)		(2)		(17)		(361)		(30)		(391)
Other segment items:
Depreciation and amortization	(23)		(150)		(316)		(15)		1		(503)		(19)		(522)
Interest expenses and related charges	(18)		14		12		1		(1)		8		(327)		(319)
Income tax benefit	—		—		—		—		—		—		176		176
Other (a)	—		2		(9)		—		1		(6)		1		(5)
Net income (loss)	$	1,132	$	(720)	$	(490)	$	77	$	(68)	$	(69)	$	(199)	$	(268)
Capital expenditures, including nuclear fuel and excluding growth expenditures	$	3	$	419	$	264	$	30	$	—	$	716	$	13	$	729

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	Three Months Ended March 31, 2024
	Retail		Texas		East		West		Asset Closure		Total Reportable Segments		Corporate and Other		Total
	(in millions)
Operating revenues	$	2,494	$	459	$	856	$	276	$	9	$	4,094	$	(1,040)	$	3,054
Fuel, purchased power costs, and delivery fees	(1,647)		(381)		(647)		(79)		(2)		(2,756)		1,040		(1,716)
Operating costs	(31)		(257)		(181)		(11)		(17)		(497)		(1)		(498)
Selling, general, and administrative expenses	(225)		(35)		(28)		(4)		(10)		(302)		(49)		(351)
Other segment items:
Depreciation and amortization	(23)		(134)		(210)		(14)		(7)		(388)		(15)		(403)
Interest expenses and related charges	(6)		10		(1)		—		(1)		2		(172)		(170)
Income tax benefit	—		—		—		—		—		—		20		20
Other (a)	(1)		2		38		—		3		42		40		82
Net income (loss)	$	561	$	(336)	$	(173)	$	168	$	(25)	$	195	$	(177)	$	18
Capital expenditures, including nuclear fuel and excluding growth expenditures	$	—	$	316	$	88	$	6	$	—	$	410	$	11	$	421

____________

(a)Other includes other income (deductions) and the impacts of the Tax Receivable Agreement.

17.    SUPPLEMENTARY FINANCIAL INFORMATION

Other Income (Deductions), Net

	Three Months Ended March 31,
	2025		2024
	(in millions)
NDT net income (loss) (a)	$	(10)	$	35
Insurance settlements (b)	—		1
Gain on sale of land	—		1
Gain on TRA settlement (c)	—		10
Interest income	6		23
All other	(1)		17
Total other income (deductions), net	$	(5)	$	87

____________

(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)Reported in the Asset Closure segment.

(c)Reported in Corporate and Other.

Inventories by Major Category

	March 31, 2025		December 31, 2024
	(in millions)
Materials and supplies	$	541	$	533
Fuel stock	399		403
Natural gas in storage	20		34
Total inventories	$	960	$	970

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Investments

	March 31, 2025		December 31, 2024
	(in millions)
Nuclear decommissioning trusts	$	4,404	$	4,440
Assets related to employee benefit plans	13		14
Land investments	42		42
Other investments	17		16
Total investments	$	4,476	$	4,512

Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:

	March 31, 2025		December 31, 2024
	(in millions)
Retirement and other employee benefits	$	204	$	224
Identifiable intangible liabilities	149		155
Regulatory liability (a)	411		452
Operating lease liabilities	81		98
Finance lease liabilities	217		218
Liability for third-party remediation	8		8
Accrued severance costs	36		36
Tax Receivable Agreement obligation	12		14
Other accrued expenses	110		65
Total other noncurrent liabilities and deferred credits	$	1,228	$	1,270

____________

(a)As of March 31, 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 $411 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 March 31, 2025 and December 31, 2024:

	March 31, 2025		December 31, 2024
	(in millions)
Cash and cash equivalents	$	561	$	1,188
Restricted cash included in current assets	29		28
Restricted cash included in noncurrent assets	6		6
Total cash, cash equivalents and restricted cash	$	596	$	1,222

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The following table summarizes our supplemental cash flow information for the three months ended March 31, 2025 and 2024. Non-cash investing and financing activities for the three months ended March 31, 2024 includes activity related to the Energy Harbor Merger (see Note 2 for additional information).

	Three Months Ended March 31,
	2025		2024
	(in millions)
Cash payments related to:
Interest paid	$	210	$	214
Capitalized interest	(29)		(12)
Interest paid (net of capitalized interest)	$	181	$	202

For the three months ended March 31, 2025 and 2024, we paid state income taxes of $5 million and $3 million respectively, and received state tax refunds of zero and $1 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

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 our nuclear and gas facilities 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 of some planned capital expenditures for our renewables projects and could impact the economic feasibility of additional projects. 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) was approved by Congress, signed into law by President Biden, and took effect on August 11, 2024. The PRUI Act 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.

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.

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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, but the two 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 at some point later this year. 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 March 31, 2025, the net book value of the Moss Landing 100 facility was approximately $170 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). We have recognized expense of approximately $7 million for costs incurred to respond to the Moss Landing Incident through March 31, 2025. As of March 31, 2025, we accrued approximately $70 million in obligations related to the Moss Landing Incident including approximately $30 million for anticipated air and soil monitoring requirements and $40 million for the expected costs of decommissioning the Moss Landing 300 structure, which includes demolition of the structure, removing and disposing of the batteries, and fulfilling land reclamation obligations (see Note 13 to the Financial Statements). Additional costs incurred 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.

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 costs and expenses incurred in other noncurrent assets on the condensed consolidated balance sheet. Given uncertainty in timing of insurance recoveries and additional expenses that could be incurred related to the fire, we cannot predict the full impacts 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, an 815 MW unit. We wrote-off the net book value of Unit 1 of the Martin Lake facility of less than $1 million to depreciation expense in December 2024. We currently expect the unit to return to service in late 2025. We incurred approximately $30 million in cash capital expenditures during the three-months ended March 31, 2025 to restore the unit to service. Cash capital expenditures to return the unit to service in 2025 are expected to be approximately $270 million. We expect to recover a majority of the expenditures associated with the Martin Lake Unit 1 through property damage insurance and receive additional business interruption proceeds. However, given uncertainty in timing of insurance recoveries and asset restart date, we cannot predict the net impacts these events will have on our 2025 financial statements.

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.

47

•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.

Our announced plan is based on market reforms that policymakers passed in the 2023 Texas legislative session, which ERCOT and the PUCT are currently implementing. These market reforms are focused on grid reliability and proper market signals. If successfully implemented, they could offer the regulatory framework necessary for Vistra to confidently make the long-term investments in these capacity projects. In addition, 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. Vistra's decision to move forward with the new west Texas gas plant projects are contingent upon supportive market reforms, approval of our Texas Energy Fund loan application, and other factors, including state and federal environmental regulations and long-term wholesale trends that continue to support gas generation.

Merger with Energy Harbor

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

Nuclear Plant License Renewal

In 2023, the Perry Nuclear Plant filed a license extension application to operate through 2046, an additional 20 years beyond the existing license. A decision from the NRC is expected in late 2025.

Inflation Reduction Act of 2022 (IRA)

In August 2022, the U.S. enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, including recognizing the value of existing carbon-free nuclear power by providing for a nuclear PTC, a solar PTC, and a first-time stand-alone battery storage investment tax credit. The 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 as power prices increase above $25 per MWh (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. U.S. Treasury regulations are expected to further define the scope of the legislation in many important respects, including critical guidance interpreting the nuclear PTC. This guidance could have a material impact on our estimate and would be reflected as a change in estimate in the period in which the guidance is received. We do not expect Vistra to be subject to the 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 relevant extensions or expansions of existing tax credits applicable to projects in our immediate development pipeline into account when forecasting cash taxes.

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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 (loss) decreased $286 million to a Net loss of $268 million for the three months ended March 31, 2025 compared to the three months ended March 31, 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).

49

Vistra Consolidated Financial Results — Three Months Ended March 31, 2025 Compared to the Three Months Ended March 31, 2024

The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the three months ended March 31, 2025:

	Three Months Ended March 31, 2025
	Retail		Texas		East		West		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
	(in millions)
Operating revenues	$	3,168	$	210	$	1,380	$	157	$	4	$	(986)	$	3,933
Fuel, purchased power costs, and delivery fees	(1,712)		(497)		(1,172)		(52)		—		986		(2,447)
Operating costs	(40)		(258)		(327)		(12)		(56)		—		(693)
Depreciation and amortization	(23)		(150)		(316)		(15)		1		(19)		(522)
Selling, general, and administrative expenses	(243)		(41)		(58)		(2)		(17)		(30)		(391)
Operating income (loss)	1,150		(736)		(493)		76		(68)		(49)		(120)
Other income (deductions)	—		2		(9)		—		1		1		(5)
Interest expense and related charges	(18)		14		12		1		(1)		(327)		(319)
Income (loss) before income taxes	1,132		(720)		(490)		77		(68)		(375)		(444)
Income tax benefit	—		—		—		—		—		176		176
Net income (loss)	$	1,132	$	(720)	$	(490)	$	77	$	(68)	$	(199)	$	(268)
Income tax benefit	—		—		—		—		—		(176)		(176)
Interest expense and related charges (a)	18		(14)		(12)		(1)		1		327		319
Depreciation and amortization (b)	23		181		396		15		(1)		19		633
EBITDA before Adjustments	1,173		(553)		(106)		91		(68)		(29)		508
Unrealized net (gain) loss resulting from commodity hedging transactions	(997)		1,030		567		(32)		(1)		—		567
Purchase accounting impacts	—		—		14		—		—		—		14
Non-cash compensation expenses	—		—		—		—		—		21		21
Transition and merger expenses	—		—		1		—		—		17		18
Decommissioning-related activities (c)	—		5		35		—		46		—		86
Other, net	8		8		3		3		(1)		(19)		2
Adjusted EBITDA	$	184	$	490	$	514	$	62	$	(24)	$	(10)	$	1,216

____________

(a)Includes $48 million of unrealized mark-to-market net losses on interest rate swaps.

(b)Includes nuclear fuel amortization of $31 million and $80 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 March 31, 2024:

	Three Months Ended March 31, 2024
	Retail		Texas		East		West		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
	(in millions)
Operating revenues	$	2,494	$	459	$	856	$	276	$	9	$	(1,040)	$	3,054
Fuel, purchased power costs, and delivery fees	(1,647)		(381)		(647)		(79)		(2)		1,040		(1,716)
Operating costs	(31)		(257)		(181)		(11)		(17)		(1)		(498)
Depreciation and amortization	(23)		(134)		(210)		(14)		(7)		(15)		(403)
Selling, general, and administrative expenses	(225)		(35)		(28)		(4)		(10)		(49)		(351)
Operating income (loss)	568		(348)		(210)		168		(27)		(65)		86
Other income (deductions)	(1)		2		38		—		3		45		87
Interest expense and related charges	(6)		10		(1)		—		(1)		(172)		(170)
Impacts of Tax Receivable Agreement	—		—		—		—		—		(5)		(5)
Income (loss) before income taxes	561		(336)		(173)		168		(25)		(197)		(2)
Income tax benefit	—		—		—		—		—		20		20
Net income (loss)	$	561	$	(336)	$	(173)	$	168	$	(25)	$	(177)	$	18
Income tax benefit	—		—		—		—		—		(20)		(20)
Interest expense and related charges (a)	6		(10)		1		—		1		172		170
Depreciation and amortization (b)	23		160		233		14		7		16		453
EBITDA before Adjustments	590		(186)		61		182		(17)		(9)		621
Unrealized net (gain) loss resulting from commodity hedging transactions	(623)		604		328		(129)		(4)		—		176
Purchase accounting impacts	(2)		—		(2)		—		—		(14)		(18)
Impacts of Tax Receivable Agreement (c)	—		—		—		—		—		(5)		(5)
Non-cash compensation expenses	—		—		—		—		—		21		21
Transition and merger expenses	1		—		4		—		—		28		33
Decommissioning-related activities (d)	—		6		(25)		—		—		—		(19)
ERP system implementation	—		—		—		—		—		6		6
Other, net	6		5		1		3		1		(41)		(25)
Adjusted EBITDA	$	(28)	$	429	$	367	$	56	$	(20)	$	(14)	$	790

____________

(a)Includes $47 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $26 million and $23 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 (loss) decreased $286 million to a net loss of $268 million for the three months ended March 31, 2025 compared to the three months ended March 31, 2024. The primary drivers for the decrease in GAAP net income (loss) include:

Unfavorable impacts:

•An increase of $391 million in unrealized mark-to-market losses on derivative positions due to power and natural gas curves moving up more significantly in the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. See further information on our derivative results in Energy-Related Commodity Contracts and Mark-to-Market Activities below.

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Favorable impacts:

•Inclusion of three months of Energy Harbor activity in the East and Retail segments for 2025 compared to one month in 2024.

The following table presents the operational performance of our retail and generation segments:

	Three Months Ended March 31,
	Retail				Texas				East				West
	2025		2024		2025		2024		2025		2024		2025		2024
Retail electricity sales volumes (GWh):
Sales volumes in ERCOT	17,965		16,074
Sales volumes in Northeast/Midwest	15,358		10,261
Total retail electricity sales volumes	33,323		26,335
Production volumes (GWh):
Natural gas facilities					9,145		8,151		14,642		14,762		502		1,228
Lignite and coal facilities					5,437		5,114		5,174		3,234
Nuclear facilities					5,229		5,008		7,679		2,329
Solar facilities					162		156		44
Capacity factors:
CCGT facilities					48.1	%	43.8	%	63.2	%	61.5	%	22.7	%	55.0	%
Lignite and coal facilities					56.0	%	52.1	%	61.0	%	37.7	%
Nuclear facilities					100.9	%	95.6	%	87.9	%	77.4	%
Weather - percent of normal (a):
Heating degree days	105	%	90	%	113	%	93	%	101	%	87	%	124	%	117	%

____________

(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 Forth Worth area.

	Three Months Ended March 31,					Three Months Ended March 31,
	2025		2024			2025		2024
Average Power Price ($MWh) (a):					Average Natural Gas Price ($MWh) (b):
ERCOT North Hub	$	30.91	$	21.58	NYMEX Henry Hub	$	4.28	$	2.43
ERCOT West Hub	$	30.13	$	25.70	Houston Ship Channel	$	3.46	$	1.92
PJM AEP Dayton Hub	$	47.91	$	29.57	Permian Basin	$	1.83	$	1.21
PJM Northern Illinois Hub	$	35.19	$	25.97	Dominion South	$	3.74	$	1.86
PJM Western Hub	$	53.91	$	32.61	Tetco ELA	$	4.06	$	2.27
MISO Indiana Hub	$	44.84	$	32.65	Chicago Citygate	$	4.00	$	2.85
ISONE Massachusetts Hub	$	102.77	$	43.93	Tetco M3	$	6.42	$	2.90
New York Zone A	$	68.63	$	32.67	Algonquin Citygates	$	11.83	$	4.26
CAISO NP15	$	40.89	$	50.46	PG&E Citygate	$	3.71	$	3.90

___________

(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.

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Adjusted EBITDA for the three months ended March 31, 2025 compared to the three months ended March 31, 2024 increased by $426 million. The primary drivers for the increase include:

	Three Months Ended March 31, 2025 Compared to 2024
	Retail (a)		Texas		East (a)		West
	(in millions)
Favorable change in realized revenue net of fuel driven primarily by addition of Energy Harbor in East.	$	—	$	65	$	293	$	6
Higher retail margins driven by favorable power supply costs, customer count growth, and inclusion of a full quarter of Energy Harbor retail contracts	213		—		—		—
Favorable impact of higher average consumption primarily due to weather	19		—		—		—
Increase in plant operating costs due primarily to addition of Energy Harbor in East	—		5		(134)		(1)
Change in SG&A and other primarily due to increase in costs related to addition of Energy Harbor in Retail and East	(20)		(9)		(12)		1
Change in Adjusted EBITDA	$	212	$	61	$	147	$	6
Change in depreciation and amortization driven primarily by addition of Energy Harbor assets in East	—		(21)		(163)		(1)
Change in unrealized net gains (losses) on hedging activities (b)	374		(426)		(239)		(97)
Decommissioning related activities	—		1		(60)		—
Other (including interest expenses)	(15)		1		(2)		1
Change in Net income (loss)	$	571	$	(384)	$	(317)	$	(91)

___________

(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.

Asset Closure Segment — Three Months Ended March 31, 2025 Compared to Three Months Ended March 31, 2024

	Three Months Ended March 31,				Favorable (Unfavorable) Change
	2025		2024
	(in millions)
Operating revenues	$	4	$	9	$	(5)
Fuel, purchased power costs, and delivery fees	—		(2)		2
Operating costs	(56)		(17)		(39)
Depreciation and amortization	1		(7)		8
Selling, general, and administrative expenses	(17)		(10)		(7)
Operating loss	(68)		(27)		(41)
Other income (deductions)	1		3		(2)
Interest expense and related charges	(1)		(1)		—
Loss before income taxes	(68)		(25)		(43)
Net loss	$	(68)	$	(25)	$	(43)
Adjusted EBITDA	$	(24)	$	(20)	$	(4)

GAAP results for the three months ended March 31, 2025 are unfavorable compared to the three months ended March 31, 2024 primarily due to operating costs associated with the Moss Landing 300 Incident net of insurance receivables. See Note 1 to the Financial Statements for additional information.

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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 three months ended March 31, 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.

In the first quarters of both 2024 and 2025, forward power prices in our Texas and East generation segments increased relative to our hedged positions resulting in unrealized losses in those segments, which were partially offset by unrealized gains in our retail segment.

The table below summarizes the changes in commodity contract assets and liabilities for the three months ended March 31, 2025 and 2024.

	Three Months Ended March 31,
	2025		2024
	(in millions)
Commodity contract net liability as of January 1	$	(1,459)	$	(2,740)
Mark-to-market adjustments:
Settlements/termination of positions (a)	189		387
Changes in fair value of positions in the portfolio (b)	(756)		(563)
Net loss associated with mark-to-market accounting	(567)		(176)
Acquired commodity contracts (c)	—		(39)
Other activity (d)	5		47
Commodity contract net liability as of March 31	$	(2,021)	$	(2,908)

____________

(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).

(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 March 31, 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 March 31, 2025
Source of Fair Value	Less than 1 year		1-3 years		4-5 years		Excess of 5 years		Total
	(in millions)
Prices actively quoted	$	(284)	$	(56)	$	21	$		$	(319)
Prices provided by other external sources	$	(643)	$	(116)	$	1	$		$	(758)
Prices based on models	$	(360)	$	(578)	$	(34)	$	28	$	(944)
Total	$	(1,287)	$	(750)	$	(12)	$	28	$	(2,021)

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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 March 31, 2025 were as follows:

	Balance of 2025		2026
Nuclear/Renewable/Coal Generation:
Texas	100	%	100	%
East	97	%	65	%
Natural Gas Generation:
Texas	100	%	65	%
East	100	%	100	%
West	100	%	39	%

Financial Condition

Cash Flows

Operating Cash Flows

Cash provided by operating activities totaled $599 million and $312 million for the three months ended March 31, 2025 and 2024, respectively. The favorable change of $287 million was primarily driven by a full quarter of Energy Harbor activity in 2025 and higher realized revenues net of fuel costs as compared to 2024. These favorable changes are partially offset by a $345 million decrease in net cash flows related to margin deposits as $217 million in net margin deposits related to commodity contracts supporting our hedging strategy were posted for the three months ended March 31, 2025 as compared to $128 million in net margin deposits returned for the three months ended March 31, 2024.

Investing Cash Flows

Cash used in investing activities includes:

	Three Months Ended March 31,				Increase (Decrease)
	2025		2024
	(in millions)
Capital expenditures, including LTSA prepayments	$	(265)	$	(152)	$	(113)
Nuclear fuel purchases	(242)		(220)		(22)
Growth and development expenditures	(261)		(93)		(168)
Total capital expenditures	(768)		(465)		(303)
Energy Harbor acquisition (net of cash acquired)	—		(3,070)		3,070
Net sales (purchases) of environmental allowances	(286)		(114)		(172)
Proceeds from sales of property, plant, and equipment, including nuclear fuel	—		127		(127)
Other investing activity	(7)		(6)		(1)
Cash used in investing activities	$	(1,061)	$	(3,528)	$	2,467

The change of $2.467 billion was primarily driven by $3.1 billion used to fund the Energy Harbor Merger in 2024 and partially offset by higher capital expenditures and 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) provided by financing activities includes:

	Three Months Ended March 31,				Increase (Decrease)
	2025		2024
	(in millions)
Share repurchases	$	(337)	$	(291)	$	(46)
Issuances of long-term debt	—		700		(700)
Other net long-term borrowings (repayments)	(6)		(756)		750
Net short-term borrowings (repayments)	—		500		(500)
Net borrowings (repayments) under the accounts receivable financing facilities	332		875		(543)
Dividends paid to common stockholders	(83)		(77)		(6)
Dividends paid to preferred stockholders	(21)		—		(21)
Tax withholding on stock based compensation	(50)		(12)		(38)
TRA Repurchase and tender offer — return of capital	—		(122)		122
Other financing activity	1		(24)		25
Cash (used in) provided by financing activities	$	(164)	$	793	$	(957)

The change of $957 million was primarily driven by the net borrowing of $332 million of short-term debt and accounts receivable financing in the three months ended March 31, 2025 compared to the net borrowing of $1.375 billion in the three months ended March 31, 2024 reflecting amounts borrowed to partially fund the Energy Harbor Merger.

Available Liquidity

The following table summarizes changes in available liquidity for the three months ended March 31, 2025:

	March 31, 2025		December 31, 2024		Change
	(in millions)
Cash and cash equivalents (a)	$	561	$	1,188	$	(627)
Vistra Operations Credit Facilities — Revolving Credit Facility (b)	2,217		2,162		55
Vistra Operations — Commodity-Linked Facility (c)	1,125		771		354
Total available liquidity (d)(e)	$	3,903	$	4,121	$	(218)

____________

(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 three months ended March 31, 2025.

(b)The increase in availability for the three months ended March 31, 2025 was driven by a $55 million decrease in letters of credit outstanding under the facility.

(c)As of March 31, 2025 and December 31, 2024, the borrowing bases were less than the facility limit of $1.75 billion. As of March 31, 2025, available capacity reflects the borrowing base of $1.125 billion 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 and maturity of the Vistra Operations Senior Secured Notes due May 2025 discussed in Note 9 to the Financial Statements. 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) 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 March 31, 2025, we received or posted cash, letters of credit, and Eligible Assets for commodity hedging and trading activities as follows:

•$1.025 billion in cash and Eligible Assets has been posted with counterparties as compared to $841 million posted as of December 31, 2024;

•$5 million in cash has been received from counterparties as compared to $49 million received as of December 31, 2024;

•$2.439 billion in letters of credit has been posted with counterparties as compared to $2.560 billion posted as of December 31, 2024; and

•$89 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 $23 million in federal income tax payments, $85 million in state income tax payments, and $2 million in TRA payments, offset by $14 million in state tax refunds.

For the three months ended March 31, 2025, there were no federal income tax payments, $5 million in state income tax payments, no state income tax refunds, and no TRA payments.

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). Although the period ended March 31, 2025 was not a compliance period, we would have been in compliance with the Vistra Operations Credit Agreement, Vistra Operations Commodity-Linked Credit Agreement, and Secured LOC Facilities 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 March 31, 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 $843 million in the form of letters of credit, $81 million in the form of a surety bond and $3 million of cash as of March 31, 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 $2.469 billion and zero, respectively, as of March 31, 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, 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, the Receivables Facility, 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, 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 $300 million 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 of $300 million or more, 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 greater of $300 million and 17.5% of Consolidated EBITDA 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 1.5% of total assets and $600 million 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 March 31, 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 three months ended March 31, 2025 and the year ended December 31, 2024, respectively.

	Three Months Ended March 31, 2025		Year Ended December 31, 2024
	(in millions)
Average VaR	$	292	$	236
High VaR	$	316	$	371
Low VaR	$	250	$	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 March 31, 2025, we have approximately $3.5 billion principal amount of variable rate debt consisting of the Vistra Operations Credit Facilities Term Loan B-3 Facility, the BCOP Credit Facilities and the Vistra Zero Term Loan B Facility (see Note 9 to the Financial Statements). 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 $108 million of our project-level debt through March 2045 (see Note 10 to Financial Statements). As of March 31, 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 arising from commodity contracts and hedging and trading activities totaled $2.249 billion as of March 31, 2025. Including collateral posted to us by counterparties, our net exposure was $2.140 billion, as seen in the following table that presents the distribution of credit exposure by counterparty credit quality as of March 31, 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	$	1,543	$	(11)	$	1,532	$	53	$	1,479
Texas, East, and Asset Closure segments:
Investment grade	$	89	$	393	$	482	$	17	$	465
Below investment grade or no rating	13		222		235		39		196
Texas, East, and Asset Closure segments	$	102	$	615	$	717	$	56	$	661
Totals	$	1,645	$	604	$	2,249	$	109	$	2,140

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 $431 million, or 65%, of our total net exposure of our wholesale segments as of March 31, 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 15a-15(e) of the Exchange Act) in effect at March 31, 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.

There have been no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(e) and 15a-15(e) of the Exchange Act) during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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 March 31, 2025.

Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of a Publicly Announced Program	Maximum Dollar Amount of Shares that may yet be Purchased under the Program (in millions)
January 1 - January 31, 2025	516,401	$	162.26	516,401	$	1,925
February 1 - February 28, 2025	553,243	$	153.71	553,243	$	1,840
March 1 - March 31, 2025	1,368,056	$	121.88	1,368,056	$	1,673
For the quarter ended March 31, 2025	2,437,700	$	137.66	2,437,700	$	1,673

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. We expect to complete repurchases under the Share Repurchase Program by the end of 2026.

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 March 31, 2025	$	6.75

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 March 31, 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:

Exhibits	Previously Filed With File Number*	As Exhibit
(2)	Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession
2.1	0001-38086 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.
(3(i))	Articles of Incorporation
3.1	0001-38086 Form 8-K (filed May 5, 2025)	3.1	—	Amended and Restated Certificate of Incorporation of Vistra Corp.
3.2	0001-38086 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
3.3	0001-38086 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
3.4	0001-38086 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
3.5	0001-38086 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
4.1	**		—	Thirteenth Supplemental Indenture for 5.500% Senior Notes due 2026, dated January 31, 2025, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the other subsidiary guarantors party thereto and the Trustee
4.2	**		—	Thirteenth Supplemental Indenture for 5.625% Senior Notes due 2027, dated January 31, 2025, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the other subsidiary guarantors party thereto and the Trustee

64

Exhibits	Previously Filed With File Number*	As Exhibit
4.3	**		—	Thirteenth Supplemental Indenture for 5.000% Senior Notes due 2027, dated January 31, 2025, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the other subsidiary guarantors party thereto and the Trustee
4.4	**		—	Nineteenth Supplemental Indenture for 4.300% Senior Secured Notes due 2029, 3.70% Senior Secured Notes due 2027, 5.125% Senior Secured Notes due 2025, 6.950% Senior Secured Notes due 2033, 6.000% Senior Secured Notes due 2034, 5.050% Senior Secured Notes due 2026 and 5.700% Senior Secured Notes due 2034, dated January 31, 2025, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the other subsidiary guarantors party thereto and the Trustee
4.5	**		—	Third Supplemental Indenture for 7.750% Senior Secured Notes due 2031, dated January 31, 2025, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the other subsidiary guarantors party thereto and the Trustee
4.6	**		—	Seventh Supplemental Indenture for 4.375% Senior Notes due 2029, dated January 31, 2025, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the other subsidiary guarantors party thereto and the Trustee
4.7	**		—	First Supplemental Indenture for 6.875% Senior Notes due 2032, dated January 31, 2025, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the other subsidiary guarantors party thereto and the Trustee
4.8	**		—	Fifth Supplemental Indenture for 7.233% Senior Notes due 2028, dated February 5, 2025, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the other subsidiary guarantors party thereto and the Trustee
(10)	Material Contracts
10.1	0001-38086 Form 8-K (filed May 5, 2025	10.1	—	2025 Employee Stock Purchase Plan, effective April 30, 2025
(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

65

Exhibits	Previously Filed With File Number*	As Exhibit
	XBRL Data Files
101.INS	**		—	The following financial information from Vistra Corp.'s Quarterly Report on Form 10-Q for the period ended March 31, 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, (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

66

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, Chief Accountant and Controller
	(Principal Accounting Officer)

Date: May 7, 2025

67

EX-4.1

Exhibit 4.1

THIRTEENTH SUPPLEMENTAL INDENTURE
SUBSIDIARY GUARANTEES

THIRTEENTH SUPPLEMENTAL INDENTURE (this “Supplemental Indenture”), dated as of January 31, 2025, among the subsidiary guarantors listed on Schedule I hereto (the “Guaranteeing Subsidiaries”), Vistra Operations Company LLC, a Delaware limited liability company (the “Company”), the other subsidiary guarantors party hereto and Wilmington Trust, National Association, as trustee under the indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Company has heretofore executed and delivered to the Trustee that certain Indenture (as supplemented and amended, the “Indenture”), dated as of August 22, 2018, among the Company, the Subsidiary Guarantors party thereto and the Trustee, providing for the original issuance of an aggregate principal amount of $1,000,000,000 of 5.500% Senior Notes due 2026 (the “Notes”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Company’s Obligations under the Notes and the Indenture (the “Subsidiary Guarantees”); and

WHEREAS, pursuant to Sections 4.07 and 9.01 of the Indenture, the Trustee, the Company and the other Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture.

NOW THEREFORE, in consideration of the foregoing and for good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries, the Trustee, the Company and the other Subsidiary Guarantors mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to be Bound; Guarantee. The Guaranteeing Subsidiaries hereby become a party to the Indenture as a Subsidiary Guarantor and as such will have all of the rights and be subject to all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. The Guaranteeing Subsidiaries hereby agree to be bound by all of the provisions of the Indenture applicable to a Subsidiary Guarantor and to perform all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. In furtherance of the foregoing, each Guaranteeing Subsidiary shall be deemed a Subsidiary Guarantor for purposes of Article 10 of the Indenture, including, without limitation, Section 10.02 thereof.

3. NEW YORK LAW TO GOVERN. THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

4. Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

5. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

6. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Company.

7. Ratification of Indenture; Supplemental Indenture Part of Indenture. Except as expressly amended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remain in full force and effect. This Supplemental Indenture shall form a part of the Indenture for all purposes, and every Holder of Notes heretofore or hereafter authenticated and delivered shall be bound hereby.

[Signature Page Follows]

2

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

Dated: January 31, 2025

Ambit California, LLC

Ambit Energy Holdings, LLC

Ambit Holdings, LLC

Ambit Illinois, LLC

Ambit Marketing, LLC

Ambit Midwest, LLC

Ambit New York, LLC

Ambit Northeast, LLC

Ambit Texas, LLC

Angus Solar, LLC

Big Sky Gas Holdings, LLC

Big Sky Gas LLC

BlueNet Holdings, LLC

Comanche Peak Power Company LLC

Connecticut Gas & Electric, LLC

Core Solar SPV I, LLC

Crius Energy Holdings, LLC

Crius Energy, LLC

Crius Solar Fulfillment, LLC

Deer Creek Solar I LLC

Dynegy Energy Services (East), LLC

Dynegy Energy Services Mid-Atlantic, LLC (f/k/a Everyday Energy NJ, LLC)

Dynegy Energy Services, LLC

Energy Harbor Generation LLC

Energy Harbor Holdings LLC (f/k/a Energy Harbor Corp.)

Energy Harbor LLC

Energy Harbor Nuclear Generation LLC

Energy Rewards, LLC

Energy Services Providers, LLC

Everyday Energy, LLC

Forest Grove Solar LLC

Illinois Power Marketing Company, LLC

Massachusetts Gas & Electric, LLC

Oak Hill Solar II LLC

Oakland Energy Storage 1, LLC

Pleasants Corp.

Pleasants LLC

Public Power & Utility of Maryland, LLC

Public Power & Utility of NY, LLC

Public Power, LLC (a Connecticut limited liability company)

Public Power, LLC (PA-3911142, a Pennsylvania limited liability company)

[Signature Page to Thirteenth Supplemental Indenture]

Public Power, LLC (PA-3933152, a Pennsylvania limited liability company)

Regional Energy Holdings, LLC

TriEagle 1, LLC

TriEagle 2, LLC

TriEagle Energy LP

TXU Energy Retail Company LLC

U.S. Gas & Electric, LLC

USG&E Solar, LLC

Value Based Brands LLC

Verengo, LLC

Viridian Energy NY, LLC

Viridian Energy Ohio LLC

Viridian Energy PA LLC

Viridian Energy, LLC

Viridian International Management LLC

Viridian Network, LLC

Vistra Nuclear Operations Company (f/k/a Energy Harbor Nuclear Corp.)

Vistra Preferred, LLC

Vistra Retail Operations Company, LLC (f/k/a TXU Retail Services Company, LLC)

Vistra Vision Holdings II LLC

Vistra Vision LLC

Vision Trading Company LLC

Vistra Zero 2.0, LLC

Vistra Zero LLC

Volt Asset Company, LLC,

as the Guaranteeing Subsidiaries

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

Vistra Operations Company LLC,

as the Company

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

Bellingham Power Generation LLC

Big Brown Power Company LLC

Blackstone Power Generation LLC

Calumet Energy Team, LLC

Casco Bay Energy Company, LLC

Coffeen and Western Railroad Company

[Signature Page to Thirteenth Supplemental Indenture]

Coleto Creek Energy Storage LLC

Coleto Creek Power, LLC

Dallas Power & Light Company, Inc.

Dicks Creek Power Company LLC

Dynegy Coal Holdco, LLC

Dynegy Coal Trading & Transportation, L.L.C.

Dynegy Conesville, LLC

Dynegy Killen, LLC

Dynegy Marketing and Trade, LLC

Dynegy Midwest Generation, LLC

Dynegy Operating Company

Dynegy Power Marketing, LLC

Dynegy Resources Generating Holdco, LLC

Dynegy South Bay, LLC

Dynegy Stuart, LLC

Ennis Power Company, LLC

EquiPower Resources Corp.

Fayette Power Company LLC

Generation SVC Company

Hanging Rock Power Company LLC

Hays Energy, LLC

Hopewell Power Generation, LLC

Illinois Power Generating Company

Illinois Power Resources Generating, LLC

Illinois Power Resources, LLC

Illinova Corporation

IPH, LLC

Kendall Power Company LLC

Kincaid Generation, L.L.C.

La Frontera Holdings, LLC

Lake Road Generating Company, LLC

Liberty Electric Power, LLC

Lone Star Energy Company, Inc.

Lone Star Pipeline Company, Inc.

Luminant Administrative Services Company

Luminant Coal Generation LLC

Luminant Commercial Asset Management LLC

Luminant Energy Company LLC

Luminant Energy Trading California Company

Luminant ET Services Company LLC

Luminant Gas Imports LLC

Luminant Generation Company LLC

Luminant Mining Company LLC

Luminant Power Generation, LLC

Luminant Power LLC

Masspower, LLC

Miami Fort Power Company LLC

Midlothian Energy, LLC

Milford Power Company, LLC

Morro Bay Energy Storage 1, LLC

[Signature Page to Thirteenth Supplemental Indenture]

Morro Bay Energy Storage 2, LLC

Morro Bay Power Company LLC

Moss Landing Energy Storage 4, LLC

Moss Landing Power Company LLC

NCA Land Holdings, LLC (f/k/a Maroon Farmer, LLC)

NCA Resources Development Company LLC

NEPCO Services Company

Northeastern Power Company

Oak Grove Management Company LLC

Oakland Energy Storage 2, LLC

Oakland Energy Storage 3, LLC

Oakland Power Company LLC

Ontelaunee Power Operating Company, LLC

Pleasants Energy, LLC

Sandow Power Company LLC

Sayreville Power Generation LP

Sayreville Power GP Inc.

Sayreville Power Holdings LLC

Sithe Energies, Inc.

Sithe/Independence LLC

Southwestern Electric Service Company, Inc.

Texas Electric Service Company, Inc.

Texas Energy Industries Company, Inc.

Texas Power & Light Company, Inc.

Texas Utilities Company, Inc.

Texas Utilities Electric Company, Inc

Trinidad Power Storage LLC

TXU Electric Company, Inc.

Vistra Asset Company LLC

Vistra Corporate Services Company

Vistra EP Properties Company

Vistra Finance Corp.

Vistra Insurance Solutions LLC

Vistra Vision Holdings I LLC

Vistra Vision Management LLC

VZ Development LLC

Washington Power Generation LLC

Wise County Power Company, LLC

Wise-Fuels Pipeline, Inc.

Zimmer Power Company LLC, as Subsidiary Guarantors

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

[Signature Page to Thirteenth Supplemental Indenture]

WILMINGTON TRUST, NATIONAL ASSOCIATION,
as the Trustee

By:    /s/ Latoya S Elvin    

Name:    Latoya S Elvin

Title:    Vice President

[Signature Page to Thirteenth Supplemental Indenture]

SCHEDULE I

GUARANTEEING SUBSIDIARIES

#	Name	Jurisdiction
1.	Ambit California, LLC	Delaware
2.	Ambit Energy Holdings, LLC	Texas
3.	Ambit Holdings, LLC	Texas
4.	Ambit Illinois, LLC	Illinois
5.	Ambit Marketing, LLC	Texas
6.	Ambit Midwest, LLC	Delaware
7.	Ambit New York, LLC	New York
8.	Ambit Northeast, LLC	Delaware
9.	Ambit Texas, LLC	Texas
10.	Angus Solar, LLC	Texas
11.	Big Sky Gas Holdings, LLC	Delaware
12.	Big Sky Gas LLC	Montana
13.	BlueNet Holdings, LLC	Delaware
14.	Comanche Peak Power Company LLC	Delaware
15.	Connecticut Gas & Electric, LLC	Delaware
16.	Core Solar SPV I, LLC	Delaware
17.	Crius Energy Holdings, LLC	Delaware
18.	Crius Energy, LLC	Delaware
19.	Crius Solar Fulfillment, LLC	Delaware
20.	Deer Creek Solar I LLC	Delaware
21.	Dynegy Energy Services (East), LLC	Delaware
22.	Dynegy Energy Services Mid-Atlantic, LLC (f/k/a Everyday Energy NJ, LLC)	New Jersey

23.	Dynegy Energy Services, LLC	Delaware
24.	Energy Harbor Generation LLC	Delaware
25.	Energy Harbor Holdings LLC (f/k/a Energy Harbor Corp.)	Delaware
26.	Energy Harbor LLC	Delaware
27.	Energy Harbor Nuclear Generation LLC	Delaware
28.	Energy Rewards, LLC	Nevada
29.	Energy Services Providers, LLC	Delaware
30.	Everyday Energy, LLC	Nevada
31.	Forest Grove Solar LLC	Delaware
32.	Illinois Power Marketing Company, LLC	Delaware
33.	Massachusetts Gas & Electric, LLC	Delaware
34.	Oak Hill Solar II LLC	Delaware
35.	Oakland Energy Storage 1, LLC	Delaware
36.	Pleasants Corp.	Delaware
37.	Pleasants LLC	Delaware
38.	Public Power & Utility of Maryland, LLC	Maryland
39.	Public Power & Utility of NY, LLC	Delaware
40.	Public Power, LLC (a Connecticut limited liability company)	Connecticut
41.	Public Power, LLC (PA-3911142, a Pennsylvania limited liability company)	Pennsylvania
42.	Public Power, LLC (PA-3933152, a Pennsylvania limited liability company)	Pennsylvania
43.	Regional Energy Holdings, LLC	Delaware
44.	TriEagle 1, LLC	Nevada
45.	TriEagle 2, LLC	Nevada
46.	TriEagle Energy LP	Texas
47.	TXU Energy Retail Company LLC	Texas

48.	U.S. Gas & Electric, LLC	Delaware
49.	USG&E Solar, LLC	Delaware
50.	Value Based Brands LLC	Texas
51.	Verengo, LLC	Delaware
52.	Viridian Energy NY, LLC	New York
53.	Viridian Energy Ohio LLC	Nevada
54.	Viridian Energy PA LLC	Nevada
55.	Viridian Energy, LLC	Nevada
56.	Viridian International Management LLC	Delaware
57.	Viridian Network, LLC	Delaware
58.	Vistra Nuclear Operations Company (f/k/a Energy Harbor Nuclear Corp.)	Delaware
59.	Vistra Preferred, LLC	Delaware
60.	Vistra Retail Operations Company, LLC (f/k/a TXU Retail Services Company, LLC)	Delaware
61.	Vistra Vision Holdings II LLC	Delaware
62.	Vistra Vision LLC	Delaware
63.	Vision Trading Company LLC	Delaware
64.	Vistra Zero 2.0, LLC	Delaware
65.	Vistra Zero LLC	Delaware
66.	Volt Asset Company, LLC	Delaware

EX-4.2

Exhibit 4.2

THIRTEENTH SUPPLEMENTAL INDENTURE
SUBSIDIARY GUARANTEES

THIRTEENTH SUPPLEMENTAL INDENTURE (this “Supplemental Indenture”), dated as of January 31, 2025, among the subsidiary guarantors listed on Schedule I hereto (the “Guaranteeing Subsidiaries”), Vistra Operations Company LLC, a Delaware limited liability company (the “Company”), the other subsidiary guarantors party hereto and Wilmington Trust, National Association, as trustee under the indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Company has heretofore executed and delivered to the Trustee that certain Indenture (as supplemented and amended, the “Indenture”), dated as of February 6, 2019, among the Company, the Subsidiary Guarantors party thereto and the Trustee, providing for the original issuance of an aggregate principal amount of $1,300,000,000 of 5.625% Senior Notes due 2027 (the “Notes”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Company’s Obligations under the Notes and the Indenture (the “Subsidiary Guarantees”); and

WHEREAS, pursuant to Sections 4.07 and 9.01 of the Indenture, the Trustee, the Company and the other Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture.

NOW THEREFORE, in consideration of the foregoing and for good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries, the Trustee, the Company and the other Subsidiary Guarantors mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to be Bound; Guarantee. The Guaranteeing Subsidiaries hereby become a party to the Indenture as a Subsidiary Guarantor and as such will have all of the rights and be subject to all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. The Guaranteeing Subsidiaries hereby agree to be bound by all of the provisions of the Indenture applicable to a Subsidiary Guarantor and to perform all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. In furtherance of the foregoing, each Guaranteeing Subsidiary shall be deemed a Subsidiary Guarantor for purposes of Article 10 of the Indenture, including, without limitation, Section 10.02 thereof.

3. NEW YORK LAW TO GOVERN. THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

4. Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

5. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

6. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Company.

7. Ratification of Indenture; Supplemental Indenture Part of Indenture. Except as expressly amended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remain in full force and effect. This Supplemental Indenture shall form a part of the Indenture for all purposes, and every Holder of Notes heretofore or hereafter authenticated and delivered shall be bound hereby.

[Signature Page Follows]

2

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

Dated: January 31, 2025

Ambit California, LLC

Ambit Energy Holdings, LLC

Ambit Holdings, LLC

Ambit Illinois, LLC

Ambit Marketing, LLC

Ambit Midwest, LLC

Ambit New York, LLC

Ambit Northeast, LLC

Ambit Texas, LLC

Angus Solar, LLC

Big Sky Gas Holdings, LLC

Big Sky Gas LLC

BlueNet Holdings, LLC

Comanche Peak Power Company LLC

Connecticut Gas & Electric, LLC

Core Solar SPV I, LLC

Crius Energy Holdings, LLC

Crius Energy, LLC

Crius Solar Fulfillment, LLC

Deer Creek Solar I LLC

Dynegy Energy Services (East), LLC

Dynegy Energy Services Mid-Atlantic, LLC (f/k/a Everyday Energy NJ, LLC)

Dynegy Energy Services, LLC

Energy Harbor Generation LLC

Energy Harbor Holdings LLC (f/k/a Energy Harbor Corp.)

Energy Harbor LLC

Energy Harbor Nuclear Generation LLC

Energy Rewards, LLC

Energy Services Providers, LLC

Everyday Energy, LLC

Forest Grove Solar LLC

Illinois Power Marketing Company, LLC

Massachusetts Gas & Electric, LLC

Oak Hill Solar II LLC

Oakland Energy Storage 1, LLC

Pleasants Corp.

Pleasants LLC

Public Power & Utility of Maryland, LLC

Public Power & Utility of NY, LLC

Public Power, LLC (a Connecticut limited liability company)

Public Power, LLC (PA-3911142, a Pennsylvania limited liability company)

[Signature Page to Thirteenth Supplemental Indenture]

Public Power, LLC (PA-3933152, a Pennsylvania limited liability company)

Regional Energy Holdings, LLC

TriEagle 1, LLC

TriEagle 2, LLC

TriEagle Energy LP

TXU Energy Retail Company LLC

U.S. Gas & Electric, LLC

USG&E Solar, LLC

Value Based Brands LLC

Verengo, LLC

Viridian Energy NY, LLC

Viridian Energy Ohio LLC

Viridian Energy PA LLC

Viridian Energy, LLC

Viridian International Management LLC

Viridian Network, LLC

Vistra Nuclear Operations Company (f/k/a Energy Harbor Nuclear Corp.)

Vistra Preferred, LLC

Vistra Retail Operations Company, LLC (f/k/a TXU Retail Services Company, LLC)

Vistra Vision Holdings II LLC

Vistra Vision LLC

Vision Trading Company LLC

Vistra Zero 2.0, LLC

Vistra Zero LLC

Volt Asset Company, LLC,

as the Guaranteeing Subsidiaries

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

Vistra Operations Company LLC,

as the Company

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

Bellingham Power Generation LLC

Big Brown Power Company LLC

Blackstone Power Generation LLC

Calumet Energy Team, LLC

Casco Bay Energy Company, LLC

Coffeen and Western Railroad Company

[Signature Page to Thirteenth Supplemental Indenture]

Coleto Creek Energy Storage LLC

Coleto Creek Power, LLC

Dallas Power & Light Company, Inc.

Dicks Creek Power Company LLC

Dynegy Coal Holdco, LLC

Dynegy Coal Trading & Transportation, L.L.C.

Dynegy Conesville, LLC

Dynegy Killen, LLC

Dynegy Marketing and Trade, LLC

Dynegy Midwest Generation, LLC

Dynegy Operating Company

Dynegy Power Marketing, LLC

Dynegy Resources Generating Holdco, LLC

Dynegy South Bay, LLC

Dynegy Stuart, LLC

Ennis Power Company, LLC

EquiPower Resources Corp.

Fayette Power Company LLC

Generation SVC Company

Hanging Rock Power Company LLC

Hays Energy, LLC

Hopewell Power Generation, LLC

Illinois Power Generating Company

Illinois Power Resources Generating, LLC

Illinois Power Resources, LLC

Illinova Corporation

IPH, LLC

Kendall Power Company LLC

Kincaid Generation, L.L.C.

La Frontera Holdings, LLC

Lake Road Generating Company, LLC

Liberty Electric Power, LLC

Lone Star Energy Company, Inc.

Lone Star Pipeline Company, Inc.

Luminant Administrative Services Company

Luminant Coal Generation LLC

Luminant Commercial Asset Management LLC

Luminant Energy Company LLC

Luminant Energy Trading California Company

Luminant ET Services Company LLC

Luminant Gas Imports LLC

Luminant Generation Company LLC

Luminant Mining Company LLC

Luminant Power Generation, LLC

Luminant Power LLC

Masspower, LLC

Miami Fort Power Company LLC

Midlothian Energy, LLC

Milford Power Company, LLC

Morro Bay Energy Storage 1, LLC

[Signature Page to Thirteenth Supplemental Indenture]

Morro Bay Energy Storage 2, LLC

Morro Bay Power Company LLC

Moss Landing Energy Storage 4, LLC

Moss Landing Power Company LLC

NCA Land Holdings, LLC (f/k/a Maroon Farmer, LLC)

NCA Resources Development Company LLC

NEPCO Services Company

Northeastern Power Company

Oak Grove Management Company LLC

Oakland Energy Storage 2, LLC

Oakland Energy Storage 3, LLC

Oakland Power Company LLC

Ontelaunee Power Operating Company, LLC

Pleasants Energy, LLC

Sandow Power Company LLC

Sayreville Power Generation LP

Sayreville Power GP Inc.

Sayreville Power Holdings LLC

Sithe Energies, Inc.

Sithe/Independence LLC

Southwestern Electric Service Company, Inc.

Texas Electric Service Company, Inc.

Texas Energy Industries Company, Inc.

Texas Power & Light Company, Inc.

Texas Utilities Company, Inc.

Texas Utilities Electric Company, Inc

Trinidad Power Storage LLC

TXU Electric Company, Inc.

Vistra Asset Company LLC

Vistra Corporate Services Company

Vistra EP Properties Company

Vistra Finance Corp.

Vistra Insurance Solutions LLC

Vistra Vision Holdings I LLC

Vistra Vision Management LLC

VZ Development LLC

Washington Power Generation LLC

Wise County Power Company, LLC

Wise-Fuels Pipeline, Inc.

Zimmer Power Company LLC, as Subsidiary Guarantors

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

[Signature Page to Thirteenth Supplemental Indenture]

WILMINGTON TRUST, NATIONAL ASSOCIATION,
as the Trustee

By:    /s/ Latoya S Elvin    

Name:    Latoya S Elvin

Title:    Vice President

[Signature Page to Thirteenth Supplemental Indenture]

SCHEDULE I

GUARANTEEING SUBSIDIARIES

#	Name	Jurisdiction
1.	Ambit California, LLC	Delaware
2.	Ambit Energy Holdings, LLC	Texas
3.	Ambit Holdings, LLC	Texas
4.	Ambit Illinois, LLC	Illinois
5.	Ambit Marketing, LLC	Texas
6.	Ambit Midwest, LLC	Delaware
7.	Ambit New York, LLC	New York
8.	Ambit Northeast, LLC	Delaware
9.	Ambit Texas, LLC	Texas
10.	Angus Solar, LLC	Texas
11.	Big Sky Gas Holdings, LLC	Delaware
12.	Big Sky Gas LLC	Montana
13.	BlueNet Holdings, LLC	Delaware
14.	Comanche Peak Power Company LLC	Delaware
15.	Connecticut Gas & Electric, LLC	Delaware
16.	Core Solar SPV I, LLC	Delaware
17.	Crius Energy Holdings, LLC	Delaware
18.	Crius Energy, LLC	Delaware
19.	Crius Solar Fulfillment, LLC	Delaware
20.	Deer Creek Solar I LLC	Delaware
21.	Dynegy Energy Services (East), LLC	Delaware
22.	Dynegy Energy Services Mid-Atlantic, LLC (f/k/a Everyday Energy NJ, LLC)	New Jersey

23.	Dynegy Energy Services, LLC	Delaware
24.	Energy Harbor Generation LLC	Delaware
25.	Energy Harbor Holdings LLC (f/k/a Energy Harbor Corp.)	Delaware
26.	Energy Harbor LLC	Delaware
27.	Energy Harbor Nuclear Generation LLC	Delaware
28.	Energy Rewards, LLC	Nevada
29.	Energy Services Providers, LLC	Delaware
30.	Everyday Energy, LLC	Nevada
31.	Forest Grove Solar LLC	Delaware
32.	Illinois Power Marketing Company, LLC	Delaware
33.	Massachusetts Gas & Electric, LLC	Delaware
34.	Oak Hill Solar II LLC	Delaware
35.	Oakland Energy Storage 1, LLC	Delaware
36.	Pleasants Corp.	Delaware
37.	Pleasants LLC	Delaware
38.	Public Power & Utility of Maryland, LLC	Maryland
39.	Public Power & Utility of NY, LLC	Delaware
40.	Public Power, LLC (a Connecticut limited liability company)	Connecticut
41.	Public Power, LLC (PA-3911142, a Pennsylvania limited liability company)	Pennsylvania
42.	Public Power, LLC (PA-3933152, a Pennsylvania limited liability company)	Pennsylvania
43.	Regional Energy Holdings, LLC	Delaware
44.	TriEagle 1, LLC	Nevada
45.	TriEagle 2, LLC	Nevada
46.	TriEagle Energy LP	Texas
47.	TXU Energy Retail Company LLC	Texas

48.	U.S. Gas & Electric, LLC	Delaware
49.	USG&E Solar, LLC	Delaware
50.	Value Based Brands LLC	Texas
51.	Verengo, LLC	Delaware
52.	Viridian Energy NY, LLC	New York
53.	Viridian Energy Ohio LLC	Nevada
54.	Viridian Energy PA LLC	Nevada
55.	Viridian Energy, LLC	Nevada
56.	Viridian International Management LLC	Delaware
57.	Viridian Network, LLC	Delaware
58.	Vistra Nuclear Operations Company (f/k/a Energy Harbor Nuclear Corp.)	Delaware
59.	Vistra Preferred, LLC	Delaware
60.	Vistra Retail Operations Company, LLC (f/k/a TXU Retail Services Company, LLC)	Delaware
61.	Vistra Vision Holdings II LLC	Delaware
62.	Vistra Vision LLC	Delaware
63.	Vision Trading Company LLC	Delaware
64.	Vistra Zero 2.0, LLC	Delaware
65.	Vistra Zero LLC	Delaware
66.	Volt Asset Company, LLC	Delaware

EX-4.3

Exhibit 4.3

THIRTEENTH SUPPLEMENTAL INDENTURE
SUBSIDIARY GUARANTEES

THIRTEENTH SUPPLEMENTAL INDENTURE (this “Supplemental Indenture”), dated as of January 31, 2025, among the subsidiary guarantors listed on Schedule I hereto (the “Guaranteeing Subsidiaries”), Vistra Operations Company LLC, a Delaware limited liability company (the “Company”), the other subsidiary guarantors party hereto and Wilmington Trust, National Association, as trustee under the indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Company has heretofore executed and delivered to the Trustee that certain Indenture (as supplemented and amended, the “Indenture”), dated as of June 21, 2019, among the Company, the Subsidiary Guarantors party thereto and the Trustee, providing for the original issuance of an aggregate principal amount of $1,300,000,000 of 5.00% Senior Notes due 2027 (the “Notes”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Company’s Obligations under the Notes and the Indenture (the “Subsidiary Guarantees”); and

WHEREAS, pursuant to Sections 4.07 and 9.01 of the Indenture, the Trustee, the Company and the other Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture.

NOW THEREFORE, in consideration of the foregoing and for good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries, the Trustee, the Company and the other Subsidiary Guarantors mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to be Bound; Guarantee. The Guaranteeing Subsidiaries hereby become a party to the Indenture as a Subsidiary Guarantor and as such will have all of the rights and be subject to all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. The Guaranteeing Subsidiaries hereby agree to be bound by all of the provisions of the Indenture applicable to a Subsidiary Guarantor and to perform all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. In furtherance of the foregoing, each Guaranteeing Subsidiary shall be deemed a Subsidiary Guarantor for purposes of Article 10 of the Indenture, including, without limitation, Section 10.02 thereof.

3. NEW YORK LAW TO GOVERN. THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

4. Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

5. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

6. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Company.

7. Ratification of Indenture; Supplemental Indenture Part of Indenture. Except as expressly amended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remain in full force and effect. This Supplemental Indenture shall form a part of the Indenture for all purposes, and every Holder of Notes heretofore or hereafter authenticated and delivered shall be bound hereby.

[Signature Page Follows]

2

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

Dated: January 31, 2025

Ambit California, LLC

Ambit Energy Holdings, LLC

Ambit Holdings, LLC

Ambit Illinois, LLC

Ambit Marketing, LLC

Ambit Midwest, LLC

Ambit New York, LLC

Ambit Northeast, LLC

Ambit Texas, LLC

Angus Solar, LLC

Big Sky Gas Holdings, LLC

Big Sky Gas LLC

BlueNet Holdings, LLC

Comanche Peak Power Company LLC

Connecticut Gas & Electric, LLC

Core Solar SPV I, LLC

Crius Energy Holdings, LLC

Crius Energy, LLC

Crius Solar Fulfillment, LLC

Deer Creek Solar I LLC

Dynegy Energy Services (East), LLC

Dynegy Energy Services Mid-Atlantic, LLC (f/k/a Everyday Energy NJ, LLC)

Dynegy Energy Services, LLC

Energy Harbor Generation LLC

Energy Harbor Holdings LLC (f/k/a Energy Harbor Corp.)

Energy Harbor LLC

Energy Harbor Nuclear Generation LLC

Energy Rewards, LLC

Energy Services Providers, LLC

Everyday Energy, LLC

Forest Grove Solar LLC

Illinois Power Marketing Company, LLC

Massachusetts Gas & Electric, LLC

Oak Hill Solar II LLC

Oakland Energy Storage 1, LLC

Pleasants Corp.

Pleasants LLC

Public Power & Utility of Maryland, LLC

Public Power & Utility of NY, LLC

Public Power, LLC (a Connecticut limited liability company)

Public Power, LLC (PA-3911142, a Pennsylvania limited liability company)

[Signature Page to Thirteenth Supplemental Indenture]

Public Power, LLC (PA-3933152, a Pennsylvania limited liability company)

Regional Energy Holdings, LLC

TriEagle 1, LLC

TriEagle 2, LLC

TriEagle Energy LP

TXU Energy Retail Company LLC

U.S. Gas & Electric, LLC

USG&E Solar, LLC

Value Based Brands LLC

Verengo, LLC

Viridian Energy NY, LLC

Viridian Energy Ohio LLC

Viridian Energy PA LLC

Viridian Energy, LLC

Viridian International Management LLC

Viridian Network, LLC

Vistra Nuclear Operations Company (f/k/a Energy Harbor Nuclear Corp.)

Vistra Preferred, LLC

Vistra Retail Operations Company, LLC (f/k/a TXU Retail Services Company, LLC)

Vistra Vision Holdings II LLC

Vistra Vision LLC

Vision Trading Company LLC

Vistra Zero 2.0, LLC

Vistra Zero LLC

Volt Asset Company, LLC,

as the Guaranteeing Subsidiaries

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

Vistra Operations Company LLC,

as the Company

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

Bellingham Power Generation LLC

Big Brown Power Company LLC

Blackstone Power Generation LLC

Calumet Energy Team, LLC

Casco Bay Energy Company, LLC

Coffeen and Western Railroad Company

[Signature Page to Thirteenth Supplemental Indenture]

Coleto Creek Energy Storage LLC

Coleto Creek Power, LLC

Dallas Power & Light Company, Inc.

Dicks Creek Power Company LLC

Dynegy Coal Holdco, LLC

Dynegy Coal Trading & Transportation, L.L.C.

Dynegy Conesville, LLC

Dynegy Killen, LLC

Dynegy Marketing and Trade, LLC

Dynegy Midwest Generation, LLC

Dynegy Operating Company

Dynegy Power Marketing, LLC

Dynegy Resources Generating Holdco, LLC

Dynegy South Bay, LLC

Dynegy Stuart, LLC

Ennis Power Company, LLC

EquiPower Resources Corp.

Fayette Power Company LLC

Generation SVC Company

Hanging Rock Power Company LLC

Hays Energy, LLC

Hopewell Power Generation, LLC

Illinois Power Generating Company

Illinois Power Resources Generating, LLC

Illinois Power Resources, LLC

Illinova Corporation

IPH, LLC

Kendall Power Company LLC

Kincaid Generation, L.L.C.

La Frontera Holdings, LLC

Lake Road Generating Company, LLC

Liberty Electric Power, LLC

Lone Star Energy Company, Inc.

Lone Star Pipeline Company, Inc.

Luminant Administrative Services Company

Luminant Coal Generation LLC

Luminant Commercial Asset Management LLC

Luminant Energy Company LLC

Luminant Energy Trading California Company

Luminant ET Services Company LLC

Luminant Gas Imports LLC

Luminant Generation Company LLC

Luminant Mining Company LLC

Luminant Power Generation, LLC

Luminant Power LLC

Masspower, LLC

Miami Fort Power Company LLC

Midlothian Energy, LLC

Milford Power Company, LLC

Morro Bay Energy Storage 1, LLC

[Signature Page to Thirteenth Supplemental Indenture]

Morro Bay Energy Storage 2, LLC

Morro Bay Power Company LLC

Moss Landing Energy Storage 4, LLC

Moss Landing Power Company LLC

NCA Land Holdings, LLC (f/k/a Maroon Farmer, LLC)

NCA Resources Development Company LLC

NEPCO Services Company

Northeastern Power Company

Oak Grove Management Company LLC

Oakland Energy Storage 2, LLC

Oakland Energy Storage 3, LLC

Oakland Power Company LLC

Ontelaunee Power Operating Company, LLC

Pleasants Energy, LLC

Sandow Power Company LLC

Sayreville Power Generation LP

Sayreville Power GP Inc.

Sayreville Power Holdings LLC

Sithe Energies, Inc.

Sithe/Independence LLC

Southwestern Electric Service Company, Inc.

Texas Electric Service Company, Inc.

Texas Energy Industries Company, Inc.

Texas Power & Light Company, Inc.

Texas Utilities Company, Inc.

Texas Utilities Electric Company, Inc

Trinidad Power Storage LLC

TXU Electric Company, Inc.

Vistra Asset Company LLC

Vistra Corporate Services Company

Vistra EP Properties Company

Vistra Finance Corp.

Vistra Insurance Solutions LLC

Vistra Vision Holdings I LLC

Vistra Vision Management LLC

VZ Development LLC

Washington Power Generation LLC

Wise County Power Company, LLC

Wise-Fuels Pipeline, Inc.

Zimmer Power Company LLC, as Subsidiary Guarantors

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

[Signature Page to Thirteenth Supplemental Indenture]

WILMINGTON TRUST, NATIONAL ASSOCIATION,
as the Trustee

By:    /s/ Latoya S Elvin    

Name:    Latoya S Elvin

Title:    Vice President

[Signature Page to Thirteenth Supplemental Indenture]

SCHEDULE I

GUARANTEEING SUBSIDIARIES

#	Name	Jurisdiction
1.	Ambit California, LLC	Delaware
2.	Ambit Energy Holdings, LLC	Texas
3.	Ambit Holdings, LLC	Texas
4.	Ambit Illinois, LLC	Illinois
5.	Ambit Marketing, LLC	Texas
6.	Ambit Midwest, LLC	Delaware
7.	Ambit New York, LLC	New York
8.	Ambit Northeast, LLC	Delaware
9.	Ambit Texas, LLC	Texas
10.	Angus Solar, LLC	Texas
11.	Big Sky Gas Holdings, LLC	Delaware
12.	Big Sky Gas LLC	Montana
13.	BlueNet Holdings, LLC	Delaware
14.	Comanche Peak Power Company LLC	Delaware
15.	Connecticut Gas & Electric, LLC	Delaware
16.	Core Solar SPV I, LLC	Delaware
17.	Crius Energy Holdings, LLC	Delaware
18.	Crius Energy, LLC	Delaware
19.	Crius Solar Fulfillment, LLC	Delaware
20.	Deer Creek Solar I LLC	Delaware
21.	Dynegy Energy Services (East), LLC	Delaware
22.	Dynegy Energy Services Mid-Atlantic, LLC (f/k/a Everyday Energy NJ, LLC)	New Jersey

23.	Dynegy Energy Services, LLC	Delaware
24.	Energy Harbor Generation LLC	Delaware
25.	Energy Harbor Holdings LLC (f/k/a Energy Harbor Corp.)	Delaware
26.	Energy Harbor LLC	Delaware
27.	Energy Harbor Nuclear Generation LLC	Delaware
28.	Energy Rewards, LLC	Nevada
29.	Energy Services Providers, LLC	Delaware
30.	Everyday Energy, LLC	Nevada
31.	Forest Grove Solar LLC	Delaware
32.	Illinois Power Marketing Company, LLC	Delaware
33.	Massachusetts Gas & Electric, LLC	Delaware
34.	Oak Hill Solar II LLC	Delaware
35.	Oakland Energy Storage 1, LLC	Delaware
36.	Pleasants Corp.	Delaware
37.	Pleasants LLC	Delaware
38.	Public Power & Utility of Maryland, LLC	Maryland
39.	Public Power & Utility of NY, LLC	Delaware
40.	Public Power, LLC (a Connecticut limited liability company)	Connecticut
41.	Public Power, LLC (PA-3911142, a Pennsylvania limited liability company)	Pennsylvania
42.	Public Power, LLC (PA-3933152, a Pennsylvania limited liability company)	Pennsylvania
43.	Regional Energy Holdings, LLC	Delaware
44.	TriEagle 1, LLC	Nevada
45.	TriEagle 2, LLC	Nevada
46.	TriEagle Energy LP	Texas
47.	TXU Energy Retail Company LLC	Texas

48.	U.S. Gas & Electric, LLC	Delaware
49.	USG&E Solar, LLC	Delaware
50.	Value Based Brands LLC	Texas
51.	Verengo, LLC	Delaware
52.	Viridian Energy NY, LLC	New York
53.	Viridian Energy Ohio LLC	Nevada
54.	Viridian Energy PA LLC	Nevada
55.	Viridian Energy, LLC	Nevada
56.	Viridian International Management LLC	Delaware
57.	Viridian Network, LLC	Delaware
58.	Vistra Nuclear Operations Company (f/k/a Energy Harbor Nuclear Corp.)	Delaware
59.	Vistra Preferred, LLC	Delaware
60.	Vistra Retail Operations Company, LLC (f/k/a TXU Retail Services Company, LLC)	Delaware
61.	Vistra Vision Holdings II LLC	Delaware
62.	Vistra Vision LLC	Delaware
63.	Vision Trading Company LLC	Delaware
64.	Vistra Zero 2.0, LLC	Delaware
65.	Vistra Zero LLC	Delaware
66.	Volt Asset Company, LLC	Delaware

EX-4.4

Exhibit 4.4

NINETEENTH SUPPLEMENTAL INDENTURE
SUBSIDIARY GUARANTEES

NINETEENTH SUPPLEMENTAL INDENTURE (this “Supplemental Indenture”), dated as of January 31, 2025, among the subsidiary guarantors listed on Schedule I hereto (the “Guaranteeing Subsidiaries”), Vistra Operations Company LLC, a Delaware limited liability company (the “Company”), the other subsidiary guarantors party hereto and Wilmington Trust, National Association, as trustee under the indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Company has heretofore executed and delivered to the Trustee (i) that certain Indenture (the “Base Indenture”), dated as of June 11, 2019, among the Company and the Trustee, (ii) that certain Supplemental Indenture (the “First Supplement”), dated as of June 11, 2019, among the Company, the Subsidiary Guarantors party thereto and the Trustee, providing for the original issuance of an aggregate principal amount of $1,200,000,000 of 3.55% Senior Secured Notes due 2024 and aggregate principal amount of $800,000,000 of 4.30% Senior Secured Notes due 2029 (the “2029 Notes”), (iii) that certain Second Supplemental Indenture, dated as of August 30, 2019, among the Company, the Subsidiary Guarantors party thereto and the Trustee (the “Second Supplement”), (iv) that certain Third Supplemental Indenture, dated as of October 25, 2019, among the Company, the Subsidiary Guarantors party thereto and the Trustee (the “Third Supplement”), (v) that certain Fourth Supplemental Indenture, dated as of November 15, 2019, among the Company, the Subsidiary Guarantors party thereto and the Trustee, providing for the issuance of $800,000,000 of 3.70% Senior Secured Notes due 2027 (the “2027 Notes”) (the “Fourth Supplement”), (vi) that certain Fifth Supplemental Indenture, dated as of January 31, 2020, among the Company, the Subsidiary Guarantors party thereto and the Trustee (the “Fifth Supplement”), (vii) that certain Sixth Supplemental Indenture, dated as of March 26, 2020, among the Company, the Subsidiary Guarantors party thereto and the Trustee (the “Sixth Supplement”), (viii) that certain Seventh Supplemental Indenture, dated as of October 7, 2020, among the Company, the Subsidiary Guarantors party thereto and the Trustee (the “Seventh Supplement”), (ix) that certain Eighth Supplemental Indenture, dated as of January 8, 2021, among the Company, the Subsidiary Guarantors party thereto and the Trustee (the “Eighth Supplement”), (x) that certain Ninth Supplemental Indenture, dated as of July 29, 2021, among the Company, the Subsidiary Guarantors party thereto and the Trustee (the “Ninth Supplement”), (xi) that certain Tenth Supplemental Indenture, dated as of December 28, 2021, among the Company, the Subsidiary Guarantors party thereto and the Trustee (the “Tenth Supplement”), (xii) that certain Eleventh Supplemental Indenture, dated as of May 13, 2022, among the Company, the Subsidiary Guarantors party thereto and the Trustee, providing for the original issuance of an aggregate principal amount of $400,000,000 of 4.875% Senior Secured Notes due 2024 and aggregate principal amount of $1,100,000,000 of 5.125% Senior Secured Notes due 2025 (the “2025 Notes”) (the “Eleventh Supplement”), that certain Twelfth Supplemental Indenture, dated as of December 15, 2022, among the Company, the Subsidiary Guarantors party thereto and the Trustee (the “Twelfth Supplement”), that certain Thirteenth Supplemental Indenture, dated as of July 31, 2023, among the Company, the Subsidiary Guarantors party thereto and the Trustee (the “Thirteenth Supplement”), that certain Fourteenth Supplemental Indenture, dated as of September 26, 2023, among the Company, the Subsidiary Guarantors party thereto and the Trustee, providing for the issuance of an aggregate principal amount of $1,050,000,000 of 6.950% Senior Secured Notes due 2033 (the “2033 Notes”) (the “Fourteenth Supplement”), that certain Fifteenth Supplemental Indenture, dated as of October 20, 2023, among the Company, the Subsidiary Guarantors party thereto and the Trustee (the “Fifteenth Supplement”), that certain Sixteenth Supplemental Indenture, dated as of March 29, 2024, among the Company, the Subsidiary Guarantors party thereto and the Trustee (the

“Sixteenth Supplement”), that certain Seventeenth Supplemental Indenture, dated as of April 12, 2024, among the Company, the Subsidiary Guarantors party thereto and the Trustee, providing for the issuance of an aggregate principal amount of $500,000,000 of 6.000% Senior Secured Notes due 2034 (the “2034 6.000% Notes”) (the “Seventeenth Supplement”), and that certain Eighteenth Supplemental Indenture, dated as of December 4, 2024, among the Company, the Subsidiary Guarantors party thereto and the Trustee, providing for the issuance of an aggregate principal amount of $500,000,000 of 5.050% Senior Secured Notes due 2026 (the “2026 Notes”) and aggregate principal amount of $750,000,000 of 5.700% Senior Secured Notes due 2034 (the “2034 5.700% Notes” and, collectively with the 2029 Notes, the 2027 Notes, the 2025 Notes, the 2033 Notes, the 2034 6.000% Notes and the 2026 Notes, the “Notes”) (the “Eighteenth Supplement” and, collectively with the Base Indenture, the First Supplement, the Second Supplement, the Third Supplement, the Fourth Supplement, the Fifth Supplement, the Sixth Supplement, the Seventh Supplement, the Eighth Supplement, the Ninth Supplement, the Tenth Supplement, the Eleventh Supplement, the Twelfth Supplement, the Thirteenth Supplement, the Fourteenth Supplement, the Fifteenth Supplement, the Sixteenth Supplement and the Seventeenth Supplement, the “Indenture”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Company’s Obligations under the Notes and the Indenture (the “Subsidiary Guarantees”); and

WHEREAS, pursuant to Section 9.01 of the Base Indenture and Sections 4.07 and 9.01 of the First Supplement, the Fourth Supplement, the Eleventh Supplement, the Fourteenth Supplement, the Seventeenth Supplement and the Eighteenth Supplement, the Trustee, the Company and the other Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture.

NOW THEREFORE, in consideration of the foregoing and for good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries, the Trustee, the Company and the other Subsidiary Guarantors mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Base Indenture, the First Supplement, the Fourth Supplement, the Eleventh Supplement, the Fourteenth Supplement, the Seventeenth Supplement or the Eighteenth Supplement, as applicable.

2. Agreement to be Bound; Guarantee. The Guaranteeing Subsidiaries hereby become a party to the Indenture as a Subsidiary Guarantor and as such will have all of the rights and be subject to all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. The Guaranteeing Subsidiaries hereby agree to be bound by all of the provisions of the Indenture applicable to a Subsidiary Guarantor and to perform all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. In furtherance of the foregoing, each Guaranteeing Subsidiary shall be deemed a Subsidiary Guarantor for purposes of Article 10 of the First Supplement, the Fourth Supplement, the Eleventh Supplement, the Fourteenth Supplement, the Seventeenth Supplement and the Eighteenth Supplement, including, without limitation, Section 10.02 thereof.

3. NEW YORK LAW TO GOVERN. THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

4. Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

2

5. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

6. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Company.

7. Ratification of Indenture; Supplemental Indenture Part of Indenture. Except as expressly amended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remain in full force and effect. This Supplemental Indenture shall form a part of the Indenture for all purposes, and every Holder of Notes heretofore or hereafter authenticated and delivered shall be bound hereby.

[Signature Page Follows]

3

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

Dated: January 31, 2025

Ambit California, LLC

Ambit Energy Holdings, LLC

Ambit Holdings, LLC

Ambit Illinois, LLC

Ambit Marketing, LLC

Ambit Midwest, LLC

Ambit New York, LLC

Ambit Northeast, LLC

Ambit Texas, LLC

Angus Solar, LLC

Big Sky Gas Holdings, LLC

Big Sky Gas LLC

BlueNet Holdings, LLC

Comanche Peak Power Company LLC

Connecticut Gas & Electric, LLC

Core Solar SPV I, LLC

Crius Energy Holdings, LLC

Crius Energy, LLC

Crius Solar Fulfillment, LLC

Deer Creek Solar I LLC

Dynegy Energy Services (East), LLC

Dynegy Energy Services Mid-Atlantic, LLC (f/k/a Everyday Energy NJ, LLC)

Dynegy Energy Services, LLC

Energy Harbor Generation LLC

Energy Harbor Holdings LLC (f/k/a Energy Harbor Corp.)

Energy Harbor LLC

Energy Harbor Nuclear Generation LLC

Energy Rewards, LLC

Energy Services Providers, LLC

Everyday Energy, LLC

Forest Grove Solar LLC

Illinois Power Marketing Company, LLC

Massachusetts Gas & Electric, LLC

Oak Hill Solar II LLC

Oakland Energy Storage 1, LLC

Pleasants Corp.

Pleasants LLC

Public Power & Utility of Maryland, LLC

Public Power & Utility of NY, LLC

Public Power, LLC (a Connecticut limited liability company)

Public Power, LLC (PA-3911142, a Pennsylvania limited liability company)

[Signature Page to Nineteenth Supplemental Indenture]

Public Power, LLC (PA-3933152, a Pennsylvania limited liability company)

Regional Energy Holdings, LLC

TriEagle 1, LLC

TriEagle 2, LLC

TriEagle Energy LP

TXU Energy Retail Company LLC

U.S. Gas & Electric, LLC

USG&E Solar, LLC

Value Based Brands LLC

Verengo, LLC

Viridian Energy NY, LLC

Viridian Energy Ohio LLC

Viridian Energy PA LLC

Viridian Energy, LLC

Viridian International Management LLC

Viridian Network, LLC

Vistra Nuclear Operations Company (f/k/a Energy Harbor Nuclear Corp.)

Vistra Preferred, LLC

Vistra Retail Operations Company, LLC (f/k/a TXU Retail Services Company, LLC)

Vistra Vision Holdings II LLC

Vistra Vision LLC

Vision Trading Company LLC

Vistra Zero 2.0, LLC

Vistra Zero LLC

Volt Asset Company, LLC,

as the Guaranteeing Subsidiaries

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

Vistra Operations Company LLC,

as the Company

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

Bellingham Power Generation LLC

Big Brown Power Company LLC

Blackstone Power Generation LLC

Calumet Energy Team, LLC

Casco Bay Energy Company, LLC

[Signature Page to Nineteenth Supplemental Indenture]

Coffeen and Western Railroad Company

Coleto Creek Energy Storage LLC

Coleto Creek Power, LLC

Dallas Power & Light Company, Inc.

Dicks Creek Power Company LLC

Dynegy Coal Holdco, LLC

Dynegy Coal Trading & Transportation, L.L.C.

Dynegy Conesville, LLC

Dynegy Killen, LLC

Dynegy Marketing and Trade, LLC

Dynegy Midwest Generation, LLC

Dynegy Operating Company

Dynegy Power Marketing, LLC

Dynegy Resources Generating Holdco, LLC

Dynegy South Bay, LLC

Dynegy Stuart, LLC

Ennis Power Company, LLC

EquiPower Resources Corp.

Fayette Power Company LLC

Generation SVC Company

Hanging Rock Power Company LLC

Hays Energy, LLC

Hopewell Power Generation, LLC

Illinois Power Generating Company

Illinois Power Resources Generating, LLC

Illinois Power Resources, LLC

Illinova Corporation

IPH, LLC

Kendall Power Company LLC

Kincaid Generation, L.L.C.

La Frontera Holdings, LLC

Lake Road Generating Company, LLC

Liberty Electric Power, LLC

Lone Star Energy Company, Inc.

Lone Star Pipeline Company, Inc.

Luminant Administrative Services Company

Luminant Coal Generation LLC

Luminant Commercial Asset Management LLC

Luminant Energy Company LLC

Luminant Energy Trading California Company

Luminant ET Services Company LLC

Luminant Gas Imports LLC

Luminant Generation Company LLC

Luminant Mining Company LLC

Luminant Power Generation, LLC

Luminant Power LLC

Masspower, LLC

Miami Fort Power Company LLC

Midlothian Energy, LLC

Milford Power Company, LLC

[Signature Page to Nineteenth Supplemental Indenture]

Morro Bay Energy Storage 1, LLC

Morro Bay Energy Storage 2, LLC

Morro Bay Power Company LLC

Moss Landing Energy Storage 4, LLC

Moss Landing Power Company LLC

NCA Land Holdings, LLC (f/k/a Maroon Farmer, LLC)

NCA Resources Development Company LLC

NEPCO Services Company

Northeastern Power Company

Oak Grove Management Company LLC

Oakland Energy Storage 2, LLC

Oakland Energy Storage 3, LLC

Oakland Power Company LLC

Ontelaunee Power Operating Company, LLC

Pleasants Energy, LLC

Sandow Power Company LLC

Sayreville Power Generation LP

Sayreville Power GP Inc.

Sayreville Power Holdings LLC

Sithe Energies, Inc.

Sithe/Independence LLC

Southwestern Electric Service Company, Inc.

Texas Electric Service Company, Inc.

Texas Energy Industries Company, Inc.

Texas Power & Light Company, Inc.

Texas Utilities Company, Inc.

Texas Utilities Electric Company, Inc

Trinidad Power Storage LLC

TXU Electric Company, Inc.

Vistra Asset Company LLC

Vistra Corporate Services Company

Vistra EP Properties Company

Vistra Finance Corp.

Vistra Insurance Solutions LLC

Vistra Vision Holdings I LLC

Vistra Vision Management LLC

VZ Development LLC

Washington Power Generation LLC

Wise County Power Company, LLC

Wise-Fuels Pipeline, Inc.

Zimmer Power Company LLC, as Subsidiary Guarantors

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

[Signature Page to Nineteenth Supplemental Indenture]

WILMINGTON TRUST, NATIONAL ASSOCIATION,
as the Trustee

By:    /s/ Latoya S Elvin    

Name:    Latoya S Elvin

Title:    Vice President

[Signature Page to Nineteenth Supplemental Indenture]

SCHEDULE I

GUARANTEEING SUBSIDIARIES

#	Name	Jurisdiction
1.	Ambit California, LLC	Delaware
2.	Ambit Energy Holdings, LLC	Texas
3.	Ambit Holdings, LLC	Texas
4.	Ambit Illinois, LLC	Illinois
5.	Ambit Marketing, LLC	Texas
6.	Ambit Midwest, LLC	Delaware
7.	Ambit New York, LLC	New York
8.	Ambit Northeast, LLC	Delaware
9.	Ambit Texas, LLC	Texas
10.	Angus Solar, LLC	Texas
11.	Big Sky Gas Holdings, LLC	Delaware
12.	Big Sky Gas LLC	Montana
13.	BlueNet Holdings, LLC	Delaware
14.	Comanche Peak Power Company LLC	Delaware
15.	Connecticut Gas & Electric, LLC	Delaware
16.	Core Solar SPV I, LLC	Delaware
17.	Crius Energy Holdings, LLC	Delaware
18.	Crius Energy, LLC	Delaware
19.	Crius Solar Fulfillment, LLC	Delaware
20.	Deer Creek Solar I LLC	Delaware
21.	Dynegy Energy Services (East), LLC	Delaware
22.	Dynegy Energy Services Mid-Atlantic, LLC (f/k/a Everyday Energy NJ, LLC)	New Jersey

23.	Dynegy Energy Services, LLC	Delaware
24.	Energy Harbor Generation LLC	Delaware
25.	Energy Harbor Holdings LLC (f/k/a Energy Harbor Corp.)	Delaware
26.	Energy Harbor LLC	Delaware
27.	Energy Harbor Nuclear Generation LLC	Delaware
28.	Energy Rewards, LLC	Nevada
29.	Energy Services Providers, LLC	Delaware
30.	Everyday Energy, LLC	Nevada
31.	Forest Grove Solar LLC	Delaware
32.	Illinois Power Marketing Company, LLC	Delaware
33.	Massachusetts Gas & Electric, LLC	Delaware
34.	Oak Hill Solar II LLC	Delaware
35.	Oakland Energy Storage 1, LLC	Delaware
36.	Pleasants Corp.	Delaware
37.	Pleasants LLC	Delaware
38.	Public Power & Utility of Maryland, LLC	Maryland
39.	Public Power & Utility of NY, LLC	Delaware
40.	Public Power, LLC (a Connecticut limited liability company)	Connecticut
41.	Public Power, LLC (PA-3911142, a Pennsylvania limited liability company)	Pennsylvania
42.	Public Power, LLC (PA-3933152, a Pennsylvania limited liability company)	Pennsylvania
43.	Regional Energy Holdings, LLC	Delaware
44.	TriEagle 1, LLC	Nevada
45.	TriEagle 2, LLC	Nevada
46.	TriEagle Energy LP	Texas
47.	TXU Energy Retail Company LLC	Texas

48.	U.S. Gas & Electric, LLC	Delaware
49.	USG&E Solar, LLC	Delaware
50.	Value Based Brands LLC	Texas
51.	Verengo, LLC	Delaware
52.	Viridian Energy NY, LLC	New York
53.	Viridian Energy Ohio LLC	Nevada
54.	Viridian Energy PA LLC	Nevada
55.	Viridian Energy, LLC	Nevada
56.	Viridian International Management LLC	Delaware
57.	Viridian Network, LLC	Delaware
58.	Vistra Nuclear Operations Company (f/k/a Energy Harbor Nuclear Corp.)	Delaware
59.	Vistra Preferred, LLC	Delaware
60.	Vistra Retail Operations Company, LLC (f/k/a TXU Retail Services Company, LLC)	Delaware
61.	Vistra Vision Holdings II LLC	Delaware
62.	Vistra Vision LLC	Delaware
63.	Vision Trading Company LLC	Delaware
64.	Vistra Zero 2.0, LLC	Delaware
65.	Vistra Zero LLC	Delaware
66.	Volt Asset Company, LLC	Delaware

EX-4.5

Exhibit 4.5

THIRD SUPPLEMENTAL INDENTURE
SUBSIDIARY GUARANTEES

THIRD SUPPLEMENTAL INDENTURE (this “Supplemental Indenture”), dated as January 31, 2025, among the subsidiary guarantors listed on Schedule I hereto (the “Guaranteeing Subsidiaries”), Vistra Operations Company LLC, a Delaware limited liability company (the “Company”), the other subsidiary guarantors party hereto and Wilmington Trust, National Association, as trustee under the indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Company has heretofore executed and delivered to the Trustee that certain Indenture (as supplemented and amended, the “Indenture”), dated as of September 26, 2023, among the Company, the Subsidiary Guarantors party thereto and the Trustee, providing for the issuance of an aggregate principal amount of $1,450,000,000 of 7.750% Senior Notes due 2031 (the “Notes”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Company’s Obligations under the Notes and the Indenture (the “Subsidiary Guarantees”); and

WHEREAS, pursuant to Sections 4.07 and 9.01 of the Indenture, the Trustee, the Company and the other Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture.

NOW THEREFORE, in consideration of the foregoing and for good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries, the Trustee, the Company and the other Subsidiary Guarantors mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to be Bound; Guarantee. The Guaranteeing Subsidiaries hereby become a party to the Indenture as a Subsidiary Guarantor and as such will have all of the rights and be subject to all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. The Guaranteeing Subsidiaries hereby agree to be bound by all of the provisions of the Indenture applicable to a Subsidiary Guarantor and to perform all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. In furtherance of the foregoing, each Guaranteeing Subsidiary shall be deemed a Subsidiary Guarantor for purposes of Article 10 of the Indenture, including, without limitation, Section 10.02 thereof.

3. NEW YORK LAW TO GOVERN. THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

4. Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

5. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

6. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Company.

7. Ratification of Indenture; Supplemental Indenture Part of Indenture. Except as expressly amended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remain in full force and effect. This Supplemental Indenture shall form a part of the Indenture for all purposes, and every Holder of Notes heretofore or hereafter authenticated and delivered shall be bound hereby.

[Signature Page Follows]

2

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

Dated: January 31, 2025

Ambit California, LLC

Ambit Energy Holdings, LLC

Ambit Holdings, LLC

Ambit Illinois, LLC

Ambit Marketing, LLC

Ambit Midwest, LLC

Ambit New York, LLC

Ambit Northeast, LLC

Ambit Texas, LLC

Angus Solar, LLC

Big Sky Gas Holdings, LLC

Big Sky Gas LLC

BlueNet Holdings, LLC

Comanche Peak Power Company LLC

Connecticut Gas & Electric, LLC

Core Solar SPV I, LLC

Crius Energy Holdings, LLC

Crius Energy, LLC

Crius Solar Fulfillment, LLC

Deer Creek Solar I LLC

Dynegy Energy Services (East), LLC

Dynegy Energy Services Mid-Atlantic, LLC (f/k/a Everyday Energy NJ, LLC)

Dynegy Energy Services, LLC

Energy Harbor Generation LLC

Energy Harbor Holdings LLC (f/k/a Energy Harbor Corp.)

Energy Harbor LLC

Energy Harbor Nuclear Generation LLC

Energy Rewards, LLC

Energy Services Providers, LLC

Everyday Energy, LLC

Forest Grove Solar LLC

Illinois Power Marketing Company, LLC

Massachusetts Gas & Electric, LLC

Oak Hill Solar II LLC

Oakland Energy Storage 1, LLC

Pleasants Corp.

Pleasants LLC

Public Power & Utility of Maryland, LLC

Public Power & Utility of NY, LLC

Public Power, LLC (a Connecticut limited liability company)

Public Power, LLC (PA-3911142, a Pennsylvania limited liability company)

[Signature Page to Third Supplemental Indenture]

Public Power, LLC (PA-3933152, a Pennsylvania limited liability company)

Regional Energy Holdings, LLC

TriEagle 1, LLC

TriEagle 2, LLC

TriEagle Energy LP

TXU Energy Retail Company LLC

U.S. Gas & Electric, LLC

USG&E Solar, LLC

Value Based Brands LLC

Verengo, LLC

Viridian Energy NY, LLC

Viridian Energy Ohio LLC

Viridian Energy PA LLC

Viridian Energy, LLC

Viridian International Management LLC

Viridian Network, LLC

Vistra Nuclear Operations Company (f/k/a Energy Harbor Nuclear Corp.)

Vistra Preferred, LLC

Vistra Retail Operations Company, LLC (f/k/a TXU Retail Services Company, LLC)

Vistra Vision Holdings II LLC

Vistra Vision LLC

Vision Trading Company LLC

Vistra Zero 2.0, LLC

Vistra Zero LLC

Volt Asset Company, LLC,

as the Guaranteeing Subsidiaries

By:    /s William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

Vistra Operations Company LLC,

as the Company

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

Bellingham Power Generation LLC

Big Brown Power Company LLC

Blackstone Power Generation LLC

Calumet Energy Team, LLC

Casco Bay Energy Company, LLC

Coffeen and Western Railroad Company

[Signature Page to Third Supplemental Indenture]

Coleto Creek Energy Storage LLC

Coleto Creek Power, LLC

Dallas Power & Light Company, Inc.

Dicks Creek Power Company LLC

Dynegy Coal Holdco, LLC

Dynegy Coal Trading & Transportation, L.L.C.

Dynegy Conesville, LLC

Dynegy Killen, LLC

Dynegy Marketing and Trade, LLC

Dynegy Midwest Generation, LLC

Dynegy Operating Company

Dynegy Power Marketing, LLC

Dynegy Resources Generating Holdco, LLC

Dynegy South Bay, LLC

Dynegy Stuart, LLC

Ennis Power Company, LLC

EquiPower Resources Corp.

Fayette Power Company LLC

Generation SVC Company

Hanging Rock Power Company LLC

Hays Energy, LLC

Hopewell Power Generation, LLC

Illinois Power Generating Company

Illinois Power Resources Generating, LLC

Illinois Power Resources, LLC

Illinova Corporation

IPH, LLC

Kendall Power Company LLC

Kincaid Generation, L.L.C.

La Frontera Holdings, LLC

Lake Road Generating Company, LLC

Liberty Electric Power, LLC

Lone Star Energy Company, Inc.

Lone Star Pipeline Company, Inc.

Luminant Administrative Services Company

Luminant Coal Generation LLC

Luminant Commercial Asset Management LLC

Luminant Energy Company LLC

Luminant Energy Trading California Company

Luminant ET Services Company LLC

Luminant Gas Imports LLC

Luminant Generation Company LLC

Luminant Mining Company LLC

Luminant Power Generation, LLC

Luminant Power LLC

Masspower, LLC

Miami Fort Power Company LLC

Midlothian Energy, LLC

Milford Power Company, LLC

Morro Bay Energy Storage 1, LLC

[Signature Page to Third Supplemental Indenture]

Morro Bay Energy Storage 2, LLC

Morro Bay Power Company LLC

Moss Landing Energy Storage 4, LLC

Moss Landing Power Company LLC

NCA Land Holdings, LLC (f/k/a Maroon Farmer, LLC)

NCA Resources Development Company LLC

NEPCO Services Company

Northeastern Power Company

Oak Grove Management Company LLC

Oakland Energy Storage 2, LLC

Oakland Energy Storage 3, LLC

Oakland Power Company LLC

Ontelaunee Power Operating Company, LLC

Pleasants Energy, LLC

Sandow Power Company LLC

Sayreville Power Generation LP

Sayreville Power GP Inc.

Sayreville Power Holdings LLC

Sithe Energies, Inc.

Sithe/Independence LLC

Southwestern Electric Service Company, Inc.

Texas Electric Service Company, Inc.

Texas Energy Industries Company, Inc.

Texas Power & Light Company, Inc.

Texas Utilities Company, Inc.

Texas Utilities Electric Company, Inc

Trinidad Power Storage LLC

TXU Electric Company, Inc.

Vistra Asset Company LLC

Vistra Corporate Services Company

Vistra EP Properties Company

Vistra Finance Corp.

Vistra Insurance Solutions LLC

Vistra Vision Holdings I LLC

Vistra Vision Management LLC

VZ Development LLC

Washington Power Generation LLC

Wise County Power Company, LLC

Wise-Fuels Pipeline, Inc.

Zimmer Power Company LLC, as Subsidiary Guarantors

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

[Signature Page to Third Supplemental Indenture]

WILMINGTON TRUST, NATIONAL ASSOCIATION,
as the Trustee

By:    /s/ Latoya S Elvin    

Name:    Latoya S Elvin

Title:    Vice President

[Signature Page to Third Supplemental Indenture]

SCHEDULE I

GUARANTEEING SUBSIDIARIES

#	Name	Jurisdiction
1.	Ambit California, LLC	Delaware
2.	Ambit Energy Holdings, LLC	Texas
3.	Ambit Holdings, LLC	Texas
4.	Ambit Illinois, LLC	Illinois
5.	Ambit Marketing, LLC	Texas
6.	Ambit Midwest, LLC	Delaware
7.	Ambit New York, LLC	New York
8.	Ambit Northeast, LLC	Delaware
9.	Ambit Texas, LLC	Texas
10.	Angus Solar, LLC	Texas
11	Big Sky Gas Holdings, LLC	Delaware
12.	Big Sky Gas LLC	Montana
13.	BlueNet Holdings, LLC	Delaware
14.	Comanche Peak Power Company LLC	Delaware
15.	Connecticut Gas & Electric, LLC	Delaware
16.	Core Solar SPV I, LLC	Delaware
17.	Crius Energy Holdings, LLC	Delaware
18.	Crius Energy, LLC	Delaware
19.	Crius Solar Fulfillment, LLC	Delaware
20.	Deer Creek Solar I LLC	Delaware
21.	Dynegy Energy Services (East), LLC	Delaware
22.	Dynegy Energy Services Mid-Atlantic, LLC (f/k/a Everyday Energy NJ, LLC)	New Jersey

23.	Dynegy Energy Services, LLC	Delaware
24.	Energy Harbor Generation LLC	Delaware
25.	Energy Harbor Holdings LLC (f/k/a Energy Harbor Corp.)	Delaware
26.	Energy Harbor LLC	Delaware
27.	Energy Harbor Nuclear Generation LLC	Delaware
28.	Energy Rewards, LLC	Nevada
29.	Energy Services Providers, LLC	Delaware
30.	Everyday Energy, LLC	Nevada
31.	Forest Grove Solar LLC	Delaware
32.	Illinois Power Marketing Company, LLC	Delaware
33.	Massachusetts Gas & Electric, LLC	Delaware
34.	Oak Hill Solar II LLC	Delaware
35.	Oakland Energy Storage 1, LLC	Delaware
36.	Pleasants Corp.	Delaware
37.	Pleasants LLC	Delaware
38.	Public Power & Utility of Maryland, LLC	Maryland
39.	Public Power & Utility of NY, LLC	Delaware
40.	Public Power, LLC (a Connecticut limited liability company)	Connecticut
41.	Public Power, LLC (PA-3911142, a Pennsylvania limited liability company)	Pennsylvania
42.	Public Power, LLC (PA-3933152, a Pennsylvania limited liability company)	Pennsylvania
43.	Regional Energy Holdings, LLC	Delaware
44.	TriEagle 1, LLC	Nevada
45.	TriEagle 2, LLC	Nevada
46.	TriEagle Energy LP	Texas
47.	TXU Energy Retail Company LLC	Texas

48.	U.S. Gas & Electric, LLC	Delaware
49.	USG&E Solar, LLC	Delaware
50.	Value Based Brands LLC	Texas
51.	Verengo, LLC	Delaware
52.	Viridian Energy NY, LLC	New York
53.	Viridian Energy Ohio LLC	Nevada
54.	Viridian Energy PA LLC	Nevada
55.	Viridian Energy, LLC	Nevada
56.	Viridian International Management LLC	Delaware
57.	Viridian Network, LLC	Delaware
58.	Vistra Nuclear Operations Company (f/k/a Energy Harbor Nuclear Corp.)	Delaware
59.	Vistra Preferred, LLC	Delaware
60.	Vistra Retail Operations Company, LLC (f/k/a TXU Retail Services Company, LLC)	Delaware
61.	Vistra Vision Holdings II LLC	Delaware
62.	Vistra Vision LLC	Delaware
63.	Vision Trading Company LLC	Delaware
64.	Vistra Zero 2.0, LLC	Delaware
65.	Vistra Zero LLC	Delaware
66.	Volt Asset Company, LLC	Delaware

EX-4.6

Exhibit 4.6

SEVENTH SUPPLEMENTAL INDENTURE
SUBSIDIARY GUARANTEES

SEVENTH SUPPLEMENTAL INDENTURE (this “Supplemental Indenture”), dated as of January 31, 2025, among the subsidiary guarantors listed on Schedule I hereto (the “Guaranteeing Subsidiaries”), Vistra Operations Company LLC, a Delaware limited liability company (the “Company”), the other subsidiary guarantors party hereto and Wilmington Trust, National Association, as trustee under the indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Company has heretofore executed and delivered to the Trustee that certain Indenture (as supplemented and amended, the “Indenture”), dated as of May 10, 2021, among the Company, the Subsidiary Guarantors party thereto and the Trustee, providing for the original issuance of an aggregate principal amount of $1,250,000,000 of 4.375% Senior Notes due 2029 (the “Notes”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Company’s Obligations under the Notes and the Indenture (the “Subsidiary Guarantees”); and

WHEREAS, pursuant to Sections 4.07 and 9.01 of the Indenture, the Trustee, the Company and the other Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture.

NOW THEREFORE, in consideration of the foregoing and for good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries, the Trustee, the Company and the other Subsidiary Guarantors mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to be Bound; Guarantee. The Guaranteeing Subsidiaries hereby become a party to the Indenture as a Subsidiary Guarantor and as such will have all of the rights and be subject to all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. The Guaranteeing Subsidiaries hereby agree to be bound by all of the provisions of the Indenture applicable to a Subsidiary Guarantor and to perform all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. In furtherance of the foregoing, each Guaranteeing Subsidiary shall be deemed a Subsidiary Guarantor for purposes of Article 10 of the Indenture, including, without limitation, Section 10.02 thereof.

3. NEW YORK LAW TO GOVERN. THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

4. Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

5. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

6. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Company.

7. Ratification of Indenture; Supplemental Indenture Part of Indenture. Except as expressly amended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remain in full force and effect. This Supplemental Indenture shall form a part of the Indenture for all purposes, and every Holder of Notes heretofore or hereafter authenticated and delivered shall be bound hereby.

[Signature Page Follows]

2

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

Dated: January 31, 2025

Ambit California, LLC

Ambit Energy Holdings, LLC

Ambit Holdings, LLC

Ambit Illinois, LLC

Ambit Marketing, LLC

Ambit Midwest, LLC

Ambit New York, LLC

Ambit Northeast, LLC

Ambit Texas, LLC

Angus Solar, LLC

Big Sky Gas Holdings, LLC

Big Sky Gas LLC

BlueNet Holdings, LLC

Comanche Peak Power Company LLC

Connecticut Gas & Electric, LLC

Core Solar SPV I, LLC

Crius Energy Holdings, LLC

Crius Energy, LLC

Crius Solar Fulfillment, LLC

Deer Creek Solar I LLC

Dynegy Energy Services (East), LLC

Dynegy Energy Services Mid-Atlantic, LLC (f/k/a Everyday Energy NJ, LLC)

Dynegy Energy Services, LLC

Energy Harbor Generation LLC

Energy Harbor Holdings LLC (f/k/a Energy Harbor Corp.)

Energy Harbor LLC

Energy Harbor Nuclear Generation LLC

Energy Rewards, LLC

Energy Services Providers, LLC

Everyday Energy, LLC

Forest Grove Solar LLC

Illinois Power Marketing Company, LLC

Massachusetts Gas & Electric, LLC

Oak Hill Solar II LLC

Oakland Energy Storage 1, LLC

Pleasants Corp.

Pleasants LLC

Public Power & Utility of Maryland, LLC

Public Power & Utility of NY, LLC

Public Power, LLC (a Connecticut limited liability company)

Public Power, LLC (PA-3911142, a Pennsylvania limited liability company)

[Signature Page to Seventh Supplemental Indenture]

Public Power, LLC (PA-3933152, a Pennsylvania limited liability company)

Regional Energy Holdings, LLC

TriEagle 1, LLC

TriEagle 2, LLC

TriEagle Energy LP

TXU Energy Retail Company LLC

U.S. Gas & Electric, LLC

USG&E Solar, LLC

Value Based Brands LLC

Verengo, LLC

Viridian Energy NY, LLC

Viridian Energy Ohio LLC

Viridian Energy PA LLC

Viridian Energy, LLC

Viridian International Management LLC

Viridian Network, LLC

Vistra Nuclear Operations Company (f/k/a Energy Harbor Nuclear Corp.)

Vistra Preferred, LLC

Vistra Retail Operations Company, LLC (f/k/a TXU Retail Services Company, LLC)

Vistra Vision Holdings II LLC

Vistra Vision LLC

Vision Trading Company LLC

Vistra Zero 2.0, LLC

Vistra Zero LLC

Volt Asset Company, LLC,

as the Guaranteeing Subsidiaries

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

Vistra Operations Company LLC,

as the Company

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

Bellingham Power Generation LLC

Big Brown Power Company LLC

Blackstone Power Generation LLC

Calumet Energy Team, LLC

Casco Bay Energy Company, LLC

Coffeen and Western Railroad Company

[Signature Page to Seventh Supplemental Indenture]

Coleto Creek Energy Storage LLC

Coleto Creek Power, LLC

Dallas Power & Light Company, Inc.

Dicks Creek Power Company LLC

Dynegy Coal Holdco, LLC

Dynegy Coal Trading & Transportation, L.L.C.

Dynegy Conesville, LLC

Dynegy Killen, LLC

Dynegy Marketing and Trade, LLC

Dynegy Midwest Generation, LLC

Dynegy Operating Company

Dynegy Power Marketing, LLC

Dynegy Resources Generating Holdco, LLC

Dynegy South Bay, LLC

Dynegy Stuart, LLC

Ennis Power Company, LLC

EquiPower Resources Corp.

Fayette Power Company LLC

Generation SVC Company

Hanging Rock Power Company LLC

Hays Energy, LLC

Hopewell Power Generation, LLC

Illinois Power Generating Company

Illinois Power Resources Generating, LLC

Illinois Power Resources, LLC

Illinova Corporation

IPH, LLC

Kendall Power Company LLC

Kincaid Generation, L.L.C.

La Frontera Holdings, LLC

Lake Road Generating Company, LLC

Liberty Electric Power, LLC

Lone Star Energy Company, Inc.

Lone Star Pipeline Company, Inc.

Luminant Administrative Services Company

Luminant Coal Generation LLC

Luminant Commercial Asset Management LLC

Luminant Energy Company LLC

Luminant Energy Trading California Company

Luminant ET Services Company LLC

Luminant Gas Imports LLC

Luminant Generation Company LLC

Luminant Mining Company LLC

Luminant Power Generation, LLC

Luminant Power LLC

Masspower, LLC

Miami Fort Power Company LLC

Midlothian Energy, LLC

Milford Power Company, LLC

Morro Bay Energy Storage 1, LLC

[Signature Page to Seventh Supplemental Indenture]

Morro Bay Energy Storage 2, LLC

Morro Bay Power Company LLC

Moss Landing Energy Storage 4, LLC

Moss Landing Power Company LLC

NCA Land Holdings, LLC (f/k/a Maroon Farmer, LLC)

NCA Resources Development Company LLC

NEPCO Services Company

Northeastern Power Company

Oak Grove Management Company LLC

Oakland Energy Storage 2, LLC

Oakland Energy Storage 3, LLC

Oakland Power Company LLC

Ontelaunee Power Operating Company, LLC

Pleasants Energy, LLC

Sandow Power Company LLC

Sayreville Power Generation LP

Sayreville Power GP Inc.

Sayreville Power Holdings LLC

Sithe Energies, Inc.

Sithe/Independence LLC

Southwestern Electric Service Company, Inc.

Texas Electric Service Company, Inc.

Texas Energy Industries Company, Inc.

Texas Power & Light Company, Inc.

Texas Utilities Company, Inc.

Texas Utilities Electric Company, Inc

Trinidad Power Storage LLC

TXU Electric Company, Inc.

Vistra Asset Company LLC

Vistra Corporate Services Company

Vistra EP Properties Company

Vistra Finance Corp.

Vistra Insurance Solutions LLC

Vistra Vision Holdings I LLC

Vistra Vision Management LLC

VZ Development LLC

Washington Power Generation LLC

Wise County Power Company, LLC

Wise-Fuels Pipeline, Inc.

Zimmer Power Company LLC, as Subsidiary Guarantors

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

[Signature Page to Seventh Supplemental Indenture]

WILMINGTON TRUST, NATIONAL ASSOCIATION,
as the Trustee

By:    /s/ Latoya S Elvin    

Name:    Latoya S Elvin

Title:    Vice President

[Signature Page to Seventh Supplemental Indenture]

SCHEDULE I

GUARANTEEING SUBSIDIARIES

#	Name	Jurisdiction
1.	Ambit California, LLC	Delaware
2.	Ambit Energy Holdings, LLC	Texas
3.	Ambit Holdings, LLC	Texas
4.	Ambit Illinois, LLC	Illinois
5.	Ambit Marketing, LLC	Texas
6.	Ambit Midwest, LLC	Delaware
7.	Ambit New York, LLC	New York
8.	Ambit Northeast, LLC	Delaware
9.	Ambit Texas, LLC	Texas
10.	Angus Solar, LLC	Texas
11.	Big Sky Gas Holdings, LLC	Delaware
12.	Big Sky Gas LLC	Montana
13.	BlueNet Holdings, LLC	Delaware
14.	Comanche Peak Power Company LLC	Delaware
15.	Connecticut Gas & Electric, LLC	Delaware
16.	Core Solar SPV I, LLC	Delaware
17.	Crius Energy Holdings, LLC	Delaware
18.	Crius Energy, LLC	Delaware
19.	Crius Solar Fulfillment, LLC	Delaware
20.	Deer Creek Solar I LLC	Delaware
21.	Dynegy Energy Services (East), LLC	Delaware
22.	Dynegy Energy Services Mid-Atlantic, LLC (f/k/a Everyday Energy NJ, LLC)	New Jersey

23.	Dynegy Energy Services, LLC	Delaware
24.	Energy Harbor Generation LLC	Delaware
25.	Energy Harbor Holdings LLC (f/k/a Energy Harbor Corp.)	Delaware
26.	Energy Harbor LLC	Delaware
27.	Energy Harbor Nuclear Generation LLC	Delaware
28.	Energy Rewards, LLC	Nevada
29.	Energy Services Providers, LLC	Delaware
30.	Everyday Energy, LLC	Nevada
31.	Forest Grove Solar LLC	Delaware
32.	Illinois Power Marketing Company, LLC	Delaware
33.	Massachusetts Gas & Electric, LLC	Delaware
34.	Oak Hill Solar II LLC	Delaware
35.	Oakland Energy Storage 1, LLC	Delaware
36.	Pleasants Corp.	Delaware
37.	Pleasants LLC	Delaware
38.	Public Power & Utility of Maryland, LLC	Maryland
39.	Public Power & Utility of NY, LLC	Delaware
40.	Public Power, LLC (a Connecticut limited liability company)	Connecticut
41.	Public Power, LLC (PA-3911142, a Pennsylvania limited liability company)	Pennsylvania
42.	Public Power, LLC (PA-3933152, a Pennsylvania limited liability company)	Pennsylvania
43.	Regional Energy Holdings, LLC	Delaware
44.	TriEagle 1, LLC	Nevada
45.	TriEagle 2, LLC	Nevada
46.	TriEagle Energy LP	Texas
47.	TXU Energy Retail Company LLC	Texas

48.	U.S. Gas & Electric, LLC	Delaware
49.	USG&E Solar, LLC	Delaware
50.	Value Based Brands LLC	Texas
51.	Verengo, LLC	Delaware
52.	Viridian Energy NY, LLC	New York
53.	Viridian Energy Ohio LLC	Nevada
54.	Viridian Energy PA LLC	Nevada
55.	Viridian Energy, LLC	Nevada
56.	Viridian International Management LLC	Delaware
57.	Viridian Network, LLC	Delaware
58.	Vistra Nuclear Operations Company (f/k/a Energy Harbor Nuclear Corp.)	Delaware
59.	Vistra Preferred, LLC	Delaware
60.	Vistra Retail Operations Company, LLC (f/k/a TXU Retail Services Company, LLC)	Delaware
61.	Vistra Vision Holdings II LLC	Delaware
62.	Vistra Vision LLC	Delaware
63.	Vision Trading Company LLC	Delaware
64.	Vistra Zero 2.0, LLC	Delaware
65.	Vistra Zero LLC	Delaware
66.	Volt Asset Company, LLC	Delaware

EX-4.7

Exhibit 4.7

FIRST SUPPLEMENTAL INDENTURE
SUBSIDIARY GUARANTEES

FIRST SUPPLEMENTAL INDENTURE (this “Supplemental Indenture”), dated as of January 31, 2025, among the subsidiary guarantors listed on Schedule I hereto (the “Guaranteeing Subsidiaries”), Vistra Operations Company LLC, a Delaware limited liability company (the “Company”), the other subsidiary guarantors party hereto and Wilmington Trust, National Association, as trustee under the indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Company has heretofore executed and delivered to the Trustee that certain Indenture (as supplemented and amended, the “Indenture”), dated as of April 12, 2024, among the Company, the Subsidiary Guarantors party thereto and the Trustee, providing for the issuance of an aggregate principal amount of $1,000,000,000 of 6.875% Senior Notes due 2032 (the “Notes”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Company’s Obligations under the Notes and the Indenture (the “Subsidiary Guarantees”); and

WHEREAS, pursuant to Sections 4.07 and 9.01 of the Indenture, the Trustee, the Company and the other Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture.

NOW THEREFORE, in consideration of the foregoing and for good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries, the Trustee, the Company and the other Subsidiary Guarantors mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to be Bound; Guarantee. The Guaranteeing Subsidiaries hereby become a party to the Indenture as a Subsidiary Guarantor and as such will have all of the rights and be subject to all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. The Guaranteeing Subsidiaries hereby agree to be bound by all of the provisions of the Indenture applicable to a Subsidiary Guarantor and to perform all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. In furtherance of the foregoing, each Guaranteeing Subsidiary shall be deemed a Subsidiary Guarantor for purposes of Article 10 of the Indenture, including, without limitation, Section 10.02 thereof.

3. NEW YORK LAW TO GOVERN. THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

4. Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

5. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

6. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Company.

7. Ratification of Indenture; Supplemental Indenture Part of Indenture. Except as expressly amended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remain in full force and effect. This Supplemental Indenture shall form a part of the Indenture for all purposes, and every Holder of Notes heretofore or hereafter authenticated and delivered shall be bound hereby.

[Signature Page Follows]

2

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

Dated: January 31, 2025

Ambit California, LLC

Ambit Energy Holdings, LLC

Ambit Holdings, LLC

Ambit Illinois, LLC

Ambit Marketing, LLC

Ambit Midwest, LLC

Ambit New York, LLC

Ambit Northeast, LLC

Ambit Texas, LLC

Angus Solar, LLC

Big Sky Gas Holdings, LLC

Big Sky Gas LLC

BlueNet Holdings, LLC

Comanche Peak Power Company LLC

Connecticut Gas & Electric, LLC

Core Solar SPV I, LLC

Crius Energy Holdings, LLC

Crius Energy, LLC

Crius Solar Fulfillment, LLC

Deer Creek Solar I LLC

Dynegy Energy Services (East), LLC

Dynegy Energy Services Mid-Atlantic, LLC (f/k/a Everyday Energy NJ, LLC)

Dynegy Energy Services, LLC

Energy Harbor Generation LLC

Energy Harbor Holdings LLC (f/k/a Energy Harbor Corp.)

Energy Harbor LLC

Energy Harbor Nuclear Generation LLC

Energy Rewards, LLC

Energy Services Providers, LLC

Everyday Energy, LLC

Forest Grove Solar LLC

Illinois Power Marketing Company, LLC

Massachusetts Gas & Electric, LLC

Oak Hill Solar II LLC

Oakland Energy Storage 1, LLC

Pleasants Corp.

Pleasants LLC

Public Power & Utility of Maryland, LLC

Public Power & Utility of NY, LLC

Public Power, LLC (a Connecticut limited liability company)

Public Power, LLC (PA-3911142, a Pennsylvania limited liability company)

[Signature Page to First Supplemental Indenture]

Public Power, LLC (PA-3933152, a Pennsylvania limited liability company)

Regional Energy Holdings, LLC

TriEagle 1, LLC

TriEagle 2, LLC

TriEagle Energy LP

TXU Energy Retail Company LLC

U.S. Gas & Electric, LLC

USG&E Solar, LLC

Value Based Brands LLC

Verengo, LLC

Viridian Energy NY, LLC

Viridian Energy Ohio LLC

Viridian Energy PA LLC

Viridian Energy, LLC

Viridian International Management LLC

Viridian Network, LLC

Vistra Nuclear Operations Company (f/k/a Energy Harbor Nuclear Corp.)

Vistra Preferred, LLC

Vistra Retail Operations Company, LLC (f/k/a TXU Retail Services Company, LLC)

Vistra Vision Holdings II LLC

Vistra Vision LLC

Vision Trading Company LLC

Vistra Zero 2.0, LLC

Vistra Zero LLC

Volt Asset Company, LLC,

as the Guaranteeing Subsidiaries

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

Vistra Operations Company LLC,

as the Company

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

Bellingham Power Generation LLC

Big Brown Power Company LLC

Blackstone Power Generation LLC

Calumet Energy Team, LLC

Casco Bay Energy Company, LLC

Coffeen and Western Railroad Company

[Signature Page to First Supplemental Indenture]

Coleto Creek Energy Storage LLC

Coleto Creek Power, LLC

Dallas Power & Light Company, Inc.

Dicks Creek Power Company LLC

Dynegy Coal Holdco, LLC

Dynegy Coal Trading & Transportation, L.L.C.

Dynegy Conesville, LLC

Dynegy Killen, LLC

Dynegy Marketing and Trade, LLC

Dynegy Midwest Generation, LLC

Dynegy Operating Company

Dynegy Power Marketing, LLC

Dynegy Resources Generating Holdco, LLC

Dynegy South Bay, LLC

Dynegy Stuart, LLC

Ennis Power Company, LLC

EquiPower Resources Corp.

Fayette Power Company LLC

Generation SVC Company

Hanging Rock Power Company LLC

Hays Energy, LLC

Hopewell Power Generation, LLC

Illinois Power Generating Company

Illinois Power Resources Generating, LLC

Illinois Power Resources, LLC

Illinova Corporation

IPH, LLC

Kendall Power Company LLC

Kincaid Generation, L.L.C.

La Frontera Holdings, LLC

Lake Road Generating Company, LLC

Liberty Electric Power, LLC

Lone Star Energy Company, Inc.

Lone Star Pipeline Company, Inc.

Luminant Administrative Services Company

Luminant Coal Generation LLC

Luminant Commercial Asset Management LLC

Luminant Energy Company LLC

Luminant Energy Trading California Company

Luminant ET Services Company LLC

Luminant Gas Imports LLC

Luminant Generation Company LLC

Luminant Mining Company LLC

Luminant Power Generation, LLC

Luminant Power LLC

Masspower, LLC

Miami Fort Power Company LLC

Midlothian Energy, LLC

Milford Power Company, LLC

Morro Bay Energy Storage 1, LLC

[Signature Page to First Supplemental Indenture]

Morro Bay Energy Storage 2, LLC

Morro Bay Power Company LLC

Moss Landing Energy Storage 4, LLC

Moss Landing Power Company LLC

NCA Land Holdings, LLC (f/k/a Maroon Farmer, LLC)

NCA Resources Development Company LLC

NEPCO Services Company

Northeastern Power Company

Oak Grove Management Company LLC

Oakland Energy Storage 2, LLC

Oakland Energy Storage 3, LLC

Oakland Power Company LLC

Ontelaunee Power Operating Company, LLC

Pleasants Energy, LLC

Sandow Power Company LLC

Sayreville Power Generation LP

Sayreville Power GP Inc.

Sayreville Power Holdings LLC

Sithe Energies, Inc.

Sithe/Independence LLC

Southwestern Electric Service Company, Inc.

Texas Electric Service Company, Inc.

Texas Energy Industries Company, Inc.

Texas Power & Light Company, Inc.

Texas Utilities Company, Inc.

Texas Utilities Electric Company, Inc

Trinidad Power Storage LLC

TXU Electric Company, Inc.

Vistra Asset Company LLC

Vistra Corporate Services Company

Vistra EP Properties Company

Vistra Finance Corp.

Vistra Insurance Solutions LLC

Vistra Vision Holdings I LLC

Vistra Vision Management LLC

VZ Development LLC

Washington Power Generation LLC

Wise County Power Company, LLC

Wise-Fuels Pipeline, Inc.

Zimmer Power Company LLC, as Subsidiary Guarantors

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

[Signature Page to First Supplemental Indenture]

WILMINGTON TRUST, NATIONAL ASSOCIATION,
as the Trustee

By:    /s/ Latoya S Elvin    

Name:    Latoya S Elvin

Title:    Vice President

[Signature Page to First Supplemental Indenture]

SCHEDULE I

GUARANTEEING SUBSIDIARIES

#	Name	Jurisdiction
1.	Ambit California, LLC	Delaware
2.	Ambit Energy Holdings, LLC	Texas
3.	Ambit Holdings, LLC	Texas
4.	Ambit Illinois, LLC	Illinois
5.	Ambit Marketing, LLC	Texas
6.	Ambit Midwest, LLC	Delaware
7.	Ambit New York, LLC	New York
8.	Ambit Northeast, LLC	Delaware
9.	Ambit Texas, LLC	Texas
10.	Angus Solar, LLC	Texas
11	Big Sky Gas Holdings, LLC	Delaware
12.	Big Sky Gas LLC	Montana
13.	BlueNet Holdings, LLC	Delaware
14.	Comanche Peak Power Company LLC	Delaware
15.	Connecticut Gas & Electric, LLC	Delaware
16.	Core Solar SPV I, LLC	Delaware
17.	Crius Energy Holdings, LLC	Delaware
18.	Crius Energy, LLC	Delaware
19.	Crius Solar Fulfillment, LLC	Delaware
20.	Deer Creek Solar I LLC	Delaware
21.	Dynegy Energy Services (East), LLC	Delaware
22.	Dynegy Energy Services Mid-Atlantic, LLC (f/k/a Everyday Energy NJ, LLC)	New Jersey

23.	Dynegy Energy Services, LLC	Delaware
24.	Energy Harbor Generation LLC	Delaware
25.	Energy Harbor Holdings LLC (f/k/a Energy Harbor Corp.)	Delaware
26.	Energy Harbor LLC	Delaware
27.	Energy Harbor Nuclear Generation LLC	Delaware
28.	Energy Rewards, LLC	Nevada
29.	Energy Services Providers, LLC	Delaware
30.	Everyday Energy, LLC	Nevada
31.	Forest Grove Solar LLC	Delaware
32.	Illinois Power Marketing Company, LLC	Delaware
33.	Massachusetts Gas & Electric, LLC	Delaware
34.	Oak Hill Solar II LLC	Delaware
35.	Oakland Energy Storage 1, LLC	Delaware
36.	Pleasants Corp.	Delaware
37.	Pleasants LLC	Delaware
38.	Public Power & Utility of Maryland, LLC	Maryland
39.	Public Power & Utility of NY, LLC	Delaware
40.	Public Power, LLC (a Connecticut limited liability company)	Connecticut
41.	Public Power, LLC (PA-3911142, a Pennsylvania limited liability company)	Pennsylvania
42.	Public Power, LLC (PA-3933152, a Pennsylvania limited liability company)	Pennsylvania
43.	Regional Energy Holdings, LLC	Delaware
44.	TriEagle 1, LLC	Nevada
45.	TriEagle 2, LLC	Nevada
46.	TriEagle Energy LP	Texas
47.	TXU Energy Retail Company LLC	Texas

48.	U.S. Gas & Electric, LLC	Delaware
49.	USG&E Solar, LLC	Delaware
50.	Value Based Brands LLC	Texas
51.	Verengo, LLC	Delaware
52.	Viridian Energy NY, LLC	New York
53.	Viridian Energy Ohio LLC	Nevada
54.	Viridian Energy PA LLC	Nevada
55.	Viridian Energy, LLC	Nevada
56.	Viridian International Management LLC	Delaware
57.	Viridian Network, LLC	Delaware
58.	Vistra Nuclear Operations Company (f/k/a Energy Harbor Nuclear Corp.)	Delaware
59.	Vistra Preferred, LLC	Delaware
60.	Vistra Retail Operations Company, LLC (f/k/a TXU Retail Services Company, LLC)	Delaware
61.	Vistra Vision Holdings II LLC	Delaware
62.	Vistra Vision LLC	Delaware
63.	Vision Trading Company LLC	Delaware
64.	Vistra Zero 2.0, LLC	Delaware
65.	Vistra Zero LLC	Delaware
66.	Volt Asset Company, LLC	Delaware

EX-4.8

Exhibit 4.8

FIFTH SUPPLEMENTAL INDENTURE
ADDITIONAL SUBSIDIARY GUARANTEES

FIFTH SUPPLEMENTAL INDENTURE (this “Supplemental Indenture”), dated as of February 5, 2025, among the subsidiary guarantors listed on Schedule I hereto (the “Guaranteeing Subsidiaries”), Vistra Operations Company LLC, a Delaware limited liability company (the “Company” ), the other subsidiary guarantors party hereto and The Bank of New York Mellon Trust Company, N.A., as trustee under the Indenture (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Company has heretofore executed and delivered to the Trustee (i) that certain indenture (the “Base Indenture”), dated as of June 15, 2023, between the Company and the Trustee and (ii) that certain first supplemental indenture, dated as of June 15, 2023 (the “First Supplemental Indenture” and, together with the Base Indenture, the “Indenture”), among the Company, the Subsidiary Guarantors party thereto and the Trustee, providing for the original issuance of an aggregate principal amount of $450,000,000 of 7.233% Senior Secured Notes due 2028 (the “Notes”);

WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall unconditionally guarantee all of the Company’s Obligations under the Notes and the Indenture (the “Subsidiary Guarantees”); and

WHEREAS, pursuant to Section 9.01(8) of the Base Indenture and Section 4.07 and Section 9.01(8) of the First Supplemental Indenture, the Trustee, the Company and the other Subsidiary Guarantors are authorized and required to execute and deliver this Supplemental Indenture.

NOW THEREFORE, in consideration of the foregoing and for good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries, the Trustee, the Company and the other Subsidiary Guarantors mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Unless otherwise defined in this Supplemental Indenture, capitalized terms used herein without definition shall have the meanings assigned to them in the Base Indenture or First Supplemental Indenture, as applicable.

2. Agreement to be Bound; Guarantee. The Guaranteeing Subsidiaries hereby become a party to the Indenture as a Subsidiary Guarantor and as such will have all of the rights and be subject to all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. The Guaranteeing Subsidiaries hereby agree to be bound by all of the provisions of the First Supplemental Indenture applicable to a Subsidiary Guarantor and to perform all of the Obligations and agreements of a Subsidiary Guarantor under the Indenture. In furtherance of the foregoing, each Guaranteeing Subsidiary shall be deemed a Subsidiary Guarantor for purposes of Article 10 of the First Supplemental Indenture, including, without limitation, Section 10.02 thereof.

3. NEW YORK LAW TO GOVERN. THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

4. Counterparts. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

5. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

6. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Company.

7. Ratification of Indenture; Supplemental Indenture Part of Indenture. Except as expressly amended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remain in full force and effect. This Supplemental Indenture shall form a part of the Indenture for all purposes, and every Holder of Notes heretofore or hereafter authenticated and delivered shall be bound hereby.

[Signature Page Follows]

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed, all as of the date first above written.

Dated: February 5, 2025

Ambit California, LLC

Ambit Energy Holdings, LLC

Ambit Holdings, LLC

Ambit Illinois, LLC

Ambit Marketing, LLC

Ambit Midwest, LLC

Ambit New York, LLC

Ambit Northeast, LLC

Ambit Texas, LLC

Angus Solar, LLC

Big Sky Gas Holdings, LLC

Big Sky Gas LLC

BlueNet Holdings, LLC

Comanche Peak Power Company LLC

Connecticut Gas & Electric, LLC

Core Solar SPV I, LLC

Crius Energy Holdings, LLC

Crius Energy, LLC

Crius Solar Fulfillment, LLC

Deer Creek Solar I LLC

Dynegy Energy Services (East), LLC

Dynegy Energy Services Mid-Atlantic, LLC (f/k/a Everyday Energy NJ, LLC)

Dynegy Energy Services, LLC

Energy Harbor Generation LLC

Energy Harbor Holdings LLC (f/k/a Energy Harbor Corp.)

Energy Harbor LLC

Energy Harbor Nuclear Generation LLC

Energy Rewards, LLC

Energy Services Providers, LLC

Everyday Energy, LLC

Forest Grove Solar LLC

Illinois Power Marketing Company, LLC

Massachusetts Gas & Electric, LLC

Oak Hill Solar II LLC

Oakland Energy Storage 1, LLC

Pleasants Corp.

Pleasants LLC

Public Power & Utility of Maryland, LLC

Public Power & Utility of NY, LLC

Public Power, LLC (a Connecticut limited liability company)

Public Power, LLC (PA-3911142, a Pennsylvania limited liability company)

[Signature Page to Fifth Supplemental Indenture]

Public Power, LLC (PA-3933152, a Pennsylvania limited liability company)

Regional Energy Holdings, LLC

TriEagle 1, LLC

TriEagle 2, LLC

TriEagle Energy LP

TXU Energy Retail Company LLC

U.S. Gas & Electric, LLC

USG&E Solar, LLC

Value Based Brands LLC

Verengo, LLC

Viridian Energy NY, LLC

Viridian Energy Ohio LLC

Viridian Energy PA LLC

Viridian Energy, LLC

Viridian International Management LLC

Viridian Network, LLC

Vistra Nuclear Operations Company (f/k/a Energy Harbor Nuclear Corp.)

Vistra Preferred, LLC

Vistra Retail Operations Company, LLC (f/k/a TXU Retail Services Company, LLC)

Vistra Vision Holdings II LLC

Vistra Vision LLC

Vision Trading Company LLC

Vistra Zero 2.0, LLC

Vistra Zero LLC

Volt Asset Company, LLC,

as the Guaranteeing Subsidiaries

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

Vistra Operations Company LLC,

as the Company

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

Bellingham Power Generation LLC

Big Brown Power Company LLC

Blackstone Power Generation LLC

Calumet Energy Team, LLC

Casco Bay Energy Company, LLC

Coffeen and Western Railroad Company

[Signature Page to Fifth Supplemental Indenture]

Coleto Creek Energy Storage LLC

Coleto Creek Power, LLC

Dallas Power & Light Company, Inc.

Dicks Creek Power Company LLC

Dynegy Coal Holdco, LLC

Dynegy Coal Trading & Transportation, L.L.C.

Dynegy Conesville, LLC

Dynegy Killen, LLC

Dynegy Marketing and Trade, LLC

Dynegy Midwest Generation, LLC

Dynegy Operating Company

Dynegy Power Marketing, LLC

Dynegy Resources Generating Holdco, LLC

Dynegy South Bay, LLC

Dynegy Stuart, LLC

Ennis Power Company, LLC

EquiPower Resources Corp.

Fayette Power Company LLC

Generation SVC Company

Hanging Rock Power Company LLC

Hays Energy, LLC

Hopewell Power Generation, LLC

Illinois Power Generating Company

Illinois Power Resources Generating, LLC

Illinois Power Resources, LLC

Illinova Corporation

IPH, LLC

Kendall Power Company LLC

Kincaid Generation, L.L.C.

La Frontera Holdings, LLC

Lake Road Generating Company, LLC

Liberty Electric Power, LLC

Lone Star Energy Company, Inc.

Lone Star Pipeline Company, Inc.

Luminant Administrative Services Company

Luminant Coal Generation LLC

Luminant Commercial Asset Management LLC

Luminant Energy Company LLC

Luminant Energy Trading California Company

Luminant ET Services Company LLC

Luminant Gas Imports LLC

Luminant Generation Company LLC

Luminant Mining Company LLC

Luminant Power Generation, LLC

Luminant Power LLC

Masspower, LLC

Miami Fort Power Company LLC

Midlothian Energy, LLC

Milford Power Company, LLC

Morro Bay Energy Storage 1, LLC

[Signature Page to Fifth Supplemental Indenture]

Morro Bay Energy Storage 2, LLC

Morro Bay Power Company LLC

Moss Landing Energy Storage 4, LLC

Moss Landing Power Company LLC

NCA Land Holdings, LLC (f/k/a Maroon Farmer, LLC)

NCA Resources Development Company LLC

NEPCO Services Company

Northeastern Power Company

Oak Grove Management Company LLC

Oakland Energy Storage 2, LLC

Oakland Energy Storage 3, LLC

Oakland Power Company LLC

Ontelaunee Power Operating Company, LLC

Pleasants Energy, LLC

Sandow Power Company LLC

Sayreville Power Generation LP

Sayreville Power GP Inc.

Sayreville Power Holdings LLC

Sithe Energies, Inc.

Sithe/Independence LLC

Southwestern Electric Service Company, Inc.

Texas Electric Service Company, Inc.

Texas Energy Industries Company, Inc.

Texas Power & Light Company, Inc.

Texas Utilities Company, Inc.

Texas Utilities Electric Company, Inc

Trinidad Power Storage LLC

TXU Electric Company, Inc.

Vistra Asset Company LLC

Vistra Corporate Services Company

Vistra EP Properties Company

Vistra Finance Corp.

Vistra Insurance Solutions LLC

Vistra Vision Holdings I LLC

Vistra Vision Management LLC

VZ Development LLC

Washington Power Generation LLC

Wise County Power Company, LLC

Wise-Fuels Pipeline, Inc.

Zimmer Power Company LLC, as Subsidiary Guarantors

By:    /s/ William M. Quinn    

Name:    William M. Quinn

Title:    Senior Vice President and Treasurer

[Signature Page to Fifth Supplemental Indenture]

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.,
not in its individual capacity but solely as the Trustee

By:    /s/ Terence Rawlins    

Name:    Terence Rawlins

Title:    Vice President

[Signature Page to Fifth Supplemental Indenture]

SCHEDULE I

GUARANTEEING SUBSIDIARIES

#	Name	Jurisdiction
1.	Ambit California, LLC	Delaware
2.	Ambit Energy Holdings, LLC	Texas
3.	Ambit Holdings, LLC	Texas
4.	Ambit Illinois, LLC	Illinois
5.	Ambit Marketing, LLC	Texas
6.	Ambit Midwest, LLC	Delaware
7.	Ambit New York, LLC	New York
8.	Ambit Northeast, LLC	Delaware
9.	Ambit Texas, LLC	Texas
10.	Angus Solar, LLC	Texas
11	Big Sky Gas Holdings, LLC	Delaware
12.	Big Sky Gas LLC	Montana
13.	BlueNet Holdings, LLC	Delaware
14.	Comanche Peak Power Company LLC	Delaware
15.	Connecticut Gas & Electric, LLC	Delaware
16.	Core Solar SPV I, LLC	Delaware
17.	Crius Energy Holdings, LLC	Delaware
18.	Crius Energy, LLC	Delaware
19.	Crius Solar Fulfillment, LLC	Delaware
20.	Deer Creek Solar I LLC	Delaware
21.	Dynegy Energy Services (East), LLC	Delaware
22.	Dynegy Energy Services Mid-Atlantic, LLC (f/k/a Everyday Energy NJ, LLC)	New Jersey

23.	Dynegy Energy Services, LLC	Delaware
24.	Energy Harbor Generation LLC	Delaware
25.	Energy Harbor Holdings LLC (f/k/a Energy Harbor Corp.)	Delaware
26.	Energy Harbor LLC	Delaware
27.	Energy Harbor Nuclear Generation LLC	Delaware
28.	Energy Rewards, LLC	Nevada
29.	Energy Services Providers, LLC	Delaware
30.	Everyday Energy, LLC	Nevada
31.	Forest Grove Solar LLC	Delaware
32.	Illinois Power Marketing Company, LLC	Delaware
33.	Massachusetts Gas & Electric, LLC	Delaware
34.	Oak Hill Solar II LLC	Delaware
35.	Oakland Energy Storage 1, LLC	Delaware
36.	Pleasants Corp.	Delaware
37.	Pleasants LLC	Delaware
38.	Public Power & Utility of Maryland, LLC	Maryland
39.	Public Power & Utility of NY, LLC	Delaware
40.	Public Power, LLC (a Connecticut limited liability company)	Connecticut
41.	Public Power, LLC (PA-3911142, a Pennsylvania limited liability company)	Pennsylvania
42.	Public Power, LLC (PA-3933152, a Pennsylvania limited liability company)	Pennsylvania
43.	Regional Energy Holdings, LLC	Delaware
44.	TriEagle 1, LLC	Nevada
45.	TriEagle 2, LLC	Nevada
46.	TriEagle Energy LP	Texas
47.	TXU Energy Retail Company LLC	Texas

48.	U.S. Gas & Electric, LLC	Delaware
49.	USG&E Solar, LLC	Delaware
50.	Value Based Brands LLC	Texas
51.	Verengo, LLC	Delaware
52.	Viridian Energy NY, LLC	New York
53.	Viridian Energy Ohio LLC	Nevada
54.	Viridian Energy PA LLC	Nevada
55.	Viridian Energy, LLC	Nevada
56.	Viridian International Management LLC	Delaware
57.	Viridian Network, LLC	Delaware
58.	Vistra Nuclear Operations Company (f/k/a Energy Harbor Nuclear Corp.)	Delaware
59.	Vistra Preferred, LLC	Delaware
60.	Vistra Retail Operations Company, LLC (f/k/a TXU Retail Services Company, LLC)	Delaware
61.	Vistra Vision Holdings II LLC	Delaware
62.	Vistra Vision LLC	Delaware
63.	Vision Trading Company LLC	Delaware
64.	Vistra Zero 2.0, LLC	Delaware
65.	Vistra Zero LLC	Delaware
66.	Volt Asset Company, LLC	Delaware

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO

EXCHANGE ACT RULES 13a-14(a) AND 15d-14(a),

AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, James A. Burke, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Vistra Corp.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: May 7, 2025	/s/ James A. Burke
	James A. Burke
	President and Chief Executive Officer
	(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO

EXCHANGE ACT RULES 13a-14(a) AND 15d-14(a),

AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Kristopher E. Moldovan, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q of Vistra Corp.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: May 7, 2025	/s/ Kristopher E. Moldovan
	Kristopher E. Moldovan
	Chief Financial Officer
	(Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Vistra Corp. (the “Company”) on Form 10-Q for the period ended March 31, 2025 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, James A. Burke, President and Chief Executive Officer of the Company, hereby certify as of the date hereof, solely for the purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge:

(1)the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.

Date: May 7, 2025	/s/ James A. Burke
	James A. Burke
	President and Chief Executive Officer
	(Principal Executive Officer)

The foregoing certification is not deemed filed with the Securities and Exchange Commission for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), and is not to be incorporated by reference into any filing of Vistra Corp. under Securities Act of 1933, as amended, or the Exchange Act, whether made before or after the date hereof, regardless of any general incorporation language of such filing.

EX-32.2

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Vistra Corp. (the “Company”) on Form 10-Q for the period ended March 31, 2025 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kristopher E. Moldovan, Chief Financial Officer of the Company, hereby certify as of the date hereof, solely for the purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge:

(1)the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and

(2)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.

Date: May 7, 2025	/s/ Kristopher E. Moldovan
	Kristopher E. Moldovan
	Chief Financial Officer
	(Principal Financial Officer)

The foregoing certification is not deemed filed with the Securities and Exchange Commission for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), and is not to be incorporated by reference into any filing of Vistra Corp. under Securities Act of 1933, as amended, or the Exchange Act, whether made before or after the date hereof, regardless of any general incorporation language of such filing.

EX-95.1

Exhibit 95.1

Mine Safety Disclosures

Safety is a top priority in all our businesses, and accordingly, it is a key component of our focus on operational excellence, our employee performance reviews and employee compensation. Our health and safety program objectives are to prevent workplace accidents and ensure that all employees return home safely and comply with all regulations.

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 U.S. Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977, as amended (the Mine Act), as well as other regulatory agencies such as the RCT. The MSHA inspects U.S. mines, including Vistra's, 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 to the Federal Mine Safety and Health Review Commission (FMSHRC), which often results in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. The number of citations, orders and proposed assessments vary depending on the size of the mine as well as other factors.

Disclosures related to specific mines pursuant to Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K sourced from data documented at April 1, 2025 in the MSHA Data Retrieval System for the three months ended March 31, 2025 (except pending legal actions, which are at March 31, 2025), are as follows:

Mine (a)	Section 104 S and S Citations (b)	Section 104(b) Orders	Section 104(d) Citations and Orders	Section 110(b)(2) Violations	Section 107(a) Orders	Total Dollar Value of MSHA Assessments Proposed (c)	Total Number of Mining Related Fatalities	Received Notice of Pattern of Violations Under Section 104	Received Notice of Potential to Have Pattern Under Section 104	Legal Actions Pending at Last Day of Period (d)	Legal Actions Initiated During Period	Legal Actions Resolved During Period
Beckville	—	—	—	—	—	—	—	—	—	—	—	—
Big Brown	—	—	—	—	—	—	—	—	—	—	—	—
Bremond	—	—	—	—	—	—	—	—	—	—	—	—
Honeybrook Refuse Operation	—	—	—	—	—	—	—	—	—	—	—	—
Kosse	—	—	—	—	—	—	—	—	—	2	2	—
Leesburg	—	—	—	—	—	—	—	—	—	—	—	—
Liberty	—	—	—	—	—	—	—	—	—	—	—	—
Northeastern Power Cogeneration Facility	—	—	—	—	—	—	—	—	—	—	—	—
Oak Hill	—	—	—	—	—	—	—	—	—	—	—	—
Sulphur Springs	—	—	—	—	—	—	—	—	—	—	—	—
Tatum	—	—	—	—	—	—	—	—	—	—	—	—
Three Oaks	—	—	—	—	—	—	—	—	—	—	—	—
Winfield North	—	—	—	—	—	—	—	—	—	—	—	—
Winfield South	—	—	—	—	—	—	—	—	—	—	—	—

____________

(a)Excludes mines for which there were no applicable events.

(b)Includes MSHA citations for mandatory health or safety standards that could significantly and substantially contribute to a serious injury if left unabated.

(c)Total value in thousands of dollars for proposed assessments received from MSHA for all citations and orders issued in the three months ended March 31, 2025, including but not limited to Sections 104, 107 and 110 citations and orders that are not required to be reported.

(d)There were two pending actions before the FMSHRC involving a coal or other mine. Both pending legal actions are contests of proposed penalties.

XML

Cover Page - shares	3 Months Ended
	Mar. 31, 2025	May 02, 2025
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2025
Document Transition Report	false
Entity File Number	001-38086
Entity Registrant Name	Vistra Corp.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	36-4833255
Entity Address, Address Line One	6555 Sierra Drive,
Entity Address, City or Town	Irving,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	75039
City Area Code	(214)
Local Phone Number	812-4600
Title of 12(b) Security	Common stock, par value $0.01 per share
Trading Symbol	VST
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		339,331,954
Entity Central Index Key	0001692819
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2025
Document Fiscal Period Focus	Q1
Amendment Flag	false

XML

Condensed Consolidated Statements of Operations - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Income Statement [Abstract]
Operating revenues	$ 3,933	$ 3,054
Fuel, purchased power costs, and delivery fees	(2,447)	(1,716)
Operating costs	(693)	(498)
Depreciation and amortization	(522)	(403)
Selling, general, and administrative expenses	(391)	(351)
Operating income (loss)	(120)	86
Other income (deductions), net	(5)	87
Interest expense and related charges	(319)	(170)
Impacts of Tax Receivable Agreement	0	(5)
Net loss before income taxes	(444)	(2)
Income tax benefit	176	20
Net income (loss)	(268)	18
Net income attributable to noncontrolling interest	0	(53)
Net loss attributable to Vistra	(268)	(35)
Cumulative dividends attributable to preferred stock	(49)	(49)
Net loss attributable to Vistra common stock	$ (317)	$ (84)
Weighted average shares of common stock outstanding:
Weighted average shares of common stock outstanding - basic (in shares)	339,799,989	348,966,197
Weighted average shares of common stock outstanding - diluted (in shares)	339,799,989	348,966,197
Net loss per weighted average share of common stock outstanding:
Net loss per weighted average share of common stock outstanding - basic (in dollars per share)	$ (0.93)	$ (0.24)
Net loss per weighted average share of common stock outstanding - diluted (in dollars per share)	$ (0.93)	$ (0.24)

XML

Condensed Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (268)	$ 18
Other comprehensive income, net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax expense of $— and $—)	0	0
Total other comprehensive income	0	0
Comprehensive income (loss)	(268)	18
Comprehensive income attributable to noncontrolling interest	0	(53)
Net loss attributable to Vistra	$ (268)	$ (35)

XML

Condensed Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Statement of Comprehensive Income [Abstract]
Effect related to pension and other retirement benefit obligations (tax)	$ 0	$ 0

XML

Condensed Consolidated Balance Sheets - USD ($) $ in Millions	Mar. 31, 2025	Dec. 31, 2024
Current assets:
Cash and cash equivalents	$ 561	$ 1,188
Restricted cash	29	28
Trade accounts receivable — net	1,924	1,982
Inventories	960	970
Commodity and other derivative contractual assets	3,335	2,587
Margin deposits related to commodity contracts	579	406
Margin deposits posted under affiliate financing agreement	446	435
Prepaid expense and other current assets	596	523
Total current assets	8,430	8,119
Restricted cash	6	6
Investments	4,476	4,512
Property, plant and equipment — net	17,716	18,173
Goodwill	2,810	2,807
Identifiable intangible assets — net	2,321	2,213
Commodity and other derivative contractual assets	769	740
Accumulated deferred income taxes	9	9
Other noncurrent assets	1,691	1,191
Total assets	38,228	37,770
Current liabilities:
Accounts receivable financing	1,082	750
Long-term debt due currently	882	880
Forward repurchase obligation due currently	723	703
Trade accounts payable	1,328	1,510
Commodity and other derivative contractual liabilities	4,646	3,351
Margin deposits related to commodity contracts	5	49
Accrued taxes other than income	101	209
Accrued interest	244	193
Asset retirement obligations	136	142
Other current liabilities	606	645
Total current liabilities	9,753	8,432
Margin deposits financing with affiliate	446	435
Long-term debt, less amounts due currently	15,423	15,418
Forward repurchase obligation, less amounts due currently	632	632
Commodity and other derivative contractual liabilities	1,459	1,367
Accumulated deferred income taxes	512	697
Asset retirement obligations	3,937	3,936
Other noncurrent liabilities and deferred credits	1,228	1,270
Total liabilities	33,390	32,187
Commitments and Contingencies
Total equity:
Preferred stock (100,000,000 shares authorized, $1,000 liquidation preference per share, 2,476,066 shares outstanding at March 31, 2025 and December 31, 2024, respectively)	2,476	2,476
Common stock (par value $0.01 per share, 1,800,000,000 shares authorized, 340,048,488 and 339,754,307 shares outstanding at March 31, 2025 and December 31, 2024, respectively)	5	5
Treasury stock, at cost (211,435,313 and 208,998,299 shares at March 31, 2025 and December 31, 2024, respectively)	(6,248)	(5,912)
Additional paid-in-capital	9,407	9,435
Accumulated deficit	(835)	(454)
Accumulated other comprehensive income	20	20
Stockholders' equity	4,825	5,570
Noncontrolling interest in subsidiary	13	13
Total equity	4,838	5,583
Total liabilities and equity	$ 38,228	$ 37,770

XML

Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares	Mar. 31, 2025	Dec. 31, 2024
Statement of Financial Position [Abstract]
Preferred stock, shares authorized (in shares)	100,000,000	100,000,000
Preferred sock, liquidation preference (in dollars per share)	$ 1,000	$ 1,000
Preferred stock, shares outstanding (in shares)	2,476,066	2,476,066
Common stock, par or stated value per share (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	1,800,000,000	1,800,000,000
Common stock, shares outstanding (in shares)	340,048,488	339,754,307
Treasury stock, common shares (in shares)	211,435,313	208,998,299

XML

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Cash flows — operating activities:
Net income (loss)	$ (268)	$ 18
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation and amortization	772	555
Deferred income tax benefit, net	(185)	(23)
Unrealized net loss from mark-to-market valuations of commodities	567	176
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps	48	(47)
Unrealized net (gain) loss from nuclear decommissioning trusts	15	(28)
Asset retirement obligation accretion expense	34	19
Bad debt expense	44	36
Stock-based compensation expense	21	21
Other, net	57	(28)
Changes in operating assets and liabilities:
Margin deposits, net	(217)	128
Accrued interest	51	(3)
Accrued taxes	(109)	(111)
Accrued employee incentive	(177)	(169)
Other operating assets and liabilities	(54)	(232)
Cash provided by operating activities	599	312
Cash flows — investing activities:
Capital expenditures, including nuclear fuel purchases and LTSA prepayments	(768)	(465)
Energy Harbor acquisition (net of cash acquired)	0	(3,070)
Proceeds from sales of nuclear decommissioning trust fund securities	2,107	214
Investments in nuclear decommissioning trust fund securities	(2,112)	(220)
Proceeds from sales of environmental allowances	21	17
Purchases of environmental allowances	(307)	(131)
Proceeds from sale of property, plant and equipment, including nuclear fuel	0	127
Other, net	(2)	0
Cash used in investing activities	(1,061)	(3,528)
Cash flows — financing activities:
Issuances of long-term debt	0	700
Repayments/repurchases of debt	(6)	(756)
Net borrowings (repayments) under accounts receivable financing	332	875
Borrowings under Commodity-Linked Facility	0	500
Stock repurchases	(337)	(291)
Dividends paid to common stockholders	(83)	(77)
Dividends paid to preferred stockholders	(21)	0
Tax withholding on stock based compensation	(50)	(12)
TRA Repurchase and tender offer — return of capital	0	(122)
Other, net	1	(24)
Cash (used in) provided by financing activities	(164)	793
Net change in cash, cash equivalents and restricted cash	(626)	(2,423)
Cash, cash equivalents and restricted cash — beginning balance	1,222	3,539
Cash, cash equivalents and restricted cash — ending balance	$ 596	$ 1,116

XML

Condensed Consolidated Statements of Changes in Equity - USD ($) $ in Millions		Total	Total Stockholders' Equity	Preferred Stock	Common Stock	Treasury Stock	Additional Paid-In Capital	Accumulated Deficit	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest in Subsidiary
Beginning balance at Dec. 31, 2023		$ 5,322	$ 5,307	$ 2,476	$ 5	$ (4,662)	$ 10,095	$ (2,613)	$ 6	$ 15
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock repurchases		(285)	(285)			(285)
Effects of stock-based incentive compensation plans	[1]	35	35				35
Equity issued in subsidiary to acquire Energy Harbor	[2]	2,307	747				747			1,560
Net income (loss)		18	(35)					(35)		53
Dividends declared on common stock		(77)	(77)					(77)
Dividends declared on preferred stock		(37)	(37)					(37)
Other		1	1				1
Ending balance at Mar. 31, 2024		7,284	5,656	2,476	5	(4,947)	10,878	(2,762)	6	1,628
Beginning balance at Dec. 31, 2024		5,583	5,570	2,476	5	(5,912)	9,435	(454)	20	13
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock repurchases		(336)	(336)			(336)
Effects of stock-based incentive compensation plans	[1]	(27)	(27)				(27)
Net income (loss)		(268)	(268)					(268)
Dividends declared on common stock		(75)	(75)					(75)
Dividends declared on preferred stock		(38)	(38)					(38)
Other		(1)	(1)				(1)
Ending balance at Mar. 31, 2025		$ 4,838	$ 4,825	$ 2,476	$ 5	$ (6,248)	$ 9,407	$ (835)	$ 20	$ 13

[1] 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.

[2] See Note 2 for additional information regarding activity associated with noncontrolling interest.

XML

Condensed Consolidated Statements of Changes in Equity (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Statement of Stockholders' Equity [Abstract]
Tax withholding obligations	$ 50	$ 12

XML

Business, Significant Accounting Policies, Significant Events, and Recent Developments

3 Months Ended

Mar. 31, 2025

Accounting Policies [Abstract]

Business, Significant Accounting Policies, Significant Events, and Recent Developments

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.

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, but the two 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 at some point later this year. 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 March 31, 2025, the net book value of the Moss Landing 100 facility was approximately $170 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). We have recognized expense of approximately $7 million for costs incurred to respond to the Moss Landing Incident through March 31, 2025. As of March 31, 2025, we accrued approximately $70 million in obligations related to the Moss Landing Incident including approximately $30 million for anticipated air and soil monitoring requirements and $40 million for the expected costs of decommissioning the Moss Landing 300 structure, which includes demolition of the structure, removing and disposing of the batteries, and fulfilling land reclamation obligations (see Note 13). Additional costs incurred 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.

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 costs and expenses incurred, in other noncurrent assets on the condensed consolidated balance sheet.

Recent Developments

BCOP Project-level Credit Facilities

On April 1, 2025, term loans under the BCOP project-level Construction/Term Loan Facility of $75 million and $46 million were funded for the Baldwin and Coffeen projects, respectively, pursuant to the BCOP Credit Agreement. On March 31, 2025, BCOP also entered into interest rate swaps that became effective on April 1, 2025 to hedge approximately $108 million of the floating rate term loans funded under the Construction/Term Loan Facility. See Notes 9 and 10 for additional information.

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Acquisitions

3 Months Ended

Mar. 31, 2025

Business Combination, Asset Acquisition, and Joint Venture Formation [Abstract]

Acquisitions

ACQUISITIONS

Energy Harbor Business Combination

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

The Energy Harbor Merger was accounted for using the acquisition method in accordance with ASC 805, Business Combinations (ASC 805), which requires identifiable assets acquired and liabilities assumed to be recorded at their estimated fair values on the Merger Date. The combined results of operations are reported in the 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 price	4,596
Fair value of noncontrolling interest in Energy Harbor (b)	811
Acquisition date fair value of Energy Harbor	$	5,407

____________

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

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

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

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 recorded since March 1, 2024
	(in millions)
Cash and cash equivalents	$	35	$	5
Trade accounts receivables, inventories, prepaid expenses and other current assets	540		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 assets	62		54
Total identifiable assets acquired	8,847		62
Trade accounts payable and other current liabilities	318		55
Long-term debt, including amounts due currently	413		—
Commodity and other derivative contractual liabilities (d)	179		—
Accumulated deferred income taxes	1,314		(50)
Asset retirement obligations (e)	1,368		—
Identifiable intangible liabilities	55		(18)
Other noncurrent liabilities and deferred credits	20		8
Total identifiable liabilities assumed	3,667		(5)
Identifiable net assets acquired	5,180		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.

The following unaudited pro forma financial information for the three months ended March 31, 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 March 31, 2024
	(in millions)
Revenues	$	3,777
Net income	$	69

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 $24 million for the three months ended March 31, 2024, 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 represent conditional redemption obligations that required us to reflect the transaction as redeemable noncontrolling interest within the mezzanine section of the consolidated balance sheet as of September 30, 2024. The UPAs were amended prior to close to accelerate principal payments to Avenue and certain Nuveen noncontrolling interest holders. The transaction closed on December 31, 2024, 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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Revenue

3 Months Ended

Mar. 31, 2025

Revenue from Contract with Customer [Abstract]

Revenue

REVENUE

Revenue Disaggregation

The following tables disaggregate our revenue by major source:

	Three Months Ended March 31, 2025
	Retail		Texas		East		West		Asset Closure		Eliminations / Corporate and Other		Consolidated
	(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	1,986	$	—	$	—	$	—	$	—	$	—	$	1,986
Retail energy charge in Northeast/Midwest	1,039		—		—		—		—		—		1,039
Wholesale generation revenue from ISO/RTO	—		78		770		26		—		—		874
Capacity revenue from ISO/RTO (a)	—		—		20		—		—		—		20
Revenue from other wholesale contracts	—		129		130		68		4		—		331
Total revenue from contracts with customers	3,025		207		920		94		4		—		4,250
Other revenues:
Transferable PTC revenues (b)	—		2		—		—		—		—		2
Hedging revenues — realized	274		(27)		(78)		26		—		—		195
Hedging revenues — unrealized	(157)		(143)		(250)		36		1		—		(513)
Intangible amortization and other revenues	—		—		(1)		—		—		—		(1)
Intersegment sales (c)	26		171		789		1		(1)		(986)		—
Total other revenues	143		3		460		63		—		(986)		(317)
Total revenues	$	3,168	$	210	$	1,380	$	157	$	4	$	(986)	$	3,933

____________

(a)Includes $73 million of capacity sold offset by $53 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 solar assets during the period.

(c)The Texas and East segments include $883 million and $271 million, respectively, of intersegment unrealized net losses, and West segment includes $1 million of intersegment net gains from mark-to-market valuations of commodity positions with the Retail segment.

	Three Months Ended March 31, 2024
	Retail		Texas		East (a)		West		Asset Closure		Eliminations / Corporate and Other		Consolidated
	(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	1,702	$	—	$	—	$	—	$	—	$	—	$	1,702
Retail energy charge in Northeast/Midwest (a)	663		—		—		—		—		—		663
Wholesale generation revenue from ISO/RTO	—		68		333		79		9		—		489
Capacity revenue from ISO/RTO (b)	—		—		19		—		—		—		19
Revenue from other wholesale contracts	—		104		125		57		—		—		286
Total revenue from contracts with customers	2,365		172		477		136		9		—		3,159
Other revenues:
Transferable PTC revenues	—		2		—		—		—		—		2
Hedging revenues — realized	278		(110)		74		3		(4)		—		241
Hedging revenues — unrealized	(155)		(132)		(200)		136		4		—		(347)
Intangible amortization and other revenues	—		—		(1)		—		—		—		(1)
Intersegment sales (c)	6		527		506		1		—		(1,040)		—
Total other revenues	129		287		379		140		—		(1,040)		(105)
Total revenues	$	2,494	$	459	$	856	$	276	$	9	$	(1,040)	$	3,054

____________

(a)Includes revenues associated with March 2024 operations acquired in the Energy Harbor Merger.

(b)Represents net capacity sold in each ISO/RTO. The East segment includes $40 million of capacity sold offset by $21 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 $7 million offset by $2 million of capacity sold within the East segment.

(c)Texas and East segments include $490 million and $291 million, respectively, of intersegment unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

Performance Obligations

As of March 31, 2025, we have future fixed fee performance obligations that are unsatisfied, or partially unsatisfied, relating to capacity auction volumes awarded through capacity auctions held by the ISO/RTO or 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		2026		2027		2028		2029		2030 and Thereafter		Total
	(in millions)
Remaining performance obligations	$	934	$	832	$	292	$	122	$	62	$	548	$	2,790

Trade Accounts Receivable

	March 31, 2025		December 31, 2024
	(in millions)
Wholesale and retail trade accounts receivable	$	1,999	$	2,061
Allowance for credit losses	(75)		(79)
Trade accounts receivable — net	$	1,924	$	1,982
Trade accounts receivable from contracts with customers — net	$	1,494	$	1,514
Other trade accounts receivable — net	430		468
Trade accounts receivable — net	$	1,924	$	1,982

Gross trade accounts receivable as of March 31, 2025 and December 31, 2024 include unbilled retail revenues of $737 million and $802 million, respectively.

Allowance for Credit Losses on Accounts Receivable

	Three Months Ended March 31,
	2025		2024
	(in millions)
Allowance for credit losses on accounts receivable at beginning of period	$	79	$	61
Increase for bad debt expense	44		36
Decrease for account write-offs	(48)		(36)
Allowance for credit losses on accounts receivable at end of period	$	75	$	61

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Government Assistance

3 Months Ended

Mar. 31, 2025

Government Assistance [Abstract]

Government Assistance

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, 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 as power prices increase above $25 per MWh, to existing nuclear facilities from 2024 through 2032 subject to an annual inflation adjustment. The Company accounts for transferable ITCs and PTCs we expect to receive by analogy to the grant model within International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance.

Sales of Transferable PTCs

In January 2025, we sold $200 million of transferable nuclear PTCs we recognized from qualifying 2024 nuclear production. Cash consideration from the sale will be received in installments through July 2025, with the initial cash installment received in January 2025.

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Income Taxes

3 Months Ended

Mar. 31, 2025

Income Tax Disclosure [Abstract]

Income Taxes

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) Benefit

The components of our income tax (expense) benefit are as follows:

	Three Months Ended March 31,
	2025			2024
	(in millions)
Net loss before income taxes	$	(444)		$	(2)
Income tax benefit	$	176		$	20
Effective tax rate	39.6		%	1,000.0		%

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.

For the three months ended March 31, 2025, the effective tax rate of 39.6% was higher than the U.S. federal statutory rate of 21% due primarily to state income taxes and permanent differences recorded discretely related to stock-based compensation.

For the three months ended March 31, 2024, the effective tax rate of 1,000.0% was higher than the U.S. federal statutory rate of 21% due primarily to the level of pre-tax earnings during the period and permanent difference recorded discretely related to stock-based compensation, partially offset by mark-to-market losses.

IRA

In August 2022, the U.S. enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases. We do not expect Vistra to be subject to the CAMT in the 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 relevant extensions or expansions of existing tax credits applicable to projects in our immediate development pipeline into account when forecasting cash taxes. See Note 4 for additional information.

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Property, Plant, and Equipment

3 Months Ended

Mar. 31, 2025

Property, Plant and Equipment [Abstract]

Property, Plant, and Equipment

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.

	March 31, 2025		December 31, 2024
	(in millions)
Power generation and structures	$	22,303	$	22,783
Office and other equipment	172		160
Land	603		603
Construction work in progress	1,394		1,060
Finance lease right-of-use assets	186		186
Nuclear fuel	2,032		1,843
Property, plant and equipment — gross	26,690		26,635
Less accumulated depreciation	(8,415)		(8,020)
Less finance lease right-of-use assets accumulated amortization	(35)		(33)
Less accumulated amortization on nuclear fuel	(524)		(409)
Property, plant and equipment — net	$	17,716	$	18,173

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 Equipment	Condensed Consolidated Statements of Operations	Three Months Ended March 31,
		2025		2024
		(in millions)
Power generation and structures and office and other equipment	Depreciation and amortization	$	479	$	365
Finance lease right-of-use assets	Depreciation and amortization	2		2
Nuclear fuel	Fuel, purchased power costs, and delivery fees	111		49
Total property, plant, and equipment expense		$	592	$	416

Retirement of Generation Facilities

Below are our facilities that are retired or have an announced retirement date. Operating results for generation facilities with defined retirement dates are included in our Asset Closure segment at the beginning of the calendar year the retirement 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.

Facility	Location	ISO/RTO	Fuel Type	Net Capacity (MW)	Expected or Actual Retirement Date (a)	Segment
Baldwin	Baldwin, IL	MISO	Coal	1,185	By the end of 2027	East
Coleto Creek (b)	Goliad, TX	ERCOT	Coal	650	By the end of 2027	Texas
Kincaid	Kincaid, IL	PJM	Coal	1,108	By the end of 2027	East
Miami Fort	North Bend, OH	PJM	Coal	1,020	By the end of 2027	East
Newton	Newton, IL	MISO	Coal	615	By the end of 2027	East
Edwards	Bartonville, IL	MISO	Coal	585	Retired January 1, 2023	Asset Closure
Total				5,163

____________

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

(b)The Company intends to repower Coleto Creek as a gas-fueled facility upon its retirement as a coal-fueled facility.

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Goodwill and Identifiable Intangible Assets and Liabilities

3 Months Ended

Mar. 31, 2025

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Identifiable Intangible Assets and Liabilities

GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

Goodwill

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

	Retail Segment		Texas Segment
	Retail Reporting Unit (a)		Texas Generation Reporting Unit		Goodwill Pending Allocation		Total 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 March 31, 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).

Identifiable Intangible Assets and Liabilities

Identifiable intangible assets are comprised of the following:

	March 31, 2025						December 31, 2024
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
	(in millions)
Retail customer relationships	$	2,173	$	1,999	$	174	$	2,173	$	1,977	$	196
Software and other technology-related assets	616		312		304		601		293		308
Retail and wholesale contracts	503		373		130		503		353		150
Long-term service agreements	18		5		13		18		5		13
Other identifiable intangible assets (a)	373		14		359		218		13		205
Total identifiable intangible assets subject to amortization	$	3,683	$	2,703	980		$	3,513	$	2,641	872
Retail trade names (not subject to amortization)					1,341						1,341
Total identifiable intangible assets					$	2,321					$	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 Liability	March 31, 2025		December 31, 2024
	(in millions)
Long-term service agreements	$	104	$	108
Wholesale power and fuel purchase contracts	45		47
Total identifiable intangible liabilities	$	149	$	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/Liabilities	Condensed Consolidated Statements of Operations		Three Months Ended March 31,
			2025		2024
		(in millions)
Retail customer relationships	Depreciation and amortization		$	23	$	22
Software and other technology-related assets	Depreciation and amortization		18		13
Retail and wholesale contracts	Operating revenues/Fuel, purchased power costs, and delivery fees		(2)		1
Other identifiable intangible assets (a)	Fuel, purchased power costs, and delivery fees/Depreciation and amortization		136		103
Total intangible asset expense, net			$	175	$	139

___________

(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.

Estimated Amortization of Identifiable Intangible Assets

As of March 31, 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.

Year	Estimated Amortization Expense
	(in millions)
2025	$	237
2026	$	177
2027	$	80
2028	$	59
2029	$	41

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Collateral Financing Agreement With Affiliate

3 Months Ended

Mar. 31, 2025

Debt Disclosure [Abstract]

Collateral Financing Agreement With Affiliate

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 March 31, 2025 and December 31, 2024, the fair value of Eligible Assets held by counterparties to satisfy current and future margin deposit requirements totaled $446 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.

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Debt, Credit Facilities and Financings

3 Months Ended

Mar. 31, 2025

Debt Disclosure [Abstract]

Debt, Credit Facilities and Financings

DEBT, CREDIT FACILITIES, AND FINANCINGS

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

	March 31, 2025		December 31, 2024
	(in millions)
Long-term debt, including amounts due currently:
Project-level debt	$	1,064	$	1,064
Vistra Operations debt	15,399		15,405
Long -term debt before unamortized premiums, discounts and issuance costs	16,463		16,469
Unamortized premiums, discounts and issuance costs	(158)		(171)
Long-term debt including amounts due currently	$	16,305	$	16,298
Accounts receivable financing	$	1,082	$	750
Forward repurchase obligation	$	1,355	$	1,335

Long-Term Debt

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

	March 31, 2025		December 31, 2024
	(in millions)
Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030	$	2,469	$	2,475
BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026	367		367
Vistra Zero Credit Facility, Term Loan B Facility due April 30, 2031	697		697
Vistra Operations Senior Secured Notes:
5.125% Senior Secured Notes, due May 13, 2025	744		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 Notes	5,144		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 Bonds	431		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 15, 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 Notes	7,300		7,300
Other:
Equipment Financing Agreements	55		55
Total other long-term debt	55		55
Unamortized debt premiums, discounts and issuance costs	(158)		(171)
Total long-term debt including amounts due currently	16,305		16,298
Less amounts due currently	(882)		(880)
Total long-term debt, less amounts due currently	$	15,423	$	15,418

Long-Term Debt Maturities

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

	March 31, 2025
	(in millions)
Remainder of 2025	$	879
2026	1,792
2027	3,427
2028	27
2029	2,177
Thereafter	8,161
Unamortized premiums, discounts and debt issuance costs	(158)
Total long-term debt, including amounts due currently	$	16,305

Credit Facilities

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

		March 31, 2025
Credit Facilities	Maturity Date	Facility Limit		Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)		Letters of Credit Outstanding		Available Capacity
		(in millions)
Vistra Operations debt:
Revolving Credit Facility	October 11, 2029	$	3,440	$	—	$	1,223	$	2,217
Term Loan B-3 Facility	December 20, 2030	2,469		2,469		—		—
Total Vistra Operations Credit Facilities		$	5,909	$	2,469	$	1,223	$	2,217
Vistra Operations Commodity-Linked Facility	October 1, 2025	1,750		—		—		1,125
Total Vistra Operations debt		$	7,659	$	2,469	$	1,223	$	3,342
Project-level debt:
Tax Credit Bridge Loan	November 1, 2025	106		106		—		—
Tax Credit Bridge Loan	December 3, 2026	261		261		—		—
BCOP Credit Facility		367		367		—		—
Vistra Zero Term Loan B Facility (a)	April 30, 2031	697		697		—		—
Total project-level debt		$	1,064	$	1,064	$	—	$	—
Total credit facilities		$	8,723	$	3,533	$	1,223	$	3,342

___________

(a)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.

Vistra Operations Credit Facilities

As of March 31, 2025, the Vistra Operations Credit Facilities have aggregate commitments of up to $5.909 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 $2.469 billion (Term Loan B-3 Facility).

Revolving Credit Facility — The Revolving Credit Facility is used for general corporate purposes. Under the Vistra Operations Credit Agreement, the interest on borrowings under the Revolving Credit Facility is paid based on (i) the forward-looking term rate based on SOFR (Term SOFR) plus a spread that ranges from 1.25% to 2.00% and (ii) the fee 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 range from 1.25% to 2.00% and are paid quarterly in arrears. Interest and fees on the Revolving Credit Facility are based on ratings of Vistra Operations' senior secured long-term debt securities. As of March 31, 2025, after taking into account sustainability pricing adjustments based on certain sustainability-linked targets and thresholds, the applicable interest rate margins for the Revolving Credit Facility and the fee for undrawn amounts relating to such commitments were 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) on outstanding borrowings of $2.469 billion was 6.07% as of March 31, 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. 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.

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 March 31, 2025, Vistra Operations can distribute approximately $10.2 billion to Parent under the Vistra Operations Credit Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Parent of approximately $425 million and $490 million for the three months ended March 31, 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 March 31, 2025, all of the restricted net assets of Vistra Operations may be distributed to Parent.

Vistra Operations Commodity-Linked Revolving Credit Facility

As of March 31, 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. As of March 31, 2025, the borrowing base of $1.125 billion 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 March 31, 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.

BCOP Project-level Credit Facilities

In December 2024, BCOP and its subsidiaries entered into the BCOP Credit Agreement to fund the development of the Baldwin and Coffeen solar generation and battery ESS facilities and the Oak Hill and Pulaski solar generation facilities in Illinois and Texas. The BCOP Credit Agreement provides for (i) tax credit bridge loans of $367 million for the Oak Hill and Pulaski projects (Tax Credit Bridge Loans) and (ii) construction/term loan commitments of $528 million (Construction/Term Loan Facility) and debt service reserve letter of credit facility commitments of $29 million (Debt Service Reserve) for all four facilities.

As of March 31, 2025, the Tax Credit 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. Interest is paid on the Tax Credit 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 5.984% as of March 31, 2025. Repayment of the Tax Credit Bridge Loans is guaranteed by Vistra as the beneficiary of the underlying investment tax credits to be generated by the projects.

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. 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. The term loans will amortize over a 20-year period beginning on the term funding date (for Baldwin and Coffeen) or term conversion date (for Oak Hill and Pulaski), as applicable, and debt amortization and interest payments will be funded by 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.

As of March 31, 2025, there were no Construction/Term Loan Facility borrowings outstanding. On April 1, 2025, term loans of $75 million and $46 million were funded for Baldwin and Coffeen, respectively.

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 6.32% as of March 31, 2025.

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

Letter of Credit Facilities

Vistra Operations Secured Letter of Credit Facilities

Between August 2020 and July 2024, we entered into uncommitted standby letters of credit facilities with various banks (each, a Secured LOC Facility and collectively, the Secured LOC Facilities). The Secured LOC Facilities are secured by a first lien on substantially all of Vistra Operations' (and certain of its subsidiaries') assets (which ranks pari passu with the Vistra Operations Credit Facilities). The Secured LOC Facilities may be renewed annually and are used for general corporate purposes. As of March 31, 2025, $1.091 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 March 31, 2025, the total capacity was $500 million and $500 million of letters of credit were outstanding under the Alternative LOC Facilities. The commitments under the Alternative LOC Facilities terminate in December 2028. There are no financial maintenance covenants in the Alternative LOC Facilities.

Vistra Operations Senior Secured Notes

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.

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.

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 April 2024, the Receivables Facility was amended to increase the purchase limit from $750 million to $1.0 billion and to add Energy Harbor LLC, a direct, wholly owned subsidiary of Energy Harbor, as an Originator. The Receivables Facility was renewed and amended in July 2024, extending the term of the Receivables Facility to July 2025.

In connection with the Receivables Facility, TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands, Energy Harbor LLC and TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), each sell and/or contribute, subject to certain exclusions, all of its receivables (other than any receivables excluded pursuant to the terms of the Receivables Facility), arising from the sale of electricity to its customers and related rights (Receivables), to RecCo, a consolidated, wholly owned, bankruptcy-remote, direct subsidiary of TXU Energy. RecCo, in turn, is subject to certain conditions, and may draw under the Receivables Facility up to the limit described above to fund its acquisition of the Receivables from the Originators. RecCo has granted a security interest on the Receivables and all related assets for the benefit of the Purchasers under the Receivables Facility and Vistra Operations has agreed to guarantee the performance of the obligations of the Originators and TXU Energy, as the servicer, under the agreements governing the Receivables Facility. Amounts funded by the Purchasers to RecCo are reflected as short-term borrowings in the 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 March 31, 2025, outstanding borrowings under the Receivables Facility totaled $957 million and were supported by $1.346 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 2024, the Repurchase Facility was renewed until July 2025 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 March 31, 2025, outstanding borrowings under the Repurchase Facility totaled $125 million. There were no outstanding borrowings under the Repurchase Facility as of December 31, 2024.

Forward Repurchase Obligation

In accordance with the amended UPAs, on December 31, 2024, Vistra closed the acquisition of the Vistra Vision minority interest from Avenue and Nuveen. Vistra paid Avenue for the purchase of their minority interest in Vistra Vision in full upon closing and paid Nuveen an initial payment at closing, with the remaining payments to Nuveen to be paid in multiple installments through December 31, 2026. Vistra Vision Holdings' remaining future payments to Nuveen are guaranteed by Vistra Operations and certain of its subsidiaries that guarantee Vistra Operations' unsecured notes. Payments remaining due to Nuveen are as follows:

	March 31, 2025
	(in millions)
Remainder of 2025	$	781
2026	669
Thereafter	—
Total scheduled payments under the UPAs	$	1,450

The present value of the remaining payment obligations to Nuveen discounted at 6% totaled $1.355 billion and $1.335 billion at March 31, 2025 and December 31, 2024, respectively.

Interest Expense and Related Charges

	Three Months Ended March 31,
	2025		2024
	(in millions)
Interest expense	$	272	$	208
Unrealized mark-to-market net (gains) losses on interest rate swaps	48		(47)
Amortization of debt issuance costs, discounts, and premiums	11		7
Debt extinguishment gain	—		(6)
Capitalized interest	(29)		(12)
Other	17		20
Total interest expense and related charges	$	319	$	170

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 10, was 5.22% and 5.56% as of March 31, 2025 and 2024, respectively.

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Derivatives

3 Months Ended

Mar. 31, 2025

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

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.

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 March 31, 2025, Vistra has entered into the following interest rate swaps:

	Notional Amount	Expiration Date	Rate Range (d)
	(in millions, except percentages)
Swapped to fixed (a)	$3,000	July 2026	2.89	%	-	2.97%
Swapped to variable (a)	$700	July 2026	1.44	%	-	1.49%
Swapped to fixed (b)	$2,300	December 2030	3.20	%	-	3.76%
Swapped to fixed (c)	$108	March 2045	3.95%

____________

(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, BCOP entered into approximately $108 million notional amount of interest rate swaps effective April 1, 2025 and expiring in March 2045. These swaps will hedge BCOP's exposure on approximately $108 million of floating rate Construction/Term Loan Facility commitments (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.

	March 31, 2025
	Derivative Contract Assets				Derivative Contract Liabilities
	Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total
	(in millions)
Current assets	$	3,306	$	28	$	1	$	—	$	3,335
Noncurrent assets	729		21		19		—		769
Current liabilities	(7)		—		(4,622)		(17)		(4,646)
Noncurrent liabilities	(14)		—		(1,433)		(12)		(1,459)
Net assets (liabilities)	$	4,014	$	49	$	(6,035)	$	(29)	$	(2,001)
Offsetting instruments (a)	(3,381)		(22)		3,381		22		—
Financial collateral (received) pledged (b)	(17)		—		331		—		314
Net amounts	$	616	$	27	$	(2,323)	$	(7)	$	(1,687)

	December 31, 2024
	Derivative Contract Assets				Derivative Contract Liabilities
	Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total
	(in millions)
Current assets	$	2,551	$	34	$	2	$	—	$	2,587
Noncurrent assets	677		62		1		—		740
Current liabilities	—		—		(3,333)		(18)		(3,351)
Noncurrent liabilities	(2)		—		(1,356)		(9)		(1,367)
Net assets (liabilities)	$	3,226	$	96	$	(4,686)	$	(27)	$	(1,391)
Offsetting instruments (a)	(2,532)		(28)		2,532		28		—
Financial collateral (received) pledged (b)	(50)		—		233		—		183
Net amounts	$	644	$	68	$	(1,921)	$	1	$	(1,208)

____________

(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 months ended March 31, 2025 and 2024:

Derivative (condensed consolidated statements of operations presentation)	Three Months Ended March 31,
	2025		2024
	(in millions)
Reversals of previously recognized unrealized (gain) loss on derivative instruments:
Commodity contracts unrealized (gain) loss in operating revenues (a)	$	212	$	261
Commodity contracts unrealized (gain) loss in fuel, purchased power costs, and delivery fees (a)	(23)		126
Interest rate swaps unrealized (gain) loss in interest expense and related charges	(5)		(11)
Total reversals of previously recognized unrealized (gain) loss on derivative instruments	$	184	$	376
Unrealized net gain (loss) from changes in fair value on derivative instruments:
Commodity contracts unrealized gain (loss) in operating revenues	$	(725)	$	(608)
Commodity contracts unrealized gain (loss) in fuel, purchased power costs, and delivery fees	(31)		45
Interest rate swaps unrealized gain (loss) in interest expense and related charges	(43)		58
Total unrealized net gain (loss) from change in fair value on derivative instruments	$	(799)	$	(505)
Net gain (loss) on derivative instruments	$	(615)	$	(129)

____________

(a)Excludes the realized effects of changes in fair value in the month the position settled, amounts related to positions entered into and settled in the same month, and physical retail and wholesale contracts accounted for as derivatives that did not financially settle but were realized at the contract's notional and price. The realized effects of these items are included in operating revenues and fuel, purchased power costs, and delivery fees.

Derivative Volumes

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:

	March 31, 2025		December 31, 2024
Derivative type	Notional Volume				Unit of Measure
Natural gas	4,563		4,568		Million MMBtu
Electricity	831,426		796,982		GWh
Financial transmission rights / Congestion revenue rights	224,032		248,742		GWh
Coal	27		27		Million U.S. tons
Fuel oil	—		2		Million gallons
Emissions	29		28		Million U.S. tons
Renewable energy certificates	28		31		Million certificates
Interest rate swaps – variable/fixed	$	5,408	$	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:

	March 31, 2025		December 31, 2024
	(in millions)
Fair value of derivative contract liabilities (a)	$	(1,963)	$	(1,587)
Offsetting fair value under netting arrangements (b)	792		724
Cash collateral and letters of credit	563		471
Liquidity exposure	$	(608)	$	(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.

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.

	March 31, 2025
	(in millions, except percentages)
Credit risk exposure to derivative contract counterparties:
Gross exposure	$	4,431
Net exposure (a)	$	689
Largest net exposure from any single counterparty (a)	$	272
Percent of credit risk exposure to derivative contract counterparties related to banking and financial sector
Gross exposure	80		%
Net exposure (a)	23		%

____________

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

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Fair Value Measurements

3 Months Ended

Mar. 31, 2025

Fair Value Disclosures [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

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

•Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date.

•Level 2 valuations use over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means, and other valuation inputs such as interest rates and yield curves observable at commonly quoted intervals.

•Level 3 valuations use unobservable inputs for the asset or liability, typically reflecting our estimate of assumptions that market participants would use in pricing the asset or liability. The fair value is therefore determined using model-based techniques, including discounted cash flow models.

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

	March 31, 2025										December 31, 2024
	Level 1		Level 2		Level 3		Reclass (a)		Total		Level 1		Level 2		Level 3		Reclass (a)		Total
	(in millions)
Assets:
Commodity contracts (b)	$	2,683	$	425	$	906	$	41	$	4,055	$	1,923	$	462	$	841	$	5	$	3,231
Interest rate swaps (b)	—		49		—		—		49		—		96		—		—		96
NDTs – equity securities (c)(d)	1,469		—		—				1,469		1,560		—		—				1,560
NDTs – debt securities (c)(e)	99		1,753		—				1,852		83		1,976		—				2,059
Sub-total	$	4,251	$	2,227	$	906	$	41	7,425		$	3,566	$	2,534	$	841	$	5	6,946
Assets measured at net asset value (f):
NDTs – equity securities (c)(d)(f)									783										821
NDTs - debt securities (c)(e)(f)									300										—
Total assets									$	8,508									$	7,767
Liabilities:
Commodity contracts (b)	$	3,002	$	1,183	$	1,850	$	41	$	6,076	$	2,118	$	975	$	1,593	$	5	$	4,691
Interest rate swaps (b)	—		29		—		—		29		—		27		—		—		27
Total liabilities	$	3,002	$	1,212	$	1,850	$	41	$	6,105	$	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 March 31, 2025.

(d)The investment objective for NDT equity securities is to invest tax efficiently and to match the performance of the S&P 500 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 4.24% and 3.99% as of March 31, 2025 and December 31, 2024, respectively, and an average maturity of eight years and seven years as of March 31, 2025 and December 31, 2024, respectively. NDT debt securities held as of March 31, 2025 mature as follows: $825 million in one to five years, $972 million in five to 10 years and $355 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.

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 March 31, 2025 and December 31, 2024:

March 31, 2025
	Fair Value
Contract Type (a)	Assets		Liabilities		Total, Net		Valuation Technique	Significant Unobservable Input	Range (b)			Average (b)
	(in millions)
Electricity purchases and sales	$	689	$	(1,616)	$	(927)	Income Approach	Hourly price curve shape (c)	$—	to	$95	$48
									MWh
								Illiquid delivery periods for hub power prices (d)	$25	to	$145	$85
									MWh
								Market Heat Rates (d)	$45	to	$120	$83
									MWh
Options	7		(181)		(174)		Option Pricing Model	Natural gas to power correlation (e)	—%	to	100%	50%
								Power and natural gas volatility (e)	5%	to	835%	420%
Financial transmission rights/Congestion revenue rights	196		(21)		175		Market Approach (f)	Illiquid price differences between settlement points (g)	$5	to	$25	$15
									MWh
Natural gas	12		(27)		(15)		Income Approach	Natural gas basis (h)	$(1)	to	$12	$5
									MMBtu
								Illiquid delivery periods (i)	$3	to	$5	$4
									MMBtu
Other (j)	2		(5)		(3)
Total	$	906	$	(1,850)	$	(944)

December 31, 2024
	Fair Value
Contract Type (a)	Assets		Liabilities		Total, Net		Valuation Technique	Significant Unobservable Input	Range (b)			Average (b)
	(in millions)
Electricity purchases and sales	$	606	$	(1,399)	$	(793)	Income Approach	Hourly price curve shape (c)	$—	to	$95	$48
									MWh
								Illiquid delivery periods for hub power prices (d)	$25	to	$140	$83
									MWh
								Market Heat Rates (d)	$30	to	$150	$90
									MWh
Options	6		(139)		(133)		Option Pricing Model	Natural gas to power correlation (e)	10%	to	100%	55%
								Power and natural gas volatility (e)	5%	to	710%	358%
Financial transmission rights/Congestion revenue rights	190		(25)		165		Market Approach (f)	Illiquid price differences between settlement points (g)	$(35)	to	$20	$(8)
									MWh
Natural gas	29		(30)		(1)		Income Approach	Natural gas basis (h)	$—	to	$10	$5
									MMBtu
								Illiquid delivery periods (i)	$—	to	$5	$2
									MMBtu
Other (j)	10		—		10
Total	$	841	$	(1,593)	$	(752)

____________

(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 March 31,
	2025		2024
	(in millions)
Net liability balance at beginning of period	$	(752)	$	(1,044)
Total unrealized valuation (losses)	(243)		(269)
Purchases, issuances and settlements (a):
Purchases	49		70
Issuances	(2)		(3)
Settlements	(7)		99
Transfers into Level 3 (b)	1		3
Transfers out of Level 3 (b)	10		8
Net liabilities assumed in connection with the Energy Harbor Merger	—		(13)
Net change	(192)		(105)
Net liability balance at end of period	$	(944)	$	(1,149)
Unrealized valuation (losses) relating to instruments held at end of period	$	(266)	$	(325)

____________

(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 March 31, 2025, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become observable. For the three months ended March 31, 2024, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of coal and natural gas derivatives where forward pricing inputs have become observable.

Assets and Liabilities Recorded on a Non-Recurring Basis

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

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

Fair Value of Debt

		March 31, 2025				December 31, 2024
Instrument:	Fair Value Hierarchy	Carrying Amount		Fair Value		Carrying Amount		Fair Value
		(in millions)
Long-term debt under the Vistra Operations Credit Facilities	Level 2	$	2,431	$	2,456	$	2,435	$	2,478
BCOP Credit Facilities Tax Credit Bridge Loan	Level 3	348		367		344		367
Vistra Zero Term Loan B Facility	Level 2	686		670		685		697
Vistra Operations Senior Notes	Level 2	12,371		12,483		12,366		12,428
Energy Harbor Revenue Bonds	Level 2	415		431		414		431
Equipment Financing Agreements	Level 3	54		54		54		53
Forward Repurchase Obligation	Level 3	1,355		1,355		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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Asset Retirement Obligations

3 Months Ended

Mar. 31, 2025

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

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 three months ended March 31, 2025 and 2024:

	Three Months Ended March 31, 2025						Three Months Ended March 31, 2024
	Nuclear Plant Decommissioning		Land Reclamation, Coal Ash and Other		Total		Nuclear 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)	37		11		48		23		10		33
Adjustment for change in estimates (b)	—		(33)		(33)		—		3		3
Adjustment for obligations assumed through acquisition	—		—		—		1,368		—		1,368
Reductions:
Payments	—		(20)		(20)		—		(17)		(17)
Liability at end of period	3,277		796		4,073		3,133		792		3,925
Less amounts due currently	—		(136)		(136)		—		(119)		(119)
Noncurrent liability at end of period	$	3,277	$	660	$	3,937	$	3,133	$	673	$	3,806

____________

(a)For the three months ended March 31, 2025 and 2024, nuclear plant decommissioning accretion includes $23 million and $9 million, respectively, of accretion expense recognized in operating costs in the condensed consolidated statements of operations and $14 million and $14 million, respectively, reflected as a change in regulatory liability in the condensed consolidated balance sheets.

(b)Includes non-cash adjustments to asset retirement costs included in property, plant, and equipment of $15 million and $1 million for the three months ended March 31, 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 March 31, 2025, the carrying value of our ARO related to our Comanche Peak nuclear generation facility decommissioning totaled $1.812 billion, which is lower than the fair value of the assets contained in the Comanche Peak NDT of $2.223 billion. The difference between the carrying value of the ARO and the NDT represents a regulatory liability of $411 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.

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.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2025

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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 March 31, 2025, we had outstanding letters of credit totaling $2.814 billion as follows:

•$2.439 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;

•$251 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

•$13 million for other credit support requirements.

Surety Bonds

As of March 31, 2025, we had outstanding surety bonds totaling $1.072 billion 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.

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.

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.

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

Moss Landing 300 Battery Fire

On January 16, 2025, we detected a fire at our Moss Landing 300 MW energy storage facility at the Moss Landing Power Plant site. We are working closely with all local, state, and federal regulatory authorities on the response, and we are investigating the cause of the fire. We are also responding to various regulatory bodies, including the CPUC, the EPA, and others investigating the incident. 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.

We are working closely with the EPA under a Notice of Federal Response Action pursuant to which the EPA is providing control and oversight of clean up and remediation efforts on the site. We are in ongoing discussions to develop an agreed upon order that will govern the clean-up and recovery efforts. As of March 31, 2025, we accrued approximately $70 million in obligations related to the Moss Landing Incident including approximately $30 million for anticipated air and soil monitoring requirements and $40 million for the expected costs of decommissioning the Moss Landing 300 structure, which includes demolition of the structure, removing and disposing of the batteries, and fulfilling land reclamation obligations. Aside from battery removal and disposal, our estimate does not reflect costs associated with removal of other hazardous waste which could be identified as the demolition progresses. 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 executive orders.

Greenhouse Gas Emissions (GHG)

In May 2023, the EPA released a proposal regulating power plant GHG emissions, while also proposing to repeal the Affordable Clean Energy (ACE) rule that had been finalized by the EPA in July 2019. In May 2024, the EPA published a final GHG rule that repealed the ACE rule and sets limits for (a) new natural gas-fired combustion turbines and (b) existing coal-, oil- and natural gas-fired steam generation units. The standards are based on technologies such as carbon capture and sequestration/storage (CCS) and natural gas co-firing. 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. In February 2025, the D.C. Circuit granted the unopposed motion filed by the Department of Justice on behalf of the EPA, holding the litigation in abeyance for a period of 60 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed.

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

In October 2015, the EPA revised the primary and secondary ozone National Ambient Air Quality Standards (NAAQS) to lower the 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. Nevertheless, 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.

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.

SO2 Designations for Texas

In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Martin Lake generation plant and our now retired Big Brown and Monticello plants. The final designations require Texas to develop nonattainment plans for these areas. Following legal challenges and additional agency actions, in January 2024, in a split decision, the Fifth Circuit Court denied the petitions for review we and the State of Texas filed over the EPA's 2016 nonattainment designation for SO2 for the area around Martin Lake. As a result of this decision, the EPA's nonattainment designation – originally made in 2016 – remains in place. In February 2024, we filed a petition asking the full Fifth Circuit Court to review the panel decision issued in January 2024, which remains pending before the full Fifth Circuit Court. In addition, in September 2021, the TCEQ considered a proposal for its nonattainment SIP revision for the Martin Lake area and an agreed order to reduce SO2 emissions from the plant. The TCEQ's SIP action was finalized in February 2022 and has been submitted to the EPA for review and approval. 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 of the SIP partial approval and disapproval in a future action. In February 2025, we, along with the State of Texas, filed a challenge to the Finding of Failure in the Fifth Circuit Court. That case is in abeyance until June 2025 so the new EPA can review the rule. If the EPA approves Texas's SIP in full, that would fully resolve this matter.

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.

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.

Legacy CCR Rulemaking

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

MISO — In 2012, the Illinois Environmental Protection Agency (IEPA) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities' CCR surface impoundments. 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.

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.

The FERC Office of Enforcement opened a formal, non-public investigation into whether market manipulation or other potential violations of the FERC orders, rules, and regulations occurred before or during the PRA.

In July 2019, the FERC issued an order denying complaints and closing the Office of Enforcement's investigation into Dynegy. Upon appeal, in 2021, the D.C. Circuit Court of Appeals remanded the case back to the FERC on a narrow question. In June 2022, the FERC issued an order on remand establishing paper hearing procedures and directing the Office of Enforcement to file a remand report within 90 days providing the Office of Enforcement's assessment of Dynegy's actions with regard to the 2015-2016 PRA. After the close of briefing in the 2022 remand proceeding, 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" that it believes cannot be resolved on the existing record, held the hearing in abeyance for the parties to engage in settlement discussions, and, in October 2024, issued an order dismissing our request for rehearing of the June 2024 order. We will continue to vigorously defend our position.

Other Matters

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

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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Equity

3 Months Ended

Mar. 31, 2025

Equity [Abstract]

Equity

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 $0.2235 and $0.2150 for the three months ended March 31, 2025 and 2024.

In May 2025, the Board declared a quarterly dividend of $0.225 per share of common stock that will be paid in June 2025.

Share Repurchase Program

The Board has authorized a $6.750 billion share repurchase program. Through May 2, 2025, 162,932,192 shares, at an average price of $31.96 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 May 2, 2025:

	$6.750 Billion Board Authorization
	Total Number of Shares Repurchased	Average Price Paid Per Share		Amount Paid for Shares Repurchased		Amount Available for Additional Repurchases at the End of the Period
	(in millions, except share amounts and price paid per share)
Three Months Ended March 31, 2025 (a)	2,437,700	$	137.66	$	336	$	1,673
April 1, 2025 through May 2, 2025	1,138,753	114.95		131
January 1, 2025 through May 2, 2025	3,576,453	$	130.43	$	467	$	1,542

____________

(a)Shares repurchased include 59,503 of unsettled shares for $7 million as of March 31, 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 Series	Issuance Date	Shares Issued	Shares Outstanding	Contractual Rates		Earliest Redemption Date (a)	Date at Which Dividend Rate Becomes Floating	Floating Annual Rates
Series A	October 15, 2021	1,000,000	1,000,000	8.000	%	October 15, 2026	October 15, 2026	5-Year U.S. Treasury rate (subject to floor of 1.07%) plus 6.93%
Series B	December 10, 2021	1,000,000	1,000,000	7.000	%	December 15, 2026	December 15, 2026	5-Year U.S. Treasury rate (subject to floor of 1.26%) plus 5.74%
Series C	December 29, 2023	476,081	476,066	8.875	%	January 15, 2029	January 15, 2029	5-Year U.S. Treasury rate (subject to floor of 3.83%) plus 5.045%

____________

(a)Subject to our right, in limited circumstances, to redeem preferred stock prior to the earliest redemption date.

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

Preferred Stock Dividends

Preferred stock dividends are payable semiannually in arrears when declared by the Board. The following table summarizes preferred stock dividends paid per share for the three months ended March 31, 2025 and 2024.

	Three Months Ended March 31,
Preferred Stock Series	2025		2024
Series C Preferred Stock	$	44.375	$	—

In February 2025, the Board declared a semi-annual dividend of $40.00 per share of Series A Preferred Stock that was paid in April 2025. In May 2025, the Board declared a semi-annual dividend of $35.00 per share of Series B Preferred Stock that will be paid in June 2025 and a semi-annual dividend of $44.375 per share of Series C Preferred Stock that will be paid in July 2025.

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Earnings Per Share

3 Months Ended

Mar. 31, 2025

Earnings Per Share [Abstract]

Earnings Per Share

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 March 31,
	2025		2024
	(in millions, except share data)
Net loss attributable to Vistra	$	(268)	$	(35)
Less cumulative dividends attributable to Series A Preferred Stock	(20)		(20)
Less cumulative dividends attributable to Series B Preferred Stock	(18)		(18)
Less cumulative dividends attributable to Series C Preferred Stock	(11)		(11)
Net loss attributable to common stock — basic and diluted	$	(317)	$	(84)
Weighted average shares of common stock outstanding:
Basic	339,799,989		348,966,197
Dilutive securities: Stock-based incentive compensation plan	—		—
Diluted	339,799,989		348,966,197
Net loss per weighted average share of common stock outstanding:
Basic	$	(0.93)	$	(0.24)
Diluted	$	(0.93)	$	(0.24)

Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 8,582,267 and 7,954,878 shares for the three months ended March 31, 2025 and 2024, respectively.

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Segment Information

3 Months Ended

Mar. 31, 2025

Segment Reporting [Abstract]

Segment Information

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, and other expenses not allocated to our operating segments.

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1 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.

	Three Months Ended March 31, 2025
	Retail		Texas		East		West		Asset Closure		Total Reportable Segments		Corporate and Other		Total
	(in millions)
Operating revenues	$	3,168	$	210	$	1,380	$	157	$	4	$	4,919	$	(986)	$	3,933
Fuel, purchased power costs, and delivery fees	(1,712)		(497)		(1,172)		(52)		—		(3,433)		986		(2,447)
Operating costs	(40)		(258)		(327)		(12)		(56)		(693)		—		(693)
Selling, general, and administrative expenses	(243)		(41)		(58)		(2)		(17)		(361)		(30)		(391)
Other segment items:
Depreciation and amortization	(23)		(150)		(316)		(15)		1		(503)		(19)		(522)
Interest expenses and related charges	(18)		14		12		1		(1)		8		(327)		(319)
Income tax benefit	—		—		—		—		—		—		176		176
Other (a)	—		2		(9)		—		1		(6)		1		(5)
Net income (loss)	$	1,132	$	(720)	$	(490)	$	77	$	(68)	$	(69)	$	(199)	$	(268)
Capital expenditures, including nuclear fuel and excluding growth expenditures	$	3	$	419	$	264	$	30	$	—	$	716	$	13	$	729

	Three Months Ended March 31, 2024
	Retail		Texas		East		West		Asset Closure		Total Reportable Segments		Corporate and Other		Total
	(in millions)
Operating revenues	$	2,494	$	459	$	856	$	276	$	9	$	4,094	$	(1,040)	$	3,054
Fuel, purchased power costs, and delivery fees	(1,647)		(381)		(647)		(79)		(2)		(2,756)		1,040		(1,716)
Operating costs	(31)		(257)		(181)		(11)		(17)		(497)		(1)		(498)
Selling, general, and administrative expenses	(225)		(35)		(28)		(4)		(10)		(302)		(49)		(351)
Other segment items:
Depreciation and amortization	(23)		(134)		(210)		(14)		(7)		(388)		(15)		(403)
Interest expenses and related charges	(6)		10		(1)		—		(1)		2		(172)		(170)
Income tax benefit	—		—		—		—		—		—		20		20
Other (a)	(1)		2		38		—		3		42		40		82
Net income (loss)	$	561	$	(336)	$	(173)	$	168	$	(25)	$	195	$	(177)	$	18
Capital expenditures, including nuclear fuel and excluding growth expenditures	$	—	$	316	$	88	$	6	$	—	$	410	$	11	$	421

____________

(a)Other includes other income (deductions) and the impacts of the Tax Receivable Agreement.

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Supplementary Financial Information

3 Months Ended

Mar. 31, 2025

Supplementary Financial Information [Abstract]

Supplementary Financial Information

SUPPLEMENTARY FINANCIAL INFORMATION

Other Income (Deductions), Net

	Three Months Ended March 31,
	2025		2024
	(in millions)
NDT net income (loss) (a)	$	(10)	$	35
Insurance settlements (b)	—		1
Gain on sale of land	—		1
Gain on TRA settlement (c)	—		10
Interest income	6		23
All other	(1)		17
Total other income (deductions), net	$	(5)	$	87

____________

(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)Reported in the Asset Closure segment.

(c)Reported in Corporate and Other.

Inventories by Major Category

	March 31, 2025		December 31, 2024
	(in millions)
Materials and supplies	$	541	$	533
Fuel stock	399		403
Natural gas in storage	20		34
Total inventories	$	960	$	970

Investments

	March 31, 2025		December 31, 2024
	(in millions)
Nuclear decommissioning trusts	$	4,404	$	4,440
Assets related to employee benefit plans	13		14
Land investments	42		42
Other investments	17		16
Total investments	$	4,476	$	4,512

Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:

	March 31, 2025		December 31, 2024
	(in millions)
Retirement and other employee benefits	$	204	$	224
Identifiable intangible liabilities	149		155
Regulatory liability (a)	411		452
Operating lease liabilities	81		98
Finance lease liabilities	217		218
Liability for third-party remediation	8		8
Accrued severance costs	36		36
Tax Receivable Agreement obligation	12		14
Other accrued expenses	110		65
Total other noncurrent liabilities and deferred credits	$	1,228	$	1,270

____________

(a)As of March 31, 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 $411 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 March 31, 2025 and December 31, 2024:

	March 31, 2025		December 31, 2024
	(in millions)
Cash and cash equivalents	$	561	$	1,188
Restricted cash included in current assets	29		28
Restricted cash included in noncurrent assets	6		6
Total cash, cash equivalents and restricted cash	$	596	$	1,222

The following table summarizes our supplemental cash flow information for the three months ended March 31, 2025 and 2024. Non-cash investing and financing activities for the three months ended March 31, 2024 includes activity related to the Energy Harbor Merger (see Note 2 for additional information).

	Three Months Ended March 31,
	2025		2024
	(in millions)
Cash payments related to:
Interest paid	$	210	$	214
Capitalized interest	(29)		(12)
Interest paid (net of capitalized interest)	$	181	$	202

For the three months ended March 31, 2025 and 2024, we paid state income taxes of $5 million and $3 million respectively, and received state tax refunds of zero and $1 million, respectively.

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Pay vs Performance Disclosure - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Pay vs Performance Disclosure
Net loss attributable to Vistra	$ (268)	$ (35)

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Insider Trading Arrangements	3 Months Ended
	Mar. 31, 2025
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

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Business, Significant Accounting Policies, Significant Events, and Recent Developments (Policies)

3 Months Ended

Mar. 31, 2025

Accounting Policies [Abstract]

Basis of Presentation

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.

Consolidation

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

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

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.

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.

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Acquisitions (Tables)

3 Months Ended

Mar. 31, 2025

Business Combination, Asset Acquisition, and Joint Venture Formation [Abstract]

Schedule of Business Acquisitions, by Acquisition

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 price	4,596
Fair value of noncontrolling interest in Energy Harbor (b)	811
Acquisition date fair value of Energy Harbor	$	5,407

____________

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

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

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

	Fair Value as of March 1, 2024		Measurement Period Adjustments recorded since March 1, 2024
	(in millions)
Cash and cash equivalents	$	35	$	5
Trade accounts receivables, inventories, prepaid expenses and other current assets	540		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 assets	62		54
Total identifiable assets acquired	8,847		62
Trade accounts payable and other current liabilities	318		55
Long-term debt, including amounts due currently	413		—
Commodity and other derivative contractual liabilities (d)	179		—
Accumulated deferred income taxes	1,314		(50)
Asset retirement obligations (e)	1,368		—
Identifiable intangible liabilities	55		(18)
Other noncurrent liabilities and deferred credits	20		8
Total identifiable liabilities assumed	3,667		(5)
Identifiable net assets acquired	5,180		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.

Schedule of Business Acquisitions, Pro Forma Information

The following unaudited pro forma financial information for the three months ended March 31, 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 March 31, 2024
	(in millions)
Revenues	$	3,777
Net income	$	69

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Revenue (Tables)

3 Months Ended

Mar. 31, 2025

Revenue from Contract with Customer [Abstract]

Schedule of Disaggregation of Revenue

The following tables disaggregate our revenue by major source:

	Three Months Ended March 31, 2025
	Retail		Texas		East		West		Asset Closure		Eliminations / Corporate and Other		Consolidated
	(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	1,986	$	—	$	—	$	—	$	—	$	—	$	1,986
Retail energy charge in Northeast/Midwest	1,039		—		—		—		—		—		1,039
Wholesale generation revenue from ISO/RTO	—		78		770		26		—		—		874
Capacity revenue from ISO/RTO (a)	—		—		20		—		—		—		20
Revenue from other wholesale contracts	—		129		130		68		4		—		331
Total revenue from contracts with customers	3,025		207		920		94		4		—		4,250
Other revenues:
Transferable PTC revenues (b)	—		2		—		—		—		—		2
Hedging revenues — realized	274		(27)		(78)		26		—		—		195
Hedging revenues — unrealized	(157)		(143)		(250)		36		1		—		(513)
Intangible amortization and other revenues	—		—		(1)		—		—		—		(1)
Intersegment sales (c)	26		171		789		1		(1)		(986)		—
Total other revenues	143		3		460		63		—		(986)		(317)
Total revenues	$	3,168	$	210	$	1,380	$	157	$	4	$	(986)	$	3,933

____________

(a)Includes $73 million of capacity sold offset by $53 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 solar assets during the period.

(c)The Texas and East segments include $883 million and $271 million, respectively, of intersegment unrealized net losses, and West segment includes $1 million of intersegment net gains from mark-to-market valuations of commodity positions with the Retail segment.

	Three Months Ended March 31, 2024
	Retail		Texas		East (a)		West		Asset Closure		Eliminations / Corporate and Other		Consolidated
	(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	1,702	$	—	$	—	$	—	$	—	$	—	$	1,702
Retail energy charge in Northeast/Midwest (a)	663		—		—		—		—		—		663
Wholesale generation revenue from ISO/RTO	—		68		333		79		9		—		489
Capacity revenue from ISO/RTO (b)	—		—		19		—		—		—		19
Revenue from other wholesale contracts	—		104		125		57		—		—		286
Total revenue from contracts with customers	2,365		172		477		136		9		—		3,159
Other revenues:
Transferable PTC revenues	—		2		—		—		—		—		2
Hedging revenues — realized	278		(110)		74		3		(4)		—		241
Hedging revenues — unrealized	(155)		(132)		(200)		136		4		—		(347)
Intangible amortization and other revenues	—		—		(1)		—		—		—		(1)
Intersegment sales (c)	6		527		506		1		—		(1,040)		—
Total other revenues	129		287		379		140		—		(1,040)		(105)
Total revenues	$	2,494	$	459	$	856	$	276	$	9	$	(1,040)	$	3,054

____________

(a)Includes revenues associated with March 2024 operations acquired in the Energy Harbor Merger.

(b)Represents net capacity sold in each ISO/RTO. The East segment includes $40 million of capacity sold offset by $21 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 $7 million offset by $2 million of capacity sold within the East segment.

(c)Texas and East segments include $490 million and $291 million, respectively, of intersegment unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

Schedule of Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

As of March 31, 2025, we have future fixed fee performance obligations that are unsatisfied, or partially unsatisfied, relating to capacity auction volumes awarded through capacity auctions held by the ISO/RTO or 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		2026		2027		2028		2029		2030 and Thereafter		Total
	(in millions)
Remaining performance obligations	$	934	$	832	$	292	$	122	$	62	$	548	$	2,790

Schedule of Accounts, Notes, Loans and Financing Receivable

Trade Accounts Receivable

	March 31, 2025		December 31, 2024
	(in millions)
Wholesale and retail trade accounts receivable	$	1,999	$	2,061
Allowance for credit losses	(75)		(79)
Trade accounts receivable — net	$	1,924	$	1,982
Trade accounts receivable from contracts with customers — net	$	1,494	$	1,514
Other trade accounts receivable — net	430		468
Trade accounts receivable — net	$	1,924	$	1,982

Allowance for Credit Losses on Accounts Receivable

	Three Months Ended March 31,
	2025		2024
	(in millions)
Allowance for credit losses on accounts receivable at beginning of period	$	79	$	61
Increase for bad debt expense	44		36
Decrease for account write-offs	(48)		(36)
Allowance for credit losses on accounts receivable at end of period	$	75	$	61

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2025

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation

The components of our income tax (expense) benefit are as follows:

	Three Months Ended March 31,
	2025			2024
	(in millions)
Net loss before income taxes	$	(444)		$	(2)
Income tax benefit	$	176		$	20
Effective tax rate	39.6		%	1,000.0		%

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Property, Plant, and Equipment (Tables)

3 Months Ended

Mar. 31, 2025

Property, Plant and Equipment [Abstract]

Schedule of Property, Plant and Equipment

	March 31, 2025		December 31, 2024
	(in millions)
Power generation and structures	$	22,303	$	22,783
Office and other equipment	172		160
Land	603		603
Construction work in progress	1,394		1,060
Finance lease right-of-use assets	186		186
Nuclear fuel	2,032		1,843
Property, plant and equipment — gross	26,690		26,635
Less accumulated depreciation	(8,415)		(8,020)
Less finance lease right-of-use assets accumulated amortization	(35)		(33)
Less accumulated amortization on nuclear fuel	(524)		(409)
Property, plant and equipment — net	$	17,716	$	18,173

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 Equipment	Condensed Consolidated Statements of Operations	Three Months Ended March 31,
		2025		2024
		(in millions)
Power generation and structures and office and other equipment	Depreciation and amortization	$	479	$	365
Finance lease right-of-use assets	Depreciation and amortization	2		2
Nuclear fuel	Fuel, purchased power costs, and delivery fees	111		49
Total property, plant, and equipment expense		$	592	$	416

Schedule of Planned Retirements of Generation Capacity

Below are our facilities that are retired or have an announced retirement date. Operating results for generation facilities with defined retirement dates are included in our Asset Closure segment at the beginning of the calendar year the retirement 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.

Facility	Location	ISO/RTO	Fuel Type	Net Capacity (MW)	Expected or Actual Retirement Date (a)	Segment
Baldwin	Baldwin, IL	MISO	Coal	1,185	By the end of 2027	East
Coleto Creek (b)	Goliad, TX	ERCOT	Coal	650	By the end of 2027	Texas
Kincaid	Kincaid, IL	PJM	Coal	1,108	By the end of 2027	East
Miami Fort	North Bend, OH	PJM	Coal	1,020	By the end of 2027	East
Newton	Newton, IL	MISO	Coal	615	By the end of 2027	East
Edwards	Bartonville, IL	MISO	Coal	585	Retired January 1, 2023	Asset Closure
Total				5,163

____________

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

(b)The Company intends to repower Coleto Creek as a gas-fueled facility upon its retirement as a coal-fueled facility.

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Goodwill and Identifiable Intangible Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2025

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

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

	Retail Segment		Texas Segment
	Retail Reporting Unit (a)		Texas Generation Reporting Unit		Goodwill Pending Allocation		Total 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 March 31, 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).

Schedule of Identifiable Intangible Assets

Identifiable intangible assets are comprised of the following:

	March 31, 2025						December 31, 2024
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
	(in millions)
Retail customer relationships	$	2,173	$	1,999	$	174	$	2,173	$	1,977	$	196
Software and other technology-related assets	616		312		304		601		293		308
Retail and wholesale contracts	503		373		130		503		353		150
Long-term service agreements	18		5		13		18		5		13
Other identifiable intangible assets (a)	373		14		359		218		13		205
Total identifiable intangible assets subject to amortization	$	3,683	$	2,703	980		$	3,513	$	2,641	872
Retail trade names (not subject to amortization)					1,341						1,341
Total identifiable intangible assets					$	2,321					$	2,213

____________

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

Schedule of Identifiable Intangible Liabilities

Identifiable intangible liabilities are comprised of the following:

Identifiable Intangible Liability	March 31, 2025		December 31, 2024
	(in millions)
Long-term service agreements	$	104	$	108
Wholesale power and fuel purchase contracts	45		47
Total identifiable intangible liabilities	$	149	$	155

Schedule of Amortization Expense Related to Intangible Assets and Liabilities

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/Liabilities	Condensed Consolidated Statements of Operations		Three Months Ended March 31,
			2025		2024
		(in millions)
Retail customer relationships	Depreciation and amortization		$	23	$	22
Software and other technology-related assets	Depreciation and amortization		18		13
Retail and wholesale contracts	Operating revenues/Fuel, purchased power costs, and delivery fees		(2)		1
Other identifiable intangible assets (a)	Fuel, purchased power costs, and delivery fees/Depreciation and amortization		136		103
Total intangible asset expense, net			$	175	$	139

___________

(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.

Schedule of Estimated Amortization Expense of Identifiable Intangible Assets and Liabilities

As of March 31, 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.

Year	Estimated Amortization Expense
	(in millions)
2025	$	237
2026	$	177
2027	$	80
2028	$	59
2029	$	41

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Debt, Credit Facilities and Financings (Tables)

3 Months Ended

Mar. 31, 2025

Debt Disclosure [Abstract]

Schedule of Debt

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

	March 31, 2025		December 31, 2024
	(in millions)
Long-term debt, including amounts due currently:
Project-level debt	$	1,064	$	1,064
Vistra Operations debt	15,399		15,405
Long -term debt before unamortized premiums, discounts and issuance costs	16,463		16,469
Unamortized premiums, discounts and issuance costs	(158)		(171)
Long-term debt including amounts due currently	$	16,305	$	16,298
Accounts receivable financing	$	1,082	$	750
Forward repurchase obligation	$	1,355	$	1,335

Schedule of Long-Term Debt Instruments

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

	March 31, 2025		December 31, 2024
	(in millions)
Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030	$	2,469	$	2,475
BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026	367		367
Vistra Zero Credit Facility, Term Loan B Facility due April 30, 2031	697		697
Vistra Operations Senior Secured Notes:
5.125% Senior Secured Notes, due May 13, 2025	744		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 Notes	5,144		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 Bonds	431		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 15, 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 Notes	7,300		7,300
Other:
Equipment Financing Agreements	55		55
Total other long-term debt	55		55
Unamortized debt premiums, discounts and issuance costs	(158)		(171)
Total long-term debt including amounts due currently	16,305		16,298
Less amounts due currently	(882)		(880)
Total long-term debt, less amounts due currently	$	15,423	$	15,418

Schedule of Maturities of Long-Term Debt

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

	March 31, 2025
	(in millions)
Remainder of 2025	$	879
2026	1,792
2027	3,427
2028	27
2029	2,177
Thereafter	8,161
Unamortized premiums, discounts and debt issuance costs	(158)
Total long-term debt, including amounts due currently	$	16,305

Schedule of Line of Credit Facilities

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

		March 31, 2025
Credit Facilities	Maturity Date	Facility Limit		Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)		Letters of Credit Outstanding		Available Capacity
		(in millions)
Vistra Operations debt:
Revolving Credit Facility	October 11, 2029	$	3,440	$	—	$	1,223	$	2,217
Term Loan B-3 Facility	December 20, 2030	2,469		2,469		—		—
Total Vistra Operations Credit Facilities		$	5,909	$	2,469	$	1,223	$	2,217
Vistra Operations Commodity-Linked Facility	October 1, 2025	1,750		—		—		1,125
Total Vistra Operations debt		$	7,659	$	2,469	$	1,223	$	3,342
Project-level debt:
Tax Credit Bridge Loan	November 1, 2025	106		106		—		—
Tax Credit Bridge Loan	December 3, 2026	261		261		—		—
BCOP Credit Facility		367		367		—		—
Vistra Zero Term Loan B Facility (a)	April 30, 2031	697		697		—		—
Total project-level debt		$	1,064	$	1,064	$	—	$	—
Total credit facilities		$	8,723	$	3,533	$	1,223	$	3,342

___________

(a)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.

Schedule of Repurchase Obligation

Payments remaining due to Nuveen are as follows:

	March 31, 2025
	(in millions)
Remainder of 2025	$	781
2026	669
Thereafter	—
Total scheduled payments under the UPAs	$	1,450

Schedule of Interest Expense and Related Charges

	Three Months Ended March 31,
	2025		2024
	(in millions)
Interest expense	$	272	$	208
Unrealized mark-to-market net (gains) losses on interest rate swaps	48		(47)
Amortization of debt issuance costs, discounts, and premiums	11		7
Debt extinguishment gain	—		(6)
Capitalized interest	(29)		(12)
Other	17		20
Total interest expense and related charges	$	319	$	170

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Derivatives (Tables)

3 Months Ended

Mar. 31, 2025

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Interest Rate Derivatives

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

	Notional Amount	Expiration Date	Rate Range (d)
	(in millions, except percentages)
Swapped to fixed (a)	$3,000	July 2026	2.89	%	-	2.97%
Swapped to variable (a)	$700	July 2026	1.44	%	-	1.49%
Swapped to fixed (b)	$2,300	December 2030	3.20	%	-	3.76%
Swapped to fixed (c)	$108	March 2045	3.95%

____________

(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, BCOP entered into approximately $108 million notional amount of interest rate swaps effective April 1, 2025 and expiring in March 2045. These swaps will hedge BCOP's exposure on approximately $108 million of floating rate Construction/Term Loan Facility commitments (see Note 9 for additional information).

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

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

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.

	March 31, 2025
	Derivative Contract Assets				Derivative Contract Liabilities
	Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total
	(in millions)
Current assets	$	3,306	$	28	$	1	$	—	$	3,335
Noncurrent assets	729		21		19		—		769
Current liabilities	(7)		—		(4,622)		(17)		(4,646)
Noncurrent liabilities	(14)		—		(1,433)		(12)		(1,459)
Net assets (liabilities)	$	4,014	$	49	$	(6,035)	$	(29)	$	(2,001)
Offsetting instruments (a)	(3,381)		(22)		3,381		22		—
Financial collateral (received) pledged (b)	(17)		—		331		—		314
Net amounts	$	616	$	27	$	(2,323)	$	(7)	$	(1,687)

	December 31, 2024
	Derivative Contract Assets				Derivative Contract Liabilities
	Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total
	(in millions)
Current assets	$	2,551	$	34	$	2	$	—	$	2,587
Noncurrent assets	677		62		1		—		740
Current liabilities	—		—		(3,333)		(18)		(3,351)
Noncurrent liabilities	(2)		—		(1,356)		(9)		(1,367)
Net assets (liabilities)	$	3,226	$	96	$	(4,686)	$	(27)	$	(1,391)
Offsetting instruments (a)	(2,532)		(28)		2,532		28		—
Financial collateral (received) pledged (b)	(50)		—		233		—		183
Net amounts	$	644	$	68	$	(1,921)	$	1	$	(1,208)

____________

(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.

Schedule of Pretax Effect on Net Income of Derivatives Not Under Hedge Accounting, Including Realized and Unrealized Effects

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 months ended March 31, 2025 and 2024:

Derivative (condensed consolidated statements of operations presentation)	Three Months Ended March 31,
	2025		2024
	(in millions)
Reversals of previously recognized unrealized (gain) loss on derivative instruments:
Commodity contracts unrealized (gain) loss in operating revenues (a)	$	212	$	261
Commodity contracts unrealized (gain) loss in fuel, purchased power costs, and delivery fees (a)	(23)		126
Interest rate swaps unrealized (gain) loss in interest expense and related charges	(5)		(11)
Total reversals of previously recognized unrealized (gain) loss on derivative instruments	$	184	$	376
Unrealized net gain (loss) from changes in fair value on derivative instruments:
Commodity contracts unrealized gain (loss) in operating revenues	$	(725)	$	(608)
Commodity contracts unrealized gain (loss) in fuel, purchased power costs, and delivery fees	(31)		45
Interest rate swaps unrealized gain (loss) in interest expense and related charges	(43)		58
Total unrealized net gain (loss) from change in fair value on derivative instruments	$	(799)	$	(505)
Net gain (loss) on derivative instruments	$	(615)	$	(129)

____________

(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.

Schedule of Notional Amounts of Outstanding Derivative Positions

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:

	March 31, 2025		December 31, 2024
Derivative type	Notional Volume				Unit of Measure
Natural gas	4,563		4,568		Million MMBtu
Electricity	831,426		796,982		GWh
Financial transmission rights / Congestion revenue rights	224,032		248,742		GWh
Coal	27		27		Million U.S. tons
Fuel oil	—		2		Million gallons
Emissions	29		28		Million U.S. tons
Renewable energy certificates	28		31		Million certificates
Interest rate swaps – variable/fixed	$	5,408	$	5,300	Million U.S. dollars
Interest rate swaps – fixed/variable	$	700	$	700	Million U.S. dollars

Schedules of Credit Risk-Related Contingent Features of Derivatives

The following table presents the commodity derivative liabilities subject to credit risk-related contingent features that are not fully collateralized:

	March 31, 2025		December 31, 2024
	(in millions)
Fair value of derivative contract liabilities (a)	$	(1,963)	$	(1,587)
Offsetting fair value under netting arrangements (b)	792		724
Cash collateral and letters of credit	563		471
Liquidity exposure	$	(608)	$	(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.

Schedules of Concentration of Risk

	March 31, 2025
	(in millions, except percentages)
Credit risk exposure to derivative contract counterparties:
Gross exposure	$	4,431
Net exposure (a)	$	689
Largest net exposure from any single counterparty (a)	$	272
Percent of credit risk exposure to derivative contract counterparties related to banking and financial sector
Gross exposure	80		%
Net exposure (a)	23		%

____________

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

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2025

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on 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:

	March 31, 2025										December 31, 2024
	Level 1		Level 2		Level 3		Reclass (a)		Total		Level 1		Level 2		Level 3		Reclass (a)		Total
	(in millions)
Assets:
Commodity contracts (b)	$	2,683	$	425	$	906	$	41	$	4,055	$	1,923	$	462	$	841	$	5	$	3,231
Interest rate swaps (b)	—		49		—		—		49		—		96		—		—		96
NDTs – equity securities (c)(d)	1,469		—		—				1,469		1,560		—		—				1,560
NDTs – debt securities (c)(e)	99		1,753		—				1,852		83		1,976		—				2,059
Sub-total	$	4,251	$	2,227	$	906	$	41	7,425		$	3,566	$	2,534	$	841	$	5	6,946
Assets measured at net asset value (f):
NDTs – equity securities (c)(d)(f)									783										821
NDTs - debt securities (c)(e)(f)									300										—
Total assets									$	8,508									$	7,767
Liabilities:
Commodity contracts (b)	$	3,002	$	1,183	$	1,850	$	41	$	6,076	$	2,118	$	975	$	1,593	$	5	$	4,691
Interest rate swaps (b)	—		29		—		—		29		—		27		—		—		27
Total liabilities	$	3,002	$	1,212	$	1,850	$	41	$	6,105	$	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 March 31, 2025.

(d)The investment objective for NDT equity securities is to invest tax efficiently and to match the performance of the S&P 500 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 4.24% and 3.99% as of March 31, 2025 and December 31, 2024, respectively, and an average maturity of eight years and seven years as of March 31, 2025 and December 31, 2024, respectively. NDT debt securities held as of March 31, 2025 mature as follows: $825 million in one to five years, $972 million in five to 10 years and $355 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.

Schedule of Fair Value of the Level 3 Assets and Liabilities by Major Contract Type and the Significant Unobservable Inputs Used in the Valuations

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 March 31, 2025 and December 31, 2024:

March 31, 2025
	Fair Value
Contract Type (a)	Assets		Liabilities		Total, Net		Valuation Technique	Significant Unobservable Input	Range (b)			Average (b)
	(in millions)
Electricity purchases and sales	$	689	$	(1,616)	$	(927)	Income Approach	Hourly price curve shape (c)	$—	to	$95	$48
									MWh
								Illiquid delivery periods for hub power prices (d)	$25	to	$145	$85
									MWh
								Market Heat Rates (d)	$45	to	$120	$83
									MWh
Options	7		(181)		(174)		Option Pricing Model	Natural gas to power correlation (e)	—%	to	100%	50%
								Power and natural gas volatility (e)	5%	to	835%	420%
Financial transmission rights/Congestion revenue rights	196		(21)		175		Market Approach (f)	Illiquid price differences between settlement points (g)	$5	to	$25	$15
									MWh
Natural gas	12		(27)		(15)		Income Approach	Natural gas basis (h)	$(1)	to	$12	$5
									MMBtu
								Illiquid delivery periods (i)	$3	to	$5	$4
									MMBtu
Other (j)	2		(5)		(3)
Total	$	906	$	(1,850)	$	(944)

December 31, 2024
	Fair Value
Contract Type (a)	Assets		Liabilities		Total, Net		Valuation Technique	Significant Unobservable Input	Range (b)			Average (b)
	(in millions)
Electricity purchases and sales	$	606	$	(1,399)	$	(793)	Income Approach	Hourly price curve shape (c)	$—	to	$95	$48
									MWh
								Illiquid delivery periods for hub power prices (d)	$25	to	$140	$83
									MWh
								Market Heat Rates (d)	$30	to	$150	$90
									MWh
Options	6		(139)		(133)		Option Pricing Model	Natural gas to power correlation (e)	10%	to	100%	55%
								Power and natural gas volatility (e)	5%	to	710%	358%
Financial transmission rights/Congestion revenue rights	190		(25)		165		Market Approach (f)	Illiquid price differences between settlement points (g)	$(35)	to	$20	$(8)
									MWh
Natural gas	29		(30)		(1)		Income Approach	Natural gas basis (h)	$—	to	$10	$5
									MMBtu
								Illiquid delivery periods (i)	$—	to	$5	$2
									MMBtu
Other (j)	10		—		10
Total	$	841	$	(1,593)	$	(752)

____________

(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.

Schedule of Changes in Fair Value of the Level 3 Assets and Liabilities

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

	Three Months Ended March 31,
	2025		2024
	(in millions)
Net liability balance at beginning of period	$	(752)	$	(1,044)
Total unrealized valuation (losses)	(243)		(269)
Purchases, issuances and settlements (a):
Purchases	49		70
Issuances	(2)		(3)
Settlements	(7)		99
Transfers into Level 3 (b)	1		3
Transfers out of Level 3 (b)	10		8
Net liabilities assumed in connection with the Energy Harbor Merger	—		(13)
Net change	(192)		(105)
Net liability balance at end of period	$	(944)	$	(1,149)
Unrealized valuation (losses) relating to instruments held at end of period	$	(266)	$	(325)

____________

(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 March 31, 2025, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become observable. For the three months ended March 31, 2024, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of coal and natural gas derivatives where forward pricing inputs have become observable.

Schedule of Fair Value of Debt

		March 31, 2025				December 31, 2024
Instrument:	Fair Value Hierarchy	Carrying Amount		Fair Value		Carrying Amount		Fair Value
		(in millions)
Long-term debt under the Vistra Operations Credit Facilities	Level 2	$	2,431	$	2,456	$	2,435	$	2,478
BCOP Credit Facilities Tax Credit Bridge Loan	Level 3	348		367		344		367
Vistra Zero Term Loan B Facility	Level 2	686		670		685		697
Vistra Operations Senior Notes	Level 2	12,371		12,483		12,366		12,428
Energy Harbor Revenue Bonds	Level 2	415		431		414		431
Equipment Financing Agreements	Level 3	54		54		54		53
Forward Repurchase Obligation	Level 3	1,355		1,355		1,335		1,335

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Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2025

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations

The following table summarizes the changes to our current and noncurrent ARO liabilities for the three months ended March 31, 2025 and 2024:

	Three Months Ended March 31, 2025						Three Months Ended March 31, 2024
	Nuclear Plant Decommissioning		Land Reclamation, Coal Ash and Other		Total		Nuclear 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)	37		11		48		23		10		33
Adjustment for change in estimates (b)	—		(33)		(33)		—		3		3
Adjustment for obligations assumed through acquisition	—		—		—		1,368		—		1,368
Reductions:
Payments	—		(20)		(20)		—		(17)		(17)
Liability at end of period	3,277		796		4,073		3,133		792		3,925
Less amounts due currently	—		(136)		(136)		—		(119)		(119)
Noncurrent liability at end of period	$	3,277	$	660	$	3,937	$	3,133	$	673	$	3,806

____________

(a)For the three months ended March 31, 2025 and 2024, nuclear plant decommissioning accretion includes $23 million and $9 million, respectively, of accretion expense recognized in operating costs in the condensed consolidated statements of operations and $14 million and $14 million, respectively, reflected as a change in regulatory liability in the condensed consolidated balance sheets.

(b)Includes non-cash adjustments to asset retirement costs included in property, plant, and equipment of $15 million and $1 million for the three months ended March 31, 2025 and 2024, respectively.

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Equity (Tables)

3 Months Ended

Mar. 31, 2025

Equity [Abstract]

Schedule of Repurchase Agreements

The following table provides information about our repurchases of common stock for the period between January 1, 2025 and May 2, 2025:

	$6.750 Billion Board Authorization
	Total Number of Shares Repurchased	Average Price Paid Per Share		Amount Paid for Shares Repurchased		Amount Available for Additional Repurchases at the End of the Period
	(in millions, except share amounts and price paid per share)
Three Months Ended March 31, 2025 (a)	2,437,700	$	137.66	$	336	$	1,673
April 1, 2025 through May 2, 2025	1,138,753	114.95		131
January 1, 2025 through May 2, 2025	3,576,453	$	130.43	$	467	$	1,542

____________

(a)Shares repurchased include 59,503 of unsettled shares for $7 million as of March 31, 2025.

Schedule of Dividends Declared

The following is a summary of our cumulative redeemable preferred stock outstanding. In the event of liquidation or dissolution of the Company, the payment of dividends and the distribution of assets to preferred stockholders takes precedence over the Company's common stockholders.

Preferred Stock Series	Issuance Date	Shares Issued	Shares Outstanding	Contractual Rates		Earliest Redemption Date (a)	Date at Which Dividend Rate Becomes Floating	Floating Annual Rates
Series A	October 15, 2021	1,000,000	1,000,000	8.000	%	October 15, 2026	October 15, 2026	5-Year U.S. Treasury rate (subject to floor of 1.07%) plus 6.93%
Series B	December 10, 2021	1,000,000	1,000,000	7.000	%	December 15, 2026	December 15, 2026	5-Year U.S. Treasury rate (subject to floor of 1.26%) plus 5.74%
Series C	December 29, 2023	476,081	476,066	8.875	%	January 15, 2029	January 15, 2029	5-Year U.S. Treasury rate (subject to floor of 3.83%) plus 5.045%

____________

(a)Subject to our right, in limited circumstances, to redeem preferred stock prior to the earliest redemption date.

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 months ended March 31, 2025 and 2024.

	Three Months Ended March 31,
Preferred Stock Series	2025		2024
Series C Preferred Stock	$	44.375	$	—

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2025

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

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 March 31,
	2025		2024
	(in millions, except share data)
Net loss attributable to Vistra	$	(268)	$	(35)
Less cumulative dividends attributable to Series A Preferred Stock	(20)		(20)
Less cumulative dividends attributable to Series B Preferred Stock	(18)		(18)
Less cumulative dividends attributable to Series C Preferred Stock	(11)		(11)
Net loss attributable to common stock — basic and diluted	$	(317)	$	(84)
Weighted average shares of common stock outstanding:
Basic	339,799,989		348,966,197
Dilutive securities: Stock-based incentive compensation plan	—		—
Diluted	339,799,989		348,966,197
Net loss per weighted average share of common stock outstanding:
Basic	$	(0.93)	$	(0.24)
Diluted	$	(0.93)	$	(0.24)

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2025

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

	Three Months Ended March 31, 2025
	Retail		Texas		East		West		Asset Closure		Total Reportable Segments		Corporate and Other		Total
	(in millions)
Operating revenues	$	3,168	$	210	$	1,380	$	157	$	4	$	4,919	$	(986)	$	3,933
Fuel, purchased power costs, and delivery fees	(1,712)		(497)		(1,172)		(52)		—		(3,433)		986		(2,447)
Operating costs	(40)		(258)		(327)		(12)		(56)		(693)		—		(693)
Selling, general, and administrative expenses	(243)		(41)		(58)		(2)		(17)		(361)		(30)		(391)
Other segment items:
Depreciation and amortization	(23)		(150)		(316)		(15)		1		(503)		(19)		(522)
Interest expenses and related charges	(18)		14		12		1		(1)		8		(327)		(319)
Income tax benefit	—		—		—		—		—		—		176		176
Other (a)	—		2		(9)		—		1		(6)		1		(5)
Net income (loss)	$	1,132	$	(720)	$	(490)	$	77	$	(68)	$	(69)	$	(199)	$	(268)
Capital expenditures, including nuclear fuel and excluding growth expenditures	$	3	$	419	$	264	$	30	$	—	$	716	$	13	$	729

	Three Months Ended March 31, 2024
	Retail		Texas		East		West		Asset Closure		Total Reportable Segments		Corporate and Other		Total
	(in millions)
Operating revenues	$	2,494	$	459	$	856	$	276	$	9	$	4,094	$	(1,040)	$	3,054
Fuel, purchased power costs, and delivery fees	(1,647)		(381)		(647)		(79)		(2)		(2,756)		1,040		(1,716)
Operating costs	(31)		(257)		(181)		(11)		(17)		(497)		(1)		(498)
Selling, general, and administrative expenses	(225)		(35)		(28)		(4)		(10)		(302)		(49)		(351)
Other segment items:
Depreciation and amortization	(23)		(134)		(210)		(14)		(7)		(388)		(15)		(403)
Interest expenses and related charges	(6)		10		(1)		—		(1)		2		(172)		(170)
Income tax benefit	—		—		—		—		—		—		20		20
Other (a)	(1)		2		38		—		3		42		40		82
Net income (loss)	$	561	$	(336)	$	(173)	$	168	$	(25)	$	195	$	(177)	$	18
Capital expenditures, including nuclear fuel and excluding growth expenditures	$	—	$	316	$	88	$	6	$	—	$	410	$	11	$	421

____________

(a)Other includes other income (deductions) and the impacts of the Tax Receivable Agreement.

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Supplementary Financial Information (Tables)

3 Months Ended

Mar. 31, 2025

Supplementary Financial Information [Abstract]

Schedule of Other Income and Deductions

	Three Months Ended March 31,
	2025		2024
	(in millions)
NDT net income (loss) (a)	$	(10)	$	35
Insurance settlements (b)	—		1
Gain on sale of land	—		1
Gain on TRA settlement (c)	—		10
Interest income	6		23
All other	(1)		17
Total other income (deductions), net	$	(5)	$	87

____________

(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)Reported in the Asset Closure segment.

(c)Reported in Corporate and Other.

Schedule of Inventories by Major Category

	March 31, 2025		December 31, 2024
	(in millions)
Materials and supplies	$	541	$	533
Fuel stock	399		403
Natural gas in storage	20		34
Total inventories	$	960	$	970

Schedule of Investments

	March 31, 2025		December 31, 2024
	(in millions)
Nuclear decommissioning trusts	$	4,404	$	4,440
Assets related to employee benefit plans	13		14
Land investments	42		42
Other investments	17		16
Total investments	$	4,476	$	4,512

Schedule of Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:

	March 31, 2025		December 31, 2024
	(in millions)
Retirement and other employee benefits	$	204	$	224
Identifiable intangible liabilities	149		155
Regulatory liability (a)	411		452
Operating lease liabilities	81		98
Finance lease liabilities	217		218
Liability for third-party remediation	8		8
Accrued severance costs	36		36
Tax Receivable Agreement obligation	12		14
Other accrued expenses	110		65
Total other noncurrent liabilities and deferred credits	$	1,228	$	1,270

____________

(a)As of March 31, 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 $411 million and $452 million, respectively.

Schedule of Cash, Cash Equivalents and Restricted Cash

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 March 31, 2025 and December 31, 2024:

	March 31, 2025		December 31, 2024
	(in millions)
Cash and cash equivalents	$	561	$	1,188
Restricted cash included in current assets	29		28
Restricted cash included in noncurrent assets	6		6
Total cash, cash equivalents and restricted cash	$	596	$	1,222

Schedule of Supplemental Cash Flow Information

The following table summarizes our supplemental cash flow information for the three months ended March 31, 2025 and 2024. Non-cash investing and financing activities for the three months ended March 31, 2024 includes activity related to the Energy Harbor Merger (see Note 2 for additional information).

	Three Months Ended March 31,
	2025		2024
	(in millions)
Cash payments related to:
Interest paid	$	210	$	214
Capitalized interest	(29)		(12)
Interest paid (net of capitalized interest)	$	181	$	202

XML

Business, Significant Accounting Policies, Significant Events, and Recent Developments (Details) $ in Millions	3 Months Ended
	Mar. 31, 2025 USD ($) segment MW	Apr. 01, 2025 USD ($)	Jan. 16, 2025 facility	Dec. 31, 2024 USD ($)
Line of Credit Facility [Line Items]
Number of reportable segments | segment	5
Property, plant and equipment — net	$ 17,716			$ 18,173
Facility limit	8,723
Line of Credit
Line of Credit Facility [Line Items]
Facility limit	5,909
Baldwin Term Loan | Term Loan | Subsequent Event
Line of Credit Facility [Line Items]
Debt instrument, face amount		$ 75
Coffeen Term Loan | Term Loan | Subsequent Event
Line of Credit Facility [Line Items]
Debt instrument, face amount		46
Construction/Term Loan Facility Commitments | Line of Credit | Secured Debt
Line of Credit Facility [Line Items]
Facility limit	$ 108
Construction/Term Loan Facility Commitments | Line of Credit | Subsequent Event | Secured Debt
Line of Credit Facility [Line Items]
Facility limit		$ 108
Moss Landing Power Plant (Battery Storage Project) | Moss Landing Battery Energy Storage System Phase I
Line of Credit Facility [Line Items]
Battery energy storage system capacity | MW	300
Depreciation expense	$ 400
Estimated liability costs incurred	7
Environmental remediation obligation	70
Environmental remediation obligation related to pollution monitoring	30
Environmental remediation obligation including battery removal and land remediation	40
Insurance settlements, limit amount	500
Insurance settlements receivable	$ 425
Moss Landing Power Plant (Battery Storage Project) | Moss Landing Battery Energy Storage System Phases II and III
Line of Credit Facility [Line Items]
Number of battery facilities | facility			2
Moss Landing Power Plant (Battery Storage Project) | Moss Landing Battery Energy Storage System Phase III
Line of Credit Facility [Line Items]
Battery energy storage system capacity | MW	350
Moss Landing Power Plant (Battery Storage Project) | Moss Landing Battery Energy Storage System Phase II
Line of Credit Facility [Line Items]
Battery energy storage system capacity | MW	100
Property, plant and equipment — net	$ 170

XML

Acquisitions - Narrative (Details) - USD ($) $ in Millions		3 Months Ended
	Sep. 18, 2024	Mar. 31, 2024	Mar. 01, 2024
Energy Harbor
Business Acquisition [Line Items]
Fair value of noncontrolling interest in Energy Harbor			$ 811
Business combination, acquisition related costs		$ 24
Vistra Vision
Business Acquisition [Line Items]
Subsidiary, ownership percentage, noncontrolling owner	15.00%
Fair value of noncontrolling interest in Energy Harbor			$ 749
Payments to acquire interest in subsidiaries and affiliates	$ 3,200
Vistra Vision | Energy Harbor
Business Acquisition [Line Items]
Subsidiary, ownership percentage, noncontrolling owner			15.00%
Subsidiary, ownership percentage, parent			85.00%

XML

Acquisitions - Schedule of Purchase Price (Details) - USD ($) $ in Millions	Mar. 01, 2024	Sep. 18, 2024
Vistra Vision
Business Acquisition [Line Items]
Fair value of noncontrolling interest in Energy Harbor	$ 749
Subsidiary, ownership percentage, noncontrolling owner		15.00%
Energy Harbor
Business Acquisition [Line Items]
Cash consideration	3,100
15% of the fair value of net assets contributed to Vistra Vision by Vistra	1,496
Total purchase price	4,596
Fair value of noncontrolling interest in Energy Harbor	811
Acquisition date fair value of Energy Harbor	$ 5,407
Energy Harbor | Vistra Vision
Business Acquisition [Line Items]
Subsidiary, ownership percentage, noncontrolling owner	15.00%
Energy Harbor | Vistra Corp. | Vistra Vision
Business Acquisition [Line Items]
Subsidiary, ownership percentage, noncontrolling owner	15.00%

XML

Acquisitions - Schedule of Business Acquisitions, by Acquisition (Details) - USD ($) $ in Millions	Mar. 01, 2024	Mar. 31, 2025	Dec. 31, 2024
Business Acquisition [Line Items]
Goodwill		$ 2,810	$ 2,807
Business combination, contractual cash flow projections, duration	5 years
Energy Harbor
Business Acquisition [Line Items]
Cash and cash equivalents	$ 35
Trade accounts receivables, inventories, prepaid expenses and other current assets	540
Investments	2,021
Property, plant and equipment	5,616
Identifiable intangible assets	444
Commodity and other derivative contractual assets	129
Other noncurrent assets	62
Total identifiable assets acquired	8,847
Trade accounts payable and other current liabilities	318
Long-term debt, including amounts due currently	413
Commodity and other derivative contractual liabilities	179
Accumulated deferred income taxes	1,314
Asset retirement obligations	1,368
Identifiable intangible liabilities	55
Other noncurrent liabilities and deferred credits	20
Total identifiable liabilities assumed	3,667
Identifiable net assets acquired	5,180
Goodwill	227	$ 0	$ 224
Net assets acquired	5,407
Cash and cash equivalents	5
Trade accounts receivables, inventories, prepaid expenses and other current assets	2
Investments	0
Property, plant and equipment	(4)
Identifiable intangible assets	16
Commodity and other derivative contractual assets	(11)
Other noncurrent assets	54
Total identifiable assets acquired	62
Trade accounts payable and other current liabilities	55
Long-term debt, including amounts due currently	0
Commodity and other derivative contractual liabilities	0
Accumulated deferred income taxes	(50)
Asset retirement obligations	0
Identifiable intangible liabilities	(18)
Other noncurrent liabilities and deferred credits	8
Total identifiable liabilities assumed	(5)
Identifiable net assets acquired	67
Goodwill	$ (67)

XML

Acquisitions - Schedule of Business Acquisitions, Pro Forma Information (Details) - Energy Harbor $ in Millions	3 Months Ended
	Mar. 31, 2024 USD ($)
Business Acquisition [Line Items]
Revenues	$ 3,777
Net income	$ 69

XML

Revenue - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 4,250	$ 3,159
Total revenues	3,933	3,054
Retail energy charge in ERCOT
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,986	1,702
Retail energy charge in Northeast/Midwest
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,039	663
Wholesale generation revenue from ISO/RTO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	874	489
Capacity revenue from ISO/RTO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	20	19
Revenue from other wholesale contracts
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	331	286
Transferable PTC revenues
Disaggregation of Revenue [Line Items]
Total revenues	2	2
Hedging revenues — realized
Disaggregation of Revenue [Line Items]
Total revenues	195	241
Hedging revenues — unrealized
Disaggregation of Revenue [Line Items]
Total revenues	(513)	(347)
Intangible amortization and other revenues
Disaggregation of Revenue [Line Items]
Total revenues	(1)	(1)
Intersegment sales
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Total other revenues
Disaggregation of Revenue [Line Items]
Total revenues	(317)	(105)
Operating Segments
Disaggregation of Revenue [Line Items]
Total revenues	4,919	4,094
Operating Segments | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	3,025	2,365
Total revenues	3,168	2,494
Operating Segments | Texas
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	207	172
Total revenues	210	459
Operating Segments | Texas | Commodity contracts unrealized (gain) loss in operating revenues
Disaggregation of Revenue [Line Items]
Unrealized gain (loss) on derivatives affiliated	(883)	(490)
Operating Segments | East
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	920	477
Total revenues	1,380	856
Operating Segments | East | Commodity contracts unrealized (gain) loss in operating revenues
Disaggregation of Revenue [Line Items]
Unrealized gain (loss) on derivatives affiliated	(271)	(291)
Operating Segments | West
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	94	136
Total revenues	157	276
Operating Segments | West | Commodity contracts unrealized (gain) loss in operating revenues
Disaggregation of Revenue [Line Items]
Unrealized gain (loss) on derivatives affiliated	1
Operating Segments | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	4	9
Total revenues	4	9
Operating Segments | Retail energy charge in ERCOT | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,986	1,702
Operating Segments | Retail energy charge in ERCOT | Texas
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Retail energy charge in ERCOT | East
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Retail energy charge in ERCOT | West
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Retail energy charge in ERCOT | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Retail energy charge in Northeast/Midwest | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,039	663
Operating Segments | Retail energy charge in Northeast/Midwest | Texas
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Retail energy charge in Northeast/Midwest | East
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Retail energy charge in Northeast/Midwest | West
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Retail energy charge in Northeast/Midwest | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Wholesale generation revenue from ISO/RTO | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Wholesale generation revenue from ISO/RTO | Texas
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	78	68
Operating Segments | Wholesale generation revenue from ISO/RTO | East
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	770	333
Operating Segments | Wholesale generation revenue from ISO/RTO | West
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	26	79
Operating Segments | Wholesale generation revenue from ISO/RTO | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	9
Operating Segments | Capacity revenue from ISO/RTO | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Capacity revenue from ISO/RTO | Texas
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Capacity revenue from ISO/RTO | East
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	20	19
Net capacity sold		40
Net capacity purchased		21
Operating Segments | Capacity revenue from ISO/RTO | East | Commodity contracts unrealized (gain) loss in operating revenues
Disaggregation of Revenue [Line Items]
Net capacity sold	73
Net capacity purchased	53
Operating Segments | Capacity revenue from ISO/RTO | East | Fuel, purchased power costs, and delivery fees/Depreciation and amortization
Disaggregation of Revenue [Line Items]
Net capacity sold		(2)
Net capacity purchased		7
Operating Segments | Capacity revenue from ISO/RTO | West
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Capacity revenue from ISO/RTO | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Revenue from other wholesale contracts | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Revenue from other wholesale contracts | Texas
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	129	104
Operating Segments | Revenue from other wholesale contracts | East
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	130	125
Operating Segments | Revenue from other wholesale contracts | West
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	68	57
Operating Segments | Revenue from other wholesale contracts | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	4	0
Operating Segments | Transferable PTC revenues | Retail
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Transferable PTC revenues | Texas
Disaggregation of Revenue [Line Items]
Total revenues	2	2
Operating Segments | Transferable PTC revenues | East
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Transferable PTC revenues | West
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Transferable PTC revenues | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Hedging revenues — realized | Retail
Disaggregation of Revenue [Line Items]
Total revenues	274	278
Operating Segments | Hedging revenues — realized | Texas
Disaggregation of Revenue [Line Items]
Total revenues	(27)	(110)
Operating Segments | Hedging revenues — realized | East
Disaggregation of Revenue [Line Items]
Total revenues	(78)	74
Operating Segments | Hedging revenues — realized | West
Disaggregation of Revenue [Line Items]
Total revenues	26	3
Operating Segments | Hedging revenues — realized | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenues	0	(4)
Operating Segments | Hedging revenues — unrealized | Retail
Disaggregation of Revenue [Line Items]
Total revenues	(157)	(155)
Operating Segments | Hedging revenues — unrealized | Texas
Disaggregation of Revenue [Line Items]
Total revenues	(143)	(132)
Operating Segments | Hedging revenues — unrealized | East
Disaggregation of Revenue [Line Items]
Total revenues	(250)	(200)
Operating Segments | Hedging revenues — unrealized | West
Disaggregation of Revenue [Line Items]
Total revenues	36	136
Operating Segments | Hedging revenues — unrealized | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenues	1	4
Operating Segments | Intangible amortization and other revenues | Retail
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Intangible amortization and other revenues | Texas
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Intangible amortization and other revenues | East
Disaggregation of Revenue [Line Items]
Total revenues	(1)	(1)
Operating Segments | Intangible amortization and other revenues | West
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Intangible amortization and other revenues | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Intersegment sales | Retail
Disaggregation of Revenue [Line Items]
Total revenues	26	6
Operating Segments | Intersegment sales | Texas
Disaggregation of Revenue [Line Items]
Total revenues	171	527
Operating Segments | Intersegment sales | East
Disaggregation of Revenue [Line Items]
Total revenues	789	506
Operating Segments | Intersegment sales | West
Disaggregation of Revenue [Line Items]
Total revenues	1	1
Operating Segments | Intersegment sales | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenues	(1)	0
Operating Segments | Total other revenues | Retail
Disaggregation of Revenue [Line Items]
Total revenues	143	129
Operating Segments | Total other revenues | Texas
Disaggregation of Revenue [Line Items]
Total revenues	3	287
Operating Segments | Total other revenues | East
Disaggregation of Revenue [Line Items]
Total revenues	460	379
Operating Segments | Total other revenues | West
Disaggregation of Revenue [Line Items]
Total revenues	63	140
Operating Segments | Total other revenues | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Eliminations
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Total revenues	(986)	(1,040)
Eliminations | Retail energy charge in ERCOT
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Eliminations | Retail energy charge in Northeast/Midwest
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Eliminations | Wholesale generation revenue from ISO/RTO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Eliminations | Capacity revenue from ISO/RTO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Eliminations | Revenue from other wholesale contracts
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Eliminations | Transferable PTC revenues
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Eliminations | Hedging revenues — realized
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Eliminations | Hedging revenues — unrealized
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Eliminations | Intangible amortization and other revenues
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Eliminations | Intersegment sales
Disaggregation of Revenue [Line Items]
Total revenues	(986)	(1,040)
Eliminations | Total other revenues
Disaggregation of Revenue [Line Items]
Total revenues	$ (986)	$ (1,040)

XML

Revenue - Schedule of Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction (Details) $ in Millions	Mar. 31, 2025 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	$ 2,790
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	$ 934
Revenue, remaining performance obligation, expected timing of satisfaction, period	9 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	$ 832
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	$ 292
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	$ 122
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	$ 62
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	$ 548
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year

XML

Revenue - Schedule of Accounts, Notes, Loans and Financing Receivable (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024	Dec. 31, 2024
Financing Receivable, Allowance for Credit Loss [Line Items]
Wholesale and retail trade accounts receivable	$ 1,999		$ 2,061
Allowance for credit losses	(75)	$ (61)	(79)
Trade accounts receivable — net	1,924		1,982
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Allowance for credit losses on accounts receivable at beginning of period	79	61
Increase for bad debt expense	44	36
Decrease for account write-offs	(48)	(36)
Allowance for credit losses on accounts receivable at end of period	75	$ 61
Trade accounts receivable from contracts with customers — net
Financing Receivable, Allowance for Credit Loss [Line Items]
Trade accounts receivable — net	1,494		1,514
Other trade accounts receivable — net
Financing Receivable, Allowance for Credit Loss [Line Items]
Trade accounts receivable — net	$ 430		$ 468

XML

Revenue - Narrative (Details) - USD ($) $ in Millions	Mar. 31, 2025	Dec. 31, 2024
Revenue from Contract with Customer [Abstract]
Unbilled receivables, current	$ 737	$ 802

XML

Government Assistance (Details) $ in Millions	Jan. 31, 2025 USD ($)
Transferable Nuclear Production Tax Credit Revenues
Government Assistance [Line Items]
PTC sold under agreements	$ 200

XML

Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Net loss before income taxes	$ (444)	$ (2)
Income tax benefit	$ 176	$ 20
Effective tax rate	39.60%	1000.00%

XML

Income Taxes - Narrative (Details)	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Income Tax Disclosure [Abstract]
Effective tax rate	39.60%	1000.00%
Effective tax rate at federal statutory rate	21.00%	21.00%

XML

Property, Plant, and Equipment - Schedule of Property, Plant, and Equipment (Details) - USD ($) $ in Millions	Mar. 31, 2025	Dec. 31, 2024
Property, Plant and Equipment [Line Items]
Construction work in progress	$ 1,394	$ 1,060
Finance lease right-of-use assets	186	186
Property, plant and equipment — gross	26,690	26,635
Less accumulated depreciation and amortization	(8,415)	(8,020)
Less finance lease right-of-use assets accumulated amortization	(35)	(33)
Property, plant and equipment — net	17,716	18,173
Power generation and structures
Property, Plant and Equipment [Line Items]
Property, plant and equipment — gross	22,303	22,783
Office and other equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment — gross	172	160
Land
Property, Plant and Equipment [Line Items]
Property, plant and equipment — gross	603	603
Nuclear fuel
Property, Plant and Equipment [Line Items]
Property, plant and equipment — gross	2,032	1,843
Less accumulated depreciation and amortization	$ (524)	$ (409)

XML

Property, Plant, and Equipment - Amortization of Property, Plant, and Equipment (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Property, Plant and Equipment [Line Items]
Total property, plant, and equipment expense	$ 592	$ 416
Depreciation and amortization | Power generation and structures and office and other equipment
Property, Plant and Equipment [Line Items]
Total property, plant, and equipment expense	479	365
Depreciation and amortization | Finance lease right-of-use assets
Property, Plant and Equipment [Line Items]
Total property, plant, and equipment expense	2	2
Fuel, purchased power costs, and delivery fees | Nuclear fuel
Property, Plant and Equipment [Line Items]
Total property, plant, and equipment expense	$ 111	$ 49

XML

Property, Plant, and Equipment - Schedule of Planned Retirements of Generation Capacity (Details)	Mar. 31, 2025 MW
Retirement of Generation Facilities [Line Items]
Net Capacity (MW)	5,163
Baldwin | East
Retirement of Generation Facilities [Line Items]
Net Capacity (MW)	1,185
Coleto Creek | Texas
Retirement of Generation Facilities [Line Items]
Net Capacity (MW)	650
Kincaid | East
Retirement of Generation Facilities [Line Items]
Net Capacity (MW)	1,108
Miami Fort | East
Retirement of Generation Facilities [Line Items]
Net Capacity (MW)	1,020
Newton | East
Retirement of Generation Facilities [Line Items]
Net Capacity (MW)	615
Edwards | Asset Closure
Retirement of Generation Facilities [Line Items]
Net Capacity (MW)	585

XML

Goodwill and Identifiable Intangible Assets and Liabilities - Schedule of Goodwill (Details) $ in Millions	3 Months Ended
	Mar. 31, 2025 USD ($)
Goodwill [Roll Forward]
Balance at beginning of period	$ 2,807
Measurement period adjustment recorded in connection with the Energy Harbor Merger	3
Balance at end of period	2,810
Energy Harbor
Goodwill [Roll Forward]
Balance at beginning of period	224
Measurement period adjustment recorded in connection with the Energy Harbor Merger	(224)
Balance at end of period	0
Retail Reporting Unit
Goodwill [Roll Forward]
Balance at beginning of period	2,461
Measurement period adjustment recorded in connection with the Energy Harbor Merger	227
Balance at end of period	2,688
Goodwill, expected tax deductible amount	$ 1,944
Business acquisition, goodwill, expected tax deductible term	15 years
Texas Generation Reporting Unit
Goodwill [Roll Forward]
Balance at beginning of period	$ 122
Measurement period adjustment recorded in connection with the Energy Harbor Merger	0
Balance at end of period	$ 122

XML

Goodwill and Identifiable Intangible Assets and Liabilities - Schedule of Identifiable Intangible Assets and Liabilities Reported in the Balance Sheet (Details) - USD ($) $ in Millions	Mar. 31, 2025	Dec. 31, 2024
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross Carrying Amount	$ 3,683	$ 3,513
Accumulated Amortization	2,703	2,641
Net	980	872
Total identifiable intangible assets	2,321	2,213
Total identifiable intangible liabilities	149	155
Retail trade names (not subject to amortization)
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Retail trade names (not subject to amortization)	1,341	1,341
Retail customer relationships
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross Carrying Amount	2,173	2,173
Accumulated Amortization	1,999	1,977
Net	174	196
Software and other technology-related assets
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross Carrying Amount	616	601
Accumulated Amortization	312	293
Net	304	308
Retail and wholesale contracts
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross Carrying Amount	503	503
Accumulated Amortization	373	353
Net	130	150
Long-term service agreements
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross Carrying Amount	18	18
Accumulated Amortization	5	5
Net	13	13
Total identifiable intangible liabilities	104	108
Other identifiable intangible assets
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross Carrying Amount	373	218
Accumulated Amortization	14	13
Net	359	205
Wholesale power and fuel purchase contracts
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Total identifiable intangible liabilities	$ 45	$ 47

XML

Goodwill and Identifiable Intangible Assets and Liabilities - Schedule of Amortization Expense Related to Intangible Assets and Liabilities (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Finite-Lived Intangible Assets and Liabilities [Line Items]
Amortization of intangible assets and liabilities	$ 175	$ 139
Retail customer relationships | Depreciation and amortization
Finite-Lived Intangible Assets and Liabilities [Line Items]
Amortization of intangible assets and liabilities	23	22
Software and other technology-related assets | Depreciation and amortization
Finite-Lived Intangible Assets and Liabilities [Line Items]
Amortization of intangible assets and liabilities	18	13
Retail and wholesale contracts | Operating revenues/Fuel, purchased power costs, and delivery fees
Finite-Lived Intangible Assets and Liabilities [Line Items]
Amortization of intangible assets and liabilities	(2)	1
Other identifiable intangible assets | Fuel, purchased power costs, and delivery fees/Depreciation and amortization
Finite-Lived Intangible Assets and Liabilities [Line Items]
Amortization of intangible assets and liabilities	$ 136	$ 103

XML

Goodwill and Identifiable Intangible Assets and Liabilities - Schedule of Estimated Amortization Expense of Identifiable Intangible Assets and Liabilities (Details) $ in Millions	Mar. 31, 2025 USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2025	$ 237
2026	177
2027	80
2028	59
2029	$ 41

XML

Collateral Financing Agreement With Affiliate (Details) $ in Millions	Mar. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($) security
Debt Instrument, Redemption [Line Items]
Margin deposits posted under affiliate financing agreement	$ 446	$ 435
Margin deposits financing with affiliate	$ 446	$ 435
Pre-Capitalized Trust Securities
Debt Instrument, Redemption [Line Items]
Derivative, number of instruments held | security			450,000
Derivative, notional amount			$ 450

XML

Debt, Credit Facilities and Financings - Schedule of Debt (Details) - USD ($) $ in Millions	Mar. 31, 2025	Dec. 31, 2024
Debt Instrument [Line Items]
Long -term debt before unamortized premiums, discounts and issuance costs	$ 16,463	$ 16,469
Unamortized debt premiums, discounts and issuance costs	(158)	(171)
Long-term debt including amounts due currently	16,305	16,298
Accounts receivable financing	1,082	750
Forward repurchase obligation	1,355	1,335
Project-level debt
Debt Instrument [Line Items]
Long -term debt before unamortized premiums, discounts and issuance costs	1,064	1,064
Vistra Operations debt
Debt Instrument [Line Items]
Long -term debt before unamortized premiums, discounts and issuance costs	$ 15,399	$ 15,405

XML

Debt, Credit Facilities and Financings - Schedule of Long-Term Debt Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2025	Dec. 31, 2024
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 16,305	$ 16,298
Total other long-term debt	55	55
Unamortized debt premiums, discounts and issuance costs	(158)	(171)
Less amounts due currently	(882)	(880)
Total long-term debt, less amounts due currently	$ 15,423	15,418
Bridge Loan
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage	1.625%
Vistra Operations Senior Secured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 5,144	5,144
Energy Harbor Revenue Bonds
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	431	431
Vistra Operations Senior Unsecured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	7,300	7,300
Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030 | Line of Credit
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	2,469	2,475
BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026 | Bridge Loan
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	367	367
Vistra Zero Credit Facility, Term Loan B Facility due April 30, 2031 | Line of Credit
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	697	697
5.125% Senior Secured Notes, due May 13, 2025 | Vistra Operations Senior Secured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 744	744
Debt instrument, interest rate, stated percentage	5.125%
5.050% Senior Secured Notes, due December 30, 2026 | Vistra Operations Senior Secured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 500	500
Debt instrument, interest rate, stated percentage	5.05%
3.700% Senior Secured Notes, due January 30, 2027 | Vistra Operations Senior Secured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 800	800
Debt instrument, interest rate, stated percentage	3.70%
4.300% Senior Secured Notes, due July 15, 2029 | Vistra Operations Senior Secured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 800	800
Debt instrument, interest rate, stated percentage	4.30%
6.950% Senior Secured Notes, due October 15, 2033 | Vistra Operations Senior Secured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 1,050	1,050
Debt instrument, interest rate, stated percentage	6.95%
6.000% Senior Secured Notes, due April 15, 2034 | Vistra Operations Senior Secured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 500	500
Debt instrument, interest rate, stated percentage	6.00%
5.700% Senior Secured Notes, due December 30, 2034 | Vistra Operations Senior Secured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 750	750
Debt instrument, interest rate, stated percentage	5.70%
3.375% Revenue Bond, due August 1, 2029 | Energy Harbor Revenue Bonds
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 100	100
Debt instrument, interest rate, stated percentage	3.375%
4.750% Revenue Bonds, due June 1, 2033 and July 1, 2033 | Energy Harbor Revenue Bonds
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 285	285
Debt instrument, interest rate, stated percentage	4.75%
3.750% Revenue Bond, due October 1, 2047 | Energy Harbor Revenue Bonds
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 46	46
Debt instrument, interest rate, stated percentage	3.75%
5.500% Senior Unsecured Notes, due September 1, 2026 | Vistra Operations Senior Unsecured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 1,000	1,000
Debt instrument, interest rate, stated percentage	5.50%
5.625% Senior Unsecured Notes, due February 15, 2027 | Vistra Operations Senior Unsecured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 1,300	1,300
Debt instrument, interest rate, stated percentage	5.625%
5.000% Senior Unsecured Notes, due July 31, 2027 | Vistra Operations Senior Unsecured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 1,300	1,300
Debt instrument, interest rate, stated percentage	5.00%
4.375% Senior Unsecured Notes, due May 15, 2029 | Vistra Operations Senior Unsecured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 1,250	1,250
Debt instrument, interest rate, stated percentage	4.375%
7.750% Senior Unsecured Notes, due October 15, 2031 | Vistra Operations Senior Unsecured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 1,450	1,450
Debt instrument, interest rate, stated percentage	7.75%
6.875% Senior Unsecured Notes, due April 15, 2032 | Vistra Operations Senior Unsecured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 1,000	1,000
Debt instrument, interest rate, stated percentage	6.875%
Equipment Financing Agreements | Other Debt
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 55	$ 55

XML

Debt, Credit Facilities and Financings - Schedule of Maturities of Long-Term Debt (Details) - USD ($) $ in Millions	Mar. 31, 2025	Dec. 31, 2024
Debt Disclosure [Abstract]
Remainder of 2025	$ 879
2026	1,792
2027	3,427
2028	27
2029	2,177
Thereafter	8,161
Unamortized premiums, discounts and debt issuance costs	(158)
Total long-term debt, including amounts due currently	$ 16,305	$ 16,298

XML

Debt, Credit Facilities and Financings - Schedule of Line of Credit Facilities (Details) $ in Millions	Mar. 31, 2025 USD ($)
Debt Instrument [Line Items]
Facility Limit	$ 8,723
Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)	3,533
Letters of Credit Outstanding	1,223
Available Capacity	3,342
Line of Credit
Debt Instrument [Line Items]
Facility Limit	5,909
Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)	2,469
Letters of Credit Outstanding	1,223
Available Capacity	2,217
Vistra Operations debt
Debt Instrument [Line Items]
Facility Limit	7,659
Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)	2,469
Letters of Credit Outstanding	1,223
Available Capacity	3,342
Project-level debt
Debt Instrument [Line Items]
Facility Limit	1,064
Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)	1,064
Letters of Credit Outstanding	0
Available Capacity	0
Revolving Credit Facility | Line of Credit
Debt Instrument [Line Items]
Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)	0
Letters of Credit Outstanding	1,223
Available Capacity	2,217
Term Loan B-3 Facility | Line of Credit
Debt Instrument [Line Items]
Letters of Credit Outstanding	0
Available Capacity	0
Vistra Operations Commodity-Linked Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)	0
Letters of Credit Outstanding	0
Available Capacity	1,125
BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026
Debt Instrument [Line Items]
Facility Limit	367
Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)	367
Letters of Credit Outstanding	0
Available Capacity	0
BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026 | Bridge Loan | Oak Hill
Debt Instrument [Line Items]
Facility Limit	106
Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)	106
Letters of Credit Outstanding	0
Available Capacity	0
BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026 | Bridge Loan | Pulaski
Debt Instrument [Line Items]
Facility Limit	261
Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)	261
Letters of Credit Outstanding	0
Available Capacity	0
Vistra Zero Term Loan B Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Facility Limit	697
Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)	697
Letters of Credit Outstanding	0
Available Capacity	$ 0

XML

Debt, Credit Facilities and Financings - Narrative (Details) $ in Thousands	1 Months Ended		3 Months Ended		12 Months Ended
	May 31, 2024 USD ($)	Mar. 31, 2024 USD ($)	Mar. 31, 2025 USD ($)	Mar. 31, 2024 USD ($)	Dec. 31, 2024 USD ($)	Apr. 01, 2025 USD ($)	Jul. 31, 2024 USD ($)	Apr. 30, 2024 USD ($)
Debt Instrument [Line Items]
Facility Limit			$ 8,723,000
Line of credit facility, borrowings outstanding			3,533,000
Total long-term debt, including amounts due currently			16,305,000		$ 16,298,000
Accounts receivable financing			1,082,000		750,000
Accounts receivable repurchase facility, term							1 month
Vistra Vision
Debt Instrument [Line Items]
Forward repurchase obligation to be paid			$ 1,355,000		$ 1,335,000
Vistra Vision | Measurement Input, Discount Rate
Debt Instrument [Line Items]
Noncontrolling interest, discount rate			0.06		0.06
BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026
Debt Instrument [Line Items]
Facility Limit			$ 367,000
Line of credit facility, borrowings outstanding			367,000
Alternate Letter Of Credit Facility | Letter of Credit
Debt Instrument [Line Items]
Facility Limit			500,000
Letters of credit outstanding			500,000
Line of credit facility, increase (decrease), net	$ 500,000
Accounts Receivable Securitization Program
Debt Instrument [Line Items]
Accounts receivable financing			957,000		$ 750,000
Accounts receivable securitization program, gross trade accounts receivable held by special purpose subsidiary			1,346,000
Accounts Receivable Securitization Program | Maximum
Debt Instrument [Line Items]
Account receivable securitization program, total borrowing capacity, July 2024 through July 2025		$ 750,000		$ 750,000				$ 1,000,000
Repurchase Facility
Debt Instrument [Line Items]
Accounts receivable repurchase facility, maximum borrowing capacity							$ 125,000
Accounts receivable repurchase facility, amounts borrowed			125,000		0
Vistra Operations Company LLC | Vistra Corp.
Debt Instrument [Line Items]
Maximum allowable distribution to parent company by consolidated subsidiary without consent			10,200,000
Dividends paid			425,000	490,000
Line of Credit
Debt Instrument [Line Items]
Facility Limit			5,909,000
Line of credit facility, borrowings outstanding			2,469,000
Line of Credit | Revolving Credit Facility
Debt Instrument [Line Items]
Line of credit facility, borrowings outstanding			$ 0
Line of Credit | BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026 | Secured Debt
Debt Instrument [Line Items]
Debt, weighted average interest rate			5.984%
Line of Credit | Construction/Term Loan Commitments | Secured Debt
Debt Instrument [Line Items]
Facility Limit					528,000
Line of Credit | Vistra Zero Project-Level Credit Agreement | Secured Debt
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			2.00%
Debt, weighted average interest rate			6.32%
Debt instrument, face amount		700,000		$ 700,000
Borrowings under Revolving Credit Facility		$ 690,000
Line of Credit | Vistra Operations Company LLC
Debt Instrument [Line Items]
Facility Limit			$ 5,909,000
Collateral suspension provision effective date, grace period, number of days			60 days
Debt instrument, interest rate during period			5.22%	5.56%
Line of Credit | Vistra Operations Company LLC | Revolving Credit Facility
Debt Instrument [Line Items]
Facility Limit			$ 3,440,000
Debt instrument, basis spread on variable rate			1.725%
Debt instrument, fee on undrawn amounts			0.270
Debt instrument, interest rate, stated percentage			1.725%
Line of Credit | Vistra Operations Company LLC | Revolving Credit Facility | Minimum
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			1.25%
Debt instrument, fee on undrawn amounts			0.175
Line of Credit | Vistra Operations Company LLC | Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			2.00%
Debt instrument, fee on undrawn amounts			0.350
Line of Credit | Vistra Operations Company LLC | Term Loan B-3 Facility
Debt Instrument [Line Items]
Facility Limit			$ 2,469,000
Debt instrument, basis spread on variable rate			1.75%
Line of credit facility, borrowings outstanding			$ 2,469,000
Line of credit facility, interest rate at period end			6.07%
Debt instrument, periodic payment			$ 6,250
Revolving Credit Facility | Vistra Operations Commodity-Linked Facility
Debt Instrument [Line Items]
Line of credit facility, borrowings outstanding			0
Revolving Credit Facility | Vistra Zero Term Loan B Facility
Debt Instrument [Line Items]
Facility Limit			697,000
Line of credit facility, borrowings outstanding			697,000
Revolving Credit Facility | Vistra Operations Company LLC | Vistra Operations Commodity-Linked Facility
Debt Instrument [Line Items]
Facility Limit			$ 1,750,000
Debt instrument, basis spread on variable rate			1.725%
Debt instrument, fee on undrawn amounts			0.270
Line of credit facility, borrowing base capacity limit			$ 1,125,000
Revolving Credit Facility | Vistra Operations Company LLC | Vistra Operations Commodity-Linked Facility | Minimum
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			1.25%
Debt instrument, fee on undrawn amounts			0.175
Revolving Credit Facility | Vistra Operations Company LLC | Vistra Operations Commodity-Linked Facility | Maximum
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			2.00%
Debt instrument, fee on undrawn amounts			0.350
Line of credit facility, potential borrowing capacity, subject to ability to obtain additional commitments			$ 3,000,000
Bridge Loan
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage			1.625%
Bridge Loan | BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently			$ 367,000		367,000
Bridge Loan | BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026 | Oak Hill
Debt Instrument [Line Items]
Facility Limit			106,000
Line of credit facility, borrowings outstanding			106,000
Bridge Loan | BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026 | Pulaski
Debt Instrument [Line Items]
Facility Limit			261,000
Line of credit facility, borrowings outstanding			$ 261,000
Letter of Credit
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage			2.00%
Letter of Credit | BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026
Debt Instrument [Line Items]
Letters of credit outstanding					$ 29,000
Letter of Credit | Vistra Operations Company LLC | Secured Letter of Credit Facilities
Debt Instrument [Line Items]
Letters of credit outstanding			$ 1,091,000
Construction Loans
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage			1.875%
Term Loan
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage			2.00%
Term loan period (in years)			20 years
Term Loan | Baldwin Term Loan | Subsequent Event
Debt Instrument [Line Items]
Debt instrument, face amount						$ 75,000
Term Loan | Coffeen Term Loan | Subsequent Event
Debt Instrument [Line Items]
Debt instrument, face amount						$ 46,000
Revenue Bonds
Debt Instrument [Line Items]
Debt instrument, face amount			$ 431,000

XML

Debt, Credit Facilities, and Financings - Schedule of Repurchase Obligation (Details) - Vistra Vision $ in Millions	Mar. 31, 2025 USD ($)
Redeemable Noncontrolling Interest [Line Items]
Remainder of 2025	$ 781
2026	669
Thereafter	0
Total scheduled payments under the UPAs	$ 1,450

XML

Debt, Credit Facilities, and Financings - Schedule of Interest Expense and Related Charges (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Debt Disclosure [Abstract]
Interest expense	$ 272	$ 208
Unrealized mark-to-market net (gains) losses on interest rate swaps	48	(47)
Amortization of debt issuance costs, discounts, and premiums	11	7
Debt extinguishment gain	0	(6)
Capitalized interest	(29)	(12)
Other	17	20
Total interest expense and related charges	$ 319	$ 170

XML

Derivatives - Schedule of Interest Rate Derivatives (Details) $ in Millions	Mar. 31, 2025 USD ($)
Derivative [Line Items]
Long-term debt, amount of variable interest debt hedged	$ 2,300
Facility Limit	8,723
Line of Credit
Derivative [Line Items]
Facility Limit	5,909
Secured Debt | Construction/Term Loan Facility Commitments | Line of Credit
Derivative [Line Items]
Facility Limit	108
Interest Rate Swap, Swapped to Fixed, Effective from July 2023 to July 2026
Derivative [Line Items]
Derivative, notional amount	$ 3,000
Interest Rate Swap, Swapped to Fixed, Effective from July 2023 to July 2026 | Minimum
Derivative [Line Items]
Rate range	2.89%
Interest Rate Swap, Swapped to Fixed, Effective from July 2023 to July 2026 | Maximum
Derivative [Line Items]
Rate range	2.97%
Interest Rate Swap, Swapped to Variable, Effective from July 2023 to July 2026
Derivative [Line Items]
Derivative, notional amount	$ 700
Interest Rate Swap, Swapped to Variable, Effective from July 2023 to July 2026 | Minimum
Derivative [Line Items]
Rate range	1.44%
Interest Rate Swap, Swapped to Variable, Effective from July 2023 to July 2026 | Maximum
Derivative [Line Items]
Rate range	1.49%
Interest Rate Swap, Swapped to Fixed, Effective from December 2023 to December 2030
Derivative [Line Items]
Derivative, notional amount	$ 2,300
Long-term debt, amount of variable interest debt hedged	$ 2,300
Interest Rate Swap, Swapped to Fixed, Effective from December 2023 to December 2030 | Minimum
Derivative [Line Items]
Rate range	3.20%
Interest Rate Swap, Swapped to Fixed, Effective from December 2023 to December 2030 | Maximum
Derivative [Line Items]
Rate range	3.76%
Interest Rate Swap, Swapped To Fixed, Expiration Date March 2045
Derivative [Line Items]
Derivative, notional amount	$ 108
Interest Rate Swap, Swapped To Fixed, Expiration Date March 2045 | Minimum
Derivative [Line Items]
Rate range	3.95%
Interest Rate Swap, Swapped to Fixed, Effective July 2026 and Expiration Date December 2030
Derivative [Line Items]
Derivative, notional amount	$ 108

XML

Derivatives - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value (Details) - USD ($) $ in Millions	Mar. 31, 2025	Dec. 31, 2024
Derivatives, Fair Value [Line Items]
Derivative assets (liabilities), fair value, net	$ (2,001)	$ (1,391)
Derivative assets (liabilities), offsetting instruments	0	0
Derivative assets (liabilities): financial collateral (received) pledged	314	183
Derivative assets (liabilities), net amounts	(1,687)	(1,208)
Current assets
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, net	3,335	2,587
Noncurrent assets
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, net	769	740
Current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, fair value, net	(4,646)	(3,351)
Noncurrent liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, fair value, net	(1,459)	(1,367)
Commodity Contract
Derivatives, Fair Value [Line Items]
Derivative assets (liabilities), fair value, gross assets	4,014	3,226
Derivative assets (liabilities), fair value, gross liability	(6,035)	(4,686)
Derivative assets: offsetting Instruments	(3,381)	(2,532)
Derivative liability, offsetting instruments	3,381	2,532
Derivative assets, financial collateral (received) pledged	(17)	(50)
Derivative liabilities, financial collateral (received) pledged	331	233
Derivative assets, net amounts	616	644
Derivative liability, net amounts	(2,323)	(1,921)
Commodity Contract | Current assets
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	(3,306)	(2,551)
Derivative liabilities, far value, gross asset	(1)	(2)
Commodity Contract | Noncurrent assets
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	(729)	(677)
Derivative liabilities, far value, gross asset	(19)	(1)
Commodity Contract | Current liabilities
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	(7)	0
Derivative liabilities, far value, gross asset	(4,622)	(3,333)
Commodity Contract | Noncurrent liabilities
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	(14)	(2)
Derivative liabilities, far value, gross asset	(1,433)	(1,356)
Interest Rate Swaps
Derivatives, Fair Value [Line Items]
Derivative assets (liabilities), fair value, gross assets	49	96
Derivative assets (liabilities), fair value, gross liability	(29)	(27)
Derivative assets: offsetting Instruments	(22)	(28)
Derivative liability, offsetting instruments	22	28
Derivative assets, financial collateral (received) pledged	0	0
Derivative liabilities, financial collateral (received) pledged	0	0
Derivative assets, net amounts	27	68
Derivative liability, net amounts	(7)	1
Interest Rate Swaps | Current assets
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	(28)	(34)
Derivative liabilities, far value, gross asset	0	0
Interest Rate Swaps | Noncurrent assets
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	(21)	(62)
Derivative liabilities, far value, gross asset	0	0
Interest Rate Swaps | Current liabilities
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	0	0
Derivative liabilities, far value, gross asset	(17)	(18)
Interest Rate Swaps | Noncurrent liabilities
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	0	0
Derivative liabilities, far value, gross asset	$ (12)	$ (9)

XML

Derivatives - Schedule of Pretax Effect on Net Income of Derivatives Not Under Hedge Accounting, Including Realized and Unrealized Effects (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized net gain (loss) from changes in fair value on derivative instruments:	$ 184	$ 376
Total unrealized net gain (loss) from change in fair value on derivative instruments	(799)	(505)
Net gain (loss) on derivative instruments	(615)	(129)
Interest Rate Swaps
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized net gain (loss) from changes in fair value on derivative instruments:	(5)	(11)
Total unrealized net gain (loss) from change in fair value on derivative instruments	(43)	58
Commodity contracts unrealized (gain) loss in operating revenues | Commodity Contracts
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized net gain (loss) from changes in fair value on derivative instruments:	212	261
Total unrealized net gain (loss) from change in fair value on derivative instruments	(725)	(608)
Commodity contracts unrealized gain (loss) in fuel, purchased power costs, and delivery fees | Commodity Contracts
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized net gain (loss) from changes in fair value on derivative instruments:	(23)	126
Total unrealized net gain (loss) from change in fair value on derivative instruments	$ (31)	$ 45

XML

Derivatives - Schedule of Notional Amounts of Outstanding Derivative Positions (Details) gal in Millions, certificate in Millions, T in Millions, MMBTU in Millions, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2025 USD ($) certificate GWh MMBTU T gal	Dec. 31, 2024 USD ($) certificate GWh MMBTU T gal
Natural gas
Derivatives, Fair Value [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	4,563	4,568
Electricity
Derivatives, Fair Value [Line Items]
Derivative, nonmonetary notional amount, energy measure | GWh	831,426	796,982
Financial transmission rights / Congestion revenue rights
Derivatives, Fair Value [Line Items]
Derivative, nonmonetary notional amount, energy measure | GWh	224,032	248,742
Coal
Derivatives, Fair Value [Line Items]
Derivative, nonmonetary notional amount, mass | T	27	27
Fuel oil
Derivatives, Fair Value [Line Items]
Derivative, nonmonetary notional amount, volume | gal	0	2
Emissions
Derivatives, Fair Value [Line Items]
Derivative, nonmonetary notional amount, mass | T	29	28
Renewable energy certificates
Derivatives, Fair Value [Line Items]
Nonmonetary notional volume | certificate	28	31
Interest rate swaps – variable/fixed
Derivatives, Fair Value [Line Items]
Derivative, notional amount | $	$ 5,408	$ 5,300
Interest rate swaps – fixed/variable
Derivatives, Fair Value [Line Items]
Derivative, notional amount | $	$ 700	$ 700

XML

Derivatives - Schedules of Credit Risk-Related Contingent Features of Derivatives (Details) - Credit Risk Contract - USD ($) $ in Millions	Mar. 31, 2025	Dec. 31, 2024
Credit Derivatives [Line Items]
Fair value of derivative contract liabilities	$ (1,963)	$ (1,587)
Offsetting fair value under netting arrangements	792	724
Cash collateral and letters of credit	563	471
Liquidity exposure	$ (608)	$ (392)

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Derivatives - Schedules of Concentration of Risk (Details) - Credit Risk Contract $ in Millions	3 Months Ended
	Mar. 31, 2025 USD ($)
Derivative [Line Items]
Total credit risk exposure to all counterparties related to derivative contracts	$ 4,431
Net exposure to those counterparties after taking into effect master netting arrangements, setoff provisions and collateral	689
Largest net exposure to single counterparty	$ 272
Credit risk exposure to banking and financial sector percentage	80.00%
Net exposure to banking and financial sector percentage	23.00%

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Fair Value Measurements - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2025	Dec. 31, 2024
Debt securities
Liabilities:
Debt, weighted average interest rate	4.24%	3.99%
Decommissioning fund investments, debt securities average maturities	8 years	7 years
Decommissioning fund investments, debt maturities, one through five years, fair value	$ 825
Decommissioning fund investments, debt maturities, five through ten years, fair value	972
Decommissioning fund investments, debt maturities, after ten years, fair value	355
Fair Value, Recurring
Assets:
Sub-total	41	$ 5
Liabilities:
Total liabilities	41	5
Fair Value, Recurring | Equity securities
Assets:
Assets measured at net asset value	783	821
Fair Value, Recurring | Debt securities
Assets:
Assets measured at net asset value	300	0
Fair Value, Recurring | Commodity Contracts
Assets:
Assets	41	5
Liabilities:
Derivative liabilities	41	5
Fair Value, Recurring | Interest Rate Swaps
Assets:
Assets	0	0
Liabilities:
Derivative liabilities	0	0
Fair Value, Recurring | Total
Assets:
Sub-total	7,425	6,946
Total assets	8,508	7,767
Liabilities:
Total liabilities	6,105	4,718
Fair Value, Recurring | Total | Equity securities
Assets:
Nuclear decommissioning trust, fair value	1,469	1,560
Fair Value, Recurring | Total | Debt securities
Assets:
Nuclear decommissioning trust, fair value	1,852	2,059
Fair Value, Recurring | Total | Commodity Contracts
Assets:
Assets	4,055	3,231
Liabilities:
Derivative liabilities	6,076	4,691
Fair Value, Recurring | Total | Interest Rate Swaps
Assets:
Assets	49	96
Liabilities:
Derivative liabilities	29	27
Level 1 | Fair Value, Recurring
Assets:
Sub-total	4,251	3,566
Liabilities:
Total liabilities	3,002	2,118
Level 1 | Fair Value, Recurring | Equity securities
Assets:
Nuclear decommissioning trust, fair value	1,469	1,560
Level 1 | Fair Value, Recurring | Debt securities
Assets:
Nuclear decommissioning trust, fair value	99	83
Level 1 | Fair Value, Recurring | Commodity Contracts
Assets:
Assets	2,683	1,923
Liabilities:
Derivative liabilities	3,002	2,118
Level 1 | Fair Value, Recurring | Interest Rate Swaps
Assets:
Assets	0	0
Liabilities:
Derivative liabilities	0	0
Level 2 | Fair Value, Recurring
Assets:
Sub-total	2,227	2,534
Liabilities:
Total liabilities	1,212	1,002
Level 2 | Fair Value, Recurring | Equity securities
Assets:
Nuclear decommissioning trust, fair value	0	0
Level 2 | Fair Value, Recurring | Debt securities
Assets:
Nuclear decommissioning trust, fair value	1,753	1,976
Level 2 | Fair Value, Recurring | Commodity Contracts
Assets:
Assets	425	462
Liabilities:
Derivative liabilities	1,183	975
Level 2 | Fair Value, Recurring | Interest Rate Swaps
Assets:
Assets	49	96
Liabilities:
Derivative liabilities	29	27
Level 3
Assets:
Assets	906	841
Liabilities:
Derivative liabilities	1,850	1,593
Level 3 | Fair Value, Recurring
Assets:
Sub-total	906	841
Liabilities:
Total liabilities	1,850	1,593
Level 3 | Fair Value, Recurring | Equity securities
Assets:
Nuclear decommissioning trust, fair value	0	0
Level 3 | Fair Value, Recurring | Debt securities
Assets:
Nuclear decommissioning trust, fair value	0	0
Level 3 | Fair Value, Recurring | Commodity Contracts
Assets:
Assets	906	841
Liabilities:
Derivative liabilities	1,850	1,593
Level 3 | Fair Value, Recurring | Interest Rate Swaps
Assets:
Assets	0	0
Liabilities:
Derivative liabilities	$ 0	$ 0

XML

Fair Value Measurements - Schedule of Fair Value of the Level 3 Assets and Liabilities by Major Contract Type and the Significant Unobservable Inputs Used in the Valuations (Details) - Level 3	Mar. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	$ 906,000,000	$ 841,000,000
Liabilities	(1,850,000,000)	(1,593,000,000)
Total	(944,000,000)	(752,000,000)
Electricity purchases and sales | Income Approach
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	689,000,000	606,000,000
Liabilities	(1,616,000,000)	(1,399,000,000)
Total	(927,000,000)	(793,000,000)
Electricity purchases and sales | Minimum | Income Approach | Hourly price curve shape
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	0	0
Electricity purchases and sales | Minimum | Income Approach | Illiquid delivery periods for hub power prices
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	25	25
Electricity purchases and sales | Minimum | Income Approach | Market Heat Rates
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	45	30
Electricity purchases and sales | Maximum | Income Approach | Hourly price curve shape
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	95	95
Electricity purchases and sales | Maximum | Income Approach | Illiquid delivery periods for hub power prices
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	145	140
Electricity purchases and sales | Maximum | Income Approach | Market Heat Rates
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	120	150
Electricity purchases and sales | Arithmetic Average | Income Approach | Hourly price curve shape
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	48	48
Electricity purchases and sales | Arithmetic Average | Income Approach | Illiquid delivery periods for hub power prices
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	85	83
Electricity purchases and sales | Arithmetic Average | Income Approach | Market Heat Rates
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	83	90
Options | Option Pricing Model
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	7,000,000	6,000,000
Liabilities	(181,000,000)	(139,000,000)
Total	$ (174,000,000)	$ (133,000,000)
Options | Minimum | Option Pricing Model | Natural gas to power correlation
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input	0	0.10
Options | Minimum | Option Pricing Model | Power and natural gas volatility
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input	0.05	0.05
Options | Maximum | Option Pricing Model | Natural gas to power correlation
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input	1	1
Options | Maximum | Option Pricing Model | Power and natural gas volatility
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input	8.35	7.10
Options | Arithmetic Average | Option Pricing Model | Natural gas to power correlation
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input	0.50	0.55
Options | Arithmetic Average | Option Pricing Model | Power and natural gas volatility
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input	4.20	3.58
Financial transmission rights/Congestion revenue rights | Market Approach
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	$ 196,000,000	$ 190,000,000
Liabilities	(21,000,000)	(25,000,000)
Total	175,000,000	165,000,000
Financial transmission rights/Congestion revenue rights | Minimum | Market Approach | Illiquid price differences between settlement points
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	5	(35)
Financial transmission rights/Congestion revenue rights | Maximum | Market Approach | Illiquid price differences between settlement points
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	25	20
Financial transmission rights/Congestion revenue rights | Arithmetic Average | Market Approach | Illiquid price differences between settlement points
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	15	(8)
Natural gas | Income Approach
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	12,000,000	29,000,000
Liabilities	(27,000,000)	(30,000,000)
Total	(15,000,000)	(1,000,000)
Natural gas | Minimum | Income Approach | Natural gas basis
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	(1)	0
Natural gas | Minimum | Income Approach | Illiquid delivery periods
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	3	0
Natural gas | Maximum | Income Approach | Natural gas basis
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	12	10
Natural gas | Maximum | Income Approach | Illiquid delivery periods
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	5	5
Natural gas | Arithmetic Average | Income Approach | Natural gas basis
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	5	5
Natural gas | Arithmetic Average | Income Approach | Illiquid delivery periods
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	4	2
Other
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	2,000,000	10,000,000
Liabilities	(5,000,000)	0
Total	$ (3,000,000)	$ 10,000,000

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Fair Value Measurements - Schedule of Changes in Fair Value of the Level 3 Assets and Liabilities (Details) - Level 3 - Commodity Contract - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Net liability balance at beginning of period	$ (752)	$ (1,044)
Total unrealized valuation (losses)	(243)	(269)
Purchases, issuances and settlements
Purchases	49	70
Issuances	(2)	(3)
Settlements	(7)	99
Transfers into Level 3	1	3
Transfers out of Level 3	10	8
Net liabilities assumed in connection with the Energy Harbor Merger	0	(13)
Net change	(192)	(105)
Net liability balance at end of period	(944)	(1,149)
Unrealized valuation (losses) relating to instruments held at end of period	$ (266)	$ (325)

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Fair Value Measurements - Schedule of Fair Value of Debt (Details) - USD ($) $ in Millions	Mar. 31, 2025	Dec. 31, 2024
Carrying Amount | Long-term debt under the Vistra Operations Credit Facilities | Level 2
Debt Instrument [Line Items]
Debt instrument, fair value disclosure	$ 2,431	$ 2,435
Carrying Amount | BCOP Credit Facilities Tax Credit Bridge Loan | Level 3
Debt Instrument [Line Items]
Debt instrument, fair value disclosure	348	344
Carrying Amount | Vistra Zero Term Loan B Facility | Level 2
Debt Instrument [Line Items]
Debt instrument, fair value disclosure	686	685
Carrying Amount | Vistra Operations Senior Notes | Level 2
Debt Instrument [Line Items]
Debt instrument, fair value disclosure	12,371	12,366
Carrying Amount | Energy Harbor Revenue Bonds | Level 2
Debt Instrument [Line Items]
Debt instrument, fair value disclosure	415	414
Carrying Amount | Equipment Financing Agreements | Level 3
Debt Instrument [Line Items]
Debt instrument, fair value disclosure	54	54
Carrying Amount | Forward Repurchase Obligation | Level 3
Debt Instrument [Line Items]
Debt instrument, fair value disclosure	1,355	1,335
Fair Value | Long-term debt under the Vistra Operations Credit Facilities | Level 2
Debt Instrument [Line Items]
Debt instrument, fair value disclosure	2,456	2,478
Fair Value | BCOP Credit Facilities Tax Credit Bridge Loan | Level 3
Debt Instrument [Line Items]
Debt instrument, fair value disclosure	367	367
Fair Value | Vistra Zero Term Loan B Facility | Level 2
Debt Instrument [Line Items]
Debt instrument, fair value disclosure	670	697
Fair Value | Vistra Operations Senior Notes | Level 2
Debt Instrument [Line Items]
Debt instrument, fair value disclosure	12,483	12,428
Fair Value | Energy Harbor Revenue Bonds | Level 2
Debt Instrument [Line Items]
Debt instrument, fair value disclosure	431	431
Fair Value | Equipment Financing Agreements | Level 3
Debt Instrument [Line Items]
Debt instrument, fair value disclosure	54	53
Fair Value | Forward Repurchase Obligation | Level 3
Debt Instrument [Line Items]
Debt instrument, fair value disclosure	$ 1,355	$ 1,335

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Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024	Dec. 31, 2024
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at beginning of period	$ 4,078	$ 2,538
Accretion	48	33
Adjustment for change in estimates	(33)	3
Adjustment for obligations assumed through acquisition	0	1,368
Payments	(20)	(17)
Liability at end of period	4,073	3,925
Additions:
Accretion	48	33
Adjustment for change in estimates	(33)	3
Adjustment for obligations assumed through acquisition	0	1,368
Reductions:
Payments	(20)	(17)
Less amounts due currently	(136)	(119)	$ (142)
Noncurrent liability at end of period	3,937	3,806	$ 3,936
Asset retirement obligation, non-cash additions, asset retirement costs	15	1
Nuclear Plant Decommissioning
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at beginning of period	3,240	1,742
Accretion	37	23
Adjustment for change in estimates	0	0
Adjustment for obligations assumed through acquisition	0	1,368
Payments	0	0
Liability at end of period	3,277	3,133
Additions:
Accretion	37	23
Adjustment for change in estimates	0	0
Adjustment for obligations assumed through acquisition	0	1,368
Reductions:
Payments	0	0
Less amounts due currently	0	0
Noncurrent liability at end of period	3,277	3,133
Increase (decrease) in regulatory liabilities	14	14
Nuclear Plant Decommissioning | Operating Expense
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion	23	9
Additions:
Accretion	23	9
Land Reclamation, Coal Ash and Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at beginning of period	838	796
Accretion	11	10
Adjustment for change in estimates	(33)	3
Adjustment for obligations assumed through acquisition	0	0
Payments	(20)	(17)
Liability at end of period	796	792
Additions:
Accretion	11	10
Adjustment for change in estimates	(33)	3
Adjustment for obligations assumed through acquisition	0	0
Reductions:
Payments	(20)	(17)
Less amounts due currently	(136)	(119)
Noncurrent liability at end of period	$ 660	$ 673

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Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024	Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligations [Line Items]
Asset retirement obligation	$ 4,073	$ 3,925	$ 4,078	$ 2,538
Regulatory liability	$ 411		452
Asset retirement obligation, individual unit basis evaluation period	5 years
Accretion	$ 48	33
Nuclear Plant Decommissioning
Asset Retirement Obligations [Line Items]
Asset retirement obligation	3,277	3,133	$ 3,240	$ 1,742
Accretion	37	23
Nuclear Plant Decommissioning | Operating Expense
Asset Retirement Obligations [Line Items]
Accretion	23	$ 9
Nuclear Plant Decommissioning | Comanche Peak Nuclear Power Plant
Asset Retirement Obligations [Line Items]
Asset retirement obligation	1,812
Assets	$ 2,223

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Commitments and Contingencies (Details) $ in Millions	1 Months Ended										3 Months Ended
	Aug. 31, 2024 state	May 31, 2024 petition	Aug. 31, 2023 application	May 31, 2023 facility category	Mar. 31, 2023 state	Oct. 31, 2022	Jul. 31, 2022 application	Jun. 30, 2022	Jan. 31, 2022 application	Oct. 31, 2021 application	Mar. 31, 2025 USD ($) lawsuit MW	Apr. 30, 2025 USD ($)	Feb. 28, 2025	Apr. 30, 2024 unit	Jul. 31, 2019 plant
Loss Contingencies [Line Items]
Legal claim, duration						5 years
Number of nuclear power plants | plant															2
Greenhouse gas emissions, final rule, number of states filing petitions challenging final rule | petition		17
Environmental protection agency, number of categories of unit | category				2
Environmental protection agency, number of potential unit | unit														10
Demand report submission period								90 days
Moss Landing Power Plant (Battery Storage Project) | Moss Landing Battery Energy Storage System Phase I
Loss Contingencies [Line Items]
Battery energy storage system capacity | MW											300
Environmental remediation obligation related to pollution monitoring											$ 30.0
Environmental remediation obligation including battery removal and land remediation											$ 40.0
Moss Landing Power Plant (Battery Storage Project) | Moss Landing Battery Energy Storage System Phase III
Loss Contingencies [Line Items]
Battery energy storage system capacity | MW											350
Undiscounted future costs, expenses within operating costs											$ 70.0
Martin Lake Steam Electric Station | Maximum
Loss Contingencies [Line Items]
Clean air act, regional haze program, best available retrofit technology alternative, sulfur dioxide emissions, number of years remaining before generation unit is subject to program				3 years
Coleto Creek | Maximum
Loss Contingencies [Line Items]
Clean air act, regional haze program, best available retrofit technology alternative, sulfur dioxide emissions, number of years remaining before generation unit is subject to program				5 years
Beaver Valley, Davis-besse And Perry Facilities
Loss Contingencies [Line Items]
Non-nuclear property damage insurance, maximum coverage											1,500.0
Accidental outage insurance, coverage for obtaining replacement energy after 12 week waiting period, maximum weekly coverage first 52 weeks											2.5
Accidental outage insurance, coverage for obtaining replacement energy after 12 week waiting period, maximum weekly payments, remining 21 weeks non-nuclear property											1.5
Accidental outage insurance, coverage for obtaining replacement energy after 12 week waiting period, maximum weekly payments, remaining 26 weeks non-nuclear and 71 weeks nuclear property											2.0
Accidental outage insurance, coverage for obtaining replacement energy, coverage limit for non-nuclear accidents											208.0
Accidental outage insurance, coverage for obtaining replacement energy, coverage limit for nuclear accidents											$ 350.0
Beaver Valley, Davis-besse And Perry Facilities | Subsequent Event
Loss Contingencies [Line Items]
Nuclear decontamination and property insurance, maximum coverage												$ 2,250.0
Non-nuclear property damage insurance, maximum coverage												1,000.0
Non-nuclear property damage insurance, deductible per accident, general												10.0
Non-nuclear property damage insurance, deductible per incident, natural hazard												20.0
Accidental outage insurance, coverage for obtaining replacement energy after 12 week waiting period, maximum weekly coverage first 52 weeks												4.5
Accidental outage insurance, coverage for obtaining replacement energy after 12 week waiting period, maximum weekly payments, remining 21 weeks non-nuclear property												2.7
Accidental outage insurance, coverage for obtaining replacement energy after 12 week waiting period, maximum weekly payments, remaining 26 weeks non-nuclear and 71 weeks nuclear property												3.6
Accidental outage insurance, coverage for obtaining replacement energy, coverage limit for non-nuclear accidents												291.0
Accidental outage insurance, coverage for obtaining replacement energy, coverage limit for nuclear accidents												$ 490.0
United States Environmental Protection Agency
Loss Contingencies [Line Items]
Cross-state air pollution rule, 2015 ozone national ambient air quality standards, federal implementation plan, beginning 2023 ozone season, number of states subject to rule | state					22
Clean air act, regional haze program, best available retrofit technology alternative, sulfur dioxide emissions, number of electricity generation units in texas subject to program | facility				6
Federal coal combustion residual rule, proposed groundwater monitoring and closure requirement, number of states challenging rule | state	17
Illinois Environmental Protection Agency
Loss Contingencies [Line Items]
Coal combustion residuals, rules for closure of coal ash ponds in Illinois, number of operating permit applications filed | application										18
Coal combustion residuals, rules for closure of coal ash ponds in Illinois, number of construction permit application filed | application			1				5		3
Gas Index Pricing Litigation | Wisconsin
Loss Contingencies [Line Items]
Loss contingency, pending claims, number | lawsuit											1
Greenhouse Gas Emissions (GHG)
Loss Contingencies [Line Items]
Litigation, period													60 days
Legacy CCR Rulemaking
Loss Contingencies [Line Items]
Litigation, period													120 days
Letters of Credit | Vistra Operations Company LLC
Loss Contingencies [Line Items]
Letters of credit outstanding											$ 2,814.0
Letters of Credit | Vistra Operations Company LLC | Support Risk Management and Trading Margin Requirements Including Over the Counter Hedging Transactions and Collateral Postings with Electric Reliability Council of Texas
Loss Contingencies [Line Items]
Letters of credit outstanding											2,439.0
Letters of Credit | Vistra Operations Company LLC | Support Battery and Solar Development Projects
Loss Contingencies [Line Items]
Letters of credit outstanding											251.0
Letters of Credit | Vistra Operations Company LLC | Support Executory Contracts and Insurance Agreements
Loss Contingencies [Line Items]
Letters of credit outstanding											25.0
Letters of Credit | Vistra Operations Company LLC | Support Retail Electric Provider's financial requirements with the Public Utility Commission of Texas
Loss Contingencies [Line Items]
Letters of credit outstanding											86.0
Letters of Credit | Vistra Operations Company LLC | Miscellaneous Credit Support Requirements
Loss Contingencies [Line Items]
Letters of credit outstanding											13.0
Surety Bonds | Vistra Operations Company LLC
Loss Contingencies [Line Items]
Surety bonds outstanding											$ 1,072.0

XML

Equity - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		3 Months Ended		4 Months Ended	43 Months Ended
	May 31, 2025	May 02, 2025	Mar. 31, 2025	Mar. 31, 2024	May 02, 2025	May 02, 2025	Dec. 31, 2024
Accelerated Share Repurchases [Line Items]
Common stock, dividends, per share, cash paid (in dollars per share)			$ 0.2235	$ 0.2150
Preferred sock, liquidation preference (in dollars per share)			1,000				$ 1,000
Subsequent Event
Accelerated Share Repurchases [Line Items]
Common stock, dividends, per share, declared (in dollars per share)	$ 0.225
Series A Preferred Stock
Accelerated Share Repurchases [Line Items]
Preferred sock, liquidation preference (in dollars per share)			1,000
Preferred stock, dividends per share, declared (in dollars per share)			40.00
Series B Preferred Stock
Accelerated Share Repurchases [Line Items]
Preferred sock, liquidation preference (in dollars per share)			1,000
Series B Preferred Stock | Subsequent Event
Accelerated Share Repurchases [Line Items]
Preferred stock, dividends per share, declared (in dollars per share)	35.00
Series C Preferred Stock
Accelerated Share Repurchases [Line Items]
Preferred sock, liquidation preference (in dollars per share)			$ 1,000
Series C Preferred Stock | Subsequent Event
Accelerated Share Repurchases [Line Items]
Preferred stock, dividends per share, declared (in dollars per share)	$ 44.375
Share Repurchase Program
Accelerated Share Repurchases [Line Items]
Stock repurchase program, authorized amount			$ 6,750
Treasury stock, shares, acquired (in shares)			2,437,700
Treasury stock acquired, average cost per share ( in dollars per share)			$ 137.66
Share Repurchase Program | Subsequent Event
Accelerated Share Repurchases [Line Items]
Treasury stock, shares, acquired (in shares)		1,138,753			3,576,453	162,932,192
Treasury stock acquired, average cost per share ( in dollars per share)		$ 114.95			$ 130.43	$ 31.96

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Equity - Schedule of Repurchase Agreements (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended		4 Months Ended	43 Months Ended
	May 02, 2025	Mar. 31, 2025	Mar. 31, 2024	May 02, 2025	May 02, 2025
Accelerated Share Repurchases [Line Items]
Treasury stock, value, acquired, cost method		$ 336	$ 285
Share Repurchase Program
Accelerated Share Repurchases [Line Items]
Treasury stock, shares, acquired (in shares)		2,437,700
Treasury stock acquired, average cost per share ( in dollars per share)		$ 137.66
Treasury stock, value, acquired, cost method		$ 336
Stock repurchase program, remaining authorized repurchase amount		$ 1,673
Treasury stock, shares, acquired, accrued (in shares)		59,503
Treasury stock, value, acquired, accrued, cost method		$ 7
Stock repurchase program, authorized amount		$ 6,750
Share Repurchase Program | Subsequent Event
Accelerated Share Repurchases [Line Items]
Treasury stock, shares, acquired (in shares)	1,138,753			3,576,453	162,932,192
Treasury stock acquired, average cost per share ( in dollars per share)	$ 114.95			$ 130.43	$ 31.96
Treasury stock, value, acquired, cost method	$ 131			$ 467
Stock repurchase program, remaining authorized repurchase amount	$ 1,542			$ 1,542	$ 1,542

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Equity - Schedule of Preferred Stock (Details) - shares	3 Months Ended
	Mar. 31, 2025	Dec. 31, 2024
Class of Stock [Line Items]
Preferred stock, shares outstanding (in shares)	2,476,066	2,476,066
Series A Preferred Stock
Class of Stock [Line Items]
Preferred stock, shares issued (in shares)	1,000,000
Preferred stock, shares outstanding (in shares)	1,000,000
Preferred stock, dividend rate, percentage	8.00%
Preferred stock, dividend rate, first reset date and thereafter, rate floor, annual term	5 years
Preferred stock, dividend rate, first reset date and thereafter, rate floor, percentage	1.07%
Preferred stock, dividend rate, first reset date and thereafter, basis spread on variable rate, percentage	6.93%
Series B Preferred Stock
Class of Stock [Line Items]
Preferred stock, shares issued (in shares)	1,000,000
Preferred stock, shares outstanding (in shares)	1,000,000
Preferred stock, dividend rate, percentage	7.00%
Preferred stock, dividend rate, first reset date and thereafter, rate floor, annual term	5 years
Preferred stock, dividend rate, first reset date and thereafter, rate floor, percentage	1.26%
Preferred stock, dividend rate, first reset date and thereafter, basis spread on variable rate, percentage	5.74%
Series C Preferred Stock
Class of Stock [Line Items]
Preferred stock, shares issued (in shares)	476,081
Preferred stock, shares outstanding (in shares)	476,066
Preferred stock, dividend rate, percentage	8.875%
Preferred stock, dividend rate, first reset date and thereafter, rate floor, annual term	5 years
Preferred stock, dividend rate, first reset date and thereafter, rate floor, percentage	3.83%
Preferred stock, dividend rate, first reset date and thereafter, basis spread on variable rate, percentage	5.045%

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Equity - Schedule of Dividends Declared (Details) - $ / shares	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Series C Preferred Stock
Dividends Payable [Line Items]
Preferred stock, dividends per share, paid (in dollars per share)	$ 44.375	$ 0

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Earnings Per Share - Schedule of Earnings Per Share, Basic and Diluted (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss attributable to Vistra	$ (268)	$ (35)
Less cumulative dividends attributable to preferred stock	(49)	(49)
Net loss attributable to Vistra common stock	(317)	(84)
Net loss attributable to Vistra common stock	$ (317)	$ (84)
Weighted average shares of common stock outstanding:
Weighted average shares of common stock outstanding - basic (in shares)	339,799,989	348,966,197
Dilutive securities - stock-based incentive compensation plan	0	0
Weighted average shares of common stock outstanding - diluted (in shares)	339,799,989	348,966,197
Net loss per weighted average share of common stock outstanding:
Net loss per weighted average share of common stock outstanding - basic (in dollars per share)	$ (0.93)	$ (0.24)
Net loss per weighted average share of common stock outstanding - diluted (in dollars per share)	$ (0.93)	$ (0.24)
Series A Preferred Stock
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Less cumulative dividends attributable to preferred stock	$ (20)	$ (20)
Series B Preferred Stock
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Less cumulative dividends attributable to preferred stock	(18)	(18)
Series C Preferred Stock
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Less cumulative dividends attributable to preferred stock	$ (11)	$ (11)

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Earnings Per Share - Narrative (Details) - shares	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Earnings Per Share [Abstract]
Antidilutive securities excluded from computation of earnings per share (in shares)	8,582,267	7,954,878

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Segment Information - Narrative (Details)	3 Months Ended
	Mar. 31, 2025 state segment
Segment Reporting [Abstract]
Number of reportable segments | segment	5
Numbers of states in which entity operates | state	16

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Segment Information - Schedule of Segment Reporting Information, by Segment (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Segment Reporting Information [Line Items]
Operating revenues	$ 3,933	$ 3,054
Fuel, purchased power costs, and delivery fees	(2,447)	(1,716)
Operating costs	(693)	(498)
Selling, general, and administrative expenses	(391)	(351)
Depreciation and amortization	(522)	(403)
Interest expenses and related charges	(319)	(170)
Income tax benefit	176	20
Other	(5)	82
Net income (loss)	(268)	18
Capital expenditures, including nuclear fuel and excluding growth expenditures	729	421
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	4,919	4,094
Fuel, purchased power costs, and delivery fees	(3,433)	(2,756)
Operating costs	(693)	(497)
Selling, general, and administrative expenses	(361)	(302)
Depreciation and amortization	(503)	(388)
Interest expenses and related charges	8	2
Income tax benefit	0	0
Other	(6)	42
Net income (loss)	(69)	195
Capital expenditures, including nuclear fuel and excluding growth expenditures	716	410
Corporate and Other
Segment Reporting Information [Line Items]
Operating revenues	(986)	(1,040)
Fuel, purchased power costs, and delivery fees	986	1,040
Operating costs	0	(1)
Selling, general, and administrative expenses	(30)	(49)
Depreciation and amortization	(19)	(15)
Interest expenses and related charges	(327)	(172)
Income tax benefit	176	20
Other	1	40
Net income (loss)	(199)	(177)
Capital expenditures, including nuclear fuel and excluding growth expenditures	13	11
Retail | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	3,168	2,494
Fuel, purchased power costs, and delivery fees	(1,712)	(1,647)
Operating costs	(40)	(31)
Selling, general, and administrative expenses	(243)	(225)
Depreciation and amortization	(23)	(23)
Interest expenses and related charges	(18)	(6)
Income tax benefit	0	0
Other	0	(1)
Net income (loss)	1,132	561
Capital expenditures, including nuclear fuel and excluding growth expenditures	3	0
Texas | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	210	459
Fuel, purchased power costs, and delivery fees	(497)	(381)
Operating costs	(258)	(257)
Selling, general, and administrative expenses	(41)	(35)
Depreciation and amortization	(150)	(134)
Interest expenses and related charges	14	10
Income tax benefit	0	0
Other	2	2
Net income (loss)	(720)	(336)
Capital expenditures, including nuclear fuel and excluding growth expenditures	419	316
East | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	1,380	856
Fuel, purchased power costs, and delivery fees	(1,172)	(647)
Operating costs	(327)	(181)
Selling, general, and administrative expenses	(58)	(28)
Depreciation and amortization	(316)	(210)
Interest expenses and related charges	12	(1)
Income tax benefit	0	0
Other	(9)	38
Net income (loss)	(490)	(173)
Capital expenditures, including nuclear fuel and excluding growth expenditures	264	88
West | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	157	276
Fuel, purchased power costs, and delivery fees	(52)	(79)
Operating costs	(12)	(11)
Selling, general, and administrative expenses	(2)	(4)
Depreciation and amortization	(15)	(14)
Interest expenses and related charges	1	0
Income tax benefit	0	0
Other	0	0
Net income (loss)	77	168
Capital expenditures, including nuclear fuel and excluding growth expenditures	30	6
Asset Closure | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	4	9
Fuel, purchased power costs, and delivery fees	0	(2)
Operating costs	(56)	(17)
Selling, general, and administrative expenses	(17)	(10)
Depreciation and amortization	1	(7)
Interest expenses and related charges	(1)	(1)
Income tax benefit	0	0
Other	1	3
Net income (loss)	(68)	(25)
Capital expenditures, including nuclear fuel and excluding growth expenditures	$ 0	$ 0

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Supplementary Financial Information - Schedule of Other Income and Deductions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Supplementary Financial Information [Abstract]
NDT net income (loss)	$ (10)	$ 35
Insurance settlements	0	1
Gain on sale of land	0	1
Gain on TRA settlement	0	10
Interest income	6	23
All other	(1)	17
Total other income (deductions), net	$ (5)	$ 87

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Supplementary Financial Information - Schedule of Inventories by Major Category (Details) - USD ($) $ in Millions	Mar. 31, 2025	Dec. 31, 2024
Inventories by Major Category
Materials and supplies	$ 541	$ 533
Fuel stock	399	403
Natural gas in storage	20	34
Total inventories	$ 960	$ 970

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Supplementary Financial Information - Schedule of Investments (Details) - USD ($) $ in Millions	Mar. 31, 2025	Dec. 31, 2024
Supplementary Financial Information [Abstract]
Nuclear decommissioning trusts	$ 4,404	$ 4,440
Assets related to employee benefit plans	13	14
Land investments	42	42
Other investments	17	16
Total investments	$ 4,476	$ 4,512

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Supplementary Financial Information - Schedule of Other Noncurrent Liabilities and Deferred Credits (Details) - USD ($) $ in Millions	Mar. 31, 2025	Dec. 31, 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Retirement and other employee benefits	$ 204	$ 224
Identifiable intangible liabilities	149	155
Regulatory liability	411	452
Operating lease liabilities	81	98
Finance lease liabilities	217	218
Liability for third-party remediation	8	8
Accrued severance costs	36	36
Tax Receivable Agreement obligation	12	14
Other accrued expenses	110	65
Total other noncurrent liabilities and deferred credits	1,228	1,270
Nuclear Plant Decommissioning - Other Noncurrent Liabilities | Comanche Peak Nuclear Power Plant
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Regulatory liability	$ 411	$ 452

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Supplementary Financial Information - Schedule Of Cash, Cash Equivalents And Restricted Cash (Details) - USD ($) $ in Millions	Mar. 31, 2025	Dec. 31, 2024	Mar. 31, 2024	Dec. 31, 2023
Supplementary Financial Information [Abstract]
Cash and cash equivalents	$ 561	$ 1,188
Restricted cash included in current assets	29	28
Restricted cash included in noncurrent assets	6	6
Total cash, cash equivalents and restricted cash	$ 596	$ 1,222	$ 1,116	$ 3,539

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Supplementary Financial Information - Schedule of Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Supplementary Financial Information [Abstract]
Interest paid	$ 210	$ 214
Capitalized interest	(29)	(12)
Interest paid (net of capitalized interest)	$ 181	$ 202

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Supplementary Financial Information - Narrative (Details) - State and Local Jurisdiction - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2025	Mar. 31, 2024
Income Tax Contingency [Line Items]
Income taxes paid	$ 5	$ 3
Income tax refunds	$ 0	$ 1