Vistra (VST) 10-Q 9 May 24 2024 Q1 Quarterly report Financial data

Cover Page

Cover Page - shares	3 Months Ended
	Mar. 31, 2024	May 03, 2024
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2024
Document Transition Report	false
Entity File Number	001-38086
Entity Registrant Name	Vistra Corp.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	36-4833255
Entity Address, Address Line One	6555 Sierra Drive,
Entity Address, City or Town	Irving,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	75039
City Area Code	(214)
Local Phone Number	812-4600
Title of 12(b) Security	Common stock, par value $0.01 per share
Trading Symbol	VST
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		347,460,001
Entity Central Index Key	0001692819
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	Q1
Amendment Flag	false

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Income Statement [Abstract]
Operating revenues	$ 3,054	$ 4,425
Fuel, purchased power costs and delivery fees	(1,716)	(2,170)
Operating costs	(498)	(421)
Depreciation and amortization	(403)	(366)
Selling, general and administrative expenses	(351)	(288)
Impairment of long-lived assets	0	(49)
Operating income	86	1,131
Other income	91	20
Other deductions	(4)	(3)
Interest expense and related charges	(170)	(207)
Impacts of Tax Receivable Agreement	(5)	(65)
Net income (loss) before income taxes	(2)	876
Income tax (expense) benefit	20	(178)
Net income	18	698
Net (income) loss attributable to noncontrolling interest	(53)	1
Net income (loss) attributable to Vistra	(35)	699
Cumulative dividends attributable to preferred stock	(49)	(38)
Net income (loss) attributable to Vistra common stock	$ (84)	$ 661
Weighted average shares of common stock outstanding:
Weighted average shares of common stock outstanding - basic (in shares)	348,966,197	383,631,369
Weighted average shares of common stock outstanding - diluted (in shares)	348,966,197	387,553,379
Net income (loss) per weighted average share of common stock outstanding:
Net income (loss) per weighted average share of common stock outstanding - basic (in dollars per share)	$ (0.24)	$ 1.72
Net income (loss) per weighted average share of common stock outstanding - diluted (in dollars per share)	$ (0.24)	$ 1.71

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 18	$ 698
Other comprehensive income, net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax expense (benefit) of $— and $—)	0	1
Total other comprehensive income	0	1
Comprehensive income	18	699
Comprehensive (income) loss attributable to noncontrolling interest	(53)	1
Comprehensive income (loss) attributable to Vistra	$ (35)	$ 700

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Statement of Comprehensive Income [Abstract]
Effect related to pension and other retirement benefit obligations (tax)	$ 0	$ 0

Condensed Consolidated Statem_4

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Cash flows — operating activities:
Net income	$ 18	$ 698
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	555	477
Deferred income tax expense (benefit), net	(23)	181
Impairment of long-lived assets	0	49
Unrealized net (gain) loss from mark-to-market valuations of commodities	176	(1,085)
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps	(47)	41
Unrealized net gain from nuclear decommissioning trusts	(28)	0
Asset retirement obligation accretion expense	19	9
Impacts of Tax Receivable Agreement	5	65
Gain on TRA repurchase and tender offers	(10)	0
Bad debt expense	36	35
Stock-based compensation	21	22
Other, net	(23)	8
Changes in operating assets and liabilities:
Margin deposits, net	128	1,227
Accrued interest	(3)	(47)
Accrued taxes	(111)	(91)
Accrued employee incentive	(169)	(79)
Other operating assets and liabilities	(232)	(75)
Cash provided by operating activities	312	1,435
Cash flows — investing activities:
Capital expenditures, including nuclear fuel purchases and LTSA prepayments	(465)	(484)
Energy Harbor acquisition (net of cash acquired)	(3,070)	0
Proceeds from sales of nuclear decommissioning trust fund securities	214	119
Investments in nuclear decommissioning trust fund securities	(220)	(125)
Proceeds from sales of environmental allowances	17	35
Purchases of environmental allowances	(131)	(61)
Proceeds from sale of property, plant and equipment, including nuclear fuel	127	2
Other, net	0	1
Cash used in investing activities	(3,528)	(513)
Cash flows — financing activities:
Issuances of long-term debt	700	0
Repayments/repurchases of debt	(756)	(7)
Net borrowings under accounts receivable financing	875	175
Borrowings under Revolving Credit Facility	0	100
Repayments under Revolving Credit Facility	0	(350)
Borrowings under Commodity-Linked Facility	500	0
Repayments under Commodity-Linked Facility	0	(400)
Stock repurchases	(291)	(301)
Dividends paid to common stockholders	(77)	(77)
TRA Repurchase and tender offer — return of capital	122	0
Other, net	(36)	(14)
Cash provided by (used in) financing activities	793	(874)
Net change in cash, cash equivalents and restricted cash	(2,423)	48
Cash, cash equivalents and restricted cash — beginning balance	3,539	525
Cash, cash equivalents and restricted cash — ending balance	$ 1,116	$ 573

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Current assets:
Cash and cash equivalents	$ 1,070	$ 3,485
Restricted cash included in current assets	32	40
Trade accounts receivable — net	1,729	1,674
Income taxes receivable	1	6
Inventories	976	740
Commodity and other derivative contractual assets	3,557	3,645
Margin deposits related to commodity contracts	1,186	1,244
Margin deposits posted under affiliate financing agreement	443	439
Prepaid expense and other current assets	439	364
Total current assets	9,433	11,637
Restricted cash included in noncurrent assets	14	14
Investments	4,219	2,035
Property, plant and equipment — net	18,014	12,432
Operating lease right-of-use assets	62	50
Goodwill	2,877	2,583
Identifiable intangible assets — net	2,278	1,864
Commodity and other derivative contractual assets	703	577
Accumulated deferred income taxes	0	1,223
Other noncurrent assets	578	551
Total assets	38,178	32,966
Current liabilities:
Short-term borrowings	500	0
Accounts receivable financing	875	0
Long-term debt due currently	54	2,286
Trade accounts payable	1,100	1,147
Commodity and other derivative contractual liabilities	5,214	5,258
Margin deposits related to commodity contracts	115	45
Accrued taxes other than income	118	203
Accrued interest	208	206
Asset retirement obligations	119	124
Operating lease liabilities	11	7
Other current liabilities	461	547
Total current liabilities	8,775	9,823
Margin deposit financing with affiliate	443	439
Total long-term debt less amounts due currently	14,693	12,116
Operating lease liabilities	56	48
Commodity and other derivative contractual liabilities	1,892	1,688
Accumulated deferred income taxes	118	1
Tax Receivable Agreement obligation	15	164
Asset retirement obligation	3,806	2,414
Total other noncurrent liabilities and deferred credits	1,096	951
Total liabilities	30,894	27,644
Commitments and Contingencies
Total equity:
Preferred stock, number of shares authorized — 100,000,000; Series A (liquidation preference — $1,000; shares outstanding: March 31, 2024 and December 31, 2023— 1,000,000); Series B (liquidation preference — $1,000; shares outstanding: March 31, 2024 and December 31, 2023 — 1,000,000); Series C (liquidation preference — $1,000; shares outstanding: March 31, 2024 and December 31, 2023 — 476,081)	2,476	2,476
Common stock (par value — $0.01; number of shares authorized — 1,800,000,000) (shares outstanding: March 31, 2024 — 348,733,986; December 31, 2023 — 351,457,016)	5	5
Treasury stock, at cost (shares: March 31, 2024 — 198,562,722; December 31, 2023 — 192,178,156)	(4,947)	(4,662)
Additional paid-in-capital	10,878	10,095
Retained deficit	(2,762)	(2,613)
Accumulated other comprehensive income	6	6
Stockholders' equity	5,656	5,307
Noncontrolling interest in subsidiary	1,628	15
Total equity	7,284	5,322
Total liabilities and equity	$ 38,178	$ 32,966

Condensed Consolidated Statem_5

Condensed Consolidated Statement of Changes in Equity - USD ($) $ in Millions		Total	Total Stockholders' Equity	Preferred Stock	Common Stock	Treasury Stock	Additional Paid-In Capital	Retained Deficit	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest in Subsidiary
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]
Stock repurchases		(311)	(311)			(311)
Effects of stock-based incentive compensation plans		24	24				24
Net income (loss)		698	699					699		(1)
Dividends declared on common stock		(77)	(77)					(77)
Dividends declared on preferred stock		(37)	(37)					(37)
Change in accumulated other comprehensive income (loss)		1	1						1
Ending balance at Mar. 31, 2023		5,216	5,201	2,000	5	(3,706)	9,952	(3,058)	8	15
Beginning balance at Dec. 31, 2023		5,322	5,307	2,476	5	(4,662)	10,095	(2,613)	6	15
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock repurchases		(285)	(285)			(285)
Effects of stock-based incentive compensation plans		35	35				35
Equity issued in subsidiary to acquire Energy Harbor	[1]	2,307	747				747			1,560
Net income (loss)		18	(35)					(35)		53
Dividends declared on common stock		(77)	(77)					(77)
Dividends declared on preferred stock		(37)	(37)					(37)
Other		1	1				1			0
Ending balance at Mar. 31, 2024		$ 7,284	$ 5,656	$ 2,476	$ 5	$ (4,947)	$ 10,878	$ (2,762)	$ 6	$ 1,628
[1] Noncontrolling interest in subsidiary includes $811 million representing the fair value of the 15% noncontrolling interest in Energy Harbor and $749 million representing 15% of the carrying value of net assets of certain subsidiaries contributed to Vistra Vision. See Note 2.

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares	Mar. 31, 2024	Dec. 31, 2023
Preferred stock, shares authorized (in shares)	100,000,000	100,000,000
Common stock, par or stated value per share (in dollars per share)	$ 0.01
Common stock, shares authorized (in shares)	1,800,000,000
Common stock, shares outstanding (in shares)	348,733,986	351,457,016
Treasury stock, common shares (in shares)	198,562,722	192,178,156
Series A Preferred Stock
Preferred sock, liquidation preference	$ 1,000	$ 1,000
Preferred stock, shares outstanding (in shares)	1,000,000	1,000,000
Series B Preferred Stock
Preferred sock, liquidation preference	$ 1,000	$ 1,000
Preferred stock, shares outstanding (in shares)	1,000,000	1,000,000
Series C Preferred Stock
Preferred sock, liquidation preference	$ 1,000	$ 1,000
Preferred stock, shares outstanding (in shares)	476,081	476,081

Condensed Consolidated Statem_6

Condensed Consolidated Statement of Changes in Equity (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2024	Mar. 01, 2024
Vistra Vision
Fair value of noncontrolling interest in Energy Harbor	$ 749
Energy Harbor
Fair value of noncontrolling interest in Energy Harbor		$ 811
Energy Harbor | Vistra Corp. | Vistra Vision
Subsidiary, ownership percentage, noncontrolling owner		15%
Subsidiary, ownership percentage, parent		15%
Energy Harbor | Vistra Vision
Subsidiary, ownership percentage, noncontrolling owner		15%
Subsidiary, ownership percentage, parent		85%

Business, Basis of Presentation

Business, Basis of Presentation and Significant Accounting Policies	3 Months Ended
	Mar. 31, 2024
Accounting Policies [Abstract]
Business, Basis of Presentation and Significant Accounting Policies	BUSINESS, BASIS OF PRESENTATION 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 six reportable segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. See Note 17 for further information concerning our reportable business segments. Basis of Presentation The condensed consolidated financial statements have been prepared in accordance with U.S. GAAP and on the same basis as the audited financial statements included in our 2023 Form 10-K. The condensed consolidated financial information herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal nature. All intercompany items and transactions have been eliminated in consolidation. 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 condensed 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. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with U.S. GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by U.S. GAAP, they should be read in conjunction with the audited financial statements and related notes contained in our 2023 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. dollars unless otherwise indicated. Significant Accounting Policies 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. Nuclear Decommissioning Trusts (NDTs) 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. Income and expense, including gains and losses associated with the NDT assets and the related decommissioning liability are offset by a corresponding change in a regulatory asset/liability (currently a regulatory liability reported in other noncurrent liabilities and deferred credits) that will ultimately be settled through changes in Oncor's delivery fees rates. 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 condensed 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. 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. Adoption of Accounting Standards 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 will adopt the amendments in this ASU for its fiscal year ended December 31, 2024 and interim periods within its fiscal year ended December 31, 2025. The amendment will be applied retrospectively to all prior periods presented. We are currently evaluating the impact this ASU will have on our consolidated financial statements and related disclosures. Improvements to Income Tax Disclosures In December 2023, the FASB issued ASU No. 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 our consolidated financial statements. Recent Developments See Note 8 for information on the Receivables Program amendment increasing the purchase limit and Note 10 for information on the $1.5 billion principal amount of senior secured and unsecured senior notes issued in April 2024.

Business Combinations

Business Combinations	3 Months Ended
	Mar. 31, 2024
Business Combination and Asset Acquisition [Abstract]
Business Combinations	BUSINESS COMBINATIONS 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 combines 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 our condensed consolidated financial statements beginning as of the Merger Date. The following table summarizes the acquisition date fair value of Energy Harbor associated with the Energy Harbor Merger on the Merger Date: (in millions) Consideration 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 maintains an 85% ownership interest in Vistra Vision and records the remaining 15% equity interest as a noncontrolling interest in our condensed consolidated balance sheets as of 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, adjustments to those measurements may be made in subsequent periods (up to one year from the acquisition date) as information necessary to complete the fair value analysis is obtained. The provisional fair values assigned to assets acquired and liabilities assumed are as follows: (in Millions) Fair Value as of March 1, 2024 Cash and cash equivalents $ 30 Trade accounts receivables, inventories, prepaid expenses and other current assets 538 Investments (a) 2,021 Property, plant and equipment (b) 5,620 Identifiable intangible assets (c) 428 Commodity and other derivative contractual assets (d) 140 Other noncurrent assets 8 Total identifiable assets acquired 8,785 Trade accounts payable and other current liabilities 263 Long-term debt, including amounts due currently 413 Commodity and other derivative contractual liabilities (d) 179 Accumulated deferred income taxes 1,364 Asset retirement obligations (e) 1,368 Identifiable intangible liabilities 73 Other noncurrent liabilities and deferred credits 12 Total identifiable liabilities assumed 3,672 Identifiable net assets acquired 5,113 Goodwill (f) 294 Net assets acquired $ 5,407 ____________ (a) NDT assets 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 12 (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 by Vistra Vision from combining operations of Energy Harbor with the contributed net assets of Vistra. None of the Goodwill is deductible for income tax purposes. The following unaudited pro forma financial information for the three months ended March 31, 2024 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. Three Months Ended March 31, (in millions) 2024 2023 Revenues $ 3,777 $ 4,891 Net income $ 69 $ 466 The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired, interest expense on debt assumed in the Energy Harbor Merger, effects of the Energy Harbor Merger on tax expense (benefit), and other related adjustments. Determining the amounts of revenue and earnings of Energy Harbor since the acquisition date is impractical as operations have been integrated into our commercial platform which is managed at a portfolio level. Acquisition costs incurred in the Energy Harbor Merger totaled $24 million and $6 million for the three months ended March 31, 2024 and 2023, respectively and are classified as selling, general and administrative expenses in our condensed consolidated statements of operations.

Retirement of Generation Facili

Retirement of Generation Facilities	3 Months Ended
	Mar. 31, 2024
Retirement of Generation Facilities [Abstract]
Retirement of Generation Facilities	RETIREMENT OF GENERATION FACILITIES Operational results for plants with defined retirement dates are included in our Sunset segment beginning in the quarter when a retirement plan is announced and move to the Asset Closure segment at the beginning of the calendar year the retirement is expected to occur. Facility Location ISO/RTO Fuel Type Net Generation Capacity (MW) Actual or Expected Retirement Date (a)(b) Segment Baldwin Baldwin, IL MISO Coal 1,185 By the end of 2025 Sunset Coleto Creek Goliad, TX ERCOT Coal 650 By the end of 2027 Sunset Kincaid Kincaid, IL PJM Coal 1,108 By the end of 2027 Sunset Miami Fort North Bend, OH PJM Coal 1,020 By the end of 2027 Sunset Newton Newton, IL MISO/PJM Coal 615 By the end of 2027 Sunset Edwards Bartonville, IL MISO Coal 585 Retired January 1, 2023 Asset Closure Joppa Joppa, IL MISO Coal 802 Retired September 1, 2022 Asset Closure Joppa Joppa, IL MISO Natural Gas 221 Retired September 1, 2022 Asset Closure Zimmer Moscow, OH PJM Coal 1,300 Retired June 1, 2022 Asset Closure Total 7,486 ____________ (a) Generation facilities may retire earlier than expected dates disclosed if economic or other conditions dictate. (b) Retirement dates represent the first full day in which a plant does not operate.

Revenue

Revenue	3 Months Ended
	Mar. 31, 2024
Revenue from Contract with Customer [Abstract]
Revenue	REVENUE Revenue Disaggregation Disaggregated revenue from contracts with customers, and other revenue included in total revenues in the condensed consolidated statements of operations is as follows: Three Months Ended March 31, 2024 (in millions) Retail (a) Texas East (a) West Sunset Asset Eliminations Consolidated Revenue from contracts with customers: Retail energy charge in ERCOT $ 1,702 $ — $ — $ — $ — $ — $ — $ 1,702 Retail energy charge in Northeast/Midwest 663 — — — — — — 663 Wholesale generation revenue from ISO/RTO — 60 261 88 80 — — 489 Capacity revenue from ISO/RTO (b) — — 15 — 4 — — 19 Revenue from other wholesale contracts — 104 70 57 55 — — 286 Total revenue from contracts with customers 2,365 164 346 145 139 — — 3,159 Other revenues: Intangible amortization — — — — (1) — — (1) Transferable PTC revenues — 2 — — — — — 2 Hedging and other revenues (c) 123 (274) (138) 139 44 — — (106) Affiliate sales (d) 6 547 429 1 57 — (1,040) — Total other revenues 129 275 291 140 100 — (1,040) (105) Total revenues $ 2,494 $ 439 $ 637 $ 285 $ 239 $ — $ (1,040) $ 3,054 ____________ (a) Includes revenues associated with March 2024 operations acquired in the Energy Harbor Merger. (b) Represents net capacity sold in each ISO/RTO. The East segment includes $36 million of capacity sold offset by $21 million of capacity purchased. The Sunset segment includes $4 million of capacity sold. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs and delivery fees in our condensed consolidated statement of operations includes capacity purchased of $7 million offset by $2 million of capacity sold within the East segment. (c) Includes $347 million of unrealized net losses from mark-to-market valuations of commodity positions. Three Months Ended Retail Texas East West Sunset Asset Closure Corporate and Other Eliminations (1) Consolidated March 31, 2024 $ (155) $ (602) $ (355) $ 136 $ (156) $ 4 $ — $ 781 $ (347) ___________________ (1) Amounts attributable to generation segments offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results. (d) Texas, East and Sunset segment includes $470 million, $255 million and $56 million, respectively, of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment. Three Months Ended March 31, 2023 (in millions) Retail Texas East West Sunset Asset Eliminations Consolidated Revenue from contracts with customers: Retail energy charge in ERCOT $ 1,568 $ — $ — $ — $ — $ — $ — $ 1,568 Retail energy charge in Northeast/Midwest 427 — — — — — — 427 Wholesale generation revenue from ISO/RTO — 50 220 193 67 — — 530 Capacity revenue from ISO/RTO (a) — — 8 — 19 — — 27 Revenue from other wholesale contracts — 107 331 41 76 — — 555 Total revenue from contracts with customers 1,995 157 559 234 162 — — 3,107 Other revenues: Intangible amortization (1) — (1) — (1) — — (3) Transferable PTC revenue — 2 — — — — — 2 Hedging and other revenues (b) 356 112 386 (7) 472 — — 1,319 Affiliate sales (c) — 1,082 865 4 195 — (2,146) — Total other revenues 355 1,196 1,250 (3) 666 — (2,146) 1,318 Total revenues $ 2,350 $ 1,353 $ 1,809 $ 231 $ 828 $ — $ (2,146) $ 4,425 ____________ (a) Represents net capacity sold in each ISO/RTO. The East segment includes $42 million of capacity sold offset by $34 million of capacity purchased. The Sunset segment includes $46 million of capacity sold offset by $27 million of capacity purchased. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs and delivery fees in our condensed consolidated statement of operations includes capacity purchased of $31 million offset by $21 million of capacity sold within the East segment. (b) Includes $1.277 billion of unrealized net gains from mark-to-market valuations of commodity positions. Three Months Ended Retail Texas East West Sunset Asset Closure Corporate and Other Eliminations (1) Consolidated March 31, 2023 $ 140 $ 368 $ 943 $ 12 $ 477 $ 17 $ — $ (680) $ 1,277 ___________________ (1) Amounts attributable to generation segments offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results. (c) Texas, East and Sunset segments include $185 million, $394 million and $103 million, respectively, of affiliated unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment. Performance Obligations As of March 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 will be recognized assuming the performance obligations are met and as capacity is made available to the related ISOs/RTOs or counterparties. Balance of 2024 2025 2026 2027 2028 2029 and Thereafter Total Remaining performance obligations $ 401 $ 463 $ 329 $ 272 $ 122 $ 610 $ 2,197 Accounts Receivable See Note 18 for details of accounts receivable relating to revenue from contracts with customers and other activities.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 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: Three Months Ended March 31, (in millions) 2024 2023 Net income (loss) before income taxes $ (2) $ 876 Income tax (expense) benefit $ 20 $ (178) Effective tax rate 1,000.0 % 20.3 % We evaluate and update our annual effective income tax rate on an interim basis based on current and forecasted earnings and tax laws. The mix and timing of our actual earnings compared to annual projections, as well as the amount of pre-tax earnings in comparison to the required discrete items, can cause interim effective tax rate fluctuations. For the three months ended March 31, 2024, the effective tax rate of 1,000.0% was higher than the U.S. federal statutory rate of 21% due primarily to the level of pre-tax earnings during the period and permanent differences recorded discretely related to stock-based compensation, partially offset by mark-to-market losses. For the three months ended March 31, 2023, the effective tax rate of 20.3% was lower than the U.S. federal statutory rate of 21% due primarily to state income taxes. 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, a first-time stand-alone battery storage investment tax credit, a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases. The section 45U nuclear PTC provides a federal tax credit of up to $15/MWh, subject to phase out as power prices increase above $25/MWh, to existing nuclear facilities from 2024 through 2032. Treasury regulations are expected to further define the scope of the legislation in many important respects over the next twelve months, including critical guidance interpreting the nuclear PTC. The Company accounts for transferable ITCs and PTCs we expect to receive by analogy to the grant model within IAS 20, as U.S. GAAP does not address how to account for these tax credits. 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. Transferable ITCs In June 2023, our 350 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase III) commenced commercial operations. As a result of Moss Landing Phase III reaching commercial operations, in 2023 we recognized $154 million of transferable ITCs associated with the project within other noncurrent assets in the condensed consolidated balance sheets. 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 addback 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 2023 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 addback of depreciation and amortization to adjusted taxable income. Liability for Uncertain Tax Positions 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. There were no uncertain tax positions as of both March 31, 2024 and December 31, 2023.

Earnings Per Share

Earnings Per Share	3 Months Ended
	Mar. 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. Three Months Ended March 31, (in millions, except share data) 2024 2023 Net income (loss) attributable to Vistra $ (35) $ 699 Less cumulative dividends attributable to Series A Preferred Stock (20) (20) Less cumulative dividends attributable to Series B Preferred Stock (18) (18) Less cumulative dividends attributable to Series C Preferred Stock (11) — Net income (loss) attributable to common stock — basic and diluted $ (84) $ 661 Weighted average shares of common stock outstanding: Basic 348,966,197 383,631,369 Dilutive securities: Stock-based incentive compensation plan — 3,922,010 Diluted 348,966,197 387,553,379 Net income (loss) per weighted average share of common stock outstanding: Basic $ (0.24) $ 1.72 Diluted $ (0.24) $ 1.71 Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 7,954,878 and 3,859,165 shares for the three months ended March 31, 2024 and 2023, respectively.

Goodwill and Identifiable Intan

Goodwill and Identifiable Intangible Assets and Liabilities	3 Months Ended
	Mar. 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 March 31, 2024 and December 31, 2023, the carrying value of goodwill totaled $2.877 billion and $2.583 billion, respectively. Retail Segment Texas Segment (in millions) Retail Reporting Unit (a) Texas Generation Reporting Unit Total Goodwill Balance at December 31, 2023 $ 2,461 $ 122 $ 2,583 Goodwill recorded in connection with the Energy Harbor Merger (b) 294 Balance at March 31, 2024 $ 2,461 $ 122 $ 2,877 ____________ (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. Identifiable Intangible Assets and Liabilities Identifiable intangible assets are comprised of the following: March 31, 2024 December 31, 2023 Identifiable Intangible Asset (in millions) Gross Carrying Amount Accumulated Net Gross Carrying Amount Accumulated Net Retail customer relationships $ 2,170 $ 1,888 $ 282 $ 2,088 $ 1,866 $ 222 Software and other technology-related assets 545 249 296 536 315 221 Retail and wholesale contracts 503 218 285 233 217 16 LTSA 18 5 13 18 5 13 Other identifiable intangible assets (a) 73 12 61 62 11 51 Total identifiable intangible assets subject to amortization $ 3,309 $ 2,372 937 $ 2,937 $ 2,414 523 Retail trade names (not subject to amortization) 1,341 1,341 Total identifiable intangible assets $ 2,278 $ 1,864 ____________ (a) Includes environmental allowances (emissions allowances and renewable energy certificates) and mining development costs. Identifiable intangible liabilities are comprised of the following: Identifiable Intangible Liability (in millions) March 31, December 31, 2023 LTSA $ 121 $ 122 Power and fuel purchase contracts 62 9 Total identifiable intangible liabilities $ 183 $ 131 Expense related to finite-lived identifiable intangible assets (including the classification in the condensed consolidated statements of operations) consist of: Identifiable Intangible Assets (in millions) Condensed Consolidated Statements of Operations Three Months Ended March 31, 2024 2023 Retail customer relationships Depreciation and amortization $ 22 $ 28 Software and other technology-related assets Depreciation and amortization 13 15 Retail and wholesale contracts Operating revenues/fuel, purchased power costs and delivery fees 1 2 Other identifiable intangible assets Fuel, purchased power costs and delivery fees 103 86 Total identifiable intangible assets expense (a) $ 139 $ 131 ___________ (a) Amounts exclude LTSA. Amounts include all expenses associated with environmental allowances including expenses accrued to comply with emissions allowance programs and renewable portfolio standards which are presented in fuel, purchased power costs and delivery fees on our condensed consolidated statements of operations. Emissions allowance obligations are accrued as associated electricity is generated and renewable energy certificate obligations are accrued as retail electricity delivery occurs. Estimated Amortization of Identifiable Intangible Assets As of March 31, 2024, the estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as shown below. Year Estimated Amortization Expense 2024 $ 167 2025 $ 141 2026 $ 77 2027 $ 49 2028 $ 32

Accounts Receivable Financing

Accounts Receivable Financing	3 Months Ended
	Mar. 31, 2024
Accounts Receivable Financing [Abstract]
Accounts Receivable Financing	ACCOUNTS RECEIVABLE FINANCING Accounts Receivable Securitization Program TXU Energy Receivables Company LLC (RecCo), an indirect subsidiary of Vistra, has an accounts receivable financing facility (Receivables Facility) provided by issuers of asset-backed commercial paper and commercial banks (Purchasers). The Receivables Facility was renewed in July 2023, extending the term of the Receivables Facility to July 2024 and adjusting the commitment of the purchasers to purchase interests in the receivables under the Receivables Facility during all periods to a fixed purchase limit of $750 million from seasonally adjusted commitment limits ranging from $600 million to $750 million. On April 8, 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. 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 on the condensed consolidated balance sheets. Proceeds and repayments under the Receivables Facility are reflected as cash flows from financing activities in our condensed consolidated statements of cash flows. Receivables transferred to the Purchasers remain on Vistra's balance sheet and Vistra reflects a liability equal to the amount advanced by the Purchasers. The Company records interest expense on amounts advanced. TXU Energy continues to service, administer and collect the Receivables on behalf of RecCo and the Purchasers, as applicable. As of March 31, 2024, outstanding borrowings under the Receivables Facility totaled $750 million and were supported by $913 million 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 2023, the Repurchase Facility was renewed until July 2024 while maintaining the facility size of $125 million. The Repurchase Facility is collateralized by a subordinated note (Subordinated Note) issued by RecCo in favor of TXU Energy for the benefit of Originators under the Receivables Facility and representing a portion of the outstanding balance of the purchase price paid for the Receivables sold by the Originators to RecCo under the Receivables Facility. Under the Repurchase Facility, TXU Energy may request that Buyer transfer funds to TXU Energy in exchange for a transfer of the Subordinated Note, with a simultaneous agreement by TXU Energy to transfer funds to Buyer at a date certain or on demand in exchange for the return of the Subordinated Note (collectively, the Repo Transaction). Each Repo Transaction is expected to have a term of one month, unless terminated earlier on demand by TXU Energy or terminated by Buyer after an event of default. TXU Energy and the other Originators have each granted Buyer a first-priority security interest in the Subordinated Note to secure its obligations under the agreements governing the Repurchase Facility, and Vistra Operations has agreed to guarantee the obligations under the agreements governing the Repurchase Facility. Unless earlier terminated under the agreements governing the Repurchase Facility, the Repurchase Facility will terminate concurrently with the scheduled termination of the Receivables Facility. As of March 31, 2024, outstanding borrowings under the Repurchase Facility totaled $125 million. There were no outstanding borrowings under the Repurchase Facility as of December 31, 2023.

Collateral Financing Agreement

Collateral Financing Agreement With Affiliate	3 Months Ended
	Mar. 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 March 31, 2024 and December 31, 2023, the fair value of Eligible Assets held by counterparties to satisfy current and future margin deposit requirements totaled $443 million and $439 million, respectively, and are reported in our condensed consolidated balance sheets as margin deposits posted under affiliate financing agreement and margin deposits financing with affiliate.

Debt

Debt	3 Months Ended
	Mar. 31, 2024
Debt Disclosure [Abstract]
Debt	DEBT Amounts in the table below represent the categories of long-term debt obligations, including amounts due currently, incurred by the Company. (in millions) March 31, December 31, Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030 $ 2,494 $ 2,500 Vistra Zero Credit Facility, Term Loan B Facility due April 30, 2031 700 — Vistra Operations Senior Secured Notes: 4.875% Senior Secured Notes, due May 13, 2024 342 400 3.550% Senior Secured Notes, due July 15, 2024 1,155 1,500 5.125% Senior Secured Notes, due May 13, 2025 744 1,100 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 Total Vistra Operations Senior Secured Notes 4,891 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 Total Vistra Operations Senior Unsecured Notes 6,300 6,300 Other: Equipment Financing Agreements 67 67 Total other long-term debt 67 67 Unamortized debt premiums, discounts and issuance costs (136) (115) Total long-term debt including amounts due currently 14,747 14,402 Less amounts due currently (a) (54) (2,286) Total long-term debt less amounts due currently $ 14,693 $ 12,116 ____________ (a) Excludes 4.875% Senior Secured Notes due May 2024 and 3.550% Senior Secured Notes due July 2024 as amounts will be refinanced on a long-term basis using net proceeds from the 6.000% Senior Secured Notes due 2034 and 6.875% Senior Unsecured Notes due 2032 (defined below) issued in April 2024. Maturities Long-term debt maturities as of March 31, 2024 are as follows: (in millions) March 31, 2024 Remainder of 2024 $ 1,532 2025 786 2026 1,038 2027 3,434 2028 35 Thereafter 8,058 Unamortized premiums, discounts and debt issuance costs (136) Total long-term debt, including amounts due currently $ 14,747 Credit Facilities Our credit facilities and related available capacity as of March 31, 2024 are presented below. (in millions) March 31, 2024 Credit Facilities Maturity Date Facility Cash Borrowings (Short-Term) Cash Borrowings (Long-Term) Letters of Credit Outstanding Available Revolving Credit Facility April 29, 2027 $ 3,175 $ — $ — $ 1,882 $ 1,293 Term Loan B-3 Facility December 20, 2030 2,494 — 2,494 — — Total Vistra Operations Credit Facilities $ 5,669 $ — $ 2,494 $ 1,882 $ 1,293 Vistra Operations Commodity-Linked Facility October 2, 2024 1,575 500 — — 637 Vistra Zero Term Loan B Facility April 30, 2031 700 — 700 — — Total credit facilities $ 7,944 $ 500 $ 3,194 $ 1,882 $ 1,930 Vistra Operations Credit Facilities As of March 31, 2024, the Vistra Operations Credit Facilities consisted of up to $5.669 billion in senior secured, first-lien revolving credit commitments and outstanding term loans, which consisted of revolving credit commitments of up to $3.175 billion (Revolving Credit Facility), including aggregate revolving letter of credit commitments of $3.105 billion, and term loans of $2.494 billion (Term Loan B-3 Facility). The Revolving Credit Facility is used for general corporate purposes. Under the Vistra Operations Credit Agreement, (i) the interest applicable to the Revolving Credit Facility is based on the forward-looking term rate based on SOFR (Term SOFR Rate) plus a spread that will range from 1.25% to 2.00% and (ii) the fee on any undrawn amounts with respect to the Revolving Credit Facility will range from 17.5 basis points to 35.0 basis points. Letters of credit issued under the Revolving Credit Facility bear interest that ranges from 1.25% to 2.00%. Interest and fees on the Revolving Credit Facility are based on ratings of Vistra Operations' senior secured long-term debt securities. As of March 31, 2024, the applicable interest rate margins for the Revolving Credit Facility and the fee for undrawn amounts relating to such commitments were 1.70% and 26.5 basis points, respectively, and the applicable interest rate margin for the letters of credit issued under the Revolving Credit facility was 1.70%. The Vistra Operations Credit Facilities also provide for certain additional customary fees payable to the agents and lenders, including fronting fees with respect to outstanding letters of credit. The Term Loan B-3 Facility bears interest based on the applicable Term SOFR Rate, plus a fixed spread of 2.00%, and the weighted average interest rates before taking into consideration interest rate swaps (see Note 11) on outstanding borrowings of $2.494 billion was 7.33% as of March 31, 2024. 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. Obligations under the Vistra Operations Credit Facilities are secured by liens covering substantially all of Vistra Operations' (and certain of its subsidiaries') consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra Operations Credit Facilities. The Vistra Operations Credit Agreement includes certain collateral suspension provisions that would take effect upon Vistra Operations achieving unsecured investment grade ratings from two ratings agencies, there being no Term Loans (under and as defined in the Vistra Operations Credit Agreement) then outstanding (or the holders thereof agreeing to release such security interests), and there being no outstanding revolving credit commitments the maturities of which have not been extended to April 29, 2027 (or the holders thereof agreeing to release such security interests), such collateral suspension provisions would continue to be in effect unless and until Vistra Operations no longer holds unsecured investment grade ratings from at least two ratings agencies, at which point collateral reversion provisions would take effect (subject to a 60-day grace period). The Vistra Operations Credit Facilities also permit certain hedging agreements and cash management agreements to be secured on a pari-passu basis with the Vistra Operations Credit Facilities in the event those hedging agreements and cash management agreements 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 agents under the Vistra Operations Credit Facilities and to not change its lines of business, and negative covenants restricting Vistra Operations' (and its restricted subsidiaries') ability to incur additional indebtedness, make investments, dispose of assets, pay dividends, grant liens or take certain other actions, in each case, except as permitted in the Vistra Operations Credit Facilities. Vistra Operations' ability to borrow under the Vistra Operations Credit Facilities is subject to the satisfaction of certain customary conditions precedent set forth therein. The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties, material breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against Vistra Operations. Solely with respect to the Revolving Credit Facility, and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $300 million) exceed 30% of the revolving commitments), the agreement includes a covenant that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first lien debt compared to an EBITDA calculation defined under the terms of the Vistra Operations Credit Facilities, not to exceed 4.25 to 1.00 (or, during a collateral suspension period, the consolidated total net leverage ratio, which is based on the ratio of consolidated total debt compared to an EBITDA calculation defined under the terms of the Vistra Operations Credit Facilities, not to exceed 5.50 to 1.00). 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. Vistra Operations Commodity-Linked Revolving Credit Facility As of March 31, 2024, the Vistra Operations senior secured commodity-linked revolving credit facility (Commodity-Linked Facility) totaled $1.575 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. The Commodity-Linked Facility is used to support our hedging strategy. As of March 31, 2024, the borrowing base of $1.137 billion is lower than the facility limit which represents the aggregate commitments of $1.575 billion. Under the Commodity-Linked Facility, the borrowing base is calculated on a weekly basis based on a set of theoretical transactions which approximate a portion of the hedge portfolio of Vistra Operations and certain of its subsidiaries in certain power markets, with availability thereunder not to exceed the aggregate available commitments nor be less than zero. Vistra Operations may, at its option, borrow an amount up to the borrowing base, as adjusted from time to time, provided that if outstanding borrowings at any time would exceed the borrowing base, Vistra Operations shall make a repayment to reduce outstanding borrowings to be less than or equal to the borrowing base. Vistra Operations intends to use any borrowings provided under the Commodity-Linked Facility to make cash postings as required under various commodity contracts to which Vistra Operations and its subsidiaries are parties as power prices increase from time-to time and for other working capital and general corporate purposes. Under the Vistra Operations Commodity-Linked Credit Agreement, (i) the interest applicable to the Commodity-Linked Facility is based on the Term SOFR Rate plus a spread that will range from 1.25% to 2.00% and (ii) the fee on any undrawn amounts with respect to the Commodity-Linked Facility will range from 17.5 basis points to 35.0 basis points. Interest and fees on the Commodity-Linked Facility are based on ratings of Vistra Operations' senior secured long-term debt securities. As of March 31, 2024, the applicable interest rate margins for the Commodity-Linked Facility and the fee on any undrawn amounts with respect to the Commodity-Linked Facility were 1.70% and 26.5 basis points, respectively As of March 31, 2024, there were $500 million in outstanding borrowings under the Commodity-Linked Facility and the weighted average interest rate on outstanding borrowings was 7.03%. The Vistra Operations Commodity-Linked Credit Agreement includes a covenant, solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings exceeds 30% of the revolving commitments), that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first lien debt compared to an EBITDA calculation defined under the terms of the Commodity-Linked Facility, not to exceed 4.25 to 1.00 (or, during a collateral suspension period, the consolidated total net leverage ratio, which is based on the ratio of consolidated total debt compared to an EBITDA calculation defined under the terms of the Commodity-Linked Facility, not to exceed 5.50 to 1.00). Vistra Zero Credit Agreement On March 26, 2024, Vistra Zero 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 borrowed in its entirety on March 26, 2024. Net proceeds of $690 million will be used (i) to pay issuance costs and (ii) for working capital and general corporate purposes. Vistra Zero's obligations under the Vistra Zero Credit Agreement are guaranteed by certain subsidiaries of Vistra Zero, but are otherwise non-recourse to Vistra Operations and its other subsidiaries. Under the Vistra Zero Credit Agreement, the interest applicable to the Term Loan B Facility is Term SOFR plus 2.75% per annum. The Term Loan B Facility is not subject to a floor or credit spread adjustment but is subject to a 1.0% "soft call" prepayment premium prior to the date that is six months following March 26, 2024. The weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings of $700 million was 8.08% as of March 31, 2024. Cash borrowings under the Term Loan B Facility are subject to required scheduled quarterly payments of $1.75 million. Amounts paid cannot be reborrowed. The Vistra Zero Credit Agreement contains customary covenants and warranties which are generally consistent in scope with the Vistra Operations Credit Agreement, except that there is no financial maintenance covenant in the Vistra Zero Credit Agreement. Vistra Operations Secured Letter of Credit Facilities In August and September 2020, Vistra entered into uncommitted standby letter of credit facilities that may be renewed annually and that are each secured by a first lien on substantially all of Vistra Operations' (and certain of its subsidiaries') assets (which ranks pari passu with the Vistra Operations Credit Facilities) (each, a Secured LOC Facility and collectively, the Secured LOC Facilities). The Secured LOC Facilities are used for general corporate purposes. In October 2021, September 2022 and October 2022, Vistra entered into additional Secured LOC Facilities which are used for general corporate purposes. As of March 31, 2024, $898 million of letters of credit were outstanding under the Secured LOC Facilities. Each of the Secured LOC Facilities includes a covenant that requires the consolidated first lien net leverage ratio not to exceed 4.25 to 1.00 (or, for certain facilities that include a collateral suspension mechanism, during a collateral suspension period, the consolidated total net leverage ratio not to exceed 5.50 to 1.00). Vistra Operations Unsecured Alternative Letter of Credit Facility In March 2024, we entered into an unsecured alternative letter of credit facility (Alternative LOC Facility) to be used for general corporate purposes. As of March 31, 2024, the total capacity was $125 million and $100 million of letters of credit were outstanding under the Alternative LOC Facility. In April 2024, the capacity of the Alternative LOC Facility was increased to $300 million. The Alternative LOC Facility matures in December 2028. There are no financial maintenance covenants in the Alternative LOC Facility. Energy Harbor Letter of Credit Facility Energy Harbor and its subsidiaries were parties to a letter of credit facility that was secured by a first lien on the Energy Harbor assets (Energy Harbor LOC Facility). As of March 31, 2024, $115 million of letters of credit were outstanding under the Energy Harbor LOC Facility. As of April 24, 2024, the Energy Harbor LOC Facility was terminated. Vistra Operations Senior Secured Notes 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. The 6.000% 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, by and among the Issuer, as borrower, Vistra Intermediate Company LLC, the guarantors party thereto, and Citibank, N.A. as administrative and collateral agent. The 6.000% Senior Secured Notes mature in April 15, 2034, with interest 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, will be used for general corporate purposes, including to refinance outstanding indebtedness (including the upcoming 2024 senior secured debt maturities). Fees and expenses related to the offering, including commissions and the original issue discount, totaled $5 million and were capitalized as a reduction in the carrying amount of the debt. In January 2024, Vistra Operations used the net proceeds from the December 2023 issuances of 6.950% senior secured notes due 2033 and 7.750% senior unsecured notes due 2031 discussed below and cash on hand to fund a cash tender offer (Senior Secured Notes Tender Offer) to purchase for cash $759 million aggregate principal amount of certain notes, including $58 million of 4.875% senior secured notes due 2024, $345 million of 3.550% senior secured notes due 2024 and $356 million of the 5.125% senior secured notes due 2025. We recorded an extinguishment gain of $6 million on the transaction in the first quarter of 2024. Since 2019, Vistra Operations issued and sold $5.65 billion aggregate principal amount of senior secured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act. The indenture (as may be amended or supplemented from time to time, the Vistra Operations Senior Secured Indenture) governing the 4.875% senior secured notes due 2024, the 3.550% senior secured notes due 2024, the 5.125% senior secured notes due 2025, the 3.700% senior secured notes due 2027, the 4.300% senior secured notes due 2029 and the 6.950% Senior Secured Notes (collectively, as each may be amended or supplemented from time to time, the Senior Secured Notes) provides for the full and unconditional guarantee by certain of Vistra Operations' current and future subsidiaries that also guarantee the Vistra Operations Credit Facilities. The Senior Secured Notes are secured by a first-priority security interest in the same collateral that is pledged for the benefit of the lenders under the Vistra Operations Credit Facilities, which consists of a substantial portion of the property, assets and rights owned by Vistra Operations and certain direct and indirect subsidiaries of Vistra Operations as subsidiary guarantors (collectively, the Guarantor Subsidiaries) as well as the stock of Vistra Operations held by Vistra Intermediate. The collateral securing the Senior Secured Notes will be released if Vistra Operations' senior, unsecured long-term debt securities obtain an investment grade rating from two out of the three rating agencies, subject to reversion if such rating agencies withdraw the investment grade rating of Vistra Operations' senior, unsecured long-term debt securities or downgrade such rating below investment grade. The Vistra Operations Senior Secured Indenture contains certain covenants and restrictions, including, among others, restrictions on the ability of Vistra Operations and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets. Energy Harbor Revenue Bonds Various governmental entities in Ohio and Pennsylvania have previously issued six different 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 (each such tranche, a revenue bond and collectively, the revenue bonds). Funds from the issuance of the revenue bonds were on-lent by the relevant governmental authority, as lender, to each of EHG or EHNG, as applicable, pursuant to individual loan agreements between the relevant governmental entity and EH entity (each such loan agreement, an on-lending agreement and collectively, the on-lending agreements). Under those on-lending agreements the relevant EH entity is obligated to provide contractual payments to service the principal and interest on the revenue bonds via payments on the loans. The repayment of the loans is not directly secured by the assets of the EH entities; rather such repayment is secured by a pledge of certain mortgage bonds issued by the EH entities to the relevant trustees under the respective revenue bonds. The mortgage bonds are issued by the relevant EH entity pursuant to an open-ended mortgage indenture (the base indenture), and supplemented by supplemental indentures adding the relevant tranche of mortgage bonds backing the related revenue bonds to the base indenture (as so supplemented, the mortgage indentures). The obligations under the mortgage bonds issued pursuant to the mortgage indentures are secured by substantially all assets of the EH entities, including their plants and related real estate. The obligations under mortgage indentures are cross-collateralized to each other, and provide that payments of principal and interest by the relevant EH entity under its on-lending agreement with the governmental authority constitute a dollar-for-dollar credit against the payment obligations of such EH entity under the mortgage indentures, such that the EH entities are never expected to make any payments under the bonds governed by the mortgage indentures. In the event of a default under the on-lending agreements (which are not cross-defaulted to each other), 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 under the on-lending agreements and the related mortgage indentures are guaranteed on an unsecured basis by Energy Harbor. Neither the EH entities nor Energy Harbor provides credit support for any of the debt obligations of Vistra Operations. Vistra Operations Senior Unsecured Notes 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. The 6.875% Senior Unsecured 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, by and among the Issuer, as borrower, Vistra Intermediate Company LLC, the guarantors party thereto, and Citibank, N.A. as administrative and collateral agent. The 6.875% Senior Secured Notes mature in April 15, 2032, with interest 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, will be used for general corporate purposes, including to refinance outstanding indebtedness (including the upcoming 2024 senior secured debt maturities). Fees and expenses related to the offering totaled $10 million and were capitalized as a reduction in the carrying amount of the debt. Since 2018, Vistra Operations has issued and sold $6.30 billion aggregate principal amount of senior unsecured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act. The indentures (as may be amended or supplemented from time to time, the Vistra Operations Senior Unsecured Indentures) governing the 5.500% senior unsecured notes due 2026, the 5.625% senior unsecured notes due 2027, the 5.000% senior unsecured notes due 2027, the 4.375% senior unsecured notes due 2029 and the 7.750% Senior Unsecured Notes (collectively, as each may be amended or supplemented from time to time, the Senior Unsecured Notes) provide for the full and unconditional guarantee by the Guarantor Subsidiaries of the punctual payment of the principal and interest on such notes. The Vistra Operations Senior Unsecured Indentures contain certain covenants and restrictions, including, among others, restrictions on the ability of Vistra Operations and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets. Debt Repurchase Program In January 2024, we settled the Senior Secured Notes Tender Offer. In April 2024, the Board authorized the voluntary repayment or repurchase of up to $1.0 billion of outstanding debt, with such authorization expiring on December 31, 2024.

Commodity and Other Derivative

Commodity and Other Derivative Contractual Assets and Liabilities	3 Months Ended
	Mar. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity and Other Derivative Contractual Assets and Liabilities	COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES We transact in derivative instruments, such as options, swaps, futures and forward contracts, to manage our exposure to commodity price and interest rate volatility. Although we do engage in economic hedging activities to manage our exposure related to commodity price fluctuations through the use of financial and physical derivative contracts, we have no derivative positions accounted for as cash flow or fair value hedges as of March 31, 2024. All changes in the fair values of our derivative contracts, excluding contracts which are considered normal purchases and sales (NPNS), are recognized as gains or losses in the earnings of the periods in which they occur. See Note 12 for a discussion of the fair value of derivatives. Commodity Hedging and Trading Activity We utilize natural gas and electricity derivatives to (i) reduce exposure to changes in electricity prices primarily to hedge future revenues from electricity sales from our generation assets, and (ii) to hedge future purchased power costs for our retail operations. We also utilize short-term electricity, natural gas, coal, and emissions derivative instruments for fuel hedging and other purposes. 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. Unrealized gains and losses arising from changes in the fair value of derivative instruments as well as realized gains and losses upon settlement of the instruments are reported in our condensed consolidated statements of operations in either operating revenues or fuel, purchased power costs and delivery fees. Interest Rate Swaps Interest rate swap agreements are used to reduce volatility in interest costs and related cash flows associated with our variable rate debt obligations. Unrealized gains and losses arising from changes in the fair value of the interest rate swaps as well as realized gains and losses upon settlement are reported in our condensed consolidated statements of operations in interest expense and related charges. As of March 31, 2024, Vistra has entered into the following interest rate swaps: (in millions, except percentages) Notional Amount Expiration Date Rate Range (c) Swapped to fixed (a) $3,000 July 2026 4.89 % - 4.97% Swapped to variable (a) $700 July 2026 3.44 % - 3.49% Swapped to fixed (b) $1,625 December 2030 5.20 % - 5.37% ____________ (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 2.00%. Financial Statement Effects of Derivatives Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of derivative contractual assets and liabilities as reported in our condensed consolidated balance sheets as of March 31, 2024 and December 31, 2023. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract. March 31, 2024 (in millions) Derivative Assets Derivative Liabilities Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total Current assets $ 3,479 $ 59 $ 19 $ — $ 3,557 Noncurrent assets 653 48 2 — 703 Current liabilities (14) — (5,176) (24) (5,214) Noncurrent liabilities (5) — (1,866) (21) (1,892) Net assets (liabilities) $ 4,113 $ 107 $ (7,021) $ (45) $ (2,846) December 31, 2023 Derivative Assets Derivative Liabilities (in millions) Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total Current assets $ 3,585 $ 53 $ 7 $ — $ 3,645 Noncurrent assets 565 11 1 — 577 Current liabilities (1) — (5,233) (24) (5,258) Noncurrent liabilities (5) — (1,659) (24) (1,688) Net assets (liabilities) $ 4,144 $ 64 $ (6,884) $ (48) $ (2,724) The following table presents the pre-tax effect of derivative gains (losses) on net income, including both the realized and unrealized effects. Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts. Derivative (condensed consolidated statements of operations presentation) (in millions) Three Months Ended March 31, 2024 2023 Commodity contracts (Operating revenues) $ (608) $ 669 Commodity contracts (Fuel, purchased power costs and delivery fees) 45 (295) Interest rate swaps (Interest expense and related charges) 58 (28) Net gain (loss) $ (505) $ 346 Balance Sheet Presentation of Derivatives We elect to report derivative assets and liabilities in our condensed consolidated balance sheets on a gross basis without taking into consideration netting arrangements we have with counterparties to those derivatives. We maintain standardized master netting agreements with certain counterparties that allow for the right to offset assets and liabilities and collateral in order to reduce credit exposure between us and the counterparty. These agreements contain specific language related to margin requirements, monthly settlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract counterparty. Generally, margin deposits that contractually offset these derivative instruments are reported separately in our condensed consolidated balance sheets, with the exception of certain margin amounts related to changes in fair value on CME transactions that are legally characterized as settlement of forward exposure rather than collateral. Margin deposits received from counterparties are primarily used for working capital or other general corporate purposes. The following tables reconcile our derivative assets and liabilities on a contract basis to net amounts after taking into consideration netting arrangements with counterparties and financial collateral: March 31, 2024 December 31, 2023 (in millions) Derivative Assets Offsetting Instruments (a) Cash Collateral (Received) Pledged (b) Net Amounts Derivative Assets Offsetting Instruments (a) Cash Collateral (Received) Pledged (b) Net Amounts Derivative assets: Commodity contracts $ 4,113 $ (3,392) $ (84) $ 637 $ 4,144 $ (3,519) $ (26) $ 599 Interest rate swaps 107 (35) — 72 64 (28) — 36 Total derivative assets 4,220 (3,427) (84) 709 4,208 (3,547) (26) 635 Derivative liabilities: Commodity contracts (7,021) 3,392 914 (2,715) (6,884) 3,519 970 (2,395) Interest rate swaps (45) 35 — (10) (48) 28 — (20) Total derivative liabilities (7,066) 3,427 914 (2,725) (6,932) 3,547 970 (2,415) Net amounts $ (2,846) $ — $ 830 $ (2,016) $ (2,724) $ — $ 944 $ (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. Derivative Volumes The following table presents the gross notional amounts of derivative volumes, by commodity, excluding those derivatives that qualified for the NPNS scope exception, as of March 31, 2024 and December 31, 2023: March 31, 2024 December 31, 2023 Derivative type Notional Volume Unit of Measure Natural gas (a) 5,277 5,335 Million MMBtu Electricity 793,133 800,001 GWh Financial transmission rights (b) 235,014 250,895 GWh Coal 31 35 Million U.S. tons Fuel oil 7 3 Million gallons Emissions 29 24 Million U.S. tons Renewable energy certificates 29 29 Million certificates Interest rate swaps – variable/fixed (c) $ 4,625 $ 5,225 Million U.S. dollars Interest rate swaps – fixed/variable (c) $ 700 $ 1,300 Million U.S. dollars ____________ (a) Represents gross notional forward sales, purchases and options transaction, locational basis swaps and other natural gas transactions. (b) Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within regions. (c) Includes notional amounts of interest rate swaps with maturity dates varying between July 2026 through December 2030. Credit Risk-Related Contingent Features of Derivatives Our derivative contracts may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of these agreements may require the posting of additional collateral if our credit rating is downgraded by one or more credit rating agencies or include cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants. The following table presents the commodity derivative liabilities subject to credit risk-related contingent features that are not fully collateralized: (in millions) March 31, December 31, Fair value of derivative contract liabilities (a) $ (2,115) $ (1,890) Offsetting fair value under netting arrangements (b) 707 692 Cash collateral and letters of credit 985 854 Liquidity exposure $ (423) $ (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 March 31, 2024, total credit risk exposure to all counterparties related to derivative contracts totaled $4.599 billion (including associated accounts receivable). The net exposure to those counterparties totaled $732 million as of March 31, 2024, after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure from any single counterparty totaling $248 million. As of March 31, 2024, the credit risk exposure to the banking and financial sector represented 83% of the total credit risk exposure and 36% of the net exposure.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 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: March 31, 2024 December 31, 2023 (in millions) Level Level Level 3 Reclass (a) Total Level Level Level 3 Reclass (a) Total Assets: Commodity contracts (b) $ 2,827 $ 571 $ 715 $ 40 $ 4,153 $ 2,886 $ 628 $ 630 $ 14 $ 4,158 Interest rate swaps (c) — 107 — — 107 — 64 — — 64 NDTs – equity securities (d) (e) 1,398 — — — 1,398 638 — — 638 NDTs – debt securities (d) (f) 101 1,908 — 2,009 — 734 — 734 Sub-total $ 4,326 $ 2,586 $ 715 $ 40 7,667 $ 3,524 $ 1,426 $ 630 $ 14 5,594 Assets measured at net asset value (g): NDTs – equity securities (d) (e) (g) 728 579 Total assets $ 8,395 $ 6,173 Liabilities: Commodity contracts $ 3,619 $ 1,538 $ 1,864 $ 40 $ 7,061 $ 3,815 $ 1,395 $ 1,674 $ 14 $ 6,898 Interest rate swaps — 45 — — 45 — 48 — — 48 Total liabilities $ 3,619 $ 1,583 $ 1,864 $ 40 $ 7,106 $ 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 on our condensed consolidated balance sheets. (b) Commodity contracts consist primarily of natural gas, electricity, coal and emissions agreements and include financial instruments entered into for economic hedging purposes as well as physical contracts that have not been designated as NPNS. (c) Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest to fixed rates. (d) NDT assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facilities. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT. The NDT investments are included in Investments in the condensed consolidated balance sheets. (e) 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. (f) 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 3.69% and 3.19% as of March 31, 2024 and December 31, 2023, respectively, and an average maturity of 8 years and 11 years as of both March 31, 2024 and December 31, 2023. NDT debt securities held as of March 31, 2024 mature as follows: $1.042 billion in one to five years, $528 million in five to 10 years and $439 million after 10 years. (g) 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 our condensed 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 March 31, 2024 and December 31, 2023: March 31, 2024 Fair Value (in millions) Contract Type (a) Assets Liabilities Total Valuation Technique Significant Unobservable Input Range (b) Average (b) Electricity purchases and sales $ 516 $ (1,523) $ (1,007) Income Approach Hourly price curve shape (c) $— to $95 $47 MWh Illiquid delivery periods for hub power prices and Heat Rates (d) $35 to $105 $72 MWh Options — (253) (253) Option Pricing Model Natural gas to power correlation (e) 10% to 100% 55% Power and natural gas volatility (e) 5% to 870% 439% Financial transmission rights/Congestion revenue rights 173 (33) 140 Market Approach (f) Illiquid price differences between settlement points (g) $(60) to $20 $(19) MWh Natural gas 14 (46) (32) Income Approach Natural gas basis (h) $— to $15 $6 MMBtu Illiquid delivery periods (i) $— to $5 $4 MMBtu Other (j) 12 (9) 3 Total $ 715 $ (1,864) $ (1,149) December 31, 2023 Fair Value (in millions) Contract Type (a) Assets Liabilities Total Valuation Technique Significant Unobservable Input Range (b) Average (b) Electricity purchases and sales $ 449 $ (1,273) $ (824) Income Approach Hourly price curve shape (c) $— to $85 $44 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) (i) Electricity purchase and sales contracts include power and Heat Rate positions in ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO regions, (ii) Options consist of physical electricity options, spread options and natural gas options, (iii) Forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points are referred to as congestion revenue rights (CRRs) in ERCOT and financial transmission rights (FTRs) in PJM, ISO-NE, NYISO and MISO regions, and (iv) Natural gas contracts include swaps and forward contracts. (b) The range of the inputs may be influenced by factors such as time of day, delivery period, season and location. The average represents the arithmetic average of the underlying inputs and is not weighted by the related fair value or notional amount. (c) Primarily based on the historical range of forward average hourly ERCOT North Hub and ERCOT South and West Zone prices. (d) Primarily based on historical forward ERCOT and PJM power prices and ERCOT Heat Rate variability. (e) Primarily based on the historical forward correlation and volatility within ERCOT and PJM. (f) While we use the market approach, there is insufficient market data for the inputs to the valuation to consider the valuation liquid. (g) Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones. (h) Primarily based on the historical forward PJM and Northeast natural gas basis prices and fixed prices. (i) Primarily based on the historical forward natural gas fixed prices. (j) Other includes contracts for coal and environmental allowances. The following table presents the changes in fair value of the Level 3 assets and liabilities. All Level 3 assets and liabilities are commodity contracts, therefore, substantially all changes in fair value detailed below are reported as Operating Revenues in the condensed consolidated statements of operations: Three Months Ended March 31, (in millions) 2024 2023 Net liability balance at beginning of period $ (1,044) $ (1,219) Total unrealized valuation losses (269) (76) Purchases, issuances and settlements (a): Purchases 70 49 Issuances (3) (5) Settlements 99 17 Transfers into Level 3 (b) 3 (14) Transfers out of Level 3 (b) 8 23 Net liabilities assumed in connection with the Energy Harbor Merger (13) — Net change (105) (6) Net liability balance at end of period $ (1,149) $ (1,225) Unrealized valuation losses relating to instruments held at end of period $ (325) $ (159) ____________ (a) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received, including CRRs and FTRs. (b) Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. For the three months ended March 31, 2024, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of coal and natural gas derivatives where forward pricing inputs have become observable. For the three months ended March 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 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.

Tax Receivable Agreement Obliga

Tax Receivable Agreement Obligation	3 Months Ended
	Mar. 31, 2024
Income Tax Disclosure [Abstract]
Tax Receivable Agreement Obligation	TAX RECEIVABLE AGREEMENT OBLIGATION On the Effective Date, Vistra entered into the TRA with a transfer agent on behalf of certain former first-lien creditors of TCEH, whereby we issued TRA rights to these former first-lien creditors of TCEH entitled to receive them under the Plan of Reorganization (TRA Rights). The TRA generally provides for the payment by us to holders of TRA Rights of 85% of the amount of cash savings, if any, in U.S. federal and state income tax that we realize in periods after Emergence as a result of (i) certain transactions consummated pursuant to the Plan of Reorganization (including the step-up in tax basis in our assets resulting from the PrefCo Preferred Stock Sale), (ii) the tax basis of all assets acquired in connection with the acquisition of two CCGT natural gas-fueled generation facilities in April 2016 and (iii) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA, plus interest accruing from the due date of the applicable tax return. Vistra began a series of repurchases of TRA Rights (Repurchase) from certain registered holders of the TRA Rights (Selling Holders) in December 2023. In connection with the Repurchase, holders of approximately 74% of the outstanding TRA Rights consented to certain amendments to the TRA which were effected in an Amended and Restated Tax Receivables Agreement (A&R TRA), dated as of December 29, 2023. Such amendments to the TRA included (i) the removal of the Company's obligation to provide registered holders of the TRA Rights (Holders) with regular reporting and access to information, (ii) limitations on the transferability of the TRA Rights, (iii) removal of certain obligations of the Company in the event it incurs indebtedness and (iv) a change to the definition of "Change of Control." The following table details our repurchases of TRA Rights during the periods indicated: Number of TRA Rights TRA Rights issued on the Effective Date and outstanding as of January 1, 2023 and March 31, 2023 426,369,370 The December 31, 2023 Repurchase (a) (317,387,412) TRA Rights outstanding as of January 1, 2024 108,981,958 The January 11, 2024 Repurchase (b) (43,494,944) The February 13, 2024 Repurchase (c) (55,056,931) The February 28, 2024 Repurchase (c) (2,235,020) TRA Rights outstanding as of March 31, 2024 (d) 8,195,063 ____________ (a) On December 31, 2023, we repurchased TRA Rights in exchange for consideration of $1.50 per TRA Right totaling an aggregate purchase price of $476 million. The consideration for the December 31, 2023 Repurchase was conveyed through the issuance of 476,081 shares of Vistra Series C Preferred Stock to the Selling Holders. (b) On January 11, 2024, we Repurchased TRA Rights in exchange for consideration of $1.50 per TRA Right totaling an aggregate purchase price of $65 million using cash on hand. (c) On January 31, 2024, we announced a cash tender offer to purchase any and all outstanding TRA Rights in exchange for consideration of $1.50 per tendered TRA Right accepted for purchase prior to close of business of February 13, 2024 (Early Tender Date), which included an early tender premium of $0.05 per TRA Right accepted for purchase. On the Early Tender Date the Company Repurchased TRA Rights in exchange for total consideration of $83 million and on February 28, 2024 additional TRA Rights were repurchased under the cash tender offer for total consideration of $3 million or $1.45 per TRA Right accepted for purchase. (d) Represents TRA Rights outstanding following Repurchases of an aggregate of 98% of the TRA Rights initially issued upon Emergence. The following table summarizes the changes to the TRA obligation, reported as other current liabilities and Tax Receivable Agreement obligation in our condensed consolidated balance sheets: Three Months Ended March 31, (in millions) 2024 2023 TRA obligation at the beginning of the period $ 171 $ 522 Accretion expense 6 20 Changes in tax assumptions impacting timing of payments (1) 45 Impacts of Tax Receivable Agreement 5 65 Repurchase/tender of TRA Rights (161) — TRA obligation at the end of the period 15 587 Less amounts due currently — (9) Noncurrent TRA obligation at the end of the period $ 15 $ 578

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2024
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation Disclosure	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. See Note 15 for a discussion of proposed regulations which could result in additional AROs if enacted as proposed and/or if decommissioning timing and cost estimates are revised based on new interpretations of the rules. The following table summarizes the changes to our current and noncurrent ARO liabilities: Three Months Ended March 31, 2024 Three Months Ended March 31, 2023 (in millions) Nuclear Plant Decommissioning Land Reclamation, Coal Ash and Other Total Nuclear Land Reclamation, Coal Ash and Other Total Liability at beginning of period $ 1,742 $ 796 $ 2,538 $ 1,688 $ 749 $ 2,437 Additions: Accretion (a) 23 10 33 13 9 22 Adjustment for change in estimates — 3 3 — 6 6 Adjustment for obligations assumed through acquisition 1,368 — 1,368 — — — Reductions: Payments — (17) (17) — (18) (18) Liability at end of period 3,133 792 3,925 1,701 746 2,447 Less amounts due currently — (119) (119) — (139) (139) Noncurrent liability at end of period $ 3,133 $ 673 $ 3,806 $ 1,701 $ 607 $ 2,308 ____________ (a) For the three months ended March 31, 2024, nuclear plant decommissioning accretion includes $9 million of accretion expense recognized in operating costs in our condensed statements of operations and $14 million reflected as a change in regulatory liability in our condensed consolidated balance sheets. For the three months ended March 31, 2023, nuclear plant decommissioning accretion reflected as a change in regulatory liability in our condensed consolidated balance sheets. 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 March 31, 2024, the carrying value of our ARO related to our Comanche Peak plant decommissioning estimate totaled $1.756 billion, which is lower than the fair value of the assets contained in the Comanche Peak NDT of $2.078 billion. The difference between the carrying value of the ARO and the NDT represents a regulatory liability of $322 million that has been recorded to our condensed consolidated balance sheets in other noncurrent liabilities and deferred credits since any excess funds in the NDT after decommissioning our Comanche Peak plant would be refunded through Oncor's delivery fees. 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 our condensed consolidated statements of operations. ARO estimates for the PJM nuclear facilities will be evaluated on an individual unit basis at least annually 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 on the condensed consolidated balance sheets; however, if the ARO estimate decreases by more than the remaining ARO asset, the balance of the change is recorded as a reduction to operating costs in our condensed consolidated statement of operations.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES Guarantees We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. Material guarantees are discussed below. Letters of Credit As of March 31, 2024, we had outstanding letters of credit totaling $2.995 billion as follows: • $2.634 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; • $186 million to support battery and solar development projects; • $27 million to support executory contracts and insurance agreements; • $95 million to support our REP financial requirements with the PUCT, and • $53 million for other credit support requirements. Surety Bonds As of March 31, 2024, we had outstanding surety bonds totaling $1.5 billion to support performance under various contracts and legal obligations in the normal course of business. Litigation and Regulatory Proceedings Our material legal proceedings and regulatory proceedings affecting our business are described below. We believe that we have valid defenses to the legal proceedings described below and intend to defend them vigorously. We also intend to participate in the regulatory processes described below. We record reserves for estimated losses related to these matters when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable, we have established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as incurred. Management has assessed each of the following legal matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, we are unable to predict the outcome of these matters or reasonably estimate the scope or amount of any associated costs and potential liabilities, but they could have a material impact on our results of operations, liquidity, or financial condition. As additional information becomes available, we adjust our assessment and estimates of such contingencies accordingly. Because litigation and rulemaking proceedings are subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of these matters could be at amounts that are different from our currently recorded reserves and that such differences could be material. Litigation Natural Gas Index Pricing Litigation — We, through our subsidiaries, and another company remain named as defendants in one consolidated putative class action lawsuit pending in federal court in Wisconsin claiming damages resulting from alleged price manipulation through false reporting of natural gas prices to various index publications, wash trading and churn trading from 2000-2002. The plaintiffs in these cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices during the relevant time period and seek damages under the respective state antitrust statutes. In April 2023, the U.S. Court of Appeals for the Seventh Circuit (Seventh Circuit Court) heard oral argument on an interlocutory appeal challenging the district court's order certifying a class. Illinois Attorney General Complaint Against Illinois Gas & Electric (IG&E) — In May 2022, the Illinois Attorney General filed a complaint against IG&E, a subsidiary we acquired when we purchased Crius Energy Trust in July 2019. The complaint filed in Illinois state court alleges, among other things, that IG&E engaged in improper marketing conduct and overcharged customers. The vast majority of the conduct in question occurred prior to our acquisition of IG&E. In July 2022, we moved to dismiss the complaint, and in October 2022, the district court granted in part our motion to dismiss, barring all claims asserted by the Illinois Attorney General that were outside of the 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 Repricing Challenges — In March 2021, we filed an appeal in the Third Court of Appeals in Austin, Texas (Third Court of Appeals), challenging the PUCT's February 15 and February 16, 2021 orders governing ERCOT's determination of wholesale power prices during load-shedding events. Other parties also supported our challenge to the PUCT's orders. In March 2023, the Third Court of Appeals issued a unanimous decision and agreed with our arguments that the PUCT's pricing orders constituted de facto competition rules and exceeded the PUCT's statutory authority. The Third Court of Appeals vacated the pricing orders and remanded the matter to the PUCT for further proceedings. In March 2023, the PUCT appealed the Third Court of Appeals' ruling to the Texas Supreme Court. In September 2023, the Texas Supreme Court granted the PUC and its intervenors petitions for review of the Third Court of Appeals' decision and the Court heard oral argument in January 2024. In addition, we have also submitted settlement disputes with ERCOT over power prices and other issues during Winter Storm Uri. Following an appeal of the PUCT's March 5, 2021 verbal order and other statements made by the PUCT, the Texas Attorney General, on behalf of the PUCT, its client, represented in a letter agreement filed with the Third Court of Appeals that we and other parties may continue disputing the pricing during Winter Storm Uri through the ERCOT process and, to the extent the outcome of that process comes before the PUCT for review, the PUCT has not prejudged or made a final decision on that matter. We are not able to reasonably estimate the financial statement impact of a repricing as, among other things, the matter is subject to ongoing legal proceedings and, even if we were ultimately successful in the current legal proceeding, the price at which the market would be resettled is not reasonably estimable because that would be subject to further proceedings at ERCOT and the PUCT. Regulatory Investigations and Other Litigation Matters — Following the events of Winter Storm Uri, various regulatory bodies, including ERCOT, the ERCOT Independent Market Monitor, the Texas Attorney General, the FERC and the NRC initiated investigations or issued requests for information of various parties related to the significant load shed event that occurred during the event as well as operational challenges for generators arising from the event, including performance and fuel and supply issues. 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. We believe we have strong defenses to these lawsuits and intend to defend against these cases vigorously. Greenhouse Gas Emissions (GHG) In July 2019, the EPA finalized a rule that repealed the Clean Power Plan (CPP) that had been finalized in 2015 and established new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the Affordable Clean Energy (ACE) rule. The ACE rule developed emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generation units. In response to challenges brought by environmental groups and certain states, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the ACE rule, including the repeal of the CPP, in January 2021 and remanded the rule to the EPA for further action. In June 2022, the U.S. Supreme Court issued an opinion reversing the D.C. Circuit Court's decision, and finding that the EPA exceeded its authority under Section 111 of the Clean Air Act when the EPA set emission requirements in the CPP based on generation shifting. In October 2022, the D.C. Circuit Court issued an amended judgment, denying petitions for review of the ACE rule and challenges to the repeal of the CPP. In May 2023, the EPA released a new proposal regulating power plant GHG emissions, while also proposing to repeal the ACE rule. In April 2024, the EPA released 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. In May 2024, a group of 27 states filed petitions challenging the final rule in the D.C. Circuit Court. Cross-State Air Pollution Rule (CSAPR) 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. The FIP applies 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 FIP as to Texas sources pending the resolution of the merits, meaning that Texas will remain in Group 2 and not be subject to any requirements under the FIP at least until the Fifth Circuit Court rules on the merits. Oral argument was heard in December 2023 before the Fifth Circuit Court. In June 2023, the EPA published the final FIP in the Federal Register, which included requirements as to Texas despite the stay of the SIP disapproval by the Fifth Circuit Court. In June 2023, the State of Texas, Luminant and various other parties also filed challenges to the FIP in the Fifth Circuit Court, filed a motion to stay the FIP and confirm venue for this dispute in the Fifth Circuit Court. After the motion to stay and to confirm venue was filed, the EPA signed an interim final rule on June 29, 2023 that confirms the FIP as to Texas is stayed. In July 2023, the Fifth Circuit Court ruled that the FIP challenge would be held in abeyance pending the resolution of the litigation on the SIP disapproval and denied the motion to stay as not needed given the EPA's administrative stay. 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 reduces 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. We anticipate the EPA will likely move forward with either proposing a federal plan for the area in light of an approved consent decree, between the Sierra Club and the EPA that requires the EPA taking final action promulgating a FIP for the nonattainment area by December 13, 2024, or the EPA may approve Texas' SIP submittal discussed above. In February 2024, we filed a petition asking the full Fifth Circuit Court to review the panel decision issued in January 2024. Particulate Matter 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. At this time, we are still determining what impact, if any, this rule will have on our existing plants or any plants we may build in the future. Based on 2020-2022 design value associated with the rule, we have just five plants (Oakland (California), Calumet (Illinois), Liberty (Pennsylvania), Miami Fort (Ohio) and Lake Hubbard (Texas)) operating in areas where the air quality monitoring data are currently exceeding the new PM2.5 standard. 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. On April 25, 2024, the EPA issued the final ELG rule revisions, which contains new requirements for legacy wastewater and combustion residual leachate. The final rule also leaves in place the subcategory for facility 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. Coal Combustion Residuals (CCR)/Groundwater 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 final rule allows a generation plant to seek the EPA's approval to extend this deadline if no alternative disposal capacity is available and either a conversion to comply with the CCR rule is underway or retirement will occur by either 2023 or 2028 (depending on the size of the impoundment at issue). Prior to the November 2020 deadline, we submitted applications to the EPA requesting compliance extensions under both conversion and retirement scenarios. In 2022 and 2023, we withdrew the applications for Coffeen, Martin Lake, Joppa and Zimmer stations because extensions were no longer needed. In November 2020, environmental groups petitioned for review of this rule in the D.C. Circuit Court, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020. Also, in November 2020, the EPA finalized a rule that would allow an alternative liner demonstration for certain qualifying facilities. In November 2020, we submitted an application for an alternate liner demonstration for one CCR unit at Martin Lake, however, we withdrew the application for an alternate liner demonstration in November 2023 after determining the pond was no longer needed for CCR. In August 2021, we submitted a request to transfer our conversion application for the Zimmer facility to a retirement application following the announcement that Zimmer will close by May 31, 2022. In January 2022, the EPA determined that our conversion and retirement applications for our CCR facilities were complete but has not yet proposed action on any of those applications. In addition, in January 2022, the EPA also made a series of public statements, including in a press release, that purported to impose new, more onerous closure requirements for CCR units. The EPA issued these new purported requirements without prior notice and without following the legal requirements for adopting new rules. These new purported requirements announced by the EPA are contrary to existing regulations and the EPA's prior positions. In April 2022, we, along with the Utility Solid Waste Activities Group (USWAG), a trade association of over 130 utility operating companies, energy companies, and certain other industry associations, filed petitions for review with the D.C. Circuit Court and have asked the court to determine that the EPA cannot implement or enforce the new purported requirements because the EPA has not followed the required procedures. The State of Texas and the TCEQ have intervened in support of the petitions filed by the Vistra subsidiaries and USWAG, and various environmental groups have intervened on behalf of the EPA. The D.C. Circuit Court heard argument in March 2024. In April 2024, the EPA issued 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 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. 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 order which the court subsequently entered. Given the violation notices and the enforcement action, the unique characteristics of the site, and the proximity of the site to the only national scenic river in Illinois, we agreed to enter into the interim consent order to resolve this matter. Per the terms of the agreed interim consent order, DMG is required to evaluate the closure alternatives und

Equity

Equity	3 Months Ended
	Mar. 31, 2024
Equity [Abstract]
Equity	EQUITY Share Repurchase Program In October 2021, we announced that the Board authorized a share repurchase program (Share Repurchase Program) under which up to $2.0 billion of our outstanding shares of common stock may be repurchased. The Share Repurchase Program became effective on October 11, 2021. In August 2022, March 2023 and February 2024, the Board authorized incremental amounts of $1.25 billion, $1.0 billion and $1.5 billion, respectively, for repurchases to bring the total authorized under the Share Repurchase Program to $5.75 billion. In the three months ended March 31, 2024, 6,138,773 shares of our common stock were repurchased for approximately $284 million at an average price of $46.21 per share of common stock. Shares repurchased include 72,839 of unsettled shares for $5 million as of March 31, 2024. In the three months ended March 31, 2023, 13,308,465 shares of our common stock were repurchased for approximately $308 million at an average price of $23.11 per share of common stock. As of March 31, 2024, approximately $1.966 billion was available for additional repurchases under the Share Repurchase Program. Under the Share Repurchase Program, shares of the Company's common stock may be repurchased in open-market transactions at prevailing market prices, in privately negotiated transactions, pursuant to plans complying with the Exchange Act, or by other means in accordance with federal securities laws. The actual timing, number and value of shares repurchased under the Share Repurchase Program or otherwise will be determined at our discretion and will depend on a number of factors, including our capital allocation priorities, the market price of our stock, general market and economic conditions, applicable legal requirements and compliance with the terms of our debt agreements and the certificates of designation of the Series A Preferred Stock, the Series B Preferred Stock, and the Series C Preferred Stock, respectively. Preferred Stock The Series A Preferred Stock, the Series B Preferred Stock, and the Series C Preferred Stock are not convertible into or exchangeable for any other securities of the Company and have limited voting rights. The Series A Preferred Stock may be redeemed at the option of the Company at any time after the Series A First Reset Date (defined below) and in certain other circumstances prior to the Series A First Reset Date. The Series B Preferred Stock may be redeemed at the option of the Company at any time after the Series B First Reset Date (defined below) and in certain other circumstances prior to the Series B First Reset Date. The Series C Preferred Stock may be redeemed at the option of the Company at any time after the Series C First Reset Date (defined below) and in certain other circumstances prior to the Series C First Reset Date. Dividends Common Stock Dividends In February 2024, the Board declared a quarterly dividend of $0.2150 per share that was paid in March 2024. In February 2023, the Board declared a quarterly dividend of $0.1975 per share that was paid in March 2023. Preferred Stock Dividends The annual dividend rate on each share of Series A Preferred Stock is 8.0% from the Series A Issuance Date to, but excluding October 15, 2026 (Series A First Reset Date). On and after the Series A First Reset Date, the dividend rate on each share of Series A Preferred Stock shall equal the five-year U.S. Treasury rate as of the most recent reset dividend determination date (subject to a floor of 1.07%), plus a spread of 6.93% per annum. The Series A Preferred Stock has a liquidation preference of $1,000 per share, plus accumulated but unpaid dividends. Cumulative cash dividends on the Series A Preferred Stock are payable semiannually, in arrears, on each April 15 and October 15, commencing on April 15, 2022, when, as and if declared by the Board. The annual dividend rate on each share of Series B Preferred Stock is 7.0% from the Series B Issuance Date to, but excluding December 15, 2026 (Series B First Reset Date). On and after the Series B First Reset Date, the dividend rate on each share of Series B Preferred Stock shall equal the five-year U.S. Treasury rate as of the most recent reset dividend determination date (subject to a floor of 1.26%), plus a spread of 5.74% per annum. The Series B Preferred Stock has a liquidation preference of $1,000 per share, plus accumulated but unpaid dividends. Cumulative cash dividends on the Series B Preferred Stock are payable semiannually, in arrears, on each June 15 and December 15, commencing on June 15, 2022, when, as and if declared by the Board. The annual dividend rate on each share of Series C Preferred Stock is 8.875% from the Series C Issuance Date to, but excluding January 15, 2029 (Series C First Reset Date). On and after the Series C First Reset Date, the dividend rate on each share of Series C Preferred Stock shall equal the five-year U.S. Treasury rate as of the most recent reset dividend determination date (subject to a floor of 3.83%), plus a spread of 5.045% per annum. The Series C Preferred Stock has a liquidation preference of $1,000 per share, plus accumulated but unpaid dividends. Cumulative cash dividends on the Series C Preferred Stock are payable semiannually, in arrears, on each July 15 and January 15, commencing on July 15, 2024, when, as and if declared by the Board. Dividend Restrictions The Vistra Operations Credit Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of March 31, 2024, Vistra Operations can distribute approximately $6.6 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 $490 million and $350 million for the three months ended March 31, 2024 and 2023, respectively. Additionally, Vistra Operations may make distributions to Parent in amounts sufficient for Parent to make any payments required under the TRA or the Tax Matters Agreement or, to the extent arising out of Parent's ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses. As of March 31, 2024, certain of the restricted net assets of Vistra Operations may be distributed to Parent. In addition to the restrictions under the Vistra Operations Credit Agreement, under applicable Delaware law, we are only permitted to make distributions either out of "surplus," which is defined as the excess of our net assets above our capital (the aggregate par value of all outstanding shares of our stock), or out of net profits for the fiscal year in which the distribution is declared or the prior fiscal year. Under the terms of the Series A Preferred Stock, the Series B Preferred Stock, and the Series C Preferred Stock, unless full cumulative dividends have been or contemporaneously are being paid or declared and a sum sufficient for the payment thereof set apart for payment on all outstanding Series A Preferred Stock (and any parity securities), Series B Preferred Stock (and any parity securities), and Series C Preferred Stock (and any parity securities), respectively, with respect to dividends through the most recent dividend payment dates, (i) no dividend may be declared or paid or set apart for payment on any junior security (other than a dividend payable solely in junior securities with respect to both dividends and the liquidation, winding-up and dissolution of our affairs), including our common stock, and (ii) we may not redeem, purchase or otherwise acquire any parity security or junior security, including our common stock, in each case subject to certain exceptions as described in the certificate of designation of the Series A Preferred Stock, the Series B Preferred Stock, and the Series C Preferred Stock, respectively.

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 2024
Segment Reporting [Abstract]
Segment Information	SEGMENT INFORMATION The operations of Vistra are aligned into six reportable business segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. Our Chief Executive Officer is our Chief Operating Decision Maker (CODM). Our CODM reviews the results of these segments separately and allocates resources to the respective segments as part of our strategic operations. A measure of assets is not applicable, as segment assets are not regularly reviewed by the CODM for evaluating performance or allocating resources. The 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 19 states in the U.S. The Texas and East segments are engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel production and fuel logistics management. The Texas segment represents results from Vistra's electricity generation operations in the ERCOT market, other than assets that are now part of the Sunset or Asset Closure segments. The East segment represents results from Vistra's electricity generation operations in the Eastern Interconnection of the U.S. electric grid, other than assets that are now part of the Sunset or Asset Closure segments, and includes operations in the PJM, ISO-NE and NYISO markets. We determined it was appropriate to aggregate results from these markets into one reportable segment, East, given similar economic characteristics. The West segment represents results from the CAISO market, including our battery ESS projects at our Moss Landing power plant site. The Sunset segment consists of generation plants with announced retirement dates after December 31, 2024. Separately reporting the Sunset segment differentiates operating plants with announced retirement plans from our other operating plants in the Texas, East and West segments. We have allocated unrealized gains and losses on the commodity risk management activities to the Sunset segment for the generation plants that have announced retirement dates after December 31, 2024. The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines (see Note 3). Upon movement of generation plant assets to either the Sunset or Asset Closure segments, prior year results are retrospectively adjusted, if the effects are material, for comparative purposes. 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 related to our support functions that provide shared services 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 of our 2023 Form 10-K, as well as those disclosed in Note 1 of this quarterly report on Form 10-Q. 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. 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. Three Months Ended (in millions) Retail Texas East West Sunset Asset Closure Corporate and Other (a) Eliminations Consolidated Operating revenues: March 31, 2024 $ 2,494 $ 439 $ 637 $ 285 $ 239 $ — $ — $ (1,040) $ 3,054 March 31, 2023 2,350 1,353 1,809 231 828 — — (2,146) 4,425 Depreciation and amortization: March 31, 2024 $ (23) $ (132) $ (192) $ (21) $ (20) $ — $ (15) $ — $ (403) March 31, 2023 (29) (130) (161) (15) (14) — (17) — (366) Operating income (loss): March 31, 2024 $ 568 $ (343) $ (223) $ 163 $ 8 $ (22) $ (65) $ — $ 86 March 31, 2023 (588) 569 744 47 425 (29) (37) — 1,131 Net income (loss): March 31, 2024 $ 561 $ (331) $ (185) $ 164 $ 7 $ (21) $ (177) $ — $ 18 March 31, 2023 (595) 584 745 52 424 (27) (485) — 698 Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures: March 31, 2024 $ — $ 268 $ 39 $ 4 $ 6 $ — $ 11 $ — $ 328 March 31, 2023 1 102 23 2 15 — 14 — 157 _____________ (a) Income tax (expense) benefit is generally not reflected in net income (loss) of the segments but is reflected almost entirely in Corporate and Other net income (loss).

Supplementary Financial Informa

Supplementary Financial Information	3 Months Ended
	Mar. 31, 2024
Supplementary Financial Information [Abstract]
Supplementary Financial Information	SUPPLEMENTARY FINANCIAL INFORMATION 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 Sunset segment and includes write-downs of property, plant and equipment of $45 million, write-downs of inventory of $2 million and write-downs of operating lease right-of-use assets of $2 million. In determining the fair value of the impaired asset group, we utilized the income approach described in ASC 820, Fair Value Measurement . Interest Expense and Related Charges Three Months Ended March 31, (in millions) 2024 2023 Interest expense $ 208 $ 156 Unrealized mark-to-market net (gains) losses on interest rate swaps (47) 41 Amortization of debt issuance costs, discounts and premiums 7 6 Facility Fee expense 4 — Debt extinguishment gain (6) — Capitalized interest (12) (10) Other 16 14 Total interest expense and related charges $ 170 $ 207 The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 11, was 5.56% and 4.70% as of March 31, 2024 and 2023. Other Income and Deductions Three Months Ended March 31, (in millions) 2024 2023 Other income: NDT net income (a) $ 35 $ — Insurance settlements (b) 1 1 Gain on sale of land 1 — Gain on TRA repurchases (c) 10 — Interest income 23 14 All other 21 5 Total other income $ 91 $ 20 Other deductions: All other $ 4 $ 3 Total other deductions $ 4 $ 3 ____________ (a) Includes interest, dividends, and net realized and unrealized gains and losses associated with the NDTs of the PJM nuclear facilities. Reported in the East segment. (b) Reported in the West segment. (c) Reported in Corporate and Other. Restricted Cash March 31, 2024 December 31, 2023 (in millions) Current Assets Noncurrent Assets Current Assets Noncurrent Assets Amounts related to remediation escrow accounts $ 32 $ 14 $ 40 $ 14 Total restricted cash $ 32 $ 14 $ 40 $ 14 Trade Accounts Receivable (in millions) March 31, December 31, Wholesale and retail trade accounts receivable $ 1,790 $ 1,735 Allowance for uncollectible accounts (61) (61) Trade accounts receivable — net $ 1,729 $ 1,674 Trade accounts receivable from contracts with customers — net $ 1,313 $ 1,239 Other trade accounts receivable — net 416 435 Trade accounts receivable — net $ 1,729 $ 1,674 Gross trade accounts receivable as of March 31, 2024 and December 31, 2023 include unbilled retail revenues of $618 million and $614 million, respectively. Allowance for Uncollectible Accounts Receivable Three Months Ended March 31, (in millions) 2024 2023 Allowance for uncollectible accounts receivable at beginning of period $ 61 $ 65 Increase for bad debt expense 36 35 Decrease for account write-offs (36) (47) Allowance for uncollectible accounts receivable at end of period $ 61 $ 53 Inventories by Major Category (in millions) March 31, December 31, Materials and supplies $ 507 $ 289 Fuel stock 443 420 Natural gas in storage 26 31 Total inventories $ 976 $ 740 Investments (in millions) March 31, December 31, Nuclear decommissioning trusts (Note 14) $ 4,135 $ 1,951 Assets related to employee benefit plans 29 28 Land investments 42 42 Other investments 13 14 Total investments $ 4,219 $ 2,035 Property, Plant and Equipment (in millions) March 31, December 31, Power generation and structures $ 22,160 $ 17,297 Land 605 572 Office and other equipment 161 159 Total 22,926 18,028 Less accumulated depreciation (6,962) (6,657) Net of accumulated depreciation 15,964 11,371 Finance lease right-of-use assets (net of accumulated depreciation) 165 160 Nuclear fuel (net of accumulated amortization of $169 million and $120 million) 1,151 379 Construction work in progress 734 522 Property, plant and equipment — net $ 18,014 $ 12,432 Depreciation expenses totaled $367 million and $323 million for three months ended March 31, 2024 and 2023, respectively. Other Noncurrent Liabilities and Deferred Credits The balance of other noncurrent liabilities and deferred credits consists of the following: (in millions) March 31, December 31, Retirement and other employee benefits $ 243 $ 247 Winter Storm Uri impact (a) 25 26 Identifiable intangible liabilities (Note 7) 183 131 Regulatory liability (b) 322 209 Finance lease liabilities 231 227 Liability for third-party remediation 17 17 Accrued severance costs 36 36 Other accrued expenses 39 58 Total other noncurrent liabilities and deferred credits $ 1,096 $ 951 ____________ (a) Includes future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri. (b) As of March 31, 2024 and December 31, 2023, 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 $322 million and $209 million, respectively, in other noncurrent liabilities and deferred credits. Fair Value of Debt (in millions) March 31, 2024 December 31, 2023 Long-term debt (see Note 10): Fair Value Hierarchy Carrying Amount Fair Carrying Amount Fair Long-term debt under the Vistra Operations Credit Facilities Level 2 $ 2,451 $ 2,491 $ 2,456 $ 2,500 Vistra Zero Term Loan B Facility Level 2 688 700 — — Vistra Operations Senior Notes Level 2 11,130 11,022 11,881 11,752 Energy Harbor Secured Notes Level 2 413 427 — — Equipment Financing Agreements Level 3 65 63 65 62 We determine fair value in accordance with accounting standards as discussed in Note 12. 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. Supplemental Cash Flow Information The following table reconciles cash, cash equivalents and restricted cash reported in our condensed consolidated statements of cash flows to the amounts reported in our condensed consolidated balance sheets as of March 31, 2024 and December 31, 2023: (in millions) March 31, December 31, Cash and cash equivalents $ 1,070 $ 3,485 Restricted cash included in current assets 32 40 Restricted cash included in noncurrent assets 14 14 Total cash, cash equivalents and restricted cash $ 1,116 $ 3,539 The following table summarizes our supplemental cash flow information for the three months ended March 31, 2024 and 2023. See Note 2 for other non cash investing and financing activity. Three Months Ended March 31, (in millions) 2024 2023 Cash payments related to: Interest paid $ 214 $ 212 Capitalized interest (12) (10) Interest paid (net of capitalized interest) $ 202 $ 202 For the three months ended March 31, 2024 and 2023, we paid state income taxes of $3 million and $1 million respectively, and received state tax refunds of $1 million and $7 million, respectively.

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Pay vs Performance Disclosure
Net income (loss) attributable to Vistra	$ (35)	$ 699

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Mar. 31, 2024
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Business, Basis of Presentati_2

Business, Basis of Presentation and Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2024
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The condensed consolidated financial statements have been prepared in accordance with U.S. GAAP and on the same basis as the audited financial statements included in our 2023 Form 10-K. The condensed consolidated financial information herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal nature. All intercompany items and transactions have been eliminated in consolidation. 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 condensed 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. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with U.S. GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by U.S. GAAP, they should be read in conjunction with the audited financial statements and related notes contained in our 2023 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. dollars unless otherwise indicated.
Business Combinations	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.
Nuclear Decommissioning Trusts (NDTs)	Nuclear Decommissioning Trusts (NDTs) 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. Income and expense, including gains and losses associated with the NDT assets and the related decommissioning liability are offset by a corresponding change in a regulatory asset/liability (currently a regulatory liability reported in other noncurrent liabilities and deferred credits) that will ultimately be settled through changes in Oncor's delivery fees rates. 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 condensed 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.
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.
Adoption of Accounting Standards	Adoption of Accounting Standards 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 will adopt the amendments in this ASU for its fiscal year ended December 31, 2024 and interim periods within its fiscal year ended December 31, 2025. The amendment will be applied retrospectively to all prior periods presented. We are currently evaluating the impact this ASU will have on our consolidated financial statements and related disclosures. Improvements to Income Tax Disclosures In December 2023, the FASB issued ASU No. 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 our consolidated financial statements. Recent Developments See Note 8 for information on the Receivables Program amendment increasing the purchase limit and Note 10 for information on the $1.5 billion principal amount of senior secured and unsecured senior notes issued in April 2024.

Merger and Business Combination

Merger and Business Combination Accounting (Tables)	3 Months Ended
	Mar. 31, 2024
Business Combination and Asset Acquisition [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: (in millions) Consideration 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. (in Millions) Fair Value as of March 1, 2024 Cash and cash equivalents $ 30 Trade accounts receivables, inventories, prepaid expenses and other current assets 538 Investments (a) 2,021 Property, plant and equipment (b) 5,620 Identifiable intangible assets (c) 428 Commodity and other derivative contractual assets (d) 140 Other noncurrent assets 8 Total identifiable assets acquired 8,785 Trade accounts payable and other current liabilities 263 Long-term debt, including amounts due currently 413 Commodity and other derivative contractual liabilities (d) 179 Accumulated deferred income taxes 1,364 Asset retirement obligations (e) 1,368 Identifiable intangible liabilities 73 Other noncurrent liabilities and deferred credits 12 Total identifiable liabilities assumed 3,672 Identifiable net assets acquired 5,113 Goodwill (f) 294 Net assets acquired $ 5,407 ____________ (a) NDT assets 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 12 (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 by Vistra Vision from combining operations of Energy Harbor with the contributed net assets of Vistra. None of the Goodwill is deductible for income tax purposes.
Schedule of Business Acquisitions, Pro Forma Information	The following unaudited pro forma financial information for the three months ended March 31, 2024 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. Three Months Ended March 31, (in millions) 2024 2023 Revenues $ 3,777 $ 4,891 Net income $ 69 $ 466

Retirement of Generation Faci_2

Retirement of Generation Facilities (Tables)	3 Months Ended
	Mar. 31, 2024
Retirement of Generation Facilities [Abstract]
Summary of Planned Retirements of Generation Capacity	Operational results for plants with defined retirement dates are included in our Sunset segment beginning in the quarter when a retirement plan is announced and move to the Asset Closure segment at the beginning of the calendar year the retirement is expected to occur. Facility Location ISO/RTO Fuel Type Net Generation Capacity (MW) Actual or Expected Retirement Date (a)(b) Segment Baldwin Baldwin, IL MISO Coal 1,185 By the end of 2025 Sunset Coleto Creek Goliad, TX ERCOT Coal 650 By the end of 2027 Sunset Kincaid Kincaid, IL PJM Coal 1,108 By the end of 2027 Sunset Miami Fort North Bend, OH PJM Coal 1,020 By the end of 2027 Sunset Newton Newton, IL MISO/PJM Coal 615 By the end of 2027 Sunset Edwards Bartonville, IL MISO Coal 585 Retired January 1, 2023 Asset Closure Joppa Joppa, IL MISO Coal 802 Retired September 1, 2022 Asset Closure Joppa Joppa, IL MISO Natural Gas 221 Retired September 1, 2022 Asset Closure Zimmer Moscow, OH PJM Coal 1,300 Retired June 1, 2022 Asset Closure Total 7,486 ____________ (a) Generation facilities may retire earlier than expected dates disclosed if economic or other conditions dictate. (b) Retirement dates represent the first full day in which a plant does not operate.

Revenue (Tables)

Revenue (Tables)	3 Months Ended
	Mar. 31, 2024
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	Disaggregated revenue from contracts with customers, and other revenue included in total revenues in the condensed consolidated statements of operations is as follows: Three Months Ended March 31, 2024 (in millions) Retail (a) Texas East (a) West Sunset Asset Eliminations Consolidated Revenue from contracts with customers: Retail energy charge in ERCOT $ 1,702 $ — $ — $ — $ — $ — $ — $ 1,702 Retail energy charge in Northeast/Midwest 663 — — — — — — 663 Wholesale generation revenue from ISO/RTO — 60 261 88 80 — — 489 Capacity revenue from ISO/RTO (b) — — 15 — 4 — — 19 Revenue from other wholesale contracts — 104 70 57 55 — — 286 Total revenue from contracts with customers 2,365 164 346 145 139 — — 3,159 Other revenues: Intangible amortization — — — — (1) — — (1) Transferable PTC revenues — 2 — — — — — 2 Hedging and other revenues (c) 123 (274) (138) 139 44 — — (106) Affiliate sales (d) 6 547 429 1 57 — (1,040) — Total other revenues 129 275 291 140 100 — (1,040) (105) Total revenues $ 2,494 $ 439 $ 637 $ 285 $ 239 $ — $ (1,040) $ 3,054 ____________ (a) Includes revenues associated with March 2024 operations acquired in the Energy Harbor Merger. (b) Represents net capacity sold in each ISO/RTO. The East segment includes $36 million of capacity sold offset by $21 million of capacity purchased. The Sunset segment includes $4 million of capacity sold. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs and delivery fees in our condensed consolidated statement of operations includes capacity purchased of $7 million offset by $2 million of capacity sold within the East segment. (c) Includes $347 million of unrealized net losses from mark-to-market valuations of commodity positions. Three Months Ended Retail Texas East West Sunset Asset Closure Corporate and Other Eliminations (1) Consolidated March 31, 2024 $ (155) $ (602) $ (355) $ 136 $ (156) $ 4 $ — $ 781 $ (347) ___________________ (1) Amounts attributable to generation segments offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results. (d) Texas, East and Sunset segment includes $470 million, $255 million and $56 million, respectively, of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment. Three Months Ended March 31, 2023 (in millions) Retail Texas East West Sunset Asset Eliminations Consolidated Revenue from contracts with customers: Retail energy charge in ERCOT $ 1,568 $ — $ — $ — $ — $ — $ — $ 1,568 Retail energy charge in Northeast/Midwest 427 — — — — — — 427 Wholesale generation revenue from ISO/RTO — 50 220 193 67 — — 530 Capacity revenue from ISO/RTO (a) — — 8 — 19 — — 27 Revenue from other wholesale contracts — 107 331 41 76 — — 555 Total revenue from contracts with customers 1,995 157 559 234 162 — — 3,107 Other revenues: Intangible amortization (1) — (1) — (1) — — (3) Transferable PTC revenue — 2 — — — — — 2 Hedging and other revenues (b) 356 112 386 (7) 472 — — 1,319 Affiliate sales (c) — 1,082 865 4 195 — (2,146) — Total other revenues 355 1,196 1,250 (3) 666 — (2,146) 1,318 Total revenues $ 2,350 $ 1,353 $ 1,809 $ 231 $ 828 $ — $ (2,146) $ 4,425 ____________ (a) Represents net capacity sold in each ISO/RTO. The East segment includes $42 million of capacity sold offset by $34 million of capacity purchased. The Sunset segment includes $46 million of capacity sold offset by $27 million of capacity purchased. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs and delivery fees in our condensed consolidated statement of operations includes capacity purchased of $31 million offset by $21 million of capacity sold within the East segment. (b) Includes $1.277 billion of unrealized net gains from mark-to-market valuations of commodity positions. Three Months Ended Retail Texas East West Sunset Asset Closure Corporate and Other Eliminations (1) Consolidated March 31, 2023 $ 140 $ 368 $ 943 $ 12 $ 477 $ 17 $ — $ (680) $ 1,277 ___________________ (1) Amounts attributable to generation segments offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results. (c) Texas, East and Sunset segments include $185 million, $394 million and $103 million, respectively, of affiliated unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction	As of March 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 will be recognized assuming the performance obligations are met and as capacity is made available to the related ISOs/RTOs or counterparties. Balance of 2024 2025 2026 2027 2028 2029 and Thereafter Total Remaining performance obligations $ 401 $ 463 $ 329 $ 272 $ 122 $ 610 $ 2,197

Income Taxes (Tables)

Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2024
Income Tax Disclosure [Abstract]
Schedule of Effective Income Tax Rate Reconciliation	The components of our income tax (expense) benefit are as follows: Three Months Ended March 31, (in millions) 2024 2023 Net income (loss) before income taxes $ (2) $ 876 Income tax (expense) benefit $ 20 $ (178) Effective tax rate 1,000.0 % 20.3 %

Earnings Per Share (Tables)

Earnings Per Share (Tables)	3 Months Ended
	Mar. 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. Three Months Ended March 31, (in millions, except share data) 2024 2023 Net income (loss) attributable to Vistra $ (35) $ 699 Less cumulative dividends attributable to Series A Preferred Stock (20) (20) Less cumulative dividends attributable to Series B Preferred Stock (18) (18) Less cumulative dividends attributable to Series C Preferred Stock (11) — Net income (loss) attributable to common stock — basic and diluted $ (84) $ 661 Weighted average shares of common stock outstanding: Basic 348,966,197 383,631,369 Dilutive securities: Stock-based incentive compensation plan — 3,922,010 Diluted 348,966,197 387,553,379 Net income (loss) per weighted average share of common stock outstanding: Basic $ (0.24) $ 1.72 Diluted $ (0.24) $ 1.71

Goodwill and Identifiable Int_2

Goodwill and Identifiable Intangible Assets and Liabilities (Tables)	3 Months Ended
	Mar. 31, 2024
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	As of March 31, 2024 and December 31, 2023, the carrying value of goodwill totaled $2.877 billion and $2.583 billion, respectively. Retail Segment Texas Segment (in millions) Retail Reporting Unit (a) Texas Generation Reporting Unit Total Goodwill Balance at December 31, 2023 $ 2,461 $ 122 $ 2,583 Goodwill recorded in connection with the Energy Harbor Merger (b) 294 Balance at March 31, 2024 $ 2,461 $ 122 $ 2,877 ____________ (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 Identifiable Intangible Assets	Identifiable intangible assets are comprised of the following: March 31, 2024 December 31, 2023 Identifiable Intangible Asset (in millions) Gross Carrying Amount Accumulated Net Gross Carrying Amount Accumulated Net Retail customer relationships $ 2,170 $ 1,888 $ 282 $ 2,088 $ 1,866 $ 222 Software and other technology-related assets 545 249 296 536 315 221 Retail and wholesale contracts 503 218 285 233 217 16 LTSA 18 5 13 18 5 13 Other identifiable intangible assets (a) 73 12 61 62 11 51 Total identifiable intangible assets subject to amortization $ 3,309 $ 2,372 937 $ 2,937 $ 2,414 523 Retail trade names (not subject to amortization) 1,341 1,341 Total identifiable intangible assets $ 2,278 $ 1,864 ____________ (a) Includes environmental allowances (emissions allowances and renewable energy certificates) and mining development costs.
Schedule of Identifiable Intangible Liabilities	Identifiable intangible liabilities are comprised of the following: Identifiable Intangible Liability (in millions) March 31, December 31, 2023 LTSA $ 121 $ 122 Power and fuel purchase contracts 62 9 Total identifiable intangible liabilities $ 183 $ 131
Schedule of Amortization Expense Related to Intangible Assets and Liabilities	Expense related to finite-lived identifiable intangible assets (including the classification in the condensed consolidated statements of operations) consist of: Identifiable Intangible Assets (in millions) Condensed Consolidated Statements of Operations Three Months Ended March 31, 2024 2023 Retail customer relationships Depreciation and amortization $ 22 $ 28 Software and other technology-related assets Depreciation and amortization 13 15 Retail and wholesale contracts Operating revenues/fuel, purchased power costs and delivery fees 1 2 Other identifiable intangible assets Fuel, purchased power costs and delivery fees 103 86 Total identifiable intangible assets expense (a) $ 139 $ 131 ___________ (a) Amounts exclude LTSA. Amounts include all expenses associated with environmental allowances including expenses accrued to comply with emissions allowance programs and renewable portfolio standards which are presented in fuel, purchased power costs and delivery fees on our condensed consolidated statements of operations. Emissions allowance obligations are accrued as associated electricity is generated and renewable energy certificate obligations are accrued as retail electricity delivery occurs.
Schedule of Estimated Amortization Expense of Identifiable Intangible Assets and Liabilities	As of March 31, 2024, the estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as shown below. Year Estimated Amortization Expense 2024 $ 167 2025 $ 141 2026 $ 77 2027 $ 49 2028 $ 32

Debt (Tables)

Debt (Tables)	3 Months Ended
	Mar. 31, 2024
Debt Disclosure [Abstract]
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. (in millions) March 31, December 31, Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030 $ 2,494 $ 2,500 Vistra Zero Credit Facility, Term Loan B Facility due April 30, 2031 700 — Vistra Operations Senior Secured Notes: 4.875% Senior Secured Notes, due May 13, 2024 342 400 3.550% Senior Secured Notes, due July 15, 2024 1,155 1,500 5.125% Senior Secured Notes, due May 13, 2025 744 1,100 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 Total Vistra Operations Senior Secured Notes 4,891 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 Total Vistra Operations Senior Unsecured Notes 6,300 6,300 Other: Equipment Financing Agreements 67 67 Total other long-term debt 67 67 Unamortized debt premiums, discounts and issuance costs (136) (115) Total long-term debt including amounts due currently 14,747 14,402 Less amounts due currently (a) (54) (2,286) Total long-term debt less amounts due currently $ 14,693 $ 12,116 ____________ (a) Excludes 4.875% Senior Secured Notes due May 2024 and 3.550% Senior Secured Notes due July 2024 as amounts will be refinanced on a long-term basis using net proceeds from the 6.000% Senior Secured Notes due 2034 and 6.875% Senior Unsecured Notes due 2032 (defined below) issued in April 2024.
Schedule of Maturities of Long-Term Debt	Long-term debt maturities as of March 31, 2024 are as follows: (in millions) March 31, 2024 Remainder of 2024 $ 1,532 2025 786 2026 1,038 2027 3,434 2028 35 Thereafter 8,058 Unamortized premiums, discounts and debt issuance costs (136) Total long-term debt, including amounts due currently $ 14,747
Schedule of Line of Credit Facilities	Our credit facilities and related available capacity as of March 31, 2024 are presented below. (in millions) March 31, 2024 Credit Facilities Maturity Date Facility Cash Borrowings (Short-Term) Cash Borrowings (Long-Term) Letters of Credit Outstanding Available Revolving Credit Facility April 29, 2027 $ 3,175 $ — $ — $ 1,882 $ 1,293 Term Loan B-3 Facility December 20, 2030 2,494 — 2,494 — — Total Vistra Operations Credit Facilities $ 5,669 $ — $ 2,494 $ 1,882 $ 1,293 Vistra Operations Commodity-Linked Facility October 2, 2024 1,575 500 — — 637 Vistra Zero Term Loan B Facility April 30, 2031 700 — 700 — — Total credit facilities $ 7,944 $ 500 $ 3,194 $ 1,882 $ 1,930

Commodity and Other Derivativ_2

Commodity and Other Derivative Contractual Assets and Liabilities (Tables)	3 Months Ended
	Mar. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Interest Rate Derivatives	As of March 31, 2024, Vistra has entered into the following interest rate swaps: (in millions, except percentages) Notional Amount Expiration Date Rate Range (c) Swapped to fixed (a) $3,000 July 2026 4.89 % - 4.97% Swapped to variable (a) $700 July 2026 3.44 % - 3.49% Swapped to fixed (b) $1,625 December 2030 5.20 % - 5.37% ____________ (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 2.00%.
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of derivative contractual assets and liabilities as reported in our condensed consolidated balance sheets as of March 31, 2024 and December 31, 2023. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract. March 31, 2024 (in millions) Derivative Assets Derivative Liabilities Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total Current assets $ 3,479 $ 59 $ 19 $ — $ 3,557 Noncurrent assets 653 48 2 — 703 Current liabilities (14) — (5,176) (24) (5,214) Noncurrent liabilities (5) — (1,866) (21) (1,892) Net assets (liabilities) $ 4,113 $ 107 $ (7,021) $ (45) $ (2,846) December 31, 2023 Derivative Assets Derivative Liabilities (in millions) Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total Current assets $ 3,585 $ 53 $ 7 $ — $ 3,645 Noncurrent assets 565 11 1 — 577 Current liabilities (1) — (5,233) (24) (5,258) Noncurrent liabilities (5) — (1,659) (24) (1,688) Net assets (liabilities) $ 4,144 $ 64 $ (6,884) $ (48) $ (2,724)
Schedule of Pretax Effect on Net Income of Derivatives Not Under Hedge Accounting, Including Realized and Unrealized Effects	The following table presents the pre-tax effect of derivative gains (losses) on net income, including both the realized and unrealized effects. Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts. Derivative (condensed consolidated statements of operations presentation) (in millions) Three Months Ended March 31, 2024 2023 Commodity contracts (Operating revenues) $ (608) $ 669 Commodity contracts (Fuel, purchased power costs and delivery fees) 45 (295) Interest rate swaps (Interest expense and related charges) 58 (28) Net gain (loss) $ (505) $ 346
Offsetting Assets and Liabilities	The following tables reconcile our derivative assets and liabilities on a contract basis to net amounts after taking into consideration netting arrangements with counterparties and financial collateral: March 31, 2024 December 31, 2023 (in millions) Derivative Assets Offsetting Instruments (a) Cash Collateral (Received) Pledged (b) Net Amounts Derivative Assets Offsetting Instruments (a) Cash Collateral (Received) Pledged (b) Net Amounts Derivative assets: Commodity contracts $ 4,113 $ (3,392) $ (84) $ 637 $ 4,144 $ (3,519) $ (26) $ 599 Interest rate swaps 107 (35) — 72 64 (28) — 36 Total derivative assets 4,220 (3,427) (84) 709 4,208 (3,547) (26) 635 Derivative liabilities: Commodity contracts (7,021) 3,392 914 (2,715) (6,884) 3,519 970 (2,395) Interest rate swaps (45) 35 — (10) (48) 28 — (20) Total derivative liabilities (7,066) 3,427 914 (2,725) (6,932) 3,547 970 (2,415) Net amounts $ (2,846) $ — $ 830 $ (2,016) $ (2,724) $ — $ 944 $ (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 Notional Amounts of Outstanding Derivative Positions	The following table presents the gross notional amounts of derivative volumes, by commodity, excluding those derivatives that qualified for the NPNS scope exception, as of March 31, 2024 and December 31, 2023: March 31, 2024 December 31, 2023 Derivative type Notional Volume Unit of Measure Natural gas (a) 5,277 5,335 Million MMBtu Electricity 793,133 800,001 GWh Financial transmission rights (b) 235,014 250,895 GWh Coal 31 35 Million U.S. tons Fuel oil 7 3 Million gallons Emissions 29 24 Million U.S. tons Renewable energy certificates 29 29 Million certificates Interest rate swaps – variable/fixed (c) $ 4,625 $ 5,225 Million U.S. dollars Interest rate swaps – fixed/variable (c) $ 700 $ 1,300 Million U.S. dollars ____________ (a) Represents gross notional forward sales, purchases and options transaction, locational basis swaps and other natural gas transactions. (b) Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within regions. (c) Includes notional amounts of interest rate swaps with maturity dates varying between July 2026 through December 2030.
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: (in millions) March 31, December 31, Fair value of derivative contract liabilities (a) $ (2,115) $ (1,890) Offsetting fair value under netting arrangements (b) 707 692 Cash collateral and letters of credit 985 854 Liquidity exposure $ (423) $ (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)	3 Months Ended
	Mar. 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: March 31, 2024 December 31, 2023 (in millions) Level Level Level 3 Reclass (a) Total Level Level Level 3 Reclass (a) Total Assets: Commodity contracts (b) $ 2,827 $ 571 $ 715 $ 40 $ 4,153 $ 2,886 $ 628 $ 630 $ 14 $ 4,158 Interest rate swaps (c) — 107 — — 107 — 64 — — 64 NDTs – equity securities (d) (e) 1,398 — — — 1,398 638 — — 638 NDTs – debt securities (d) (f) 101 1,908 — 2,009 — 734 — 734 Sub-total $ 4,326 $ 2,586 $ 715 $ 40 7,667 $ 3,524 $ 1,426 $ 630 $ 14 5,594 Assets measured at net asset value (g): NDTs – equity securities (d) (e) (g) 728 579 Total assets $ 8,395 $ 6,173 Liabilities: Commodity contracts $ 3,619 $ 1,538 $ 1,864 $ 40 $ 7,061 $ 3,815 $ 1,395 $ 1,674 $ 14 $ 6,898 Interest rate swaps — 45 — — 45 — 48 — — 48 Total liabilities $ 3,619 $ 1,583 $ 1,864 $ 40 $ 7,106 $ 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 on our condensed consolidated balance sheets. (b) Commodity contracts consist primarily of natural gas, electricity, coal and emissions agreements and include financial instruments entered into for economic hedging purposes as well as physical contracts that have not been designated as NPNS. (c) Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest to fixed rates. (d) NDT assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facilities. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT. The NDT investments are included in Investments in the condensed consolidated balance sheets. (e) 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. (f) 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 3.69% and 3.19% as of March 31, 2024 and December 31, 2023, respectively, and an average maturity of 8 years and 11 years as of both March 31, 2024 and December 31, 2023. NDT debt securities held as of March 31, 2024 mature as follows: $1.042 billion in one to five years, $528 million in five to 10 years and $439 million after 10 years. (g) 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 our condensed consolidated balance sheets.
Schedule of Fair Value of the Level 3 Assets and Liabilities by Major Contract Type and the Significant Unobservable Inputs Used in the Valuations	The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations as of March 31, 2024 and December 31, 2023: March 31, 2024 Fair Value (in millions) Contract Type (a) Assets Liabilities Total Valuation Technique Significant Unobservable Input Range (b) Average (b) Electricity purchases and sales $ 516 $ (1,523) $ (1,007) Income Approach Hourly price curve shape (c) $— to $95 $47 MWh Illiquid delivery periods for hub power prices and Heat Rates (d) $35 to $105 $72 MWh Options — (253) (253) Option Pricing Model Natural gas to power correlation (e) 10% to 100% 55% Power and natural gas volatility (e) 5% to 870% 439% Financial transmission rights/Congestion revenue rights 173 (33) 140 Market Approach (f) Illiquid price differences between settlement points (g) $(60) to $20 $(19) MWh Natural gas 14 (46) (32) Income Approach Natural gas basis (h) $— to $15 $6 MMBtu Illiquid delivery periods (i) $— to $5 $4 MMBtu Other (j) 12 (9) 3 Total $ 715 $ (1,864) $ (1,149) December 31, 2023 Fair Value (in millions) Contract Type (a) Assets Liabilities Total Valuation Technique Significant Unobservable Input Range (b) Average (b) Electricity purchases and sales $ 449 $ (1,273) $ (824) Income Approach Hourly price curve shape (c) $— to $85 $44 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) (i) Electricity purchase and sales contracts include power and Heat Rate positions in ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO regions, (ii) Options consist of physical electricity options, spread options and natural gas options, (iii) Forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points are referred to as congestion revenue rights (CRRs) in ERCOT and financial transmission rights (FTRs) in PJM, ISO-NE, NYISO and MISO regions, and (iv) Natural gas contracts include swaps and forward contracts. (b) The range of the inputs may be influenced by factors such as time of day, delivery period, season and location. The average represents the arithmetic average of the underlying inputs and is not weighted by the related fair value or notional amount. (c) Primarily based on the historical range of forward average hourly ERCOT North Hub and ERCOT South and West Zone prices. (d) Primarily based on historical forward ERCOT and PJM power prices and ERCOT Heat Rate variability. (e) Primarily based on the historical forward correlation and volatility within ERCOT and PJM. (f) While we use the market approach, there is insufficient market data for the inputs to the valuation to consider the valuation liquid. (g) Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones. (h) Primarily based on the historical forward PJM and Northeast natural gas basis prices and fixed prices. (i) Primarily based on the historical forward natural gas fixed prices. (j) Other includes contracts for coal and environmental allowances.
Schedule of Changes in Fair Value of the Level 3 Assets and Liabilities	The following table presents the changes in fair value of the Level 3 assets and liabilities. All Level 3 assets and liabilities are commodity contracts, therefore, substantially all changes in fair value detailed below are reported as Operating Revenues in the condensed consolidated statements of operations: Three Months Ended March 31, (in millions) 2024 2023 Net liability balance at beginning of period $ (1,044) $ (1,219) Total unrealized valuation losses (269) (76) Purchases, issuances and settlements (a): Purchases 70 49 Issuances (3) (5) Settlements 99 17 Transfers into Level 3 (b) 3 (14) Transfers out of Level 3 (b) 8 23 Net liabilities assumed in connection with the Energy Harbor Merger (13) — Net change (105) (6) Net liability balance at end of period $ (1,149) $ (1,225) Unrealized valuation losses relating to instruments held at end of period $ (325) $ (159) ____________ (a) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received, including CRRs and FTRs. (b) Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. For the three months ended March 31, 2024, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of coal and natural gas derivatives where forward pricing inputs have become observable. For the three months ended March 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 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.

Tax Receivable Agreement Obli_2

Tax Receivable Agreement Obligation (Tables)	3 Months Ended
	Mar. 31, 2024
Income Tax Disclosure [Abstract]
Tax Receivable Agreement Obligations Rights Repurchased	The following table details our repurchases of TRA Rights during the periods indicated: Number of TRA Rights TRA Rights issued on the Effective Date and outstanding as of January 1, 2023 and March 31, 2023 426,369,370 The December 31, 2023 Repurchase (a) (317,387,412) TRA Rights outstanding as of January 1, 2024 108,981,958 The January 11, 2024 Repurchase (b) (43,494,944) The February 13, 2024 Repurchase (c) (55,056,931) The February 28, 2024 Repurchase (c) (2,235,020) TRA Rights outstanding as of March 31, 2024 (d) 8,195,063 ____________ (a) On December 31, 2023, we repurchased TRA Rights in exchange for consideration of $1.50 per TRA Right totaling an aggregate purchase price of $476 million. The consideration for the December 31, 2023 Repurchase was conveyed through the issuance of 476,081 shares of Vistra Series C Preferred Stock to the Selling Holders. (b) On January 11, 2024, we Repurchased TRA Rights in exchange for consideration of $1.50 per TRA Right totaling an aggregate purchase price of $65 million using cash on hand. (c) On January 31, 2024, we announced a cash tender offer to purchase any and all outstanding TRA Rights in exchange for consideration of $1.50 per tendered TRA Right accepted for purchase prior to close of business of February 13, 2024 (Early Tender Date), which included an early tender premium of $0.05 per TRA Right accepted for purchase. On the Early Tender Date the Company Repurchased TRA Rights in exchange for total consideration of $83 million and on February 28, 2024 additional TRA Rights were repurchased under the cash tender offer for total consideration of $3 million or $1.45 per TRA Right accepted for purchase. (d) Represents TRA Rights outstanding following Repurchases of an aggregate of 98% of the TRA Rights initially issued upon Emergence.
Schedule of Tax Receivable Agreement Obligation	The following table summarizes the changes to the TRA obligation, reported as other current liabilities and Tax Receivable Agreement obligation in our condensed consolidated balance sheets: Three Months Ended March 31, (in millions) 2024 2023 TRA obligation at the beginning of the period $ 171 $ 522 Accretion expense 6 20 Changes in tax assumptions impacting timing of payments (1) 45 Impacts of Tax Receivable Agreement 5 65 Repurchase/tender of TRA Rights (161) — TRA obligation at the end of the period 15 587 Less amounts due currently — (9) Noncurrent TRA obligation at the end of the period $ 15 $ 578

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 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: Three Months Ended March 31, 2024 Three Months Ended March 31, 2023 (in millions) Nuclear Plant Decommissioning Land Reclamation, Coal Ash and Other Total Nuclear Land Reclamation, Coal Ash and Other Total Liability at beginning of period $ 1,742 $ 796 $ 2,538 $ 1,688 $ 749 $ 2,437 Additions: Accretion (a) 23 10 33 13 9 22 Adjustment for change in estimates — 3 3 — 6 6 Adjustment for obligations assumed through acquisition 1,368 — 1,368 — — — Reductions: Payments — (17) (17) — (18) (18) Liability at end of period 3,133 792 3,925 1,701 746 2,447 Less amounts due currently — (119) (119) — (139) (139) Noncurrent liability at end of period $ 3,133 $ 673 $ 3,806 $ 1,701 $ 607 $ 2,308 ____________ (a) For the three months ended March 31, 2024, nuclear plant decommissioning accretion includes $9 million of accretion expense recognized in operating costs in our condensed statements of operations and $14 million reflected as a change in regulatory liability in our condensed consolidated balance sheets. For the three months ended March 31, 2023, nuclear plant decommissioning accretion reflected as a change in regulatory liability in our condensed consolidated balance sheets.

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2024
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Three Months Ended (in millions) Retail Texas East West Sunset Asset Closure Corporate and Other (a) Eliminations Consolidated Operating revenues: March 31, 2024 $ 2,494 $ 439 $ 637 $ 285 $ 239 $ — $ — $ (1,040) $ 3,054 March 31, 2023 2,350 1,353 1,809 231 828 — — (2,146) 4,425 Depreciation and amortization: March 31, 2024 $ (23) $ (132) $ (192) $ (21) $ (20) $ — $ (15) $ — $ (403) March 31, 2023 (29) (130) (161) (15) (14) — (17) — (366) Operating income (loss): March 31, 2024 $ 568 $ (343) $ (223) $ 163 $ 8 $ (22) $ (65) $ — $ 86 March 31, 2023 (588) 569 744 47 425 (29) (37) — 1,131 Net income (loss): March 31, 2024 $ 561 $ (331) $ (185) $ 164 $ 7 $ (21) $ (177) $ — $ 18 March 31, 2023 (595) 584 745 52 424 (27) (485) — 698 Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures: March 31, 2024 $ — $ 268 $ 39 $ 4 $ 6 $ — $ 11 $ — $ 328 March 31, 2023 1 102 23 2 15 — 14 — 157 _____________ (a) Income tax (expense) benefit is generally not reflected in net income (loss) of the segments but is reflected almost entirely in Corporate and Other net income (loss).

Supplementary Financial Infor_2

Supplementary Financial Information (Tables)	3 Months Ended
	Mar. 31, 2024
Supplementary Financial Information [Abstract]
Schedule of Interest Expense and Related Charges	Interest Expense and Related Charges Three Months Ended March 31, (in millions) 2024 2023 Interest expense $ 208 $ 156 Unrealized mark-to-market net (gains) losses on interest rate swaps (47) 41 Amortization of debt issuance costs, discounts and premiums 7 6 Facility Fee expense 4 — Debt extinguishment gain (6) — Capitalized interest (12) (10) Other 16 14 Total interest expense and related charges $ 170 $ 207
Schedule of Other Income and Deductions	Other Income and Deductions Three Months Ended March 31, (in millions) 2024 2023 Other income: NDT net income (a) $ 35 $ — Insurance settlements (b) 1 1 Gain on sale of land 1 — Gain on TRA repurchases (c) 10 — Interest income 23 14 All other 21 5 Total other income $ 91 $ 20 Other deductions: All other $ 4 $ 3 Total other deductions $ 4 $ 3 ____________ (a) Includes interest, dividends, and net realized and unrealized gains and losses associated with the NDTs of the PJM nuclear facilities. Reported in the East segment. (b) Reported in the West segment. (c) Reported in Corporate and Other.
Schedule of Restricted Cash	Restricted Cash March 31, 2024 December 31, 2023 (in millions) Current Assets Noncurrent Assets Current Assets Noncurrent Assets Amounts related to remediation escrow accounts $ 32 $ 14 $ 40 $ 14 Total restricted cash $ 32 $ 14 $ 40 $ 14
Schedule of Accounts, Notes, Loans and Financing Receivable	Trade Accounts Receivable (in millions) March 31, December 31, Wholesale and retail trade accounts receivable $ 1,790 $ 1,735 Allowance for uncollectible accounts (61) (61) Trade accounts receivable — net $ 1,729 $ 1,674 Trade accounts receivable from contracts with customers — net $ 1,313 $ 1,239 Other trade accounts receivable — net 416 435 Trade accounts receivable — net $ 1,729 $ 1,674 Allowance for Uncollectible Accounts Receivable Three Months Ended March 31, (in millions) 2024 2023 Allowance for uncollectible accounts receivable at beginning of period $ 61 $ 65 Increase for bad debt expense 36 35 Decrease for account write-offs (36) (47) Allowance for uncollectible accounts receivable at end of period $ 61 $ 53
Schedule of Inventories by Major Category	Inventories by Major Category (in millions) March 31, December 31, Materials and supplies $ 507 $ 289 Fuel stock 443 420 Natural gas in storage 26 31 Total inventories $ 976 $ 740
Schedule of Investments	Investments (in millions) March 31, December 31, Nuclear decommissioning trusts (Note 14) $ 4,135 $ 1,951 Assets related to employee benefit plans 29 28 Land investments 42 42 Other investments 13 14 Total investments $ 4,219 $ 2,035
Schedule of Property, Plant and Equipment	Property, Plant and Equipment (in millions) March 31, December 31, Power generation and structures $ 22,160 $ 17,297 Land 605 572 Office and other equipment 161 159 Total 22,926 18,028 Less accumulated depreciation (6,962) (6,657) Net of accumulated depreciation 15,964 11,371 Finance lease right-of-use assets (net of accumulated depreciation) 165 160 Nuclear fuel (net of accumulated amortization of $169 million and $120 million) 1,151 379 Construction work in progress 734 522 Property, plant and equipment — net $ 18,014 $ 12,432
Schedule of Other Noncurrent Liabilities and Deferred Credits	Other Noncurrent Liabilities and Deferred Credits The balance of other noncurrent liabilities and deferred credits consists of the following: (in millions) March 31, December 31, Retirement and other employee benefits $ 243 $ 247 Winter Storm Uri impact (a) 25 26 Identifiable intangible liabilities (Note 7) 183 131 Regulatory liability (b) 322 209 Finance lease liabilities 231 227 Liability for third-party remediation 17 17 Accrued severance costs 36 36 Other accrued expenses 39 58 Total other noncurrent liabilities and deferred credits $ 1,096 $ 951 ____________ (a) Includes future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri. (b) As of March 31, 2024 and December 31, 2023, 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 $322 million and $209 million, respectively, in other noncurrent liabilities and deferred credits.
Schedule of Fair Value of Debt	Fair Value of Debt (in millions) March 31, 2024 December 31, 2023 Long-term debt (see Note 10): Fair Value Hierarchy Carrying Amount Fair Carrying Amount Fair Long-term debt under the Vistra Operations Credit Facilities Level 2 $ 2,451 $ 2,491 $ 2,456 $ 2,500 Vistra Zero Term Loan B Facility Level 2 688 700 — — Vistra Operations Senior Notes Level 2 11,130 11,022 11,881 11,752 Energy Harbor Secured Notes Level 2 413 427 — — Equipment Financing Agreements Level 3 65 63 65 62
Schedule of Cash, Cash Equivalents and Restricted Cash	The following table reconciles cash, cash equivalents and restricted cash reported in our condensed consolidated statements of cash flows to the amounts reported in our condensed consolidated balance sheets as of March 31, 2024 and December 31, 2023: (in millions) March 31, December 31, Cash and cash equivalents $ 1,070 $ 3,485 Restricted cash included in current assets 32 40 Restricted cash included in noncurrent assets 14 14 Total cash, cash equivalents and restricted cash $ 1,116 $ 3,539
Schedule of Supplemental Cash Flow Information	The following table summarizes our supplemental cash flow information for the three months ended March 31, 2024 and 2023. See Note 2 for other non cash investing and financing activity. Three Months Ended March 31, (in millions) 2024 2023 Cash payments related to: Interest paid $ 214 $ 212 Capitalized interest (12) (10) Interest paid (net of capitalized interest) $ 202 $ 202

Business, Basis of Presentati_3

Business, Basis of Presentation and Significant Accounting Policies - Narrative (Details) $ in Billions	3 Months Ended
	Mar. 31, 2024 reportableSegment	Apr. 30, 2024 USD ($)
Debt Instrument [Line Items]
Number of reportable segments | reportableSegment	6
Senior Loans | Subsequent Event
Debt Instrument [Line Items]
Debt instrument, face amount | $		$ 1.5

Business Combinations - Narrati

Business Combinations - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Mar. 01, 2024
Energy Harbor
Business Acquisition [Line Items]
Fair value of noncontrolling interest in Energy Harbor			$ 811
Business combination, acquisition related costs	$ 24	$ 6
Vistra Vision
Business Acquisition [Line Items]
Fair value of noncontrolling interest in Energy Harbor	$ 749
Vistra Vision | Energy Harbor
Business Acquisition [Line Items]
Subsidiary, ownership percentage, noncontrolling owner			15%
Subsidiary, ownership percentage, parent			85%

Business Combinations - Purchas

Business Combinations - Purchase Price (Details) - USD ($) $ in Millions	Mar. 01, 2024	Mar. 31, 2024
Vistra Vision
Business Acquisition [Line Items]
Fair value of noncontrolling interest in Energy Harbor		$ 749
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
Net assets acquired	$ 5,407
Energy Harbor | Vistra Vision
Business Acquisition [Line Items]
Subsidiary, ownership percentage, noncontrolling owner	15%

Business Combinations - Schedul

Business Combinations - Schedule of Business Acquisitions, by Acquisition (Details) - USD ($) $ in Millions	Mar. 31, 2024	Mar. 01, 2024	Dec. 31, 2023
Business Acquisition [Line Items]
Goodwill	$ 2,877		$ 2,583
Business combination, contractual cash flow projections, duration		5 years
Energy Harbor
Business Acquisition [Line Items]
Cash and cash equivalents		$ 30
Trade accounts receivables, inventories, prepaid expenses and other current assets		538
Investments		2,021
Property, plant and equipment		5,620
Identifiable intangible assets		428
Commodity and other derivative contractual assets		140
Other noncurrent assets		8
Total identifiable assets acquired		8,785
Trade accounts payable and other current liabilities		263
Long-term debt, including amounts due currently		413
Commodity and other derivative contractual liabilities		179
Accumulated deferred income taxes		1,364
Asset retirement obligations		1,368
Identifiable intangible liabilities		73
Other noncurrent liabilities and deferred credits		12
Total identifiable liabilities assumed		3,672
Identifiable net assets acquired		5,113
Goodwill		294
Net assets acquired		$ 5,407

Business Combinations - Sched_2

Business Combinations - Schedule of Business Acquisitions, Pro Forma Information (Details) - Energy Harbor - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Business Acquisition [Line Items]
Revenues	$ 3,777,000	$ 4,891,000
Net income	$ 69,000	$ 466,000

Retirement of Generation Faci_3

Retirement of Generation Facilities - Summary of Planned Retirements of Generation Capacity (Details)	Mar. 31, 2024 MW
Retirement of Generation Facilities [Line Items]
Net Generation Capacity (MW)	7,486
Baldwin | Sunset
Retirement of Generation Facilities [Line Items]
Net Generation Capacity (MW)	1,185
Coleto Creek | Sunset
Retirement of Generation Facilities [Line Items]
Net Generation Capacity (MW)	650
Kincaid | Sunset
Retirement of Generation Facilities [Line Items]
Net Generation Capacity (MW)	1,108
Miami Fort | Sunset
Retirement of Generation Facilities [Line Items]
Net Generation Capacity (MW)	1,020
Newton | Sunset
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

Revenue - Disaggregation of Rev

Revenue - Disaggregation of Revenue (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 3,159	$ 3,107
Total revenues	3,054	4,425
Unrealized gain (loss) on commodity related derivatives	(176)	1,085
Commodity contracts (Operating revenues)
Disaggregation of Revenue [Line Items]
Unrealized gain (loss) on derivatives	(347)	1,277
Unrealized gain (loss) on commodity related derivatives		1,277
Retail energy charge in ERCOT
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,702	1,568
Retail energy charge in Northeast/Midwest
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	663	427
Wholesale generation revenue from ISO/RTO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	489	530
Capacity revenue from ISO/RTO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	19	27
Capacity revenue from ISO/RTO | East
Disaggregation of Revenue [Line Items]
Net capacity sold	2	21
Net capacity purchased	7	31
Revenue from other wholesale contracts
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	286	555
Intangible amortization
Disaggregation of Revenue [Line Items]
Total revenues	(1)	(3)
Transferable PTC revenues
Disaggregation of Revenue [Line Items]
Total revenues	2	2
Hedging and Other Revenues
Disaggregation of Revenue [Line Items]
Total revenues	(106)	1,319
Affiliate sales
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Total other revenues
Disaggregation of Revenue [Line Items]
Total revenues	(105)	1,318
Operating Segments | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2,365	1,995
Total revenues	2,494	2,350
Operating Segments | Retail | Commodity contracts (Operating revenues)
Disaggregation of Revenue [Line Items]
Unrealized gain (loss) on commodity related derivatives	(155)	140
Operating Segments | Texas
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	164	157
Total revenues	439	1,353
Operating Segments | Texas | Commodity contracts (Operating revenues)
Disaggregation of Revenue [Line Items]
Unrealized gain (loss) on commodity related derivatives	(602)	368
Unrealized gain (loss) on derivatives affiliated	(470)	185
Operating Segments | East
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	346	559
Total revenues	637	1,809
Operating Segments | East | Commodity contracts (Operating revenues)
Disaggregation of Revenue [Line Items]
Unrealized gain (loss) on commodity related derivatives	(355)	943
Unrealized gain (loss) on derivatives affiliated	(255)	394
Operating Segments | West
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	145	234
Total revenues	285	231
Operating Segments | West | Commodity contracts (Operating revenues)
Disaggregation of Revenue [Line Items]
Unrealized gain (loss) on commodity related derivatives	136	12
Operating Segments | Sunset
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	139	162
Total revenues	239	828
Operating Segments | Sunset | Commodity contracts (Operating revenues)
Disaggregation of Revenue [Line Items]
Unrealized gain (loss) on commodity related derivatives	(156)	477
Unrealized gain (loss) on derivatives affiliated	(56)	103
Operating Segments | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Total revenues	0	0
Operating Segments | Asset Closure | Commodity contracts (Operating revenues)
Disaggregation of Revenue [Line Items]
Unrealized gain (loss) on commodity related derivatives	4	17
Operating Segments | Retail energy charge in ERCOT | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,702	1,568
Operating Segments | Retail energy charge in ERCOT | Texas
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Retail energy charge in ERCOT | East
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Retail energy charge in ERCOT | West
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Retail energy charge in ERCOT | Sunset
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Retail energy charge in ERCOT | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Retail energy charge in Northeast/Midwest | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	663	427
Operating Segments | Retail energy charge in Northeast/Midwest | Texas
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Retail energy charge in Northeast/Midwest | East
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Retail energy charge in Northeast/Midwest | West
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Retail energy charge in Northeast/Midwest | Sunset
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Retail energy charge in Northeast/Midwest | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Wholesale generation revenue from ISO/RTO | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Wholesale generation revenue from ISO/RTO | Texas
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	60	50
Operating Segments | Wholesale generation revenue from ISO/RTO | East
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	261	220
Operating Segments | Wholesale generation revenue from ISO/RTO | West
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	88	193
Operating Segments | Wholesale generation revenue from ISO/RTO | Sunset
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	80	67
Operating Segments | Wholesale generation revenue from ISO/RTO | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Capacity revenue from ISO/RTO | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Capacity revenue from ISO/RTO | Texas
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Capacity revenue from ISO/RTO | East
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	15	8
Net capacity sold	36	42
Net capacity purchased	21	34
Operating Segments | Capacity revenue from ISO/RTO | West
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Capacity revenue from ISO/RTO | Sunset
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	4	19
Net capacity sold	4	46
Net capacity purchased		27
Operating Segments | Capacity revenue from ISO/RTO | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Revenue from other wholesale contracts | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Revenue from other wholesale contracts | Texas
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	104	107
Operating Segments | Revenue from other wholesale contracts | East
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	70	331
Operating Segments | Revenue from other wholesale contracts | West
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	57	41
Operating Segments | Revenue from other wholesale contracts | Sunset
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	55	76
Operating Segments | Revenue from other wholesale contracts | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Operating Segments | Intangible amortization | Retail
Disaggregation of Revenue [Line Items]
Total revenues	0	(1)
Operating Segments | Intangible amortization | Texas
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Intangible amortization | East
Disaggregation of Revenue [Line Items]
Total revenues	0	(1)
Operating Segments | Intangible amortization | West
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Intangible amortization | Sunset
Disaggregation of Revenue [Line Items]
Total revenues	(1)	(1)
Operating Segments | Intangible amortization | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Transferable PTC revenues | Retail
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Transferable PTC revenues | Texas
Disaggregation of Revenue [Line Items]
Total revenues	2	2
Operating Segments | Transferable PTC revenues | East
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Transferable PTC revenues | West
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Transferable PTC revenues | Sunset
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Transferable PTC revenues | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Hedging and Other Revenues | Retail
Disaggregation of Revenue [Line Items]
Total revenues	123	356
Operating Segments | Hedging and Other Revenues | Texas
Disaggregation of Revenue [Line Items]
Total revenues	(274)	112
Operating Segments | Hedging and Other Revenues | East
Disaggregation of Revenue [Line Items]
Total revenues	(138)	386
Operating Segments | Hedging and Other Revenues | West
Disaggregation of Revenue [Line Items]
Total revenues	139	(7)
Operating Segments | Hedging and Other Revenues | Sunset
Disaggregation of Revenue [Line Items]
Total revenues	44	472
Operating Segments | Hedging and Other Revenues | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Affiliate sales | Retail
Disaggregation of Revenue [Line Items]
Total revenues	6	0
Operating Segments | Affiliate sales | Texas
Disaggregation of Revenue [Line Items]
Total revenues	547	1,082
Operating Segments | Affiliate sales | East
Disaggregation of Revenue [Line Items]
Total revenues	429	865
Operating Segments | Affiliate sales | West
Disaggregation of Revenue [Line Items]
Total revenues	1	4
Operating Segments | Affiliate sales | Sunset
Disaggregation of Revenue [Line Items]
Total revenues	57	195
Operating Segments | Affiliate sales | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Operating Segments | Total other revenues | Retail
Disaggregation of Revenue [Line Items]
Total revenues	129	355
Operating Segments | Total other revenues | Texas
Disaggregation of Revenue [Line Items]
Total revenues	275	1,196
Operating Segments | Total other revenues | East
Disaggregation of Revenue [Line Items]
Total revenues	291	1,250
Operating Segments | Total other revenues | West
Disaggregation of Revenue [Line Items]
Total revenues	140	(3)
Operating Segments | Total other revenues | Sunset
Disaggregation of Revenue [Line Items]
Total revenues	100	666
Operating Segments | Total other revenues | Asset Closure
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Eliminations
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Total revenues	(1,040)	(2,146)
Eliminations | Retail energy charge in ERCOT
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Eliminations | Retail energy charge in Northeast/Midwest
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Eliminations | Wholesale generation revenue from ISO/RTO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Eliminations | Capacity revenue from ISO/RTO
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Eliminations | Revenue from other wholesale contracts
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	0	0
Eliminations | Intangible amortization
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Eliminations | Transferable PTC revenues
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Eliminations | Hedging and Other Revenues
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Eliminations | Affiliate sales
Disaggregation of Revenue [Line Items]
Total revenues	(1,040)	(2,146)
Eliminations | Total other revenues
Disaggregation of Revenue [Line Items]
Total revenues	(1,040)	(2,146)
Corporate and Other
Disaggregation of Revenue [Line Items]
Total revenues	0	0
Corporate and Other | Commodity contracts (Operating revenues)
Disaggregation of Revenue [Line Items]
Unrealized gain (loss) on commodity related derivatives	0	0
Eliminations
Disaggregation of Revenue [Line Items]
Total revenues	(1,040)	(2,146)
Unrealized gain (loss) on commodity related derivatives	(347)
Eliminations | Commodity contracts (Operating revenues)
Disaggregation of Revenue [Line Items]
Unrealized gain (loss) on commodity related derivatives	$ 781	$ (680)

Revenue - Revenue, Remaining Pe

Revenue - Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction (Details) $ in Millions	Mar. 31, 2024 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	$ 2,197
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	$ 401
Revenue, remaining performance obligation, expected timing of satisfaction, period	9 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	$ 463
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]
Revenue, remaining performance obligation, amount	$ 329
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	$ 272
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	$ 122
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligation, amount	$ 610
Revenue, remaining performance obligation, expected timing of satisfaction, period	1 year

Income Taxes - Schedule of Effe

Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Net income (loss) before income taxes	$ (2)	$ 876
Income tax (expense) benefit	$ 20	$ (178)
Effective tax rate	1,000%	20.30%

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) $ in Millions	3 Months Ended
	Mar. 31, 2024 USD ($) MW	Mar. 31, 2023	Dec. 31, 2023 USD ($)
Income Tax Contingency [Line Items]
Effective tax rate	1,000%	20.30%
Effective tax rate at federal statutory rate	21%	21%
Unrecognized tax benefits	$ 0		$ 0
Moss Landing Power Plant (Battery Storage Project) | Moss Landing Battery Energy Storage System Phase III | West | Vistra Corp.
Income Tax Contingency [Line Items]
Battery energy storage system capacity | MW	350
Investment tax credit	$ 154
Domestic Tax Authority
Income Tax Contingency [Line Items]
Inflation Reduction Act of 2022, alternative minimum tax on book income of certain large corporations	15%
Inflation Reduction Act of 2022, excise tax on net stock repurchases	1%
Inflation Reduction Act of 2022, alternative minimum tax on book income of certain large corporations, three-year average annual adjusted financial statement income minimum threshold	$ 1,000

Earnings Per Share - Schedule o

Earnings Per Share - Schedule of Earnings Per Share, Basic and Diluted (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Net income (loss) attributable to Vistra	$ (35)	$ 699
Less cumulative dividends attributable to preferred stock	(49)	(38)
Net income (loss) attributable to Vistra common stock	$ (84)	$ 661
Weighted average shares of common stock outstanding - basic (in shares)	348,966,197	383,631,369
Dilutive securities - stock-based incentive compensation plan	0	3,922,010
Weighted average shares of common stock outstanding - diluted (in shares)	348,966,197	387,553,379
Net income (loss) per weighted average share of common stock outstanding - basic (in dollars per share)	$ (0.24)	$ 1.72
Net income (loss) per weighted average share of common stock outstanding - diluted (in dollars per share)	$ (0.24)	$ 1.71
Series A Preferred Stock
Less cumulative dividends attributable to preferred stock	$ (20)	$ (20)
Series B Preferred Stock
Less cumulative dividends attributable to preferred stock	(18)	(18)
Series C Preferred Stock
Less cumulative dividends attributable to preferred stock	$ (11)	$ 0

Earnings Per Share - Narrative

Earnings Per Share - Narrative (Details) - shares	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Earnings Per Share [Abstract]
Antidilutive securities excluded from computation of earnings per share (in shares)	7,954,878	3,859,165

Goodwill and Identifiable Int_3

Goodwill and Identifiable Intangible Assets and Liabilities - Schedule of Goodwill (Details) $ in Millions	3 Months Ended
	Mar. 31, 2024 USD ($)
Goodwill [Roll Forward]
Balance at beginning of period	$ 2,583
Goodwill recorded in connections with the Energy Harbor Merger	294
Balance at end of period	2,877
Retail Reporting Unit
Goodwill [Roll Forward]
Balance at beginning of period	2,461
Balance at end of period	2,461
Goodwill, expected tax deductible amount	$ 1,944
Business acquisition, goodwill, expected tax deductible term	15 years
Texas Generation Reporting Unit
Goodwill [Roll Forward]
Balance at beginning of period	$ 122
Balance at end of period	$ 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	Mar. 31, 2024	Dec. 31, 2023
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross Carrying Amount	$ 3,309	$ 2,937
Accumulated Amortization	2,372	2,414
Net	937	523
Total identifiable intangible assets	2,278	1,864
Total identifiable intangible liabilities	183	131
Retail trade names (not subject to amortization)
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross carrying amount, unamortized intangibles	1,341	1,341
Retail customer relationships
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross Carrying Amount	2,170	2,088
Accumulated Amortization	1,888	1,866
Net	282	222
Software and other technology-related assets
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross Carrying Amount	545	536
Accumulated Amortization	249	315
Net	296	221
Retail and wholesale contracts
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross Carrying Amount	503	233
Accumulated Amortization	218	217
Net	285	16
LTSA
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross Carrying Amount	18	18
Accumulated Amortization	5	5
Net	13	13
Total identifiable intangible liabilities	121	122
Other identifiable intangible assets
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Gross Carrying Amount	73	62
Accumulated Amortization	12	11
Net	61	51
Power and fuel purchase contracts
Finite-Lived and Indefinite-Lived Intangible [Line Items]
Total identifiable intangible liabilities	$ 62	$ 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	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Finite-Lived Intangible Assets and Liabilities [Line Items]
Amortization of intangible assets and liabilities	$ 139	$ 131
Retail customer relationships | Depreciation and amortization
Finite-Lived Intangible Assets and Liabilities [Line Items]
Amortization of intangible assets and liabilities	22	28
Software and other technology-related assets | Depreciation and amortization
Finite-Lived Intangible Assets and Liabilities [Line Items]
Amortization of intangible assets and liabilities	13	15
Retail and wholesale contracts | Operating revenues/fuel, purchased power costs and delivery fees
Finite-Lived Intangible Assets and Liabilities [Line Items]
Amortization of intangible assets and liabilities	1	2
Other identifiable intangible assets | Fuel, purchased power costs and delivery fees
Finite-Lived Intangible Assets and Liabilities [Line Items]
Amortization of intangible assets and liabilities	$ 103	$ 86

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	Mar. 31, 2024 USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2024	$ 167
2025	141
2026	77
2027	49
2028	$ 32

Accounts Receivable Financing (

Accounts Receivable Financing (Details) - USD ($) $ in Millions	Apr. 08, 2024	Mar. 31, 2024	Dec. 31, 2023	Jul. 31, 2023
Financing Receivable, Nonaccrual [Line Items]
Accounts receivable financing		$ 875	$ 0
Accounts Receivable Securitization Program
Financing Receivable, Nonaccrual [Line Items]
Accounts receivable financing		750	0
Accounts receivable securitization program, gross trade accounts receivable held by special purpose subsidiary		913
Repurchase Facility
Financing Receivable, Nonaccrual [Line Items]
Accounts receivable repurchase facility, maximum borrowing capacity				$ 125
Accounts receivable repurchase facility, amounts borrowed		$ 125	$ 0
Maximum | Accounts Receivable Securitization Program
Financing Receivable, Nonaccrual [Line Items]
Account receivable securitization program, total borrowing capacity, July 2023 through July 2024				750
Maximum | Accounts Receivable Securitization Program | Subsequent Event
Financing Receivable, Nonaccrual [Line Items]
Account receivable securitization program, total borrowing capacity, July 2023 through July 2024	$ 1,000
Minimum | Accounts Receivable Securitization Program
Financing Receivable, Nonaccrual [Line Items]
Account receivable securitization program, total borrowing capacity, July 2022 through July 2023				$ 600

Collateral Financing Agreemen_2

Collateral Financing Agreement With Affiliate (Details) $ in Millions	Mar. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Jun. 15, 2023 USD ($) security
Debt Instrument, Redemption [Line Items]
Margin deposits posted under affiliate financing agreement	$ 443	$ 439
Margin deposit financing with affiliate	443	$ 439
7.233% Senior Secured Notes Due 2028 | Vistra Operations Senior Secured Notes
Debt Instrument, Redemption [Line Items]
Debt instrument, face amount	$ 450
Debt instrument, interest rate, stated percentage	7.233%
Pre-Capitalized Trust Securities
Debt Instrument, Redemption [Line Items]
Derivative, number of instruments held | security			450,000
Derivative, notional amount			$ 450
Facility Agreement
Debt Instrument, Redemption [Line Items]
Facility fee	3.3608%

Debt - Schedule of Long-Term De

Debt - Schedule of Long-Term Debt Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 14,747	$ 14,402
Total other long-term debt	67	67
Unamortized debt premiums, discounts and issuance costs	(136)	(115)
Less amounts due currently (a)	(54)	(2,286)
Total long-term debt less amounts due currently	14,693	12,116
Vistra Operations Senior Secured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	4,891	5,650
Energy Harbor Secured Notes
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	6,300	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	2,494	2,500
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	700	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	342	400
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	1,155	1,500
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
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
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
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
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
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
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
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
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
3.375% Revenue Bond, due August 1, 2029 | Energy Harbor Secured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 100	0
Debt instrument, interest rate, stated percentage	3.375%
4.750% Revenue Bond, due June 1, 2033 and July 1, 2033 | Energy Harbor Secured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 285	0
Debt instrument, interest rate, stated percentage	4.75%
3.750% Revenue Bond, due October 1, 2047 | Energy Harbor Secured Notes
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 46	0
Debt instrument, interest rate, stated percentage	3.75%
Equipment Financing Agreements | Other Debt
Debt Instrument [Line Items]
Total long-term debt, including amounts due currently	$ 67	$ 67

Debt - Schedule of Maturities o

Debt - Schedule of Maturities of Long-Term Debt (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Debt Disclosure [Abstract]
Remainder of 2024	$ 1,532
2025	786
2026	1,038
2027	3,434
2028	35
Thereafter	8,058
Unamortized premiums, discounts and debt issuance costs	(136)
Total long-term debt, including amounts due currently	$ 14,747	$ 14,402

Debt - Schedule of Line of Cred

Debt - Schedule of Line of Credit Facilities (Details) $ in Millions	Mar. 31, 2024 USD ($)
Debt Instrument [Line Items]
Facility Limit	$ 7,944
Cash borrowings (short-term)	500
Cash borrowings (long-term)	3,194
Letters of Credit Outstanding	1,882
Available Capacity	1,930
Line of Credit | Vistra Operations Company LLC
Debt Instrument [Line Items]
Facility Limit	5,669
Cash borrowings (short-term)	0
Cash borrowings (long-term)	2,494
Letters of Credit Outstanding	1,882
Available Capacity	1,293
Revolving Credit Facility | Line of Credit | Vistra Operations Company LLC
Debt Instrument [Line Items]
Facility Limit	3,175
Cash borrowings (short-term)	0
Cash borrowings (long-term)	0
Letters of Credit Outstanding	1,882
Available Capacity	1,293
Term Loan B-3 Facility | Line of Credit | Vistra Operations Company LLC
Debt Instrument [Line Items]
Facility Limit	2,494
Cash borrowings (short-term)	0
Cash borrowings (long-term)	2,494
Letters of Credit Outstanding	0
Available Capacity	0
Vistra Operations Commodity-Linked Facility | Revolving Credit Facility | Vistra Operations Company LLC
Debt Instrument [Line Items]
Facility Limit	1,575
Cash borrowings (short-term)	500
Cash borrowings (long-term)	0
Letters of Credit Outstanding	0
Available Capacity	637
Vistra Zero Term Loan B Facility | Revolving Credit Facility | Vistra Zero Operating Company, LLC
Debt Instrument [Line Items]
Facility Limit	700
Cash borrowings (short-term)	0
Cash borrowings (long-term)	700
Letters of Credit Outstanding	0
Available Capacity	$ 0

Debt- Narrative (Details)

Debt- Narrative (Details) - USD ($)		1 Months Ended		3 Months Ended		63 Months Ended	75 Months Ended
	Mar. 26, 2024	Apr. 30, 2024	Jan. 31, 2024	Mar. 31, 2024	Mar. 31, 2023	Mar. 31, 2024	Mar. 31, 2024
Debt Instrument [Line Items]
Facility Limit				$ 7,944,000,000		$ 7,944,000,000	$ 7,944,000,000
Cash borrowings (long-term)				3,194,000,000		3,194,000,000	3,194,000,000
Cash borrowings (short-term)				500,000,000		500,000,000	500,000,000
Borrowings under Revolving Credit Facility				0	$ 100,000,000
Gain (loss) on extinguishment of debt				6,000,000	$ 0
Alternate Letter Of Credit Facility | Letter of Credit
Debt Instrument [Line Items]
Facility Limit				125,000,000		125,000,000	125,000,000
Letters of credit outstanding				100,000,000		100,000,000	100,000,000
Alternate Letter Of Credit Facility | Letter of Credit | Subsequent Event
Debt Instrument [Line Items]
Facility Limit		$ 300,000,000
Energy Harbor Letter Of Credit Facility | Letter of Credit
Debt Instrument [Line Items]
Letters of credit outstanding				115,000,000		$ 115,000,000	$ 115,000,000
Bond Repurchase Program Authorized April 2024 | Subsequent Event
Debt Instrument [Line Items]
Bond repurchase program, authorized amount		$ 1,000,000,000
Line of Credit | Vistra Zero Term Loan B Facility | Secured Debt
Debt Instrument [Line Items]
Debt instrument, periodic payment				$ 1,750,000
Debt, weighted average interest rate				8.08%		8.08%	8.08%
Debt instrument, face amount	$ 700,000,000
Borrowings under Revolving Credit Facility	$ 690,000,000
Debt instrument, soft call prepayment premium, percentage	1%
Long-term line of credit				$ 700,000,000		$ 700,000,000	$ 700,000,000
Line of Credit | Vistra Zero Term Loan B Facility | Secured Debt | SOFR
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate				2.75%
Line of Credit | Vistra Operations Company LLC
Debt Instrument [Line Items]
Facility Limit				$ 5,669,000,000		5,669,000,000	5,669,000,000
Cash borrowings (long-term)				$ 2,494,000,000		2,494,000,000	2,494,000,000
Collateral suspension provision effective date, grace period, number of days				60 days
Cash borrowings (short-term)				$ 0		0	0
Line of Credit | Vistra Operations Company LLC | Revolving Credit Facility
Debt Instrument [Line Items]
Facility Limit				$ 3,175,000,000		$ 3,175,000,000	$ 3,175,000,000
Debt instrument, basis spread on variable rate				1.70%
Debt instrument, fee on undrawn amounts				0.265
Debt instrument, interest rate, stated percentage				1.70%		1.70%	1.70%
Cash borrowings (long-term)				$ 0		$ 0	$ 0
Debt covenant, outstanding borrowings to outstanding commitments threshold, amount of letters of credit excluded				$ 300,000,000		$ 300,000,000	$ 300,000,000
Debt covenant, outstanding borrowings to outstanding commitments threshold, percent				30%		30%	30%
Cash borrowings (short-term)				$ 0		$ 0	$ 0
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
Debt covenant, net first lien debt to EBITDA threshold				4.25		4.25	4.25
Debt covenant, net leverage ratio threshold, collateral suspension period				5.50		5.50	5.50
Line of Credit | Vistra Operations Company LLC | Senior Secured Revolving Credit Facility Letter of Credit Sub-Facility
Debt Instrument [Line Items]
Facility Limit				$ 3,105,000,000		$ 3,105,000,000	$ 3,105,000,000
Line of Credit | Vistra Operations Company LLC | Term Loan B-3 Facility
Debt Instrument [Line Items]
Facility Limit				$ 2,494,000,000		2,494,000,000	2,494,000,000
Debt instrument, basis spread on variable rate				2%
Cash borrowings (long-term)				$ 2,494,000,000		$ 2,494,000,000	$ 2,494,000,000
Line of credit facility, interest rate at period end				7.33%		7.33%	7.33%
Debt instrument, periodic payment				$ 6,250,000
Cash borrowings (short-term)				$ 0		$ 0	$ 0
Line of Credit | Vistra Operations Company LLC | Vistra Operations Commodity-Linked Facility
Debt Instrument [Line Items]
Debt covenant, outstanding borrowings to outstanding commitments threshold, percent				30%		30%	30%
Line of Credit | Vistra Operations Company LLC | Vistra Operations Commodity-Linked Facility | Maximum
Debt Instrument [Line Items]
Debt covenant, net first lien debt to EBITDA threshold				4.25		4.25	4.25
Debt covenant, net leverage ratio threshold, collateral suspension period				5.50		5.50	5.50
Revolving Credit Facility | Vistra Operations Company LLC | Vistra Operations Commodity-Linked Facility
Debt Instrument [Line Items]
Facility Limit				$ 1,575,000,000		$ 1,575,000,000	$ 1,575,000,000
Debt instrument, basis spread on variable rate				1.70%
Debt instrument, fee on undrawn amounts				0.265
Cash borrowings (long-term)				$ 0		0	0
Line of credit facility, borrowing base capacity limit				1,137,000,000		1,137,000,000	1,137,000,000
Cash borrowings (short-term)				$ 500,000,000		$ 500,000,000	$ 500,000,000
Debt, weighted average interest rate				7.03%		7.03%	7.03%
Revolving Credit Facility | Vistra Operations Company LLC | Vistra Operations Commodity-Linked Facility | Minimum
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate				1.25%
Debt instrument, fee on undrawn amounts				0.175
Revolving Credit Facility | Vistra Operations Company LLC | Vistra Operations Commodity-Linked Facility | Maximum
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate				2%
Debt instrument, fee on undrawn amounts				0.350
Line of credit facility, potential borrowing capacity, subject to ability to obtain additional commitments				$ 3,000,000,000		$ 3,000,000,000	$ 3,000,000,000
Letter of Credit | Vistra Operations Company LLC | Secured Letter of Credit Facilities
Debt Instrument [Line Items]
Letters of credit outstanding				$ 898,000,000		$ 898,000,000	$ 898,000,000
Letter of Credit | Vistra Operations Company LLC | Secured Letter of Credit Facilities | Maximum
Debt Instrument [Line Items]
Debt covenant, net first lien debt to EBITDA threshold				4.25		4.25	4.25
Debt covenant, net leverage ratio threshold, collateral suspension period				5.50		5.50	5.50
Senior Notes
Debt Instrument [Line Items]
Debt instrument, repaid, principal			$ 759,000,000
Gain (loss) on extinguishment of debt				$ 6,000,000
Proceeds from issuance of senior long-term debt						$ 5,650,000,000
Proceeds from issuance of unsecured debt							$ 6,300,000,000
Senior Notes | 6.000% Senior Secured Notes due 2034 | Subsequent Event
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage		6%
Debt instrument, face amount		$ 500,000,000
Proceeds from debt, net of issuance costs		495,000,000
Debt issuance costs, gross		$ 5,000,000
Senior Notes | 6.875% Senior Unsecured Notes due 2032 | Subsequent Event
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage		6.875%
Debt instrument, face amount		$ 1,000,000,000
Proceeds from debt, net of issuance costs		990,000,000
Debt issuance costs, gross		$ 10,000,000
Senior Notes | 6.950% Senior Secured Notes, due October 15, 2033
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage			6.95%
Senior Notes | 7.750% Senior Unsecured Notes, due October 15, 2031
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage			7.75%
Senior Notes | 4.875% Senior Secured Notes, due May 13, 2024
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage				4.875%		4.875%	4.875%
Debt instrument, repaid, principal			$ 58,000,000
Senior Notes | 3.550% Senior Secured Notes, due July 15, 2024
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage				3.55%		3.55%	3.55%
Debt instrument, repaid, principal			$ 345,000,000
Senior Notes | 5.125% Senior Secured Notes, due May 13, 2025
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage			5.125%
Debt instrument, repaid, principal			$ 356,000,000
Senior Notes | 3.700% Senior Secured Notes, due January 30, 2027
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage				3.70%		3.70%	3.70%
Senior Notes | 4.300% Senior Secured Notes, due July 15, 2029
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage				4.30%		4.30%	4.30%
Senior Notes | 5.500% Senior Unsecured Notes, due September 1, 2026
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage				5.50%		5.50%	5.50%
Senior Notes | 5.625% Senior Unsecured Notes, due February 15, 2027
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage				5.625%		5.625%	5.625%
Senior Notes | 5.000% Senior Unsecured Notes, due July 31, 2027
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage				5%		5%	5%
Senior Notes | 4.375% Senior Unsecured Notes, due May 15, 2029
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage				4.375%		4.375%	4.375%
Revenue Bonds
Debt Instrument [Line Items]
Debt instrument, face amount				$ 431,000,000		$ 431,000,000	$ 431,000,000

Commodity and Other Derivativ_3

Commodity and Other Derivative Contractual Assets and Liabilities - Schedule of Interest Rate Derivatives (Details) $ in Millions	Mar. 31, 2024 USD ($)
Derivative [Line Items]
Long-term debt, amount of variable interest debt hedged	$ 2,300
Interest Rate Swap, Swapped to Fixed, Effective from July 2023 to July 2026
Derivative [Line Items]
Derivative, notional amount	$ 3,000
Interest Rate Swap, Swapped to Fixed, Effective from July 2023 to July 2026 | Minimum
Derivative [Line Items]
Rate Range	4.89%
Interest Rate Swap, Swapped to Fixed, Effective from July 2023 to July 2026 | Maximum
Derivative [Line Items]
Rate Range	4.97%
Interest Rate Swap, Swapped to Variable, Effective from July 2023 to July 2026
Derivative [Line Items]
Derivative, notional amount	$ 700
Interest Rate Swap, Swapped to Variable, Effective from July 2023 to July 2026 | Minimum
Derivative [Line Items]
Rate Range	3.44%
Interest Rate Swap, Swapped to Variable, Effective from July 2023 to July 2026 | Maximum
Derivative [Line Items]
Rate Range	3.49%
Interest Rate Swap, Swapped to Fixed, Effective from December 2023 to December 2030
Derivative [Line Items]
Derivative, notional amount	$ 1,625
Interest Rate Swap, Swapped to Fixed, Effective from December 2023 to December 2030 | Minimum
Derivative [Line Items]
Rate Range	5.20%
Interest Rate Swap, Swapped to Fixed, Effective from December 2023 to December 2030 | Maximum
Derivative [Line Items]
Rate Range	5.37%
Interest rate swaps | SOFR
Derivative [Line Items]
Derivative, basis spread on variable rate	2%

Commodity and Other Derivativ_4

Commodity and Other Derivative Contractual Assets and Liabilities - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	$ 4,220	$ 4,208
Offsetting fair value under netting arrangements	3,427	3,547
Derivative assets, fair value, gross liability	(3,427)	(3,547)
Derivative liabilities, fair value, gross liability	(7,066)	(6,932)
Derivative, fair value, net	(2,846)	(2,724)
Current assets
Derivatives, Fair Value [Line Items]
Derivative assets and liabilities, fair value, gross asset	3,557	3,645
Noncurrent assets
Derivatives, Fair Value [Line Items]
Derivative assets and liabilities, fair value, gross asset	703	577
Current liabilities
Derivatives, Fair Value [Line Items]
Derivative assets and liabilities, fair value, gross liability	(5,214)	(5,258)
Noncurrent liabilities
Derivatives, Fair Value [Line Items]
Derivative assets and liabilities, fair value, gross liability	(1,892)	(1,688)
Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	4,113	4,144
Offsetting fair value under netting arrangements	3,392	3,519
Derivative assets, fair value, gross liability	(3,392)	(3,519)
Derivative liabilities, fair value, gross liability	(7,021)	(6,884)
Derivative asset, fair value, net	4,113	4,144
Derivative liabilities, fair value, net	(7,021)	(6,884)
Commodity contracts | Current assets
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	3,479	3,585
Offsetting fair value under netting arrangements	19	7
Commodity contracts | Noncurrent assets
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	653	565
Offsetting fair value under netting arrangements	2	1
Commodity contracts | Current liabilities
Derivatives, Fair Value [Line Items]
Derivative assets, fair value, gross liability	(14)	(1)
Derivative liabilities, fair value, gross liability	(5,176)	(5,233)
Commodity contracts | Noncurrent liabilities
Derivatives, Fair Value [Line Items]
Derivative assets, fair value, gross liability	(5)	(5)
Derivative liabilities, fair value, gross liability	(1,866)	(1,659)
Interest rate swaps
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	107	64
Offsetting fair value under netting arrangements	35	28
Derivative assets, fair value, gross liability	(35)	(28)
Derivative liabilities, fair value, gross liability	(45)	(48)
Derivative asset, fair value, net	107	64
Derivative liabilities, fair value, net	(45)	(48)
Interest rate swaps | Current assets
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	59	53
Offsetting fair value under netting arrangements	0	0
Interest rate swaps | Noncurrent assets
Derivatives, Fair Value [Line Items]
Derivative assets, far value, gross asset	48	11
Offsetting fair value under netting arrangements	0	0
Interest rate swaps | Current liabilities
Derivatives, Fair Value [Line Items]
Derivative assets, fair value, gross liability	0	0
Derivative liabilities, fair value, gross liability	(24)	(24)
Interest rate swaps | Noncurrent liabilities
Derivatives, Fair Value [Line Items]
Derivative assets, fair value, gross liability	0	0
Derivative liabilities, fair value, gross liability	$ (21)	$ (24)

Commodity and Other Derivativ_5

Commodity and Other Derivative Contractual Assets and Liabilities - Schedule of Pretax Effect on Net Income of Derivatives Not Under Hedge Accounting, Including Realized and Unrealized Effects (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss)	$ (505)	$ 346
Interest rate swaps
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss)	58	(28)
Commodity contracts (Operating revenues) | Commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss)	(608)	669
Commodity contracts (Fuel, purchased power costs and delivery fees) | Commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss)	$ 45	$ (295)

Commodity and Other Derivativ_6

Commodity and Other Derivative Contractual Assets and Liabilities - Offsetting Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Derivatives, Fair Value [Line Items]
Derivative assets: Derivative Assets and Liabilities	$ 4,220	$ 4,208
Derivative assets: Offsetting Instruments	(3,427)	(3,547)
Derivative assets: Cash Collateral (Received) Pledged	(84)	(26)
Derivative assets: Net Amounts	709	635
Derivative liabilities: Derivative Assets and Liabilities	(7,066)	(6,932)
Derivative liabilities: Offsetting Instruments	3,427	3,547
Derivative liabilities: Cash Collateral (Received) Pledged	914	970
Liquidity exposure	(2,725)	(2,415)
Derivative assets (liabilities): Derivative Assets and Liabilities	(2,846)	(2,724)
Derivative assets (liabilities): Offsetting Instruments	0	0
Derivative assets (liabilities): Cash Collateral (Received) Pledged	830	944
Derivative assets (liabilities): Net Amounts	(2,016)	(1,780)
Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative assets: Derivative Assets and Liabilities	4,113	4,144
Derivative assets: Offsetting Instruments	(3,392)	(3,519)
Derivative assets: Cash Collateral (Received) Pledged	(84)	(26)
Derivative assets: Net Amounts	637	599
Derivative liabilities: Derivative Assets and Liabilities	(7,021)	(6,884)
Derivative liabilities: Offsetting Instruments	3,392	3,519
Derivative liabilities: Cash Collateral (Received) Pledged	914	970
Liquidity exposure	(2,715)	(2,395)
Interest rate swaps
Derivatives, Fair Value [Line Items]
Derivative assets: Derivative Assets and Liabilities	107	64
Derivative assets: Offsetting Instruments	(35)	(28)
Derivative assets: Cash Collateral (Received) Pledged	0	0
Derivative assets: Net Amounts	72	36
Derivative liabilities: Derivative Assets and Liabilities	(45)	(48)
Derivative liabilities: Offsetting Instruments	35	28
Derivative liabilities: Cash Collateral (Received) Pledged	0	0
Liquidity exposure	$ (10)	$ (20)

Commodity and Other Derivativ_7

Commodity and Other Derivative Contractual Assets and Liabilities - Schedule of Notional Amounts of Outstanding Derivative Positions (Details) gal in Millions, certificate in Millions, T in Millions, MMBTU in Millions, $ in Millions	Mar. 31, 2024 USD ($) gal MMBTU GWh certificate T	Dec. 31, 2023 USD ($) GWh certificate T MMBTU gal
Natural gas
Derivatives, Fair Value [Line Items]
Nonmonetary notional volume | MMBTU	5,277	5,335
Electricity
Derivatives, Fair Value [Line Items]
Nonmonetary notional volume | GWh	793,133	800,001
Financial transmission rights/Congestion revenue rights
Derivatives, Fair Value [Line Items]
Nonmonetary notional volume | GWh	235,014	250,895
Coal
Derivatives, Fair Value [Line Items]
Nonmonetary notional volume | T	31	35
Fuel oil
Derivatives, Fair Value [Line Items]
Nonmonetary notional volume | gal	7	3
Emissions
Derivatives, Fair Value [Line Items]
Nonmonetary notional volume | T	29	24
Renewable energy certificates
Derivatives, Fair Value [Line Items]
Nonmonetary notional volume | certificate	29	29
Interest rate swaps – variable/fixed
Derivatives, Fair Value [Line Items]
Derivative, notional amount | $	$ 4,625	$ 5,225
Interest rate swaps – fixed/variable
Derivatives, Fair Value [Line Items]
Derivative, notional amount | $	$ 700	$ 1,300

Commodity and Other Derivativ_8

Commodity and Other Derivative Contractual Assets and Liabilities - Credit Risk-Related Contingent Features of Derivatives (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Credit Derivatives [Line Items]
Derivative liabilities, fair value, gross liability	$ (7,066)	$ (6,932)
Offsetting fair value under netting arrangements	3,427	3,547
Cash collateral and letters of credit	914	970
Liquidity exposure	(2,725)	(2,415)
Credit Risk Contract
Credit Derivatives [Line Items]
Derivative liabilities, fair value, gross liability	(2,115)	(1,890)
Offsetting fair value under netting arrangements	707	692
Cash collateral and letters of credit	985	854
Liquidity exposure	$ (423)	$ (344)

Commodity and Other Derivativ_9

Commodity and Other Derivative Contractual Assets and Liabilities - Narrative (Details) - Credit Risk Contract $ in Millions	3 Months Ended
	Mar. 31, 2024 USD ($)
Derivative [Line Items]
Total credit risk exposure to all counterparties related to derivative contracts	$ 4,599
Net exposure to those counterparties after taking into effect master netting arrangements, setoff provisions and collateral	732
Largest net exposure to single counterparty	$ 248
Credit risk exposure to banking and financial sector percentage	83%
Net exposure to banking and financial sector percentage	36%

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023
Debt securities
Liabilities:
Debt, weighted average interest rate	3.69%		3.19%
Decommissioning fund investments, debt securities average maturities	8 years	11 years
Decommissioning fund investments, debt maturities, one through five years, fair value	$ 1,042
Decommissioning fund investments, debt maturities, five through ten years, fair value	528
Decommissioning fund investments, debt maturities, after ten years, fair value	439
Fair Value, Recurring
Assets:
Sub-total	40		$ 14
Liabilities:
Total liabilities	40		14
Fair Value, Recurring | Equity securities
Assets:
Assets measured at net asset value	728		579
Fair Value, Recurring | Commodity contracts
Assets:
Derivative assets	40		14
Liabilities:
Derivative liabilities	40		14
Fair Value, Recurring | Interest rate swaps
Assets:
Derivative assets	0		0
Liabilities:
Derivative liabilities	0		0
Fair Value, Recurring | Total
Assets:
Sub-total	7,667		5,594
Total assets	8,395		6,173
Liabilities:
Total liabilities	7,106		6,946
Fair Value, Recurring | Total | Equity securities
Assets:
Nuclear decommissioning trust, fair value	1,398		638
Fair Value, Recurring | Total | Debt securities
Assets:
Nuclear decommissioning trust, fair value	2,009		734
Fair Value, Recurring | Total | Commodity contracts
Assets:
Derivative assets	4,153		4,158
Liabilities:
Derivative liabilities	7,061		6,898
Fair Value, Recurring | Total | Interest rate swaps
Assets:
Derivative assets	107		64
Liabilities:
Derivative liabilities	45		48
Level 1 | Fair Value, Recurring
Assets:
Sub-total	4,326		3,524
Liabilities:
Total liabilities	3,619		3,815
Level 1 | Fair Value, Recurring | Equity securities
Assets:
Nuclear decommissioning trust, fair value	1,398		638
Level 1 | Fair Value, Recurring | Debt securities
Assets:
Nuclear decommissioning trust, fair value	101		0
Level 1 | Fair Value, Recurring | Commodity contracts
Assets:
Derivative assets	2,827		2,886
Liabilities:
Derivative liabilities	3,619		3,815
Level 1 | Fair Value, Recurring | Interest rate swaps
Assets:
Derivative assets	0		0
Liabilities:
Derivative liabilities	0		0
Level 2 | Fair Value, Recurring
Assets:
Sub-total	2,586		1,426
Liabilities:
Total liabilities	1,583		1,443
Level 2 | Fair Value, Recurring | Equity securities
Assets:
Nuclear decommissioning trust, fair value	0		0
Level 2 | Fair Value, Recurring | Debt securities
Assets:
Nuclear decommissioning trust, fair value	1,908		734
Level 2 | Fair Value, Recurring | Commodity contracts
Assets:
Derivative assets	571		628
Liabilities:
Derivative liabilities	1,538		1,395
Level 2 | Fair Value, Recurring | Interest rate swaps
Assets:
Derivative assets	107		64
Liabilities:
Derivative liabilities	45		48
Level 3
Assets:
Sub-total	715		630
Liabilities:
Total liabilities	1,864		1,674
Level 3 | Fair Value, Recurring
Assets:
Sub-total	715		630
Liabilities:
Total liabilities	1,864		1,674
Level 3 | Fair Value, Recurring | Equity securities
Assets:
Nuclear decommissioning trust, fair value	0		0
Level 3 | Fair Value, Recurring | Debt securities
Assets:
Nuclear decommissioning trust, fair value	0		0
Level 3 | Fair Value, Recurring | Commodity contracts
Assets:
Derivative assets	715		630
Liabilities:
Derivative liabilities	1,864		1,674
Level 3 | Fair Value, Recurring | Interest rate swaps
Assets:
Derivative 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) - Level 3 - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2024	Dec. 31, 2023
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	$ 715,000,000	$ 630,000,000
Liabilities	(1,864,000,000)	(1,674,000,000)
Total	(1,149,000,000)	(1,044,000,000)
Electricity purchases and sales | Income Approach
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	516,000,000	449,000,000
Liabilities	(1,523,000,000)	(1,273,000,000)
Total	(1,007,000,000)	(824,000,000)
Electricity purchases and sales | Minimum | Income Approach
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair value inputs, hourly price curve shape	0	0
Fair value inputs, Illiquid delivery periods for hub power prices and heat rates	35	30
Electricity purchases and sales | Maximum | Income Approach
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair value inputs, hourly price curve shape	95	85
Fair value inputs, Illiquid delivery periods for hub power prices and heat rates	105	110
Electricity purchases and sales | Arithmetic Average | Income Approach
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair value inputs, hourly price curve shape	47	44
Fair value inputs, Illiquid delivery periods for hub power prices and heat rates	72	71
Options | Option Pricing Model
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	0	1,000,000
Liabilities	(253,000,000)	(237,000,000)
Total	$ (253,000,000)	$ (236,000,000)
Options | Minimum | Option Pricing Model
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair value inputs, gas to power correlation	10%	10%
Fair value inputs, power and gas volatility	5%	10%
Options | Maximum | Option Pricing Model
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair value inputs, gas to power correlation	100%	100%
Fair value inputs, power and gas volatility	870%	870%
Options | Arithmetic Average | Option Pricing Model
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair value inputs, gas to power correlation	55%	55%
Fair value inputs, power and gas volatility	439%	441%
Financial transmission rights/Congestion revenue rights | Market Approach
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	$ 173,000,000	$ 157,000,000
Liabilities	(33,000,000)	(34,000,000)
Total	140,000,000	123,000,000
Financial transmission rights/Congestion revenue rights | Minimum | Market Approach
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair value inputs, Illiquid price differences between settlement points	(60)	(85)
Financial transmission rights/Congestion revenue rights | Maximum | Market Approach
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair value inputs, Illiquid price differences between settlement points	20	25
Financial transmission rights/Congestion revenue rights | Arithmetic Average | Market Approach
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair value inputs, Illiquid price differences between settlement points	(19)	(30)
Natural gas | Income Approach
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	14,000,000	9,000,000
Liabilities	(46,000,000)	(112,000,000)
Total	(32,000,000)	(103,000,000)
Natural gas | Minimum | Income Approach
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair value inputs, gas basis and illiquid delivery points	0	0
Fair value inputs, delivery periods	0	0
Natural gas | Maximum | Income Approach
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair value inputs, gas basis and illiquid delivery points	15	15
Fair value inputs, delivery periods	5	5
Natural gas | Arithmetic Average | Income Approach
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair value inputs, gas basis and illiquid delivery points	6	6
Fair value inputs, delivery periods	4	4
Other
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Assets	12,000,000	14,000,000
Liabilities	(9,000,000)	(18,000,000)
Total	$ 3,000,000	$ (4,000,000)

Fair Value Measurements - Sch_3

Fair Value Measurements - Schedule of Changes in Fair Value of the Level 3 Assets and Liabilities (Details) - Level 3 - Commodity Contract - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
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)
Total unrealized valuation gains (losses)	(269)	(76)
Purchases, issuances and settlements
Purchases	70	49
Issuances	(3)	(5)
Settlements	99	17
Transfers into Level 3	3	(14)
Transfers out of Level 3	8	23
Net liabilities assumed in connection with the Energy Harbor Merger	(13)	0
Net change	(105)	(6)
Net liability balance at end of period	(1,149)	(1,225)
Unrealized valuation losses relating to instruments held at end of period	$ (325)	$ (159)

Tax Receivable Agreement Obli_3

Tax Receivable Agreement Obligation - Narrative (Details) - facility		3 Months Ended
	Dec. 29, 2023	Mar. 31, 2024
Income Tax Contingency [Line Items]
Percent of cash tax savings due tax receivable agreement rights holders		85%
Number of facilities (in facilities)		2
Tax receivable agreement, outstanding repurchase rights percentage		98%
Tax Receivable Agreement
Income Tax Contingency [Line Items]
Tax receivable agreement, outstanding repurchase rights percentage	74%

Tax Receivable Agreement Obli_4

Tax Receivable Agreement Obligation - Tax Receivable Agreement Obligations Rights Repurchased (Details) $ / shares in Units, $ in Millions

1 Months Ended

3 Months Ended

Feb. 28, 2024 right

Feb. 13, 2024 USD ($) right

Jan. 31, 2024 $ / shares

Jan. 11, 2024 USD ($) right $ / shares

Jan. 01, 2024 right

Dec. 31, 2023 right

Dec. 29, 2023 shares

Jan. 01, 2023 right

Feb. 27, 2024 USD ($) $ / shares

Dec. 31, 2023 USD ($) $ / shares

Mar. 31, 2024 right

Mar. 31, 2023 right

Income Tax Contingency [Line Items]

Tax receivable agreement, outstanding repurchase rights percentage

98%

Series C Preferred Stock

Income Tax Contingency [Line Items]

Preferred stock, shares issued (in shares) | shares

476,081

Tax Receivable Agreement

Income Tax Contingency [Line Items]

Tax receivable agreement, right outstanding (in rights)

108,981,958

8,195,063

Tax receivable agreement, repurchase additional rights (in rights)

(2,235,020)

(55,056,931)

(43,494,944)

(317,387,412)

Tax receivable agreement, repurchase rights, per rights (in dollars per right) | $ / shares

$ 1.50

$ 1.50

$ 1.50

Tax receivable agreement, repurchase rights, aggregate purchase price | $

$ 476

Tax receivable agreement, repurchase rights total consideration, paid in cash | $

$ 83

$ 65

$ 3

Tax receivable agreement, repurchase rights, early tender premium (in dollars per TRA right) | $ / shares

$ 0.05

$ 1.45

Tax receivable agreement, outstanding repurchase rights percentage

74%

Tax Receivable Agreement | TCEH

Income Tax Contingency [Line Items]

Tax receivable agreement, right outstanding (in rights)

426,369,370

426,369,370

Tax Receivable Agreement Obli_5

Tax Receivable Agreement Obligation - Schedule of Tax Receivable Agreement Obligation (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023
Tax Receivable Agreement [Roll Forward]
TRA obligation at the beginning of the period	$ 171	$ 522
Accretion expense	6	20
Changes in tax assumption impacting timing of payments	(1)	45
Impacts of Tax Receivable Agreement	5	65
Repurchase/tender of TRA Rights	(161)	0
TRA obligation at the end of the period	15	587	$ 171
Less amounts due currently	0	(9)
Noncurrent TRA obligation at the end of the period	$ 15	$ 578	$ 164

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at beginning of period	$ 2,538	$ 2,437
Additions:
Accretion	33	22
Adjustment for change in estimates	3	6
Adjustment for obligations assumed through acquisition	1,368	0
Reductions:
Payments	(17)	(18)
Liability at end of period	3,925	2,447
Less amounts due currently	(119)	(139)	$ (124)
Asset retirement obligation	3,806	2,308	$ 2,414
Nuclear Plant Decommissioning
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at beginning of period	1,742	1,688
Additions:
Accretion	23	13
Adjustment for change in estimates	0	0
Adjustment for obligations assumed through acquisition	1,368	0
Reductions:
Payments	0	0
Liability at end of period	3,133	1,701
Less amounts due currently	0	0
Asset retirement obligation	3,133	1,701
Increase (decrease) in regulatory liabilities	14
Nuclear Plant Decommissioning | Operating Expense
Additions:
Accretion	9
Land Reclamation, Coal Ash and Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at beginning of period	796	749
Additions:
Accretion	10	9
Adjustment for change in estimates	3	6
Adjustment for obligations assumed through acquisition	0	0
Reductions:
Payments	(17)	(18)
Liability at end of period	792	746
Less amounts due currently	(119)	(139)
Asset retirement obligation	$ 673	$ 607

Asset Retirement Obligations _2

Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023	Mar. 31, 2023	Dec. 31, 2022
Asset Retirement Obligations [Line Items]
Asset retirement obligation	$ 3,925	$ 2,538	$ 2,447	$ 2,437
Regulatory liability	322	209
Nuclear Plant Decommissioning
Asset Retirement Obligations [Line Items]
Asset retirement obligation	3,133	1,742	$ 1,701	$ 1,688
Regulatory liability		$ 209
Nuclear Plant Decommissioning | Comanche Peak Nuclear Power Plant
Asset Retirement Obligations [Line Items]
Asset retirement obligation	1,756
Assets	2,078
Regulatory liability	$ 322

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details) $ in Millions

1 Months Ended

3 Months Ended

May 31, 2024 state

Aug. 31, 2023 application

May 31, 2023 facility unit

Oct. 31, 2022

Jul. 31, 2022 application

Jun. 30, 2022

Apr. 30, 2022 company

Jan. 31, 2022 application

Oct. 31, 2021 application

Mar. 31, 2024 USD ($) impoundment lawsuit state company

Feb. 29, 2024 plant

Oct. 31, 2017 unit

May 31, 2015 complaint

Loss Contingencies [Line Items]

Legal claim, duration

5 years

Loss contingency, number of plaintiffs | company

100

Number of plants | plant

5

Environmental protection agency, number of potential unit | unit

10

Demand report submission period

90 days

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 even of any single nuclear liability loss annual

$ 24.7

Vermilion Facility Old East and North Sites

Loss Contingencies [Line Items]

Site contingency, number of sites with regulatory violations | impoundment

2

Comanche Peak Nuclear Power Plant

Loss Contingencies [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

2.7

Energy after 12 Week waiting period, maximum weekly payments, remaining 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

Loss Contingencies [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%

Maximum | Martin Lake Steam Electric Station

Loss Contingencies [Line Items]

Clean air act, regional haze program, best available retrofit technology alternative, sulfur dioxide emissions, number of years remaining before generation unit is subject to program

3

Maximum | Coleto Creek

Loss Contingencies [Line Items]

Clean air act, regional haze program, best available retrofit technology alternative, sulfur dioxide emissions, number of years remaining before generation unit is subject to program

5

United States Environmental Protection Agency

Loss Contingencies [Line Items]

Cross-state air pollution rule, 2015 ozone national ambient air quality standards, federal implementation plan, beginning 2023 ozone season, number of states subject to rule | state

22

Clean air act, regional haze program, best available retrofit technology alternative, sulfur dioxide emissions, sulfur dioxide emissions, number of units in texas subject to rule, total | 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

Utility solid waste activities group, member entities, number | company

130

United States Environmental Protection Agency | Subsequent Event

Loss Contingencies [Line Items]

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

27

Illinois Environmental Protection Agency

Loss Contingencies [Line Items]

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

18

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

1

5

3

Section 170 (Price-Anderson) Of The Atomic Energy Act

Loss Contingencies [Line Items]

Nuclear insurance, public liability limit per incident

$ 16,200

Secondary financial protection pool, minimum single nuclear liability loss triggering assessment

500

United States Nuclear Regulatory Commission

Loss Contingencies [Line Items]

Required nuclear decontamination and property damage insurance, maximum coverage

$ 1,060

Gas Index Pricing Litigation | Wisconsin

Loss Contingencies [Line Items]

Loss contingency, pending claims, number | lawsuit

1

MISO 2015-2016 Planning Resource Auction

Loss Contingencies [Line Items]

Loss contingency, pending claims, number | complaint

3

Dynegy Inc. | MISO 2015-2016 Planning Resource Auction

Loss Contingencies [Line Items]

Loss contingency, pending claims, number | complaint

1

Vistra Corp.

Loss Contingencies [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

Letters of Credit | Vistra Operations Company LLC

Loss Contingencies [Line Items]

Letters of credit outstanding

2,995

Letters of Credit | Vistra Operations Company LLC | Support Risk Management and Trading Margin Requirements Including Over the Counter Hedging Transactions and Collateral Postings With Electric Reliability Council of Texas

Loss Contingencies [Line Items]

Letters of credit outstanding

2,634

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

Loss Contingencies [Line Items]

Letters of credit outstanding

186

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

Loss Contingencies [Line Items]

Letters of credit outstanding

27

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

Loss Contingencies [Line Items]

Letters of credit outstanding

95

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

Loss Contingencies [Line Items]

Letters of credit outstanding

53

Surety Bonds | Vistra Operations Company LLC

Loss Contingencies [Line Items]

Surety bonds outstanding

$ 1,500

Equity - Narrative (Details)

Equity - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Mar. 31, 2024	Mar. 31, 2023	Feb. 29, 2024	Dec. 31, 2023	Aug. 31, 2022	Oct. 31, 2021
Accelerated Share Repurchases [Line Items]
Treasury stock, value, acquired, cost method			$ 285	$ 311
Common stock, dividends, per share, cash paid (in dollars per share)	$ 0.2150	$ 0.1975
Vistra Corp. | Vistra Operations Company LLC
Accelerated Share Repurchases [Line Items]
Maximum allowable distribution to parent company by consolidated subsidiary without consent	$ 6,600		6,600
Dividends paid			$ 490	350
Series A Preferred Stock
Accelerated Share Repurchases [Line Items]
Preferred sock, 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, basis spread on variable rate			6.93%
Preferred sock, liquidation preference	$ 1,000		$ 1,000			$ 1,000
Series B Preferred Stock
Accelerated Share Repurchases [Line Items]
Preferred sock, 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, basis spread on variable rate			5.74%
Preferred sock, liquidation preference	1,000		$ 1,000			1,000
Series C Preferred Stock
Accelerated Share Repurchases [Line Items]
Preferred sock, 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, basis spread on variable rate			5.045%
Preferred sock, liquidation preference	$ 1,000		$ 1,000			$ 1,000
Share Repurchase Program Approved by the Board of Directors in October 2021
Accelerated Share Repurchases [Line Items]
Stock repurchase program, authorized amount								$ 2,000
Incremental Share Repurchase Program Approved by the Board of Directors in August 2022
Accelerated Share Repurchases [Line Items]
Stock repurchase program, authorized amount							$ 1,250
Incremental Share Repurchase Program Approved by the Board of Directors in March 2023
Accelerated Share Repurchases [Line Items]
Stock repurchase program, authorized amount		$ 1,000		$ 1,000
Incremental Share Repurchase Program Approved by the Board of Directors In February 2024
Accelerated Share Repurchases [Line Items]
Stock repurchase program, authorized amount					$ 1,500
Share Repurchase Program Approved by the Board of Directors in October 2021, August 2022, March 2023 and February 2024
Accelerated Share Repurchases [Line Items]
Stock repurchase program, authorized amount	$ 5,750		$ 5,750
Treasury stock, shares, acquired (in shares)			6,138,773	13,308,465
Treasury stock, value, acquired, cost method			$ 284	$ 308
Treasury stock acquired, average cost per share ( in dollars per share)			$ 46.21	$ 23.11
Treasury stock, shares, acquired, accrued (in shares)			72,839
Treasury stock, value, acquired, accrued, cost method			$ 5
Share Repurchase Program Approved by the Board of Directors in October 2021, August 2022 and March 2023
Accelerated Share Repurchases [Line Items]
Stock repurchase program, remaining authorized repurchase amount	$ 1,966		$ 1,966

Segment Information - Narrative

Segment Information - Narrative (Details)	3 Months Ended
	Mar. 31, 2024 reportableSegment state
Segment Reporting Information [Line Items]
Numbers of states in which entity operates | state	19
Number of reportable segments	6
East
Segment Reporting Information [Line Items]
Number of reportable segments	1

Segment Information - Schedule

Segment Information - Schedule of Segment Reporting Information, by Segment (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Segment Reporting Information [Line Items]
Total revenues	$ 3,054	$ 4,425
Depreciation and amortization	(403)	(366)
Operating income (loss)	86	1,131
Net income (loss)	18	698
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures	328	157
Corporate and Other
Segment Reporting Information [Line Items]
Total revenues	0	0
Depreciation and amortization	(15)	(17)
Operating income (loss)	(65)	(37)
Net income (loss)	(177)	(485)
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures	11	14
Eliminations
Segment Reporting Information [Line Items]
Total revenues	(1,040)	(2,146)
Depreciation and amortization	0	0
Operating income (loss)	0	0
Net income (loss)	0	0
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures	0	0
Retail
Segment Reporting Information [Line Items]
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures		1
Retail | Operating Segments
Segment Reporting Information [Line Items]
Total revenues	2,494	2,350
Depreciation and amortization	(23)	(29)
Operating income (loss)	568	(588)
Net income (loss)	561	(595)
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures	0	1
Texas
Segment Reporting Information [Line Items]
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures	268	102
Texas | Operating Segments
Segment Reporting Information [Line Items]
Total revenues	439	1,353
Depreciation and amortization	(132)	(130)
Operating income (loss)	(343)	569
Net income (loss)	(331)	584
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures	268	102
East
Segment Reporting Information [Line Items]
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures	39	23
East | Operating Segments
Segment Reporting Information [Line Items]
Total revenues	637	1,809
Depreciation and amortization	(192)	(161)
Operating income (loss)	(223)	744
Net income (loss)	(185)	745
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures	39	23
West
Segment Reporting Information [Line Items]
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures	4	2
West | Operating Segments
Segment Reporting Information [Line Items]
Total revenues	285	231
Depreciation and amortization	(21)	(15)
Operating income (loss)	163	47
Net income (loss)	164	52
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures	4	2
Sunset | Operating Segments
Segment Reporting Information [Line Items]
Total revenues	239	828
Depreciation and amortization	(20)	(14)
Operating income (loss)	8	425
Net income (loss)	7	424
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures	6	15
Asset Closure | Operating Segments
Segment Reporting Information [Line Items]
Total revenues	0	0
Depreciation and amortization	0	0
Operating income (loss)	(22)	(29)
Net income (loss)	(21)	(27)
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures	$ 0	$ 0

Supplementary Financial Infor_3

Supplementary Financial Information - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets	$ 0	$ 49
Unbilled receivables, current	618		$ 614
Depreciation expense	367	323
State and Local Jurisdiction
Impaired Long-Lived Assets Held and Used [Line Items]
Income taxes paid	3	1
Income tax refunds	$ 1	$ 7
Line of Credit | Vistra Operations Company LLC
Impaired Long-Lived Assets Held and Used [Line Items]
Debt instrument, interest rate during period	5.56%	4.70%
Kincaid | Sunset
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets		$ 49
Kincaid Generation, Property, Plant And Equipment | Sunset
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets		45
Kincaid Generation, Inventory | Sunset
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets		2
Kincaid Generation, Operating Lease Right-Of-Use Assets | Sunset
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets		$ 2

Supplementary Financial Infor_4

Supplementary Financial Information - Schedule of Interest Expense and Related Charges (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Supplementary Financial Information [Abstract]
Interest expense	$ 208	$ 156
Unrealized mark-to-market net (gains) losses on interest rate swaps	(47)	41
Amortization of debt issuance costs, discounts and premiums	7	6
Facility Fee expense	4	0
Debt extinguishment gain	(6)	0
Capitalized interest	(12)	(10)
Other	16	14
Total interest expense and related charges	$ 170	$ 207

Supplementary Financial Infor_5

Supplementary Financial Information - Schedule of Other Income and Deductions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Other income:
NDT net income	$ 35	$ 0
Insurance settlements	1	1
Gain on sale of land	1	0
Gain on TRA repurchases	10	0
Interest income	23	14
All other	21	5
Total other income	91	20
Other deductions:
All other	4	3
Total other deductions	$ 4	$ 3

Supplementary Financial Infor_6

Supplementary Financial Information - Schedule of Restricted Cash (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Cash and Cash Equivalents [Line Items]
Restricted cash included in current assets	$ 32	$ 40
Restricted cash included in noncurrent assets	14	14
Amounts related to remediation escrow accounts
Cash and Cash Equivalents [Line Items]
Restricted cash included in current assets	32	40
Restricted cash included in noncurrent assets	$ 14	$ 14

Supplementary Financial Infor_7

Supplementary Financial Information - Schedule of Accounts, Notes, Loans and Financing Receivable (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023	Jan. 01, 2023	Jan. 01, 2022
Accounts Receivable, before Allowance for Credit Loss, Current	$ 1,790		$ 1,735
Allowance for uncollectible accounts	(61)	$ (53)	(61)	$ (61)	$ (65)
Trade accounts receivable — net	1,729		1,674
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Allowance for uncollectible accounts receivable at beginning of period	61
Increase for bad debt expense	36	35
Decrease for account write-offs	(36)	(47)
Allowance for uncollectible accounts receivable at end of period	61	$ 53
Trade accounts receivable from contracts with customers — net
Trade accounts receivable — net	1,313		1,239
Other trade accounts receivable — net
Trade accounts receivable — net	$ 416		$ 435

Supplementary Financial Infor_8

Supplementary Financial Information - Schedule of Inventories by Major Category (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Inventories by Major Category
Materials and supplies	$ 507	$ 289
Fuel stock	443	420
Natural gas in storage	26	31
Total inventories	$ 976	$ 740

Supplementary Financial Infor_9

Supplementary Financial Information - Schedule of Investments (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Other Investments [Abstract]
Nuclear decommissioning trusts	$ 4,135	$ 1,951
Assets related to employee benefit plans	29	28
Land investments	42	42
Other investments	13	14
Total investments	$ 4,219	$ 2,035

Supplementary Financial Info_10

Supplementary Financial Information - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Property, Plant and Equipment [Line Items]
Total	$ 22,926	$ 18,028
Less accumulated depreciation	(6,962)	(6,657)
Net of accumulated depreciation	15,964	11,371
Finance lease right-of-use assets (net of accumulated depreciation)	165	160
Nuclear fuel (net of accumulated amortization of $169 million and $120 million)	1,151	379
Construction work in progress	734	522
Property, plant and equipment — net	18,014	12,432
Power generation and structures
Property, Plant and Equipment [Line Items]
Total	22,160	17,297
Land
Property, Plant and Equipment [Line Items]
Total	605	572
Office and other equipment
Property, Plant and Equipment [Line Items]
Total	161	159
Nuclear fuel
Property, Plant and Equipment [Line Items]
Less accumulated depreciation	$ (169)	$ (120)

Supplementary Financial Info_11

Supplementary Financial Information - Schedule of Other Noncurrent Liabilities and Deferred Credits (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Retirement and other employee benefits	$ 243	$ 247
Winter Storm Uri impact	25	26
Total identifiable intangible liabilities	183	131
Regulatory liability	322	209
Finance lease liabilities	231	227
Liability for third-party remediation	17	17
Accrued severance costs	36	36
Other accrued expenses	39	58
Total other noncurrent liabilities and deferred credits	$ 1,096	951
Nuclear Plant Decommissioning
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Regulatory liability		$ 209

Supplementary Financial Info_12

Supplementary Financial Information - Schedule of Fair Value of Debt (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Carrying Amount | Long-term debt under the Vistra Operations Credit Facilities
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value disclosure	$ 2,451	$ 2,456
Carrying Amount | Vistra Operations Senior Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value disclosure	11,130	11,881
Carrying Amount | Energy Harbor Secured Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value disclosure	413	0
Carrying Amount | Equipment Financing Agreements
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value disclosure	65	65
Carrying Amount | Vistra Zero Term Loan B Facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value disclosure	688	0
Fair Value | Long-term debt under the Vistra Operations Credit Facilities | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value disclosure	2,491	2,500
Fair Value | Vistra Operations Senior Notes | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value disclosure	11,022	11,752
Fair Value | Energy Harbor Secured Notes | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value disclosure	427	0
Fair Value | Equipment Financing Agreements | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value disclosure	63	62
Fair Value | Vistra Zero Term Loan B Facility | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, fair value disclosure	$ 700	$ 0

Supplementary Financial Info_13

Supplementary Financial Information - Schedule Of Cash, Cash Equivalents And Restricted Cash (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023	Mar. 31, 2023	Dec. 31, 2022
Text Block [Abstract]
Cash and cash equivalents	$ 1,070	$ 3,485
Restricted cash included in current assets	32	40
Restricted cash included in noncurrent assets	14	14
Total cash, cash equivalents and restricted cash	$ 1,116	$ 3,539	$ 573	$ 525

Supplementary Financial Info_14

Supplementary Financial Information - Schedule of Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Supplementary Financial Information [Abstract]
Interest paid	$ 214	$ 212
Capitalized interest	(12)	(10)
Interest paid (net of capitalized interest)	$ 202	$ 202