Vistra (VST) 10-K 27 Feb 25 2024 FY Annual report Financial data

Cover

Cover - USD ($)	12 Months Ended
	Dec. 31, 2024	Feb. 24, 2025	Jun. 30, 2024
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2024
Current Fiscal Year End Date	--12-31
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 Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
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
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
Entity Public Float			$ 29,500,179,937
Entity Common Stock, Shares Outstanding		338,963,642
Documents Incorporated by Reference	Portions of the Registrant's definitive Proxy Statement relating to its 2025 Annual Meeting of Stockholders are incorporated by reference in Part III of this annual report on Form 10-K.
Entity Central Index Key	0001692819
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	FY
Amendment Flag	false

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2024
Audit Information [Abstract]
Auditor Name	Deloitte & Touche LLP
Auditor Location	Dallas, Texas
Auditor Firm ID	34

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income Statement [Abstract]
Operating revenues	$ 17,224	$ 14,779	$ 13,728
Fuel, purchased power costs, and delivery fees	(7,285)	(7,557)	(10,401)
Operating costs	(2,414)	(1,702)	(1,645)
Depreciation and amortization	(1,843)	(1,502)	(1,596)
Selling, general, and administrative expenses	(1,601)	(1,308)	(1,189)
Impairment of long-lived and other assets	0	(49)	(74)
Operating income (loss)	4,081	2,661	(1,177)
Other income	312	257	117
Other deductions	(21)	(14)	(4)
Interest expense and related charges	(900)	(740)	(368)
Impacts of Tax Receivable Agreement	(5)	(164)	(128)
Net income (loss) before income taxes	3,467	2,000	(1,560)
Income tax expense	(655)	(508)	350
Net income (loss)	2,812	1,492	(1,210)
Net (income) loss attributable to noncontrolling interest and redeemable noncontrolling interest	(153)	1	(17)
Net income (loss) attributable to Vistra	2,659	1,493	(1,227)
Cumulative dividends attributable to preferred stock	(192)	(150)	(150)
Net income (loss) attributable to Vistra common stock	$ 2,467	$ 1,343	$ (1,377)
Weighted average shares of common stock outstanding:
Basic (in shares)	344,788,634	369,771,359	422,447,074
Diluted (in shares)	352,567,060	375,193,110	422,447,074
Net income (loss) per weighted average share of common stock outstanding:
Basic (in dollars per share)	$ 7.16	$ 3.63	$ (3.26)
Diluted (in dollars per share)	$ 7	$ 3.58	$ (3.26)

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 2,812	$ 1,492	$ (1,210)
Other comprehensive income (loss), net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax expense of $4, $— and $7)	14	(1)	23
Total other comprehensive income (loss)	14	(1)	23
Comprehensive income (loss)	2,826	1,491	(1,187)
Comprehensive (income) loss attributable to noncontrolling interest and redeemable noncontrolling interest	(153)	1	(17)
Comprehensive income (loss) attributable to Vistra	$ 2,673	$ 1,492	$ (1,204)

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Statement of Comprehensive Income [Abstract]
Effects related to pension and other retirement obligations (tax)	$ 4	$ 0	$ 7

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Current assets:
Cash and cash equivalents	$ 1,188	$ 3,485
Restricted cash	28	40
Total trade accounts receivable — net	1,982	1,674
Income taxes receivable	8	6
Inventories	970	740
Commodity and other derivative contractual assets	2,587	3,645
Margin deposits related to commodity contracts	406	1,244
Margin deposits posted under affiliate financing agreement	435	439
Prepaid expense and other current assets	515	364
Total current assets	8,119	11,637
Restricted cash	6	14
Investments	4,512	2,035
Property, plant, and equipment — net	18,173	12,432
Goodwill	2,807	2,583
Identifiable intangible assets — net	2,213	1,864
Commodity and other derivative contractual assets	740	577
Accumulated deferred income taxes	9	1,223
Other noncurrent assets	1,191	601
Total assets	37,770	32,966
Current liabilities:
Accounts receivable financing	750	0
Long-term debt due currently	880	2,286
Forward repurchase obligation due currently	703	0
Trade accounts payable	1,510	1,147
Commodity and other derivative contractual liabilities	3,351	5,258
Margin deposits related to commodity contracts	49	45
Accrued taxes other than income	209	203
Accrued interest	193	206
Asset retirement obligations	142	124
Other current liabilities	645	554
Total current liabilities	8,432	9,823
Margin deposits financing with affiliate	435	439
Long-term debt, less amounts due currently	15,418	12,116
Forward repurchase obligation, less amounts due currently	632	0
Commodity and other derivative contractual liabilities	1,367	1,688
Accumulated deferred income taxes	697	1
Tax Receivable Agreement obligation	14	164
Asset retirement obligations	3,936	2,414
Other noncurrent liabilities and deferred credits	1,256	999
Total liabilities	32,187	27,644
Commitments and Contingencies
Preferred stock, shares outstanding (in shares)	2,476,066	2,476,081
Preferred sock, liquidation preference	$ 1,000	$ 1,000
Total equity:
Preferred stock (100,000,000 shares authorized, $1,000 liquidation preference per share, 2,476,066 and 2,476,081 shares outstanding at December 31, 2024 and 2023, respectively)	$ 2,476	$ 2,476
Common stock (par value $0.01 per share, 1,800,000,000 shares authorized, 339,754,307 and 351,457,016 shares outstanding at December 31, 2024 and 2023, respectively)	5	5
Treasury stock, at cost (208,998,299 and 192,178,156 shares at December 31, 2024 and 2023, respectively)	(5,912)	(4,662)
Additional paid-in-capital	9,435	10,095
Accumulated deficit	(454)	(2,613)
Accumulated other comprehensive income	20	6
Stockholders' equity	5,570	5,307
Noncontrolling interest in subsidiary	13	15
Total equity	5,583	5,322
Total liabilities and equity	$ 37,770	$ 32,966

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2024	Dec. 31, 2023
Statement of Financial Position [Abstract]
Preferred stock, shares authorized (in shares)	100,000,000	100,000,000
Preferred sock, liquidation preference	$ 1,000	$ 1,000
Preferred stock, shares outstanding (in shares)	2,476,066	2,476,081
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)	339,754,307	351,457,016
Treasury stock, common shares (in shares)	208,998,299	192,178,156

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Cash flows — operating activities:
Net income (loss)	$ 2,812	$ 1,492	$ (1,210)
Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:
Depreciation and amortization	2,631	1,956	2,047
Deferred income tax expense (benefit), net	607	457	(359)
Gain on sale of land	0	(95)	(8)
Impairment of long-lived and other assets	0	49	74
Unrealized net (gain) loss from mark-to-market valuations of commodities	(1,155)	(490)	2,510
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps	(53)	36	(250)
Unrealized net gain from nuclear decommissioning trusts	(116)	0	0
Change in asset retirement obligation liability	38	27	13
Asset retirement obligation accretion expense	114	34	34
Impacts of Tax Receivable Agreement	5	164	128
Gain on TRA repurchase and tender offers	(10)	(29)	0
Bad debt expense	183	164	179
Stock-based compensation	100	77	63
Other, net	(89)	103	(71)
Changes in operating assets and liabilities:
Accounts receivable — trade	(242)	214	(852)
Inventories	(31)	(174)	36
Accounts payable — trade	19	(350)	94
Commodity and other derivative contractual assets and liabilities	(175)	82	(228)
Margin deposits, net	842	1,899	(1,874)
Uplift securitization proceeds receivable from ERCOT	0	0	544
Accrued interest	(18)	46	16
Accrued taxes	(1)	5	(8)
Accrued employee incentive	8	58	21
Asset retirement obligation settlement	(88)	(81)	(87)
Major plant outage deferral	(91)	(32)	20
Other — net assets	(616)	84	(17)
Other — net liabilities	(111)	(243)	(330)
Cash provided by operating activities	4,563	5,453	485
Cash flows — investing activities:
Capital expenditures, including nuclear fuel purchases and LTSA prepayments	(2,078)	(1,676)	(1,301)
Energy Harbor acquisition (net of cash acquired)	(3,065)	0	0
Proceeds from sales of nuclear decommissioning trust fund securities	2,216	601	670
Investments in nuclear decommissioning trust fund securities	(2,239)	(624)	(693)
Proceeds from sales of environmental allowances	773	500	1,275
Purchases of environmental allowances	(1,226)	(1,071)	(1,303)
Proceeds from sales of property, plant, and equipment, including nuclear fuel	196	115	78
Proceeds from sales of transferable ITCs	150	0	0
Other, net	(3)	10	35
Cash used in investing activities	(5,276)	(2,145)	(1,239)
Cash flows — financing activities:
Issuances of long-term debt	3,817	2,498	1,498
Repayments/repurchases of debt	(2,287)	(33)	(251)
Net borrowings (repayments) under accounts receivable financing	750	(425)	425
Borrowings under Revolving Credit Facility	50	100	1,750
Repayments under Revolving Credit Facility	(50)	(350)	(1,500)
Borrowings under Commodity-Linked Facility	1,802	0	3,150
Repayments under Commodity-Linked Facility	(1,802)	(400)	(2,750)
Debt issuance costs	(76)	(59)	(31)
Stock repurchases	(1,266)	(1,245)	(1,949)
Dividends paid to common stockholders	(305)	(313)	(302)
Dividends paid to preferred stockholders	(173)	(150)	(151)
Dividends paid to noncontrolling and redeemable noncontrolling interest holders	(180)	0	0
Principal payment on Closing Date	(1,748)	0	0
TRA Repurchase and tender offer — return of capital	(122)	0	0
Other, net	(14)	83	31
Cash used in financing activities	(1,604)	(294)	(80)
Net change in cash, cash equivalents and restricted cash	(2,317)	3,014	(834)
Cash, cash equivalents and restricted cash — beginning balance	3,539	525	1,359
Cash, cash equivalents and restricted cash — ending balance	$ 1,222	$ 3,539	$ 525

Consolidated Statement of Chang

Consolidated Statement of Changes in Equity - USD ($) $ in Millions		Total	Series C Preferred Stock	Total Stockholders' Equity	Total Stockholders' Equity Series C Preferred Stock	Preferred Stock	Preferred Stock Series C 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, 2021		$ 8,292		$ 8,291		$ 2,000		$ 5	$ (1,558)	$ 9,824	$ (1,964)	$ (16)	$ 1
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock repurchases		(1,837)		(1,837)					(1,837)
Effects of stock-based incentive compensation plans		103		103						103
Net income (loss)		(1,210)		(1,227)							(1,227)		17
Dividends declared on common stock		(302)		(302)							(302)
Dividends declared on preferred stock		(151)		(151)							(151)
Change in accumulated other comprehensive income (loss)		23		23								23
Other		0		2						1	1		(2)
Ending balance at Dec. 31, 2022		4,918		4,902		2,000		5	(3,395)	9,928	(3,643)	7	16
Beginning balance at Dec. 31, 2021		8,292		8,291		2,000		5	(1,558)	9,824	(1,964)	(16)	1
Ending balance at Dec. 31, 2024		5,583		5,570		2,476		5	(5,912)	9,435	(454)	20	13
Beginning balance at Dec. 31, 2022		4,918		4,902		2,000		5	(3,395)	9,928	(3,643)	7	16
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Series C Preferred Stock issued			$ 476		$ 476		$ 476
Stock repurchases		(1,267)		(1,267)					(1,267)
Effects of stock-based incentive compensation plans		168		168						168
Net income (loss)		1,492		1,493							1,493		(1)
Dividends declared on common stock		(313)		(313)							(313)
Dividends declared on preferred stock		(150)		(150)							(150)
Change in accumulated other comprehensive income (loss)		(1)		(1)								(1)
Other		(1)		(1)						(1)	0		0
Ending 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		(1,250)		(1,250)					(1,250)
Effects of stock-based incentive compensation plans		140		140						140
Net income (loss)		2,812
Net Income		2,761		2,659							2,659		102
Dividends declared on common stock		(307)		(307)							(307)
Dividends declared on preferred stock		(192)		(192)							(192)
Dividends to noncontrolling interest		(15)											(15)
Change in accumulated other comprehensive income (loss)		14		14								14
Equity issued in subsidiary to acquire Energy Harbor		2,307		747						747			1,560
Modification of noncontrolling interest to redeemable noncontrolling interest	[1]	(3,198)		(1,539)						(1,539)			(1,659)
Other		1		(9)						(8)	(1)		10
Ending balance at Dec. 31, 2024		$ 5,583		$ 5,570		$ 2,476		$ 5	$ (5,912)	$ 9,435	$ (454)	$ 20	$ 13
[1] See Note 2 for additional information regarding activity associated with noncontrolling interest.

Business And Significant Accoun

Business And Significant Accounting Policies	12 Months Ended
	Dec. 31, 2024
Accounting Policies [Abstract]
Business And Significant Accounting Policies	BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES 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 19 for additional information. Significant Accounting Policies Basis of Presentation The 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 2023 Form 10-K. All intercompany items and transactions have been eliminated in consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. dollars unless otherwise indicated. Certain prior period amounts have been reclassified to conform with the current year presentation. 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. Business Combinations The Company accounts for its business combinations in accordance with ASC 805, Business Combinations , which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value as of the acquisition date. The excess of the purchase price over those fair values is recognized as goodwill (if any). During the measurement period, which may be up to one year from the acquisition date, we may record adjustments to the assets acquired and liabilities assumed in the period in which they are determined. See Note 2 for additional information. Derivative Instruments and Mark-to-Market Accounting We enter derivative instruments, including commodity contracts and interest rate swaps, to manage commodity price and interest rate risks. All our derivatives are accounted for as economic hedges and are recorded at estimated fair value in the consolidated balance sheets with changes in fair value recorded as gains or losses in the earnings of the period in which they occur. No derivative positions are accounted for as cash flow or fair value hedges. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed. A commodity-related derivative contract may be designated as a normal purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement. We report derivative instruments in the consolidated balance sheets as commodity and other derivative contractual assets or liabilities on a gross basis without taking into consideration netting arrangements we have with counterparties. We maintain standardized master netting agreements with certain counterparties that allow for the right to offset derivative assets and liabilities, receivables and payables on settled positions, and collateral to reduce credit exposure between us and the counterparty. Generally, margin deposits that contractually offset derivative instruments are reported separately in the consolidated balance sheets, except for certain margin amounts related to changes in fair value on CME transactions that are legally characterized as settlement of forward exposure rather than collateral. We report commodity hedging and trading results as revenue, fuel expense, or purchased power in the consolidated statements of operations depending on the type of activity. Electricity hedges, financial natural gas hedges, and trading activities are primarily reported as revenue. Physical hedges for coal or fuel oil, along with physical natural gas trades, are primarily reported as fuel expense. Realized and unrealized gains and losses associated with interest rate swap transactions are reported in the consolidated statements of operations in interest expense. See Note 11 for additional information. Revenue Recognition Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes delivered or services provided. Sales tax is excluded from revenue. Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Estimated amounts are adjusted when actual usage is known and billed. We record wholesale generation revenue when volumes are delivered or services are performed for transactions that are not accounted for on a mark-to-market basis. These revenues primarily consist of physical electricity sales to the ISO/RTO, ancillary service revenue for reliability services, capacity revenue for making installed generation and demand response available for system reliability requirements, and certain other electricity sales contracts. See Note 3 for additional information. See Derivative Instruments and Mark-to-Market Accounting for revenue recognition related to derivative contracts. Government Assistance The Company qualifies for tax incentives through eligible construction spending and production through the Inflation Reduction Act of 2022 (IRA). These tax incentives generally provide for transferable tax credits upon the applicable qualifying event for the credit type, typically production or in-service date. We account for transferable ITCs and PTCs we expect to receive by analogy to the grant model within International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance (IAS 20). Transferable PTCs are included in other noncurrent assets in the consolidated balance sheet and included in revenues in the consolidated statements of operations when receipt of the credit is reasonably assured. Transferable investment tax credits (ITCs) are included in other noncurrent assets on the consolidated balance sheet with a corresponding reduction to the cost basis of the Company's plant assets when receipt of the credit is reasonably assured, and reduces depreciation expense over the life of the asset. We believe the reasonable assurance term as used in IAS 20 is analogous to the term probable as defined in ASC 450-20 of U.S. GAAP. See Note 4 for additional information. Major Maintenance Costs Major maintenance costs incurred during generation plant outages are deferred and amortized into operating costs over the period between the major maintenance outages for the respective asset. Other routine costs of maintenance activities are charged to expense as incurred and reported as operating costs in the consolidated statements of operations. Defined Benefit Pension Plans and OPEB Plans Certain health care and life insurance benefits are offered to eligible employees and their dependents upon the retirement of such employees from the company. Pension benefits are offered to eligible employees under collective bargaining agreements based on either a traditional defined benefit formula or a cash balance formula. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates. See Note 14 for additional information. Stock-Based Compensation Stock-based compensation is accounted for in accordance with ASC 718, Compensation - Stock Compensation. We recognize compensation expense for graded vesting awards on a straight-line basis over the requisite service period for the entire award. Forfeitures are recognized as they occur. See Note 18 for additional information. Sales and Excise Taxes Sales and excise taxes are accounted for as "pass through" items in the consolidated balance sheets with no effect on the consolidated statements of operations ( i.e. , the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability to the taxing jurisdiction in other current liabilities in the consolidated statements of operations). Franchise and Revenue-Based Taxes Unlike sales and excise taxes, franchise and revenue-based taxes are not "pass through" items. These taxes are imposed on us by state and local taxing authorities, based on revenues or kWh delivered, as a cost of doing business and are recorded as an expense. Rates we charge to customers are intended to recover our costs, including the franchise and revenue-based receipt taxes, but we are not acting as an agent to collect the taxes from customers. We report franchise and revenue-based taxes in SG&A expense in the consolidated statements of operations. Income Taxes Deferred income tax assets and liabilities are recorded to reflect, among other things, the temporary timing differences between the book basis and tax basis of assets and liabilities, as required under accounting rules. Investment tax credits that are not transferable are accounted for using the deferral method, which reduces the tax basis of our solar and battery storage facilities. As of both December 31, 2024 and 2023, deferred tax assets related to these credits totaled $69 million. We report interest and penalties related to uncertain tax positions as current income tax expense. See Note 5 for additional information. Accounting for Contingencies Our financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 15 for additional information. Cash and Cash Equivalents For purposes of reporting cash and cash equivalents, temporary cash investments purchased with an original maturity of three months or less are considered cash equivalents. Property, Plant, and Equipment Property, plant, and equipment has been recorded at estimated fair values at the time of acquisition for assets acquired or at cost for capital improvements and individual facilities developed. Significant improvements or additions to our property, plant, and equipment that extend the life of the respective asset are capitalized at cost, while other costs are expensed when incurred. The cost of self-constructed property additions includes materials and both direct and indirect labor, including payroll-related costs. Interest related to qualifying construction projects and qualifying software projects is capitalized in accordance with accounting guidance related to capitalization of interest cost. Depreciation of our property, plant, and equipment (except for nuclear fuel) is calculated on a straight-line basis over the estimated service lives of the properties. Depreciation expense is calculated on an asset-by-asset basis. Estimated depreciable lives are based on management's estimates of the assets' economic useful lives. See Note 6 for additional information. Nuclear Fuel Nuclear fuel is capitalized and reported as a component of our property, plant, and equipment in the consolidated balance sheets. Amortization of nuclear fuel is calculated on the units-of-production method and is reported as a component of fuel, purchased power costs, and delivery fees in the consolidated statements of operations. Impairment of Long-Lived Assets We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less than the carrying value. If there is such impairment, a loss is recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable. See Note 6 for additional information. Goodwill and Intangible Assets with Indefinite Lives As part of our fresh start reporting and purchase accounting from acquisitions, reorganization value or the purchase consideration is generally allocated, first, to identifiable tangible assets and liabilities, identifiable intangible assets and liabilities, then any remaining excess reorganization value or purchase consideration is allocated to goodwill. We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually, or when indications of impairment exist. We have established October 1 as the date we evaluate goodwill and intangible assets with indefinite lives for impairment. See Note 7 for additional information. Asset Retirement Obligations (ARO) A liability is initially recorded at fair value for an asset retirement obligation associated with the legal obligation associated with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets in the period in which it is incurred if a fair value is reasonably estimable. At initial recognition of an ARO obligation, an offsetting asset is also recorded for the long-lived asset that the liability corresponds with, which is subsequently depreciated over the estimated useful life of the asset. These liabilities primarily relate to our nuclear generation plant decommissioning, land reclamation related to lignite mining and removal of lignite/coal-fueled plant ash treatment facilities. Over time, the liability is accreted for the change in present value and the initial capitalized costs are depreciated over the remaining useful lives of the assets. Generally, changes in estimates related to ARO obligations are recorded as increases or decreases to the liability and related asset as information becomes available. Changes in estimates related to assets that have been retired or for which costs are not recoverable are recorded as operating costs in the consolidated statements of operations. See Note 13 for additional information. Inventories Inventories consist of materials and supplies, fuel stock and natural gas in storage. Materials and supplies inventory is valued at weighted average cost and is expensed or capitalized when used for repairs/maintenance or capital projects, respectively. Fuel stock and natural gas in storage are reported at the lower of cost (calculated on a weighted average basis) or net realizable value. We expect to recover the value of inventory costs in the normal course of business. See Note 20 for additional information. Nuclear Decommissioning Trust (NDT) Investments and Regulatory Assets or Liability The NRC is responsible for regulating all nuclear power plants in the U.S. This regulatory oversight results in specific accounting considerations for nuclear plant decommissioning. Our NDTs hold funds primarily for the ultimate decommissioning of our nuclear power plants. Each unit has its own NDT and funds from one unit may not be used to fund decommissioning obligations of another unit. Decommissioning costs associated with the Comanche Peak nuclear generation facility in Texas are being recovered from Oncor Electric Delivery Company LLC's (Oncor) customers as a delivery fee surcharge over the life of the plant and deposited by Vistra (and prior to the Effective Date, a subsidiary of TCEH) in the NDT. As a result, the asset retirement obligation and the investments in the decommissioning trust are accounted for as rate regulated operations. Changes in these accounts, including investment income and accretion expense, do not impact net income, but are reported as a change in the corresponding regulatory asset or liability balance that is reflected in the consolidated balance sheets as other noncurrent assets or other noncurrent liabilities and deferred credits. The NDTs associated with our PJM nuclear facilities have been funded with amounts collected from the previous owners and their respective utility customers. Any shortfall of funds necessary for decommissioning the PJM nuclear facilities, determined for each generating station unit, are required to be funded by us. Investments in the PJM NDTs are carried at fair value and gains and losses are recognized as other income or other deductions in the consolidated statements of operations. NDTs are invested in diversified portfolios of securities generally designed to achieve a return sufficient to fund the future decommissioning work. We retain any funds remaining in the trusts of the PJM nuclear facilities after all decommissioning has been completed. Noncontrolling Interest and Redeemable Noncontrolling Interest in Subsidiary A noncontrolling interest in a consolidated subsidiary represents the portion of the equity in a subsidiary not attributable, directly or indirectly, to the Company. Noncontrolling interests are presented as a separate component of equity in the consolidated balance sheets and the presentation of net income is modified to present earnings attributed to controlling and noncontrolling interests. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. See Note 2 for additional information. Redeemable noncontrolling interests are presented as a component of temporary equity in the mezzanine section of the consolidated balance sheet and the presentation of net income is modified to present earnings attributed to the controlling and redeemable noncontrolling interest. In December 2024, we closed on the repurchase of the noncontrolling interest in Vistra Vision and reclassified the remaining future payments attributable to the redeemable noncontrolling interest to a financing obligation. See Note 2 and Note 9 for additional information. Treasury Stock Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock, which is presented in the consolidated balance sheets as a reduction to additional paid-in capital. Treasury stock purchases made by third party brokers on our behalf are recorded on a trade date basis when we are contractually obligated to pay the broker for their repurchase costs. See Note 16 for additional information. Leases At the inception of a contract we determine if it is or contains a lease, which involves the contract conveying the right to control the use of explicitly or implicitly identified property, plant, or equipment for a period of time in exchange for consideration. Right-of-use (ROU) assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized at the commencement date of the underlying lease based on the present value of lease payments over the lease term. We use our secured incremental borrowing rate based on the information available at the lease commencement date to determine the present value of lease payments. Operating leases are included in other noncurrent assets, other current liabilities, and other noncurrrent liabilities and deferred credits on the consolidated balance sheet. Finance leases are included in property, plant, and equipment, other current liabilities and other noncurrent liabilities and deferred credits on the consolidated balance sheet. Lease term includes options to extend or terminate the lease when it is reasonably certain that we will exercise the option. We apply the practical expedient permitted by ASC 842, Leases to not separate lease and non-lease components for a majority of our lease asset classes. Leases with an initial lease term of 12 months or less are not recorded on the balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term. Adoption of Accounting Standards in 2024 Improvements to Reportable Segment Disclosures In November 2023, the Financial Accounting Standards Board (FASB) issued ASU No. 2023-07, Segment Reporting (Topic 280), Improvements to Reportable Segment Disclosures , to improve the disclosures about reportable segments and add more detailed information about a reportable segment's expenses. The amendments in the ASU require public entities to disclose on an annual and interim basis significant segment expenses that are regularly provided to the chief operating decision maker (CODM) and included within each reported measure of segment profit or loss, other segment items by reportable segment, the title and position of the CODM, and an explanation of how the CODM uses the reported measures of segment profit or loss in assessing segment performance and deciding how to allocate resources. The ASU does not change the definition of a segment, the method for determining segments, the criteria for aggregating operating segments into reportable segments, or the current specifically enumerated segment expenses that are required to be disclosed. The Company adopted the amendments in this ASU for its fiscal year ended December 31, 2024 which resulted in disclosure of significant segment expenses such as segment fuel, purchased power costs, and delivery fees, operating costs, and selling, general, and administrative expenses. The amendment was applied retrospectively to all prior periods presented. See Note 19 for additional information. Recent Accounting Pronouncements Improvements to Income Tax Disclosures In December 2023, the FASB issued ASU No. 2023-09 (ASU 2023-09), Income Taxes (Topic 740): Improvements to Income Tax Disclosures to enhance the transparency and decision usefulness of income tax disclosures. ASU 2023-09 is effective for annual periods beginning after December 15, 2024 on a prospective basis. Early adoption is permitted. As the amendments apply to income tax disclosures only, the Company does not expect adoption to have a material impact on the consolidated financial statements. Expense Disaggregation Disclosures In November 2024, the FASB issued ASU No. 2024-03 (ASU 2024-03), Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses to improve disclosures by providing additional information about certain expenses in the notes to financial statements in interim and annual reporting periods. Among other provisions, the new standard requires disclosure of disaggregated amounts for expenses such as employee compensation, depreciation, and intangible asset amortization included in each expense caption presented on the face of the income statement. ASU 2024-03 is effective for annual periods beginning after December 15, 2026 and interim periods within annual reporting periods beginning after December 15, 2027 and can be applied prospectively or retrospectively. Early adoption is permitted. We are currently evaluating the impact this ASU will have on the consolidated financial statements and related disclosures. Recent Developments In January, a fire occurred at our Moss Landing 300 MW battery energy storage facility in the West segment. We are still investigating the cause of the fire and impacts, including insurance claim recoveries, but expect to write off approximately $400 million of plant value to depreciation expense in the first quarter of 2025, representing the remaining net book value of the facility. Moss Landing 300 is part of the Moss Landing complex, which includes two other battery facilities and a gas plant, with an aggregate book value of approximately $1 billion. While the gas plant is operational, the other two battery facilities remain offline as we investigate the fire. We will continue to assess if a triggering event has occurred to evaluate impairment for the other complex assets.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2024
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 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 consolidated balance sheets as of the Merger Date. On the Merger Date, we reclassified the carrying value of assets contributed to Vistra Vision of $749 million from additional paid-in-capital of Vistra (the controlling interest) to the noncontrolling interest in subsidiary. Provisional fair value measurements were made for acquired assets and liabilities in the first quarter of 2024 and adjustments to those measurements were made in the second, third and fourth quarters of 2024. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. The provisional fair values assigned to assets acquired and liabilities assumed are as follows: Fair Value as of March 1, 2024 Measurement Period Adjustments recorded through December 31, 2024 (in millions) Cash and cash equivalents $ 35 $ 5 Trade accounts receivables, inventories, prepaid expenses, and other current assets 544 6 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 61 53 Total identifiable assets acquired 8,850 65 Trade accounts payable and other current liabilities 320 57 Long-term debt, including amounts due currently 413 — Commodity and other derivative contractual liabilities (d) 179 — Accumulated deferred income taxes 1,314 (50) Asset retirement obligations (e) 1,368 — Identifiable intangible liabilities 55 (18) Other noncurrent liabilities and deferred credits 18 6 Total identifiable liabilities assumed 3,667 (5) Identifiable net assets acquired 5,183 70 Goodwill (f) 224 (70) Net assets acquired $ 5,407 ____________ (a) Investments represent securities held in nuclear decommissioning trusts (NDT) for the purpose of funding the future retirement and decommissioning of the PJM nuclear generation facilities. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC. They are valued using a market approach (Level 1 or Level 2 depending on security). (b) Acquired property, plant, and equipment are valued using a combination of an income approach and a market approach. The income approach utilized a discounted cash flow analysis based upon a debt-free, free cash flow model (Level 3). (c) Includes acquired nuclear fuel supply contracts valued based on contractual cash flow projections over approximately five years compared with cash flows based on current market prices with the resulting difference discounted to present value (Level 3). Also includes acquired retail customer relationships which are valued based on discounted cash flow analysis of acquired customers and estimated attrition rates (Level 3). (d) Acquired derivatives are valued using the methods described in Note 11 (Level 1, Level 2, or Level 3). Contracts with terms that were not at current market prices are also valued using a discounted cash flow analysis (Level 3). (e) Asset retirement obligations are valued using a discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning methods and are based on decommissioning cost studies (Level 3). (f) The excess of the consideration transferred over the fair value of identifiable assets acquired and liabilities assumed is recorded as goodwill. Goodwill represents expected synergies to be generated from combining operations of Energy Harbor with Vistra. None of the Goodwill is deductible for income tax purposes. The following unaudited pro forma financial information for the years ended December 31, 2024 and 2023 assumes that the Energy Harbor Merger occurred on January 1, 2023. The unaudited pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the Energy Harbor Merger been completed on January 1, 2023, nor is the unaudited pro forma financial information indicative of future results of operations, which may differ materially from the pro forma financial information presented here. Year Ended December 31, 2024 2023 (in millions) Revenues $ 17,948 $ 17,148 Net income $ 2,901 $ 1,398 The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired, interest expense on debt assumed in the Energy Harbor Merger, effects of the Energy Harbor Merger on tax expense (benefit), and other related adjustments. Determining the amounts of revenue and earnings of Energy Harbor since the acquisition date is impractical as operations have been integrated into our commercial platform which is managed at a portfolio level. Acquisition costs incurred in the Energy Harbor Merger totaled $25 million and $24 million for the year ended December 31, 2024 and 2023, respectively, and are classified as selling, general, and administrative expenses in the consolidated statements of operations. Acquisition of Noncontrolling Interest

Revenue

Revenue	12 Months Ended
	Dec. 31, 2024
Revenue from Contract with Customer [Abstract]
Revenue	REVENUE Revenue Disaggregation The following tables disaggregate our revenue by major source: Year Ended December 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 $ 8,064 $ — $ — $ — $ — $ — $ 8,064 Retail energy charge in Northeast/Midwest (a) 3,595 — — — — — 3,595 Wholesale generation revenue from ISO/RTO — 399 1,351 228 — — 1,978 Capacity revenue from ISO/RTO (b) — — 74 — — — 74 Revenue from other wholesale contracts — 422 398 230 — — 1,050 Total revenue from contracts with customers 11,659 821 1,823 458 — — 14,761 Other revenues: Transferable PTC revenues (c) — 292 264 — — — 556 Hedging revenues — realized 1,241 (453) 31 84 (8) — 895 Hedging revenue — unrealized (168) 700 143 329 9 — 1,013 Intangible amortization and other revenues 1 — (4) — — 2 (1) Intersegment sales (d) 64 4,034 3,404 6 — (7,508) — Total other revenues 1,138 4,573 3,838 419 1 (7,506) 2,463 Total revenues $ 12,797 $ 5,394 $ 5,661 $ 877 $ 1 $ (7,506) $ 17,224 ____________ (a) Includes ten months of revenue associated with operations acquired in the Energy Harbor Merger. (b) Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $126 million of capacity sold offset by $52 million of capacity purchased. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $139 million offset by $116 million of capacity sold within the East segment. (c) Represents transferable PTCs generated from qualifying nuclear and solar assets during the period. (d) East segment includes $195 million of intersegment unrealized net losses, and Texas and West segments include $74 million and $4 million, respectively, of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment. Year Ended December 31, 2023 Retail Texas East West Asset Closure Eliminations / Corporate and Other Consolidated (in millions) Revenue from contracts with customers: Retail energy charge in ERCOT $ 7,674 $ — $ — $ — $ — $ — $ 7,674 Retail energy charge in Northeast/Midwest 1,642 — — — — — 1,642 Wholesale generation revenue from ISO/RTO — 1,190 1,298 421 — — 2,909 Capacity revenue from ISO/RTO (a) — — 98 — — — 98 Revenue from other wholesale contracts — 505 797 179 — — 1,481 Total revenue from contracts with customers 9,316 1,695 2,193 600 — — 13,804 Other revenues: Transferable PTC revenues (b) — 10 — — — — 10 Hedging revenues — realized 1,063 (885) 43 67 (36) — 252 Hedging revenue — unrealized 191 (714) 958 243 36 — 714 Intangible amortization and other revenues 2 — (5) — — 2 (1) Intersegment sales (c) — 3,873 2,701 4 — (6,578) — Total other revenues 1,256 2,284 3,697 314 — (6,576) 975 Total revenues $ 10,572 $ 3,979 $ 5,890 $ 914 $ — $ (6,576) $ 14,779 ____________ (a) Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $233 million of capacity sold offset by $135 million of capacity purchased. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $82 million offset by $73 million of capacity sold within the East segment. (b) Represents transferable PTCs generated from qualifying solar assets during the period. (c) East segment includes $814 million of intersegment unrealized net gains, and Texas and West segments include $48 million and $6 million, respectively, of intersegment unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment. Year Ended December 31, 2022 Retail Texas East West Asset Closure Eliminations / Corporate and Other Consolidated (in millions) Revenue from contracts with customers: Retail energy charge in ERCOT $ 6,971 $ — $ — $ — $ — $ — $ 6,971 Retail energy charge in Northeast/Midwest 2,139 — — — — — 2,139 Wholesale generation revenue from ISO/RTO — 1,277 1,987 467 562 — 4,293 Capacity revenue from ISO/RTO (a) — — 76 — 27 — 103 Revenue from other wholesale contracts — 696 1,256 151 22 — 2,125 Total revenue from contracts with customers 9,110 1,973 3,319 618 611 — 15,631 Other revenues: Hedging revenues — realized 875 (67) (247) 35 (333) 1 264 Hedging revenue — unrealized (532) (637) (770) (326) 102 — (2,163) Intangible amortization and other revenues 2 — (6) — — — (4) Intersegment sales (b) — 2,609 2,133 9 4 (4,755) — Total other revenues 345 1,905 1,110 (282) (227) (4,754) (1,903) Total revenues $ 9,455 $ 3,878 $ 4,429 $ 336 $ 384 $ (4,754) $ 13,728 ____________ (a) Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $361 million of capacity sold offset by $285 million of capacity purchased. The Asset Closure segment includes $27 million of capacity sold. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $212 million offset by $167 million of capacity sold within the East segment. (b) Texas and East segments include $780 million and $45 million, respectively, of intersegment unrealized net losses and West and Asset Closure segments include $2 million and $4 million respectively, of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment. Retail Energy Charges Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes delivered or services provided. Sales tax is excluded from revenue. Payment terms vary from 15 to 60 days from invoice date. Revenue is recognized over-time using the output method based on kilowatt hours delivered. Energy charges are delivered as a series of distinct services and are accounted for as a single performance obligation. Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Estimated amounts are adjusted when actual usage is known and billed. As contracts for retail electricity can be for multi-year periods, the Company has performance obligations under these contracts that have not yet been satisfied. These performance obligations have transaction prices that are both fixed and variable, and that vary based on the contract duration and customer type. For the fixed price contracts, the amount of any unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and customer activity and therefore it is not practicable to estimate such amounts. Wholesale Generation Revenue from ISOs/RTOs and Revenue from Other Wholesale Contracts Wholesale generation revenue is recognized when volumes are delivered to the ISO/RTO. Other wholesale contracts include other revenue activity with the ISO/RTO, such as ancillary services, auction revenue, neutrality revenue and revenue from nonaffiliated retail electric providers, municipalities or other wholesale counterparties. Wholesale revenues are recognized over time using the output method based on kilowatt hours delivered or other applicable performance measurements and cash is settled shortly after invoicing. Vistra operates as a market participant within ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO and expects to continue to remain under contract with each ISO/RTO indefinitely. Wholesale revenues are delivered as a series of distinct services and are accounted for as a single performance obligation. When electricity is sold to and purchased from the same ISO/RTO in the same period, the excess of the amount sold over the amount purchased is reflected in wholesale generation revenues. Capacity Revenue From ISO/RTO We offer generation capacity into competitive ISO/RTO auctions in exchange for revenue from awarded capacity offers. Capacity ensures installed generation and demand response is available to satisfy system integrity and reliability requirements. Capacity revenues are recognized when the performance obligation is satisfied ratably over time as our power generation facilities stand ready to deliver power to the customer. Penalties are assessed by the ISO/RTO against generation facilities if the facility is not available during the capacity period and are recorded as a reduction to revenue. When capacity is sold to and purchased from the same ISO/RTO in the same period, the excess of the amount sold over the amount purchased is reflected in capacity revenue from ISO/RTO. Other Revenues Other revenues, as included in the tables of disaggregated revenue above, represent amounts not accounted for under ASC 606, Revenue from Contracts with Customers and are comprised of the following: • Transferable production tax credit revenues accounted for as income-related grants by analogy to IAS 20 (see Note 4 for additional information). • Intangible amortization of acquired intangible liabilities related to retail and wholesale contracts (see Note 7 for additional information). • Hedging revenue from electricity and natural gas derivative contracts accounted for under ASC 815, Derivatives and Hedging, including the impact of realized and unrealized gains or losses on those contracts (see Note 11 for additional information). • Intersegment sales are presented by segment and eliminated in consolidation. Contract and Other Customer Acquisition Costs We defer costs to acquire retail contracts and amortize these costs over the expected life of the contract. The expected life of a retail contract is calculated using historical attrition rates, which we believe to be an accurate indicator of future attrition rates. The deferred acquisition and contract cost balance as of December 31, 2024 and 2023 was $114 million and $97 million, respectively. The amortization related to these costs during the years ended December 31, 2024, 2023, and 2022 totaled $97 million, $88 million, and $83 million respectively, recorded as SG&A expenses, and $6 million, $6 million, and $6 million, respectively, recorded as a reduction to operating revenues in the consolidated statements of operations. Practical Expedients The majority of our revenues are recognized under the right to invoice practical expedient, which allows us to recognize revenue in the same amount that we have a right to invoice our customers. Unbilled revenues are recorded based on the volumes delivered and services provided to the customers at the end of the period, using the right to invoice practical expedient. We have elected to not disclose the value of unsatisfied performance obligations for contracts with variable consideration for which we recognize revenue using the right to invoice practical expedient. We use the portfolio approach in evaluating similar customer contracts with similar performance obligations. Sales taxes are not included in revenue. Performance Obligations As of December 31, 2024, we have future fixed fee performance obligations that are unsatisfied, or partially unsatisfied, relating to capacity auction volumes awarded through capacity auctions held by the ISO/RTO or contracts with customers for which the total consideration is fixed and determinable at contract execution. Capacity revenues are recognized as the performance obligations to make capacity available to the related ISOs/RTOs or counterparties are met. 2025 2026 2027 2028 2029 2030 and Thereafter Total (in millions) Remaining performance obligations $ 1,123 $ 825 $ 289 $ 122 $ 62 $ 548 $ 2,969 Trade Accounts Receivable December 31, December 31, (in millions) Wholesale and retail trade accounts receivable $ 2,061 $ 1,735 Allowance for credit losses (79) (61) Trade accounts receivable — net $ 1,982 $ 1,674 Trade accounts receivable from contracts with customers — net $ 1,514 $ 1,239 Other trade accounts receivable — net 468 435 Total trade accounts receivable — net $ 1,982 $ 1,674 Gross trade accounts receivable as of December 31, 2024 and December 31, 2023 include unbilled retail revenues of $802 million and $614 million, respectively. Allowance for Credit Losses on Accounts Receivable Year Ended December 31, 2024 2023 2022 (in millions) Allowance for credit losses on accounts receivable at beginning of period $ 61 $ 65 $ 45 Increase for bad debt expense 183 164 179 Decrease for account write-offs (165) (168) (159) Allowance for credit losses on accounts receivable at end of period $ 79 $ 61 $ 65

Government Assistance

Government Assistance	12 Months Ended
	Dec. 31, 2024
Government Assistance [Abstract]
Government Assistance	GOVERNMENT ASSISTANCE Inflation Reduction Act of 2022 (IRA) In August 2022, the U.S. enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, including recognizing the value of existing carbon-free nuclear power by providing for a nuclear PTC, a solar PTC, and a first-time stand-alone battery storage investment tax credit. The section 45U nuclear PTC provides a federal tax credit of up to $15 per MWh, subject to phase out as power prices increase above $25 per MWh, to existing nuclear facilities from 2024 through 2032 subject to an annual inflation adjustment. The Company accounts for transferable ITCs and PTCs we expect to receive by analogy to the grant model within International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance . Transferable PTCs In the year ended December 31, 2024, we recognized transferable nuclear PTC revenues of $545 million and transferable solar PTC revenues of $11 million. Our nuclear PTC revenues are an estimate based on gross receipts generated from qualifying nuclear production in 2024 and reflect our determination that we will meet the prevailing wage requirements necessary to earn the five times multiplier at all of our nuclear units. Our computation of gross receipts includes settled spot energy revenues and capacity revenues at each nuclear unit, and excludes any hedges. Treasury regulations are expected to further define the scope of the legislation in many important respects over the next year, including interpretive guidance on the definition of gross receipts for the nuclear PTC. Any interpretive guidance on the definition of gross receipts which differs from the interpretation used in our estimate could result in a material change to PTC revenues attributable to 2024 and would be reflected as a change in estimate in the period in which the guidance is received. Transferable ITCs In June 2023, our 350 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase III) in California commenced commercial operations. As a result of Moss Landing Phase III meeting requirements to be placed in service in June 2023, we recognized $154 million of transferable ITCs associated with the project in other noncurrent assets in the consolidated balance sheet. In September 2024, we recognized an additional $2 million of transferable ITCs associated with the project and reclassified the $156 million of credits to other current assets. In December 2024, our Baldwin 68 MW solar / 2 MW battery ESS and Coffeen 44 MW solar / 2 MW battery ESS facilities in Illinois met requirements to be placed in service. As a result, we recognized $57 million and $45 million of transferable ITCs associated with the projects, respectively, in other noncurrent assets in the consolidated balance sheet. Sales of Transferable PTCs and ITCs In October 2024, we sold $156 million of transferable ITCs and $10 million of transferable solar PTCs generated in 2023. Vistra received cash consideration from the sale in October 2024. In January 2025, we sold $200 million of transferable nuclear PTCs we recognized from qualifying 2024 nuclear production. Cash consideration from the sale will be received in installments through July 2025 with an initial payment received in January 2025.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2024
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: Year Ended December 31, 2024 2023 2022 (in millions) Current: U.S. Federal $ 2 $ (1) $ 2 State 46 52 7 Total current 48 51 9 Deferred: U.S. Federal 561 421 (304) State 46 36 (55) Total deferred 607 457 (359) Total $ 655 $ 508 $ (350) Reconciliation of income taxes computed at the U.S. federal statutory rate to income tax expense (benefit) recorded: Year Ended December 31, 2024 2023 2022 (in millions) Income (loss) before income taxes $ 3,467 $ 2,000 $ (1,560) U.S. federal statutory rate 21 % 21 % 21 % Income taxes at the U.S. federal statutory rate 728 420 (328) State tax, net of federal benefit 80 86 (19) Nondeductible TRA accretion 2 41 18 Transferable PTC revenues (115) (2) — Equity awards (53) (3) (3) Valuation allowance (2) (20) (8) Release of Uncertain Tax Positions — (35) — Other 15 21 (10) Income tax expense (benefit) $ 655 $ 508 $ (350) Effective tax rate 18.9 % 25.4 % 22.4 % Deferred Income Tax Balances Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2024 and 2023 are as follows: December 31, 2024 2023 (in millions) Noncurrent Deferred Income Tax Assets Tax credit carryforwards $ 86 $ 84 Loss carryforwards 949 1,081 Identifiable intangible assets 340 380 Long-term debt 225 173 Employee benefit obligations 133 117 Commodity contracts and interest rate swaps 383 664 Other 36 33 Total deferred tax assets $ 2,152 $ 2,532 Noncurrent Deferred Income Tax Liabilities Property, plant, and equipment 2,765 1,264 Total deferred tax liabilities 2,765 1,264 Valuation allowance 75 46 Net Deferred Income Tax Asset (Liability) $ (688) $ 1,222 As of December 31, 2024, we had total net deferred tax liabilities of approximately $688 million that were substantially comprised of book and tax basis differences related to our generation and mining property, plant, and equipment, partially offset by federal and state net operating loss (NOL) carryforwards. Our net deferred tax liabilities were significantly impacted by the Energy Harbor Merger. For the years ended December 31, 2024 and 2023, we recognized tax benefits of $2 million and $20 million primarily related to the release of the federal valuation allowance on charitable contributions and state valuation allowances, respectively. As of December 31, 2024, we assessed the need for a valuation allowance related to our deferred tax asset and considered both positive and negative evidence related to the likelihood of realization of the deferred tax assets. We have identified positive evidence in the form of cumulative income on an unadjusted basis over the preceding 12 quarters. We evaluated historical earnings, performed scheduling of the reversal of temporary differences, and considered other positive and negative evidence. In connection with our analysis, we concluded that it is more likely than not that the federal deferred tax assets will be fully utilized by future taxable income, and thus no valuation allowance was required. A valuation allowance of approximately $30 million was recorded as part of Energy Harbor purchase accounting on state NOL carryforwards. As of December 31, 2024, we had $3.2 billion pre-tax net operating loss (NOL) carryforwards for federal income tax purposes that will begin to expire in 2031. The income tax effects of the components included in accumulated other comprehensive income totaled net deferred tax liabilities of $4 million and zero at December 31, 2024 and 2023, respectively. 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 2024 tax year as it applies only to corporations with a three-year average annual adjusted financial statement income in excess of $1 billion. We have taken the CAMT and relevant extensions or expansions of existing tax credits applicable to projects in our immediate development pipeline into account when forecasting cash taxes. See Notes 1 and 4 for additional information. Final Section 163(j) Regulations The final Section 163(j) regulations, which limits qualified deductions for business interest expense, were issued in July 2020 and provided a critical correction to the proposed regulations regarding the computation of adjusted taxable income. As of January 1, 2022, certain provisions in the final Section 163(j) regulations have sunset, including the add-back of depreciation and amortization to adjusted taxable income. As a result, under the law as currently enacted, Vistra's deductible business interest expense was significantly limited for the 2024 tax year and will continue to be so limited under current law going forward. Vistra remains active in legislative monitoring and advocacy efforts to support a legislative solution to reinstate and make permanent the add-back of depreciation and amortization to adjusted taxable income. Liability for Uncertain Tax Positions Accounting guidance related to uncertain tax positions requires that all tax positions subject to uncertainty be reviewed and assessed with recognition and measurement of the tax benefit based on a "more-likely-than-not" standard with respect to the ultimate outcome, regardless of whether this assessment is favorable or unfavorable. We classify interest and penalties related to uncertain tax positions as current income tax expense. The amounts were immaterial for the years ended December 31, 2024, 2023, and 2022. The following table summarizes the changes to the uncertain tax positions, reported in accumulated deferred income taxes and other current liabilities in the consolidated balance sheets for the years ended December 31, 2024, 2023, and 2022. Year Ended December 31, 2024 2023 2022 (in millions) Balance at beginning of period, excluding interest and penalties $ — $ 36 $ 38 Additions based on tax positions related to prior years 4 — — Reductions based on tax positions related to prior years — — (1) Reductions related to the lapse of the tax statute of limitations — (35) — Settlements with taxing authorities — (1) (1) Balance at end of period, excluding interest and penalties $ 4 $ — $ 36 Vistra and its subsidiaries file income tax returns in U.S. federal, state and foreign jurisdictions and are, at times, subject to examinations by the IRS and other taxing authorities. In February 2021, Vistra was notified that the IRS had opened a federal income tax audit for tax years 2018 and 2019. The federal income tax audit was closed in June 2023 with immaterial changes. Uncertain tax positions totaled $4 million and zero as of December 31, 2024 and 2023, respectively. Of the amounts recorded as unrecognized tax benefits, an insignificant portion would impact our effective tax rate if recognized. Tax Matters Agreement On the Effective Date, we entered into the Tax Matters Agreement with EFH Corp. whereby the parties have agreed to take certain actions and refrain from taking certain actions in order to preserve the intended tax treatment of the Spin-Off and to indemnify the other parties to the extent a breach of such agreement results in additional taxes to the other parties. Among other things, the Tax Matters Agreement allocates the responsibility for taxes for periods prior to the Spin-Off between EFH Corp. and us. For periods prior to the Spin-Off: (a) Vistra is generally required to reimburse EFH Corp. with respect to any taxes paid by EFH Corp. that are attributable to us and (b) EFH Corp. is generally required to reimburse us with respect to any taxes paid by us that are attributable to EFH Corp. We are also required to indemnify EFH Corp. against taxes, under certain circumstance, if the IRS or another taxing authority successfully challenges the amount of gain relating to the PrefCo Preferred Stock Sale or the amount or allowance of EFH Corp.'s net operating loss deductions. Subject to certain exceptions, the Tax Matters Agreement prohibits us from taking certain actions that could reasonably be expected to undermine the intended tax treatment of the Spin-Off or to jeopardize the conclusions of the private letter ruling we obtained from the IRS or opinions of counsel received by us or EFH Corp., in each case, in connection with the Spin-Off. Certain of these restrictions apply for two years after the Spin-Off. Under the Tax Matters Agreement, we may engage in an otherwise restricted action if (a) we obtain written consent from EFH Corp., (b) such action or transaction is described in or otherwise consistent with the facts in the private letter ruling we obtained from the IRS in connection with the Spin-Off, (c) we obtain a supplemental private letter ruling from the IRS, or (d) we obtain an unqualified opinion of a nationally recognized law or accounting firm that is reasonably acceptable to EFH Corp. that the action will not affect the intended tax treatment of the Spin-Off.

Property, Plant, and Equipment

Property, Plant, and Equipment	12 Months Ended
	Dec. 31, 2024
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 system hardware, capitalized corporate office lease space and other leasehold improvements. The estimated remaining useful lives of our property, plant, and equipment ranges from 1 to 29 years. Land is not depreciated. December 31, 2024 2023 (in millions) Power generation and structures $ 22,783 $ 17,297 Land 603 572 Office and other equipment 160 159 Total 23,546 18,028 Less accumulated depreciation (8,020) (6,657) Net of accumulated depreciation 15,526 11,371 Finance lease right-of-use assets (net of accumulated amortization) 153 160 Nuclear fuel (net of accumulated amortization of $409 million and $120 million) 1,434 379 Construction work in progress 1,060 522 Property, plant, and equipment — net $ 18,173 $ 12,432 Depreciation expenses totaled $1.670 billion, $1.344 billion, and $1.388 billion for the years ended December 31, 2024, 2023, and 2022, respectively. Retirement of Generation Facilities The following are all of our facilities that have either been retired, or that have announced retirement dates. Operation results for plants with defined retirement dates are included in our Asset Closure segment at the beginning of the calendar year the retirement is expected to occur. Facility Location ISO/RTO Fuel Type Net Generation Capacity (MW) Announced Retirement Date (a) Segment Baldwin Baldwin, IL MISO Coal 1,185 By the end of 2027 East Coleto Creek Goliad, TX ERCOT Coal 650 By the end of 2027 (b) 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 Joppa Joppa, IL MISO Coal 802 Retired September 1, 2022 Asset Closure Joppa Joppa, IL MISO Natural Gas 221 Retired September 1, 2022 Asset Closure Zimmer Moscow, OH PJM Coal 1,300 Retired June 1, 2022 Asset Closure Total 7,486 ____________ (a) Generation facilities may retire earlier than expected dates disclosed if economic or other conditions dictate. (b) Following the retirement of Coleto Creek as a coal-fueled plant, the Company intends to repower it as a gas-fueled plant. Impairment of Long-Lived Assets In the first quarter of 2023, we recognized an impairment loss of $49 million related to our Kincaid generation facility in Illinois as a result of a significant decrease in the projected operating margins of the facility, primarily driven by a decrease in projected power prices. The impairment is reported in our East segment and includes write-downs of property, plant, and equipment of $45 million, write-downs of inventory of $2 million, and write-downs of operating lease right-of-use assets of $2 million. In the fourth quarter of 2022, we recognized an impairment loss of $74 million related to our Miami Fort generation facility in Ohio as a result of a significant decrease in the projected operating margins of the facility, reflecting an increase in projected coal costs along with a decrease in projected power prices. The impairment is reported in our East segment and includes write-downs of property, plant, and equipment of $71 million and write-downs of inventory of $3 million. In determining the fair value of the impaired asset groups in 2023 and 2022, we utilized the income approach described in ASC 820, Fair Value Measurement .

Goodwill and Identifiable Intan

Goodwill and Identifiable Intangible Assets and Liabilities	12 Months Ended
	Dec. 31, 2024
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Identifiable Intangible Assets and Liabilities	GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES Goodwill As of December 31, 2024 and 2023, the carrying value of goodwill totaled $2.807 billion and $2.583 billion, respectively. Retail Segment Texas Segment Retail Reporting Unit (a) Texas Generation Reporting Unit Total Goodwill (in millions) Balance at December 31, 2023 $ 2,461 $ 122 $ 2,583 Goodwill recorded in connection with the Energy Harbor Merger (b) 224 Balance at December 31 2024 $ 2,461 $ 122 $ 2,807 ____________ (a) Goodwill of $1.944 billion is deductible for tax purposes over 15 years on a straight-line basis. (b) Allocation of goodwill attributable to the Energy Harbor acquisition to reporting units is pending completion of purchase accounting measurement period. Goodwill is required to be evaluated for impairment at least annually or whenever events or changes in circumstances indicate an impairment may exist. We have selected October 1 as our annual goodwill test date. On the most recent goodwill testing date, we applied qualitative factors and determined that it was more likely than not that the fair value of our Retail and Texas Generation reporting units exceeded their carrying value at October 1, 2024. Significant qualitative factors evaluated included reporting unit financial performance and market multiples, general macroeconomic, industry, and market conditions, cost factors, customer attrition, interest rates, market capitalization, and changes in reporting unit book value. Identifiable Intangible Assets and Liabilities Identifiable intangible assets are comprised of the following: December 31, 2024 December 31, 2023 Identifiable Intangible Asset Gross Accumulated Net Gross Accumulated Net (in millions) Retail customer relationship $ 2,173 $ 1,977 $ 196 $ 2,088 $ 1,866 $ 222 Software and other technology-related assets 601 293 308 536 315 221 Retail and wholesale contracts 503 353 150 233 217 16 Long-term service agreements 18 5 13 18 5 13 Other identifiable intangible assets (a) 218 13 205 62 11 51 Total identifiable intangible assets subject to amortization $ 3,513 $ 2,641 872 $ 2,937 $ 2,414 523 Retail trade names (not subject to amortization) 1,341 1,341 Total identifiable intangible assets $ 2,213 $ 1,864 ____________ (a) Includes mining development costs and environmental allowances (emissions allowances and renewable energy certificates). Identifiable intangible liabilities are comprised of the following: Year Ended December 31, Identifiable Intangible Liability 2024 2023 (in millions) Long-term service agreements $ 108 $ 122 Wholesale power and fuel purchase contracts 47 9 Total identifiable intangible liabilities $ 155 $ 131 Amortization of finite-lived identifiable intangible assets and liabilities (including the classification in the consolidated statements of operations) consisted of: Identifiable Intangible Assets/Liabilities Consolidated Statements of Operations Remaining useful lives of identifiable intangible assets at December 31, Year Ended December 31, 2024 2023 2022 (in millions) Retail customer relationship Depreciation and amortization 2 $ 111 $ 98 $ 137 Software and other technology-related assets Depreciation and amortization 3 60 58 69 Retail and wholesale contracts Operating revenues/Fuel, purchased power costs, and delivery fees 3 (12) 8 7 Other identifiable intangible assets Fuel, purchased power costs, and delivery fees/Depreciation and amortization 4 414 357 391 Total intangible asset expense, net $ 573 $ 521 $ 604 Amounts recorded in depreciation and amortization totaled $173 million, $158 million, and $208 million for the years ended December 31, 2024, 2023, and 2022, respectively. Amounts include all expenses associated with environmental allowances including expenses accrued to comply with emissions allowance programs and renewable portfolio standards which are presented in fuel, purchased power costs, and delivery fees in the consolidated statements of operations. Emissions allowance obligations are accrued as associated electricity is generated and renewable energy certificate obligations are accrued as retail electricity delivery occurs. The following is a description of the separately identifiable intangible assets recorded in fresh start reporting and in connection with purchase accounting from acquisitions. • Retail customer relationship — Retail customer relationship intangible asset represents the fair value of our non-contracted retail customer base, including residential and business customers, and is amortized using an accelerated method based on historical customer attrition rates and reflecting the expected pattern in which economic benefits are realized over their estimated useful life. • Retail and wholesale contracts — These intangible assets and liabilities represent the value of various acquired retail and wholesale contracts and fuel and transportation purchase contracts. The contracts were identified as either assets or liabilities based on the respective fair values utilizing prevailing market prices for commodities or services compared to the fixed prices contained in these agreements. The intangible assets or liabilities are amortized in relation to the economic terms of the related contracts. • LTSA — Our acquired LTSA intangibles represent the estimated fair value of favorable or unfavorable contract obligations with respect to long-term plant maintenance agreements and are amortized based on the expected usage of the service agreements over the contract terms. The majority of the plant maintenance services relate to capital improvements and the related amortization of the plant maintenance agreements is recorded to property, plant, and equipment. • Retail trade names — Our retail trade name intangible assets represent the fair value of our retail brands, including the trade names of TXU Energy TM , Ambit Energy, 4Change Energy TM , Homefield Energy, Dynegy Energy Services, TriEagle Energy, Public Power, and U.S. Gas & Electric, and were determined to be indefinite-lived assets not subject to amortization. These intangible assets are evaluated for impairment at least annually in accordance with accounting guidance related to other indefinite-lived intangible assets. We have selected October 1 as our test date. Significant qualitative factors evaluated included trade name financial performance, general macroeconomic, industry, and market conditions, customer attrition and interest rates. On the most recent testing date, we determined that it was more likely than not that the fair value of our retail trade name intangible asset exceeded its carrying value at October 1, 2024. Estimated Amortization of Identifiable Intangible Assets As of December 31, 2024, the estimated aggregate amortization expense of identifiable intangible assets, excluding environmental allowances, for each of the next five fiscal years is as shown below. Year Estimated Amortization Expense (in millions) 2025 $ 231 2026 $ 167 2027 $ 72 2028 $ 51 2029 $ 34

Collateral Financing Agreement

Collateral Financing Agreement With Affiliate	12 Months Ended
	Dec. 31, 2024
Debt Disclosure [Abstract]
Collateral Financing Agreement With Affiliate	COLLATERAL FINANCING AGREEMENT WITH AFFILIATE On June 15, 2023, Vistra Operations entered into a facility agreement (Facility Agreement) with a Delaware trust formed by the Company (the Trust) that sold 450,000 pre-capitalized trust securities (P-Caps) redeemable May 17, 2028 for an initial purchase price of $450 million. The Trust is not consolidated by Vistra. The Trust invested the proceeds from the sale of the P-Caps in a portfolio of either (a) U.S. Treasury securities (Treasuries) or (b) Treasuries and/or principal and interest strips of Treasuries (Treasury Strips, and together with the Treasuries and cash denominated in U.S. dollars, the Eligible Assets). At the direction of Vistra Operations, the Eligible Assets held by the Trust can be (i) delivered to one or more designated subsidiaries of Vistra Operations in order to allow such subsidiaries to use the Eligible Assets to meet certain posting obligations with counterparties, and/or (ii) pledged as collateral support for a letter of credit program. Under the Facility Agreement, Vistra Operations has the right (Issuance Right), from time to time, to require the Trust to purchase from Vistra Operations up to $450 million aggregate principal amount of Vistra Operations' 7.233% Senior Secured Notes due 2028 (7.233% Senior Secured Notes) in exchange for the delivery of all or a portion of the Treasuries and Treasury Strips corresponding to the portion of the issuance right exercised at such time. The Trust will terminate at any time prior to May 17, 2028 and distribute the 7.233% Senior Secured Notes to the holders of the P-Caps if its sole assets consist of 7.233% Senior Secured Notes that Vistra Operations is no longer entitled to repurchase. Vistra Operations pays a facility fee (Facility Fee) to the Trust payable on each May 17 and November 17, commencing on November 17, 2023, to and including May 17, 2028 (each, a Distribution Date), and on certain other dates as provided in the Facility Agreement. The Facility Fee is generally calculated at a rate of 3.3608% per annum, applied to the maximum amount of 7.233% Senior Secured Notes that Vistra Operations could issue and sell to the Trust under the Facility Agreement as of the close of business on the business day immediately preceding the applicable Distribution Date. As of December 31, 2024 and 2023, the fair value of Eligible Assets held by counterparties to satisfy current and future margin deposit requirements totaled $435 million and $439 million, respectively, and is reported in the consolidated balance sheets as margin deposits posted under affiliate financing agreement and margin deposits financing with affiliate.

Debt, Credit Facilities, and Fi

Debt, Credit Facilities, and Financings	12 Months Ended
	Dec. 31, 2024
Debt Disclosure [Abstract]
Debt, Credit Facilities, and Financings	DEBT, CREDIT FACILITIES, AND FINANCINGS Amounts in the table below represent the categories of debt obligations incurred by the Company. December 31, 2024 2023 (in millions) Long-term debt, including amounts due currently: Project-level debt $ 1,064 $ — Vistra Operations debt 15,405 14,517 Long-term debt before unamortized premiums, discounts, and issuance costs 16,469 14,517 Unamortized premiums, discounts, and issuance costs (171) (115) Long-term debt including debt due currently $ 16,298 $ 14,402 Accounts receivable financing $ 750 $ — Forward repurchase obligation $ 1,335 $ — Long-Term Debt Amounts in the table below represent the categories of long-term debt obligations, including amounts due currently, incurred by the Company. December 31, 2024 2023 (in millions) Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030 $ 2,475 $ 2,500 BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026 367 — Vistra Zero Credit Facility, Term Loan B Facility due April 30, 2031 697 — Vistra Operations Senior Secured Notes: 4.875% Senior Secured Notes, due May 13, 2024 — 400 3.550% Senior Secured Notes, due July 15, 2024 — 1,500 5.125% Senior Secured Notes, due May 13, 2025 744 1,100 5.050% Senior Secured Notes, due December 30, 2026 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 — 5.700% Senior Secured Notes, due December 30, 2034 750 — Total Vistra Operations Senior Secured Notes 5,144 5,650 Energy Harbor Revenue Bonds: 3.375% Revenue Bond, due August 1, 2029 100 — 4.750% Revenue Bond, due June 1, 2033 and July 1, 2033 285 — 3.750% Revenue Bond, due October 1, 2047 46 — Total Energy Harbor Revenue Bonds 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 — Total Vistra Operations Senior Unsecured Notes 7,300 6,300 Other: Equipment Financing Agreements 55 67 Total other long-term debt 55 67 Unamortized debt premiums, discounts, and issuance costs (171) (115) Total long-term debt including amounts due currently 16,298 14,402 Less amounts due currently (880) (2,286) Total long-term debt less amounts due currently $ 15,418 $ 12,116 Long-Term Debt Maturities Long-term debt maturities at December 31, 2024 are as follows: December 31, 2024 (in millions) 2025 $ 885 2026 1,792 2027 3,427 2028 27 2029 2,177 Thereafter 8,161 Unamortized premiums, discounts, and debt issuance costs (171) Total long-term debt, including amounts due currently $ 16,298 Credit Facilities Our credit facilities and related available capacity at December 31, 2024 are presented below. December 31, 2024 Credit Facilities Maturity Date Facility Cash Borrowings (Long-Term Debt, Including Amounts Due Currently) Letters of Credit Outstanding Available (in millions) Vistra Operations debt: Revolving Credit Facility October 11, 2029 $ 3,440 $ — $ 1,278 $ 2,162 Term Loan B-3 Facility December 20, 2030 2,475 2,475 — — Total Vistra Operations Credit Facilities $ 5,915 $ 2,475 $ 1,278 $ 2,162 Vistra Operations Commodity-Linked Facility October 1, 2025 1,750 — — 771 Total Vistra Operations debt $ 7,665 $ 2,475 $ 1,278 $ 2,933 Project-level debt: Tax Credit Bridge Loan November 1, 2025 106 106 — — Tax Credit Bridge Loan December 3, 2026 261 261 — — BCOP Credit Facility 367 367 — — Vistra Zero Term Loan B Facility (a) April 30, 2031 697 697 — — Total project-level debt $ 1,064 $ 1,064 $ — $ — Total credit facilities $ 8,729 $ 3,539 $ 1,278 $ 2,933 ____________ (a) Vistra Zero Operations' obligations under the Vistra Zero Credit Agreement are guaranteed by subsidiaries of Vistra Zero Operations, but are otherwise non-recourse to Vistra Operations and its other subsidiaries. Vistra Operations Credit Facilities Vistra maintains credit facilities with certain financial institutions and, as of December 31, 2024, has aggregate commitments of up to $5.915 billion in senior secured, first-lien revolving credit commitments and outstanding term loans (Vistra Operations Credit Facilities). The Vistra Operations Credit Facilities consist of (i) revolving credit commitments of up to $3.440 billion, including aggregate revolving letter of credit commitments of up to $3.440 billion (Revolving Credit Facility), and (ii) term loans of $2.475 billion (Term Loan B-3 Facility). These amounts reflect the following transactions and amendments completed in 2024: Amendment Date Key Changes December 2024 Lowered fixed spread on Term Loan B-3 Facility borrowings from 2.00% to 1.75% October 2024 Increased Revolving Credit Facility commitments from $3.175 billion to $3.440 billion Extended the maturity date of the Revolving Credit Facility to October 11, 2029 Revolving Credit Facility — The Revolving Credit Facility is used for general corporate purposes. Under the Vistra Operations Credit Agreement, the interest on borrowings under the Revolving Credit Facility is paid based on (i) the forward-looking term rate based on SOFR (Term SOFR) plus a spread that will range from 1.25% to 2.00% and (ii) the fee on any undrawn amounts with respect to the Revolving Credit Facility ranges from 17.5 basis points to 35.0 basis points. Interest periods for Term SOFR borrowings are for a one-, three-, or six-month periods with interest paid in arrears. Letters of credit issued under the Revolving Credit Facility bear interest that ranges from 1.25% to 2.00% and are paid quarterly in arrears. Interest and fees on the Revolving Credit Facility are based on ratings of Vistra Operations' senior secured long-term debt securities. As of December 31, 2024, after taking into account sustainability pricing adjustments based on certain sustainability-linked targets and thresholds, the applicable interest rate margins for the Revolving Credit Facility and the fee for undrawn amounts relating to such commitments were 1.725% and 27.0 basis points, respectively, and the applicable interest rate margin for the letters of credit issued under the Revolving Credit Facility was 1.725%. Term Loan B-3 Facility — The Term Loan B-3 Facility is used for general corporate purposes and bears interest based on the applicable Term SOFR, plus a fixed spread of 2.00% through December 9, 2024 and 1.75% thereafter, and the weighted average interest rates before taking into consideration interest rate swaps (see Note 11) on outstanding borrowings of $2.475 billion was 6.11% as of December 31, 2024. Interest periods for Term SOFR loans are for a one-, three-, or six-month periods with interest paid in arrears. Cash borrowings under the Term Loan B-3 Facility are subject to required scheduled quarterly payments of $6.25 million. Amounts paid cannot be reborrowed. 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 December 31, 2024, Vistra Operations can distribute approximately $8.2 billion to Parent under the Vistra Operations Credit Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Parent of approximately $1.705 billion, $1.625 billion, and $1.775 billion during the years ended December 31, 2024, 2023, and 2022, respectively. Additionally, Vistra Operations may make distributions to Parent in amounts sufficient for Parent to pay any taxes or general operating or corporate overhead expenses arising out of Parent's ownership or operation of Vistra Operations. As of December 31, 2024, all of the restricted net assets of Vistra Operations may be distributed to Parent. Vistra Operations Commodity-Linked Revolving Credit Facility As of December 31, 2024, Vistra Operations senior secured commodity-linked revolving credit facility (Commodity-Linked Facility) totaled $1.75 billion of aggregate available commitments. We have the flexibility, subject to our ability to obtain additional commitments, to further increase the size of the Commodity-Linked Facility to $3.0 billion. As of December 31, 2024, the borrowing base of $771 million is lower than the facility limit which represents the aggregate commitments of $1.75 billion. These amounts reflect the following amendment completed in 2024: Amendment Date Key Changes October 2024 Increased the aggregate available commitments to $1.75 billion Extended the maturity date to October 1, 2025 Under the Commodity-Linked Facility, the borrowing base is calculated on a weekly basis based on a set of theoretical transactions which approximate a portion of the hedge portfolio of Vistra Operations and certain of its subsidiaries in certain power markets, with availability thereunder not to exceed the aggregate available commitments nor be less than zero. 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 (i) based on either the Term SOFR or a daily simple SOFR rate, (ii) a spread that ranges from 1.25% to 2.00%, and (iii) sustainability pricing adjustments based on certain sustainability-linked targets and thresholds. Interest periods for Term SOFR borrowings are for a one-, three-, or six-month periods with interest paid in arrears. The interest period for a daily simple SOFR is for a one-week period with interest paid in arrears. The fee on any undrawn amounts with respect to the Commodity-Linked Facility ranges from 17.5 basis points to 35.0 basis points. As of December 31, 2024, the applicable interest rate margins for borrowings outstanding under the Commodity-Linked Facility was 1.725% and the fee on any undrawn amounts with respect to the Commodity-Linked Facility was 27.0 basis points. Interest and fees on the Commodity-Linked Facility are based on ratings of Vistra Operations' senior secured long-term debt securities. BCOP Project-level Credit Facilities In December 2024, BCOP and its subsidiaries entered into the BCOP Credit Agreement to fund the development of the Baldwin and Coffeen solar generation and battery ESS facilities and the Oak Hill and Pulaski solar generation facilities in Illinois and Texas. The BCOP Credit Agreement provides for (i) tax credit bridge loans of $367 million for the Oak Hill and Pulaski projects (Tax Credit Bridge Loans) and (ii) construction/term loan commitments of $528 million and debt service reserve letter of credit facility commitments of $29 million for all four facilities. At December 31, 2024, the Tax Credit Bridge Loans for Oak Hill and Pulaski totaled $106 million and $261 million, respectively, and mature in November 2025 and December 2026, respectively, subject to the terms of the BCOP Credit Agreement. The weighted average interest rate on outstanding borrowings was 5.984% at December 31, 2024. Repayment of the Tax Credit Bridge Loans are guaranteed by Vistra as the beneficiary of the underlying investment tax credits to be generated by the projects. At December 31, 2024, there were no construction/term loan borrowings outstanding or debt service reserve letters of credit issued. Interest is paid on the Tax Credit Bridge Loan in arrears based on the applicable Term SOFR rate elected in the borrowing notice plus a fixed spread of 1.625% per annum. Interest on the construction/term loans will be paid in arrears based on the applicable Term SOFR rate elected in the borrowing notice plus fixed spreads of 1.875% per annum for construction loans and 2.000% per annum for term loans. Fees on the debt service reserve letter of credit loans will be paid in arrears at 2.000% per annum. Commitment fees on the undrawn loan commitments and unissued letter of credit commitments will pay quarterly in arrears at a fixed percentage of the loan's fixed spread. Vistra Zero Project-level Credit Agreement In March 2024, Vistra Zero Operations entered into the Vistra Zero Credit Agreement. The Vistra Zero Credit Agreement provides for a senior secured term loan (Term Loan B Facility) of up to $700 million, which Vistra Zero Operations borrowed in its entirety in March 2024. Net proceeds of $690 million were used (i) to pay issuance costs and (ii) for working capital and general corporate purposes. Vistra Zero Operations' obligations under the Vistra Zero Credit Agreement are guaranteed by subsidiaries of Vistra Zero Operations, but are otherwise non-recourse to Vistra Operations and its other subsidiaries. These amounts reflect the following amendment completed in 2024: Amendment Date Key Changes December 2024 Lowered the fixed spread interest applicable to the Term Loan B Facility from 2.75% to 2.00% Removed required scheduled quarterly payment requirements Interest on the Term Loan B Facility is based on Term SOFR plus 2.75% per year through December 16, 2024. The December 2024 amendment lowered the fixed spread on this instrument to 2.00% thereafter. Interest periods for Term SOFR loans are for a one-, three-, or six-month periods with interest paid in arrears. The weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings of $697 million was 6.36% as of December 31, 2024. The Vistra Zero Credit Agreement contains customary covenants and warranties which are generally consistent in scope with the Vistra Operations Credit Agreement, except that there is no financial maintenance covenant in the Vistra Zero Credit Agreement. Letter of Credit Facilities Vistra Operations Secured Letter of Credit Facilities Between August 2020 and July 2024, we entered into uncommitted standby letter of credit facilities with various banks (each, a Secured LOC Facility and collectively, the Secured LOC Facilities). The Secured LOC Facilities are secured by a first lien on substantially all of Vistra Operations' (and certain of its subsidiaries') assets (which ranks pari passu with the Vistra Operations Credit Facilities). The Secured LOC Facilities may be renewed annually and are used for general corporate purposes. As of December 31, 2024, $1.157 billion of letters of credit were outstanding under the Secured LOC Facilities. Vistra Operations Unsecured Alternative Letter of Credit Facilities In March 2024, we entered into unsecured alternative letter of credit facilities (Alternative LOC Facilities) to be used for general corporate purposes. In May 2024, the Alternative LOC Facilities were amended to increase the commitment cap to a total of $500 million. As of December 31, 2024, the total capacity was $500 million and $500 million of letters of credit were outstanding under the Alternative LOC Facilities. The commitments under the Alternative LOC Facilities terminate in December 2028. There are no financial maintenance covenants in the Alternative LOC Facilities. Vistra Operations Senior Secured Notes Vistra Operations issues and sells its senior secured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act (collectively, the Senior Secured Notes). The indenture (as may be amended or supplemented from time to time, the Vistra Operations Senior Secured Indenture) governing the Senior Secured Notes provides for the full and unconditional guarantee by certain of Vistra Operations' current and future subsidiaries that also guarantee the Vistra Operations Credit Facilities. The Senior Secured Notes are secured by a first-priority security interest in the same collateral that is pledged for the benefit of the lenders under the Vistra Operations Credit Facilities and contains certain covenants and restrictions consistent with the Vistra Operations Credit Facilities. In December 2024, Vistra Operations issued $1.25 billion aggregate principal amount of senior secured notes, consisting of $500 million aggregate principal amount of 5.050% senior secured notes due 2026 (5.050% Senior Secured Notes) and $750 million aggregate principal amount of 5.700% senior secured notes due 2034 (5.700% Senior Secured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act. Interest is payable in cash semiannually in arrears on June 30 and December 30 beginning June 30, 2025. Net proceeds totaling approximately $1.240 billion, together with cash on hand, will be used for (i) general corporate purposes, including to refinance outstanding indebtedness (including 2025 debt maturities), (ii) to fund the opportunistic early payout of the purchase price installment payments scheduled to be paid in 2025 and 2026 to Avenue for the acquisition of the noncontrolling interest in Vistra Vision and (iii) to pay fees and expenses related to the offering. In May 2024 and July 2024, the 4.875% senior secured notes due May 2024 and 3.550% senior secured notes due July 2024, respectively, were repaid at maturity. In April 2024, Vistra Operations issued $500 million aggregate principal amount of 6.000% senior secured notes due 2034 (6.000% Senior Secured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act. Interest is payable in cash semiannually in arrears on April 15 and October 15 beginning October 15, 2024. Net proceeds totaling approximately $495 million, together with proceeds from the April 2024 issuance of 6.875% Senior Unsecured Notes discussed below and cash on hand, were to be used for general corporate purposes, including to refinance outstanding indebtedness (the senior secured debt maturities in May 2024 and July 2024). Energy Harbor Revenue Bonds Various governmental entities in Ohio and Pennsylvania have issued multiple tranches of revenue bonds for the benefit of Energy Harbor Generation LLC (EHG) or Energy Harbor Nuclear Generation LLC (EHNG); (collectively, the EH entities), in an aggregate principal amount of $431 million. The relevant EH entity is obligated to provide contractual payments to the applicable issuer of the revenue bonds to service the principal and interest on the revenue bonds, the payment of which is indirectly secured by all or substantially all of the assets of the EH entities under various mortgage bonds issued by the EH entities. In the event of a default by the EH entities of their contractual obligation to pay principal and interest in respect of the revenue bonds, the trustee of the revenue bonds would be able to call the mortgage bonds due and, if unpaid, foreclose on the assets securing the mortgage bonds. The obligations of the EH entities in respect of the revenue bonds and related mortgage bonds are guaranteed on an unsecured basis by Energy Harbor and Vistra. Vistra Operations Senior Unsecured Notes Vistra Operations issues and sells its senior unsecured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act (collectively, the Senior Unsecured Notes). The indentures (as may be amended or supplemented from time to time, the Vistra Operations Senior Unsecured Indentures) governing the Senior Unsecured Notes provide for the full and unconditional guarantee by the Guarantor Subsidiaries. The Vistra Operations Senior Unsecured Indentures contain certain covenants and restrictions, including, among others, restrictions on the ability of Vistra Operations and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets. In April 2024, Vistra Operations issued $1.0 billion aggregate principal amount of 6.875% senior unsecured notes due 2032 (6.875% Senior Unsecured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act. Interest is payable in cash semiannually in arrears on April 15 and October 15 beginning October 15, 2024. Net proceeds totaling approximately $990 million, together with proceeds from the April 2024 issuance of 6.000% Senior Secured Notes discussed above and cash on hand, were to be used for general corporate purposes, including to refinance outstanding indebtedness (including the senior secured debt maturities in May 2024 and July 2024). Other Debt Activity Senior Secured Notes Tender Offer In January 2024, Vistra Operations used the net proceeds from (i) the December 2023 issuances of the 6.950% senior secured notes due 2033 and 7.750% senior unsecured notes due 2031 and (ii) cash on hand, to fund a cash tender offer (Senior Secured Notes Tender Offer) to purchase for cash $759 million aggregate principal amount of certain notes, including $58 million of 4.875% senior secured notes due 2024, $345 million of 3.550% senior secured notes due 2024 and $356 million of the 5.125% senior secured notes due 2025. We recorded an extinguishment gain of $6 million on the transaction in the first quarter of 2024. Accounts Receivable Financing Accounts Receivable Securitization Program 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 consolidated balance sheets. Proceeds and repayments under the Receivables Facility are reflected as cash flows from financing activities in the consolidated statements of cash flows. Receivables transferred to the Purchasers remain on Vistra's balance sheet and Vistra reflects a liability equal to the amount advanced by the Purchasers. The Company records interest expense on amounts advanced. TXU Energy continues to service, administer and collect the Receivables on behalf of RecCo and the Purchasers, as applicable. As of December 31, 2024, outstanding borrowings under the Receivables Facility totaled $750 million and were supported by $1.334 billion of RecCo gross receivables. As of December 31, 2023, there were no outstanding borrowings under the Receivables Facility. Repurchase Facility TXU Energy and the other Originators under the Receivables Facility have a repurchase facility (Repurchase Facility) that is provided on an uncommitted basis by a commercial bank as buyer (Buyer). In July 2024, the Repurchase Facility was renewed until July 2025 while maintaining the facility size of $125 million. The Repurchase Facility is collateralized by a subordinated note (Subordinated Note) issued by RecCo in favor of TXU Energy for the benefit of Originators under the Receivables Facility and representing a portion of the outstanding balance of the purchase price paid for the Receivables sold by the Originators to RecCo under the Receivables Facility. Under the Repurchase Facility, TXU Energy may request that Buyer transfer funds to TXU Energy in exchange for a transfer of the Subordinated Note, with a simultaneous agreement by TXU Energy to transfer funds to Buyer at a date certain or on demand in exchange for the return of the Subordinated Note (collectively, the Repo Transaction). Each Repo Transaction is expected to have a term of one month, unless terminated earlier on demand by TXU Energy or terminated by Buyer after an event of default. TXU Energy and the other Originators have each granted Buyer a first-priority security interest in the Subordinated Note to secure its obligations under the agreements governing the Repurchase Facility, and Vistra Operations has agreed to guarantee the obligations under the agreements governing the Repurchase Facility. Unless earlier terminated under the agreements governing the Repurchase Facility, the Repurchase Facility will terminate concurrently with the scheduled termination of the Receivables Facility. There were no outstanding borrowings under the Repurchase Facility as of both December 31, 2024 and December 31, 2023. Forward Repurchase Obligation In accordance with the amended UPAs, on December 31, 2024, Vistra closed the acquisition of the Vistra Vision minority interests from Avenue and Nuveen. Vistra paid Avenue for the purchase of their minority interest in Vistra Vision in full upon closing and paid Nuveen an initial payment at closing, with the remaining payments to Nuveen to be paid in multiple installments through December 31, 2026. Vistra Vision Holdings' remaining future payments to Nuveen are guaranteed by Vistra Operations and certain of its subsidiaries that guarantee Vistra Operations' unsecured notes. Payments remaining due to Nuveen are as follows: December 31, 2024 (in millions) 2025 $ 781 2026 669 Thereafter — Total scheduled payments under the UPAs $ 1,450 A roll-forward of the noncontrolling interest redemption obligation is as follows (in millions): Redeemable noncontrolling interest at September 30, 2024 $ 3,198 Income attributable to redeemable noncontrolling interest (a) 51 Dividends to redeemable noncontrolling interest holders (165) Redeemable noncontrolling interest balance at Closing Date (b) 3,084 Principal payment on Closing Date (1,749) Forward Repurchase Obligation at December 31, 2024 (c) $ 1,335 ____________ (a) Represents accretion attributable to fixed price redemption obligation. (b) Reclassified to a financing obligation. (c) Fair value of the remaining payment obligations to Nuveen discounted at 6%. Interest Expense and Related Charges Year Ended December 31, 2024 2023 2022 (in millions) Interest expense $ 936 $ 654 $ 591 Unrealized mark-to-market net (gains) losses on interest rate swaps (53) 36 (250) Amortization of debt issuance costs, discounts, and premiums 34 26 28 Facility Fee expense 15 8 — Debt extinguishment gain (6) (3) (1) Capitalized interest (77) (37) (29) Other 51 56 29 Total interest expense and related charges $ 900 $ 740 $ 368 The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 11, was 5.23%, 5.69%, and 4.30% as of December 31, 2024, 2023, and 2022, respectively.

Leases

Leases	12 Months Ended
	Dec. 31, 2024
Leases [Abstract]
Leases	LEASES Vistra has both finance and operating leases for real estate, rail cars and equipment. Our leases have remaining lease terms for 1 to 42 years. Our leases include options to renew up to 17 years. Certain leases also contain options to terminate the lease. Lease Cost The following table presents costs related to lease activities: Year Ended December 31, 2024 2023 2022 (in millions) Operating lease cost $ 17 $ 12 $ 9 Finance lease: Finance lease right-of-use asset amortization 8 10 9 Interest on lease liabilities 11 11 12 Total finance lease cost 19 21 21 Variable lease cost (a) 29 37 22 Short-term lease cost 56 44 47 Total lease cost $ 121 $ 114 $ 99 ____________ (a) Represents coal stockpile management services, common area maintenance services, and rail car payments based on the number of rail cars used. Balance Sheet Information The following table presents lease related balance sheet information: December 31, 2024 2023 (in millions) Lease assets: Operating lease right-of-use assets (reported in other noncurrent assets in the consolidated balance sheets) $ 106 $ 50 Finance lease right-of-use assets, net of accumulated amortization (reported in property, plant, and equipment in the consolidated balance sheets) 153 $ 160 Total lease right-of-use assets $ 259 $ 210 Current lease liabilities (reported in other current liabilities in the consolidated balance sheets): Operating lease liabilities $ 13 $ 7 Finance lease liabilities 9 9 Total current lease liabilities 22 16 Noncurrent lease liabilities (reported in other noncurrent liabilities and deferred credits in the consolidated balance sheets): Operating lease liabilities 98 48 Finance lease liabilities 218 227 Total noncurrent lease liabilities 316 275 Total lease liabilities $ 338 $ 291 Supplemental Cash Flow Information The following table presents lease related cash flows and other information: Year Ended December 31, 2024 2023 2022 (in millions) Non-cash disclosure upon commencement of new lease: Right-of-use assets obtained in exchange for new operating lease liabilities 68 3 19 Right-of-use assets obtained in exchange for new finance lease liabilities — — 6 Non-cash disclosure upon modification of existing lease: Modification of operating lease right-of-use assets 1 7 — Modification of finance lease right-of-use assets — (1) 4 Weighted Average Remaining Lease Term The following table presents weighted average remaining lease term information: December 31, 2024 2023 Weighted average remaining lease term: Operating lease 23.8 years 20.1 years Finance lease 23.7 years 24.0 years Weighted average discount rate: Operating lease 7.85% 6.49 % Finance lease 4.82% 4.81 % Maturity of Lease Liabilities The following table presents maturity of lease liabilities: Operating Lease Finance Lease Total Lease (in millions) 2025 $ 19 $ 19 $ 38 2026 13 14 27 2027 14 13 27 2028 10 13 23 2029 8 13 21 Thereafter 222 331 553 Total lease payments 286 403 689 Less: Imputed interest (175) (176) (351) Present value of lease liabilities $ 111 $ 227 $ 338
Leases	LEASES Vistra has both finance and operating leases for real estate, rail cars and equipment. Our leases have remaining lease terms for 1 to 42 years. Our leases include options to renew up to 17 years. Certain leases also contain options to terminate the lease. Lease Cost The following table presents costs related to lease activities: Year Ended December 31, 2024 2023 2022 (in millions) Operating lease cost $ 17 $ 12 $ 9 Finance lease: Finance lease right-of-use asset amortization 8 10 9 Interest on lease liabilities 11 11 12 Total finance lease cost 19 21 21 Variable lease cost (a) 29 37 22 Short-term lease cost 56 44 47 Total lease cost $ 121 $ 114 $ 99 ____________ (a) Represents coal stockpile management services, common area maintenance services, and rail car payments based on the number of rail cars used. Balance Sheet Information The following table presents lease related balance sheet information: December 31, 2024 2023 (in millions) Lease assets: Operating lease right-of-use assets (reported in other noncurrent assets in the consolidated balance sheets) $ 106 $ 50 Finance lease right-of-use assets, net of accumulated amortization (reported in property, plant, and equipment in the consolidated balance sheets) 153 $ 160 Total lease right-of-use assets $ 259 $ 210 Current lease liabilities (reported in other current liabilities in the consolidated balance sheets): Operating lease liabilities $ 13 $ 7 Finance lease liabilities 9 9 Total current lease liabilities 22 16 Noncurrent lease liabilities (reported in other noncurrent liabilities and deferred credits in the consolidated balance sheets): Operating lease liabilities 98 48 Finance lease liabilities 218 227 Total noncurrent lease liabilities 316 275 Total lease liabilities $ 338 $ 291 Supplemental Cash Flow Information The following table presents lease related cash flows and other information: Year Ended December 31, 2024 2023 2022 (in millions) Non-cash disclosure upon commencement of new lease: Right-of-use assets obtained in exchange for new operating lease liabilities 68 3 19 Right-of-use assets obtained in exchange for new finance lease liabilities — — 6 Non-cash disclosure upon modification of existing lease: Modification of operating lease right-of-use assets 1 7 — Modification of finance lease right-of-use assets — (1) 4 Weighted Average Remaining Lease Term The following table presents weighted average remaining lease term information: December 31, 2024 2023 Weighted average remaining lease term: Operating lease 23.8 years 20.1 years Finance lease 23.7 years 24.0 years Weighted average discount rate: Operating lease 7.85% 6.49 % Finance lease 4.82% 4.81 % Maturity of Lease Liabilities The following table presents maturity of lease liabilities: Operating Lease Finance Lease Total Lease (in millions) 2025 $ 19 $ 19 $ 38 2026 13 14 27 2027 14 13 27 2028 10 13 23 2029 8 13 21 Thereafter 222 331 553 Total lease payments 286 403 689 Less: Imputed interest (175) (176) (351) Present value of lease liabilities $ 111 $ 227 $ 338

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2024
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 consolidated statements of operations in operating revenues. We utilize physical natural gas, coal, emissions, and renewable energy certificate derivatives primarily to hedge future purchased power costs of our retail operations or fuel costs of our generation assets. Gains and losses associated with these derivatives are reported in the consolidated statements of operations in fuel, purchased power costs, and delivery fees. Our retail segment procures power from our generation segments to serve future load obligations. In locations and periods where our load service activities do not naturally offset existing generation portfolio risks, remaining commodity price exposure is managed through portfolio hedging activities. Interest Rate Swaps Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate interest rates to fixed rates, thereby hedging future interest costs and related cash flows. Gains and losses associated with these derivatives are reported in the consolidated statements of operations in interest expense and related charges. As of December 31, 2024, Vistra has entered into the following interest rate swaps: Notional Amount Expiration Date Rate Range (c) (in millions, except percentages) Swapped to fixed (a) $3,000 July 2026 4.64 % - 4.72% Swapped to variable (a) $700 July 2026 3.19 % - 3.24% Swapped to fixed (b) $2,300 December 2030 4.95 % - 5.51% ____________ (a) The $700 million of pay variable rate and receive fixed rate swaps match the terms of a portion of the $3.0 billion pay fixed rate and receive variable rate swaps. These matched swaps will settle over time and effectively offset the hedged position. These offsetting swaps expiring in July 2026 hedge our exposure on $2.3 billion of variable rate debt through July 2026. (b) Effective from July 2026 through December 2030. (c) The rate ranges reflect the fixed leg of each swap at a Term SOFR rate plus an interest margin of 1.75 In November 2024, Vistra entered into $675 million notional amount of interest rate swaps effective July 31, 2026 and expiring on December 31, 2030. These swaps, along with $1.625 billion notional amount of interest rate swaps with similar terms entered into in 2023, will hedge our exposure on $2.3 billion of floating rate debt from August 2026 through December 2030. Effect of Derivative Instruments in the Consolidated Balance Sheets We maintain standardized master netting agreements with certain counterparties that allow for the right to offset accounts payable, accounts receivable and cash collateral paid in order to reduce credit exposure. The following tables reconcile our gross derivative assets and liabilities as reported in the consolidated balance sheets to the net value on a contract basis, after taking into consideration netting arrangements with counterparties and cash collateral recorded. December 31, 2024 Derivative Contract Assets Derivative Contract Liabilities Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total (in millions) Current assets $ 2,551 $ 34 $ 2 $ — $ 2,587 Noncurrent assets 677 62 1 — 740 Current liabilities — — (3,333) (18) (3,351) Noncurrent liabilities (2) — (1,356) (9) (1,367) Net assets (liabilities) $ 3,226 $ 96 $ (4,686) $ (27) $ (1,391) Offsetting instruments (a) $ (2,532) $ (28) $ 2,532 $ 28 — Financial collateral (received) pledged (b) $ (50) $ — $ 233 $ — 183 Net amounts $ 644 $ 68 $ (1,921) $ 1 $ (1,208) December 31, 2023 Derivative Contract Assets Derivative Contract Liabilities Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total (in millions) Current assets $ 3,585 $ 53 $ 7 $ — $ 3,645 Noncurrent assets 565 11 1 — 577 Current liabilities (1) — (5,233) (24) (5,258) Noncurrent liabilities (5) — (1,659) (24) (1,688) Net assets (liabilities) $ 4,144 $ 64 $ (6,884) $ (48) $ (2,724) Offsetting instruments (a) $ (3,519) $ (28) $ 3,519 $ 28 — Financial collateral (received) pledged (b) $ (26) $ — $ 970 $ — 944 Net amounts $ 599 $ 36 $ (2,395) $ (20) $ (1,780) ____________ (a) Amounts presented exclude trade accounts receivable and payable related to settled financial instruments. (b) Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin requirements, and, to a lesser extent, initial margin requirements. Effect of Derivative Instruments in the Consolidated Statements of Operations The following table summarizes the location and amount of unrealized gains and losses from our derivative instruments recorded in the consolidated statements of operations for the periods presented. Year Ended December 31, Derivative (consolidated statements of operations presentation) 2024 2023 2022 (in millions) Reversals of previously recognized unrealized (gain) loss on derivative instruments: Commodity contracts unrealized (gain) loss in operating revenues (a) $ 1,140 $ 1,472 $ 1,940 Commodity contracts unrealized (gain) loss in fuel and purchased power expense (a) 73 171 (722) Interest rate swaps unrealized (gain) loss in interest expense and related charges (41) (78) 16 Total reversals of previously recognized unrealized (gain) loss on derivative instruments $ 1,172 $ 1,565 $ 1,234 Unrealized net gains (losses) from changes in fair value on derivative instruments: Commodity contracts unrealized gain (loss) in operating revenues $ (127) $ (758) $ (4,103) Commodity contracts unrealized gain (loss) in fuel and purchased power expense 69 (395) 375 Interest rate swaps unrealized gain (loss) in interest expense and related charges 94 42 234 Total unrealized net gains (losses) from changes in fair value on derivative instruments $ 36 $ (1,111) $ (3,494) Net gain (loss) on derivative instruments $ 1,208 $ 454 $ (2,260) ____________ (a) Excludes the realized effects of changes in fair value in the month the position settled, amounts related to positions entered into and settled in the same month, and physical retail and wholesale contracts accounted for as derivatives which did not financially settle but realized at the contract's notional and price. The realized effects of these items are included in operating revenues and fuel and purchased power expense. Derivative Volumes The following table presents the gross notional amounts of derivative volumes by commodity, excluding our NPNS derivatives that are not recorded at fair value: December 31, 2024 December 31, 2023 Derivative type Notional Volume Unit of Measure Natural gas 4,568 5,335 Million MMBtu Electricity 796,982 800,001 GWh Financial transmission rights / Congestion revenue rights 248,742 250,895 GWh Coal 27 35 Million U.S. tons Fuel oil 2 3 Million gallons Emissions 28 24 Million U.S. tons Renewable energy certificates 31 29 Million certificates Interest rate swaps – variable/fixed $ 5,300 $ 5,225 Million U.S. dollars Interest rate swaps - fixed/variable $ 700 $ 1,300 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: December 31, 2024 2023 (in millions) Fair value of derivative contract liabilities (a) $ (1,587) $ (1,890) Offsetting fair value under netting arrangements (b) 724 692 Cash collateral and letters of credit 471 854 Liquidity exposure $ (392) $ (344) ____________ (a) Excludes fair value of contracts that contain contingent features that do not provide specific amounts to be posted if features are triggered, including provisions that generally provide the right to request additional collateral (material adverse change, performance assurance and other clauses). (b) Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master netting arrangements. Concentrations of Credit Risk Related to Derivatives We have concentrations of credit risk with the counterparties to our derivative contracts. As of December 31, 2024, total credit risk exposure to all counterparties related to derivative contracts totaled $3.772 billion (including associated accounts receivable). The net exposure to those counterparties totaled $776 million as of December 31, 2024 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure from any single counterparty totaling $262 million. As of December 31, 2024, the credit risk exposure to the banking and financial sector represented 75% of the total credit risk exposure and 26% of the net exposure. This concentration of credit risk increases the risk that a default by any of our counterparties could have a material effect on our financial condition, results of operations and liquidity. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize specific risk mitigation procedures including, but not limited to, (i) requiring counterparties to have investment grade credit ratings, (ii) use of standardized master agreements with our counterparties that allow for netting of positive and negative exposures, and (iii) that detail credit enhancements (such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits) are required in the event of a material downgrade in their credit rating.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2024
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: December 31, 2024 December 31, 2023 Level Level Level Reclass (a) Total Level Level Level Reclass (a) Total (in millions) Assets: Commodity contracts (b) $ 1,923 $ 462 $ 841 $ 5 $ 3,231 $ 2,886 $ 628 $ 630 $ 14 $ 4,158 Interest rate swaps (b) — 96 — — 96 — 64 — — 64 NDTs – equity securities (c)(d) 1,560 — — — 1,560 638 — — — 638 NDTs – debt securities (c)(e) 83 1,976 — — 2,059 — 734 — — 734 Sub-total $ 3,566 $ 2,534 $ 841 $ 5 6,946 $ 3,524 $ 1,426 $ 630 $ 14 5,594 Assets measured at net asset value (f): NDTs – equity securities (c)(d)(f) 821 579 Total assets $ 7,767 $ 6,173 Liabilities: Commodity contracts (b) $ 2,118 $ 975 $ 1,593 $ 5 $ 4,691 $ 3,815 $ 1,395 $ 1,674 $ 14 $ 6,898 Interest rate swaps (b) — 27 — — 27 — 48 — — 48 Total liabilities $ 2,118 $ 1,002 $ 1,593 $ 5 $ 4,718 $ 3,815 $ 1,443 $ 1,674 $ 14 $ 6,946 ____________ (a) Fair values for each level are determined on a contract basis, but certain contracts are in both an asset and a liability position. This reclassification represents the adjustment needed to reconcile to the gross amounts presented in the consolidated balance sheets. (b) See Note 11 for additional information. (c) NDT assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facilities. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT. The NDT investments are included in Investments in the consolidated balance sheets. There were no significant concentrations of credit risk from an individual counterparty or groups of counterparties in our NDT portfolio as of December 31, 2024. (d) The investment objective for NDT equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index for U.S. equity investments and the MSCI EAFE Index for non-U.S. equity investments. (e) The investment objective for NDT debt securities is to invest in a diversified, high quality, tax efficient portfolio. The debt securities are weighted with government and investment grade corporate bonds. Other investable debt securities include, but are not limited to, municipal bonds, high yield bonds, securitized bonds, non-U.S. developed bonds, emerging market bonds, loans and treasury inflation-protected securities. The debt securities had an average coupon rate of 3.99% and 3.19% as of December 31, 2024 and 2023, respectively, and an average maturity of 7 years and 11 years as of December 31, 2024 and 2023, respectively. NDT debt securities held as of December 31, 2024 mature as follows: $1.045 billion in one to five years, $599 million in five to 10 years and $415 million after 10 years. (f) Net asset value is a practical expedient used for the classification of assets that do not have readily determinable fair values and therefore are not classified in the fair value hierarchy. This amount is presented to permit reconciliation of this table to the amounts presented in the consolidated balance sheets. The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations as of December 31, 2024 and 2023: December 31, 2024 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) December 31, 2023 Fair Value Contract Type (a) Assets Liabilities Total, Net Valuation Technique Significant Unobservable Input Range (b) Average (b) (in millions) Electricity purchases and sales $ 449 $ (1,273) $ (824) Income Approach Hourly price curve shape (c) $ — to $ 85 $ 44 MWh Illiquid delivery periods for hub power prices and Heat Rates (d) $ 30 to $ 110 $ 71 MWh Options 1 (237) (236) Option Pricing Model Natural gas to power correlation (e) 10 % to 100 % 55 % Power and natural gas volatility (e) 10 % to 870 % 441 % Financial transmission rights/Congestion revenue rights 157 (34) 123 Market Approach (f) Illiquid price differences between settlement points (g) $ (85) to $ 25 $ (30) MWh Natural gas 9 (112) (103) Income Approach Natural gas basis (h) $ — to $ 15 $ 6 MMBtu Illiquid delivery periods (i) $ — to $ 5 $ 4 MMBtu Other (j) 14 (18) (4) Total $ 630 $ (1,674) $ (1,044) ____________ (a) Electricity purchase and sales contracts include (i) power and Heat Rate positions in ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO regions, (ii) Options consist of physical electricity options, spread options and natural gas options, (iii) Forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points are referred to as congestion revenue rights (CRRs) in ERCOT and financial transmission rights (FTRs) in PJM, ISO-NE, NYISO and MISO regions, and (iv) Natural gas contracts include swaps and forward contracts. (b) The range of the inputs may be influenced by factors such as time of day, delivery period, season and location. The average represents the arithmetic average of the underlying inputs and is not weighted by the related fair value or notional amount. (c) Primarily based on the historical range of forward average hourly ERCOT North Hub and ERCOT South and West Zone prices. (d) Primarily based on historical forward ERCOT and PJM power prices and ERCOT Heat Rate variability. (e) Primarily based on the historical forward correlation and volatility within ERCOT and PJM. (f) While we use the market approach, there is insufficient market data for the inputs to the valuation to consider the valuation liquid. (g) Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones. (h) Primarily based on the historical forward PJM and Northeast natural gas basis prices and fixed prices. (i) Primarily based on the historical forward natural gas fixed prices. (j) Other includes contracts for coal and environmental allowances. The following table presents the changes in fair value of the Level 3 assets and liabilities: Year Ended December 31, 2024 2023 2022 (in millions) Net liability balance at beginning of period $ (1,044) $ (1,219) $ (360) Total unrealized valuation gains (losses) (175) (765) (1,382) Purchases, issuances and settlements (a): Purchases 266 222 185 Issuances (26) (30) (62) Settlements 137 136 345 Transfers into Level 3 (b) (15) (48) (30) Transfers out of Level 3 (b) 118 660 85 Net liabilities assumed in connection with the Energy Harbor Merger (13) — — Net change 292 175 (859) Net liability balance at end of period $ (752) $ (1,044) $ (1,219) Unrealized valuation (losses) relating to instruments held at end of period $ (416) $ (676) $ (977) ____________ (a) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received, including CRRs and FTRs. (b) Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. For the year ended December 31, 2024, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power and natural gas derivatives where forward pricing inputs have become observable. For the year ended December 31, 2023, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become observable. For the year ended December 31, 2022, transfers into Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power, natural gas, and coal derivatives where forward pricing inputs have become observable. Assets and Liabilities Recorded on a Non-Recurring Basis Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include inventories, assets acquired and liabilities assumed in business combinations, goodwill and other long-lived assets that are written down to fair value when they are determined to be impaired or held for sale. The Energy Harbor Merger was accounted for under the acquisition method which requires all assets acquired and liabilities assumed in the acquisition be recorded at fair value at the acquisition date. See Note 2 for additional information. Fair Value of Debt December 31, 2024 December 31, 2023 Instrument Fair Value Hierarchy Carrying Amount Fair Carrying Amount Fair (in millions) Long-term debt under the Vistra Operations Credit Facilities Level 2 $ 2,435 $ 2,478 $ 2,456 $ 2,500 BCOP Credit Facilities Tax Credit Bridge Loan Level 3 344 367 — — Vistra Zero Term Loan B Facility Level 2 685 697 — — Vistra Operations Senior Notes Level 2 12,366 12,428 11,881 11,752 Energy Harbor Revenue Bonds Level 2 414 431 — — Equipment Financing Agreements Level 3 54 53 65 62 Forward Repurchase Obligation Level 3 1,335 1,335 — — We determine fair value in accordance with accounting standards. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services, such as Bloomberg.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2024
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 years ended December 31, 2024 and 2023: Nuclear Plant Decommissioning Land Reclamation, Coal Ash and Other Total (in millions) Liability at December 31, 2022 $ 1,688 $ 749 $ 2,437 Additions: Accretion (a) 54 34 88 Adjustment for change in estimates (b) — 94 94 Reductions: Payments — (81) (81) Liability at December 31, 2023 1,742 796 2,538 Additions: Accretion (a) 130 40 170 Adjustment for change in estimates (b) — 90 90 Adjustment for obligations assumed through acquisitions 1,368 — 1,368 Reductions: Payments — (88) (88) Liability at December 31, 2024 3,240 838 4,078 Less amounts due currently — (142) (142) Noncurrent liability at December 31, 2024 $ 3,240 $ 696 $ 3,936 ____________ (a) For the year ended December 31, 2024, nuclear plant decommissioning accretion includes $74 million of accretion expense recognized in operating costs in the consolidated statements of operations and $56 million reflected as a change in regulatory liability in the consolidated balance sheets. For the year ended December 31, 2023, nuclear plant decommissioning accretion reflected as a change in regulatory liability in the consolidated balance sheets. (b) Includes non-cash additions to asset retirement costs included in property, plant, and equipment of $52 million and $67 million for the years ended December 31, 2024 and 2023, respectively. For the next five years, Vistra is projected to spend approximately $546 million (on a nominal basis) to achieve its mining reclamation and other coal ash remediation objectives. Nuclear Decommissioning AROs AROs for nuclear generation decommissioning relate to the Comanche Peak plant in ERCOT and the facilities acquired from Energy Harbor which include the Beaver Valley, Perry and Davis-Besse plants in PJM (the PJM nuclear facilities). To estimate our nuclear decommissioning obligations we use a discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning methods and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. As of December 31, 2024, the carrying value of our ARO related to our Comanche Peak nuclear generation facility decommissioning totaled $1.797 billion, which is lower than the fair value of the assets contained in the Comanche Peak NDT of $2.249 billion. The difference between the carrying value of the ARO and the NDT represents a regulatory liability of $452 million recorded to the consolidated balance sheets in other noncurrent liabilities and deferred credits since any excess funds in the NDT after decommissioning our Comanche Peak plant would be refunded to Oncor. The carrying value of our ARO for our PJM nuclear facilities was recorded at fair value on the Merger Date. ARO accretion expense attributable to the PJM nuclear facilities is reflected in operating costs in the consolidated statements of operations. ARO estimates for the PJM nuclear facilities will be evaluated on an individual unit basis at least every five years unless triggering events warrant a more frequent review. Any changes in ARO estimates are recorded as an increase or decrease in ARO liability along with a corresponding change to asset retirement cost asset within property, plant, and equipment in the consolidated balance sheets; however, if the ARO estimate decreases by more than the remaining ARO asset, the balance of the change is recorded as a reduction to operating costs in the consolidated statement of operations.

Pension and Other Postretiremen

Pension and Other Postretirement Employee Benefits (OPEB) Plans	12 Months Ended
	Dec. 31, 2024
Compensation and Retirement Benefits Disclosures [Abstract]
Pension and Other Postretirement Employee Benefits (OPEB) Plans	PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS Vistra is the plan sponsor of the Vistra Retirement Plan (the Retirement Plan), which provides benefits to eligible employees of its subsidiaries. Oncor is a participant in the Retirement Plan. Effective January 1, 2018, Vistra entered into a contractual arrangement with Oncor whereby the costs associated with providing OPEB coverage for certain retirees (Split Participants) whose employment included service with both the regulated businesses of Oncor (or its predecessors) and the non-regulated businesses of Vistra (or its predecessors) are split between Oncor and Vistra. As Vistra accounts for its interests in the Retirement Plan as a multiple employer plan, only Vistra's share of the plan assets and obligations are reported in the pension benefit information presented below. The Retirement Plan is a qualified defined benefit pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of ERISA. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs. It is our policy to fund the Retirement Plan assets only to the extent required under existing federal regulations. Since 2012, the Retirement Plan has been closed to new participants and the only participants who remain in the Retirement Plan are employees who were active prior to 2012, including retired collective bargaining unit employees. Accordingly, ongoing expenses associated with the Retirement plan are immaterial, including expenses associated with pensions plans acquired from Dynegy and Energy Harbor. Vistra and our participating subsidiaries offer other postretirement employee benefits (OPEB) in the form of certain health care and life insurance benefits to eligible retirees and their eligible dependents. The retiree contributions required for such coverage vary based on a formula depending on the retiree's age and years of service. Pension and OPEB Costs The following table summarizes the total benefit costs of our pension and OPEB plans for the years ended December 31, 2024, 2023, and 2022. The individual components of benefit costs, including service cost, interest cost, expected return on assets and the net amortization of unrecognized amounts from accumulated other comprehensive income were immaterial. Year Ended December 31, 2024 2023 2022 (in millions) Pension costs $ 9 $ 9 $ 2 OPEB costs 5 5 4 Total benefit costs recognized as expense $ 14 $ 14 $ 6 Market-Related Value of Assets Held in Pension Benefit Trusts We use the calculated value method to determine the market-related value of the assets held in the trust for purposes of calculating pension costs. We include all gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year. Detailed Information Regarding Pension Plans and OPEB Benefits The following information is based on a December 31, 2024, 2023, and 2022 measurement dates: Retirement Plan OPEB Plans Year Ended December 31, Year Ended December 31, 2024 2023 2022 2024 2023 2022 Assumptions Used to Determine Benefit Obligations at Period End: Discount rate 5.63 % 4.97 % 5.16 % 5.62 % 4.98 % 5.18 % Expected rate of compensation increase (Vistra Plan) 3.50 % 3.64 % 3.79 % Expected rate of compensation increase (Dynegy Plan) 4.46 % Interest crediting rate for cash balance plans 3.75 % 3.50 % 3.00 % Retirement Plan OPEB Plans Year Ended December 31, Year Ended December 31, 2024 2023 2024 2023 (in millions, except percentages) Change in Pension and Postretirement Benefit Obligations: Projected benefit obligation at beginning of period $ 425 $ 449 $ 108 $ 110 Acquisitions 23 — — — Service cost 2 3 1 1 Interest cost 21 21 5 5 Participant contributions — — 3 3 Plan amendments — 1 — — Actuarial (gain) loss (24) 10 (7) 1 Benefits paid (38) (59) (11) (12) Projected benefit obligation at end of year $ 409 $ 425 $ 99 $ 108 Accumulated benefit obligation at end of year $ 408 $ 422 $ — $ — Change in Plan Assets: Fair value of assets at beginning of period $ 285 $ 320 $ 12 $ 29 Acquisitions 18 — — — Employer contributions 19 — 8 9 Participant contributions — — 2 3 Actual gain on assets 1 24 1 2 Transfers — — (2) (19) Benefits paid (38) (59) (11) (12) Fair value of assets at end of year $ 285 $ 285 $ 10 $ 12 Funded Status: Projected benefit obligation $ (409) $ (425) $ (99) $ (108) Fair value of assets 285 285 10 12 Funded status at end of year $ (124) $ (140) $ (89) $ (96) Retirement Plan OPEB Plans Year Ended December 31, Year Ended December 31, 2024 2023 2024 2023 Amounts Recognized in the Balance Sheet Consist of: Investments $ 1 $ — $ 2 $ 3 Other current liabilities — — (8) (9) Other noncurrent liabilities (125) (140) (83) (90) Net liability recognized $ (124) $ (140) $ (89) $ (96) Amounts Recognized in Accumulated Other Comprehensive Income Consist of: Net actuarial (gain) loss $ (5) $ 4 $ (22) $ (15) Prior services cost — 3 1 1 Net actuarial (gain) loss and prior service cost $ (5) $ 7 $ (21) $ (14) Fair Value Measurement of Pension and OPEB Plan Assets Retirement Plan As of December 31, 2024 and 2023, all of the Retirement Plan assets were measured at fair value using the net asset value per share (or its equivalent) except as noted and consisted of the following: December 31, 2024 2023 (in millions) Asset Category: Cash commingled trusts $ 6 $ 4 Equity securities: Global equities 86 82 Fixed income securities: Corporate bonds (a) 79 82 Government bonds 42 54 Other (b) 28 18 Real estate 27 28 Hedge funds 17 17 Total assets measured at net asset value $ 285 $ 285 ___________ (a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's. (b) Consists primarily of high-yield bonds, emerging market debt, bank loans, securitized bonds and private investment grade fixed income. OPEB Plans As of December 31, 2024 and 2023, the Vistra OPEB plan assets measured at fair value totaled $10 million and $12 million, respectively. At December 31, 2024 and 2023, assets consisted of $7 million and $9 million, respectively, of comingled funds valued at net asset value and $3 million and $3 million, respectively, of municipal bond and cash equivalent mutual funds classified as Level 1. Pension Plans with Projected Benefit Obligations (PBO) and Accumulated Benefit Obligations (ABO) in Excess of Plan Assets The following table provides information regarding pension plans with PBO and ABO in excess of the fair value of plan assets. December 31, 2024 2023 (in millions) Pension Plans with PBO and ABO in Excess of Plan Assets: Projected benefit obligations $ 409 $ 425 Accumulated benefit obligation $ 408 $ 422 Plan assets $ 285 $ 285 Retirement Plan Investment Strategy and Asset Allocations Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions. Fixed income securities held primarily consist of corporate bonds from a diversified range of companies, U.S. Treasuries and agency securities, and money market instruments. Equity securities are held to enhance returns by participating in a wide range of investment opportunities. International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging markets. Real estate, hedge funds, and credit strategies (primarily high yield bonds and emerging market debt) provide additional portfolio diversification and return potential. The target asset allocation ranges of pension plan investments by asset category are as follows: Retirement Plan Target Allocation Ranges Asset Category: Vistra Plan Dynegy Plan Energy Harbor Plan Fixed income securities 50 % - 70% 40 % - 50% 45 % - 55% Global equity securities 20 % - 28% 28 % - 38% 30 % - 38% Real estate 6 % - 10% 7 % - 15% 5 % - 10% Credit strategies 2 % - 6% 4 % - 8% 4 % - 8% Hedge funds 2 % - 6% 4 % - 8% 1 % - 5% Retirement Plan Expected Long-Term Rate of Return on Assets Assumption The Retirement Plan strategic asset allocation is determined in conjunction with the plan's advisors and utilizes a comprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies. The study incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management. Retirement Plan Expected Long-Term Rate of Return Asset Class: Vistra Plan Dynegy Plan Energy Harbor Plan Fixed income securities 5.9 % 5.5 % 4.6 % Global equity securities 7.2 % 7.2 % 7.2 % Real estate 5.8 % 5.8 % 5.8 % Credit strategies 7.4 % 7.4 % 7.4 % Hedge funds 7.3 % 7.3 % 7.3 % Weighted average 6.3 % 6.3 % 5.8 % Benefit Plan Assumed Health Care Cost Trend Rates The following tables provide information regarding the assumed health care cost trend rates. December 31, 2024 2023 Assumed Health Care Cost Trend Rates-Not Medicare Eligible: Health care cost trend rate assumed for next year 7.00 % 7.00 % Rate to which the cost trend is expected to decline (the ultimate trend rate) 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate 2034 2033 Assumed Health Care Cost Trend Rates-Medicare Eligible: Health care cost trend rate assumed for next year (Vistra Plan) 15.70 % 12.90 % Health care cost trend rate assumed for next year (Split-Participant Plan) 13.80 % 12.30 % Rate to which the cost trend is expected to decline (the ultimate trend rate) 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate 2034 2033 Significant Concentrations of Risk The plans' investments are exposed to risks such as interest rate, capital market and credit risks. We seek to optimize return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing capital market conditions and other factors specific to us. While we recognize the importance of return, investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings for certain investment securities to assist in the mitigation of the risk of large losses. Assumed Discount Rate We selected the assumed discount rates using the Aon AA Above Median yield curve, which is based on corporate bond yields and at December 31, 2024 consisted of 490 corporate bonds with an average rating of AA using Moody's, S&P and Fitch ratings. Contributions Contributions to the Retirement Plan for the years ended December 31, 2024, 2023, and 2022 totaled $19 million, zero, and zero, respectively, and contributions in 2025 are expected to total $25 million. OPEB plan funding for each of the years ended December 31, 2024, 2023, and 2022 totaled $8 million, $9 million, and $9 million, respectively, and funding in 2025 is expected to total $8 million. Future Benefit Payments Estimated future benefit payments to beneficiaries are as follows: 2025 2026 2027 2028 2029 2030-2034 (in millions) Pension benefits $ 33 $ 34 $ 43 $ 32 $ 32 $ 151 OPEB $ 9 $ 9 $ 9 $ 8 $ 8 $ 36 Qualified Savings Plans Our employees may participate in a qualified savings plan (the Thrift Plan). This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code and is subject to the provisions of ERISA. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more than such threshold may contribute from 1% to 20% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% (75% for employees covered under the traditional formula in the Retirement Plan) of the first 6% of employee contributions. Employer matching contributions are made in cash and may be allocated by participants to any of the plan's investment options. Aggregate employer contributions to the qualified savings plans totaled $46 million, $33 million, and $33 million for the years ended December 31, 2024, 2023, and 2022, respectively.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES Contractual Commitments As of December 31, 2024, we had minimum contractual commitments under long-term service and maintenance contracts, energy-related contracts and other agreements as follows: Long-Term Service and Maintenance Contracts (a) Coal transportation agreements Pipeline transportation and storage reservation fees Water (in millions) 2025 $ 227 $ 59 $ 187 $ 9 2026 206 26 200 9 2027 207 26 209 9 2028 265 — 228 9 2029 259 — 234 9 Thereafter 1,916 — 115 37 Total $ 3,080 $ 111 $ 1,173 $ 82 ____________ (a) Long-term service and maintenance contracts reflect expected expenditures as these contracts do not include minimum spending requirements, but can only be terminated based on events outside the control of the Company. In addition to the commitments detailed above, we have nuclear fuel contracts with early termination penalties. As of December 31, 2024, termination costs of $116 million would be incurred if we terminated those contracts. Expenditures under our coal purchase and coal transportation agreements totaled $744 million, $936 million, and $995 million for the years ended December 31, 2024, 2023, and 2022, respectively. 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 December 31, 2024, we had outstanding letters of credit totaling $2.935 billion as follows: • $2.560 billion to support commodity risk management and collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and collateral postings with ISOs/RTOs; • $248 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 • $16 million for other credit support requirements. Surety Bonds As of December 31, 2024, we had outstanding surety bonds totaling $1.087 billion to support performance under various contracts and legal obligations in the normal course of business. Litigation and Regulatory Proceedings 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 in July 2019. The complaint filed in Illinois state court alleges, among other things, that IG&E engaged in improper marketing conduct and overcharged customers. The vast majority of the conduct in question occurred prior to our acquisition of IG&E. In July 2022, we moved to dismiss the complaint, and in October 2022, the district court granted in part our motion to dismiss, barring all claims asserted by the Illinois Attorney General that were outside of the 5-year statute of limitations period, which now limits the period during which claims may be made to start in May 2017 rather than extending back to 2013 as the Illinois Attorney General had alleged in its complaint. 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 and wrongful death lawsuits related to Winter Storm Uri have been, and continue to be, filed in various Texas state courts against us and numerous generators, transmission and distribution utilities, retail and electric providers, as well as ERCOT. We and other defendants requested that all pretrial proceedings in these personal injury cases be consolidated and transferred to a single multi-district litigation (MDL) pretrial judge. In June 2021, the MDL panel granted the request to consolidate all these cases into an MDL for pretrial proceedings. Additional personal injury cases that have been, and continue to be, filed on behalf of additional plaintiffs have been consolidated with the MDL proceedings. In addition, in January 2022, an insurance subrogation lawsuit was filed in Austin state court by over one hundred insurance companies against ERCOT, Vistra and several other defendants. The lawsuit seeks recovery of insurance funds paid out by these insurance companies to various policyholders for claims related to Winter Storm Uri, and that case has also now been consolidated with the MDL proceedings. In the summer of 2022, various defendant groups filed motions to dismiss five so-called bellwether cases, and the MDL court heard oral argument on those motions in October 2022. In January 2023, the MDL court ruled on the various motions to dismiss and denied the motions to dismiss of the generator defendants and the transmission distribution utilities defendants, but granted the motions of some of the other defendant groups, including the retail electric providers and ERCOT. In February 2023, the generator defendants filed a mandamus petition with the First Court of Appeals in Houston, Texas (First Court of Appeals) to review the MDL court's denial of the motion to dismiss. In December 2023, the First Court of Appeals in a unanimous decision granted our mandamus petition and instructed the MDL court to grant the motions to dismiss in full filed by the generator defendants. In January 2024, the plaintiffs filed a request with the full Court of Appeals to review that panel ruling, which was denied in November 2024. The plaintiffs have petitioned the Texas Supreme Court to review that decision. We believe we have strong defenses to these lawsuits and intend to defend against these cases vigorously if they continue. Moss Landing 300 Battery Fire On January 16, 2025, we detected a fire at our Moss Landing 300 MW energy storage facility at the Moss Landing Power Plant site. We are working closely with all local, state, and federal regulatory authorities on the response, and we are investigating the cause of the fire. We are also responding to various regulatory bodies, including the CPUC, the EPA, and others investigating the incident. Finally, two lawsuits have been filed in California state court against Vistra, LG, and others, arising from the event. Unleashing American Energy Executive Order In January 2025, President Trump issued a series of executive orders, including an order titled Unleashing American Energy (the Order) that ordered that all federal agencies are to review all existing regulations, orders, and other actions for consistency with the policy goals, and develop an action plan within 30 days to resolve any policy inconsistencies. The Order requires the EPA to review the GHG, CSAPR, Legacy CCR and ELG rules discussed below. Additionally, the Order states the U.S. Attorney General may request a stay of the litigation involving these rules while the EPA conducts its reviews. Greenhouse Gas Emissions (GHG) In May 2023, the EPA released a proposal regulating power plant GHG emissions, while also proposing to repeal the Affordable Clean Energy (ACE) rule that had been finalized by the EPA in July 2019. In May 2024, the EPA published a final GHG rule that repealed the ACE rule and sets limits for (a) new natural gas-fired combustion turbines and (b) existing coal-, oil- and natural gas-fired steam generation units. The standards are based on technologies such as carbon capture and sequestration/storage (CCS) and natural gas co-firing. Starting in 2030, the rule would begin to require more CO 2 emissions control at certain existing fossil fuel-fired steam generating units, with more stringent standards beginning in 2032 for coal-fired units that plan to operate for a longer period of time. For new natural gas combustion turbines that operate more frequently, the rule would phase in increasingly stringent CO 2 requirements over time. Under the rule, states would be required to submit plans to the EPA within 24 months of the rule's publication in the Federal Register that provide for the establishment, implementation, and enforcement of standards of performance for existing sources. These state plans must generally establish standards that are at least as stringent as the EPA's emission guidelines. Under the rule, existing coal-fired steam generation units that will operate on or after January 1, 2039 must start complying with their standards of performance (based on application of CCS with 90 percent capture) by January 1, 2032. Units that are permanently retiring before January 1, 2039, but after December 31, 2031, must start complying with their standards of performance (based on co-firing with 40 percent natural gas on a heat input basis) beginning on January 1, 2030. Units permanently retiring by January 1, 2032 are exempt from the rule. Given our previously announced coal unit retirement commitments, our Martin Lake and Oak Grove plants are the only coal units that are subject to this rule. Our Graham, Lake Hubbard, Stryker Creek and Trinidad oil/natural gas facilities are also regulated under this rule. None of our existing large or small combustion turbines are subject to this rule. The rule also regulates any new gas units. For new combustion turbine units, the rule establishes three different categories depending on how intensively those units are operated, with immediate compliance obligations for all three categories but more stringent standards beginning in 2032 only for the category of units operating the most intensively. Following finalization of the rule in May 2024, 17 petitions for review from various states, industry groups, and companies were filed in the D.C. Circuit Court along with multiple motions to stay the rule. We are participating in an industry coalition challenging the rule. In July 2024, the D.C. Circuit Court denied the motions to stay and a number of parties subsequently filed an emergency request with the U.S. Supreme Court to stay the rule which was denied in October 2024. Oral argument on the merits of the legal challenges to the rule was held in December 2024 before the D.C. Circuit Court. In February 2025, the D.C. Circuit granted the unopposed motion filed by the Department of Justice on behalf of the EPA, holding the litigation in abeyance for a period of 60 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed. Cross-State Air Pollution Rule (CSAPR) and Good Neighbor Plan In October 2015, the EPA revised the primary and secondary ozone National Ambient Air Quality Standards (NAAQS) to lower the 8-hour standard for ozone emissions during ozone season (May to September). As required under the CAA, in October 2018, the State of Texas submitted a State Implementation Plan (SIP) to the EPA demonstrating that emissions from Texas sources do not contribute significantly to nonattainment in, or interfere with maintenance by, any other state with respect to the revised ozone NAAQS. In February 2023, the EPA disapproved Texas' SIP and the State of Texas, Luminant, certain trade groups, and others challenged that disapproval in the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court). In March 2023, those same parties filed motions to stay the EPA's SIP disapproval in the Fifth Circuit Court and the EPA moved to transfer our challenges to the D.C. Circuit Court or have those challenges dismissed. In April 2022, prior to the EPA's disapproval of Texas' SIP, the EPA proposed a Federal Implementation Plan (FIP) to address the 2015 ozone NAAQS. We, along with many other companies, trade groups, states, and ISOs, including ERCOT, PJM and MISO, filed responsive comments to the EPA's proposal in June 2022, expressing concerns about certain elements of the proposal, particularly those that may result in challenges to electric reliability under certain conditions. In March 2023, the EPA administrator signed its final FIP, called the Good Neighbor Plan (GNP). 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. Allowances will be limited under the program and will be further reduced beginning in ozone season 2026 to a level that is intended to reduce operating time of coal-fueled power plants during ozone season or force coal plants to retire, particularly those that do not have selective catalytic reduction systems such as our Martin Lake power plant. In May 2023, the Fifth Circuit Court granted our motion to stay the EPA's disapproval of Texas' SIP pending a decision on the merits and denied the EPA's motion to transfer our challenge to the D.C. Circuit Court. As a result of the stay, we do not believe the EPA has authority to implement the GNP FIP as to Texas sources pending the resolution of the merits, meaning that Texas will remain in Group 2 and not be subject to any requirements under the GNP FIP at least until the Fifth Circuit Court rules on the merits. Oral argument was heard in December 2023 before the Fifth Circuit Court. In June 2023, the EPA published the final FIP in the Federal Register, which included requirements as to Texas despite the stay of the SIP disapproval by the Fifth Circuit Court. In June 2023, the State of Texas, Luminant and various other parties also filed challenges to the GNP FIP in the Fifth Circuit Court, filed a motion to stay the FIP and confirm venue for this dispute in the Fifth Circuit Court. After the motion to stay and to confirm venue was filed, the EPA signed an interim final rule on June 29, 2023 that confirms the GNP FIP as to Texas is stayed. In February 2025, the Department of Justice filed a motion on behalf of the EPA in the Fifth Circuit Court, seeking to hold the litigation in abeyance while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed. In February 2025, the State of Texas filed a response opposing the requested abatement, which we joined. In July 2023, the Fifth Circuit Court ruled that the GNP FIP challenge would be held in abeyance pending the resolution of the litigation on the SIP disapproval and denied the motion to stay as not needed given the EPA's administrative stay. In a related action brought by other states and parties challenging the GNP FIP, in June 2024, the U.S. Supreme Court granted a stay of the GNP FIP pending a review of the merits by the D.C. Circuit Court and any further appeal to the U.S. Supreme Court. As a result, the GNP FIP is now stayed for all covered states until the courts resolve the legality of the FIP. In February 2025, the D.C. Circuit Court denied a motion filed by the Department of Justice on behalf of the EPA, seeking to hold the litigation in abeyance for a period of 60 days while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed. Regional Haze — Reasonable Progress and Best Available Retrofit Technology (BART) for Texas 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 SO 2 , the rule established an intrastate Texas emission allowance trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program. The program includes 39 generation units (including the Martin Lake, Big Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2, and Graham 2 plants). The compliance obligations in the program started on January 1, 2019. For NO X , the rule adopted the CSAPR's ozone program as BART and for particulate matter, the rule approved Texas' SIP that determines that no electricity generation units are subject to BART for particulate matter. In August 2020, the EPA issued a final rule affirming the prior BART final rule but also included additional revisions that were proposed in November 2019. Challenges to both the 2017 rule and the 2020 rules have been consolidated in the D.C. Circuit Court, where we have intervened in support of the EPA. We are in compliance with the rule, and the retirements of our Monticello, Big Brown, and Sandow 4 plants have enhanced our ability to comply. The EPA is in the process of reconsidering the BART rule, and the challenges in the D.C. Circuit Court have been held in abeyance pending the EPA's final action on reconsideration. In May 2023, a proposed BART rule was published in the Federal Register that would withdraw the trading program provisions of the prior rule and would establish SO 2 limits on six facilities in Texas, including Martin Lake and Coleto Creek. Under the current proposal, compliance would be required within 3 years for Martin Lake and 5 years for Coleto Creek. Due to the announced shutdown for Coleto Creek, we do not anticipate any impacts at that facility, and we are evaluating potential compliance options at Martin Lake should this proposal become final. We submitted comments to the EPA on this proposal in August 2023. SO 2 Designations for Texas In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Martin Lake generation plant and our now retired Big Brown and Monticello plants. The final designations require Texas to develop nonattainment plans for these areas. In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court. In August 2019, the EPA issued a proposed Error Correction Rule for all three areas, which, if finalized, would have revised its previous nonattainment designations and each area at issue would be designated unclassifiable. In May 2021, the EPA finalized a "Clean Data" determination for the areas surrounding the retired Big Brown and Monticello plants, redesignating those areas as attainment based on monitoring data supporting an attainment designation. In June 2021, the EPA published two notices; one that it was withdrawing the August 2019 Error Correction Rule and a second separate notice denying petitions from Luminant and the State of Texas to reconsider the original nonattainment designations. We, along with the State of Texas, challenged that EPA action and have consolidated it with the pending challenge in the Fifth Circuit Court, and this case was argued before the Fifth Circuit Court in July 2022. In September 2021, the TCEQ considered a proposal for its nonattainment SIP revision for the Martin Lake area and an agreed order to reduce SO 2 emissions from the plant. The proposed agreed order associated with the SIP proposal reduced emission limits as of January 2022. Emission reductions required are those necessary to demonstrate attainment with the NAAQS. The TCEQ's SIP action was finalized in February 2022 and has been submitted to the EPA for review and approval. In January 2024, in a split decision, the Fifth Circuit Court denied the petitions for review we and the State of Texas filed over the EPA's 2016 nonattainment designation for SO 2 for the area around Martin Lake. As a result of this decision, the EPA's nonattainment designation – originally made in 2016 – remains in place. In February 2024, we filed a petition asking the full Fifth Circuit Court to review the panel decision issued in January 2024, which remains pending before the full Fifth Circuit Court. In August 2024, the EPA proposed a Finding of Failure to attain the SO 2 standard for Rusk and Panola Counties, a partial approval and partial disapproval of the Texas SIP and a proposed federal plan for the area. In December 2024, the EPA finalized the Finding of Failure to attain the standard and stated that it would take final action of the SIP partial approval and disapproval in a future action. In February 2025, we, along with the State of Texas, filed a challenge to the Finding of Failure in the Fifth Circuit Court. Particulate Matte r In February 2024, the EPA issued a rule addressing the annual health-based national ambient air quality standards for fine particulate matter (or PM2.5). In general, the rule lowers the level of the annual PM2.5 standard from 12.0 micrograms per cubic meter (µg/m3) to 9.0 µg/m3. The effective date of the rule is 60 days from publication in the Federal Register, and the earliest attainment date for areas exceeding the new standard is 2032. Based on 2021-2023 design value associated with the rule, we have just four plants (Calumet (Illinois), Dicks Creek and Miami Fort (Ohio), and Lake Hubbard (Texas)) operating in areas where the air quality monitoring data are currently exceeding the new PM2.5 standard. We have previously announced that our Miami Fort generation facility will close by the end of 2027. States will have to develop a plan (by late 2027 at the earliest) to get those areas into attainment and there would be a possibility that additional controls would be required for those sites. However, before the state begins this planning process, the designation process will occur within two years from the issuance of the final rule. The states develop recommendations about the boundaries of the nonattainment counties and the EPA must finalize the designations including the boundaries of each nonattainment area. Effluent Limitation Guidelines (ELGs) In November 2015, the EPA revised the ELGs for steam electricity generation facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, such as flue gas desulfurization (FGD), fly ash, bottom ash, and flue gas mercury control wastewaters. Various parties filed petitions for review of the ELG rule, and the petitions were consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions requesting reconsideration of the ELG rule and administratively stayed the rule's compliance date deadlines. In April 2019, the Fifth Circuit Court vacated and remanded portions of the EPA's ELG rule pertaining to effluent limitations for legacy wastewater and leachate. The EPA published a final rule in October 2020 that extends the compliance date for both FGD and bottom ash transport water to no later than December 2025, as negotiated with the state permitting agency. Additionally, the final rule allows for a retirement exemption that exempts facilities certifying that units will retire by December 2028 provided certain effluent limitations are met. In 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. We are reviewing the rule for impact but believe it will require additional treatment costs for legacy wastewaters during pond closure activities and combustion residual leachate. At this time, we don't expect the impact of these additional treatment costs to be material. A number of parties have since challenged the rule and that case is pending in the U.S. Court of Appeals for the Eighth Circuit. We are not a party to that litigation. In February 2025, the Department of Justice on behalf of the EPA filed an unopposed motion seeking to hold the litigation in abeyance while the new leadership at the EPA evaluates the rule and determines how it wishes to proceed. Coal Combustion Residuals (CCR) Rule Revisions and Extension Applications In August 2018, the D.C. 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, which was not potentially subject to the EPA's 2015 CCR rule until the aforementioned D.C. Circuit Court decision in August 2018, we submitted proposed corrective action plans involving closure of two CCR surface impoundments ( i.e. , the old east and the north impoundments) to the IEPA in 2012, and we submitted revised plans in 2014. In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options. In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface impoundments at our retired Vermilion facility, which is owned by our subsidiary DMG, and that notice was referred to the Illinois Attorney General. In June 2021, the Illinois Attorney General and the Vermilion County State Attorney filed a complaint in Illinois state court with an agreed interim consent ord

Equity

Equity	12 Months Ended
	Dec. 31, 2024
Stockholders' Equity Note [Abstract]
Equity	EQUITY Common Stock Issuances and Repurchases Changes in the number of shares of common stock issued and outstanding for the years ended December 31, 2024, 2023, and 2022 are reflected in the table below. Shares Treasury Shares Outstanding Balance at December 31, 2021 532,929,476 (69,031,742) 463,897,734 Shares issued (a) 4,262,575 — 4,262,575 Shares retired (12,979) — (12,979) Shares repurchased (b) — (78,470,547) (78,470,547) Balance at December 31, 2022 537,179,072 (147,502,289) 389,676,783 Shares issued (a) 6,474,491 — 6,474,491 Shares retired (18,391) — (18,391) Shares repurchased (b) — (44,994,499) (44,994,499) Balance at December 31, 2023 543,635,172 (192,496,788) 351,138,384 Shares issued (a) 5,117,434 — 5,117,434 Shares repurchased (b) — (16,560,328) (16,560,328) Balance at December 31, 2024 548,752,606 (209,057,116) 339,695,490 ____________ (a) Shares issued include share awards granted to nonemployee directors. (b) Shares repurchased include 58,817, 318,632, and 78,087 of unsettled shares as of December 31, 2024, 2023, and 2022, respectively. C ommon Stock Dividends Dividends are subject to declaration by the Board and may be subject to numerous factors at the time of declaration. These factors include, but are not limited to, prevailing market conditions, Vistra's results of operations, financial condition and liquidity, Delaware law, and any contractual limitations, such as the cumulative dividend requirements described in the certificates of designation of our outstanding preferred stock. Dividends per common share totaled $0.8735, $0.8205, and $0.7240 in the years ended December 31, 2024, 2023, and 2022, respectively. In February 2025, the Board declared a quarterly dividend of $0.2235 per share of common stock that will be paid in March 2025. Share Repurchase Program In October 2021, the Board authorized a share repurchase program (Share Repurchase Program). Under this program, shares of the Company's common stock may be repurchased in open market transactions, privately negotiated transactions, or other means in accordance with federal securities laws. The timing, number, and value of shares repurchased will be determined at our discretion, considering factors such as capital allocation priorities, stock market price, general market and economic conditions, legal requirements, and compliance with debt agreements and preferred stock certificates of designation. Amount Authorized for Share Repurchases (in billions) Board Authorization Dates: October 2021 $ 2.00 August 2022 1.25 March 2023 1.00 February 2024 1.50 October 2024 1.00 Cumulative authorization at December 31, 2024 $ 6.75 The following table provides information about our repurchases of common stock for the period between January 1, 2022 and February 24, 2025. $6.750 Billion Board Authorization Total Number of Shares Repurchased Average Price Paid Amount Paid for Shares Repurchased Amount Available for Additional Repurchases at the End of the Period (in millions, except share amounts and price paid per share) Year Ended December 31, 2022 78,470,547 $ 23.40 $ 1,836 Year Ended December 31, 2023 44,994,499 27.89 1,255 Year Ended December 31, 2024 16,560,328 74.96 1,241 January 1, 2022 through December 31, 2024 (a) 140,025,374 $ 30.94 $ 4,332 $ 2,009 January 1, 2025 through February 24, 2025 848,866 163.23 139 January 1, 2022 through February 24, 2025 140,874,240 $ 31.74 $ 4,471 $ 1,870 ____________ (a) Shares repurchased include 58,817 of unsettled shares for $8 million as of December 31, 2024. 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 and Outstanding (a) Contractual Rates Earliest Redemption Date (b) Date at Which Dividend Rate Becomes Floating Floating Annual Rates Series A October 15, 2021 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 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 476,066 8.875 % January 15, 2029 January 15, 2029 5-Year U.S. Treasury rate (subject to floor of 3.83%) plus 5.045% ____________ (a) Series C Preferred Stock issued totaled 476,081 shares at December 31, 2023. (b) Subject to our right, in limited circumstances, to redeem preferred stock prior to the earliest redemption date. Each series of preferred stock has a liquidation price of $1,000, plus accrued and unpaid dividends through their redemption date. Preferred stock is not convertible into or exchangeable for any other securities of the Company and has limited voting rights. Preferred Stock Dividends Preferred stock dividends are payable semiannually in arrears when declared by the Board. The following table summarizes preferred stock dividends paid per share in the years ended December 31, 2024, 2023, and 2022. Year Ended December 31, Preferred Stock Series 2024 2023 2022 Series A Preferred Stock $ 80.00 $ 80.00 $ 80.00 Series B Preferred Stock $ 70.00 $ 70.00 $ 70.97 Series C Preferred Stock $ 48.32 In October 2024, the Board declared a semi-annual dividend of $44.375 per share of Series C Preferred Stock that was paid in January 2025. In February 2025, the Board declared a semi-annual dividend of $40.00 per share of Series A Preferred Stock that will be paid in April 2025.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2024
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. Year Ended December 31, 2024 2023 2022 (in millions, except share data) Net income (loss) attributable to Vistra $ 2,659 $ 1,493 $ (1,227) Less cumulative dividends attributable to Series A Preferred Stock (80) (80) (80) Less cumulative dividends attributable to Series B Preferred Stock (70) (70) (70) Less cumulative dividends attributable to Series C Preferred Stock (42) — — Net income (loss) attributable to common stock — basic and diluted 2,467 1,343 (1,377) Weighted average shares of common stock outstanding: Basic 344,788,634 369,771,359 422,447,074 Dilutive securities: Stock-based incentive compensation plan 7,778,426 5,421,752 — Diluted 352,567,060 375,193,110 422,447,074 Net income (loss) per weighted average share of common stock outstanding: Basic $ 7.16 $ 3.63 $ (3.26) Diluted $ 7.00 $ 3.58 $ (3.26) Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive were immaterial in the year ended December 31, 2024 and were 392,218 and 8,292,647 shares for the years ended December 31, 2023 and 2022, respectively.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2024
Share-Based Payment Arrangement [Abstract]
Stock-Based Compensation	STOCK-BASED COMPENSATION Vistra 2016 Omnibus Incentive Plan On the Effective Date, the Board adopted the 2016 Omnibus Incentive Plan (2016 Incentive Plan), under which an aggregate of 22,500,000 shares of our common stock were reserved for issuance as equity-based awards to our non-employee directors, employees, and certain other persons. Following approval of the Board and approval by the stockholders at the 2019 and 2024 annual meetings of the Company, the 2016 Incentive Plan was amended to increase the maximum number of shares reserved for issuance under the 2016 Incentive Plan to 37,500,000 and 43,000,000, respectively. The Board or any committee duly authorized by the Board will administer the 2016 Incentive Plan and has broad authority under the 2016 Incentive Plan to, among other things: (a) select participants, (b) determine the types of awards that participants are to receive and the number of shares that are to be subject to such awards, and (c) establish the terms and conditions of awards, including the price (if any) to be paid for the shares of the award. The types of awards that may be granted under the 2016 Incentive Plan include stock options, RSUs, restricted stock, performance awards, and other forms of awards granted or denominated in shares of Vistra common stock, as well as certain cash-based awards. If any stock option or other stock-based award granted under the 2016 Incentive Plan expires, terminates or is canceled for any reason without having been exercised in full, the number of shares of Vistra common stock underlying any unexercised award shall again be available for awards under the 2016 Incentive Plan. If any shares of restricted stock, performance awards or other stock-based awards denominated in shares of Vistra common stock awarded under the 2016 Incentive Plan are forfeited for any reason, the number of forfeited shares shall again be available for purposes of awards under the 2016 Incentive Plan. Any award under the 2016 Incentive Plan settled in cash shall not be counted against the maximum share limitation. No awards under the 2016 Incentive Plan have been settled in cash since the Effective Date. As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the 2016 Incentive Plan and any outstanding awards, as well as the exercise or purchase price of awards, and performance targets under certain types of performance-based awards, are required to be adjusted in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the Vistra stockholders. Stock-Based Compensation Expense Stock-based compensation expense is reported as SG&A in the consolidated statements of operations as follows: Year Ended December 31, 2024 2023 2022 (in millions) Total stock-based compensation expense $ 100 $ 77 $ 65 Income tax benefit (23) (18) (15) Stock based-compensation expense, net of tax $ 77 $ 59 $ 50 Stock Options Stock options outstanding at December 31, 2024 are all held by current or former employees. The following table summarizes our stock option activity: Year Ended December 31, 2024 Stock Options Weighted Weighted Average Remaining Contractual Term (Years) Aggregate Intrinsic Value (in millions) Total outstanding at beginning of period 6,126 $ 20.01 4.2 $ 113.5 Exercised (2,526) $ 20.06 Total outstanding at end of period 3,600 $ 19.97 3.5 $ 424.4 Exercisable at December 31, 2024 3,600 $ 19.97 3.5 $ 424.4 As of December 31, 2024, there was no unrecognized compensation cost related to unvested stock options granted under the 2016 Incentive Plan and no new options were issued in the three years ended December 31, 2024. Restricted Stock Units The following table summarizes our restricted stock unit activity: Year Ended December 31, 2024 Restricted Stock Units Weighted Total nonvested at beginning of period 3,908 $ 21.90 Granted 1,017 $ 59.11 Vested (1,785) $ 22.20 Forfeited (86) $ 33.55 Total nonvested at end of period 3,054 $ 34.30 As of December 31, 2024, $61 million of unrecognized compensation cost related to unvested restricted stock units granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 2.0 years. Performance Stock Units We also issue Performance Stock Units (PSUs) to certain members of management on an annual basis. All PSUs have a three

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2024
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. In the fourth quarter of 2024, we updated our reportable segments to reflect changes in how the Company's CODM makes operating decisions, assesses performance, and allocates resources by removing the Sunset segment. The results of the plants previously included in the Sunset segment are now reflected in the Texas and East segments based on their respective geography. Our Chief Executive Officer is our CODM. Our CODM reviews the results of these segments separately and allocates resources to the respective segments as part of our strategic operations. A measure of assets is not applicable, as segment assets are not regularly reviewed by the CODM for evaluating performance or allocating resources. The 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 segments. The East segment represents results from Vistra's electricity generation operations in the Eastern Interconnection of the U.S. electric grid, other than assets included in the Asset Closure segment, and includes operations in the PJM, MISO, ISO-NE, and NYISO markets. The West segment represents results from the CAISO market, including our battery ESS projects at our Moss Landing power plant site. The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines (see Note 6 for additional information). Upon movement of generation plant assets to the Asset Closure segment, prior year results are retrospectively adjusted, if the effects are material, for comparative purposes. Separately reporting the Asset Closure segment provides management with better information related to the performance and earnings power of Vistra's ongoing operations and facilitates management's focus on minimizing the cost associated with decommissioning and reclamation of retired plants and mines. Corporate and Other represents the remaining non-segment operations consisting primarily of general corporate expenses, interest, taxes and other expenses not allocated to our operating segments. The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1. 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 in evaluating drivers of segment profits available to the Company's equity holders. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at market prices. Certain shared services costs are allocated to the segments. Substantially all income tax (expense) benefit is recognized in Corporate and Other. Year Ended December 31, 2024 Retail Texas East West Asset Closure Total Reportable Segments Corporate and Other Total (in millions) Operating revenues $ 12,797 $ 5,394 $ 5,661 $ 877 $ 1 $ 24,730 $ (7,506) $ 17,224 Fuel, purchased power costs, and delivery fees (10,276) (1,596) (2,698) (221) (3) (14,794) 7,509 (7,285) Operating costs (159) (996) (1,103) (72) (81) (2,411) (3) (2,414) Selling, general, and administrative expenses (977) (169) (148) (25) (43) (1,362) (239) (1,601) Other segment items: Depreciation and amortization (114) (581) (996) (86) — (1,777) (66) (1,843) Interest expenses and related charges (54) 46 9 1 (4) (2) (898) (900) Income tax expense — — — — — — (655) (655) Other (a) (1) 35 177 (3) 14 222 64 286 Net income (loss) $ 1,216 $ 2,133 $ 902 $ 471 $ (116) $ 4,606 $ (1,794) $ 2,812 Capital expenditures, including nuclear fuel and excluding growth expenditures $ 4 $ 1,124 $ 661 $ 70 $ — $ 1,859 $ 58 $ 1,917 Year Ended December 31, 2023 Retail Texas East West Asset Closure (b) Total Reportable Segments Corporate and Other Total (in millions) Operating revenues $ 10,572 $ 3,979 $ 5,890 $ 914 $ — $ 21,355 $ (6,576) $ 14,779 Fuel, purchased power costs, and delivery fees (9,046) (2,028) (2,730) (328) (3) (14,135) 6,578 (7,557) Operating costs (123) (917) (528) (58) (74) (1,700) (2) (1,702) Selling, general, and administrative expenses (858) (140) (127) (24) (34) (1,183) (125) (1,308) Other segment items: Depreciation and amortization (102) (550) (703) (79) — (1,434) (68) (1,502) Interest expenses and related charges (20) 21 (2) 8 (5) 2 (742) (740) Income tax expense — — (1) — — (1) (507) (508) Other (a) 1 33 (50) 21 110 115 (85) 30 Net income (loss) $ 424 $ 398 $ 1,749 $ 454 $ (6) $ 3,019 $ (1,527) $ 1,492 Capital expenditures, including nuclear fuel and excluding growth expenditures $ 1 $ 750 $ 362 $ 366 $ — $ 1,479 $ 58 $ 1,537 Year Ended December 31, 2022 Retail Texas East West Asset Closure (b) Total Reportable Segments Corporate and Other Total (in millions) Operating revenues $ 9,455 $ 3,878 $ 4,429 $ 336 $ 384 $ 18,482 $ (4,754) $ 13,728 Fuel, purchased power costs, and delivery fees (7,169) (3,052) (4,132) (481) (322) (15,156) 4,755 (10,401) Operating costs (143) (832) (482) (42) (145) (1,644) (1) (1,645) Selling, general, and administrative expenses (826) (135) (97) (21) (44) (1,123) (66) (1,189) Other segment items: Interest expenses and related charges (14) 20 (6) 6 (3) 3 (371) (368) Depreciation and amortization (145) (541) (768) (42) (31) (1,527) (69) (1,596) Income tax benefit — — — — — — 350 350 Other (a) — 76 (71) 6 14 25 (114) (89) Net income (loss) $ 1,158 $ (586) $ (1,127) $ (238) $ (147) $ (940) $ (270) $ (1,210) Capital expenditures, including nuclear fuel and excluding growth expenditures $ 1 $ 520 $ 187 $ 345 $ — $ 1,053 $ 55 $ 1,108 ____________ (a) Other includes impairment of long-lived assets, other income, other deductions, and the impacts of the Tax Receivable Agreement. (b) We have allocated unrealized gains and losses on the commodity risk management activities attributable to the plants retired in 2022 and 2023. See Note 6 for additional information.

Supplementary Financial Informa

Supplementary Financial Information	12 Months Ended
	Dec. 31, 2024
Supplementary Financial Information [Abstract]
Supplementary Financial Information	SUPPLEMENTARY FINANCIAL INFORMATION Other Income and Deductions Year Ended December 31, 2024 2023 2022 (in millions) Other income: NDT net income (a) $ 170 $ — $ — Insurance settlements (b) 23 24 70 Gain on sale of land (c) 6 95 8 Gain on TRA settlement (d) 10 29 — Interest income 65 86 19 All other 38 23 20 Total other income $ 312 $ 257 $ 117 Other deductions: All other $ 21 $ 14 $ 4 Total other deductions $ 21 $ 14 $ 4 ____________ (a) Includes interest, dividends, and net realized and unrealized gains and losses associated with NDTs of the PJM nuclear facilities. Reported in the East segment. (b) For the year ended December 31, 2024, $20 million reported in the Texas segment and $3 million reported in the West segment. For the year ended December 31, 2023, $19 million reported in the West segment and $5 million in the Asset Closure segment. For the year ended December 31, 2022, $62 million reported in the Texas segment, $6 million reported in the West segment, $1 million reported in the Asset Closure segment, and $1 million reported in the Corporate and Other non-segment. (c) For the year ended December 31, 2024, reported in the Asset Closure segment. For the year ended December 31, 2023, $94 million reported in the Asset Closure segment and $1 million reported in the Texas segment. For the year ended December 31, 2022, reported in the Asset Closure segment. (d) Reported in the Corporate and Other. Inventories by Major Category December 31, 2024 2023 (in millions) Materials and supplies $ 533 $ 289 Fuel stock 403 420 Natural gas in storage 34 31 Total inventories $ 970 $ 740 Investments December 31, 2024 2023 (in millions) Nuclear decommissioning trusts $ 4,440 $ 1,951 Assets related to employee benefit plans 14 28 Land investments 42 42 Other investments 16 14 Total investments $ 4,512 $ 2,035 Other Noncurrent Liabilities and Deferred Credits The balance of other noncurrent liabilities and deferred credits consists of the following: December 31, 2024 2023 (in millions) Retirement and other employee benefits (Note 14) $ 224 $ 247 Winter Storm Uri impact (a) 1 26 Identifiable intangible liabilities (Note 7) 155 131 Regulatory liability (b) 452 209 Operating lease liabilities 98 48 Finance lease liabilities 218 227 Liability for third-party remediation 8 17 Accrued severance costs 36 36 Other accrued expenses 64 58 Total other noncurrent liabilities and deferred credits $ 1,256 $ 999 ____________ (a) Includes future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri. (b) As of December 31, 2024, the fair value of the assets contained in the Comanche Peak NDT was higher than the carrying value of our ARO related to our nuclear generation plant decommissioning and recorded as a regulatory liability of $452 million and $209 million, respectively, in other noncurrent liabilities and deferred credits. Supplemental Cash Flow Information The following table reconciles cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows to the amounts reported in the consolidated balance sheets at December 31, 2024 and 2023: December 31, 2024 2023 (in millions) Cash and cash equivalents $ 1,188 $ 3,485 Restricted cash included in current assets (a) 28 40 Restricted cash included in noncurrent assets (a) 6 14 Total cash, cash equivalents and restricted cash $ 1,222 $ 3,539 ____________ (a) Restricted cash consists of amounts related to remediation escrow accounts. Vistra has transferred various asset retirement obligations related to several closed plant sites to a third-party remediation company. As part of certain transfers, Vistra deposits funds into escrow accounts, and the funds are released to the remediation company as milestones are reached in the remediation process. Amounts contractually payable to the third party in exchange for assuming the obligations are included in other current liabilities and other noncurrent liabilities and deferred credits. The following table summarizes our supplemental cash flow information for the years ended December 31, 2024, 2023, and 2022, respectively. Non-cash investing and financing activities also includes activity related to the Energy Harbor Merger. See Note 2 for additional information. Year Ended December 31, 2024 2023 2022 (in millions) Cash payments related to: Interest paid $ 987 $ 636 $ 581 Capitalized interest (77) (37) (29) Interest paid (net of capitalized interest) $ 910 $ 599 $ 552 Non-cash investing and financing activities: Accrued property, plant, and equipment additions (a) $ 258 $ 104 $ 103 Issuance of Series C Preferred Stock as consideration for the repurchase of TRA Rights with a carrying value of $506 million $ — $ 476 $ — Book value of property, plant, and equipment sold, including nuclear fuel $ 117 $ 26 $ — ____________ (a) Represents property, plant, and equipment accruals during the period for which cash has not been paid as of the end of the period. For the years ended December 31, 2024, 2023, and 2022, we paid federal income taxes of $5 million, zero, and $1 million, respectively, paid state income taxes of $59 million, $44 million, and $33 million, respectively, and received state tax refunds of $9 million, $13 million, and $8 million, respectively.

Schedule I - Condensed Financia

Schedule I - Condensed Financial Information of Registrant	12 Months Ended
	Dec. 31, 2024
Condensed Financial Information Disclosure [Abstract]
Schedule I - Condensed Financial Information of Registrant	(a) Our financial statements and financial statement schedules are incorporated under Part II, Item 8 of this annual report on Form 10-K. (b) SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT VISTRA CORP. (PARENT) SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENTS OF OPERATIONS (Millions of Dollars) Year Ended December 31, 2024 2023 2022 Depreciation and amortization $ — $ (15) $ (16) Selling, general, and administrative expenses (102) (80) (69) Operating loss (102) (95) (85) Other income 28 31 6 Impacts of Tax Receivable Agreement (5) (164) (128) Loss before income tax benefit (79) (228) (207) Income tax benefit 17 58 47 Equity in earnings (losses) of subsidiaries, net of tax 2,721 1,663 (1,067) Net income (loss) $ 2,659 $ 1,493 $ (1,227) See Notes to the Condensed Financial Statements. VISTRA CORP. (PARENT) SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED BALANCE SHEETS (Millions of Dollars) December 31, 2024 2023 ASSETS Cash and cash equivalents $ 22 $ 31 Trade accounts receivable — affiliates 13 — Income taxes receivable 8 6 Total current assets 43 37 Investment in affiliated companies 4,670 4,507 Property, plant, and equipment — net 2 3 Accumulated deferred income taxes 960 1,086 Other noncurrent assets 3 — Total assets $ 5,678 $ 5,633 LIABILITIES AND EQUITY Trade accounts payable $ 8 $ 12 Accounts payable —affiliates 27 91 Accrued taxes 9 12 Other current liabilities 27 12 Total current liabilities 71 127 Tax Receivable Agreement obligations 14 164 Other noncurrent liabilities and deferred debits 10 20 Total liabilities 95 311 Total stockholders' equity 5,583 5,322 Total liabilities and equity $ 5,678 $ 5,633 See Notes to the Condensed Financial Statements. VISTRA CORP. (PARENT) SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENTS OF CASH FLOWS (Millions of Dollars) Year Ended December 31, 2024 2023 2022 Cash flows — operating activities: Cash used in operating activities $ (37) $ (31) $ (27) Cash flows — investing activities: Dividend received from subsidiaries 1,705 1,625 1,775 Proceeds from sales of subsidiary transferable ITCs 150 — — Cash provided by investing activities 1,855 1,625 1,775 Cash flows — financing activities: Stock repurchases (1,266) (1,245) (1,949) Dividends paid to common stockholders (305) (313) (302) Dividends paid to preferred stockholders (173) (150) (151) TRA Repurchase and tender offer - return of capital (122) — — Other, net 39 91 40 Cash used in financing activities (1,827) (1,617) (2,362) Net change in cash, cash equivalents and restricted cash (9) (23) (614) Cash, cash equivalents and restricted cash — beginning balance 31 54 668 Cash, cash equivalents and restricted cash — ending balance $ 22 $ 31 $ 54 See Notes to the Condensed Financial Statements. NOTES TO CONDENSED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION The accompanying unconsolidated condensed balance sheets, statements of net loss and cash flows present results of operations and cash flows of Vistra Corp. (Parent). Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been omitted pursuant to the rules of the SEC. Because the unconsolidated condensed financial statements do not include all of the information and footnotes required by U.S. GAAP, they should be read in conjunction with the financial statements and related notes of Vistra Corp. and Subsidiaries included in the annual report on Form 10-K for the year ended December 31, 2024. Vistra Corp.'s subsidiaries have been accounted for under the equity method. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. dollars unless otherwise indicated. Vistra Corp. (Parent) files a consolidated U.S. federal income tax return. Consolidated tax expenses or benefits and deferred tax assets or liabilities have been allocated to the respective subsidiaries in accordance with the accounting rules that apply to separate financial statements of subsidiaries. 2. RESTRICTIONS ON SUBSIDIARIES The Vistra Operations Credit Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of December 31, 2024, Vistra Operations can distribute approximately $8.2 billion to Vistra Corp. (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 Vistra Corp. (Parent) of approximately $1.705 billion, $1.625 billion, and $1.775 billion during the years ended December 31, 2024, 2023, and 2022, respectively. Additionally, Vistra Operations may make distributions to Vistra Corp. (Parent) in amounts sufficient for Vistra Corp. (Parent) to make any payments required under the TRA or the Tax Matters Agreement or, to the extent arising out of Vistra Corp. (Parent)'s ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses. As of December 31, 2024, all of the restricted net assets of Vistra Operations may be distributed to Vistra Corp. (Parent). 3. GUARANTEES Vistra Corp. (Parent) has entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. As of December 31, 2024, there are no material outstanding claims related to guarantee obligations of Vistra Corp. (Parent), and Vistra Corp. (Parent) does not anticipate it will be required to make any material payments under these guarantees in the near term. 4. DIVIDEND RESTRICTIONS Under applicable law, Vistra Corp. (Parent) is prohibited from paying any dividend to the extent that immediately following payment of such dividend there would be no statutory surplus or Vistra Corp. (Parent) would be insolvent. Vistra Corp. (Parent) received $1.705 billion, $1.625 billion, and $1.775 billion in dividends from its consolidated subsidiaries in the years ended December 31, 2024, 2023, and 2022, respectively.

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Pay vs Performance Disclosure
Net income (loss) attributable to Vistra	$ 2,659	$ 1,493	$ (1,227)

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended	12 Months Ended
	Dec. 31, 2024 shares	Dec. 31, 2024 shares
Trading Arrangements, by Individual
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false
Kristopher Moldovan [Member]
Trading Arrangements, by Individual
Material Terms of Trading Arrangement		On December 17, 2024, Kristopher Moldovan, Executive Vice President and Chief Financial Officer of the Company, entered into a trading plan intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) of the Exchange Act (the 10b5-1 Plan). The 10b5-1 Plan provides for the potential exercise and sale of options for up to 139,925 shares of our common stock pursuant to stock option awards that will be expiring over the next several years. Any sales are subject to certain price limitations set forth in the 10b5-1 Plan such that the actual number of shares sold could vary if certain minimum stock prices are not met. The 10b5-1 Plan will become effective on March 18, 2025 and will terminate on November 28, 2025, subject to earlier termination as provided in the 10b5-1 Plan. The 10b5-1 Plan was entered into during an open insider trading window in accordance with our Transactions in Securities Policy.
Name	Kristopher Moldovan
Title	Executive Vice President and Chief Financial Officer
Rule 10b5-1 Arrangement Adopted	true
Adoption Date	December 17, 2024
Expiration Date	November 28, 2025
Arrangement Duration	255 days
Aggregate Available	139,925	139,925

Insider Trading Policies and Pr

Insider Trading Policies and Procedures	12 Months Ended
	Dec. 31, 2024
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

Cybersecurity Risk Management a

Cybersecurity Risk Management and Strategy Disclosure	12 Months Ended
	Dec. 31, 2024
Cybersecurity Risk Management, Strategy, and Governance [Line Items]
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]	The Company has a cybersecurity and incident response program designed to assess, identify, and manage material risks from cybersecurity threats, including matters related to the cybersecurity of the Company's critical infrastructure, data, or information technology systems and the Company's actions to prepare for, identify, assess, respond, mitigate and remediate material cyber, information security, or technology risks (collectively referred to as Information Security). This program includes: • operating a Cyber Security Operations Center; • raising employee awareness through annual general and job-specific cybersecurity trainings and employee phishing simulations; • maintaining defined cyber incident response plans; • enhancing security measures to protect our systems and data; • evolving monitoring capabilities to improve early detection and rapid response to potential cyber threats; and • adapting to new work environments that include off-site work through mitigation of remote network risk to our internal systems, assets, or data. Cybersecurity represents an important component of the Company's overall approach to enterprise risk management and is integrated into the risk management process and ongoing assessment. In addition to an internal security program, we strive to stay ahead of the threat landscape by actively monitoring and conducting due diligence on key third-party vendors' Information Security programs and risks. This includes qualitative assessments to gain a deeper understanding of their security posture and potential vulnerabilities. We make strategic investments in our perimeter and internal defenses, cyber security operations center, and regulatory compliance activities with the advice of consultants and third parties. Moreover, to minimize risk, we maintain an insurance policy that provides coverage for matters relating to Information Security. Vistra's Chief Information Officer (CIO) ensures Information Security is built into the Company's larger technology strategy and oversees our Chief Information Security Officer (CISO). Our CISO and his Information Security team are responsible for leading the enterprise-wide information security strategy, policy, standards, architecture, and processes. Additionally, our Cyber Incident Response Teams under the CISO are responsible for monitoring and analyzing the Company's cybersecurity posture in partnership with Risk and Legal. The CIO and CISO collaborate with our internal audit department and external consultants to review information technology-related risks (based upon the National Institute of Standards and Technology (NIST) Cybersecurity Framework) as part of the overall Vistra cyber risk management process. Through these processes, the CIO and CISO are informed about and monitor the prevention, detection, mitigation, and remediation of cybersecurity threats. We also participate in industry groups and with regulators to gain additional knowledge, including, but not limited to, the Federal Bureau of Investigation, U.S. Cybersecurity and Infrastructure Security Agency, U.S. Department of Homeland Security, Electricity Information Sharing and Analysis Center, U.S. Cyber Emergency Response Team, the NRC and NERC. We apply the knowledge gained through industry partnerships, government organizations, external cyber risk platforms, and program maturity assessments to improve our processes to detect and mitigate cyber threats. As of the date of this report, we have not identified any impacts from cybersecurity threats, including those from any previous cybersecurity incidents, that have materially affected our results of operation or financial condition. However, despite our efforts, we cannot eliminate all risks from cybersecurity threats, or provide assurances that we have not experienced undetected cybersecurity incidents. For additional information on risks from cybersecurity threats, see Item 1A. Risk Factors .
Cybersecurity Risk Management Processes Integrated [Flag]	true
Cybersecurity Risk Management Processes Integrated [Text Block]	Cybersecurity represents an important component of the Company's overall approach to enterprise risk management and is integrated into the risk management process and ongoing assessment. In addition to an internal security program, we strive to stay ahead of the threat landscape by actively monitoring and conducting due diligence on key third-party vendors' Information Security programs and risks. This includes qualitative assessments to gain a deeper understanding of their security posture and potential vulnerabilities. We make strategic investments in our perimeter and internal defenses, cyber security operations center, and regulatory compliance activities with the advice of consultants and third parties. Moreover, to minimize risk, we maintain an insurance policy that provides coverage for matters relating to Information Security.
Cybersecurity Risk Management Third Party Engaged [Flag]	true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag]	true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]	false
Cybersecurity Risk Board of Directors Oversight [Text Block]	The Sustainability and Risk Committee of the Board has been delegated oversight responsibility of Vistra's Information Security. Vistra periodically engages third-party advisors to provide cybersecurity oversight and tabletop training to the full Board to further our commitment to responsible oversight of cybersecurity risk management. At least quarterly, our CIO reports to the Board on our Information Security program, including cybersecurity risks and threats (including the emerging threat landscape), an assessment of our Information Security program, and the status of projects to strengthen our Information Security program. In furtherance of our commitment to responsible oversight of cybersecurity risk management, in 2023, the Board appointed a director who brings extensive cybersecurity expertise to the Board. Our CIO serves as head of Vistra's Technology Services and is responsible for ensuring the reliability, security, and continued development of the Company's technology platforms and delivering new solutions to support the business. The CIO has served in various senior information technology roles in public companies for over 30 years, including Keurig Dr. Pepper Inc., General Motors, Pfizer, and Electronic Data Systems. Our CISO has over 23 years of information technology experience. He has held technology positions across various areas — including infrastructure management, application management, architecture, operations, and cybersecurity — and brings expertise from Farmers Insurance and Zurich Insurance.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]	The Sustainability and Risk Committee of the Board has been delegated oversight responsibility of Vistra's Information Security.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]	The Sustainability and Risk Committee of the Board has been delegated oversight responsibility of Vistra's Information Security. Vistra periodically engages third-party advisors to provide cybersecurity oversight and tabletop training to the full Board to further our commitment to responsible oversight of cybersecurity risk management. At least quarterly, our CIO reports to the Board on our Information Security program, including cybersecurity risks and threats (including the emerging threat landscape), an assessment of our Information Security program, and the status of projects to strengthen our Information Security program. In furtherance of our commitment to responsible oversight of cybersecurity risk management, in 2023, the Board appointed a director who brings extensive cybersecurity expertise to the Board.
Cybersecurity Risk Role of Management [Text Block]	The CIO and CISO collaborate with our internal audit department and external consultants to review information technology-related risks (based upon the National Institute of Standards and Technology (NIST) Cybersecurity Framework) as part of the overall Vistra cyber risk management process. Through these processes, the CIO and CISO are informed about and monitor the prevention, detection, mitigation, and remediation of cybersecurity threats. We also participate in industry groups and with regulators to gain additional knowledge, including, but not limited to, the Federal Bureau of Investigation, U.S. Cybersecurity and Infrastructure Security Agency, U.S. Department of Homeland Security, Electricity Information Sharing and Analysis Center, U.S. Cyber Emergency Response Team, the NRC and NERC. We apply the knowledge gained through industry partnerships, government organizations, external cyber risk platforms, and program maturity assessments to improve our processes to detect and mitigate cyber threats. As of the date of this report, we have not identified any impacts from cybersecurity threats, including those from any previous cybersecurity incidents, that have materially affected our results of operation or financial condition. However, despite our efforts, we cannot eliminate all risks from cybersecurity threats, or provide assurances that we have not experienced undetected cybersecurity incidents. For additional information on risks from cybersecurity threats, see Item 1A. Risk Factors . The Sustainability and Risk Committee of the Board has been delegated oversight responsibility of Vistra's Information Security. Vistra periodically engages third-party advisors to provide cybersecurity oversight and tabletop training to the full Board to further our commitment to responsible oversight of cybersecurity risk management. At least quarterly, our CIO reports to the Board on our Information Security program, including cybersecurity risks and threats (including the emerging threat landscape), an assessment of our Information Security program, and the status of projects to strengthen our Information Security program. In furtherance of our commitment to responsible oversight of cybersecurity risk management, in 2023, the Board appointed a director who brings extensive cybersecurity expertise to the Board. Our CIO serves as head of Vistra's Technology Services and is responsible for ensuring the reliability, security, and continued development of the Company's technology platforms and delivering new solutions to support the business. The CIO has served in various senior information technology roles in public companies for over 30 years, including Keurig Dr. Pepper Inc., General Motors, Pfizer, and Electronic Data Systems. Our CISO has over 23 years of information technology experience. He has held technology positions across various areas — including infrastructure management, application management, architecture, operations, and cybersecurity — and brings expertise from Farmers Insurance and Zurich Insurance.
Cybersecurity Risk Management Positions or Committees Responsible [Flag]	true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	Vistra's Chief Information Officer (CIO) ensures Information Security is built into the Company's larger technology strategy and oversees our Chief Information Security Officer (CISO). Our CISO and his Information Security team are responsible for leading the enterprise-wide information security strategy, policy, standards, architecture, and processes. Additionally, our Cyber Incident Response Teams under the CISO are responsible for monitoring and analyzing the Company's cybersecurity posture in partnership with Risk and Legal.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]	Our CIO serves as head of Vistra's Technology Services and is responsible for ensuring the reliability, security, and continued development of the Company's technology platforms and delivering new solutions to support the business. The CIO has served in various senior information technology roles in public companies for over 30 years, including Keurig Dr. Pepper Inc., General Motors, Pfizer, and Electronic Data Systems. Our CISO has over 23 years of information technology experience. He has held technology positions across various areas — including infrastructure management, application management, architecture, operations, and cybersecurity — and brings expertise from Farmers Insurance and Zurich Insurance.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]	Our CIO serves as head of Vistra's Technology Services and is responsible for ensuring the reliability, security, and continued development of the Company's technology platforms and delivering new solutions to support the business.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]	true

Business And Significant Acco_2

Business And Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2024
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The 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 2023 Form 10-K. All intercompany items and transactions have been eliminated in consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. dollars unless otherwise indicated. Certain prior period amounts have been reclassified to conform with the current year presentation.
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.
Business Combinations	Business Combinations The Company accounts for its business combinations in accordance with ASC 805, Business Combinations
Derivative Instruments and Mark-to-Market Accounting	Derivative Instruments and Mark-to-Market Accounting We enter derivative instruments, including commodity contracts and interest rate swaps, to manage commodity price and interest rate risks. All our derivatives are accounted for as economic hedges and are recorded at estimated fair value in the consolidated balance sheets with changes in fair value recorded as gains or losses in the earnings of the period in which they occur. No derivative positions are accounted for as cash flow or fair value hedges. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed. A commodity-related derivative contract may be designated as a normal purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement. We report derivative instruments in the consolidated balance sheets as commodity and other derivative contractual assets or liabilities on a gross basis without taking into consideration netting arrangements we have with counterparties. We maintain standardized master netting agreements with certain counterparties that allow for the right to offset derivative assets and liabilities, receivables and payables on settled positions, and collateral to reduce credit exposure between us and the counterparty. Generally, margin deposits that contractually offset derivative instruments are reported separately in the consolidated balance sheets, except for certain margin amounts related to changes in fair value on CME transactions that are legally characterized as settlement of forward exposure rather than collateral.
Revenue Recognition	Revenue Recognition Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes delivered or services provided. Sales tax is excluded from revenue. Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Estimated amounts are adjusted when actual usage is known and billed.
Government Assistance	Government Assistance The Company qualifies for tax incentives through eligible construction spending and production through the Inflation Reduction Act of 2022 (IRA). These tax incentives generally provide for transferable tax credits upon the applicable qualifying event for the credit type, typically production or in-service date. We account for transferable ITCs and PTCs we expect to receive by analogy to the grant model within International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance
Major Maintenance Costs	Major Maintenance Costs Major maintenance costs incurred during generation plant outages are deferred and amortized into operating costs over the period between the major maintenance outages for the respective asset. Other routine costs of maintenance activities are charged to expense as incurred and reported as operating costs in the consolidated statements of operations.
Defined Benefit Plans and OPEB Plans	Defined Benefit Pension Plans and OPEB Plans
Stock-Based Compensation	Stock-Based Compensation Stock-based compensation is accounted for in accordance with ASC 718, Compensation - Stock Compensation.
Sales and Excise Taxes	Sales and Excise Taxes Sales and excise taxes are accounted for as "pass through" items in the consolidated balance sheets with no effect on the consolidated statements of operations ( i.e. , the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability to the taxing jurisdiction in other current liabilities in the consolidated statements of operations).
Franchise and Revenue-Based Taxes	Franchise and Revenue-Based Taxes Unlike sales and excise taxes, franchise and revenue-based taxes are not "pass through" items. These taxes are imposed on us by state and local taxing authorities, based on revenues or kWh delivered, as a cost of doing business and are recorded as an expense. Rates we charge to customers are intended to recover our costs, including the franchise and revenue-based receipt taxes, but we are not acting as an agent to collect the taxes from customers. We report franchise and revenue-based taxes in SG&A expense in the consolidated statements of operations.
Income Taxes	Income Taxes
Accounting for Contingencies	Accounting for Contingencies
Cash and Cash Equivalents	Cash and Cash Equivalents For purposes of reporting cash and cash equivalents, temporary cash investments purchased with an original maturity of three months or less are considered cash equivalents.
Property, Plant and Equipment	Property, Plant, and Equipment Property, plant, and equipment has been recorded at estimated fair values at the time of acquisition for assets acquired or at cost for capital improvements and individual facilities developed. Significant improvements or additions to our property, plant, and equipment that extend the life of the respective asset are capitalized at cost, while other costs are expensed when incurred. The cost of self-constructed property additions includes materials and both direct and indirect labor, including payroll-related costs. Interest related to qualifying construction projects and qualifying software projects is capitalized in accordance with accounting guidance related to capitalization of interest cost.
Nuclear Fuel	Nuclear Fuel Nuclear fuel is capitalized and reported as a component of our property, plant, and equipment in the consolidated balance sheets. Amortization of nuclear fuel is calculated on the units-of-production method and is reported as a component of fuel, purchased power costs, and delivery fees in the consolidated statements of operations.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets
Goodwill and Intangible Assets with Indefinite Lives	Goodwill and Intangible Assets with Indefinite Lives
Asset Retirement Obligations (ARO)	Asset Retirement Obligations (ARO)
Inventories	Inventories
Nuclear Decommissioning Trust (NDT) Investments and Regulatory Assets or Liability	Nuclear Decommissioning Trust (NDT) Investments and Regulatory Assets or Liability The NRC is responsible for regulating all nuclear power plants in the U.S. This regulatory oversight results in specific accounting considerations for nuclear plant decommissioning. Our NDTs hold funds primarily for the ultimate decommissioning of our nuclear power plants. Each unit has its own NDT and funds from one unit may not be used to fund decommissioning obligations of another unit. Decommissioning costs associated with the Comanche Peak nuclear generation facility in Texas are being recovered from Oncor Electric Delivery Company LLC's (Oncor) customers as a delivery fee surcharge over the life of the plant and deposited by Vistra (and prior to the Effective Date, a subsidiary of TCEH) in the NDT. As a result, the asset retirement obligation and the investments in the decommissioning trust are accounted for as rate regulated operations. Changes in these accounts, including investment income and accretion expense, do not impact net income, but are reported as a change in the corresponding regulatory asset or liability balance that is reflected in the consolidated balance sheets as other noncurrent assets or other noncurrent liabilities and deferred credits. The NDTs associated with our PJM nuclear facilities have been funded with amounts collected from the previous owners and their respective utility customers. Any shortfall of funds necessary for decommissioning the PJM nuclear facilities, determined for each generating station unit, are required to be funded by us. Investments in the PJM NDTs are carried at fair value and gains and losses are recognized as other income or other deductions in the consolidated statements of operations. NDTs are invested in diversified portfolios of securities generally designed to achieve a return sufficient to fund the future decommissioning work. We retain any funds remaining in the trusts of the PJM nuclear facilities after all decommissioning has been completed.
Noncontrolling Interest and Redeemable Noncontrolling Interest in Subsidiary	Noncontrolling Interest and Redeemable Noncontrolling Interest in Subsidiary A noncontrolling interest in a consolidated subsidiary represents the portion of the equity in a subsidiary not attributable, directly or indirectly, to the Company. Noncontrolling interests are presented as a separate component of equity in the consolidated balance sheets and the presentation of net income is modified to present earnings attributed to controlling and noncontrolling interests. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. See Note 2 for additional information.
Treasury Stock	Treasury Stock
Leases	Leases At the inception of a contract we determine if it is or contains a lease, which involves the contract conveying the right to control the use of explicitly or implicitly identified property, plant, or equipment for a period of time in exchange for consideration. Right-of-use (ROU) assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized at the commencement date of the underlying lease based on the present value of lease payments over the lease term. We use our secured incremental borrowing rate based on the information available at the lease commencement date to determine the present value of lease payments. Operating leases are included in other noncurrent assets, other current liabilities, and other noncurrrent liabilities and deferred credits on the consolidated balance sheet. Finance leases are included in property, plant, and equipment, other current liabilities and other noncurrent liabilities and deferred credits on the consolidated balance sheet. Lease term includes options to extend or terminate the lease when it is reasonably certain that we will exercise the option. We apply the practical expedient permitted by ASC 842, Leases to not separate lease and non-lease components for a majority of our lease asset classes. Leases with an initial lease term of 12 months or less are not recorded on the balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term.
Adoption of Accounting Standards in 2024	Adoption of Accounting Standards in 2024 Improvements to Reportable Segment Disclosures In November 2023, the Financial Accounting Standards Board (FASB) issued ASU No. 2023-07, Segment Reporting (Topic 280), Improvements to Reportable Segment Disclosures , to improve the disclosures about reportable segments and add more detailed information about a reportable segment's expenses. The amendments in the ASU require public entities to disclose on an annual and interim basis significant segment expenses that are regularly provided to the chief operating decision maker (CODM) and included within each reported measure of segment profit or loss, other segment items by reportable segment, the title and position of the CODM, and an explanation of how the CODM uses the reported measures of segment profit or loss in assessing segment performance and deciding how to allocate resources. The ASU does not change the definition of a segment, the method for determining segments, the criteria for aggregating operating segments into reportable segments, or the current specifically enumerated segment expenses that are required to be disclosed. The Company adopted the amendments in this ASU for its fiscal year ended December 31, 2024 which resulted in disclosure of significant segment expenses such as segment fuel, purchased power costs, and delivery fees, operating costs, and selling, general, and administrative expenses. The amendment was applied retrospectively to all prior periods presented. See Note 19 for additional information. Recent Accounting Pronouncements Improvements to Income Tax Disclosures In December 2023, the FASB issued ASU No. 2023-09 (ASU 2023-09), Income Taxes (Topic 740): Improvements to Income Tax Disclosures to enhance the transparency and decision usefulness of income tax disclosures. ASU 2023-09 is effective for annual periods beginning after December 15, 2024 on a prospective basis. Early adoption is permitted. As the amendments apply to income tax disclosures only, the Company does not expect adoption to have a material impact on the consolidated financial statements. Expense Disaggregation Disclosures In November 2024, the FASB issued ASU No. 2024-03 (ASU 2024-03), Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses to improve disclosures by providing additional information about certain expenses in the notes to financial statements in interim and annual reporting periods. Among other provisions, the new standard requires disclosure of disaggregated amounts for expenses such as employee compensation, depreciation, and intangible asset amortization included in each expense caption presented on the face of the income statement. ASU 2024-03 is effective for annual periods beginning after December 15, 2026 and interim periods within annual reporting periods beginning after December 15, 2027 and can be applied prospectively or retrospectively. Early adoption is permitted. We are currently evaluating the impact this ASU will have on the consolidated financial statements and related disclosures. Recent Developments In January, a fire occurred at our Moss Landing 300 MW battery energy storage facility in the West segment. We are still investigating the cause of the fire and impacts, including insurance claim recoveries, but expect to write off approximately $400 million of plant value to depreciation expense in the first quarter of 2025, representing the remaining net book value of the facility. Moss Landing 300 is part of the Moss Landing complex, which includes two other battery facilities and a gas plant, with an aggregate book value of approximately $1 billion. While the gas plant is operational, the other two battery facilities remain offline as we investigate the fire. We will continue to assess if a triggering event has occurred to evaluate impairment for the other complex assets.

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2024
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. Fair Value as of March 1, 2024 Measurement Period Adjustments recorded through December 31, 2024 (in millions) Cash and cash equivalents $ 35 $ 5 Trade accounts receivables, inventories, prepaid expenses, and other current assets 544 6 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 61 53 Total identifiable assets acquired 8,850 65 Trade accounts payable and other current liabilities 320 57 Long-term debt, including amounts due currently 413 — Commodity and other derivative contractual liabilities (d) 179 — Accumulated deferred income taxes 1,314 (50) Asset retirement obligations (e) 1,368 — Identifiable intangible liabilities 55 (18) Other noncurrent liabilities and deferred credits 18 6 Total identifiable liabilities assumed 3,667 (5) Identifiable net assets acquired 5,183 70 Goodwill (f) 224 (70) Net assets acquired $ 5,407 ____________ (a) Investments represent securities held in nuclear decommissioning trusts (NDT) for the purpose of funding the future retirement and decommissioning of the PJM nuclear generation facilities. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC. They are valued using a market approach (Level 1 or Level 2 depending on security). (b) Acquired property, plant, and equipment are valued using a combination of an income approach and a market approach. The income approach utilized a discounted cash flow analysis based upon a debt-free, free cash flow model (Level 3). (c) Includes acquired nuclear fuel supply contracts valued based on contractual cash flow projections over approximately five years compared with cash flows based on current market prices with the resulting difference discounted to present value (Level 3). Also includes acquired retail customer relationships which are valued based on discounted cash flow analysis of acquired customers and estimated attrition rates (Level 3). (d) Acquired derivatives are valued using the methods described in Note 11 (Level 1, Level 2, or Level 3). Contracts with terms that were not at current market prices are also valued using a discounted cash flow analysis (Level 3). (e) Asset retirement obligations are valued using a discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning methods and are based on decommissioning cost studies (Level 3). (f) The excess of the consideration transferred over the fair value of identifiable assets acquired and liabilities assumed is recorded as goodwill. Goodwill represents expected synergies to be generated from combining operations of Energy Harbor with Vistra. None of the Goodwill is deductible for income tax purposes.
Schedule of Business Acquisitions, Pro Forma Information	The following unaudited pro forma financial information for the years ended December 31, 2024 and 2023 assumes that the Energy Harbor Merger occurred on January 1, 2023. The unaudited pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the Energy Harbor Merger been completed on January 1, 2023, nor is the unaudited pro forma financial information indicative of future results of operations, which may differ materially from the pro forma financial information presented here. Year Ended December 31, 2024 2023 (in millions) Revenues $ 17,948 $ 17,148 Net income $ 2,901 $ 1,398

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2024
Revenue from Contract with Customer [Abstract]
Schedule of Disaggregation of Revenue	The following tables disaggregate our revenue by major source: Year Ended December 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 $ 8,064 $ — $ — $ — $ — $ — $ 8,064 Retail energy charge in Northeast/Midwest (a) 3,595 — — — — — 3,595 Wholesale generation revenue from ISO/RTO — 399 1,351 228 — — 1,978 Capacity revenue from ISO/RTO (b) — — 74 — — — 74 Revenue from other wholesale contracts — 422 398 230 — — 1,050 Total revenue from contracts with customers 11,659 821 1,823 458 — — 14,761 Other revenues: Transferable PTC revenues (c) — 292 264 — — — 556 Hedging revenues — realized 1,241 (453) 31 84 (8) — 895 Hedging revenue — unrealized (168) 700 143 329 9 — 1,013 Intangible amortization and other revenues 1 — (4) — — 2 (1) Intersegment sales (d) 64 4,034 3,404 6 — (7,508) — Total other revenues 1,138 4,573 3,838 419 1 (7,506) 2,463 Total revenues $ 12,797 $ 5,394 $ 5,661 $ 877 $ 1 $ (7,506) $ 17,224 ____________ (a) Includes ten months of revenue associated with operations acquired in the Energy Harbor Merger. (b) Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $126 million of capacity sold offset by $52 million of capacity purchased. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $139 million offset by $116 million of capacity sold within the East segment. (c) Represents transferable PTCs generated from qualifying nuclear and solar assets during the period. (d) East segment includes $195 million of intersegment unrealized net losses, and Texas and West segments include $74 million and $4 million, respectively, of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment. Year Ended December 31, 2023 Retail Texas East West Asset Closure Eliminations / Corporate and Other Consolidated (in millions) Revenue from contracts with customers: Retail energy charge in ERCOT $ 7,674 $ — $ — $ — $ — $ — $ 7,674 Retail energy charge in Northeast/Midwest 1,642 — — — — — 1,642 Wholesale generation revenue from ISO/RTO — 1,190 1,298 421 — — 2,909 Capacity revenue from ISO/RTO (a) — — 98 — — — 98 Revenue from other wholesale contracts — 505 797 179 — — 1,481 Total revenue from contracts with customers 9,316 1,695 2,193 600 — — 13,804 Other revenues: Transferable PTC revenues (b) — 10 — — — — 10 Hedging revenues — realized 1,063 (885) 43 67 (36) — 252 Hedging revenue — unrealized 191 (714) 958 243 36 — 714 Intangible amortization and other revenues 2 — (5) — — 2 (1) Intersegment sales (c) — 3,873 2,701 4 — (6,578) — Total other revenues 1,256 2,284 3,697 314 — (6,576) 975 Total revenues $ 10,572 $ 3,979 $ 5,890 $ 914 $ — $ (6,576) $ 14,779 ____________ (a) Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $233 million of capacity sold offset by $135 million of capacity purchased. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $82 million offset by $73 million of capacity sold within the East segment. (b) Represents transferable PTCs generated from qualifying solar assets during the period. (c) East segment includes $814 million of intersegment unrealized net gains, and Texas and West segments include $48 million and $6 million, respectively, of intersegment unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment. Year Ended December 31, 2022 Retail Texas East West Asset Closure Eliminations / Corporate and Other Consolidated (in millions) Revenue from contracts with customers: Retail energy charge in ERCOT $ 6,971 $ — $ — $ — $ — $ — $ 6,971 Retail energy charge in Northeast/Midwest 2,139 — — — — — 2,139 Wholesale generation revenue from ISO/RTO — 1,277 1,987 467 562 — 4,293 Capacity revenue from ISO/RTO (a) — — 76 — 27 — 103 Revenue from other wholesale contracts — 696 1,256 151 22 — 2,125 Total revenue from contracts with customers 9,110 1,973 3,319 618 611 — 15,631 Other revenues: Hedging revenues — realized 875 (67) (247) 35 (333) 1 264 Hedging revenue — unrealized (532) (637) (770) (326) 102 — (2,163) Intangible amortization and other revenues 2 — (6) — — — (4) Intersegment sales (b) — 2,609 2,133 9 4 (4,755) — Total other revenues 345 1,905 1,110 (282) (227) (4,754) (1,903) Total revenues $ 9,455 $ 3,878 $ 4,429 $ 336 $ 384 $ (4,754) $ 13,728 ____________ (a) Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $361 million of capacity sold offset by $285 million of capacity purchased. The Asset Closure segment includes $27 million of capacity sold. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs, and delivery fees in the consolidated statement of operations includes capacity purchased of $212 million offset by $167 million of capacity sold within the East segment. (b) Texas and East segments include $780 million and $45 million, respectively, of intersegment unrealized net losses and West and Asset Closure segments include $2 million and $4 million respectively, of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.
Schedule of Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction	As of December 31, 2024, we have future fixed fee performance obligations that are unsatisfied, or partially unsatisfied, relating to capacity auction volumes awarded through capacity auctions held by the ISO/RTO or contracts with customers for which the total consideration is fixed and determinable at contract execution. Capacity revenues are recognized as the performance obligations to make capacity available to the related ISOs/RTOs or counterparties are met. 2025 2026 2027 2028 2029 2030 and Thereafter Total (in millions) Remaining performance obligations $ 1,123 $ 825 $ 289 $ 122 $ 62 $ 548 $ 2,969
Schedule of Accounts, Notes, Loans and Financing Receivable	Trade Accounts Receivable December 31, December 31, (in millions) Wholesale and retail trade accounts receivable $ 2,061 $ 1,735 Allowance for credit losses (79) (61) Trade accounts receivable — net $ 1,982 $ 1,674 Trade accounts receivable from contracts with customers — net $ 1,514 $ 1,239 Other trade accounts receivable — net 468 435 Total trade accounts receivable — net $ 1,982 $ 1,674 Allowance for Credit Losses on Accounts Receivable Year Ended December 31, 2024 2023 2022 (in millions) Allowance for credit losses on accounts receivable at beginning of period $ 61 $ 65 $ 45 Increase for bad debt expense 183 164 179 Decrease for account write-offs (165) (168) (159) Allowance for credit losses on accounts receivable at end of period $ 79 $ 61 $ 65

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2024
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The components of our income tax expense (benefit) are as follows: Year Ended December 31, 2024 2023 2022 (in millions) Current: U.S. Federal $ 2 $ (1) $ 2 State 46 52 7 Total current 48 51 9 Deferred: U.S. Federal 561 421 (304) State 46 36 (55) Total deferred 607 457 (359) Total $ 655 $ 508 $ (350)
Schedule of Effective Income Tax Rate Reconciliation	Reconciliation of income taxes computed at the U.S. federal statutory rate to income tax expense (benefit) recorded: Year Ended December 31, 2024 2023 2022 (in millions) Income (loss) before income taxes $ 3,467 $ 2,000 $ (1,560) U.S. federal statutory rate 21 % 21 % 21 % Income taxes at the U.S. federal statutory rate 728 420 (328) State tax, net of federal benefit 80 86 (19) Nondeductible TRA accretion 2 41 18 Transferable PTC revenues (115) (2) — Equity awards (53) (3) (3) Valuation allowance (2) (20) (8) Release of Uncertain Tax Positions — (35) — Other 15 21 (10) Income tax expense (benefit) $ 655 $ 508 $ (350) Effective tax rate 18.9 % 25.4 % 22.4 %
Schedule of Deferred Tax Assets and Liabilities	Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2024 and 2023 are as follows: December 31, 2024 2023 (in millions) Noncurrent Deferred Income Tax Assets Tax credit carryforwards $ 86 $ 84 Loss carryforwards 949 1,081 Identifiable intangible assets 340 380 Long-term debt 225 173 Employee benefit obligations 133 117 Commodity contracts and interest rate swaps 383 664 Other 36 33 Total deferred tax assets $ 2,152 $ 2,532 Noncurrent Deferred Income Tax Liabilities Property, plant, and equipment 2,765 1,264 Total deferred tax liabilities 2,765 1,264 Valuation allowance 75 46 Net Deferred Income Tax Asset (Liability) $ (688) $ 1,222
Schedule of Unrecognized Tax Benefits Roll Forward	The following table summarizes the changes to the uncertain tax positions, reported in accumulated deferred income taxes and other current liabilities in the consolidated balance sheets for the years ended December 31, 2024, 2023, and 2022. Year Ended December 31, 2024 2023 2022 (in millions) Balance at beginning of period, excluding interest and penalties $ — $ 36 $ 38 Additions based on tax positions related to prior years 4 — — Reductions based on tax positions related to prior years — — (1) Reductions related to the lapse of the tax statute of limitations — (35) — Settlements with taxing authorities — (1) (1) Balance at end of period, excluding interest and penalties $ 4 $ — $ 36

Property, Plant, and Equipment

Property, Plant, and Equipment (Tables)	12 Months Ended
	Dec. 31, 2024
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	December 31, 2024 2023 (in millions) Power generation and structures $ 22,783 $ 17,297 Land 603 572 Office and other equipment 160 159 Total 23,546 18,028 Less accumulated depreciation (8,020) (6,657) Net of accumulated depreciation 15,526 11,371 Finance lease right-of-use assets (net of accumulated amortization) 153 160 Nuclear fuel (net of accumulated amortization of $409 million and $120 million) 1,434 379 Construction work in progress 1,060 522 Property, plant, and equipment — net $ 18,173 $ 12,432
Schedule of Planned Retirements of Generation Capacity	The following are all of our facilities that have either been retired, or that have announced retirement dates. Operation results for plants with defined retirement dates are included in our Asset Closure segment at the beginning of the calendar year the retirement is expected to occur. Facility Location ISO/RTO Fuel Type Net Generation Capacity (MW) Announced Retirement Date (a) Segment Baldwin Baldwin, IL MISO Coal 1,185 By the end of 2027 East Coleto Creek Goliad, TX ERCOT Coal 650 By the end of 2027 (b) 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 Joppa Joppa, IL MISO Coal 802 Retired September 1, 2022 Asset Closure Joppa Joppa, IL MISO Natural Gas 221 Retired September 1, 2022 Asset Closure Zimmer Moscow, OH PJM Coal 1,300 Retired June 1, 2022 Asset Closure Total 7,486 ____________ (a) Generation facilities may retire earlier than expected dates disclosed if economic or other conditions dictate. (b) Following the retirement of Coleto Creek as a coal-fueled plant, the Company intends to repower it as a gas-fueled plant.

Goodwill and Identifiable Int_2

Goodwill and Identifiable Intangible Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2024
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	As of December 31, 2024 and 2023, the carrying value of goodwill totaled $2.807 billion and $2.583 billion, respectively. Retail Segment Texas Segment Retail Reporting Unit (a) Texas Generation Reporting Unit Total Goodwill (in millions) Balance at December 31, 2023 $ 2,461 $ 122 $ 2,583 Goodwill recorded in connection with the Energy Harbor Merger (b) 224 Balance at December 31 2024 $ 2,461 $ 122 $ 2,807 ____________ (a) Goodwill of $1.944 billion is deductible for tax purposes over 15 years on a straight-line basis. (b) Allocation of goodwill attributable to the Energy Harbor acquisition to reporting units is pending completion of purchase accounting measurement period.
Schedule of Finite-Lived Intangible Assets	Identifiable intangible assets are comprised of the following: December 31, 2024 December 31, 2023 Identifiable Intangible Asset Gross Accumulated Net Gross Accumulated Net (in millions) Retail customer relationship $ 2,173 $ 1,977 $ 196 $ 2,088 $ 1,866 $ 222 Software and other technology-related assets 601 293 308 536 315 221 Retail and wholesale contracts 503 353 150 233 217 16 Long-term service agreements 18 5 13 18 5 13 Other identifiable intangible assets (a) 218 13 205 62 11 51 Total identifiable intangible assets subject to amortization $ 3,513 $ 2,641 872 $ 2,937 $ 2,414 523 Retail trade names (not subject to amortization) 1,341 1,341 Total identifiable intangible assets $ 2,213 $ 1,864 ____________ (a) Includes mining development costs and environmental allowances (emissions allowances and renewable energy certificates).
Schedule of Finite-Lived Intangible Liabilities	Identifiable intangible liabilities are comprised of the following: Year Ended December 31, Identifiable Intangible Liability 2024 2023 (in millions) Long-term service agreements $ 108 $ 122 Wholesale power and fuel purchase contracts 47 9 Total identifiable intangible liabilities $ 155 $ 131
Schedule of Amortization Expense Related to Intangible Assets Including Income Statement	Amortization of finite-lived identifiable intangible assets and liabilities (including the classification in the consolidated statements of operations) consisted of: Identifiable Intangible Assets/Liabilities Consolidated Statements of Operations Remaining useful lives of identifiable intangible assets at December 31, Year Ended December 31, 2024 2023 2022 (in millions) Retail customer relationship Depreciation and amortization 2 $ 111 $ 98 $ 137 Software and other technology-related assets Depreciation and amortization 3 60 58 69 Retail and wholesale contracts Operating revenues/Fuel, purchased power costs, and delivery fees 3 (12) 8 7 Other identifiable intangible assets Fuel, purchased power costs, and delivery fees/Depreciation and amortization 4 414 357 391 Total intangible asset expense, net $ 573 $ 521 $ 604 Amounts recorded in depreciation and amortization totaled $173 million, $158 million, and $208 million for the years ended December 31, 2024, 2023, and 2022, respectively. Amounts include all expenses associated with environmental allowances including expenses accrued to comply with emissions allowance programs and renewable portfolio standards which are presented in fuel, purchased power costs, and delivery fees in the consolidated statements of operations. Emissions allowance obligations are accrued as associated electricity is generated and renewable energy certificate obligations are accrued as retail electricity delivery occurs.
Schedule of Estimated Amortization Expense of Identifiable Intangible Assets and Liabilities	As of December 31, 2024, the estimated aggregate amortization expense of identifiable intangible assets, excluding environmental allowances, for each of the next five fiscal years is as shown below. Year Estimated Amortization Expense (in millions) 2025 $ 231 2026 $ 167 2027 $ 72 2028 $ 51 2029 $ 34

Debt, Credit Facilities, and _2

Debt, Credit Facilities, and Financings (Tables)	12 Months Ended
	Dec. 31, 2024
Debt Disclosure [Abstract]
Schedule of Debt	Amounts in the table below represent the categories of debt obligations incurred by the Company. December 31, 2024 2023 (in millions) Long-term debt, including amounts due currently: Project-level debt $ 1,064 $ — Vistra Operations debt 15,405 14,517 Long-term debt before unamortized premiums, discounts, and issuance costs 16,469 14,517 Unamortized premiums, discounts, and issuance costs (171) (115) Long-term debt including debt due currently $ 16,298 $ 14,402 Accounts receivable financing $ 750 $ — Forward repurchase obligation $ 1,335 $ —
Schedule of Long-Term Debt Instruments	Amounts in the table below represent the categories of long-term debt obligations, including amounts due currently, incurred by the Company. December 31, 2024 2023 (in millions) Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030 $ 2,475 $ 2,500 BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026 367 — Vistra Zero Credit Facility, Term Loan B Facility due April 30, 2031 697 — Vistra Operations Senior Secured Notes: 4.875% Senior Secured Notes, due May 13, 2024 — 400 3.550% Senior Secured Notes, due July 15, 2024 — 1,500 5.125% Senior Secured Notes, due May 13, 2025 744 1,100 5.050% Senior Secured Notes, due December 30, 2026 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 — 5.700% Senior Secured Notes, due December 30, 2034 750 — Total Vistra Operations Senior Secured Notes 5,144 5,650 Energy Harbor Revenue Bonds: 3.375% Revenue Bond, due August 1, 2029 100 — 4.750% Revenue Bond, due June 1, 2033 and July 1, 2033 285 — 3.750% Revenue Bond, due October 1, 2047 46 — Total Energy Harbor Revenue Bonds 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 — Total Vistra Operations Senior Unsecured Notes 7,300 6,300 Other: Equipment Financing Agreements 55 67 Total other long-term debt 55 67 Unamortized debt premiums, discounts, and issuance costs (171) (115) Total long-term debt including amounts due currently 16,298 14,402 Less amounts due currently (880) (2,286) Total long-term debt less amounts due currently $ 15,418 $ 12,116
Schedule of Maturities of Long-Term Debt	Long-term debt maturities at December 31, 2024 are as follows: December 31, 2024 (in millions) 2025 $ 885 2026 1,792 2027 3,427 2028 27 2029 2,177 Thereafter 8,161 Unamortized premiums, discounts, and debt issuance costs (171) Total long-term debt, including amounts due currently $ 16,298
Schedule of Line of Credit Facilities	Our credit facilities and related available capacity at December 31, 2024 are presented below. December 31, 2024 Credit Facilities Maturity Date Facility Cash Borrowings (Long-Term Debt, Including Amounts Due Currently) Letters of Credit Outstanding Available (in millions) Vistra Operations debt: Revolving Credit Facility October 11, 2029 $ 3,440 $ — $ 1,278 $ 2,162 Term Loan B-3 Facility December 20, 2030 2,475 2,475 — — Total Vistra Operations Credit Facilities $ 5,915 $ 2,475 $ 1,278 $ 2,162 Vistra Operations Commodity-Linked Facility October 1, 2025 1,750 — — 771 Total Vistra Operations debt $ 7,665 $ 2,475 $ 1,278 $ 2,933 Project-level debt: Tax Credit Bridge Loan November 1, 2025 106 106 — — Tax Credit Bridge Loan December 3, 2026 261 261 — — BCOP Credit Facility 367 367 — — Vistra Zero Term Loan B Facility (a) April 30, 2031 697 697 — — Total project-level debt $ 1,064 $ 1,064 $ — $ — Total credit facilities $ 8,729 $ 3,539 $ 1,278 $ 2,933 ____________ (a) Vistra Zero Operations' obligations under the Vistra Zero Credit Agreement are guaranteed by subsidiaries of Vistra Zero Operations, but are otherwise non-recourse to Vistra Operations and its other subsidiaries. Amendment Date Key Changes December 2024 Lowered fixed spread on Term Loan B-3 Facility borrowings from 2.00% to 1.75% October 2024 Increased Revolving Credit Facility commitments from $3.175 billion to $3.440 billion Extended the maturity date of the Revolving Credit Facility to October 11, 2029 Amendment Date Key Changes October 2024 Increased the aggregate available commitments to $1.75 billion Extended the maturity date to October 1, 2025 Amendment Date Key Changes December 2024 Lowered the fixed spread interest applicable to the Term Loan B Facility from 2.75% to 2.00% Removed required scheduled quarterly payment requirements
Schedule of Repurchase Obligation	Payments remaining due to Nuveen are as follows: December 31, 2024 (in millions) 2025 $ 781 2026 669 Thereafter — Total scheduled payments under the UPAs $ 1,450
Schedule of Debt Instrument Redemption	A roll-forward of the noncontrolling interest redemption obligation is as follows (in millions): Redeemable noncontrolling interest at September 30, 2024 $ 3,198 Income attributable to redeemable noncontrolling interest (a) 51 Dividends to redeemable noncontrolling interest holders (165) Redeemable noncontrolling interest balance at Closing Date (b) 3,084 Principal payment on Closing Date (1,749) Forward Repurchase Obligation at December 31, 2024 (c) $ 1,335 ____________ (a) Represents accretion attributable to fixed price redemption obligation. (b) Reclassified to a financing obligation. (c) Fair value of the remaining payment obligations to Nuveen discounted at 6%.
Schedule of Interest Expense and Related Charges	Interest Expense and Related Charges Year Ended December 31, 2024 2023 2022 (in millions) Interest expense $ 936 $ 654 $ 591 Unrealized mark-to-market net (gains) losses on interest rate swaps (53) 36 (250) Amortization of debt issuance costs, discounts, and premiums 34 26 28 Facility Fee expense 15 8 — Debt extinguishment gain (6) (3) (1) Capitalized interest (77) (37) (29) Other 51 56 29 Total interest expense and related charges $ 900 $ 740 $ 368

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2024
Leases [Abstract]
Schedule of Lease Cost	Lease Cost The following table presents costs related to lease activities: Year Ended December 31, 2024 2023 2022 (in millions) Operating lease cost $ 17 $ 12 $ 9 Finance lease: Finance lease right-of-use asset amortization 8 10 9 Interest on lease liabilities 11 11 12 Total finance lease cost 19 21 21 Variable lease cost (a) 29 37 22 Short-term lease cost 56 44 47 Total lease cost $ 121 $ 114 $ 99 ____________ (a) Represents coal stockpile management services, common area maintenance services, and rail car payments based on the number of rail cars used.
Schedule of Lease Balance Sheet Information	Balance Sheet Information The following table presents lease related balance sheet information: December 31, 2024 2023 (in millions) Lease assets: Operating lease right-of-use assets (reported in other noncurrent assets in the consolidated balance sheets) $ 106 $ 50 Finance lease right-of-use assets, net of accumulated amortization (reported in property, plant, and equipment in the consolidated balance sheets) 153 $ 160 Total lease right-of-use assets $ 259 $ 210 Current lease liabilities (reported in other current liabilities in the consolidated balance sheets): Operating lease liabilities $ 13 $ 7 Finance lease liabilities 9 9 Total current lease liabilities 22 16 Noncurrent lease liabilities (reported in other noncurrent liabilities and deferred credits in the consolidated balance sheets): Operating lease liabilities 98 48 Finance lease liabilities 218 227 Total noncurrent lease liabilities 316 275 Total lease liabilities $ 338 $ 291
Schedule of Lease Cash Flow Information	Supplemental Cash Flow Information The following table presents lease related cash flows and other information: Year Ended December 31, 2024 2023 2022 (in millions) Non-cash disclosure upon commencement of new lease: Right-of-use assets obtained in exchange for new operating lease liabilities 68 3 19 Right-of-use assets obtained in exchange for new finance lease liabilities — — 6 Non-cash disclosure upon modification of existing lease: Modification of operating lease right-of-use assets 1 7 — Modification of finance lease right-of-use assets — (1) 4
Schedule of Weighted Average Remaining Lease Terms and Discount Rates	Weighted Average Remaining Lease Term The following table presents weighted average remaining lease term information: December 31, 2024 2023 Weighted average remaining lease term: Operating lease 23.8 years 20.1 years Finance lease 23.7 years 24.0 years Weighted average discount rate: Operating lease 7.85% 6.49 % Finance lease 4.82% 4.81 %
Schedule of Maturity of Operating Lease Liabilities	Maturity of Lease Liabilities The following table presents maturity of lease liabilities: Operating Lease Finance Lease Total Lease (in millions) 2025 $ 19 $ 19 $ 38 2026 13 14 27 2027 14 13 27 2028 10 13 23 2029 8 13 21 Thereafter 222 331 553 Total lease payments 286 403 689 Less: Imputed interest (175) (176) (351) Present value of lease liabilities $ 111 $ 227 $ 338
Schedule of Maturity of Finance Lease Liabilities	Maturity of Lease Liabilities The following table presents maturity of lease liabilities: Operating Lease Finance Lease Total Lease (in millions) 2025 $ 19 $ 19 $ 38 2026 13 14 27 2027 14 13 27 2028 10 13 23 2029 8 13 21 Thereafter 222 331 553 Total lease payments 286 403 689 Less: Imputed interest (175) (176) (351) Present value of lease liabilities $ 111 $ 227 $ 338

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Interest Rate Derivatives	As of December 31, 2024, Vistra has entered into the following interest rate swaps: Notional Amount Expiration Date Rate Range (c) (in millions, except percentages) Swapped to fixed (a) $3,000 July 2026 4.64 % - 4.72% Swapped to variable (a) $700 July 2026 3.19 % - 3.24% Swapped to fixed (b) $2,300 December 2030 4.95 % - 5.51% ____________ (a) The $700 million of pay variable rate and receive fixed rate swaps match the terms of a portion of the $3.0 billion pay fixed rate and receive variable rate swaps. These matched swaps will settle over time and effectively offset the hedged position. These offsetting swaps expiring in July 2026 hedge our exposure on $2.3 billion of variable rate debt through July 2026. (b) Effective from July 2026 through December 2030. (c) The rate ranges reflect the fixed leg of each swap at a Term SOFR rate plus an interest margin of 1.75
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 consolidated balance sheets to the net value on a contract basis, after taking into consideration netting arrangements with counterparties and cash collateral recorded. December 31, 2024 Derivative Contract Assets Derivative Contract Liabilities Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total (in millions) Current assets $ 2,551 $ 34 $ 2 $ — $ 2,587 Noncurrent assets 677 62 1 — 740 Current liabilities — — (3,333) (18) (3,351) Noncurrent liabilities (2) — (1,356) (9) (1,367) Net assets (liabilities) $ 3,226 $ 96 $ (4,686) $ (27) $ (1,391) Offsetting instruments (a) $ (2,532) $ (28) $ 2,532 $ 28 — Financial collateral (received) pledged (b) $ (50) $ — $ 233 $ — 183 Net amounts $ 644 $ 68 $ (1,921) $ 1 $ (1,208) December 31, 2023 Derivative Contract Assets Derivative Contract Liabilities Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total (in millions) Current assets $ 3,585 $ 53 $ 7 $ — $ 3,645 Noncurrent assets 565 11 1 — 577 Current liabilities (1) — (5,233) (24) (5,258) Noncurrent liabilities (5) — (1,659) (24) (1,688) Net assets (liabilities) $ 4,144 $ 64 $ (6,884) $ (48) $ (2,724) Offsetting instruments (a) $ (3,519) $ (28) $ 3,519 $ 28 — Financial collateral (received) pledged (b) $ (26) $ — $ 970 $ — 944 Net amounts $ 599 $ 36 $ (2,395) $ (20) $ (1,780) ____________ (a) Amounts presented exclude trade accounts receivable and payable related to settled financial instruments. (b) Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin requirements, and, to a lesser extent, initial margin requirements.
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 consolidated statements of operations for the periods presented. Year Ended December 31, Derivative (consolidated statements of operations presentation) 2024 2023 2022 (in millions) Reversals of previously recognized unrealized (gain) loss on derivative instruments: Commodity contracts unrealized (gain) loss in operating revenues (a) $ 1,140 $ 1,472 $ 1,940 Commodity contracts unrealized (gain) loss in fuel and purchased power expense (a) 73 171 (722) Interest rate swaps unrealized (gain) loss in interest expense and related charges (41) (78) 16 Total reversals of previously recognized unrealized (gain) loss on derivative instruments $ 1,172 $ 1,565 $ 1,234 Unrealized net gains (losses) from changes in fair value on derivative instruments: Commodity contracts unrealized gain (loss) in operating revenues $ (127) $ (758) $ (4,103) Commodity contracts unrealized gain (loss) in fuel and purchased power expense 69 (395) 375 Interest rate swaps unrealized gain (loss) in interest expense and related charges 94 42 234 Total unrealized net gains (losses) from changes in fair value on derivative instruments $ 36 $ (1,111) $ (3,494) Net gain (loss) on derivative instruments $ 1,208 $ 454 $ (2,260) ____________ (a) Excludes the realized effects of changes in fair value in the month the position settled, amounts related to positions entered into and settled in the same month, and physical retail and wholesale contracts accounted for as derivatives which did not financially settle but realized at the contract's notional and price. The realized effects of these items are included in operating revenues and fuel and purchased power expense.
Schedule of Notional Amounts of Outstanding Derivative Positions	The following table presents the gross notional amounts of derivative volumes by commodity, excluding our NPNS derivatives that are not recorded at fair value: December 31, 2024 December 31, 2023 Derivative type Notional Volume Unit of Measure Natural gas 4,568 5,335 Million MMBtu Electricity 796,982 800,001 GWh Financial transmission rights / Congestion revenue rights 248,742 250,895 GWh Coal 27 35 Million U.S. tons Fuel oil 2 3 Million gallons Emissions 28 24 Million U.S. tons Renewable energy certificates 31 29 Million certificates Interest rate swaps – variable/fixed $ 5,300 $ 5,225 Million U.S. dollars Interest rate swaps - fixed/variable $ 700 $ 1,300 Million U.S. dollars
Schedule 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: December 31, 2024 2023 (in millions) Fair value of derivative contract liabilities (a) $ (1,587) $ (1,890) Offsetting fair value under netting arrangements (b) 724 692 Cash collateral and letters of credit 471 854 Liquidity exposure $ (392) $ (344) ____________ (a) Excludes fair value of contracts that contain contingent features that do not provide specific amounts to be posted if features are triggered, including provisions that generally provide the right to request additional collateral (material adverse change, performance assurance and other clauses). (b) Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master netting arrangements.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2024
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: December 31, 2024 December 31, 2023 Level Level Level Reclass (a) Total Level Level Level Reclass (a) Total (in millions) Assets: Commodity contracts (b) $ 1,923 $ 462 $ 841 $ 5 $ 3,231 $ 2,886 $ 628 $ 630 $ 14 $ 4,158 Interest rate swaps (b) — 96 — — 96 — 64 — — 64 NDTs – equity securities (c)(d) 1,560 — — — 1,560 638 — — — 638 NDTs – debt securities (c)(e) 83 1,976 — — 2,059 — 734 — — 734 Sub-total $ 3,566 $ 2,534 $ 841 $ 5 6,946 $ 3,524 $ 1,426 $ 630 $ 14 5,594 Assets measured at net asset value (f): NDTs – equity securities (c)(d)(f) 821 579 Total assets $ 7,767 $ 6,173 Liabilities: Commodity contracts (b) $ 2,118 $ 975 $ 1,593 $ 5 $ 4,691 $ 3,815 $ 1,395 $ 1,674 $ 14 $ 6,898 Interest rate swaps (b) — 27 — — 27 — 48 — — 48 Total liabilities $ 2,118 $ 1,002 $ 1,593 $ 5 $ 4,718 $ 3,815 $ 1,443 $ 1,674 $ 14 $ 6,946 ____________ (a) Fair values for each level are determined on a contract basis, but certain contracts are in both an asset and a liability position. This reclassification represents the adjustment needed to reconcile to the gross amounts presented in the consolidated balance sheets. (b) See Note 11 for additional information. (c) NDT assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facilities. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT. The NDT investments are included in Investments in the consolidated balance sheets. There were no significant concentrations of credit risk from an individual counterparty or groups of counterparties in our NDT portfolio as of December 31, 2024. (d) The investment objective for NDT equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index for U.S. equity investments and the MSCI EAFE Index for non-U.S. equity investments. (e) The investment objective for NDT debt securities is to invest in a diversified, high quality, tax efficient portfolio. The debt securities are weighted with government and investment grade corporate bonds. Other investable debt securities include, but are not limited to, municipal bonds, high yield bonds, securitized bonds, non-U.S. developed bonds, emerging market bonds, loans and treasury inflation-protected securities. The debt securities had an average coupon rate of 3.99% and 3.19% as of December 31, 2024 and 2023, respectively, and an average maturity of 7 years and 11 years as of December 31, 2024 and 2023, respectively. NDT debt securities held as of December 31, 2024 mature as follows: $1.045 billion in one to five years, $599 million in five to 10 years and $415 million after 10 years. (f) Net asset value is a practical expedient used for the classification of assets that do not have readily determinable fair values and therefore are not classified in the fair value hierarchy. This amount is presented to permit reconciliation of this table to the amounts presented in the consolidated balance sheets. As of December 31, 2024 and 2023, all of the Retirement Plan assets were measured at fair value using the net asset value per share (or its equivalent) except as noted and consisted of the following: December 31, 2024 2023 (in millions) Asset Category: Cash commingled trusts $ 6 $ 4 Equity securities: Global equities 86 82 Fixed income securities: Corporate bonds (a) 79 82 Government bonds 42 54 Other (b) 28 18 Real estate 27 28 Hedge funds 17 17 Total assets measured at net asset value $ 285 $ 285 ___________ (a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's. (b) Consists primarily of high-yield bonds, emerging market debt, bank loans, securitized bonds and private investment grade fixed income.
Schedule of Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation	The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations as of December 31, 2024 and 2023: December 31, 2024 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) December 31, 2023 Fair Value Contract Type (a) Assets Liabilities Total, Net Valuation Technique Significant Unobservable Input Range (b) Average (b) (in millions) Electricity purchases and sales $ 449 $ (1,273) $ (824) Income Approach Hourly price curve shape (c) $ — to $ 85 $ 44 MWh Illiquid delivery periods for hub power prices and Heat Rates (d) $ 30 to $ 110 $ 71 MWh Options 1 (237) (236) Option Pricing Model Natural gas to power correlation (e) 10 % to 100 % 55 % Power and natural gas volatility (e) 10 % to 870 % 441 % Financial transmission rights/Congestion revenue rights 157 (34) 123 Market Approach (f) Illiquid price differences between settlement points (g) $ (85) to $ 25 $ (30) MWh Natural gas 9 (112) (103) Income Approach Natural gas basis (h) $ — to $ 15 $ 6 MMBtu Illiquid delivery periods (i) $ — to $ 5 $ 4 MMBtu Other (j) 14 (18) (4) Total $ 630 $ (1,674) $ (1,044) ____________ (a) Electricity purchase and sales contracts include (i) power and Heat Rate positions in ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO regions, (ii) Options consist of physical electricity options, spread options and natural gas options, (iii) Forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points are referred to as congestion revenue rights (CRRs) in ERCOT and financial transmission rights (FTRs) in PJM, ISO-NE, NYISO and MISO regions, and (iv) Natural gas contracts include swaps and forward contracts. (b) The range of the inputs may be influenced by factors such as time of day, delivery period, season and location. The average represents the arithmetic average of the underlying inputs and is not weighted by the related fair value or notional amount. (c) Primarily based on the historical range of forward average hourly ERCOT North Hub and ERCOT South and West Zone prices. (d) Primarily based on historical forward ERCOT and PJM power prices and ERCOT Heat Rate variability. (e) Primarily based on the historical forward correlation and volatility within ERCOT and PJM. (f) While we use the market approach, there is insufficient market data for the inputs to the valuation to consider the valuation liquid. (g) Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones. (h) Primarily based on the historical forward PJM and Northeast natural gas basis prices and fixed prices. (i) Primarily based on the historical forward natural gas fixed prices. (j) Other includes contracts for coal and environmental allowances.
Schedule of Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation	The following table presents the changes in fair value of the Level 3 assets and liabilities: Year Ended December 31, 2024 2023 2022 (in millions) Net liability balance at beginning of period $ (1,044) $ (1,219) $ (360) Total unrealized valuation gains (losses) (175) (765) (1,382) Purchases, issuances and settlements (a): Purchases 266 222 185 Issuances (26) (30) (62) Settlements 137 136 345 Transfers into Level 3 (b) (15) (48) (30) Transfers out of Level 3 (b) 118 660 85 Net liabilities assumed in connection with the Energy Harbor Merger (13) — — Net change 292 175 (859) Net liability balance at end of period $ (752) $ (1,044) $ (1,219) Unrealized valuation (losses) relating to instruments held at end of period $ (416) $ (676) $ (977) ____________ (a) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received, including CRRs and FTRs. (b) Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. For the year ended December 31, 2024, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power and natural gas derivatives where forward pricing inputs have become observable. For the year ended December 31, 2023, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become observable. For the year ended December 31, 2022, transfers into Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power, natural gas, and coal derivatives where forward pricing inputs have become observable.
Schedule of Fair Value of Debt	December 31, 2024 December 31, 2023 Instrument Fair Value Hierarchy Carrying Amount Fair Carrying Amount Fair (in millions) Long-term debt under the Vistra Operations Credit Facilities Level 2 $ 2,435 $ 2,478 $ 2,456 $ 2,500 BCOP Credit Facilities Tax Credit Bridge Loan Level 3 344 367 — — Vistra Zero Term Loan B Facility Level 2 685 697 — — Vistra Operations Senior Notes Level 2 12,366 12,428 11,881 11,752 Energy Harbor Revenue Bonds Level 2 414 431 — — Equipment Financing Agreements Level 3 54 53 65 62 Forward Repurchase Obligation Level 3 1,335 1,335 — —

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2024
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 years ended December 31, 2024 and 2023: Nuclear Plant Decommissioning Land Reclamation, Coal Ash and Other Total (in millions) Liability at December 31, 2022 $ 1,688 $ 749 $ 2,437 Additions: Accretion (a) 54 34 88 Adjustment for change in estimates (b) — 94 94 Reductions: Payments — (81) (81) Liability at December 31, 2023 1,742 796 2,538 Additions: Accretion (a) 130 40 170 Adjustment for change in estimates (b) — 90 90 Adjustment for obligations assumed through acquisitions 1,368 — 1,368 Reductions: Payments — (88) (88) Liability at December 31, 2024 3,240 838 4,078 Less amounts due currently — (142) (142) Noncurrent liability at December 31, 2024 $ 3,240 $ 696 $ 3,936 ____________ (a) For the year ended December 31, 2024, nuclear plant decommissioning accretion includes $74 million of accretion expense recognized in operating costs in the consolidated statements of operations and $56 million reflected as a change in regulatory liability in the consolidated balance sheets. For the year ended December 31, 2023, nuclear plant decommissioning accretion reflected as a change in regulatory liability in the consolidated balance sheets. (b) Includes non-cash additions to asset retirement costs included in property, plant, and equipment of $52 million and $67 million for the years ended December 31, 2024 and 2023, respectively.

Pension and Other Postretirem_2

Pension and Other Postretirement Employee Benefits (OPEB) Plans (Tables)	12 Months Ended
	Dec. 31, 2024
Compensation and Retirement Benefits Disclosures [Abstract]
Schedule of Pension and OPEB Costs	The following table summarizes the total benefit costs of our pension and OPEB plans for the years ended December 31, 2024, 2023, and 2022. The individual components of benefit costs, including service cost, interest cost, expected return on assets and the net amortization of unrecognized amounts from accumulated other comprehensive income were immaterial. Year Ended December 31, 2024 2023 2022 (in millions) Pension costs $ 9 $ 9 $ 2 OPEB costs 5 5 4 Total benefit costs recognized as expense $ 14 $ 14 $ 6
Schedule of Defined Benefit Plans Disclosures	The following information is based on a December 31, 2024, 2023, and 2022 measurement dates: Retirement Plan OPEB Plans Year Ended December 31, Year Ended December 31, 2024 2023 2022 2024 2023 2022 Assumptions Used to Determine Benefit Obligations at Period End: Discount rate 5.63 % 4.97 % 5.16 % 5.62 % 4.98 % 5.18 % Expected rate of compensation increase (Vistra Plan) 3.50 % 3.64 % 3.79 % Expected rate of compensation increase (Dynegy Plan) 4.46 % Interest crediting rate for cash balance plans 3.75 % 3.50 % 3.00 % Retirement Plan OPEB Plans Year Ended December 31, Year Ended December 31, 2024 2023 2024 2023 (in millions, except percentages) Change in Pension and Postretirement Benefit Obligations: Projected benefit obligation at beginning of period $ 425 $ 449 $ 108 $ 110 Acquisitions 23 — — — Service cost 2 3 1 1 Interest cost 21 21 5 5 Participant contributions — — 3 3 Plan amendments — 1 — — Actuarial (gain) loss (24) 10 (7) 1 Benefits paid (38) (59) (11) (12) Projected benefit obligation at end of year $ 409 $ 425 $ 99 $ 108 Accumulated benefit obligation at end of year $ 408 $ 422 $ — $ — Change in Plan Assets: Fair value of assets at beginning of period $ 285 $ 320 $ 12 $ 29 Acquisitions 18 — — — Employer contributions 19 — 8 9 Participant contributions — — 2 3 Actual gain on assets 1 24 1 2 Transfers — — (2) (19) Benefits paid (38) (59) (11) (12) Fair value of assets at end of year $ 285 $ 285 $ 10 $ 12 Funded Status: Projected benefit obligation $ (409) $ (425) $ (99) $ (108) Fair value of assets 285 285 10 12 Funded status at end of year $ (124) $ (140) $ (89) $ (96) Retirement Plan OPEB Plans Year Ended December 31, Year Ended December 31, 2024 2023 2024 2023 Amounts Recognized in the Balance Sheet Consist of: Investments $ 1 $ — $ 2 $ 3 Other current liabilities — — (8) (9) Other noncurrent liabilities (125) (140) (83) (90) Net liability recognized $ (124) $ (140) $ (89) $ (96) Amounts Recognized in Accumulated Other Comprehensive Income Consist of: Net actuarial (gain) loss $ (5) $ 4 $ (22) $ (15) Prior services cost — 3 1 1 Net actuarial (gain) loss and prior service cost $ (5) $ 7 $ (21) $ (14)
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: December 31, 2024 December 31, 2023 Level Level Level Reclass (a) Total Level Level Level Reclass (a) Total (in millions) Assets: Commodity contracts (b) $ 1,923 $ 462 $ 841 $ 5 $ 3,231 $ 2,886 $ 628 $ 630 $ 14 $ 4,158 Interest rate swaps (b) — 96 — — 96 — 64 — — 64 NDTs – equity securities (c)(d) 1,560 — — — 1,560 638 — — — 638 NDTs – debt securities (c)(e) 83 1,976 — — 2,059 — 734 — — 734 Sub-total $ 3,566 $ 2,534 $ 841 $ 5 6,946 $ 3,524 $ 1,426 $ 630 $ 14 5,594 Assets measured at net asset value (f): NDTs – equity securities (c)(d)(f) 821 579 Total assets $ 7,767 $ 6,173 Liabilities: Commodity contracts (b) $ 2,118 $ 975 $ 1,593 $ 5 $ 4,691 $ 3,815 $ 1,395 $ 1,674 $ 14 $ 6,898 Interest rate swaps (b) — 27 — — 27 — 48 — — 48 Total liabilities $ 2,118 $ 1,002 $ 1,593 $ 5 $ 4,718 $ 3,815 $ 1,443 $ 1,674 $ 14 $ 6,946 ____________ (a) Fair values for each level are determined on a contract basis, but certain contracts are in both an asset and a liability position. This reclassification represents the adjustment needed to reconcile to the gross amounts presented in the consolidated balance sheets. (b) See Note 11 for additional information. (c) NDT assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facilities. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT. The NDT investments are included in Investments in the consolidated balance sheets. There were no significant concentrations of credit risk from an individual counterparty or groups of counterparties in our NDT portfolio as of December 31, 2024. (d) The investment objective for NDT equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index for U.S. equity investments and the MSCI EAFE Index for non-U.S. equity investments. (e) The investment objective for NDT debt securities is to invest in a diversified, high quality, tax efficient portfolio. The debt securities are weighted with government and investment grade corporate bonds. Other investable debt securities include, but are not limited to, municipal bonds, high yield bonds, securitized bonds, non-U.S. developed bonds, emerging market bonds, loans and treasury inflation-protected securities. The debt securities had an average coupon rate of 3.99% and 3.19% as of December 31, 2024 and 2023, respectively, and an average maturity of 7 years and 11 years as of December 31, 2024 and 2023, respectively. NDT debt securities held as of December 31, 2024 mature as follows: $1.045 billion in one to five years, $599 million in five to 10 years and $415 million after 10 years. (f) Net asset value is a practical expedient used for the classification of assets that do not have readily determinable fair values and therefore are not classified in the fair value hierarchy. This amount is presented to permit reconciliation of this table to the amounts presented in the consolidated balance sheets. As of December 31, 2024 and 2023, all of the Retirement Plan assets were measured at fair value using the net asset value per share (or its equivalent) except as noted and consisted of the following: December 31, 2024 2023 (in millions) Asset Category: Cash commingled trusts $ 6 $ 4 Equity securities: Global equities 86 82 Fixed income securities: Corporate bonds (a) 79 82 Government bonds 42 54 Other (b) 28 18 Real estate 27 28 Hedge funds 17 17 Total assets measured at net asset value $ 285 $ 285 ___________ (a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's. (b) Consists primarily of high-yield bonds, emerging market debt, bank loans, securitized bonds and private investment grade fixed income.
Schedule of Accumulated and Projected Benefit Obligations	The following table provides information regarding pension plans with PBO and ABO in excess of the fair value of plan assets. December 31, 2024 2023 (in millions) Pension Plans with PBO and ABO in Excess of Plan Assets: Projected benefit obligations $ 409 $ 425 Accumulated benefit obligation $ 408 $ 422 Plan assets $ 285 $ 285
Schedule of Allocation of Plan Assets	The target asset allocation ranges of pension plan investments by asset category are as follows: Retirement Plan Target Allocation Ranges Asset Category: Vistra Plan Dynegy Plan Energy Harbor Plan Fixed income securities 50 % - 70% 40 % - 50% 45 % - 55% Global equity securities 20 % - 28% 28 % - 38% 30 % - 38% Real estate 6 % - 10% 7 % - 15% 5 % - 10% Credit strategies 2 % - 6% 4 % - 8% 4 % - 8% Hedge funds 2 % - 6% 4 % - 8% 1 % - 5%
Schedule of Defined Benefit Plan, Assumptions	Retirement Plan Expected Long-Term Rate of Return Asset Class: Vistra Plan Dynegy Plan Energy Harbor Plan Fixed income securities 5.9 % 5.5 % 4.6 % Global equity securities 7.2 % 7.2 % 7.2 % Real estate 5.8 % 5.8 % 5.8 % Credit strategies 7.4 % 7.4 % 7.4 % Hedge funds 7.3 % 7.3 % 7.3 % Weighted average 6.3 % 6.3 % 5.8 %
Schedule of Health Care Cost Trend Rates	The following tables provide information regarding the assumed health care cost trend rates. December 31, 2024 2023 Assumed Health Care Cost Trend Rates-Not Medicare Eligible: Health care cost trend rate assumed for next year 7.00 % 7.00 % Rate to which the cost trend is expected to decline (the ultimate trend rate) 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate 2034 2033 Assumed Health Care Cost Trend Rates-Medicare Eligible: Health care cost trend rate assumed for next year (Vistra Plan) 15.70 % 12.90 % Health care cost trend rate assumed for next year (Split-Participant Plan) 13.80 % 12.30 % Rate to which the cost trend is expected to decline (the ultimate trend rate) 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate 2034 2033
Schedule of Expected Benefit Payments	Estimated future benefit payments to beneficiaries are as follows: 2025 2026 2027 2028 2029 2030-2034 (in millions) Pension benefits $ 33 $ 34 $ 43 $ 32 $ 32 $ 151 OPEB $ 9 $ 9 $ 9 $ 8 $ 8 $ 36

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
Schedule of Contractual Obligation, Fiscal Year Maturity	As of December 31, 2024, we had minimum contractual commitments under long-term service and maintenance contracts, energy-related contracts and other agreements as follows: Long-Term Service and Maintenance Contracts (a) Coal transportation agreements Pipeline transportation and storage reservation fees Water (in millions) 2025 $ 227 $ 59 $ 187 $ 9 2026 206 26 200 9 2027 207 26 209 9 2028 265 — 228 9 2029 259 — 234 9 Thereafter 1,916 — 115 37 Total $ 3,080 $ 111 $ 1,173 $ 82 ____________ (a) Long-term service and maintenance contracts reflect expected expenditures as these contracts do not include minimum spending requirements, but can only be terminated based on events outside the control of the Company.

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2024
Stockholders' Equity Note [Abstract]
Schedule of Common Stock Outstanding Roll Forward	Changes in the number of shares of common stock issued and outstanding for the years ended December 31, 2024, 2023, and 2022 are reflected in the table below. Shares Treasury Shares Outstanding Balance at December 31, 2021 532,929,476 (69,031,742) 463,897,734 Shares issued (a) 4,262,575 — 4,262,575 Shares retired (12,979) — (12,979) Shares repurchased (b) — (78,470,547) (78,470,547) Balance at December 31, 2022 537,179,072 (147,502,289) 389,676,783 Shares issued (a) 6,474,491 — 6,474,491 Shares retired (18,391) — (18,391) Shares repurchased (b) — (44,994,499) (44,994,499) Balance at December 31, 2023 543,635,172 (192,496,788) 351,138,384 Shares issued (a) 5,117,434 — 5,117,434 Shares repurchased (b) — (16,560,328) (16,560,328) Balance at December 31, 2024 548,752,606 (209,057,116) 339,695,490 ____________ (a) Shares issued include share awards granted to nonemployee directors. (b) Shares repurchased include 58,817, 318,632, and 78,087 of unsettled shares as of December 31, 2024, 2023, and 2022, respectively.
Schedule of Repurchase Agreements	The following table provides information about our repurchases of common stock for the period between January 1, 2022 and February 24, 2025. $6.750 Billion Board Authorization Total Number of Shares Repurchased Average Price Paid Amount Paid for Shares Repurchased Amount Available for Additional Repurchases at the End of the Period (in millions, except share amounts and price paid per share) Year Ended December 31, 2022 78,470,547 $ 23.40 $ 1,836 Year Ended December 31, 2023 44,994,499 27.89 1,255 Year Ended December 31, 2024 16,560,328 74.96 1,241 January 1, 2022 through December 31, 2024 (a) 140,025,374 $ 30.94 $ 4,332 $ 2,009 January 1, 2025 through February 24, 2025 848,866 163.23 139 January 1, 2022 through February 24, 2025 140,874,240 $ 31.74 $ 4,471 $ 1,870 ____________ (a) Shares repurchased include 58,817 of unsettled shares for $8 million as of December 31, 2024.
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 and Outstanding (a) Contractual Rates Earliest Redemption Date (b) Date at Which Dividend Rate Becomes Floating Floating Annual Rates Series A October 15, 2021 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 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 476,066 8.875 % January 15, 2029 January 15, 2029 5-Year U.S. Treasury rate (subject to floor of 3.83%) plus 5.045% ____________ (a) Series C Preferred Stock issued totaled 476,081 shares at December 31, 2023. (b) Subject to our right, in limited circumstances, to redeem preferred stock prior to the earliest redemption date. Preferred stock dividends are payable semiannually in arrears when declared by the Board. The following table summarizes preferred stock dividends paid per share in the years ended December 31, 2024, 2023, and 2022. Year Ended December 31, Preferred Stock Series 2024 2023 2022 Series A Preferred Stock $ 80.00 $ 80.00 $ 80.00 Series B Preferred Stock $ 70.00 $ 70.00 $ 70.97 Series C Preferred Stock $ 48.32
Schedule of Share Repurchase Program	Amount Authorized for Share Repurchases (in billions) Board Authorization Dates: October 2021 $ 2.00 August 2022 1.25 March 2023 1.00 February 2024 1.50 October 2024 1.00 Cumulative authorization at December 31, 2024 $ 6.75

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2024
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. Year Ended December 31, 2024 2023 2022 (in millions, except share data) Net income (loss) attributable to Vistra $ 2,659 $ 1,493 $ (1,227) Less cumulative dividends attributable to Series A Preferred Stock (80) (80) (80) Less cumulative dividends attributable to Series B Preferred Stock (70) (70) (70) Less cumulative dividends attributable to Series C Preferred Stock (42) — — Net income (loss) attributable to common stock — basic and diluted 2,467 1,343 (1,377) Weighted average shares of common stock outstanding: Basic 344,788,634 369,771,359 422,447,074 Dilutive securities: Stock-based incentive compensation plan 7,778,426 5,421,752 — Diluted 352,567,060 375,193,110 422,447,074 Net income (loss) per weighted average share of common stock outstanding: Basic $ 7.16 $ 3.63 $ (3.26) Diluted $ 7.00 $ 3.58 $ (3.26)

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2024
Share-Based Payment Arrangement [Abstract]
Schedule of Share-Based Payment Arrangement, Expensed and Capitalized, Amount	Stock-based compensation expense is reported as SG&A in the consolidated statements of operations as follows: Year Ended December 31, 2024 2023 2022 (in millions) Total stock-based compensation expense $ 100 $ 77 $ 65 Income tax benefit (23) (18) (15) Stock based-compensation expense, net of tax $ 77 $ 59 $ 50
Schedule of Share-Based Payment Arrangement, Option and Stock Appreciation Rights, Activity	Stock options outstanding at December 31, 2024 are all held by current or former employees. The following table summarizes our stock option activity: Year Ended December 31, 2024 Stock Options Weighted Weighted Average Remaining Contractual Term (Years) Aggregate Intrinsic Value (in millions) Total outstanding at beginning of period 6,126 $ 20.01 4.2 $ 113.5 Exercised (2,526) $ 20.06 Total outstanding at end of period 3,600 $ 19.97 3.5 $ 424.4 Exercisable at December 31, 2024 3,600 $ 19.97 3.5 $ 424.4
Schedule of Share-Based Payment Arrangement, Restricted Stock Unit, Activity	The following table summarizes our restricted stock unit activity: Year Ended December 31, 2024 Restricted Stock Units Weighted Total nonvested at beginning of period 3,908 $ 21.90 Granted 1,017 $ 59.11 Vested (1,785) $ 22.20 Forfeited (86) $ 33.55 Total nonvested at end of period 3,054 $ 34.30

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2024
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Year Ended December 31, 2024 Retail Texas East West Asset Closure Total Reportable Segments Corporate and Other Total (in millions) Operating revenues $ 12,797 $ 5,394 $ 5,661 $ 877 $ 1 $ 24,730 $ (7,506) $ 17,224 Fuel, purchased power costs, and delivery fees (10,276) (1,596) (2,698) (221) (3) (14,794) 7,509 (7,285) Operating costs (159) (996) (1,103) (72) (81) (2,411) (3) (2,414) Selling, general, and administrative expenses (977) (169) (148) (25) (43) (1,362) (239) (1,601) Other segment items: Depreciation and amortization (114) (581) (996) (86) — (1,777) (66) (1,843) Interest expenses and related charges (54) 46 9 1 (4) (2) (898) (900) Income tax expense — — — — — — (655) (655) Other (a) (1) 35 177 (3) 14 222 64 286 Net income (loss) $ 1,216 $ 2,133 $ 902 $ 471 $ (116) $ 4,606 $ (1,794) $ 2,812 Capital expenditures, including nuclear fuel and excluding growth expenditures $ 4 $ 1,124 $ 661 $ 70 $ — $ 1,859 $ 58 $ 1,917 Year Ended December 31, 2023 Retail Texas East West Asset Closure (b) Total Reportable Segments Corporate and Other Total (in millions) Operating revenues $ 10,572 $ 3,979 $ 5,890 $ 914 $ — $ 21,355 $ (6,576) $ 14,779 Fuel, purchased power costs, and delivery fees (9,046) (2,028) (2,730) (328) (3) (14,135) 6,578 (7,557) Operating costs (123) (917) (528) (58) (74) (1,700) (2) (1,702) Selling, general, and administrative expenses (858) (140) (127) (24) (34) (1,183) (125) (1,308) Other segment items: Depreciation and amortization (102) (550) (703) (79) — (1,434) (68) (1,502) Interest expenses and related charges (20) 21 (2) 8 (5) 2 (742) (740) Income tax expense — — (1) — — (1) (507) (508) Other (a) 1 33 (50) 21 110 115 (85) 30 Net income (loss) $ 424 $ 398 $ 1,749 $ 454 $ (6) $ 3,019 $ (1,527) $ 1,492 Capital expenditures, including nuclear fuel and excluding growth expenditures $ 1 $ 750 $ 362 $ 366 $ — $ 1,479 $ 58 $ 1,537 Year Ended December 31, 2022 Retail Texas East West Asset Closure (b) Total Reportable Segments Corporate and Other Total (in millions) Operating revenues $ 9,455 $ 3,878 $ 4,429 $ 336 $ 384 $ 18,482 $ (4,754) $ 13,728 Fuel, purchased power costs, and delivery fees (7,169) (3,052) (4,132) (481) (322) (15,156) 4,755 (10,401) Operating costs (143) (832) (482) (42) (145) (1,644) (1) (1,645) Selling, general, and administrative expenses (826) (135) (97) (21) (44) (1,123) (66) (1,189) Other segment items: Interest expenses and related charges (14) 20 (6) 6 (3) 3 (371) (368) Depreciation and amortization (145) (541) (768) (42) (31) (1,527) (69) (1,596) Income tax benefit — — — — — — 350 350 Other (a) — 76 (71) 6 14 25 (114) (89) Net income (loss) $ 1,158 $ (586) $ (1,127) $ (238) $ (147) $ (940) $ (270) $ (1,210) Capital expenditures, including nuclear fuel and excluding growth expenditures $ 1 $ 520 $ 187 $ 345 $ — $ 1,053 $ 55 $ 1,108 ____________ (a) Other includes impairment of long-lived assets, other income, other deductions, and the impacts of the Tax Receivable Agreement. (b) We have allocated unrealized gains and losses on the commodity risk management activities attributable to the plants retired in 2022 and 2023. See Note 6 for additional information.

Supplementary Financial Infor_2

Supplementary Financial Information (Tables)	12 Months Ended
	Dec. 31, 2024
Supplementary Financial Information [Abstract]
Schedule of Other Nonoperating Income (Expense)	Year Ended December 31, 2024 2023 2022 (in millions) Other income: NDT net income (a) $ 170 $ — $ — Insurance settlements (b) 23 24 70 Gain on sale of land (c) 6 95 8 Gain on TRA settlement (d) 10 29 — Interest income 65 86 19 All other 38 23 20 Total other income $ 312 $ 257 $ 117 Other deductions: All other $ 21 $ 14 $ 4 Total other deductions $ 21 $ 14 $ 4 ____________ (a) Includes interest, dividends, and net realized and unrealized gains and losses associated with NDTs of the PJM nuclear facilities. Reported in the East segment. (b) For the year ended December 31, 2024, $20 million reported in the Texas segment and $3 million reported in the West segment. For the year ended December 31, 2023, $19 million reported in the West segment and $5 million in the Asset Closure segment. For the year ended December 31, 2022, $62 million reported in the Texas segment, $6 million reported in the West segment, $1 million reported in the Asset Closure segment, and $1 million reported in the Corporate and Other non-segment. (c) For the year ended December 31, 2024, reported in the Asset Closure segment. For the year ended December 31, 2023, $94 million reported in the Asset Closure segment and $1 million reported in the Texas segment. For the year ended December 31, 2022, reported in the Asset Closure segment. (d) Reported in the Corporate and Other.
Schedule of Inventory, Current	December 31, 2024 2023 (in millions) Materials and supplies $ 533 $ 289 Fuel stock 403 420 Natural gas in storage 34 31 Total inventories $ 970 $ 740
Summary of Other Investments	December 31, 2024 2023 (in millions) Nuclear decommissioning trusts $ 4,440 $ 1,951 Assets related to employee benefit plans 14 28 Land investments 42 42 Other investments 16 14 Total investments $ 4,512 $ 2,035
Schedule of Other Noncurrent Liabilities and Deferred Credits	The balance of other noncurrent liabilities and deferred credits consists of the following: December 31, 2024 2023 (in millions) Retirement and other employee benefits (Note 14) $ 224 $ 247 Winter Storm Uri impact (a) 1 26 Identifiable intangible liabilities (Note 7) 155 131 Regulatory liability (b) 452 209 Operating lease liabilities 98 48 Finance lease liabilities 218 227 Liability for third-party remediation 8 17 Accrued severance costs 36 36 Other accrued expenses 64 58 Total other noncurrent liabilities and deferred credits $ 1,256 $ 999 ____________ (a) Includes future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri. (b) As of December 31, 2024, the fair value of the assets contained in the Comanche Peak NDT was higher than the carrying value of our ARO related to our nuclear generation plant decommissioning and recorded as a regulatory liability of $452 million and $209 million, respectively, in other noncurrent liabilities and deferred credits.
Schedule of Cash and Cash Equivalents	The following table reconciles cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows to the amounts reported in the consolidated balance sheets at December 31, 2024 and 2023: December 31, 2024 2023 (in millions) Cash and cash equivalents $ 1,188 $ 3,485 Restricted cash included in current assets (a) 28 40 Restricted cash included in noncurrent assets (a) 6 14 Total cash, cash equivalents and restricted cash $ 1,222 $ 3,539 ____________ (a) Restricted cash consists of amounts related to remediation escrow accounts. Vistra has transferred various asset retirement obligations related to several closed plant sites to a third-party remediation company. As part of certain transfers, Vistra deposits funds into escrow accounts, and the funds are released to the remediation company as milestones are reached in the remediation process. Amounts contractually payable to the third party in exchange for assuming the obligations are included in other current liabilities and other noncurrent liabilities and deferred credits.
Schedule of Restricted Cash	The following table reconciles cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows to the amounts reported in the consolidated balance sheets at December 31, 2024 and 2023: December 31, 2024 2023 (in millions) Cash and cash equivalents $ 1,188 $ 3,485 Restricted cash included in current assets (a) 28 40 Restricted cash included in noncurrent assets (a) 6 14 Total cash, cash equivalents and restricted cash $ 1,222 $ 3,539 ____________ (a) Restricted cash consists of amounts related to remediation escrow accounts. Vistra has transferred various asset retirement obligations related to several closed plant sites to a third-party remediation company. As part of certain transfers, Vistra deposits funds into escrow accounts, and the funds are released to the remediation company as milestones are reached in the remediation process. Amounts contractually payable to the third party in exchange for assuming the obligations are included in other current liabilities and other noncurrent liabilities and deferred credits.
Schedule of Cash Flow, Supplemental Disclosures	The following table summarizes our supplemental cash flow information for the years ended December 31, 2024, 2023, and 2022, respectively. Non-cash investing and financing activities also includes activity related to the Energy Harbor Merger. See Note 2 for additional information. Year Ended December 31, 2024 2023 2022 (in millions) Cash payments related to: Interest paid $ 987 $ 636 $ 581 Capitalized interest (77) (37) (29) Interest paid (net of capitalized interest) $ 910 $ 599 $ 552 Non-cash investing and financing activities: Accrued property, plant, and equipment additions (a) $ 258 $ 104 $ 103 Issuance of Series C Preferred Stock as consideration for the repurchase of TRA Rights with a carrying value of $506 million $ — $ 476 $ — Book value of property, plant, and equipment sold, including nuclear fuel $ 117 $ 26 $ — ____________ (a) Represents property, plant, and equipment accruals during the period for which cash has not been paid as of the end of the period.

Schedule I - Condensed Financ_2

Schedule I - Condensed Financial Information of Registrant (Tables)	12 Months Ended
	Dec. 31, 2024
Condensed Financial Information Disclosure [Abstract]
Condensed Statements of Operations	VISTRA CORP. (PARENT) SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENTS OF OPERATIONS (Millions of Dollars) Year Ended December 31, 2024 2023 2022 Depreciation and amortization $ — $ (15) $ (16) Selling, general, and administrative expenses (102) (80) (69) Operating loss (102) (95) (85) Other income 28 31 6 Impacts of Tax Receivable Agreement (5) (164) (128) Loss before income tax benefit (79) (228) (207) Income tax benefit 17 58 47 Equity in earnings (losses) of subsidiaries, net of tax 2,721 1,663 (1,067) Net income (loss) $ 2,659 $ 1,493 $ (1,227)
Condensed Balance Sheets	VISTRA CORP. (PARENT) SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED BALANCE SHEETS (Millions of Dollars) December 31, 2024 2023 ASSETS Cash and cash equivalents $ 22 $ 31 Trade accounts receivable — affiliates 13 — Income taxes receivable 8 6 Total current assets 43 37 Investment in affiliated companies 4,670 4,507 Property, plant, and equipment — net 2 3 Accumulated deferred income taxes 960 1,086 Other noncurrent assets 3 — Total assets $ 5,678 $ 5,633 LIABILITIES AND EQUITY Trade accounts payable $ 8 $ 12 Accounts payable —affiliates 27 91 Accrued taxes 9 12 Other current liabilities 27 12 Total current liabilities 71 127 Tax Receivable Agreement obligations 14 164 Other noncurrent liabilities and deferred debits 10 20 Total liabilities 95 311 Total stockholders' equity 5,583 5,322 Total liabilities and equity $ 5,678 $ 5,633
Condensed Statements of Cash Flows	VISTRA CORP. (PARENT) SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENTS OF CASH FLOWS (Millions of Dollars) Year Ended December 31, 2024 2023 2022 Cash flows — operating activities: Cash used in operating activities $ (37) $ (31) $ (27) Cash flows — investing activities: Dividend received from subsidiaries 1,705 1,625 1,775 Proceeds from sales of subsidiary transferable ITCs 150 — — Cash provided by investing activities 1,855 1,625 1,775 Cash flows — financing activities: Stock repurchases (1,266) (1,245) (1,949) Dividends paid to common stockholders (305) (313) (302) Dividends paid to preferred stockholders (173) (150) (151) TRA Repurchase and tender offer - return of capital (122) — — Other, net 39 91 40 Cash used in financing activities (1,827) (1,617) (2,362) Net change in cash, cash equivalents and restricted cash (9) (23) (614) Cash, cash equivalents and restricted cash — beginning balance 31 54 668 Cash, cash equivalents and restricted cash — ending balance $ 22 $ 31 $ 54

Business And Significant Acco_3

Business And Significant Accounting Policies - Narrative (Details) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2025 USD ($)	Dec. 31, 2024 USD ($) segment	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Jan. 31, 2025 USD ($) facility MW	Jan. 16, 2025 MW	Jun. 30, 2023 MW
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Number of reportable segments | segment		5
Deferred tax assets, gross		$ 2,152	$ 2,532
Depreciation		1,670	1,344	$ 1,388
Property, plant, and equipment — net		18,173	12,432
Moss Landing Power Plant (Battery Storage Project) | Moss Landing Battery Energy Storage System Phase III
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Battery energy storage system capacity | MW							350
Moss Landing Power Plant (Battery Storage Project) | Moss Landing Battery Energy Storage System Phase III | Subsequent Event
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Battery energy storage system capacity | MW					300	300
Depreciation	$ 400
Number of battery facilities | facility					2
Property, plant, and equipment — net					$ 1,000
Number of offline battery facilities | facility					2
Vistra Corp. | Solar Generation and Battery Energy Storage Projects
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred tax assets, gross		$ 69	$ 69

Acquisitions - Narrative (Detai

Acquisitions - Narrative (Details) - USD ($) $ in Millions		12 Months Ended
	Dec. 31, 2024	Dec. 31, 2024	Dec. 31, 2023	Mar. 01, 2024
Vistra Vision
Business Acquisition [Line Items]
Subsidiary, ownership percentage, noncontrolling owner	15%	15%
Fair value of noncontrolling interest in Energy Harbor				$ 749
Payments to acquire interest in subsidiaries and affiliates	$ 3,200
Energy Harbor
Business Acquisition [Line Items]
Fair value of noncontrolling interest in Energy Harbor				$ 811
Business combination, acquisition related costs		$ 25	$ 24
Energy Harbor | Vistra Vision
Business Acquisition [Line Items]
Subsidiary, ownership percentage, noncontrolling owner				15%
Subsidiary, ownership percentage, parent				85%

Acquisitions - Purchase Price (

Acquisitions - Purchase Price (Details) - USD ($) $ in Millions	Mar. 01, 2024	Dec. 31, 2024
Vistra Vision
Business Acquisition [Line Items]
Fair value of noncontrolling interest in Energy Harbor	$ 749
Subsidiary, ownership percentage, noncontrolling owner		15%
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%
Energy Harbor | Vistra Corp. | Vistra Vision
Business Acquisition [Line Items]
Subsidiary, ownership percentage, noncontrolling owner	15%

Acquisitions - Schedule of Busi

Acquisitions - Schedule of Business Acquisitions, by Acquisitions (Details) - USD ($) $ in Millions	10 Months Ended
	Dec. 31, 2024	Mar. 01, 2024	Dec. 31, 2023
Business Acquisition [Line Items]
Goodwill	$ 2,807		$ 2,583
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		544
Investments		2,021
Property, plant and equipment		5,616
Identifiable intangible assets		444
Commodity and other derivative contractual assets		129
Other noncurrent assets		61
Total identifiable assets acquired		8,850
Trade accounts payable and other current liabilities		320
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		18
Total identifiable liabilities assumed		3,667
Identifiable net assets acquired		5,183
Goodwill		224
Net assets acquired		$ 5,407
Cash and cash equivalents	$ 5
Trade accounts receivables, inventories, prepaid expenses, and other current assets	6
Investments	0
Property, plant and equipment	(4)
Identifiable intangible assets	16
Commodity and other derivative contractual assets	(11)
Other noncurrent assets	53
Total identifiable assets acquired	65
Trade accounts payable and other current liabilities	57
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	6
Total identifiable liabilities assumed	(5)
Identifiable net assets acquired	70
Goodwill	$ (70)

Acquisitions - Schedule of Bu_2

Acquisitions - Schedule of Business Acquisitions, Pro Forma Information (Details) - Energy Harbor - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Business Acquisition [Line Items]
Revenues	$ 17,948	$ 17,148
Net income	$ 2,901	$ 1,398

Revenue - Disaggregation of Rev

Revenue - Disaggregation of Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 14,761	$ 13,804	$ 15,631
Operating revenues	17,224	14,779	13,728
Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	24,730	21,355	18,482
Eliminations / Corporate and Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Operating revenues	(7,506)	(6,576)	(4,754)
Retail | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	11,659	9,316	9,110
Operating revenues	12,797	10,572	9,455
Texas | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	821	1,695	1,973
Operating revenues	5,394	3,979	3,878
Texas | Operating Segments | Operating revenues
Disaggregation of Revenue [Line Items]
Unrealized gain (loss) on derivatives affiliated	74	(48)	(780)
East | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,823	2,193	3,319
Operating revenues	5,661	5,890	4,429
East | Operating Segments | Operating revenues
Disaggregation of Revenue [Line Items]
Unrealized gain (loss) on derivatives affiliated	(195)	814	(45)
West | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	458	600	618
Operating revenues	877	914	336
West | Operating Segments | Operating revenues
Disaggregation of Revenue [Line Items]
Unrealized gain (loss) on derivatives affiliated	4	(6)	2
Asset Closure | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	611
Operating revenues	1	0	384
Asset Closure | Operating Segments | Operating revenues
Disaggregation of Revenue [Line Items]
Unrealized gain (loss) on derivatives affiliated			4
Retail energy charge in ERCOT
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	8,064	7,674	6,971
Retail energy charge in ERCOT | Eliminations / Corporate and Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Retail energy charge in ERCOT | Retail | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	8,064	7,674	6,971
Retail energy charge in ERCOT | Texas | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Retail energy charge in ERCOT | East | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Retail energy charge in ERCOT | West | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Retail energy charge in ERCOT | Asset Closure | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Retail energy charge in Northeast/Midwest
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	3,595	1,642	2,139
Retail energy charge in Northeast/Midwest | Eliminations / Corporate and Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Retail energy charge in Northeast/Midwest | Retail | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	3,595	1,642	2,139
Retail energy charge in Northeast/Midwest | Texas | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Retail energy charge in Northeast/Midwest | East | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Retail energy charge in Northeast/Midwest | West | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Retail energy charge in Northeast/Midwest | Asset Closure | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Wholesale generation revenue from ISO/RTO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,978	2,909	4,293
Wholesale generation revenue from ISO/RTO | Eliminations / Corporate and Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Wholesale generation revenue from ISO/RTO | Retail | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Wholesale generation revenue from ISO/RTO | Texas | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	399	1,190	1,277
Wholesale generation revenue from ISO/RTO | East | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,351	1,298	1,987
Wholesale generation revenue from ISO/RTO | West | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	228	421	467
Wholesale generation revenue from ISO/RTO | Asset Closure | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	562
Capacity revenue from ISO/RTO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	74	98	103
Capacity revenue from ISO/RTO | Eliminations / Corporate and Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Capacity revenue from ISO/RTO | Retail | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Capacity revenue from ISO/RTO | Texas | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Capacity revenue from ISO/RTO | East | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	74	98	76
Net capacity sold		233	361
Net capacity purchased		135	285
Capacity revenue from ISO/RTO | East | Operating Segments | Operating revenues
Disaggregation of Revenue [Line Items]
Net capacity sold	126
Net capacity purchased	52
Capacity revenue from ISO/RTO | East | Operating Segments | Fuel, purchased power costs, and delivery fees/Depreciation and amortization
Disaggregation of Revenue [Line Items]
Net capacity sold	116	73	167
Net capacity purchased	139	82	212
Capacity revenue from ISO/RTO | West | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Capacity revenue from ISO/RTO | Asset Closure | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	27
Net capacity sold			27
Revenue from other wholesale contracts
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,050	1,481	2,125
Revenue from other wholesale contracts | Eliminations / Corporate and Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Revenue from other wholesale contracts | Retail | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	0
Revenue from other wholesale contracts | Texas | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	422	505	696
Revenue from other wholesale contracts | East | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	398	797	1,256
Revenue from other wholesale contracts | West | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	230	179	151
Revenue from other wholesale contracts | Asset Closure | Operating Segments
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0	22
Total other revenues
Disaggregation of Revenue [Line Items]
Operating revenues	2,463	975	(1,903)
Total other revenues | Eliminations / Corporate and Other
Disaggregation of Revenue [Line Items]
Operating revenues	(7,506)	(6,576)	(4,754)
Total other revenues | Retail | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	1,138	1,256	345
Total other revenues | Texas | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	4,573	2,284	1,905
Total other revenues | East | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	3,838	3,697	1,110
Total other revenues | West | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	419	314	(282)
Total other revenues | Asset Closure | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	1	0	(227)
Transferable PTC revenues
Disaggregation of Revenue [Line Items]
Operating revenues	556	10
Transferable PTC revenues | Eliminations / Corporate and Other
Disaggregation of Revenue [Line Items]
Operating revenues	0	0
Transferable PTC revenues | Retail | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	0	0
Transferable PTC revenues | Texas | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	292	10
Transferable PTC revenues | East | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	264	0
Transferable PTC revenues | West | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	0	0
Transferable PTC revenues | Asset Closure | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	0	0
Hedging revenues — realized
Disaggregation of Revenue [Line Items]
Operating revenues	895	252	264
Hedging revenues — realized | Eliminations / Corporate and Other
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	1
Hedging revenues — realized | Retail | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	1,241	1,063	875
Hedging revenues — realized | Texas | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	(453)	(885)	(67)
Hedging revenues — realized | East | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	31	43	(247)
Hedging revenues — realized | West | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	84	67	35
Hedging revenues — realized | Asset Closure | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	(8)	(36)	(333)
Hedging revenue — unrealized
Disaggregation of Revenue [Line Items]
Operating revenues	1,013	714	(2,163)
Hedging revenue — unrealized | Eliminations / Corporate and Other
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0
Hedging revenue — unrealized | Retail | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	(168)	191	(532)
Hedging revenue — unrealized | Texas | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	700	(714)	(637)
Hedging revenue — unrealized | East | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	143	958	(770)
Hedging revenue — unrealized | West | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	329	243	(326)
Hedging revenue — unrealized | Asset Closure | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	9	36	102
Intangible amortization and other revenues
Disaggregation of Revenue [Line Items]
Operating revenues	(1)	(1)	(4)
Intangible amortization and other revenues | Eliminations / Corporate and Other
Disaggregation of Revenue [Line Items]
Operating revenues	2	2	0
Intangible amortization and other revenues | Retail | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	1	2	2
Intangible amortization and other revenues | Texas | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0
Intangible amortization and other revenues | East | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	(4)	(5)	(6)
Intangible amortization and other revenues | West | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0
Intangible amortization and other revenues | Asset Closure | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0
Intersegment sales
Disaggregation of Revenue [Line Items]
Operating revenues	0	0	0
Intersegment sales | Eliminations / Corporate and Other
Disaggregation of Revenue [Line Items]
Operating revenues	(7,508)	(6,578)	(4,755)
Intersegment sales | Retail | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	64	0	0
Intersegment sales | Texas | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	4,034	3,873	2,609
Intersegment sales | East | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	3,404	2,701	2,133
Intersegment sales | West | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	6	4	9
Intersegment sales | Asset Closure | Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues	$ 0	$ 0	$ 4

Revenue - Narrative (Details)

Revenue - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Unbilled receivables, current	$ 802	$ 614
Selling, General and Administrative Expenses
Disaggregation of Revenue [Line Items]
Capitalized contract cost, amortization	97	88	$ 83
Operating revenues
Disaggregation of Revenue [Line Items]
Capitalized contract cost, amortization	6	6	$ 6
Costs to Acquire Residential and Business Retail Customers
Disaggregation of Revenue [Line Items]
Capitalized contract cost, net	$ 114	$ 97
Minimum | Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers, payment terms, number of days due from invoice date	15 days
Maximum | Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers, payment terms, number of days due from invoice date	60 days

Revenue - Revenue, Remaining Pe

Revenue - Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction (Details) $ in Millions	Dec. 31, 2024 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 2,969
Revenue, remaining performance obligation, expected timing of satisfaction, start date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 1,123
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, remaining performance obligation, expected timing of satisfaction, start date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 825
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]
Remaining performance obligations	$ 289
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]
Remaining performance obligations	$ 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]
Remaining performance obligations	$ 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]
Remaining performance obligations	$ 548
Revenue, remaining performance obligation, expected timing of satisfaction, period

Revenue - Schedule of Accounts,

Revenue - Schedule of Accounts, Notes, Loans and Financing Receivable (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Financing Receivable, Allowance for Credit Loss [Line Items]
Wholesale and retail trade accounts receivable	$ 2,061	$ 1,735
Allowance for credit losses	(79)	(61)	$ (65)
Total trade accounts receivable — net	1,982	1,674
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Allowance for credit losses on accounts receivable at beginning of period	61	65	45
Increase for bad debt expense	183	164	179
Decrease for account write-offs	(165)	(168)	(159)
Allowance for credit losses on accounts receivable at end of period	79	61	$ 65
Trade accounts receivable from contracts with customers — net
Financing Receivable, Allowance for Credit Loss [Line Items]
Total trade accounts receivable — net	1,514	1,239
Other trade accounts receivable — net
Financing Receivable, Allowance for Credit Loss [Line Items]
Total trade accounts receivable — net	$ 468	$ 435

Government Assistance (Details)

Government Assistance (Details) $ in Millions	1 Months Ended		12 Months Ended
	Sep. 30, 2024 USD ($)	Jun. 30, 2023 USD ($) MW	Dec. 31, 2024 USD ($) MW	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Jan. 31, 2025 USD ($) MW	Jan. 16, 2025 MW	Oct. 31, 2024 USD ($)
Property, Plant and Equipment [Line Items]
Operating revenues			$ 17,224	$ 14,779	$ 13,728
Investment tax credit sold under agreements, carrying amount								$ 156
Production tax credit sold under agreements								$ 10
Moss Landing Power Plant (Battery Storage Project) | Moss Landing Battery Energy Storage System Phase III
Property, Plant and Equipment [Line Items]
Battery energy storage system capacity | MW		350
Investment tax credit		$ 154
Additional investment tax credit	$ 2
Investment tax credit sold under agreements, carrying amount	$ 156
Moss Landing Power Plant (Battery Storage Project) | Moss Landing Battery Energy Storage System Phase III | Subsequent Event
Property, Plant and Equipment [Line Items]
Battery energy storage system capacity | MW						300	300
Baldwin Facility
Property, Plant and Equipment [Line Items]
Battery energy storage system capacity | MW		2
Investment tax credit			$ 57
Solar energy storage system capacity | MW			68
Coffeen Facility
Property, Plant and Equipment [Line Items]
Battery energy storage system capacity | MW		2
Investment tax credit			$ 45
Solar energy storage system capacity | MW			44
Transferable Nuclear Production Tax Credit Revenues
Property, Plant and Equipment [Line Items]
Operating revenues			$ 545
Transferable Nuclear Production Tax Credit Revenues | Subsequent Event
Property, Plant and Equipment [Line Items]
Production tax credit sold under agreements						$ 200
Transferable Solar Production Tax Credit Revenues
Property, Plant and Equipment [Line Items]
Operating revenues			$ 11

Income Taxes - Schedule of Comp

Income Taxes - Schedule of Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Current:
U.S. Federal	$ 2	$ (1)	$ 2
State	46	52	7
Total current	48	51	9
Deferred:
U.S. Federal	561	421	(304)
State	46	36	(55)
Total deferred	607	457	(359)
Income tax expense (benefit)	$ 655	$ 508	$ (350)

Income Taxes - Schedule of Effe

Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Income (loss) before income taxes	$ 3,467	$ 2,000	$ (1,560)
U.S. federal statutory rate	21%	21%	21%
Income taxes at the U.S. federal statutory rate	$ 728	$ 420	$ (328)
State tax, net of federal benefit	80	86	(19)
Nondeductible TRA accretion	2	41	18
Transferable PTC revenues	(115)	(2)	0
Equity awards	(53)	(3)	(3)
Valuation allowance	(2)	(20)	(8)
Release of Uncertain Tax Positions	0	(35)	0
Other	15	21	(10)
Income tax expense (benefit)	$ 655	$ 508	$ (350)
Effective tax rate	18.90%	25.40%	22.40%

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Noncurrent Deferred Income Tax Assets
Tax credit carryforwards	$ 86	$ 84
Loss carryforwards	949	1,081
Identifiable intangible assets	340	380
Long-term debt	225	173
Employee benefit obligations	133	117
Commodity contracts and interest rate swaps	383	664
Other	36	33
Total deferred tax assets	2,152	2,532
Noncurrent Deferred Income Tax Liabilities
Property, plant, and equipment	2,765	1,264
Total deferred tax liabilities	2,765	1,264
Valuation allowance	75	46
Net Deferred Income Tax Liability	$ (688)
Net Deferred Income Tax Asset		$ 1,222

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Contingency [Line Items]
Deferred tax liabilities, net	$ 688
Operating loss carryforwards	3,200
Deferred tax liabilities, other comprehensive income	4	$ 0
Uncertain tax positions	$ 4	0	$ 36	$ 38
Tax Matters Agreements, Restriction Duration	2 years
State and Local Jurisdiction
Income Tax Contingency [Line Items]
Valuation allowance, deferred tax asset, increase (decrease), amount	$ 2	$ 20
Internal Revenue Service (IRS)
Income Tax Contingency [Line Items]
Valuation allowance, deferred tax asset, increase (decrease), amount	$ 30

Income Taxes - Schedule of Unre

Income Taxes - Schedule of Unrecognized Tax Benefits Roll Forward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Unrecognized Tax Benefits [Roll Forward]
Balance at beginning of period, excluding interest and penalties	$ 0	$ 36	$ 38
Additions based on tax positions related to prior years	4	0	0
Reductions based on tax positions related to prior years	0	0	(1)
Reductions related to the lapse of the tax statute of limitations	0	(35)	0
Settlements with taxing authorities	0	(1)	(1)
Balance at end of period, excluding interest and penalties	$ 4	$ 0	$ 36

Property, Plant, and Equipmen_2

Property, Plant, and Equipment - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Depreciation			$ 1,670	$ 1,344	$ 1,388
Impairment of long-lived and other assets			$ 0	$ 49	$ 74
Kincaid | Kincaid
Impairment of long-lived and other assets	$ 49
Kincaid Generation, Property, Plant and Equipment | East
Impairment of long-lived and other assets	45
Kincaid Generation, Inventory | East
Impairment of long-lived and other assets	2
Kincaid Generation, Operating Lease Right-Of-Use Assets | East
Impairment of long-lived and other assets	$ 2
Miami Fort Power Station, Property, Plant and Equipment and Inventory | Miami Fort
Impairment of long-lived and other assets		$ 74
Miami Fort Power Station, Property, Plant And Equipment | East
Impairment of long-lived and other assets		71
Miami Fort Power Station, Inventory | East
Impairment of long-lived and other assets		$ 3
Minimum
Property, plant and equipment, useful life			1 year
Maximum
Property, plant and equipment, useful life			29 years

Property, Plant, and Equipmen_3

Property, Plant, and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Property, Plant and Equipment [Line Items]
Less accumulated depreciation	$ (8,020,000)	$ (6,657,000)
Finance lease right-of-use assets (net of accumulated amortization)	153,000	160,000
Nuclear fuel (net of accumulated amortization of $409 million and $120 million)	1,434,000	379,000
Property, plant, and equipment — net	18,173,000	12,432,000
Depreciable Property, Plant and Equipment
Property, Plant and Equipment [Line Items]
Total	23,546,000	18,028,000
Property, plant, and equipment — net	15,526,000	11,371,000
Power generation and structures
Property, Plant and Equipment [Line Items]
Total	22,783,000	17,297,000
Land
Property, Plant and Equipment [Line Items]
Total	603,000	572,000
Office and other equipment
Property, Plant and Equipment [Line Items]
Total	160,000	159,000
Construction work in progress
Property, Plant and Equipment [Line Items]
Total	1,060,000	522,000
Nuclear Fuel
Property, Plant and Equipment [Line Items]
Less accumulated depreciation	$ (409,000)	$ (120,000)

Property, Plant, and Equipmen_4

Property, Plant, and Equipment - Schedule of Planned Retirements of Generation Capacity (Details)	Dec. 31, 2024 MW
Retirement of Generation Facilities [Line Items]
Net Generation Capacity (MW)	7,486
Baldwin | East
Retirement of Generation Facilities [Line Items]
Net Generation Capacity (MW)	1,185
Coleto Creek | Texas
Retirement of Generation Facilities [Line Items]
Net Generation Capacity (MW)	650
Kincaid | East
Retirement of Generation Facilities [Line Items]
Net Generation Capacity (MW)	1,108
Miami Fort | East
Retirement of Generation Facilities [Line Items]
Net Generation Capacity (MW)	1,020
Newton | East
Retirement of Generation Facilities [Line Items]
Net Generation Capacity (MW)	615
Edwards | Asset Closure
Retirement of Generation Facilities [Line Items]
Net Generation Capacity (MW)	585
Joppa | Asset Closure
Retirement of Generation Facilities [Line Items]
Net Generation Capacity (MW)	802
Joppa | Asset Closure
Retirement of Generation Facilities [Line Items]
Net Generation Capacity (MW)	221
Zimmer | Asset Closure
Retirement of Generation Facilities [Line Items]
Net Generation Capacity (MW)	1,300

Goodwill and Identifiable Int_3

Goodwill and Identifiable Intangible Assets and Liabilities - Schedule of Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Goodwill [Roll Forward]
Balance at beginning of period	$ 2,583
Goodwill recorded in connection with the Energy Harbor Merger	224
Balance at end of period	2,807	$ 2,583
Retail Reporting Unit
Goodwill [Roll Forward]
Balance at beginning of period	2,461
Balance at end of period	2,461	2,461
Goodwill, expected tax deductible amount	$ 1,944	$ 1,944
Goodwill, expected tax deductible term	15 years	15 years
Texas Generation Reporting Unit
Goodwill [Roll Forward]
Balance at beginning of period	$ 122
Balance at end of period	$ 122	$ 122

Goodwill and Identifiable Int_4

Goodwill and Identifiable Intangible Assets and Liabilities - Schedule of Identifiable Intangible Assets and Liabilities Reported in the Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross Carrying Amount	$ 3,513	$ 2,937
Accumulated Amortization	2,641	2,414
Net	872	523
Total identifiable intangible assets	2,213	1,864
Total identifiable intangible liabilities	155	131
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 relationship
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross Carrying Amount	2,173	2,088
Accumulated Amortization	1,977	1,866
Net	196	222
Software and other technology-related assets
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross Carrying Amount	601	536
Accumulated Amortization	293	315
Net	308	221
Retail and wholesale contracts
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross Carrying Amount	503	233
Accumulated Amortization	353	217
Net	150	16
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	108	122
Other identifiable intangible assets
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross Carrying Amount	218	62
Accumulated Amortization	13	11
Net	205	51
Wholesale power and fuel purchase contracts
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Total identifiable intangible liabilities	$ 47	$ 9

Goodwill and Identifiable Int_5

Goodwill and Identifiable Intangible Assets and Liabilities - Schedule of Amortization Expense Related to Intangible Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets and liabilities	$ 573	$ 521	$ 604
Depreciation and amortization
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets and liabilities	$ 173	158	208
Retail customer relationship | Depreciation and amortization
Finite-Lived Intangible Assets [Line Items]
Remaining useful lives of identifiable intangible assets at December 31, 2024 (weighted average in years)	2 years
Amortization of intangible assets and liabilities	$ 111	98	137
Software and other technology-related assets | Depreciation and amortization
Finite-Lived Intangible Assets [Line Items]
Remaining useful lives of identifiable intangible assets at December 31, 2024 (weighted average in years)	3 years
Amortization of intangible assets and liabilities	$ 60	58	69
Retail and wholesale contracts | Operating revenues/Fuel, purchased power costs, and delivery fees
Finite-Lived Intangible Assets [Line Items]
Remaining useful lives of identifiable intangible assets at December 31, 2024 (weighted average in years)	3 years
Amortization of intangible assets and liabilities	$ (12)	8	7
Other identifiable intangible assets | Fuel, purchased power costs, and delivery fees/Depreciation and amortization
Finite-Lived Intangible Assets [Line Items]
Remaining useful lives of identifiable intangible assets at December 31, 2024 (weighted average in years)	4 years
Amortization of intangible assets and liabilities	$ 414	$ 357	$ 391

Goodwill and Identifiable Int_6

Goodwill and Identifiable Intangible Assets and Liabilities - Schedule of Estimated Amortization Expense of Identifiable Intangible Assets and Liabilities (Details) $ in Millions	Dec. 31, 2024 USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2025	$ 231
2026	167
2027	72
2028	51
2029	$ 34

Collateral Financing Agreemen_2

Collateral Financing Agreement With Affiliate (Details) $ in Millions	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Jun. 15, 2023 USD ($) security
Debt Instrument [Line Items]
Margin deposits posted under affiliate financing agreement	$ 435	$ 439
Margin deposits financing with affiliate	435	$ 439
7.233% Senior Secured Notes Due 2028 | Vistra Operations Senior Secured Notes:
Debt Instrument [Line Items]
Debt instrument, face amount	$ 450
Stated debt interest rate (percent)	7.233%
Pre-Capitalized Trust Securities
Debt Instrument [Line Items]
Derivative, number of instruments held | security			450,000
Derivative, notional amount			$ 450
Facility Agreement
Debt Instrument [Line Items]
Facility fee, percentage	3.3608%

Debt, Credit Facilities, and _3

Debt, Credit Facilities, and Financings - Schedule of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Debt Instrument [Line Items]
Long-term debt before unamortized premiums, discounts, and issuance costs	$ 16,469	$ 14,517
Unamortized premiums, discounts, and debt issuance costs	(171)	(115)
Long-term debt including debt due currently	16,298	14,402
Accounts receivable financing	750	0
Forward repurchase obligation	1,335	0
Project-level debt
Debt Instrument [Line Items]
Long-term debt before unamortized premiums, discounts, and issuance costs	1,064	0
Vistra Operations debt
Debt Instrument [Line Items]
Long-term debt before unamortized premiums, discounts, and issuance costs	$ 15,405	$ 14,517

Debt, Credit Facilities, and _4

Debt, Credit Facilities, and Financings - Schedule of Long-Term Debt Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Debt Instrument [Line Items]
Total long-term debt including amounts due currently	$ 16,298	$ 14,402
Total other long-term debt	55	67
Unamortized premiums, discounts, and debt issuance costs	(171)	(115)
Less amounts due currently	(880)	(2,286)
Total long-term debt less amounts due currently	$ 15,418	12,116
Bridge Loan
Debt Instrument [Line Items]
Stated debt interest rate (percent)	1.625%
Vistra Operations Senior Secured Notes:
Debt Instrument [Line Items]
Total long-term debt including amounts due currently	$ 5,144	5,650
Energy Harbor Revenue Bonds
Debt Instrument [Line Items]
Total long-term debt including amounts due currently	431	0
Vistra Operations Senior Unsecured Notes:
Debt Instrument [Line Items]
Total long-term debt including amounts due currently	7,300	6,300
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	2,475	2,500
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	0
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	0
4.875% Senior Secured Notes, due May 13, 2024 | Vistra Operations Senior Secured Notes:
Debt Instrument [Line Items]
Total long-term debt including amounts due currently	$ 0	400
Stated debt interest rate (percent)	4.875%
3.550% Senior Secured Notes, due July 15, 2024 | Vistra Operations Senior Secured Notes:
Debt Instrument [Line Items]
Total long-term debt including amounts due currently	$ 0	1,500
Stated debt interest rate (percent)	3.55%
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	1,100
Stated debt interest rate (percent)	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	0
Stated debt interest rate (percent)	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
Stated debt interest rate (percent)	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
Stated debt interest rate (percent)	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
Stated debt interest rate (percent)	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	0
Stated debt interest rate (percent)	6%
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	0
Stated debt interest rate (percent)	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	$ 0
Stated debt interest rate (percent)	3.375%	3.375%
4.750% Revenue Bond, due June 1, 2033 and July 1, 2023 | Energy Harbor Revenue Bonds
Debt Instrument [Line Items]
Total long-term debt including amounts due currently	$ 285	$ 0
Stated debt interest rate (percent)	4.75%	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	$ 0
Stated debt interest rate (percent)	3.75%	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
Stated debt interest rate (percent)	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
Stated debt interest rate (percent)	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
Stated debt interest rate (percent)	5%
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
Stated debt interest rate (percent)	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
Stated debt interest rate (percent)	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	0
Stated debt interest rate (percent)	6.875%
Equipment Financing Agreements | Equipment Financing Agreements
Debt Instrument [Line Items]
Total long-term debt including amounts due currently	$ 55	$ 67

Debt, Credit Facilities, and _5

Debt, Credit Facilities, and Financings - Schedule of Maturities of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Debt Disclosure [Abstract]
2025	$ 885
2026	1,792
2027	3,427
2028	27
2029	2,177
Thereafter	8,161
Unamortized premiums, discounts, and debt issuance costs	(171)	$ (115)
Long-term debt including debt due currently	$ 16,298	$ 14,402

Debt, Credit Facilities, and _6

Debt, Credit Facilities, and Financings - Schedule of Line of Credit Facilities (Details) - USD ($) $ in Millions		12 Months Ended
	Dec. 31, 2024	Dec. 16, 2024
Debt Instrument [Line Items]
Facility Limit	$ 8,729
Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)	3,539
Letters of Credit Outstanding	1,278
Available Capacity	2,933
Line of Credit
Debt Instrument [Line Items]
Facility Limit	5,915
Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)	2,475
Letters of Credit Outstanding	1,278
Available Capacity	2,162
Vistra Operations debt
Debt Instrument [Line Items]
Facility Limit	7,665
Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)	2,475
Letters of Credit Outstanding	1,278
Available Capacity	2,933
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]
Facility Limit	3,440
Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)	0
Letters of Credit Outstanding	1,278
Available Capacity	2,162
Term Loan B-3 Facility | Line of Credit
Debt Instrument [Line Items]
Facility Limit	2,475
Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)	2,475
Letters of Credit Outstanding	0
Available Capacity	0
Vistra Operations Commodity-Linked Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Facility Limit	1,750
Cash Borrowings (Long-Term Debt, Including Amounts Due Currently)	0
Letters of Credit Outstanding	0
Available Capacity	771
BCOP Credit Facilities Tax Credit Bridge Loan
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 Facilities Tax Credit Bridge Loan | 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 Facilities Tax Credit Bridge Loan | 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 | Line of Credit | Secured Debt
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	2%	2.75%
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

Debt, Credit Facilities, and _7

Debt, Credit Facilities, and Financings - Narrative (Details) $ in Thousands		1 Months Ended						3 Months Ended	11 Months Ended	12 Months Ended
	Dec. 31, 2024 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2024 USD ($)	May 31, 2024 USD ($)	Apr. 30, 2024 USD ($)	Mar. 31, 2024 USD ($)	Jan. 31, 2024 USD ($)	Mar. 31, 2024 USD ($)	Dec. 09, 2024	Dec. 31, 2024 USD ($)	Dec. 16, 2024	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Jul. 31, 2024 USD ($)	Jun. 30, 2024 USD ($)
Debt Instrument [Line Items]
Facility Limit	$ 8,729,000	$ 8,729,000	$ 8,729,000							$ 8,729,000
Line of credit facility, borrowings outstanding	3,539,000	3,539,000	3,539,000							3,539,000
Maximum allowable distribution to parent company by consolidated subsidiary without consent	8,200,000	8,200,000	8,200,000							8,200,000
Total long-term debt including amounts due currently	16,298,000	16,298,000	16,298,000							16,298,000		$ 14,402,000
Proceeds from lines of credit										50,000		100,000	$ 1,750,000
Debt extinguishment gain										6,000		3,000	1,000
Accounts receivable financing	750,000	750,000	750,000							750,000		0
Accounts receivable repurchase facility, term														1 month
BCOP Credit Facility, Tax Credit Bridge Loan due November 1, 2025 / December 3, 2026
Debt Instrument [Line Items]
Facility Limit	367,000	367,000	367,000							367,000
Line of credit facility, borrowings outstanding	367,000	367,000	367,000							367,000
Alternate Letter Of Credit Facility | Letter of Credit
Debt Instrument [Line Items]
Facility Limit	500,000	500,000	500,000							500,000
Letters of credit outstanding, amount	500,000	500,000	500,000							500,000
Line of credit facility, increase (decrease), net				$ 500,000
Accounts Receivable Securitization Program
Debt Instrument [Line Items]
Accounts receivable financing	750,000	750,000	750,000							750,000		0
Accounts receivable securitization program, gross trade accounts receivable held by special purpose subsidiary	1,334,000	1,334,000	1,334,000							1,334,000
Accounts Receivable Securitization Program | Minimum
Debt Instrument [Line Items]
Account receivable securitization program, total borrowing capacity, july 2023 through july 2024															$ 750,000
Accounts Receivable Securitization Program | Maximum
Debt Instrument [Line Items]
Account receivable securitization program, total borrowing capacity, july 2024 through july 2025	1,000,000	1,000,000	1,000,000							1,000,000
Repurchase Facility
Debt Instrument [Line Items]
Accounts receivable repurchase facility, maximum borrowing capacity														$ 125,000
Accounts receivable repurchase facility, amounts borrowed	0	0	0							0		0
Vistra Operations Company LLC | Vistra Corp.
Debt Instrument [Line Items]
Maximum allowable distribution to parent company by consolidated subsidiary without consent	8,200,000	8,200,000	8,200,000							8,200,000
Cash dividends paid										1,705,000		$ 1,625,000	$ 1,775,000
Line of Credit
Debt Instrument [Line Items]
Facility Limit	5,915,000	5,915,000	5,915,000							5,915,000
Line of credit facility, borrowings outstanding	2,475,000	2,475,000	2,475,000							2,475,000
Line of Credit | Revolving Credit Facility
Debt Instrument [Line Items]
Facility Limit	3,440,000	3,440,000	3,440,000							3,440,000
Line of credit facility, borrowings outstanding	0	0	0							0
Line of Credit | Senior Secured Term Loan B-3 Facility
Debt Instrument [Line Items]
Facility Limit	2,475,000	2,475,000	2,475,000							2,475,000
Line of credit facility, borrowings outstanding	$ 2,475,000	$ 2,475,000	$ 2,475,000							$ 2,475,000
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%	5.984%	5.984%							5.984%
Line of Credit | Construction/Term Loan Commitments | Secured Debt
Debt Instrument [Line Items]
Facility Limit	$ 528,000	$ 528,000	$ 528,000							$ 528,000
Line of Credit | Vistra Zero Term Loan B Facility | Secured Debt
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	2%										2.75%
Debt instrument, face amount						$ 700,000		$ 700,000
Proceeds from lines of credit						$ 690,000
Debt, weighted average interest rate	6.36%	6.36%	6.36%							6.36%
Line of Credit | Vistra Operations Company LLC
Debt Instrument [Line Items]
Facility Limit	$ 5,915,000	$ 5,915,000	$ 5,915,000							$ 5,915,000
Collateral suspension provision effective date, grace period, number of days										60 days
Debt instrument, interest rate curing period										5.23%		5.69%	4.30%
Line of Credit | Vistra Operations Company LLC | Revolving Credit Facility
Debt Instrument [Line Items]
Facility Limit	$ 3,440,000	$ 3,440,000	$ 3,440,000							$ 3,440,000		$ 3,175,000
Debt instrument, basis spread on variable rate										1.725%
Debt instrument, fee on undrawn amounts										0.270
Stated debt interest rate (percent)	1.725%	1.725%	1.725%							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%
Debt instrument, fee on undrawn amounts										0.350
Line of Credit | Vistra Operations Company LLC | Senior Secured Term Loan B-3 Facility
Debt Instrument [Line Items]
Line of credit facility, interest rate at period end	6.11%	6.11%	6.11%							6.11%
Debt instrument, periodic payment										$ 6,250
Line of Credit | Vistra Operations Company LLC | Senior Secured Term Loan B-3 Facility | Minimum
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate			1.75%
Line of Credit | Vistra Operations Company LLC | Senior Secured Term Loan B-3 Facility | Maximum
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate									2%
Revolving Credit Facility | Senior Secured Commodity-Linked Revolving Credit Facility
Debt Instrument [Line Items]
Facility Limit	$ 1,750,000	$ 1,750,000	$ 1,750,000							1,750,000
Line of credit facility, borrowings outstanding	0	0	0							0
Revolving Credit Facility | Vistra Zero Term Loan B Facility
Debt Instrument [Line Items]
Facility Limit	697,000	697,000	697,000							697,000
Line of credit facility, borrowings outstanding	697,000	697,000	697,000							$ 697,000
Revolving Credit Facility | Vistra Operations Company LLC | Senior Secured Commodity-Linked Revolving Credit Facility
Debt Instrument [Line Items]
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	771,000	771,000	771,000							$ 771,000
Revolving Credit Facility | Vistra Operations Company LLC | Senior Secured Commodity-Linked 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
Revolving Credit Facility | Vistra Operations Company LLC | Senior Secured Commodity-Linked Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate										2%
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	$ 3,000,000	$ 3,000,000							$ 3,000,000
Bridge Loan
Debt Instrument [Line Items]
Stated debt interest rate (percent)	1.625%	1.625%	1.625%							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	$ 367,000							$ 367,000		0
Letter of Credit
Debt Instrument [Line Items]
Stated debt interest rate (percent)	2%	2%	2%							2%
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, amount	$ 29,000	$ 29,000	$ 29,000							$ 29,000
Letter of Credit | Vistra Operations Company LLC | Secured Letter of Credit Facilities
Debt Instrument [Line Items]
Letters of credit outstanding, amount	$ 1,157,000	$ 1,157,000	$ 1,157,000							$ 1,157,000
Building financing
Debt Instrument [Line Items]
Stated debt interest rate (percent)	1.875%	1.875%	1.875%							1.875%
Term Loan
Debt Instrument [Line Items]
Stated debt interest rate (percent)	2%	2%	2%							2%
Vistra Operations Senior Notes
Debt Instrument [Line Items]
Debt instrument, face amount	$ 1,250,000	$ 1,250,000	$ 1,250,000							$ 1,250,000
Proceeds from debt, net of issuance costs		1,240,000
Debt extinguishment gain								$ 6,000
Vistra Operations Senior Notes | 5.050% Senior Secured Notes, due December 30, 2026
Debt Instrument [Line Items]
Debt instrument, face amount	500,000	500,000	500,000							500,000
Vistra Operations Senior Notes | 5.700% Senior Secured Notes, due December 30, 2034
Debt Instrument [Line Items]
Debt instrument, face amount	750,000	750,000	750,000							750,000
Vistra Operations Senior Notes | 4.875% Senior Secured Notes, due May 13, 2024
Debt Instrument [Line Items]
Stated debt interest rate (percent)				4.875%
Vistra Operations Senior Notes | 3.550% Senior Secured Notes, due July 15, 2024
Debt Instrument [Line Items]
Stated debt interest rate (percent)														3.55%
Vistra Operations Senior Notes | 6.000% Senior Secured Notes, due April 15, 2034
Debt Instrument [Line Items]
Stated debt interest rate (percent)					6%
Debt instrument, face amount					$ 500,000
Proceeds from debt, net of issuance costs					$ 495,000
Vistra Operations Senior Notes | 6.875% Senior Unsecured Notes, due April 15, 2032
Debt Instrument [Line Items]
Stated debt interest rate (percent)					6.875%
Debt instrument, face amount					$ 1,000,000
Proceeds from debt, net of issuance costs					$ 990,000
Revenue Bonds
Debt Instrument [Line Items]
Debt instrument, face amount	431,000	431,000	431,000							431,000
Vistra Operations Senior Secured Notes:
Debt Instrument [Line Items]
Total long-term debt including amounts due currently	$ 5,144,000	$ 5,144,000	$ 5,144,000							$ 5,144,000		5,650,000
Debt instrument, repaid, principal							$ 759,000
Vistra Operations Senior Secured Notes: | 5.050% Senior Secured Notes, due December 30, 2026
Debt Instrument [Line Items]
Stated debt interest rate (percent)	5.05%	5.05%	5.05%							5.05%
Total long-term debt including amounts due currently	$ 500,000	$ 500,000	$ 500,000							$ 500,000		0
Vistra Operations Senior Secured Notes: | 5.700% Senior Secured Notes, due December 30, 2034
Debt Instrument [Line Items]
Stated debt interest rate (percent)	5.70%	5.70%	5.70%							5.70%
Total long-term debt including amounts due currently	$ 750,000	$ 750,000	$ 750,000							$ 750,000		0
Vistra Operations Senior Secured Notes: | 4.875% Senior Secured Notes, due May 13, 2024
Debt Instrument [Line Items]
Stated debt interest rate (percent)	4.875%	4.875%	4.875%							4.875%
Total long-term debt including amounts due currently	$ 0	$ 0	$ 0							$ 0		400,000
Debt instrument, repaid, principal							58,000
Vistra Operations Senior Secured Notes: | 3.550% Senior Secured Notes, due July 15, 2024
Debt Instrument [Line Items]
Stated debt interest rate (percent)	3.55%	3.55%	3.55%							3.55%
Total long-term debt including amounts due currently	$ 0	$ 0	$ 0							$ 0		1,500,000
Debt instrument, repaid, principal							345,000
Vistra Operations Senior Secured Notes: | 6.000% Senior Secured Notes, due April 15, 2034
Debt Instrument [Line Items]
Stated debt interest rate (percent)	6%	6%	6%							6%
Total long-term debt including amounts due currently	$ 500,000	$ 500,000	$ 500,000							$ 500,000		0
Vistra Operations Senior Secured Notes: | 6.950% Senior Secured Notes, due October 15, 2033
Debt Instrument [Line Items]
Stated debt interest rate (percent)	6.95%	6.95%	6.95%							6.95%
Total long-term debt including amounts due currently	$ 1,050,000	$ 1,050,000	$ 1,050,000							$ 1,050,000		1,050,000
Vistra Operations Senior Secured Notes: | 5.125% Senior Secured Notes, due May 13, 2025
Debt Instrument [Line Items]
Stated debt interest rate (percent)	5.125%	5.125%	5.125%							5.125%
Total long-term debt including amounts due currently	$ 744,000	$ 744,000	$ 744,000							$ 744,000		$ 1,100,000
Debt instrument, repaid, principal							$ 356,000

Debt, Credit Facilities, and _8

Debt, Credit Facilities, and Financings - Schedule of Repurchase Obligation (Details) - Vistra Vision $ in Millions	Dec. 31, 2024 USD ($)
Redeemable Noncontrolling Interest [Line Items]
2025	$ 781
2026	669
Thereafter	0
Total scheduled payments under the UPAs	$ 1,450

Debt, Credit Facilities, and _9

Debt, Credit Facilities, and Financings - Schedule of Debt Instrument Redemption (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Sep. 30, 2024
Redeemable Noncontrolling Interest [Line Items]
Dividends to noncontrolling interest		$ (15)
Principal payment on Closing Date		$ (1,748)	$ 0	$ 0
Discount rate	6%	6%
Vistra Vision
Redeemable Noncontrolling Interest [Line Items]
Redeemable NCI at September 30, 2024					$ 3,198
Income attributable to redeemable noncontrolling interest	$ 51
Dividends to noncontrolling interest	(165)
Principal payment on Closing Date	(1,749)
Forward repurchase obligation		$ 1,335
Noncontrolling Interest in Subsidiary
Redeemable Noncontrolling Interest [Line Items]
Dividends to noncontrolling interest		(15)
Noncontrolling Interest in Subsidiary | Vistra Vision
Redeemable Noncontrolling Interest [Line Items]
Redeemable noncontrolling interest balance at Closing Date	$ 3,084	$ 3,084

Debt, Credit Facilities, and_10

Debt, Credit Facilities, and Financings - Schedule of Interest Expense and Related Charges (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Debt Disclosure [Abstract]
Interest expense	$ 936	$ 654	$ 591
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps	(53)	36	(250)
Amortization of debt issuance costs, discounts, and premiums	34	26	28
Facility Fee expense	15	8	0
Debt extinguishment gain	(6)	(3)	(1)
Capitalized interest	(77)	(37)	(29)
Other	51	56	29
Total interest expense and related charges	$ 900	$ 740	$ 368

Leases - Narrative (Details)

Leases - Narrative (Details)	12 Months Ended
	Dec. 31, 2024
Lessee, Lease, Description [Line Items]
Lease renewal term, lessee	17 years
Minimum
Lessee, Lease, Description [Line Items]
Remaining lease term	1 year
Maximum
Lessee, Lease, Description [Line Items]
Remaining lease term	42 years

Leases - Schedule of Lease Cost

Leases - Schedule of Lease Cost (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Operating lease cost	$ 17	$ 12	$ 9
Finance lease:
Finance lease right-of-use asset amortization	8	10	9
Interest on lease liabilities	11	11	12
Total finance lease cost	19	21	21
Variable lease cost	29	37	22
Short-term lease cost	56	44	47
Total lease cost	$ 121	$ 114	$ 99

Leases - Schedule of Lease Bala

Leases - Schedule of Lease Balance Sheet Information (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Lease assets:
Operating lease right-of-use assets (reported in other noncurrent assets in the consolidated balance sheets)	$ 106	$ 50
Finance lease right-of-use assets, net of accumulated amortization (reported in property, plant, and equipment in the consolidated balance sheets)	153	160
Total lease right-of-use assets	259	210
Current lease liabilities (reported in other current liabilities in the consolidated balance sheets):
Operating lease liabilities	13	7
Finance lease liabilities	9	9
Total current lease liabilities	22	16
Noncurrent lease liabilities (reported in other noncurrent liabilities and deferred credits in the consolidated balance sheets):
Operating lease liabilities	98	48
Finance lease liabilities	218	227
Total noncurrent lease liabilities	316	275
Total lease liabilities	$ 338	$ 291
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other noncurrent assets	Other noncurrent assets
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Property, plant, and equipment — net	Property, plant, and equipment — net
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other current liabilities	Other current liabilities
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other current liabilities	Other current liabilities
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other noncurrent liabilities and deferred debits	Other noncurrent liabilities and deferred debits
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other noncurrent liabilities and deferred debits	Other noncurrent liabilities and deferred debits

Leases - Schedule of Lease Cash

Leases - Schedule of Lease Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Non-cash disclosure upon commencement of new lease:
Right-of-use assets obtained in exchange for new operating lease liabilities	$ 68	$ 3	$ 19
Right-of-use assets obtained in exchange for new finance lease liabilities	0	0	6
Non-cash disclosure upon modification of existing lease:
Modification of operating lease right-of-use assets	1	7	0
Modification of finance lease right-of-use assets	$ 0	$ (1)	$ 4

Leases - Schedule of Weighted A

Leases - Schedule of Weighted Average Remaining Lease Terms and Discount Rates (Details)	Dec. 31, 2024	Dec. 31, 2023
Weighted average remaining lease term:
Operating lease	23 years 9 months 18 days	20 years 1 month 6 days
Finance lease	23 years 8 months 12 days	24 years
Weighted average discount rate:
Operating lease	7.85%	6.49%
Finance lease	4.82%	4.81%

Leases - Schedule of Maturity o

Leases - Schedule of Maturity of Operating and Finance Lease Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Operating Lease
2025	$ 19
2026	13
2027	14
2028	10
2029	8
Thereafter	222
Total lease payments	286
Less: Imputed interest	(175)
Present value of lease liabilities	111
Finance Lease
2025	19
2026	14
2027	13
2028	13
2029	13
Thereafter	331
Total lease payments	403
Less: Imputed interest	(176)
Present value of lease liabilities	227
Total Lease
2025	38
2026	27
2027	27
2028	23
2029	21
Thereafter	553
Total lease payments	689
Less: Imputed interest	(351)
Total lease liabilities	$ 338	$ 291

Derivatives - Schedule of Inter

Derivatives - Schedule of Interest Rate Derivatives (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Derivative [Line Items]
Long-term debt, percentage bearing variable interest, amount	$ 2,300
Debt Instrument, Variable Interest Rate, Type [Extensible Enumeration]	Secured Overnight Financing Rate (SOFR) [Member]
Interest Rate Swap, Swapped to Fixed, Expiration Date July 2026
Derivative [Line Items]
Derivative, notional amount	$ 3,000
Interest Rate Swap, Swapped to Fixed, Expiration Date July 2026 | Minimum
Derivative [Line Items]
Rate range	4.64%
Interest Rate Swap, Swapped to Fixed, Expiration Date July 2026 | Maximum
Derivative [Line Items]
Rate range	4.72%
Interest Rate Swap, Swapped to Variable, Expiration Date July 2026
Derivative [Line Items]
Derivative, notional amount	$ 700
Interest Rate Swap, Swapped to Variable, Expiration Date July 2026 | Minimum
Derivative [Line Items]
Rate range	3.19%
Interest Rate Swap, Swapped to Variable, Expiration Date July 2026 | Maximum
Derivative [Line Items]
Rate range	3.24%
Interest Rate Swap, Swapped to Fixed, Expiration Date December 2030
Derivative [Line Items]
Derivative, notional amount	$ 2,300	$ 1,625
Interest Rate Swap, Swapped to Fixed, Expiration Date December 2030 | Minimum
Derivative [Line Items]
Rate range	4.95%
Interest Rate Swap, Swapped to Fixed, Expiration Date December 2030 | Maximum
Derivative [Line Items]
Rate range	5.51%
Interest rate swaps
Derivative [Line Items]
Derivative, basis spread on variable rate	1.75%

Derivatives - Narrative (Detail

Derivatives - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Nov. 30, 2024	Dec. 31, 2023
Derivative Instruments, Gain (Loss) [Line Items]
Long-term debt, percentage bearing variable interest, amount	$ 2,300
Interest Rate Swap, Swapped to Fixed, Effective July 2026 and Expiration Date December 2030
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, notional amount		$ 675
Interest Rate Swap, Swapped to Fixed, Expiration Date December 2030
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, notional amount	2,300		$ 1,625
Interest Rate Swap, Swapped To Fixed, Effective August 2026 And Expiration Date December 2030
Derivative Instruments, Gain (Loss) [Line Items]
Long-term debt, percentage bearing variable interest, amount	2,300
Credit risk contract
Derivative Instruments, Gain (Loss) [Line Items]
Total credit risk exposure to all counterparties related to derivative contracts	3,772
Net exposure to those counterparties after taking into effect master netting arrangements, setoff provisions and collateral	776
Largest net exposure to single counterparty	$ 262
Credit risk exposure to banking and financial sector percentage	75%
Net exposure to banking and financial sector percentage	26%

Derivatives - Schedule of Deriv

Derivatives - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Derivatives, Fair Value [Line Items]
Derivative assets (liabilities), fair value, net	$ (1,391)	$ (2,724)
Derivative assets (liabilities), offsetting instruments	0	0
Derivative assets (liabilities): financial collateral (received) pledged	183	944
Derivative assets (liabilities), net amounts	(1,208)	(1,780)
Current assets
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, net	2,587	3,645
Noncurrent assets
Derivatives, Fair Value [Line Items]
Derivative asset, fair value, net	740	577
Current liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, fair value, net	(3,351)	(5,258)
Noncurrent liabilities
Derivatives, Fair Value [Line Items]
Derivative liability, fair value, net	(1,367)	(1,688)
Commodity Contracts
Derivatives, Fair Value [Line Items]
Derivative assets (liabilities), fair value, gross assets	3,226	4,144
Derivative assets (liabilities), fair value, gross liability	(4,686)	(6,884)
Derivative assets, offsetting instruments	(2,532)	(3,519)
Derivative liability, offsetting instruments	2,532	3,519
Derivative assets, financial collateral (received) pledged	(50)	(26)
Derivative liabilities, financial collateral (received) pledged	233	970
Derivative assets, net amounts	644	599
Derivative liability, net amounts	(1,921)	(2,395)
Commodity Contracts | Current assets
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	(2,551)	(3,585)
Derivative liabilities, far value, gross asset	(2)	(7)
Commodity Contracts | Noncurrent assets
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	(677)	(565)
Derivative liabilities, far value, gross asset	(1)	(1)
Commodity Contracts | Current liabilities
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	0	(1)
Derivative liabilities, far value, gross asset	(3,333)	(5,233)
Commodity Contracts | Noncurrent liabilities
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	(2)	(5)
Derivative liabilities, far value, gross asset	(1,356)	(1,659)
Interest Rate Swaps
Derivatives, Fair Value [Line Items]
Derivative assets (liabilities), fair value, gross assets	96	64
Derivative assets (liabilities), fair value, gross liability	(27)	(48)
Derivative assets, offsetting instruments	(28)	(28)
Derivative liability, offsetting instruments	28	28
Derivative assets, financial collateral (received) pledged	0	0
Derivative liabilities, financial collateral (received) pledged	0	0
Derivative assets, net amounts	68	36
Derivative liability, net amounts	1	(20)
Interest Rate Swaps | Current assets
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	(34)	(53)
Derivative liabilities, far value, gross asset	0	0
Interest Rate Swaps | Noncurrent assets
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	(62)	(11)
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	(18)	(24)
Interest Rate Swaps | Noncurrent liabilities
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	0	0
Derivative liabilities, far value, gross asset	$ (9)	$ (24)

Derivatives - Schedule of Preta

Derivatives - Schedule of Pretax Effect on Net Income of Derivatives Not Under Hedge Accounting, Including Realized and Unrealized Effects (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Derivative Instruments, Gain (Loss) [Line Items]
Total reversals of previously recognized unrealized (gain) loss on derivative instruments	$ 1,172	$ 1,565	$ 1,234
Total unrealized net gains (losses) from changes in fair value on derivative instruments	36	(1,111)	(3,494)
Net gain (loss) on derivative instruments	$ 1,208	$ 454	$ (2,260)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating revenues	Operating revenues	Operating revenues
Interest rate swaps
Derivative Instruments, Gain (Loss) [Line Items]
Total reversals of previously recognized unrealized (gain) loss on derivative instruments	$ (41)	$ (78)	$ 16
Total unrealized net gains (losses) from changes in fair value on derivative instruments	94	42	234
Operating revenues | Commodity Contracts
Derivative Instruments, Gain (Loss) [Line Items]
Total reversals of previously recognized unrealized (gain) loss on derivative instruments	1,140	1,472	1,940
Total unrealized net gains (losses) from changes in fair value on derivative instruments	(127)	(758)	(4,103)
Fuel, purchased power costs, and delivery fees/Depreciation and amortization | Commodity Contracts
Derivative Instruments, Gain (Loss) [Line Items]
Total reversals of previously recognized unrealized (gain) loss on derivative instruments	73	171	(722)
Total unrealized net gains (losses) from changes in fair value on derivative instruments	$ 69	$ (395)	$ 375

Derivatives - Schedule of Notio

Derivatives - Schedule of Notional Amounts of Outstanding Derivative Positions (Details) gal in Millions, certificate in Millions, T in Millions, MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($) certificate GWh MMBTU T gal	Dec. 31, 2023 USD ($) certificate MMBTU GWh T gal
Natural gas
Derivatives, Fair Value [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	4,568	5,335
Electricity
Derivatives, Fair Value [Line Items]
Derivative, nonmonetary notional amount, energy measure | GWh	796,982	800,001
Financial transmission rights / Congestion revenue rights
Derivatives, Fair Value [Line Items]
Derivative, nonmonetary notional amount, energy measure | GWh	248,742	250,895
Coal
Derivatives, Fair Value [Line Items]
Derivative, nonmonetary notional amount, mass | T	27	35
Fuel oil
Derivatives, Fair Value [Line Items]
Derivative, nonmonetary notional amount, volume | gal	2	3
Emissions
Derivatives, Fair Value [Line Items]
Derivative, nonmonetary notional amount, mass | T	28	24
Renewable energy certificates
Derivatives, Fair Value [Line Items]
Nonmonetary notional volume | certificate	31	29
Interest rate swaps – variable/fixed
Derivatives, Fair Value [Line Items]
Derivative, notional amount | $	$ 5,300	$ 5,225
Interest rate swaps - fixed/variable
Derivatives, Fair Value [Line Items]
Derivative, notional amount | $	$ 700	$ 1,300

Derivatives - Credit Risk-Relat

Derivatives - Credit Risk-Related Contingent Features of Derivatives (Details) - Credit risk contract - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Credit Derivatives [Line Items]
Derivative liabilities, fair value, gross liability	$ (1,587)	$ (1,890)
Offsetting fair value under netting arrangements	724	692
Cash collateral and letters of credit	471	854
Liquidity exposure	$ (392)	$ (344)

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Debt Securities
Liabilities:
Debt, weighted average interest rate	3.99%	3.19%
Decommissioning fund investments, debt securities, average maturity	7 years	11 years
Decommissioning fund investments, debt maturities, one through five years, fair value	$ 1,045
Decommissioning fund investments, debt maturities, five through ten years, fair value	599
Decommissioning fund investments, debt maturities, after ten years, fair value	415
Fair Value, Recurring
Assets:
Sub-total	5	$ 14
Liabilities:
Total liabilities	5	14
Fair Value, Recurring | Equity Securities
Assets:
Assets measured at net asset value	821	579
Fair Value, Recurring | Commodity contract
Assets:
Assets	5	14
Liabilities:
Derivative liabilities	5	14
Fair Value, Recurring | Interest Rate Swaps
Assets:
Assets	0	0
Liabilities:
Derivative liabilities	0	0
Fair Value, Recurring | Total
Assets:
Sub-total	6,946	5,594
Total assets	7,767	6,173
Liabilities:
Total liabilities	4,718	6,946
Fair Value, Recurring | Total | Equity Securities
Assets:
Nuclear decommissioning trust	1,560	638
Fair Value, Recurring | Total | Debt Securities
Assets:
Nuclear decommissioning trust	2,059	734
Fair Value, Recurring | Total | Commodity contract
Assets:
Assets	3,231	4,158
Liabilities:
Derivative liabilities	4,691	6,898
Fair Value, Recurring | Total | Interest Rate Swaps
Assets:
Assets	96	64
Liabilities:
Derivative liabilities	27	48
Level 1 | Fair Value, Recurring
Assets:
Sub-total	3,566	3,524
Liabilities:
Total liabilities	2,118	3,815
Level 1 | Fair Value, Recurring | Equity Securities
Assets:
Nuclear decommissioning trust	1,560	638
Level 1 | Fair Value, Recurring | Debt Securities
Assets:
Nuclear decommissioning trust	83	0
Level 1 | Fair Value, Recurring | Commodity contract
Assets:
Assets	1,923	2,886
Liabilities:
Derivative liabilities	2,118	3,815
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	2,534	1,426
Liabilities:
Total liabilities	1,002	1,443
Level 2 | Fair Value, Recurring | Equity Securities
Assets:
Nuclear decommissioning trust	0	0
Level 2 | Fair Value, Recurring | Debt Securities
Assets:
Nuclear decommissioning trust	1,976	734
Level 2 | Fair Value, Recurring | Commodity contract
Assets:
Assets	462	628
Liabilities:
Derivative liabilities	975	1,395
Level 2 | Fair Value, Recurring | Interest Rate Swaps
Assets:
Assets	96	64
Liabilities:
Derivative liabilities	27	48
Level 3
Assets:
Assets	841	630
Liabilities:
Derivative liabilities	1,593	1,674
Level 3 | Fair Value, Recurring
Assets:
Sub-total	841	630
Liabilities:
Total liabilities	1,593	1,674
Level 3 | Fair Value, Recurring | Equity Securities
Assets:
Nuclear decommissioning trust	0	0
Level 3 | Fair Value, Recurring | Debt Securities
Assets:
Nuclear decommissioning trust	0	0
Level 3 | Fair Value, Recurring | Commodity contract
Assets:
Assets	841	630
Liabilities:
Derivative liabilities	1,593	1,674
Level 3 | Fair Value, Recurring | Interest Rate Swaps
Assets:
Assets	0	0
Liabilities:
Derivative liabilities	$ 0	$ 0

Fair Value Measurements - Sch_2

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)	12 Months Ended
	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative Asset, Statement of Financial Position, Extensible Enumeration Not Disclosed Flag	Assets
Derivative Liability Statement of Financial Position Extensible Enumeration Not Disclosed Flag	Liabilities
Level 3
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	$ 841,000,000	$ 630,000,000
Liabilities	(1,593,000,000)	(1,674,000,000)
Total, Net	(752,000,000)	(1,044,000,000)
Electricity purchases and sales | Income Approach | Level 3
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	606,000,000	449,000,000
Liabilities	(1,399,000,000)	(1,273,000,000)
Total, Net	(793,000,000)	(824,000,000)
Electricity purchases and sales | Minimum | Income Approach | Level 3 | 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 | Level 3 | Illiquid delivery periods for hub power prices and heat rates
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	25	30
Electricity purchases and sales | Minimum | Income Approach | Level 3 | Market Heat Rates
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	30
Electricity purchases and sales | Maximum | Income Approach | Level 3 | Hourly price curve shape
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	95	85
Electricity purchases and sales | Maximum | Income Approach | Level 3 | Illiquid delivery periods for hub power prices and heat rates
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	140	110
Electricity purchases and sales | Maximum | Income Approach | Level 3 | Market Heat Rates
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	150
Electricity purchases and sales | Arithmetic Average | Income Approach | Level 3 | Hourly price curve shape
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	48	44
Electricity purchases and sales | Arithmetic Average | Income Approach | Level 3 | Illiquid delivery periods for hub power prices and heat rates
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	83	71
Electricity purchases and sales | Arithmetic Average | Income Approach | Level 3 | Market Heat Rates
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	90
Options | Option Pricing Model | Level 3
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	6,000,000	1,000,000
Liabilities	(139,000,000)	(237,000,000)
Total, Net	$ (133,000,000)	$ (236,000,000)
Options | Minimum | Option Pricing Model | Level 3 | Natural gas to power correlation
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input	0.10	0.10
Options | Minimum | Option Pricing Model | Level 3 | Power and natural gas volatility
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input	0.05	0.10
Options | Maximum | Option Pricing Model | Level 3 | 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 | Level 3 | Power and natural gas volatility
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input	7.10	8.70
Options | Arithmetic Average | Option Pricing Model | Level 3 | Natural gas to power correlation
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input	0.55	0.55
Options | Arithmetic Average | Option Pricing Model | Level 3 | Power and natural gas volatility
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input	3.58	4.41
Financial transmission rights/Congestion revenue rights | Market Approach | Level 3
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	$ 190,000,000	$ 157,000,000
Liabilities	(25,000,000)	(34,000,000)
Total, Net	165,000,000	123,000,000
Financial transmission rights/Congestion revenue rights | Minimum | Market Approach | Level 3 | Illiquid price differences between settlement points
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	(35)	(85)
Financial transmission rights/Congestion revenue rights | Maximum | Market Approach | Level 3 | Illiquid price differences between settlement points
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	20	25
Financial transmission rights/Congestion revenue rights | Arithmetic Average | Market Approach | Level 3 | Illiquid price differences between settlement points
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	(8)	(30)
Natural gas | Income Approach | Level 3
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	29,000,000	9,000,000
Liabilities	(30,000,000)	(112,000,000)
Total, Net	(1,000,000)	(103,000,000)
Natural gas | Minimum | Income Approach | Level 3 | Natural gas basis
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	0	0
Natural gas | Minimum | Income Approach | Level 3 | Illiquid delivery periods
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	0	0
Natural gas | Maximum | Income Approach | Level 3 | Natural gas basis
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	10	15
Natural gas | Maximum | Income Approach | Level 3 | 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 | Level 3 | Natural gas basis
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	5	6
Natural gas | Arithmetic Average | Income Approach | Level 3 | Illiquid delivery periods
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Derivative asset (liability), measurement input amount	2	4
Other | Level 3
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	10,000,000	14,000,000
Liabilities	0	(18,000,000)
Total, Net	$ 10,000,000	$ (4,000,000)

Fair Value Measurements - Sch_3

Fair Value Measurements - Schedule of Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation (Details) - Level 3 - Commodity Contracts - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Net liability balance at beginning of period	$ (1,044)	$ (1,219)	$ (360)
Total unrealized valuation gains (losses)	(175)	(765)	(1,382)
Purchases, issuances and settlements:
Purchases	266	222	185
Issuances	(26)	(30)	(62)
Settlements	137	136	345
Transfers into Level 3	(15)	(48)	(30)
Transfers out of Level 3	118	660	85
Net liabilities assumed in connection with the Energy Harbor Merger	(13)	0	0
Net change	292	175	(859)
Net liability balance at end of period	(752)	(1,044)	(1,219)
Unrealized valuation (losses) relating to instruments held at end of period	$ (416)	$ (676)	$ (977)

Fair Value Measurements - Sch_4

Fair Value Measurements - Schedule of Fair Value of Debt (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Carrying Amount | Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030 | Level 2
Debt Instrument [Line Items]
Debt Instrument, fair value disclosure	$ 2,435	$ 2,456
Carrying Amount | BCOP Credit Facilities Tax Credit Bridge Loan | Level 3
Debt Instrument [Line Items]
Debt Instrument, fair value disclosure	344	0
Carrying Amount | Vistra Zero Term Loan B Facility | Level 2
Debt Instrument [Line Items]
Debt Instrument, fair value disclosure	685	0
Carrying Amount | Vistra Operations Senior Notes | Level 2
Debt Instrument [Line Items]
Debt Instrument, fair value disclosure	12,366	11,881
Carrying Amount | Energy Harbor Revenue Bonds | Level 2
Debt Instrument [Line Items]
Debt Instrument, fair value disclosure	414	0
Carrying Amount | Equipment Financing Agreements | Level 3
Debt Instrument [Line Items]
Debt Instrument, fair value disclosure	54	65
Carrying Amount | Forward Repurchase Obligation | Level 3
Debt Instrument [Line Items]
Debt Instrument, fair value disclosure	1,335	0
Fair Value | Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030 | Level 2
Debt Instrument [Line Items]
Debt Instrument, fair value disclosure	2,478	2,500
Fair Value | BCOP Credit Facilities Tax Credit Bridge Loan | Level 3
Debt Instrument [Line Items]
Debt Instrument, fair value disclosure	367	0
Fair Value | Vistra Zero Term Loan B Facility | Level 2
Debt Instrument [Line Items]
Debt Instrument, fair value disclosure	697	0
Fair Value | Vistra Operations Senior Notes | Level 2
Debt Instrument [Line Items]
Debt Instrument, fair value disclosure	12,428	11,752
Fair Value | Energy Harbor Revenue Bonds | Level 2
Debt Instrument [Line Items]
Debt Instrument, fair value disclosure	431	0
Fair Value | Equipment Financing Agreements | Level 3
Debt Instrument [Line Items]
Debt Instrument, fair value disclosure	53	62
Fair Value | Forward Repurchase Obligation | Level 3
Debt Instrument [Line Items]
Debt Instrument, fair value disclosure	$ 1,335	$ 0

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance, liability	$ 2,538	$ 2,437
Accretion	170	88
Adjustment for change in estimates	90	94
Adjustment for obligations assumed through acquisition	1,368
Payments	(88)	(81)
Ending balance, liability	4,078	2,538
Additions:
Accretion	170	88
Adjustment for change in estimates	90	94
Adjustment for obligations assumed through acquisition	1,368
Reductions:
Payments	(88)	(81)
Less amounts due currently	(142)	(124)
Noncurrent liability at December 31, 2024	3,936	2,414
Asset retirement obligation, non-cash additions, asset retirement costs	52	67
Nuclear Plant Decommissioning
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance, liability	1,742	1,688
Accretion	130	54
Adjustment for change in estimates	0	0
Adjustment for obligations assumed through acquisition	1,368
Payments	0	0
Ending balance, liability	3,240	1,742
Additions:
Accretion	130	54
Adjustment for change in estimates	0	0
Adjustment for obligations assumed through acquisition	1,368
Reductions:
Payments	0	0
Less amounts due currently	0
Noncurrent liability at December 31, 2024	3,240
Increase (decrease) in regulatory liabilities	56
Nuclear Plant Decommissioning | Operating Expense
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion	74
Additions:
Accretion	74
Land Reclamation, Coal Ash and Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance, liability	796	749
Accretion	40	34
Adjustment for change in estimates	90	94
Adjustment for obligations assumed through acquisition	0
Payments	(88)	(81)
Ending balance, liability	838	796
Additions:
Accretion	40	34
Adjustment for change in estimates	90	94
Adjustment for obligations assumed through acquisition	0
Reductions:
Payments	(88)	$ (81)
Less amounts due currently	(142)
Noncurrent liability at December 31, 2024	$ 696

Asset Retirement Obligations _2

Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligations [Line Items]
Environmental Remediation Expense Recovery Statement of Income or Comprehensive Income, Extensible Enumeration, Not Disclosed Flag	mining reclamation and other coal ash remediation
Asset retirement obligation	$ 4,078	$ 2,538	$ 2,437
Regulatory liability	$ 452	209
Asset retirement obligation, individual unit basis evaluation period	5 years
Mining Properties and Mineral Rights
Asset Retirement Obligations [Line Items]
Mining reclamation	$ 546
Coal
Asset Retirement Obligations [Line Items]
Coal ash remediation	546
Nuclear Plant Decommissioning
Asset Retirement Obligations [Line Items]
Asset retirement obligation	3,240	$ 1,742	$ 1,688
Nuclear Plant Decommissioning | Comanche Peak Nuclear Power Plant
Asset Retirement Obligations [Line Items]
Asset retirement obligation	1,797
Assets	2,249
Nuclear Plant Decommissioning - Other Noncurrent Liabilities | Comanche Peak Nuclear Power Plant
Asset Retirement Obligations [Line Items]
Regulatory liability	$ 452

Pension and Other Postretirem_3

Pension and Other Postretirement Employee Benefits (OPEB) Plans - Schedule of Pension and OPEB Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Total benefit costs recognized as expense	$ 14	$ 14	$ 6
Pension costs
Defined Benefit Plan Disclosure [Line Items]
Total benefit costs recognized as expense	9	9	2
OPEB costs
Defined Benefit Plan Disclosure [Line Items]
Total benefit costs recognized as expense	$ 5	$ 5	$ 4

Pension and Other Postretirem_4

Pension and Other Postretirement Employee Benefits (OPEB) Plans - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($) corporate_bond	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Market-related value of assets held in trust, realized and unrealized gains or losess, included in preceding period, related to vesting percentage	25%
Fair value of assets	$ 14	$ 28
Assumed discount rate, number of corporate bonds used to derive yield curve | corporate_bond	490
Maximum amount employee may contribute if earnings are less that IRS threshold	75%
Percent of employees pay eligible for contribution to plan, minimum	1%
Percent of employees pay eligible for contribution to plan, maximum	20%
Percent of employees pay eligible to be matched by employer	6%
Employer contributions to the thrift plan	$ 46	33	$ 33
Pension costs
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets	285	285	320
Employer contributions	19	0	0
Expected future employer contributions to retirement plan	25
Pension costs | Fair Value, Recurring
Defined Benefit Plan Disclosure [Line Items]
Total assets measured at net asset value	285	285
Pension costs | Cash commingled trusts | Fair Value, Recurring
Defined Benefit Plan Disclosure [Line Items]
Total assets measured at net asset value	6	4
OPEB costs
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets	10	12	29
Employer contributions	8	9	$ 9
Expected future employer contributions to retirement plan	8
OPEB costs | Cash commingled trusts | Fair Value, Recurring
Defined Benefit Plan Disclosure [Line Items]
Total assets measured at net asset value	7	9
OPEB costs | Municipal Bond and Cash Equivalent Mutual Fund | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets	$ 3	$ 3
Qualified Plan
Defined Benefit Plan Disclosure [Line Items]
Percent of employees contribution matched by employer	100%
Traditional Retirement Plan Formula of Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Percent of employees contribution matched by employer	75%

Pension and Other Postretirem_5

Pension and Other Postretirement Employee Benefits (OPEB) Plans - Schedule of Defined Benefit Plans Disclosures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Assumptions Used to Determine Benefit Obligations at Period End:
Discount rate	6%
Change in Plan Assets:
Fair value of assets at beginning of period	$ 28
Fair value of assets at end of year	14	$ 28
Funded Status:
Fair value of assets	14	28
Retirement Plan
Change in Pension and Postretirement Benefit Obligations:
Projected benefit obligation at beginning of period	425	449
Acquisitions	23	0
Service cost	2	3
Interest cost	21	21
Participant contributions	0	0
Plan amendments	0	1
Actuarial (gain) loss	(24)	10
Benefits paid	(38)	(59)
Projected benefit obligation at end of year	409	425	$ 449
Accumulated benefit obligation at end of year	408	422
Change in Plan Assets:
Fair value of assets at beginning of period	285	320
Acquisitions	18	0
Employer contributions	19	0	0
Participant contributions	0	0
Actual gain on assets	1	24
Transfers	0	0
Benefits paid	(38)	(59)
Fair value of assets at end of year	285	285	320
Funded Status:
Projected benefit obligation	(409)	(425)	(449)
Fair value of assets	285	285	$ 320
Funded status at end of year	(124)	(140)
Amounts Recognized in the Balance Sheet Consist of:
Investments	1	0
Other current liabilities	0	0
Other noncurrent liabilities	(125)	(140)
Net liability recognized	(124)	(140)
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net actuarial (gain) loss	(5)	4
Prior services cost	0	3
Net actuarial (gain) loss and prior service cost	$ (5)	$ 7
Retirement Plan | Vistra Plan, Dynegy Plan And EEI Plan
Assumptions Used to Determine Benefit Obligations at Period End:
Discount rate	5.63%	4.97%	5.16%
Interest crediting rate for cash balance plans	3.75%	3.50%	3%
Retirement Plan | Expected return on plan assets (Vistra Plan)
Assumptions Used to Determine Benefit Obligations at Period End:
Expected rate of compensation increase	3.50%	3.64%	3.79%
Retirement Plan | Expected return on plan assets (Dynegy Plan)
Assumptions Used to Determine Benefit Obligations at Period End:
Expected rate of compensation increase	4.46%
OPEB Plans
Change in Pension and Postretirement Benefit Obligations:
Projected benefit obligation at beginning of period	$ 108	$ 110
Acquisitions	0	0
Service cost	1	1
Interest cost	5	5
Participant contributions	3	3
Plan amendments	0	0
Actuarial (gain) loss	(7)	1
Benefits paid	(11)	(12)
Projected benefit obligation at end of year	99	108	$ 110
Accumulated benefit obligation at end of year	0	0
Change in Plan Assets:
Fair value of assets at beginning of period	12	29
Acquisitions	0	0
Employer contributions	8	9	9
Participant contributions	2	3
Actual gain on assets	1	2
Transfers	(2)	(19)
Benefits paid	(11)	(12)
Fair value of assets at end of year	10	12	29
Funded Status:
Projected benefit obligation	(99)	(108)	(110)
Fair value of assets	10	12	$ 29
Funded status at end of year	(89)	(96)
Amounts Recognized in the Balance Sheet Consist of:
Investments	2	3
Other current liabilities	(8)	(9)
Other noncurrent liabilities	(83)	(90)
Net liability recognized	(89)	(96)
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
Net actuarial (gain) loss	(22)	(15)
Prior services cost	1	1
Net actuarial (gain) loss and prior service cost	$ (21)	$ (14)
OPEB Plans | Vistra Plan, Split-Participant Plan And Dynegy Plan
Assumptions Used to Determine Benefit Obligations at Period End:
Discount rate	5.62%	4.98%	5.18%

Pension and Other Postretirem_6

Pension and Other Postretirement Employee Benefits (OPEB) Plans - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of assets	$ 14	$ 28
Pension costs
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of assets	285	285	$ 320
Pension costs | Fair Value, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets measured at net asset value	285	285
Pension costs | Cash commingled trusts | Fair Value, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets measured at net asset value	6	4
Pension costs | Global equities | Fair Value, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets measured at net asset value	86	82
Pension costs | Corporate bonds | Fair Value, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets measured at net asset value	79	82
Pension costs | Government bonds | Fair Value, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets measured at net asset value	42	54
Pension costs | Other | Fair Value, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets measured at net asset value	28	18
Pension costs | Real estate | Fair Value, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets measured at net asset value	27	28
Pension costs | Hedge funds | Fair Value, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets measured at net asset value	$ 17	$ 17

Pension and Other Postretirem_7

Pension and Other Postretirement Employee Benefits (OPEB) Plans - Schedule of Accumulated and Projected Benefit Obligations (Details) - Pension costs - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligations	$ 409	$ 425
Accumulated benefit obligation	408	422
Plan assets	$ 285	$ 285

Pension and Other Postretirem_8

Pension and Other Postretirement Employee Benefits (OPEB) Plans - Schedule of Allocation of Plan Assets (Details) - Pension costs	Dec. 31, 2024
Expected return on plan assets (Vistra Plan) | Fixed income securities | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	50%
Expected return on plan assets (Vistra Plan) | Fixed income securities | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	70%
Expected return on plan assets (Vistra Plan) | Global equity securities | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	20%
Expected return on plan assets (Vistra Plan) | Global equity securities | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	28%
Expected return on plan assets (Vistra Plan) | Real estate | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	6%
Expected return on plan assets (Vistra Plan) | Real estate | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	10%
Expected return on plan assets (Vistra Plan) | Credit strategies | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	2%
Expected return on plan assets (Vistra Plan) | Credit strategies | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	6%
Expected return on plan assets (Vistra Plan) | Hedge funds | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	2%
Expected return on plan assets (Vistra Plan) | Hedge funds | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	6%
Expected return on plan assets (Dynegy Plan) | Fixed income securities | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	40%
Expected return on plan assets (Dynegy Plan) | Fixed income securities | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	50%
Expected return on plan assets (Dynegy Plan) | Global equity securities | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	28%
Expected return on plan assets (Dynegy Plan) | Global equity securities | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	38%
Expected return on plan assets (Dynegy Plan) | Real estate | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	7%
Expected return on plan assets (Dynegy Plan) | Real estate | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	15%
Expected return on plan assets (Dynegy Plan) | Credit strategies | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	4%
Expected return on plan assets (Dynegy Plan) | Credit strategies | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	8%
Expected return on plan assets (Dynegy Plan) | Hedge funds | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	4%
Expected return on plan assets (Dynegy Plan) | Hedge funds | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	8%
Energy Harbor Plan | Fixed income securities | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	45%
Energy Harbor Plan | Fixed income securities | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	55%
Energy Harbor Plan | Global equity securities | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	30%
Energy Harbor Plan | Global equity securities | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	38%
Energy Harbor Plan | Real estate | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	5%
Energy Harbor Plan | Real estate | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	10%
Energy Harbor Plan | Credit strategies | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	4%
Energy Harbor Plan | Credit strategies | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	8%
Energy Harbor Plan | Hedge funds | Minimum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	1%
Energy Harbor Plan | Hedge funds | Maximum
Defined Benefit Plan Disclosure [Line Items]
Target Allocation Ranges	5%

Pension and Other Postretirem_9

Pension and Other Postretirement Employee Benefits (OPEB) Plans - Schedule of Defined Benefit Plan, Assumptions (Details) - Pension costs	12 Months Ended
	Dec. 31, 2024
Expected return on plan assets (Vistra Plan) | Weighted average
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	6.30%
Expected return on plan assets (Vistra Plan) | Fixed income securities
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	5.90%
Expected return on plan assets (Vistra Plan) | Global equity securities
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	7.20%
Expected return on plan assets (Vistra Plan) | Real estate
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	5.80%
Expected return on plan assets (Vistra Plan) | Credit strategies
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	7.40%
Expected return on plan assets (Vistra Plan) | Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	7.30%
Expected return on plan assets (Dynegy Plan) | Weighted average
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	6.30%
Expected return on plan assets (Dynegy Plan) | Fixed income securities
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	5.50%
Expected return on plan assets (Dynegy Plan) | Global equity securities
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	7.20%
Expected return on plan assets (Dynegy Plan) | Real estate
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	5.80%
Expected return on plan assets (Dynegy Plan) | Credit strategies
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	7.40%
Expected return on plan assets (Dynegy Plan) | Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	7.30%
Energy Harbor Plan | Weighted average
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	5.80%
Energy Harbor Plan | Fixed income securities
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	4.60%
Energy Harbor Plan | Global equity securities
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	7.20%
Energy Harbor Plan | Real estate
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	5.80%
Energy Harbor Plan | Credit strategies
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	7.40%
Energy Harbor Plan | Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans
Expected Long-Term Rate of Return	7.30%

Pension and Other Postretire_10

Pension and Other Postretirement Employee Benefits (OPEB) Plans - Schedule of Health Care Cost Trend Rates (Details) - OPEB costs	Dec. 31, 2024	Dec. 31, 2023
Assumed Health Care Cost Trend Rates-Not Medicare Eligible:
Assumed Health Care Cost Trend Rates [Abstract]
Health care cost trend rate assumed for next year	7%	7%
Rate to which the cost trend is expected to decline (the ultimate trend rate)	4.50%	4.50%
Health care cost trend rate assumed for next year (Vistra Plan)
Assumed Health Care Cost Trend Rates [Abstract]
Health care cost trend rate assumed for next year	15.70%	12.90%
Health care cost trend rate assumed for next year (Split-Participant Plan)
Assumed Health Care Cost Trend Rates [Abstract]
Health care cost trend rate assumed for next year	13.80%	12.30%
Rate to which the cost trend is expected to decline (the ultimate trend rate)
Assumed Health Care Cost Trend Rates [Abstract]
Rate to which the cost trend is expected to decline (the ultimate trend rate)	4.50%	4.50%

Pension and Other Postretire_11

Pension and Other Postretirement Employee Benefits (OPEB) Plans - Schedule of Expected Benefit Payments (Details) $ in Millions	Dec. 31, 2024 USD ($)
Pension costs
Defined Benefit Plans and Other Postretirement Benefit Plans
2025	$ 33
2026	34
2027	43
2028	32
2029	32
2030-2034	151
OPEB costs
Defined Benefit Plans and Other Postretirement Benefit Plans
2025	9
2026	9
2027	9
2028	8
2029	8
2030-2034	$ 36

Commitments and Contingencies -

Commitments and Contingencies - Contractual Obligation, Fiscal Year Maturity (Details) $ in Millions	Dec. 31, 2024 USD ($)
Long-Term Service and Maintenance Contracts
Long-term Purchase Commitment [Line Items]
2025	$ 227
2026	206
2027	207
2028	265
2029	259
Thereafter	1,916
Total	3,080
Coal transportation agreements
Long-term Purchase Commitment [Line Items]
2025	59
2026	26
2027	26
2028	0
2029	0
Thereafter	0
Total	111
Pipeline transportation and storage reservation fees
Long-term Purchase Commitment [Line Items]
2025	187
2026	200
2027	209
2028	228
2029	234
Thereafter	115
Total	1,173
Water Contracts
Long-term Purchase Commitment [Line Items]
2025	9
2026	9
2027	9
2028	9
2029	9
Thereafter	37
Total	$ 82

Commitments and Contingencies_2

Commitments and Contingencies - Narrative (Details) $ in Millions

1 Months Ended

12 Months Ended

Aug. 31, 2024 state

May 31, 2024 petition

Aug. 31, 2023 application

May 31, 2023 facility unit category

Mar. 31, 2023 state

Oct. 31, 2022

Jul. 31, 2022 site

Jun. 30, 2022

Jan. 31, 2022 site insurance_company

Oct. 31, 2021 impoundment

Aug. 31, 2018

Dec. 31, 2024 USD ($) lawsuit

Dec. 31, 2023 USD ($)

Dec. 31, 2022 USD ($)

Feb. 28, 2025

Jan. 31, 2025 MW

Jan. 16, 2025 lawsuit MW

Feb. 29, 2024 plant

Jun. 30, 2023 MW

Jul. 31, 2019 plant

Oct. 31, 2017 generation_unit

May 31, 2015 complaint

Long-term Purchase Commitment [Line Items]

Legal claim, duration

5 years

Number of nuclear power plants | plant

2

Loss contingency, number of plaintiffs | insurance_company

100

Greenhouse gas emissions, final rule, number of states filing petitions challenging final rule | petition

17

Number of plants | plant

4

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

Subsequent Event

Long-term Purchase Commitment [Line Items]

Loss contingency, pending claims, number | lawsuit

2

Vermillion Facility Old East and North Sites

Long-term Purchase Commitment [Line Items]

Site contingency, number of sites with regulatory violations

2

Moss Landing Power Plant (Battery Storage Project) | Moss Landing Battery Energy Storage System Phase III

Long-term Purchase Commitment [Line Items]

Battery energy storage system capacity | MW

350

Moss Landing Power Plant (Battery Storage Project) | Moss Landing Battery Energy Storage System Phase III | Subsequent Event

Long-term Purchase Commitment [Line Items]

Battery energy storage system capacity | MW

300

300

Maximum | Martin Lake Steam Electric Station

Long-term Purchase Commitment [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

Maximum | Coleto Creek

Long-term Purchase Commitment [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

United States Environmental Protection Agency

Long-term Purchase Commitment [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, sulfur dioxide emissions, number of units in texas subject to rule, total | generation_unit

39

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

Long-term Purchase Commitment [Line Items]

Coal combustion residuals, rules for closure of coal ash ponds in Illinois, number of operating permit applications filed | impoundment

18

Coal combustion residuals, rules for closure of coal ash ponds in Illinois, number of construction permit application filed

1

5

3

Greenhouse Gas Emissions (GHG) | Subsequent Event

Long-term Purchase Commitment [Line Items]

Litigation, period

60 days

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

Long-term Purchase Commitment [Line Items]

Litigation, period

60 days

Legacy CCR Rulemaking | Subsequent Event

Long-term Purchase Commitment [Line Items]

Litigation, period

120 days

Gas Index Pricing Litigation | Wisconsin

Long-term Purchase Commitment [Line Items]

Loss contingency, pending claims, number | lawsuit

1

MISO 2015-2016 Planning Resource Auction

Long-term Purchase Commitment [Line Items]

Loss contingency, pending claims, number | complaint

3

MISO 2015-2016 Planning Resource Auction | Pending Litigation

Long-term Purchase Commitment [Line Items]

Loss contingency, pending claims, number | complaint

1

Letters of Credit | Vistra Operations Company LLC

Long-term Purchase Commitment [Line Items]

Letters of credit outstanding, amount

$ 2,935

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

Long-term Purchase Commitment [Line Items]

Letters of credit outstanding, amount

2,560

Letters of Credit | Vistra Operations Company LLC | Support Battery and Solar Development Projects

Long-term Purchase Commitment [Line Items]

Letters of credit outstanding, amount

248

Letters of Credit | Vistra Operations Company LLC | Support Executory Contracts and Insurance Agreements

Long-term Purchase Commitment [Line Items]

Letters of credit outstanding, amount

25

Letters of Credit | Vistra Operations Company LLC | Support Retail Electric Provider's financial requirements with the Public Utility Commission of Texas

Long-term Purchase Commitment [Line Items]

Letters of credit outstanding, amount

86

Letters of Credit | Vistra Operations Company LLC | Miscellaneous Credit Support Requirements

Long-term Purchase Commitment [Line Items]

Letters of credit outstanding, amount

16

Surety Bonds | Vistra Operations Company LLC

Long-term Purchase Commitment [Line Items]

Surety bonds

1,087

Nuclear Fuel Contracts

Long-term Purchase Commitment [Line Items]

Contractual obligations expenditures

116

Coal transportation agreements

Long-term Purchase Commitment [Line Items]

Contractual obligations expenditures

$ 744

$ 936

$ 995

Commitments and Contingencies_3

Commitments and Contingencies - Narrative Nuclear Insurance (Details) $ in Millions	Dec. 31, 2024 USD ($)
Long-term Purchase Commitment [Line Items]
Secondary financial protection pool, maximum assessment paid per operating licensed reactor in the event of any single nuclear liability loss	$ 165.9
Secondary financial protection pool, maximum assessment paid per operating licensed reactor in the event of any single nuclear liability loss, annual	24.7
Comanche Peak Nuclear Power Plant
Long-term Purchase Commitment [Line Items]
Nuclear decontamination and property insurance, maximum coverage	2,250
Non-nuclear property damage insurance, maximum coverage	1,000
Non-nuclear property damage insurance, deductible per accident, general	5
Non-nuclear property damage insurance, deductible per incident, natural hazard	9.5
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
Accidental outage insurance, coverage for obtaining replacement energy, coverage limit for nuclear accidents	490
Beaver Valley Nuclear Power Station, Davis-Besse Nuclear Power Station and Perry Nuclear Generating Station
Long-term Purchase Commitment [Line Items]
Non-nuclear property damage insurance, maximum coverage	1,500
Non-nuclear property damage insurance, deductible per incident, natural hazard	20
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, coverage limit for non-nuclear accidents	208
Accidental outage insurance, coverage for obtaining replacement energy, coverage limit for nuclear accidents	350
Accidental outage insurance, coverage for obtaining replacement energy after 12 week waiting period, maximum weekly payments, remaining 52 weeks non-nuclear and 52 weeks nuclear property	1.5
Accidental outage insurance coverage, coverage for obtaining replacement energy after 12 week waiting period, maximum weekly payments, remaining 52 weeks nuclear property	$ 2
Accidental outage insurance, coverage for obtaining replacement energy after 12 week waiting period, maximum percent of coverage if both units out of service	80%
Vistra Corp.
Long-term Purchase Commitment [Line Items]
Secondary financial protection pool, maximum assessment paid in the event of any single nuclear liability loss	$ 995.4
Secondary financial protection pool, maximum assessment paid in the event of any single nuclear liability loss, annual	148.2
Section 170 (Price-Anderson) of the Atomic Energy Act
Long-term Purchase Commitment [Line Items]
Nuclear insurance, annual coverage limit	16,200
Secondary financial protection pool, maximum single nuclear liability loss triggering assessment	500
United States Nuclear Regulatory Commission
Long-term Purchase Commitment [Line Items]
Nuclear decontamination and property insurance, maximum coverage	$ 1,060

Equity - Schedule of Common Sto

Equity - Schedule of Common Stock Outstanding Roll Forward (Details) - shares	12 Months Ended			36 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2024
Shares Issued
Beginning balance, share issued (in shares)	543,635,172	537,179,072	532,929,476	532,929,476
Shares issued (in shares)	5,117,434	6,474,491	4,262,575
Shares retired (in shares)		(18,391)	(12,979)
Shares repurchased (in shares)	0	0	0
Ending balance, share issued (in shares)	548,752,606	543,635,172	537,179,072	548,752,606
Treasury Shares
Beginning balance, treasury shares (in shares)	(192,496,788)	(147,502,289)	(69,031,742)	(69,031,742)
Shares issued (in shares)	0	0	0
Shares retired (in shares)		0	0
Shares repurchased (in shares)	(16,560,328)	(44,994,499)	(78,470,547)
Ending balance, treasury shares (in shares)	(209,057,116)	(192,496,788)	(147,502,289)	(209,057,116)
Shares Outstanding
Beginning balance, shares outstanding (in shares)	351,138,384	389,676,783	463,897,734	463,897,734
Shares issued (in shares)	5,117,434	6,474,491	4,262,575
Shares retired (in shares)		(18,391)	(12,979)
Shares repurchased (in shares)	(16,560,328)	(44,994,499)	(78,470,547)
Ending balance, shares outstanding (in shares)	339,695,490	351,138,384	389,676,783	339,695,490
Treasury stock, shares, acquired, unsettled shares (in shares)	58,817	318,632	78,087

Equity - Narrative (Details)

Equity - Narrative (Details) - $ / shares	1 Months Ended	3 Months Ended	12 Months Ended
	Feb. 28, 2025	Dec. 31, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Accelerated Share Repurchases [Line Items]
Common stock, dividends, per share, cash paid (in dollars per share)			$ 0.8735	$ 0.8205	$ 0.7240
Preferred sock, liquidation preference		$ 1,000	1,000	$ 1,000
Series B
Accelerated Share Repurchases [Line Items]
Preferred sock, liquidation preference		1,000	1,000
Series A Preferred Stock
Accelerated Share Repurchases [Line Items]
Preferred sock, liquidation preference		1,000	1,000
Series C Preferred Stock
Accelerated Share Repurchases [Line Items]
Preferred sock, liquidation preference		1,000	$ 1,000
Preferred stock, dividends per share, declared (in dollars per share)		$ 44.375
Subsequent Event
Accelerated Share Repurchases [Line Items]
Common stock, dividends, per share, declared (in dollars per share)	$ 0.2235
Subsequent Event | Series A Preferred Stock
Accelerated Share Repurchases [Line Items]
Preferred stock, dividends per share, declared (in dollars per share)	$ 40

Equity - Schedule of Share Repu

Equity - Schedule of Share Repurchase Program (Details) - USD ($) $ in Millions	Dec. 31, 2024	Oct. 31, 2024	Feb. 29, 2024	Mar. 31, 2023	Aug. 31, 2022	Oct. 31, 2021
October 2021
Share Repurchase Program [Line Items]
Stock repurchase program, authorized amount						$ 2,000
August 2022
Share Repurchase Program [Line Items]
Stock repurchase program, authorized amount					$ 1,250
March 2023
Share Repurchase Program [Line Items]
Stock repurchase program, authorized amount				$ 1,000
February 2024
Share Repurchase Program [Line Items]
Stock repurchase program, authorized amount			$ 1,500
October 2024
Share Repurchase Program [Line Items]
Stock repurchase program, authorized amount		$ 1,000
Cumulative authorization at December 31, 2024
Share Repurchase Program [Line Items]
Stock repurchase program, authorized amount	$ 6,750

Equity - Schedule of Repurchase

Equity - Schedule of Repurchase Agreements (Details) - USD ($) $ / shares in Units, $ in Millions	2 Months Ended	12 Months Ended			36 Months Ended	38 Months Ended
	Feb. 24, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2024	Feb. 24, 2025
Class of Stock [Line Items]
Total Number of Shares Repurchased (in shares)		16,560,328	44,994,499	78,470,547
Amount Paid for Shares Repurchased		$ 1,250	$ 1,267	$ 1,837
Cumulative authorization at December 31, 2024
Class of Stock [Line Items]
Total Number of Shares Repurchased (in shares)		16,560,328	44,994,499	78,470,547	140,025,374
Average Price Paid Per Share (in dollars per share)		$ 74.96	$ 27.89	$ 23.40	$ 30.94
Amount Paid for Shares Repurchased		$ 1,241	$ 1,255	$ 1,836	$ 4,332
Amount Available for Additional Repurchases at the End of the Period		$ 2,009			$ 2,009
Treasury stock, shares acquired, accrued (in shares)		58,817
Treasury Stock, value, acquired, accrued, cost method		$ 8
Cumulative authorization at December 31, 2024 | Subsequent Event
Class of Stock [Line Items]
Total Number of Shares Repurchased (in shares)	848,866					140,874,240
Average Price Paid Per Share (in dollars per share)	$ 163.23					$ 31.74
Amount Paid for Shares Repurchased	$ 139					$ 4,471
Amount Available for Additional Repurchases at the End of the Period	$ 1,870					$ 1,870

Equity - Preferred Stock (Detai

Equity - Preferred Stock (Details) - shares	Dec. 29, 2023	Dec. 10, 2021	Oct. 15, 2021	Dec. 31, 2024	Dec. 31, 2023
Class of Stock [Line Items]
Preferred stock, shares outstanding (in shares)				2,476,066	2,476,081
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%
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%
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)	476,066				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, percentage	3.83%
Preferred stock, dividend rate, first reset date and thereafter, basis spread on variable rate, percentage	5.045%

Equity - Schedule of Preferred

Equity - Schedule of Preferred Dividends Declared (Details) - $ / shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Series A Preferred Stock
Class of Stock [Line Items]
Preferred stock, dividends, per share, cash paid (in dollars per share)	$ 80	$ 80	$ 80
Series B Preferred Stock
Class of Stock [Line Items]
Preferred stock, dividends, per share, cash paid (in dollars per share)	70	$ 70	$ 70.97
Series C Preferred Stock
Class of Stock [Line Items]
Preferred stock, dividends, per share, cash paid (in dollars per share)	$ 48.32

Earnings Per Share - Schedule o

Earnings Per Share - Schedule of Earnings Per Share, Basic and Diluted (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Class of Stock [Line Items]
Net income (loss) attributable to Vistra	$ 2,659	$ 1,493	$ (1,227)
Cumulative dividends attributable to preferred stock	(192)	(150)	(150)
Net income (loss) attributable to Vistra common stock	2,467	1,343	(1,377)
Net income (loss) attributable to common stock — diluted	$ 2,467	$ 1,343	$ (1,377)
Weighted average shares of common stock outstanding:
Basic (in shares)	344,788,634	369,771,359	422,447,074
Dilutive securities: Stock-based incentive compensation plan (in shares)	7,778,426	5,421,752	0
Diluted (in shares)	352,567,060	375,193,110	422,447,074
Net income (loss) per weighted average share of common stock outstanding:
Basic (in dollars per share)	$ 7.16	$ 3.63	$ (3.26)
Diluted (in dollars per share)	$ 7	$ 3.58	$ (3.26)
Series A Preferred Stock
Class of Stock [Line Items]
Cumulative dividends attributable to preferred stock	$ (80)	$ (80)	$ (80)
Series B Preferred Stock
Class of Stock [Line Items]
Cumulative dividends attributable to preferred stock	(70)	(70)	(70)
Series C Preferred Stock
Class of Stock [Line Items]
Cumulative dividends attributable to preferred stock	$ (42)	$ 0	$ 0

Earnings Per Share - Narrative

Earnings Per Share - Narrative (Details) - shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Earnings Per Share [Abstract]
Antidilutive securities excluded from computation of earnings per share, amount (in shares)	0	392,218	8,292,647

Stock-Based Compensation - Narr

Stock-Based Compensation - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2019	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense, net of tax	$ 77	$ 59	$ 50
Share-based payment arrangement, option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested stock options granted	$ 0
Share-based compensation arrangement by share-based payment award, shares issued in period (in shares)	0
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested restricted stock units granted	$ 61
Unrecognized compensation cost related to unvested stock options granted, weighted average recognition period	2 years
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested restricted stock units granted	$ 64
Performance period	3 years
Stock-based compensation expense, net of tax	$ 54	$ 36	$ 22
Performance Shares | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights, percentage	0%
Performance Shares | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights, percentage	200%
Performance Shares | Median
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting rights, percentage	100%
Vistra Energy 2016 Omnibus Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized for issuance as equity-based awards (in shares)	43,000,000			37,500,000	22,500,000

Stock-Based Compensation - Sche

Stock-Based Compensation - Schedule of Share-Based Payment Arrangement, Expensed and Capitalized, Amount (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
Total stock-based compensation expense	$ 100	$ 77	$ 65
Income tax benefit	(23)	(18)	(15)
Stock based-compensation expense, net of tax	$ 77	$ 59	$ 50

Stock-Based Compensation - Sc_2

Stock-Based Compensation - Schedule of Share-Based Payment Arrangement, Option and Stock Appreciation Rights, Activity (Details) - Share-based payment arrangement, option - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Stock Options (in thousands)
Total outstanding at beginning of period (in shares)	6,126
Exercised (in shares)	(2,526)
Total outstanding at end of period (in shares)	3,600	6,126
Exercisable (in shares)	3,600
Weighted Average Exercise Price
Total outstanding at beginning of period -weighted average exercise price (in dollars per share)	$ 20.01
Exercised - weighted average exercise price (in dollars per share)	20.06
Total outstanding at end of the period - weighted average exercise price (in dollars per share)	19.97	$ 20.01
Exercisable - weighted average exercise price (in dollars per share)	$ 19.97
Weighted Average Remaining Contractual Term (Years)
Total outstanding - weighted average remaining contractual term	3 years 6 months	4 years 2 months 12 days
Exercisable - weighted average remaining contractual term	3 years 6 months
Aggregate Intrinsic Value (in millions)
Total outstanding at beginning of period -aggregate intrinsic value	$ 113.5
Total outstanding at end of period - aggregate intrinsic value	424.4	$ 113.5
Exercisable - aggregate intrinsic value	$ 424.4

Stock-Based Compensation - Sc_3

Stock-Based Compensation - Schedule of Share-Based Payment Arrangement, Restricted Stock Unit, Activity (Details) - Restricted Stock Units (RSUs) shares in Thousands	12 Months Ended
	Dec. 31, 2024 $ / shares shares
Restricted Stock Units (in thousands)
Total outstanding at beginning of period (in shares) | shares	3,908
Granted (in shares) | shares	1,017
Vested (in shares) | shares	(1,785)
Forfeited (in shares) | shares	(86)
Total outstanding at end of period (in shares) | shares	3,054
Weighted Average Grant Date Fair Value
Total outstanding at beginning of period - weighted average grant date fair value (in dollars per share) | $ / shares	$ 21.90
Granted - weighted average grant date fair value (in dollars per share) | $ / shares	59.11
Vested - weighted average grant date fair value (in dollars per share) | $ / shares	22.20
Forfeited or expired - weighted average grant date fair value (in dollars per share) | $ / shares	33.55
Total outstanding at end of period - weighted average grant date fair value (in dollars per share) | $ / shares	$ 34.30

Segment Information - Narrative

Segment Information - Narrative (Details)	12 Months Ended
	Dec. 31, 2024 state segment
Number of reportable segments | segment	5
Numbers of states in which entity operates | state	16

Segment Information - Schedule

Segment Information - Schedule of Segment Reporting Information, by Segment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Operating revenues	$ 17,224	$ 14,779	$ 13,728
Fuel, purchased power costs, and delivery fees	(7,285)	(7,557)	(10,401)
Operating costs	(2,414)	(1,702)	(1,645)
Selling, general, and administrative expenses	(1,601)	(1,308)	(1,189)
Interest expenses and related charges	(900)	(740)	(368)
Depreciation and amortization	(1,843)	(1,502)	(1,596)
Income tax expense (benefit)	(655)	(508)	350
Other	286	30	(89)
Net income (loss)	2,812	1,492	(1,210)
Capital expenditures, including nuclear fuel and excluding growth expenditures	1,917	1,537	1,108
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	24,730	21,355	18,482
Fuel, purchased power costs, and delivery fees	(14,794)	(14,135)	(15,156)
Operating costs	(2,411)	(1,700)	(1,644)
Selling, general, and administrative expenses	(1,362)	(1,183)	(1,123)
Interest expenses and related charges	(2)	2	3
Depreciation and amortization	(1,777)	(1,434)	(1,527)
Income tax expense (benefit)	0	(1)	0
Other	222	115	25
Net income (loss)	4,606	3,019	(940)
Capital expenditures, including nuclear fuel and excluding growth expenditures	1,859	1,479	1,053
Corporate and Other
Segment Reporting Information [Line Items]
Operating revenues	(7,506)	(6,576)	(4,754)
Fuel, purchased power costs, and delivery fees	7,509	6,578	4,755
Operating costs	(3)	(2)	(1)
Selling, general, and administrative expenses	(239)	(125)	(66)
Interest expenses and related charges	(898)	(742)	(371)
Depreciation and amortization	(66)	(68)	(69)
Income tax expense (benefit)	(655)	(507)	350
Other	64	(85)	(114)
Net income (loss)	(1,794)	(1,527)	(270)
Capital expenditures, including nuclear fuel and excluding growth expenditures	58	58	55
Retail | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	12,797	10,572	9,455
Fuel, purchased power costs, and delivery fees	(10,276)	(9,046)	(7,169)
Operating costs	(159)	(123)	(143)
Selling, general, and administrative expenses	(977)	(858)	(826)
Interest expenses and related charges	(54)	(20)	(14)
Depreciation and amortization	(114)	(102)	(145)
Income tax expense (benefit)	0	0	0
Other	(1)	1	0
Net income (loss)	1,216	424	1,158
Capital expenditures, including nuclear fuel and excluding growth expenditures	4	1	1
Texas | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	5,394	3,979	3,878
Fuel, purchased power costs, and delivery fees	(1,596)	(2,028)	(3,052)
Operating costs	(996)	(917)	(832)
Selling, general, and administrative expenses	(169)	(140)	(135)
Interest expenses and related charges	46	21	20
Depreciation and amortization	(581)	(550)	(541)
Income tax expense (benefit)	0	0	0
Other	35	33	76
Net income (loss)	2,133	398	(586)
Capital expenditures, including nuclear fuel and excluding growth expenditures	1,124	750	520
East | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	5,661	5,890	4,429
Fuel, purchased power costs, and delivery fees	(2,698)	(2,730)	(4,132)
Operating costs	(1,103)	(528)	(482)
Selling, general, and administrative expenses	(148)	(127)	(97)
Interest expenses and related charges	9	(2)	(6)
Depreciation and amortization	(996)	(703)	(768)
Income tax expense (benefit)	0	(1)	0
Other	177	(50)	(71)
Net income (loss)	902	1,749	(1,127)
Capital expenditures, including nuclear fuel and excluding growth expenditures	661	362	187
West | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	877	914	336
Fuel, purchased power costs, and delivery fees	(221)	(328)	(481)
Operating costs	(72)	(58)	(42)
Selling, general, and administrative expenses	(25)	(24)	(21)
Interest expenses and related charges	1	8	6
Depreciation and amortization	(86)	(79)	(42)
Income tax expense (benefit)	0	0	0
Other	(3)	21	6
Net income (loss)	471	454	(238)
Capital expenditures, including nuclear fuel and excluding growth expenditures	70	366	345
Asset Closure | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	1	0	384
Fuel, purchased power costs, and delivery fees	(3)	(3)	(322)
Operating costs	(81)	(74)	(145)
Selling, general, and administrative expenses	(43)	(34)	(44)
Interest expenses and related charges	(4)	(5)	(3)
Depreciation and amortization	0	0	(31)
Income tax expense (benefit)	0	0	0
Other	14	110	14
Net income (loss)	(116)	(6)	(147)
Capital expenditures, including nuclear fuel and excluding growth expenditures	$ 0	$ 0	$ 0

Supplementary Financial Infor_3

Supplementary Financial Information - Schedule of Other Nonoperating Income (Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Finite-Lived Intangible Assets [Line Items]
NDT net income	$ 170	$ 0	$ 0
Insurance settlements	23	24	70
Gain on sale of land	0	95	8
Interest income	65	86	19
All other	38	23	20
Total other income	312	257	117
All other	21	14	4
Total other deductions	21	14	4
Operating Segments
Finite-Lived Intangible Assets [Line Items]
Gain on sale of land	6	95	8
Gain on TRA settlement	10	29	0
Operating Segments | Texas
Finite-Lived Intangible Assets [Line Items]
Insurance settlements	20		62
Gain on sale of land		1
Operating Segments | West
Finite-Lived Intangible Assets [Line Items]
Insurance settlements	$ 3	19	6
Operating Segments | Asset Closure
Finite-Lived Intangible Assets [Line Items]
Insurance settlements		5	1
Gain on sale of land		$ 94
Operating Segments | Corporate Segment and Other Non - Segment
Finite-Lived Intangible Assets [Line Items]
Insurance settlements			$ 1

Supplementary Financial Infor_4

Supplementary Financial Information - Summary of Inventories by Major Category and Other Investments (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Inventories by Major Category
Materials and supplies	$ 533	$ 289
Fuel stock	403	420
Natural gas in storage	34	31
Total inventories	970	740
Other Investments
Nuclear decommissioning trusts	4,440	1,951
Assets related to employee benefit plans	14	28
Land investments	42	42
Other investments	16	14
Total investments	$ 4,512	$ 2,035

Supplementary Financial Infor_5

Supplementary Financial Information - Schedule of Other Noncurrent Liabilities and Deferred Credits (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligations [Line Items]
Retirement and other employee benefits	$ 224	$ 247
Winter Storm Uri impacts	1	26
Identifiable intangible liabilities	155	131
Regulatory liability	452	209
Operating lease liabilities	98	48
Finance lease liabilities	218	227
Liability for third-party remediation	8	17
Accrued severance costs	36	36
Other accrued expenses	64	58
Total other noncurrent liabilities and deferred credits	1,256	$ 999
Nuclear Plant Decommissioning - Other Noncurrent Liabilities | Comanche Peak Nuclear Power Plant
Asset Retirement Obligations [Line Items]
Regulatory liability	452
Nuclear Plant Decommissioning - Deferred Credits | Comanche Peak Nuclear Power Plant
Asset Retirement Obligations [Line Items]
Regulatory liability	$ 209

Supplementary Financial Infor_6

Supplementary Financial Information - Schedule of Cash Flow, Supplemental Disclosures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Supplementary Financial Information [Abstract]
Cash and cash equivalents	$ 1,188	$ 3,485
Restricted cash included in current assets	28	40
Restricted cash included in noncurrent assets	6	14
Total cash, cash equivalents and restricted cash	1,222	3,539	$ 525	$ 1,359
Cash payments related to:
Interest paid	987	636	581
Capitalized interest	(77)	(37)	(29)
Interest paid (net of capitalized interest)	910	599	552
Non-cash investing and financing activities:
Accrued property, plant and equipment additions	258	104	103
Issuance of Series C Preferred Stock as consideration for the repurchase of TRA Rights with a carrying value of $506 million	0	476	0
Book value of property, plant, and equipment sold, including nuclear fuel	$ 117	26	$ 0
Gain on taxable receivable agreement, repurchase rights, carrying value of the repurchase rights		$ 506

Supplementary Financial Infor_7

Supplementary Financial Information - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Domestic Tax Jurisdiction
Impaired Long-Lived Assets Held and Used [Line Items]
Taxes paid	$ 5	$ 0	$ 1
State and Local Jurisdiction
Impaired Long-Lived Assets Held and Used [Line Items]
Taxes paid	59	44	33
Proceeds from income tax refunds	$ 9	$ 13	$ 8

Schedule I - Condensed Financ_3

Schedule I - Condensed Financial Information of Registrant (Condensed Statements of Operations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Condensed Financial Statements, Captions [Line Items]
Depreciation and amortization	$ (1,843)	$ (1,502)	$ (1,596)
Selling, general, and administrative expenses	(1,601)	(1,308)	(1,189)
Operating income (loss)	4,081	2,661	(1,177)
Other income	312	257	117
Impacts of Tax Receivable Agreement	(5)	(164)	(128)
Net income (loss) before income taxes	3,467	2,000	(1,560)
Income tax expense (benefit)	(655)	(508)	350
Net income (loss)	2,812	1,492	(1,210)
Parent
Condensed Financial Statements, Captions [Line Items]
Depreciation and amortization	0	(15)	(16)
Selling, general, and administrative expenses	(102)	(80)	(69)
Operating income (loss)	(102)	(95)	(85)
Other income	28	31	6
Impacts of Tax Receivable Agreement	(5)	(164)	(128)
Net income (loss) before income taxes	(79)	(228)	(207)
Income tax expense (benefit)	17	58	47
Equity in earnings (losses) of subsidiaries, net of tax	2,721	1,663	(1,067)
Net income (loss)	$ 2,659	$ 1,493	$ (1,227)

Schedule I - Condensed Financ_4

Schedule I - Condensed Financial Information of Registrant (Condensed Statements of Cash Flows) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Cash flows — operating activities:
Cash provided by operating activities	$ 4,563	$ 5,453	$ 485
Cash flows — investing activities:
Proceeds from sales of subsidiary transferable ITCs	150	0	0
Cash used in investing activities	(5,276)	(2,145)	(1,239)
Cash flows — financing activities:
Stock repurchases	(1,266)	(1,245)	(1,949)
Dividends paid to common stockholders	(305)	(313)	(302)
Dividends paid to preferred stockholders	(173)	(150)	(151)
TRA Repurchase and tender offer — return of capital	(122)	0	0
Other, net	(14)	83	31
Cash used in financing activities	(1,604)	(294)	(80)
Cash, cash equivalents and restricted cash — beginning balance	3,539	525	1,359
Cash, cash equivalents and restricted cash — ending balance	1,222	3,539	525
Parent
Cash flows — operating activities:
Cash provided by operating activities	(37)	(31)	(27)
Cash flows — investing activities:
Dividend received from subsidiaries	1,705	1,625	1,775
Proceeds from sales of subsidiary transferable ITCs	150	0	0
Cash used in investing activities	1,855	1,625	1,775
Cash flows — financing activities:
Stock repurchases	(1,266)	(1,245)	(1,949)
Dividends paid to common stockholders	(305)	(313)	(302)
Dividends paid to preferred stockholders	(173)	(150)	(151)
TRA Repurchase and tender offer — return of capital	(122)	0	0
Other, net	39	91	40
Cash used in financing activities	(1,827)	(1,617)	(2,362)
Net change in cash, cash equivalents and restricted cash	(9)	(23)	(614)
Cash, cash equivalents and restricted cash — beginning balance	31	54	668
Cash, cash equivalents and restricted cash — ending balance	$ 22	$ 31	$ 54

Schedule I - Condensed Financ_5

Schedule I - Condensed Financial Information of Registrant (Condensed Balance Sheets) (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents	$ 1,188	$ 3,485
Total trade accounts receivable — net	1,982	1,674
Income taxes receivable	8	6
Total current assets	8,119	11,637
Investment in affiliated companies	4,512	2,035
Property, plant, and equipment — net	18,173	12,432
Accumulated deferred income taxes	9	1,223
Other noncurrent assets	1,191	601
Total assets	37,770	32,966
Current liabilities:
Accounts payable	1,510	1,147
Other current liabilities	645	554
Total current liabilities	8,432	9,823
Tax Receivable Agreement obligation	14	164
Other noncurrent liabilities and deferred debits	1,256	999
Total liabilities	32,187	27,644
Equity [Abstract]
Total equity	5,583	5,322	$ 4,918	$ 8,292
Total liabilities and equity	37,770	32,966
Parent
Current assets:
Cash and cash equivalents	22	31
Total trade accounts receivable — net	13	0
Income taxes receivable	8	6
Total current assets	43	37
Property, plant, and equipment — net	2	3
Accumulated deferred income taxes	960	1,086
Other noncurrent assets	3	0
Total assets	5,678	5,633
Current liabilities:
Accrued income taxes	9	12
Other current liabilities	27	12
Total current liabilities	71	127
Tax Receivable Agreement obligation	14	164
Other noncurrent liabilities and deferred debits	10	20
Total liabilities	95	311
Equity [Abstract]
Total equity	5,583	5,322
Total liabilities and equity	5,678	5,633
Parent | Related Party
Current assets:
Investment in affiliated companies	4,670	4,507
Current liabilities:
Accounts payable	27	91
Parent | Nonrelated Party
Current liabilities:
Accounts payable	$ 8	$ 12

Schedule I - Condensed Financ_6

Schedule I - Condensed Financial Information (Notes to Condensed Financial Statements) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Condensed Financial Statements, Captions [Line Items]
Maximum allowable distribution to parent company by consolidated subsidiary without consent	$ 8,200
Parent Company
Condensed Financial Statements, Captions [Line Items]
Cash dividends paid	1,705	$ 1,625	$ 1,775
Total Stockholders' Equity
Condensed Financial Statements, Captions [Line Items]
Dividend received from subsidiaries	$ 1,705	$ 1,625	$ 1,775