UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2024

— OR —

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __ to __

Commission File Number 001-38086

Vistra Corp.

(Exact name of registrant as specified in its charter)

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

Securities registered pursuant to Section 12(b) of the Act:

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

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

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

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

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

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

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

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.

Class	Outstanding as of May 3, 2024
Common stock, par value $0.01 per share	347,460,001

TABLE OF CONTENTS

				PAGE
Glossary of Terms and Abbreviations				i
Forward-Looking Statements				v
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
		Condensed Consolidated Statements of Operations — Three Months Ended March 31, 2024 and 2023		1
		Condensed Consolidated Statements of Comprehensive Income (Loss) — Three Months Ended March 31, 2024 and 2023		1
		Condensed Consolidated Statements of Cash Flows — Three Months Ended March 31, 2024 and 2023		2
		Condensed Consolidated Balance Sheets — March 31, 2024 and December 31, 2023		4
		Notes to Condensed Consolidated Financial Statements		7
			1. Business, Basis of Presentation and Significant Accounting Policies	7
			2. Business Combinations	9
			3. Retirement of Generation Facilities	11
			4. Revenue	12
			5. Income Taxes	14
			6. Earnings Per Share	15
			7. Goodwill and Identifiable Intangible Assets and Liabilities	16
			8. Accounts Receivable Financing	17
			9. Collateral Financing Agreement with Affiliate	18
			10. Debt	20
			11. Commodity and Other Derivative Contractual Assets and Liabilities	26
			12. Fair Value Measurements	29
			13. Tax Receivable Agreement Obligation	33
			14. Asset Retirement Obligations (ARO)	34
			15. Commitments and Contingencies	35
			16. Equity	44
			17. Segment Information	45
			18. Supplementary Financial Information	47
Item 2.	Management's Discussion and Analysis of Financial Condition, and Results of Operations			51
		Significant Activities and Events, and Items Influencing Future Performance		51
		Results of Operations		54
		Financial Condition		62
		Commitments and Contingencies		68
		Changes in Accounting Standards		68
Item 3.	Quantitative and Qualitative Disclosures About Market Risk			68
Item 4.	Controls and Procedures			71
PART II.	OTHER INFORMATION			72
Item 1.		Legal Proceedings		72
Item 1A.		Risk Factors		72
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds		73
Item 3.		Defaults Upon Senior Securities		74
Item 4.		Mine Safety Disclosures		74
Item 5.		Other Information		74
Item 6.		Exhibits		74
SIGNATURE				78

i

GLOSSARY OF TERMS AND ABBREVIATIONS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

Current and Former Related Entities:
Ambit	Ambit Holdings, LLC, and/or its subsidiaries (d/b/a Ambit), depending on context
Dynegy	Dynegy Inc., and/or its subsidiaries, depending on context
Dynegy Energy Services	Dynegy Energy Services, LLC and Dynegy Energy Services (East), LLC (each d/b/a Dynegy, Better Buy Energy, Brighten Energy, Honor Energy and True Fit Energy), indirect subsidiaries of Vistra, that are REPs in certain areas of MISO and PJM, respectively, and are engaged in the retail sale of electricity to residential and business customers.
Energy Harbor	Energy Harbor Holdings LLC (formerly known as Energy Harbor Corp.), and/or its subsidiaries, depending on context
Homefield Energy	Illinois Power Marketing Company (d/b/a Homefield Energy), an indirect subsidiary of Vistra, a REP in certain areas of MISO that is engaged in the retail sale of electricity to municipal customers
Luminant	subsidiaries of Vistra engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management
Parent	Vistra Corp.
Public Power	Public Power, LLC (d/b/a Public Power), an indirect subsidiary of Vistra, a REP in certain areas of PJM, ISO-NE, NYISO and MISO that is engaged in the retail sale of electricity to residential and business customers
TCEH	Texas Competitive Electric Holdings Company LLC, a direct, wholly owned subsidiary of Energy Future Competitive Holdings Company LLC, and, prior to the Effective Date, the parent company of our predecessor, depending on context, that were engaged in electricity generation and wholesale and retail energy market activities, and whose major subsidiaries included Luminant and TXU Energy
TriEagle Energy	TriEagle Energy, LP (d/b/a TriEagle Energy, TriEagle Energy Services, Eagle Energy, Energy Rewards, Power House Energy and Viridian Energy), an indirect subsidiary of Vistra, a REP in certain areas of ERCOT and PJM that is engaged in the retail sale of electricity to residential and business customers
TXU Energy	TXU Energy Retail Company LLC (d/b/a TXU), an indirect subsidiary of Vistra that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers
U.S. Gas & Electric	U.S. Gas and Electric, LLC (d/b/a USG&E, Illinois Gas & Electric and ILG&E), an indirect subsidiary of Vistra, a REP in certain areas of PJM, ISO-NE, NYISO and MISO that is engaged in the retail sale of electricity to residential and business customers
Value Based Brands	Value Based Brands LLC (d/b/a 4Change Energy, Express Energy and Veteran Energy), an indirect subsidiary of Vistra that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers
Vistra	Vistra Corp., and/or its subsidiaries, depending on context
Vistra Intermediate	Vistra Intermediate Company LLC, a direct, wholly owned subsidiary of Vistra
Vistra Operations	Vistra Operations Company LLC, an indirect, wholly owned subsidiary of Vistra that is the issuer of certain series of notes (see Note 10 to the Financial Statements) and borrower under the Vistra Operations Credit Facilities
Vistra Vision	Vistra Vision LLC, an indirect subsidiary of Vistra
Vistra Zero	Vistra Zero Operating Company, LLC, an indirect subsidiary of Vistra Vision LLC
Transmission System Operators:
CAISO	The California Independent System Operator
ERCOT	Electric Reliability Council of Texas, Inc.
ISO-NE	ISO New England Inc.
MISO	Midcontinent Independent System Operator, Inc.
NYISO	New York Independent System Operator, Inc.
PJM	PJM Interconnection, LLC
Authoritative Organizations:
EPA	U.S. Environmental Protection Agency

ii

FERC	U.S. Federal Energy Regulatory Commission
IEPA	Illinois Environmental Protection Agency
IPCB	Illinois Pollution Control Board
IRS	U.S. Internal Revenue Service
MSHA	U.S. Mine Safety and Health Administration
NRC	U.S. Nuclear Regulatory Commission
PUCT	Public Utility Commission of Texas
RCT	Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas, and has jurisdiction over oil and natural gas exploration and production, permitting and inspecting intrastate pipelines, and overseeing natural gas utility rates and compliance
SEC	U.S. Securities and Exchange Commission
TCEQ	Texas Commission on Environmental Quality
Rules and Regulations:
Exchange Act	Securities Exchange Act of 1934, as amended
IRA	Inflation Reduction Act of 2022
Securities Act	Securities Act of 1933, as amended
General Terms:
2023 Form 10-K	Vistra's annual report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 29, 2024
ARO	asset retirement and mining reclamation obligation
CCGT	combined cycle natural gas turbine
CCR	coal combustion residuals
CME	Chicago Mercantile Exchange
CO2	carbon dioxide
EBITDA	earnings (net income) before interest expense, income taxes, depreciation and amortization
Effective Date	October 3, 2016, the date our predecessor completed its reorganization under Chapter 11 of the U.S. Bankruptcy Code
Emergence	emergence of our predecessor from reorganization under Chapter 11 of the U.S. Bankruptcy Code as subsidiaries of a newly formed company, Vistra, on the Effective Date
ERP	enterprise resource program
ESS	energy storage system
GAAP	generally accepted accounting principles
GHG	greenhouse gas
GWh	gigawatt-hours
Heat Rate	Heat Rate is a measure of the efficiency of converting a fuel source to electricity
ISO	independent system operator
ITC	investment tax credit
load	demand for electricity
LTSA	long-term service agreements for plant maintenance
MMBtu	million British thermal units
MW	megawatts
MWh	megawatt-hours
NOX	nitrogen oxide
NYMEX	the New York Mercantile Exchange, a commodity derivatives exchange
Plan of Reorganization	Third Amended Joint Plan of Reorganization filed by the parent company of our predecessor in August 2016 and confirmed by the U.S. Bankruptcy Court for the District of Delaware in August 2016 solely with respect to our predecessor

iii

PrefCo Preferred Stock Sale	as part of the tax-free spin-off from Energy Future Holdings Corp. (EFH Corp.), executed pursuant to the Plan of Reorganization on the Effective Date by our predecessor, the contribution of certain of the assets of our predecessor and its subsidiaries by a subsidiary of TEX Energy LLC to Vistra Preferred, LLC (PrefCo) in exchange for all of PrefCo's authorized preferred stock, consisting of 70,000 shares, par value $0.01 per share
PTC	production tax credit
REP	retail electric provider
RTO	regional transmission organization
S&P	Standard & Poor's Ratings (a credit rating agency)
Series A Preferred Stock	Vistra's 8.0% Series A Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, $0.01 par value, with a liquidation preference of $1,000 per share
Series B Preferred Stock	Vistra's 7.0% Series B Fixed-Rate Reset Cumulative Green Redeemable Perpetual Preferred Stock, $0.01 par value, with a liquidation preference of $1,000 per share
Series C Preferred Stock	Vistra's 8.875% Series C Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Stock, $0.01 par value, with a liquidation preference of $1,000 per share
SO2	sulfur dioxide
SOFR	Secured Overnight Financing Rate, the average rate at which institutions can borrow U.S. dollars overnight while posting U.S. Treasury Bonds as collateral
Tax Matters Agreement	Tax Matters Agreement, dated as of the Effective Date, by and among EFH Corp., Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and EFH Merger Co. LLC
TRA	Tax Receivable Agreement, containing certain rights (TRA Rights) to receive payments from Vistra related to certain tax benefits, including benefits realized as a result of certain transactions entered into at Emergence (see Note 13 to the Financial Statements)
U.S.	United States of America
Vistra Operations Commodity-Linked Credit Agreement	Credit agreement, dated as of February 4, 2022 (as amended, restated, amended and restated, supplemented, and/or otherwise modified from time to time) by and among Vistra Operations, Vistra Intermediate, the lenders party thereto, the other credit parties thereto, the administrative agent, the collateral agent, and the other parties named therein
Vistra Operations Credit Agreement	Credit agreement, dated as of October 3, 2016 (as amended, restated, amended and restated, supplemented and/or otherwise modified from time to time), by and among Vistra Operations, Vistra Intermediate, the lenders party thereto, the letter of credit issuers party thereto, the administrative agent, the collateral agent, and the other parties named therein
Vistra Operations Credit Facilities	Vistra Operations senior secured financing facilities (see Note 10 to the Financial Statements)
Vistra Zero Credit Agreement	Credit agreement, dated as of March 26, 2024 (as amended, restated, amended and restated, supplemented and/or otherwise modified from time to time), by and among Vistra Zero, the lenders party thereto, the administrative agent, and collateral agent, and the other parties named therein

iv

FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10-Q contains "forward-looking statements" that involve risk and uncertainties. All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that may occur in the future, including (without limitation) such matters as activities related to our financial or operational projections, capital allocation, capital expenditures, liquidity, dividend policy, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our businesses and operations (often, but not always, through the use of words or phrases such as "intends," "plans," "potential," "will likely," "unlikely," "believe," "expect," "anticipated," "estimate," "should," "could," "may," "projection," "forecast," "target," "goal," "objective" and "outlook"), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and risks and is qualified in its entirety by reference to the discussion in (i) Item 1A. Risk Factors and Item 7. Management's Discussion and Analysis of Financial Condition, and Results of Operations in our 2023 Form 10-K and (ii) in Part I, Item 2 Management's Discussion and Analysis of Financial Condition, and Results of Operations in this quarterly report on Form 10-Q, that could cause our actual results to differ materially from those projected in or implied by such forward-looking statements:

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

v

PART I. FINANCIAL INFORMATION

Item 1.FINANCIAL STATEMENTS

VISTRA CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited) (Millions of Dollars, Except Share Data)

	Three Months Ended March 31,
	2024		2023
Operating revenues (Note 4)	$	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 (Note 18)	—		(49)
Operating income	86		1,131
Other income (Note 18)	91		20
Other deductions (Note 18)	(4)		(3)
Interest expense and related charges (Note 18)	(170)		(207)
Impacts of Tax Receivable Agreement (Note 13)	(5)		(65)
Net income (loss) before income taxes	(2)		876
Income tax (expense) benefit (Note 5)	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:
Basic	348,966,197		383,631,369
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

See Notes to the Condensed Consolidated Financial Statements.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited) (Millions of Dollars)

	Three Months Ended March 31,
	2024		2023
Net income	$	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 $—)	—		1
Total other comprehensive income	—		1
Comprehensive income	$	18	$	699
Comprehensive (income) loss attributable to noncontrolling interest	(53)		1
Comprehensive income (loss) attributable to Vistra	$	(35)	$	700

See Notes to the Condensed Consolidated Financial Statements.

1

VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars)
	Three Months Ended March 31,
	2024		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	—		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)		—
Asset retirement obligation accretion expense	19		9
Impacts of Tax Receivable Agreement	5		65
Gain on TRA repurchase and tender offers	(10)		—
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)		—
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	—		1
Cash used in investing activities	(3,528)		(513)
Cash flows — financing activities:
Issuances of long-term debt	700		—
Repayments/repurchases of debt	(756)		(7)
Net borrowings under accounts receivable financing	875		175
Borrowings under Revolving Credit Facility	—		100
Repayments under Revolving Credit Facility	—		(350)
Borrowings under Commodity-Linked Facility	500		—
Repayments under Commodity-Linked Facility	—		(400)
Stock repurchases	(291)		(301)
Dividends paid to common stockholders	(77)		(77)
TRA Repurchase and tender offer — return of capital	(122)		—
Other, net	(36)		(14)
Cash provided by (used in) financing activities	793		(874)

2

VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars)
	Three Months Ended March 31,
	2024		2023
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

See Notes to the Condensed Consolidated Financial Statements.

3

VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars, Except Share Data)
	March 31, 2024		December 31, 2023
ASSETS
Current assets:
Cash and cash equivalents	$	1,070	$	3,485
Restricted cash (Note 18)	32		40
Trade accounts receivable — net (Note 18)	1,729		1,674
Income taxes receivable	1		6
Inventories (Note 18)	976		740
Commodity and other derivative contractual assets (Note 11)	3,557		3,645
Margin deposits related to commodity contracts	1,186		1,244
Margin deposits posted under affiliate financing agreement (Note 9)	443		439
Prepaid expense and other current assets	439		364
Total current assets	9,433		11,637
Restricted cash (Note 18)	14		14
Investments (Note 18)	4,219		2,035
Property, plant and equipment — net (Note 18)	18,014		12,432
Operating lease right-of-use assets	62		50
Goodwill (Note 7)	2,877		2,583
Identifiable intangible assets — net (Note 7)	2,278		1,864
Commodity and other derivative contractual assets (Note 11)	703		577
Accumulated deferred income taxes	—		1,223
Other noncurrent assets	578		551
Total assets	$	38,178	$	32,966
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (Note 10)	$	500	$	—
Accounts receivable financing (Note 8)	875		—
Long-term debt due currently (Note 10)	54		2,286
Trade accounts payable	1,100		1,147
Commodity and other derivative contractual liabilities (Note 11)	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 (Note 14)	119		124
Operating lease liabilities	11		7
Other current liabilities	461		547
Total current liabilities	8,775		9,823
Margin deposits financing with affiliate (Note 9)	443		439
Long-term debt, less amounts due currently (Note 10)	14,693		12,116
Operating lease liabilities	56		48
Commodity and other derivative contractual liabilities (Note 11)	1,892		1,688
Accumulated deferred income taxes	118		1
Tax Receivable Agreement obligation (Note 13)	15		164
Asset retirement obligations (Note 14)	3,806		2,414

4

VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars, Except Share Data)
	March 31, 2024		December 31, 2023
Other noncurrent liabilities and deferred credits (Note 18)	1,096		951
Total liabilities	30,894		27,644
Commitments and Contingencies (Note 15)
Total equity (Note 16):
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

See Notes to the Condensed Consolidated Financial Statements.

5

VISTRA CORP. CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (Millions of Dollars)
	Preferred Stock		Common Stock		Treasury Stock		Additional Paid-In Capital		Retained Deficit		Accumulated Other Comprehensive Income (Loss)		Total Stockholders' Equity		Noncontrolling Interest in Subsidiary		Total Equity
Balances at December 31, 2023	$	2,476	$	5	$	(4,662)	$	10,095	$	(2,613)	$	6	$	5,307	$	15	$	5,322
Stock repurchases	—		—		(285)		—		—		—		(285)		—		(285)
Effects of stock-based incentive compensation plans	—		—		—		35		—		—		35		—		35
Equity issued in subsidiary to acquire Energy Harbor (a)	—		—		—		747		—		—		747		1,560		2,307
Net income (loss)	—		—		—		—		(35)		—		(35)		53		18
Dividends declared on common stock	—		—		—		—		(77)		—		(77)		—		(77)
Dividends declared on preferred stock	—		—		—		—		(37)		—		(37)		—		(37)
Other	—		—		—		1		—		—		1		—		1
Balances at March 31, 2024	$	2,476	$	5	$	(4,947)	$	10,878	$	(2,762)	$	6	$	5,656	$	1,628	$	7,284

____________

(a)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.

See Notes to the Condensed Consolidated Financial Statements.

VISTRA CORP. CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (CONTINUED) (Millions of Dollars)
	Preferred Stock		Common Stock		Treasury Stock		Additional Paid-In Capital		Retained Deficit		Accumulated Other Comprehensive Income (Loss)		Total Stockholders' Equity		Noncontrolling Interest in Subsidiary		Total Equity
Balances at December 31, 2022	$	2,000	$	5	$	(3,395)	$	9,928	$	(3,643)	$	7	$	4,902	$	16	$	4,918
Stock repurchases	—		—		(311)		—		—		—		(311)		—		(311)
Effects of stock-based incentive compensation plans	—		—		—		24		—		—		24		—		24
Net income (loss)	—		—		—		—		699		—		699		(1)		698
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
Balances at March 31, 2023	$	2,000	$	5	$	(3,706)	$	9,952	$	(3,058)	$	8	$	5,201	$	15	$	5,216

See Notes to the Condensed Consolidated Financial Statements.

6

VISTRA CORP.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.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.

7

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.

8

2.    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.

9

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

10

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.

3.    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.

11

4.    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 Closure		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.

12

	Three Months Ended March 31, 2023
(in millions)	Retail		Texas		East		West		Sunset		Asset Closure		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.

13

5.    INCOME TAXES

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

Income Tax (Expense) Benefit

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

	Three Months Ended March 31,
(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.

14

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.

6.    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.

15

7.    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 Amortization		Net		Gross Carrying Amount		Accumulated Amortization		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, 2024		December 31, 2023
LTSA	$	121	$	122
Power and fuel purchase contracts	62		9
Total identifiable intangible liabilities	$	183	$	131

16

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 (in millions)
2024	$	167
2025	$	141
2026	$	77
2027	$	49
2028	$	32

8.    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.

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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.

9.    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.

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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.

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10.    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, 2024		December 31, 2023
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

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(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.

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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 Limit		Cash Borrowings (Short-Term)		Cash Borrowings (Long-Term)		Letters of Credit Outstanding		Available Capacity
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.

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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.

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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.

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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.

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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.

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11.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.

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	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.

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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 and Liabilities		Offsetting Instruments (a)		Cash Collateral (Received) Pledged (b)		Net Amounts		Derivative Assets and Liabilities		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.

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

(in millions)	March 31, 2024		December 31, 2023
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.

This concentration of credit risk increases the risk that a default by any of our counterparties could have a material effect on our financial condition, results of operations and liquidity. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize specific risk mitigation procedures including, but not limited to, (i) requiring counterparties to have investment grade credit ratings, (ii) use of standardized master agreements with our counterparties that allow for netting of positive and negative exposures, and that detail credit enhancements (such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits) required in the event of a material downgrade in their credit rating.

12.    FAIR VALUE MEASUREMENTS

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

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

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

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

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

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Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

	March 31, 2024										December 31, 2023
(in millions)	Level 1		Level 2		Level 3		Reclass (a)		Total		Level 1		Level 2		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.

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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.

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(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.

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

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13.    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.

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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

14.    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 Plant Decommissioning		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.

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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.

15.    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.

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Litigation

Natural Gas Index Pricing Litigation — We, through our subsidiaries, and another company remain named as defendants in one consolidated putative class action lawsuit pending in federal court in Wisconsin claiming damages resulting from alleged price manipulation through false reporting of natural gas prices to various index publications, wash trading and churn trading from 2000-2002. The plaintiffs in these cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices during the relevant time period and seek damages under the respective state antitrust statutes. In April 2023, the U.S. Court of Appeals for the Seventh Circuit (Seventh Circuit Court) heard oral argument on an interlocutory appeal challenging the district court's order certifying a class.

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.

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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 CO2 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 CO2 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.

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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 SO2, the rule established an intrastate Texas emission allowance trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program. 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 NOX, 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 SO2 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.

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SO2 Designations for Texas

In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Martin Lake generation plant and our now retired Big Brown and Monticello plants. The final designations require Texas to develop nonattainment plans for these areas. 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 SO2 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 SO2 for the area around Martin Lake. As a result of this decision the EPA's nonattainment designation - originally made in 2016 - remains in place. 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.

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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.

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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 under the requirements of the newly implemented Illinois Coal Ash regulation (discussed below) and close the site by removal. In addition, the interim consent order requires that during the impoundment closure process, impacted groundwater will be collected before it leaves the site or enters the nearby Vermilion river and, if necessary, DMG will be required to install temporary riverbank protection if the river migrates within a certain distance of the impoundments. The interim order was modified in December 2022 to require certain amendments to the Safety Emergency Response Plan. In June 2023, the Illinois state court approved and entered the final consent order, which included the terms above and a requirement that when IEPA issues a final closure permit for the site, DMG will demolish the power station and submit for approval to construct an on-site landfill within the footprint of the former plant to store and manage the coal ash. These proposed closure costs are reflected in the ARO in our condensed consolidated balance sheets (see Note 18).

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

In July 2019, coal ash disposal and storage legislation in Illinois was enacted. The legislation addresses state requirements for the proper closure of coal ash ponds in the state of Illinois. The law tasks the IEPA and the IPCB to set up a series of guidelines, rules and permit requirements for closure of ash ponds. Under the final rule, which was finalized and became effective in April 2021, coal ash impoundment owners would be required to submit a closure alternative analysis to the IEPA for the selection of the best method for coal ash remediation at a particular site. The rule does not mandate closure by removal at any site. In May 2021, we, along with other industry petitioners, filed an appeal in the Illinois Fourth Judicial District over certain provisions of the final rule. In March 2024, the Illinois Fourth Judicial District issued a decision denying the industry petitions. We do not anticipate any impacts from this decision. In October 2021, we filed operating permit applications for 18 impoundments as required by the Illinois coal ash rule, and filed construction permit applications for three of our sites in January 2022 and five of our sites in July 2022. One additional closure construction application was filed for our Baldwin facility in August 2023.

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For all of the above matters, if certain corrective action measures, including groundwater treatment or removal of ash, are required at any of our coal-fueled facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows. The Illinois coal ash rule was finalized in April 2021 and does not require removal. However, the rule required us to undertake further site-specific evaluations required by each program. We will not know the full range of decommissioning costs, including groundwater remediation, if any, that ultimately may be required under the Illinois rule until permit applications have been approved by the IEPA and as such, an estimate of such costs cannot be made. The CCR surface impoundment and landfill closure costs currently reflected in our existing ARO liabilities reflect the costs of closure methods that our operations and environmental services teams determined were appropriate based on then existing closure requirements, and is reasonably possible to increase once the IEPA determines final closure requirements. Once the IEPA acts on our permit applications, we will reassess the decommissioning costs and adjust our ARO liabilities accordingly.

MISO 2015-2016 Planning Resource Auction

In May 2015, three complaints were filed at the FERC regarding the Zone 4 results for the 2015-2016 planning resource auction (PRA) conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc., the Illinois Attorney General and Southwestern Electric Cooperative, Inc. (Complainants), challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO planning resource auction structure going forward. Complainants also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the PRA. The Independent Market Monitor for MISO (MISO IMM), which was responsible for monitoring the PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the remedies sought by the Complainants. We filed our answer to these complaints explaining that we complied fully with the terms of the MISO tariff in connection with the PRA and disputing the allegations. The Illinois Industrial Energy Consumers filed a related complaint at the FERC against MISO in June 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this complaint with respect to Dynegy's conduct alleged in the complaint.

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

In December 2015, the FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff provisions effective as of the 2016-2017 planning resource auction. The order did not address the arguments of the Complainants regarding the PRA and stated that those issues remained under consideration and would be addressed in a future order.

In July 2019, the FERC issued an order denying the remaining issues raised by the complaints and noted that the investigation into Dynegy was closed. The FERC found that Dynegy's conduct did not constitute market manipulation and the results of the PRA were just and reasonable because the PRA was conducted in accordance with MISO's tariff. A request for rehearing was denied by the FERC in March 2020. The order was appealed by Public Citizen, Inc. to the D.C. Circuit Court in May 2020, and Vistra, Dynegy and Illinois Power Marketing Company intervened in the case in June 2020. In August 2021, the D.C. Circuit Court issued a ruling denying Public Citizen, Inc.'s arguments that the FERC failed to meet its obligation to ensure just and reasonable rates because it did not review the prices resulting from the auction before those prices went into effect and that the FERC was arbitrary and capricious in failing to adequately explain its decision to close its investigation into whether Dynegy engaged in market manipulation. The D.C. Circuit Court of Appeals granted Public Citizen, Inc.'s petition in part finding that the FERC's decision that the auction results were just and reasonable solely because the auction process complied with the filed tariff was unreasoned and remanded the case back to the FERC for further proceedings on that issue. On February 4, 2022 the Illinois Attorney General and Public Citizen, Inc. filed a motion at the FERC requesting that the FERC on remand reverse its prior decision and either find that auction results were not just and reasonable and order Dynegy to pay refunds to Illinois or, in the alternative, initiate an evidentiary hearing and discovery. We filed a response to this motion and will continue to vigorously defend our position. In June 2022, the FERC issued an order on remand establishing paper hearing procedures and directing the Office of Enforcement to file a remand report within 90 days providing the Office of Enforcement's assessment of Dynegy's actions with regard to the 2015-2016 planning resource auction. Although the FERC directed the Office of Enforcement to file a remand report, the FERC stated in the June 2022 order that it is not reopening the Office of Enforcement investigation. In September 2022, the Office of Enforcement filed its remand report stating that the Office of Enforcement staff found during its investigation that Dynegy knowingly engaged in manipulative behavior to set the Zone 4 price in the 2015-2016 PRA. In June 2023, the Company filed its initial brief and response to the remand report, and in August 2023 the Company filed a reply to the initial briefs from other parties. We will continue to vigorously defend our position.

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Other Matters

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

Nuclear Insurance

Nuclear insurance includes nuclear liability coverage, property damage, nuclear accident decontamination and accidental premature decommissioning coverage and accidental outage and/or extra expense coverage. We maintain nuclear insurance that meets or exceeds requirements promulgated by Section 170 (Price-Anderson) of the Atomic Energy Act (the Act) and Title 10 of the Code of Federal Regulations. We intend to maintain insurance against nuclear risks as long as such insurance is available. We are self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Any such self-insured losses could have a material adverse effect on our results of operations, liquidity or financial condition.

With regard to nuclear liability coverage, the Act provides for financial protection for the public in the event of a significant nuclear generation plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $16.2 billion and requires nuclear generation plant operators to provide financial protection for this amount. However, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims that exceed the $16.2 billion limit for a single incident. As required, we insure against a possible nuclear incident at our nuclear facilities resulting in public nuclear-related bodily injury and property damage through a combination of private insurance and an industry-wide retrospective payment plan known as Secondary Financial Protection (SFP).

Under the SFP, in the event of any single nuclear liability loss in excess of $500 million at any nuclear generation facility in the U.S., each operating licensed reactor in the U.S. is subject to an assessment of up to $165.9 million. This approximately $165.9 million maximum assessment is subject to increases for inflation every five years, with the next expected adjustment scheduled to occur by November 2028. Assessments are currently limited to $24.7 million per operating licensed reactor per year per incident. As of March 31, 2024, our maximum potential assessment under the industry retrospective plan would be approximately $995.4 million per incident but no more than $148.2 million in any one year for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $500 million per accident at any nuclear facility.

The United States Nuclear Regulatory Commission (NRC) requires that nuclear generation plant license holders maintain at least $1.06 billion of nuclear accident decontamination and reactor damage stabilization insurance, and requires that the proceeds thereof be used to place a plant in a safe and stable condition, to decontaminate a plant pursuant to a plan submitted to, and approved by, the NRC prior to using the proceeds for plant repair or restoration, or to provide for premature decommissioning. We maintain nuclear accident decontamination and reactor damage stabilization insurance for our Comanche Peak facility in the amount of $2.25 billion and non-nuclear accident related property damage in the amount of $1.0 billion (subject to a $5 million deductible per accident except for natural hazards which are subject to a $9.5 million deductible per accident), and losses excluded or above such limits are self-insured. We maintain nuclear accident decontamination and reactor damage stabilization insurance and non-nuclear accident related property damage for our Beaver Valley, Davis-Besse and Perry facilities in the amount of $1.5 billion (subject to a $20 million deductible per accident), and losses excluded or above such limits are self-insured.

We also maintain Accidental Outage insurance to help cover the additional costs of obtaining replacement electricity from another source if the units are out of service for more than twelve weeks as a result of covered direct physical damage. Coverage at Comanche Peak provides for weekly payments per unit up to $4.5 million for the first 52 weeks and up to $2.7 million for a remaining 21 weeks for non-nuclear and up to $3.6 million for a remaining 71 weeks for nuclear property damage outages. The total maximum coverage is $291 million for non-nuclear property damage and $490 million for nuclear property damage outages. Coverage at Beaver Valley, Davis-Besse and Perry facilities provide for weekly payments per unit up to $2.5 million for the first 52 weeks and up to $1.5 million for a remaining 52 weeks for non-nuclear and up to $2 million for a remaining 110 weeks for nuclear property damage outages. The total maximum coverage is $208 million for non-nuclear property damage and $350 million for nuclear damage outages. There are two units at Comanche Peak and Beaver Valley, and coverage amounts applicable to each unit will reduce to 80% if both units are out of service at the same time as a result of the same accident.

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16.    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.

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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.

17.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.

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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).

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18.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.

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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, 2024		December 31, 2023
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, 2024		December 31, 2023
Materials and supplies	$	507	$	289
Fuel stock	443		420
Natural gas in storage	26		31
Total inventories	$	976	$	740

Investments

(in millions)	March 31, 2024		December 31, 2023
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

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Property, Plant and Equipment

(in millions)	March 31, 2024		December 31, 2023
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, 2024		December 31, 2023
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 Value		Carrying Amount		Fair Value
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.

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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, 2024		December 31, 2023
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.

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

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

Significant Activities and Events and Items Influencing Future Performance

Merger with Energy Harbor

On March 1, 2024 (Merger Date), pursuant to a transaction agreement dated March 6, 2023 (Transaction Agreement), (i) Vistra Operations transferred certain of its subsidiary entities into Vistra Vision, (ii) Black Pen Inc., a wholly owned subsidiary of Vistra, merged with and into Energy Harbor, (iii) Energy Harbor became a wholly-owned subsidiary of Vistra Vision, and (iv) affiliates of Nuveen 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 cash consideration for Energy Harbor Merger was funded by Vistra Operations using a combination of cash on hand and borrowings under the Commodity-Linked Facility, the Receivables Facility and the Repurchase Facility. See Note 2 to the Financial Statements for more information concerning the Energy Harbor Merger.

Inflation Reduction Act of 2022

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.

Repurchase of TRA Rights and Preferred Stock Issuance

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."

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During December 2023, we repurchased approximately 317 million 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.

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.

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.

As of March 31, 2024, we have repurchased an aggregate 98% of the initial issuance of TRA Rights upon Emergence, of which 8,195,063 TRA Rights remain outstanding. See Note 13 to the Financial Statements for details of the TRA and Note 16 to the Financial Statements for details of the Series C Preferred Stock.

Macroeconomic Conditions

Historically, the base case assumption for U.S. electricity demand was for modest growth driven by the interplay of growth in population, industrial activity and new demand sources (like electric vehicles), partially offset by continued advancements in energy efficiency. Multiple demand drivers such as emergence of large load data centers and electrification of oil field operations (specifically the Permian Basin of west Texas), have accelerated load growth in the geographic regions we serve. We continue to monitor the impact of load growth on electricity demand and our operations.

The industry continues to experience supply chain constraints and labor shortages that have reduced the availability of certain equipment and supply relevant to construction of renewables projects, and increased (i) the lead time to procure certain materials necessary to maintain, and (ii) the labor costs associated with maintenance activity on our natural gas, nuclear and coal fleet. We are proactively managing the increased costs of materials and supply chain disruptions and continuing to prudently re-evaluate the business cases and timing of our planned development projects, which has resulted in a deferral of some of our planned capital spend for our renewables projects. In addition, we have proactively engaged our suppliers to secure key materials needed to maintain our existing generation facilities prior to future planned outages, and our Vistra Zero operational and development projects are anticipated to benefit from the impact of the IRA. The inflationary environment continues to drive elevated interest rates, resulting in increased refinancing or borrowing costs, including recently completed and expected future non-recourse financing for our development projects, recently completed corporate debt refinancing activities, and refinancing expected in connection with debt due in 2025 and beyond.

We are closely monitoring developments in the Russia and Ukraine conflict, specifically with regards to, (i) sanctions (or potential sanctions) against Russian energy exports and Russian nuclear fuel supply and enrichment activities, and (ii) actions by Russia to limit energy deliveries, which may further impact commodity prices in Europe and globally. On April 30, 2024, the Prohibiting Russian Uranium Imports Act (PRUI Act) was approved by Congress and is expected to be submitted to and signed by President Biden. The PRUI Act would become effective 90 days after the President's signature. If the PRUI Act becomes effective, it would prohibit importation of Russian uranium; however, the Department of Energy can issue waivers (subject to decreasing annual caps) until 2027 if there is no alternate source of low-enriched uranium available to keep U.S. nuclear reactors operating or is in the national interest. Additionally, the PRUI Act would release $2.72 billion in federal funding to ramp up production of domestic uranium fuel. We are monitoring the status of the PRUI Act and evaluating the potential impacts of the PRUI Act on our operations. Our 2024 refueling plans have not been affected by the Russia and Ukraine conflict, nor have we seen any disruption to the delivery of nuclear fuel. We are taking affirmative action by building strategic inventory and deploying mitigating strategies in our procurement portfolio to ensure we can secure the nuclear fuel needed to continue to operate our nuclear facility through potential Russian supply disruption. We work with a diverse set of global nuclear fuel cycle suppliers to procure our nuclear fuel years in advance, and therefore, we have enough nuclear fuel contracted to support all our refueling needs, including the Energy Harbor facilities acquired, through 2027.

52

Critical Accounting Policies and Estimates

The Company's discussion and analysis of its financial position and results of operations is based upon its condensed consolidated financial statements. The preparation of these condensed consolidated financial statements requires estimation and judgment that affect the reported amounts of revenue, expenses, assets and liabilities. The Company bases its estimates on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the accounting for assets and liabilities that are not readily apparent from other sources. If the estimates differ materially from actual results, the impact on the condensed consolidated financial statements may be material. Except as discussed below, the Company's critical accounting policies are disclosed in our 2023 Form 10-K.

Business Combinations

Determining fair values of assets acquired and liabilities assumed in the Energy Harbor Merger requires significant estimates and judgments. We determine fair value based on the estimated price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. See Note 2 to the Financial Statements. The acquired assets and liabilities that involved the most subjectivity in determining fair value consisted of property, plant and equipment and asset retirement obligations:

Property, Plant and Equipment

The fair value of each power plant acquired was estimated using a combination of an income approach and a market approach. The income approach is based on the discounted cash flow method that uses (i) our estimates of forecasted future growth and long term prices of electricity, capacity and nuclear fuel, and (ii) financial performance including revenues, gross margins, operating expenses, and taxes, as well as working capital and capital asset requirements. Projected cash flows are then discounted to a present value employing a discount rate that properly accounts for the estimated market weighted-average cost of capital, as well as any risks unique to the subject cash flows. These estimates are subjective in nature and require judgement to interpret market data. The market valuation method used prices paid for a reasonably similar asset by other purchasers in the relevant market, with adjustments relating to physical differences in the asset as well as their locations.

Nuclear Decommissioning Asset Retirement Obligation

To estimate our nuclear decommissioning asset retirement obligation on assets acquired from Energy Harbor, we used a discounted cash flow model based on our estimates of cost escalation factors and discount rates, and considered multiple decommissioning scenarios: (i) DECON, which assumes major decommissioning activities begin shortly after the facility ceases operations, and (ii) SAFSTOR, which assumes the nuclear facility is placed and maintained in a condition during decommissioning that allows the nuclear facility to be safely stored until subsequently decontaminated within 60 years after the facility ceases operations. The probability-weighted estimated future cash flows were discounted using our specific credit-adjusted, risk-free rates which reflected the secured nature of the obligation due to acquired investments in NDTs which are intended to fund the future decommissioning obligations.

53

RESULTS OF OPERATIONS

Net income decreased $680 million to Net income of $18 million for the three months ended March 31, 2024 compared to the three months ended March 31, 2023. For additional information see the following discussion of our results of operations.

EBITDA and Adjusted EBITDA

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

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

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

54

Vistra Consolidated Financial Results — Three Months Ended March 31, 2024 Compared to the Three Months Ended March 31, 2023

The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the three months ended March 31, 2024:

	Three Months Ended March 31, 2024
(in millions)	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	2,494	$	439	$	637	$	285	$	239	$	—	$	(1,040)	$	3,054
Fuel, purchased power costs and delivery fees	(1,647)		(368)		(526)		(80)		(134)		(1)		1,040		(1,716)
Operating costs	(31)		(248)		(124)		(16)		(66)		(12)		(1)		(498)
Depreciation and amortization	(23)		(132)		(192)		(21)		(20)		—		(15)		(403)
Selling, general and administrative expenses	(225)		(34)		(18)		(5)		(11)		(9)		(49)		(351)
Operating income (loss)	568		(343)		(223)		163		8		(22)		(65)		86
Other income	—		3		39		1		—		3		45		91
Other deductions	(1)		(1)		—		—		(1)		(1)		—		(4)
Interest expense and related charges	(6)		10		(1)		—		—		(1)		(172)		(170)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(5)		(5)
Income (loss) before income taxes	561		(331)		(185)		164		7		(21)		(197)		(2)
Income tax benefit	—		—		—		—		—		—		20		20
Net income (loss)	$	561	$	(331)	$	(185)	$	164	$	7	$	(21)	$	(177)	$	18
Income tax benefit	—		—		—		—		—		—		(20)		(20)
Interest expense and related charges (a)	6		(10)		1		—		—		1		172		170
Depreciation and amortization (b)	23		158		215		21		20		—		16		453
EBITDA before Adjustments	590		(183)		31		185		27		(20)		(9)		621
Unrealized net (gain) loss resulting from commodity hedging transactions	(623)		584		193		(129)		155		(4)		—		176
Purchase accounting impacts	(2)		—		(2)		—		—		—		(14)		(18)
Impacts of Tax Receivable Agreement (c)	—		—		—		—		—		—		(5)		(5)
Non-cash compensation expenses	—		—		—		—		—		—		21		21
Transition and merger expenses	1		—		4		—		—		—		28		33
Decommissioning-related activities (d)	—		5		(26)		—		2		—		—		(19)
ERP system implementation	—		—		—		—		—		—		6		6
Other, net	6		5		1		3		—		1		(41)		(25)
Adjusted EBITDA	$	(28)	$	411	$	201	$	59	$	184	$	(23)	$	(14)	$	790

____________

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

(b)Includes nuclear fuel amortization of $26 million and $23 million, respectively, in Texas and East segments.

(c)Includes $10 million gain recognized on the repurchase of TRA Rights in the three months ended March 31, 2024 (see Note 13 to the Financial Statements).

(d)Represents net of all NDT income (loss), ARO accretion expense for operating assets and ARO remeasurement impacts for operating assets.

55

The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the three months ended March 31, 2023:

	Three Months Ended March 31, 2023
(in millions)	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	2,350	$	1,353	$	1,809	$	231	$	828	$	—	$	(2,146)	$	4,425
Fuel, purchased power costs and delivery fees	(2,690)		(395)		(820)		(148)		(262)		(1)		2,146		(2,170)
Operating costs	(28)		(228)		(65)		(15)		(65)		(20)		—		(421)
Depreciation and amortization	(29)		(130)		(161)		(15)		(14)		—		(17)		(366)
Selling, general and administrative expenses	(191)		(31)		(19)		(6)		(13)		(8)		(20)		(288)
Impairment of long-lived assets	—		—		—		—		(49)		—		—		(49)
Operating income (loss)	(588)		569		744		47		425		(29)		(37)		1,131
Other income	—		12		1		1		1		3		2		20
Other deductions	—		(1)		—		—		(1)		—		(1)		(3)
Interest expense and related charges	(7)		4		—		4		(1)		(1)		(206)		(207)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(65)		(65)
Income (loss) before income taxes	(595)		584		745		52		424		(27)		(307)		876
Income tax expense	—		—		—		—		—		—		(178)		(178)
Net income (loss)	$	(595)	$	584	$	745	$	52	$	424	$	(27)	$	(485)	$	698
Income tax expense	—		—		—		—		—		—		178		178
Interest expense and related charges (a)	7		(4)		—		(4)		1		1		206		207
Depreciation and amortization (b)	29		153		161		15		14		—		17		389
EBITDA before Adjustments	(559)		733		906		63		439		(26)		(84)		1,472
Unrealized net (gain) loss resulting from commodity hedging transactions	559		(346)		(923)		(18)		(340)		(17)		—		(1,085)
Generation plant retirement expenses	—		—		—		—		—		—		1		1
Fresh start/purchase accounting impacts	1		(1)		2		—		1		—		—		3
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		65		65
Non-cash compensation expenses	—		—		—		—		—		—		22		22
Transition and merger expenses	(2)		—		—		—		1		—		2		1
Impairment of long-lived assets	—		—		—		—		49		—		—		49
PJM capacity performance default impacts (c)	—		—		14		—		6		—		—		20
Winter Storm Uri impacts (d)	(34)		1		—		—		—		—		—		(33)
Other, net	6		(4)		2		1		8		2		(17)		(2)
Adjusted EBITDA	$	(29)	$	383	$	1	$	46	$	164	$	(41)	$	(11)	$	513

____________

(a)Includes $41 million of unrealized mark-to-market net losses on interest rate swaps.

(b)Includes nuclear fuel amortization of $23 million in Texas segment.

(c)Represents estimate of anticipated market participant defaults or settlements on initial PJM capacity performance penalties due to extreme magnitude of penalties associated with Winter Storm Elliott.

(d)Adjusted EBITDA impacts of Winter Storm Uri reflects the application of bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri and a reduction in the allocation of ERCOT default uplift charges which were expected to be paid over several decades under protocols existing at the time of the storm.

56

GAAP operating income decreased $1.045 billion to operating income of $86 million in the three months ended March 31, 2024 compared to the three months ended March 31, 2023. The primary driver for the decrease is a $1.261 billion change in unrealized mark-to-market activity as results for the three months ended March 31, 2024 were unfavorably impacted by $176 million in pre-tax unrealized mark-to-market losses on derivative positions due to power and natural gas forward market curves moving up in the three months ended March 31, 2024 compared to $1.085 billion in pre-tax unrealized mark-to-market gains on commodity derivative positions due to power and natural gas forward market curves moving down in the three months ended March 31, 2023. See further information on our derivative results in Energy-Related Commodity Contracts and Mark-to-Market Activities below.

In addition to the mark-to-market impacts discussed above, operating results for the three months ended March 31, 2024, compared to the three months ended March 31, 2023 were impacted by additional factors including:

Favorable impacts:

•Expiration of contracts in the East segment which resulted in higher-than-expected migration of customers to default service providers at rates below prevailing wholesale market prices in the three months ended March 31, 2023.

•Addition of Energy Harbor in March 2024 with results reflected in the East and Retail segments.

Unfavorable impacts:

•Decreases in capacity revenues primarily in the Sunset segment.

•Increase in selling, general and administrative expenses in Retail and Corp driven primarily by the addition of Energy Harbor.

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

	Three Months Ended March 31,
	Retail				Texas				East				West				Sunset
	2024		2023		2024		2023		2024		2023		2024		2023		2024		2023
Retail sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT	16,074		14,982
Sales volumes in Northeast/Midwest	10,261		5,830
Total retail electricity sales volumes	26,335		20,812
Production volumes (GWh):
Natural gas facilities					8,151		6,225		14,762		14,585		1,228		1,543
Lignite and coal facilities					4,797		4,971										3,551		3,516
Nuclear facilities					5,008		5,227		2,329
Solar facilities					156		154
Capacity factors:
CCGT facilities					43.8	%	35.0	%	61.5	%	62.2	%	55.0	%	70.1	%
Lignite and coal facilities					57.1	%	59.7	%									35.5	%	35.6	%
Nuclear facilities					95.6	%	100.9	%	77.4	%
Weather - percent of normal (a):
Heating degree days	90	%	83	%	93	%	81	%	87	%	84	%	117	%	149	%	88	%	87	%

____________

(a)Reflects heating degree days for the region based on Weather Services International (WSI) data.

57

	Three Months Ended March 31,					Three Months Ended March 31,
	2024		2023			2024		2023
Market pricing					Average Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)	$	21.66	$	21.98	PJM West Hub	$	36.03	$	36.35
					AEP Dayton Hub	$	33.11	$	33.65
Average NYMEX Henry Hub natural gas price ($/MMBtu)	$	2.43	$	2.68	NYISO Zone C	$	38.13	$	30.96
					Massachusetts Hub	$	47.97	$	51.98
Average natural gas price (a):					Indiana Hub	$	36.79	$	35.52
TetcoM3 ($/MMBtu)	$	2.90	$	2.93	Northern Illinois Hub	$	30.34	$	29.58
Algonquin Citygates ($/MMBtu)	$	4.26	$	5.13	CAISO NP15	$	50.86	$	100.31

___________

(a)    Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.

(b)Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

For the three months ended March 31, 2024, other income totaled $91 million driven by NDT net gains of $35 million, interest income of $23 million and a gain of $10 million on TRA repurchases. For the three months ended March 31, 2023, other income totaled $20 million driven by interest income.

Consolidated interest expense and related charges decreased $37 million in the three months ended March 31, 2024 compared to the three months ended March 31, 2023 primarily due to unrealized mark-to-market gains on interest rate swaps of $47 million in 2024 compared to unrealized mark-to-market losses on interest rate swaps of $41 million in 2023 due to an increase in interest rates in the three months ended March 31, 2024 compared to a decrease in the three months ended March 31, 2023, partially offset by an increase in interest paid/accrued of $52 million driven by higher average borrowings and rates in 2024. See Note 18 to the Financial Statements.

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The following table presents additional changes to Net income (loss) and Adjusted EBITDA for the three months ended March 31, 2024 compared to the three months ended March 31, 2023.

	Three Months Ended March 31, 2024 Compared to 2023
(in millions)	Retail (a)		Texas		East (a)		West		Sunset
Favorable change in realized revenue net of fuel driven by effectiveness of hedging strategies (b), rolloff of negative margin default service contracts in East and addition of Energy Harbor	$	—	$	46	$	246	$	11	$	17
Higher margins driven by addition of Energy Harbor	8
Favorable impact of less Winter Storm Uri bill credits applied	27		—		—		—		—
Negative impacts of milder weather in 2024	(4)
Increase in operating costs due primarily to change in generation volumes	—		(15)		(47)		(1)		1
Change in SG&A and other	(30)		(3)		1		3		2
Change in Adjusted EBITDA	$	1	$	28	$	200	$	13	$	20
Favorable/(unfavorable) change in depreciation and amortization	6		(5)		(54)		(6)		(6)
Change in unrealized net gains (losses) on hedging activities (b)	1,182		(930)		(1,116)		111		(495)
Impairment of long-lived assets	—		—		—		—		49
Decommissioning related activities	—		(5)		26		—		(2)
PJM capacity performance default impacts	—		—		14		—		6
Winter Storm Uri impact	(34)		1		—		—		—
Other (including interest expenses)	1		(4)		—		(6)		11
Change in Net income (loss)	$	1,156	$	(915)	$	(930)	$	112	$	(417)

___________

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

(b)    See Energy-Related Commodity Contracts and Mark-to-Market Activities below for analysis of hedging strategy.

Asset Closure Segment — Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023

	Three Months Ended March 31,				Favorable (Unfavorable) Change
(in millions)	2024		2023
Fuel, purchased power costs and delivery fees	$	(1)	$	(1)	$	—
Operating costs	(12)		(20)		8
Selling, general and administrative expenses	(9)		(8)		(1)
Operating loss	(22)		(29)		7
Other income	3		3		—
Other deductions	(1)		—		(1)
Interest expense and related charges	(1)		(1)		—
Loss before income taxes	(21)		(27)		6
Net loss	$	(21)	$	(27)	$	6
Adjusted EBITDA	$	(23)	$	(41)	$	18

Operating costs for the three months ended March 31, 2024 and 2023 include ongoing costs associated with the decommissioning and reclamation of retired plants and mines. GAAP and Adjusted EBITDA results for 2024 are favorable compared to 2023 primarily due to higher costs incurred in 2023 for the January 2023 retirement of the Edwards generation facility.

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

As forward power prices materially increased in 2022, our generation segments (Texas, East, West and Sunset) aggressively sold forward power for future years. We entered the 2023 and 2024 calendar years with more than 99% of our expected generation volumes hedged. While settled power prices in the first quarter of 2023 and 2024 are lower than historical averages, the strategic hedging allowed us to lock in margins above what we would have been able to realize if unhedged. Additionally, the margins we were able to lock in with hedges for the first quarter of 2024 were higher than the first quarter of 2023 which is driving the increase in realized revenue net of fuel in the generation segments along with the addition of Energy Harbor in the East segment. The forward power sales are also the drivers of the changes in unrealized gains/losses on hedging activities. As power prices increase/decrease in comparison to what our generation segments have sold forward, the generation segments recognize unrealized losses/gains. The retail segment procures power from the generation segments to serve future load obligations and thus changes in forward power prices have an inverse effect on unrealized mark to market for the retail segment as compared to the generation segments. This is evident in the first quarter of 2023 as decrease in forward power prices drove material unrealized gains in our generation segment, partially offset by unrealized losses in our retail segment. In the first quarter of 2024, forward power prices increased slightly which resulted in unrealized losses in our generation segments which is partially offset by unrealized gains in our retail segment.

The table below summarizes the changes in commodity contract assets and liabilities for the three months ended March 31, 2024 and 2023. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $176 million in unrealized net losses and $1.085 billion in unrealized net gains for the three months ended March 31, 2024 and 2023, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.

	Three Months Ended March 31,
(in millions)	2024		2023
Commodity contract net liability at beginning of period	$	(2,740)	$	(3,148)
Settlements/termination of positions (a)	387		711
Changes in fair value of positions in the portfolio (b)	(563)		374
Acquired commodity contracts (c)	(39)		—
Other activity (d)	47		(36)
Commodity contract net liability at end of period	$	(2,908)	$	(2,099)

____________

(a)Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains/(losses) recognized in the settlement period). Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.

(b)Represents unrealized net gains/(losses) recognized, reflecting the effect of changes in fair value. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.

(c)Includes fair value of commodity contracts acquired in the Energy Harbor Merger (see Note 2 to the Financial Statements).

(d)Primarily represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses. Amounts are generally related to premiums related to options purchased or sold as well as certain margin deposits classified as settlement for certain transactions executed on the CME.

The following maturity table presents the net commodity contract liability arising from recognition of fair values as of March 31, 2024, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

(in millions)	Maturity dates of unrealized commodity contract net liability as of March 31, 2024
Source of Fair Value	Less than 1 year		1-3 years		4-5 years		Excess of 5 years		Total
Prices actively quoted	$	(521)	$	(272)	$	1	$	—	$	(792)
Prices provided by other external sources	(578)		(389)		—		—		(967)
Prices based on models	(322)		(609)		(130)		(88)		(1,149)
Total	$	(1,421)	$	(1,270)	$	(129)	$	(88)	$	(2,908)

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

Estimated hedging levels for generation volumes in our Texas, East, West and Sunset segments as of March 31, 2024 were as follows:

	Balance of 2024		2025
Nuclear/Renewable/Coal Generation:
Texas	100	%	100	%
East	74	%	39	%
Sunset	97	%	66	%
Natural Gas Generation:
Texas	95	%	84	%
East	100	%	84	%
West	100	%	99	%

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Financial Condition

Cash Flows

Operating Cash Flows

Cash provided by operating activities totaled $312 million and $1.435 billion in the three months ended March 31, 2024 and 2023, respectively. The unfavorable change of $1.123 billion was primarily driven by a lower decrease in net margin deposits (returns of cash related to commodity contracts which support our hedging strategy) as $128 million was returned in the three months ended March 31, 2024 as compared to $1.227 billion returned in the three months ended March 31, 2023, partially offset by cash received from an increase in realized energy margins recognized in the three months ended March 31, 2024 compared to the three months ended March 31, 2023.

Depreciation and amortization — Depreciation and amortization expense reported as a reconciling adjustment in the condensed consolidated statements of cash flows exceeds the amount reported in the condensed consolidated statements of operations by $152 million and $111 million for the three months ended March 31, 2024 and 2023, respectively. The difference represents amortization of nuclear fuel, which is reported as fuel costs in the condensed consolidated statements of operations consistent with industry practice, and amortization of intangible net assets and liabilities that are reported in various other condensed consolidated statements of operations line items including operating revenues and fuel and purchased power costs and delivery fees (see Note 7 to the Financial Statements).

Investing Cash Flows

Cash used in investing activities totaled $3.528 billion and $513 million for the three months ended March 31, 2024 and 2023, respectively. The increase of $3.015 billion was driven primarily by (a) $3.1 billion used to fund the Energy Harbor Merger and (b) $88 million in higher net purchases of environmental allowances, partially offset by a $125 million increase in proceeds from sales of property, plant and equipment, including nuclear fuel.

	Three Months Ended March 31,				Increase (Decrease)
(in millions)	2024		2023
Capital expenditures, including LTSA prepayments	$	(152)	$	(202)	$	50
Nuclear fuel purchases	(220)		(64)		(156)
Growth and development expenditures	(93)		(218)		125
Total capital expenditures	(465)		(484)		19
Energy Harbor acquisition (net of cash acquired)	(3,070)		—		(3,070)
Net sales (purchases) of environmental allowances	(114)		(26)		(88)
Proceeds from sales of property, plant and equipment, including nuclear fuel	127		2		125
Other investing activity	(6)		(5)		(1)
Cash used in investing activities	$	(3,528)	$	(513)	$	(3,015)

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Financing Cash Flows

Cash provided by financing activities totaled $793 million in the three months ended March 31, 2024 compared to cash used in financing activities of $874 million in the three months ended March 31, 2023. The change of $1.667 billion was driven by (a) the net borrowing of $1.375 billion of short-term debt and accounts receivable financing amounts in the three months ended March 31, 2024 to partially fund the Energy Harbor Merger compared to the net repayment of $475 million of short-term debt and accounts receivable financing amounts in the three months ended March 31, 2023 and (b) $700 million of borrowings under the Vistra Zero Term Loan B Facility, partially offset by cash used for long-term debt and TRA tender offers executed in January 2024.

	Three Months Ended March 31,				Increase (Decrease)
(in millions)	2024		2023
Share repurchases	$	(291)	$	(301)	$	10
Issuances of long-term debt	700		—		700
Other net long-term borrowings (repayments)	(756)		(7)		(749)
Net short-term borrowings (repayments)	500		(650)		1,150
Net borrowings (repayments) under the accounts receivable financing facilities	875		175		700
Dividends paid to common stockholders	(77)		(77)		—
TRA Repurchase and tender offer — return of capital	(122)		—		(122)
Other financing activity	(36)		(14)		(22)
Cash used in financing activities	$	793	$	(874)	$	1,667

Debt Activity

We remain committed to a strong balance sheet and have continued to state our objective to reduce our consolidated net leverage. We also intend to maintain adequate liquidity and pursue opportunities to refinance our long-term debt to extend maturities.

In May 2024 and July 2024, after taking into account the Senior Secured Notes Tender Offer settled in January 2024, $342 million of 4.875% Senior Secured Notes and $1.155 billion of 3.550% Senior Secured Notes, respectively, will reach maturity. We plan to fund these upcoming principal payments using a combination of (a) the proceeds from the issuance of $500 million of 6.000% Senior Secured Notes due 2034 and $1.0 billion of 6.875% Senior Unsecured Notes due 2032 and (b) cash on hand. Increases in interest rates have resulted in, and will likely continue to result in, increased borrowing costs.

See Note 8 to the Financial Statements for details of the Receivables Facility and Repurchase Facility and Note 10 to the Financial Statements for details of the Vistra Operations Credit Facilities, the Commodity-Linked Facility and other long-term debt.

Available Liquidity

The following table summarizes changes in available liquidity for the three months ended March 31, 2024:

(in millions)	March 31, 2024		December 31, 2023		Change
Cash and cash equivalents (a)	$	1,070	$	3,485	$	(2,415)
Vistra Operations Credit Facilities — Revolving Credit Facility (b)	1,293		1,213		80
Vistra Operations — Commodity-Linked Facility (c)	637		1,101		(464)
Total available liquidity (d)(e)	$	3,000	$	5,799	$	(2,799)

____________

(a)See the condensed consolidated statements of cash flows in the Financial Statements and Cash Flows above for details of the decrease in cash and cash equivalents for the three months ended March 31, 2024. The decrease includes $3.1 billion that was used to fund the Energy Harbor Merger.

(b)The increase in availability for the three months ended March 31, 2024 was driven by an $80 million decrease in letters of credit outstanding under the facility.

(c)As of both March 31, 2024 and December 31, 2023, the borrowing bases are less than the facility limit of $1.575 billion. As of March 31, 2024, available capacity reflects the borrowing base of $1.137 billion and $500 million in cash borrowings. As of December 31, 2023, available capacity reflects the borrowing base of $1.101 billion and no cash borrowings.

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(d)Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See Note 8 to the Financial Statements for detail on our accounts receivable financing.

(e)Excludes any additional letters of credit that may be issued under the Secured LOC Facilities, the Alternative LOC Facility or the Energy Harbor LOC Facility. See Note 10 to the Financial Statements for detail on our letter of credit facilities.

We believe that we will have access to sufficient liquidity to fund our other anticipated cash requirements through at least the next 12 months. Our operational cash flows tend to be seasonal and weighted toward the second half of the year.

Including obligations assumed in the Energy Harbor Merger, our obligations under commodity purchase and services agreements, including capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase commitments, are expected to total approximately $3.0 billion in fiscal year 2024, $2.9 billion in 2025-2026, $1.1 billion in 2027-2028 and $500 million thereafter.

Capital Expenditures

Estimated 2024 capital expenditures and nuclear fuel purchases as of May 8, 2024 total approximately $1.943 billion and include:

•$822 million for investments in generation and mining facilities;

•$745 million for solar and energy storage development;

•$302 million for nuclear fuel purchases; and

•$74 million for other growth expenditures.

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, at which time it superseded the 2020 Share Repurchase Program (described below) and any authorization remaining as of such date. 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.

The following table provides information about our repurchases of common stock for the period between January 1, 2024 and May 3, 2024:

(in millions, except share amounts and price paid per share)	$5.75 billion Board Authorization
	Total Number of Shares Repurchased	Average Price Paid Per Share		Amount Paid for Shares Repurchased		Amount Available for Additional Repurchases at the End of the Period
Three Months Ended March 31, 2024 (a)	6,138,773	$	46.21	$	284
April 1, 2024 through May 3, 2024	1,455,357	71.34		104
January 1, 2024 through May 3, 2024	7,594,130	$	51.02	$	388	$	1,862

____________

(a)Shares repurchased include 72,839 of unsettled shares for $5 million as of March 31, 2024.

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Dividends

Common Stock Dividends

In November 2018, Vistra announced the Board adopted a dividend program which we initiated in the first quarter of 2019. Each dividend under the program is subject to declaration by the Board and, thus, may be subject to numerous factors in existence at the time of any such declaration including, but not limited to, prevailing market conditions, Vistra's results of operations, financial condition and liquidity, Delaware law and any contractual limitations. Quarterly dividends paid per share of common stock in 2024 and 2023 are reflected in the table below.

Three Months Ended March 31, 2024				Year Ended December 31, 2023
Board Declaration Date	Payment Date	Per Share Amount		Board Declaration Date	Payment Date	Per Share Amount
February 2024	March 2024	$	0.2150	February 2023	March 2023	$	0.1975
				May 2023	June 2023	$	0.2040
				July 2023	September 2023	$	0.2060
				October 2023	December 2023	$	0.2130

In May 2024, the Board declared a quarterly dividend of $0.2175 per share of common stock that will be paid in June 2024.

Preferred Stock Dividends

Semiannual dividends paid per share of each respective preferred stock series in 2024 and 2023 are reflected in the table below. Dividends payable are recorded on the Board declaration date.

Series A Preferred Stock				Series B Preferred Stock
Board Declaration Date	Payment Date	Per Share Amount		Board Declaration Date	Payment Date	Per Share Amount
February 2023	April 2023	$	40.00	May 2023	June 2023	$	35.00
August 2023	October 2023	$	40.00	November 2023	December 2023	$	35.00
February 2024	April 2024	$	40.00

In May 2024, the Board declared a semi-annual dividend of $35.00 per share of Series B Preferred Stock that will be paid in June 2024 and an initial dividend of $48.32 per share on Series C Preferred Stock that will be paid in July 2024.

Liquidity Effects of Commodity Hedging and Trading Activities

We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. We use cash, letters of credit, Eligible Assets (see Note 9 to the Financial Statements) and other forms of credit support to satisfy such collateral posting obligations. See Note 10 to the Financial Statements for discussion of the Vistra Operations Credit Facilities, the Commodity-Linked Facility, the Secured LOC Facilities, the Alternative LOC Facility and the Energy Harbor LOC Facility.

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

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As of March 31, 2024, we received or posted cash, letters of credit, and Eligible Assets for commodity hedging and trading activities as follows:

•$1.629 billion in cash and Eligible Assets have been posted with counterparties as compared to $1.244 billion posted as of December 31, 2023;

•$115 million in cash has been received from counterparties as compared to $45 million received as of December 31, 2023;

•$2.634 billion in letters of credit have been posted with counterparties as compared to $2.408 billion posted as of December 31, 2023; and

•$140 million in letters of credit have been received from counterparties as compared to $143 million received as of December 31, 2023.

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

Income Tax Payments

In the next 12 months, we expect to make approximately $4 million in federal income tax payments and $52 million in state income tax payments, offset by $8 million in state tax refunds.

For the three months ended March 31, 2024, there were no federal income tax payments, $3 million in state income tax payments, $1 million in state income tax refunds and no TRA payments.

Financial Covenants

The Vistra Operations Credit Agreement and the Vistra Operations Commodity-Linked Credit Agreement each includes a covenant, solely with respect to the Revolving Credit Facility and the Commodity-Linked Facility and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit exceed 30% of the revolving commitments, provided that solely with respect to the Revolving Credit Facility only such amounts in excess of $300 million are taken into account for purposes of determining whether a compliance period is in effect), that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, during a collateral suspension period, the consolidated total net leverage ratio not to exceed 5.50 to 1.00). In addition, each of the Secured LOC Facilities includes a covenant that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, for certain facilities that include a collateral suspension mechanism, during a collateral suspension period, the consolidated total net leverage ratio not to exceed 5.50 to 1.00). As of March 31, 2024, we were in compliance with the Vistra Operations Credit Agreement, Vistra Operations Commodity-Linked Credit Agreement and Secured LOC Facilities financial covenants.

See Note 10 to the Financial Statements for discussion of other covenants related to the Vistra Operations Credit Facilities.

Collateral Support Obligations

The RCT has rules in place to assure that parties can meet their mining reclamation obligations. In September 2016, the RCT agreed to a collateral bond of up to $975 million to support Luminant's reclamation obligations. The collateral bond is effectively a first lien on all of Vistra Operations' assets (which ranks pari passu with the Vistra Operations Credit Facilities) that contractually enables the RCT to be paid (up to $975 million) before the other first-lien lenders in the event of a liquidation of our assets. Collateral support relates to land mined or being mined and not yet reclaimed as well as land for which permits have been obtained but mining activities have not yet begun and land already reclaimed but not released from regulatory obligations by the RCT, and includes cost contingency amounts.

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, as of March 31, 2024, Vistra has posted letters of credit in the amount of $95 million with the PUCT, which is subject to adjustments.

The ISOs/RTOs we operate in have rules in place to assure adequate creditworthiness of parties that participate in the markets operated by those ISOs/RTOs. Under these rules, Vistra has posted collateral support totaling $583 million in the form of letters of credit, $81 million in the form of a surety bond and $12 million of cash as of March 31, 2024 (which is subject to daily adjustments based on settlement activity with the ISOs/RTOs).

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Material Cross Default/Acceleration Provisions

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

A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greater of $300 million and 17.5% of Consolidated EBITDA may result in a cross default under the Vistra Operations Credit Facilities and the Commodity-Linked Facility. Such a default would allow the lenders under each such facility to accelerate the maturity of outstanding balances under such facilities, which totaled approximately $2.494 billion and $500 million, respectively, as of March 31, 2024.

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

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

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

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

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

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

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Under the Alternative LOC Facility, a default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greater of $300 million and 17.5% of Consolidated EBITDA may result in a cross default under the Alternative LOC Facility. In addition, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount exceeding the threshold above, may result in a termination of the Alternative LOC Facility.

Under the Vistra Operations Senior Unsecured Indenture and the Vistra Operations Senior Secured Indenture governing the 7.750% Senior Unsecured Notes and 6.950% Senior Secured Notes, respectively, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount that exceeds the greater of 1.5% of total assets and $600 million may result in a cross default under the respective notes and other current or future documents evidencing any indebtedness for borrowed money by the applicable borrower or issuer, as the case may be, and the applicable Guarantor Subsidiaries party thereto.

A default by Vistra Zero or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greater of $100 million and 75% of Consolidated EBITDA may result in a cross default under the Vistra Zero Credit Agreement. Such a default would allow the lenders under each such facility to accelerate the maturity of outstanding balances under such facilities, which totaled approximately $700 million as of March 31, 2024.

Guarantees

See Note 15 to the Financial Statements for discussion of guarantees.

Commitments and Contingencies

See Note 15 to the Financial Statements for discussion of commitments and contingencies.

Changes in Accounting Standards

See Note 1 to the Financial Statements for discussion of changes in accounting standards.

Item 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the risk that in the normal course of business we may experience a loss in value because of changes in market conditions that affect economic factors such as commodity prices, interest rates and counterparty credit. Our exposure to market risk is affected by several factors, including the size, duration and composition of our energy and financial portfolio, as well as the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swaps to hedge debt costs, as well as exchange-traded, over-the-counter contracts and other contractual arrangements to hedge commodity prices.

Risk Oversight

We manage the commodity price, counterparty credit and commodity-related operational risk related to the competitive energy business within limitations established by senior management and in accordance with overall risk management policies. Interest rate risk is managed centrally by our treasury function. Market risks are monitored by risk management groups that operate independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies. These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions and include, but are not limited to, position reporting and review, Value at Risk (VaR) methodologies and stress test scenarios. Key risk control activities include, but are not limited to, transaction review and approval (including credit review), operational and market risk measurement, transaction authority oversight, validation of transaction capture, market price validation and reporting, and portfolio valuation and reporting, including mark-to-market valuation, VaR and other risk measurement metrics.

Vistra has a risk management organization that enforces applicable risk limits, including the respective policies and procedures to ensure compliance with such limits, and evaluates the risks inherent in our businesses.

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Commodity Price Risk

Our business is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. We actively manage the portfolio of generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. Similar to other participants in the market, we cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices.

In managing energy price risk, we enter into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange-traded and over-the-counter financial contracts and bilateral contracts with customers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. We continuously monitor the valuation of identified risks and adjust positions based on current market conditions. We strive to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.

VaR Methodology

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

Parametric processes are used to calculate VaR and are considered by management to be the most effective way to estimate changes in a portfolio's value based on assumed market conditions for liquid markets. The use of these methods requires a number of key assumptions, such as use of (i) an assumed confidence level, (ii) an assumed holding period (i.e., the time necessary for management action, such as to liquidate positions); and (iii) historical estimates of volatility and correlation data. The table below details certain VaR measures related to various portfolios of contracts.

VaR for Underlying Generation Assets and Energy-Related Contracts

This measurement estimates the potential loss in value, due to changes in market conditions, of all underlying generation assets and contracts, based on a 95% confidence level and an assumed holding period of 60 days. The forward period covered by this calculation includes the current and subsequent calendar year at the time of calculation.

(in millions)	Three Months Ended March 31, 2024		Year Ended December 31, 2023
Month-end average VaR	$	251	$	190
Month-end high VaR	$	329	$	423
Month-end low VaR	$	197	$	115

The month-end VaR risk measures in 2024 are consistent with prior year.

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Price Sensitivities

The following sensitivity table provides approximate estimates of the potential impact of movements in power prices and spark spreads (the difference between the power revenue and fuel expense of natural gas-fired generation as calculated using an assumed Heat Rate of 7.2 MMBtu/MWh) on realized pre-tax earnings (in millions) taking into account the hedge positions noted above for the periods presented. The residual natural gas position is calculated based on two steps: first, calculating the difference between actual Heat Rates of our natural gas generation units and the assumed 7.2 Heat Rate used to calculate the sensitivity to spark spreads; and second, calculating the residual natural gas exposure that is not already included in the natural gas generation spark spread sensitivity shown in the table below. The estimates related to price sensitivity are based on our expected generation, related hedges and forward prices as of March 31, 2024.

(in millions)	Balance of 2024		2025
Texas:
Natural Gas Generation: $1.00/MWh increase in spark spread	$	3	$	8
Natural Gas Generation: $1.00/MWh decrease in spark spread	$	(2)	$	(8)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	—	$	9
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	(5)	$	(15)
East:
Nuclear Generation: $2.50/MWh increase in power price	$	17	$	50
Nuclear Generation: $2.50/MWh decrease in power price	$	(17)	$	(50)
Natural Gas Generation: $1.00/MWh increase in spark spread	$	1	$	10
Natural Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	(8)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	(6)	$	(24)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	—	$	20
West:
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	—	$	1
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	(1)	$	(2)
Sunset:
Coal Generation: $2.50/MWh increase in power price	$	2	$	23
Coal Generation: $2.50/MWh decrease in power price	$	1	$	(23)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	—	$	1
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	—	$	(1)

Interest Rate Risk

We manage our interest rate risk to limit the impact of interest rate changes on our results of operations and cash flows and to lower our overall borrowing costs. To achieve these objectives, a majority of our borrowings have fixed interest rates.

As of March 31, 2024, the potential reduction of annual pretax earnings over the next twelve months due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $9 million taking into account the interest rate swaps discussed in Note 11 to Financial Statements. The inflationary environment continues to drive elevated interest rates, resulting in increased recently completed and expected refinancing or borrowing costs. See Item 2. Management's Discussion and Analysis of Financial Condition, and Results of Operations – Significant Activities and Events, and Items Influencing Future Performance – Macroeconomic Conditions.

Credit Risk

Credit risk relates to the risk of loss associated with nonperformance by counterparties. We minimize credit risk by evaluating potential counterparties, monitoring ongoing counterparty risk and assessing overall portfolio risk. This includes review of counterparty financial condition, current and potential credit exposures, credit rating and other quantitative and qualitative credit criteria. We also employ certain risk mitigation practices, including utilization of standardized master agreements that provide for netting and setoff rights, as well as credit enhancements such as margin deposits and customer deposits, letters of credit, parental guarantees and surety bonds. See Note 11 to the Financial Statements for further discussion of this exposure.

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Credit Exposure

Our gross credit exposure (excluding collateral impacts) associated with retail and wholesale trade accounts receivable and net derivative assets arising from commodity contracts and hedging and trading activities totaled $2.164 billion as of March 31, 2024.

As of March 31, 2024, Retail segment credit exposure totaled approximately $1.392 billion, including $1.370 billion of trade accounts receivable and $22 million related to derivatives. Cash deposits and letters of credit held as collateral for these receivables totaled $51 million, resulting in a net exposure of $1.341 billion. Allowances for uncollectible accounts receivable are established for the expected loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition of large business customers.

As of March 31, 2024, aggregate Texas, East, Sunset and Asset Closure segments credit exposure totaled $772 million including $681 million related to derivative assets and $91 million of trade accounts receivable, after taking into account master netting agreement provisions but excluding collateral impacts.

Including collateral posted to us by counterparties, our net Texas, East, Sunset and Asset Closure segments exposure was $581 million, as seen in the following table that presents the distribution of credit exposure by counterparty credit quality as of March 31, 2024. Credit collateral includes cash and letters of credit but excludes other credit enhancements such as guarantees or liens on assets.

(in millions)	Exposure Before Credit Collateral		Credit Collateral		Net Exposure
Investment grade	$	633	$	111	$	522
Below investment grade or no rating	139		80		59
Totals	$	772	$	191	$	581

Significant (i.e., 10% or greater) concentration of credit exposure exists with two counterparties, which represent an aggregate $310 million, or 53%, of our total net exposure as of March 31, 2024. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the counterparties' credit ratings, the counterparties' market role and deemed creditworthiness and the importance of our business relationship with the counterparties. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts such as margin deposits are owed to the counterparties or delays in receipts of expected settlements owed to us.

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

Item 4.CONTROLS AND PROCEDURES

An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15a-15(e) of the Exchange Act) in effect at March 31, 2024. Based on the evaluation performed, our principal executive officer and principal financial officer concluded that the disclosure controls and procedures were effective. During the fiscal quarter covered by this quarterly report on Form 10-Q, other than additional controls associated with the integration of Energy Harbor due to the Energy Harbor Merger, there have been no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(e) and 15a-15(e) of the Exchange Act) during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1.LEGAL PROCEEDINGS

Reference is made to the discussion in Note 15 to the Financial Statements regarding legal proceedings.

Item 1A.RISK FACTORS

As of the date of this Quarterly Report on Form 10-Q, except as set forth below, there have been no material changes to the risk factors discussed in Part I, Item 1A Risk Factors in our 2023 Form 10-K. We could also be affected by additional factors that are not presently known to us or that we currently consider to be immaterial to our operations.

We may suffer material losses, costs and liabilities due to operation risks, regulatory risks, and the risk of nuclear accidents arising from the ownership and operation of the nuclear generation facilities.

We own and operate nuclear generation facilities in Texas, Ohio, and Pennsylvania. The ownership and operation of nuclear generation facilities involves certain risks. These risks include:

•unscheduled outages or unexpected costs due to equipment, mechanical, structural, cybersecurity, insider threat, third-party compromise or other problems;

•inadequacy or lapses in maintenance protocols;

•the impairment of reactor operation and safety systems due to human error or force majeure;

•the costs of, and liabilities relating to, storage, handling, treatment, transport, release, use and disposal of radioactive materials;

•the costs of procuring nuclear fuel, including impacts from restrictions on imports from Russia or China (see Part I, Item 2. Management's Discussion and Analysis of Financial Condition, and Results of Operations – Significant Activities and Events, and Items Influencing Future Performance – Macroeconomic Conditions);

•the costs of storing and maintaining spent nuclear fuel at our on-site dry cask storage facility;

•terrorist or cybersecurity attacks by nation-states or other threat actors and the cost to protect and recover against any such attack;

•the impact of a natural disaster;

•financial risk associated with retrospective insurance premium that could become due under secondary coverage required by the Price Anderson Act;

•limitations on the amounts and types of insurance coverage commercially available; and

•uncertainties with respect to the technological and financial aspects of modifying or decommissioning nuclear facilities at the end of their useful lives.

Our financial performance could be materially and negatively affected by matters arising from our ownership and operation of nuclear facilities, including any prolonged unavailability of any of our nuclear generation facilities. The following are among the more significant related risks:

•Operational Risk — Operations at any generation facility could degrade to the point where the facility would have to be shut down. If such degradations were to occur at a nuclear generation facility, the process of identifying and correcting the causes of the operational downgrade to return the facility to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments. Furthermore, a shut-down or failure at any other nuclear generation facility could cause regulators to require a shut-down or reduced availability at our nuclear generation facilities.

•Regulatory Risk — The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear generation facilities. Unless extended, as to which no assurance can be given, the NRC operating licenses for the two units at the Comanche Peak Facility will expire in 2030 and 2033, respectively, and for the unit at the Perry Facility will expire in 2026, and are pending license renewal applications subject to review by the NRC. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.

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•Spent Nuclear Fuel Storage. Our nuclear operations produce various types of nuclear waste materials, including spent nuclear fuel. The availability of a national repository for the storage of spent nuclear fuel and the timing of that facility opening will significantly affect the costs associated with storage of spent nuclear fuel and the ultimate amounts received from the DOE to reimburse us for these costs. Any regulatory action relating to the timing and availability of a repository for spent nuclear fuel could adversely affect our ability to decommission fully our nuclear units. We cannot predict whether a fee may be established or to what extent in the future for spent nuclear fuel disposal.

•Decommissioning Obligation and Funding. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility.

Actual costs to decommission our nuclear facilities may substantially exceed our estimates as a result of changes in the approach and timing of decommissioning activities, changes in decommissioning costs, changes in federal or state regulatory requirements, other changes in our estimates or ability to effectively execute on our planned decommissioning activities.

Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. In addition, financial market performance directly affects the asset values in the NDT trust funds. If the investments held by our PJM NDT funds are not sufficient to fund the decommissioning of our nuclear units, we could be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current and future NRC minimum funding requirements are met.

•Nuclear Accident Risk — Although the safety record of our nuclear generation facilities generally has been very good, accidents and other unforeseen problems have occurred at nuclear stations both in the U.S. and elsewhere. The consequences of an accident can be severe and include loss of life, injury, lasting negative health impacts and property damage. Any accident, or perceived accident, could result in significant liabilities that may exceed our resources, including insurance coverages, and could damage our reputation. Such liabilities to third parties are currently covered by a primary layer of financial protection required by the Price Anderson Act in the form of insurance carried by the owners of each nuclear facility and by a secondary layer of insurance coverage into which each nuclear licensee in the country is required to contribute in the event of an accident at any facility which exceeds the primary level of coverage for that facility. Our potential exposure for the secondary layer of coverage is currently capped at $165.9 million per reactor but is subject to adjustment for inflation, and the total retrospective premium per reactor per incident is capped at $24.7 million in any one year. Any such resulting liability from a nuclear accident could exceed our resources, including insurance coverage, and could ultimately result in the suspension or termination of power generation from the impacted facility. Such accidents could also result in property damage to our nuclear plant and equipment, which could exceed coverage available under insurance provided by Nuclear Electric Insurance Limited. If a serious nuclear incident were to occur, our business, reputation, financial condition and results of operations could be materially adversely affected.

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

The following table provides information about our repurchase of common stock during the three months ended March 31, 2024.

	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of a Publicly Announced Program	Maximum Dollar Amount of Shares that may yet be Purchased under the Program (in millions)
January 1 - January 31, 2024	2,788,825	$	39.50	2,788,825	$	640
February 1 - February 29, 2024	2,070,289	$	45.68	2,070,289	$	2,045
March 1 - March 31, 2024	1,279,659	$	61.68	1,279,659	$	1,966
For the quarter ended March 31, 2024	6,138,773			6,138,773

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In October 2021, we announced that the Board had authorized a share repurchase program (Share Repurchase Program) under which up to $2.0 billion of our outstanding 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. We expect to complete repurchases under the Share Repurchase Program by the end of 2025.

See Note 16 to the Financial Statements for more information concerning the Share Repurchase Program.

Item 3.DEFAULTS UPON SENIOR SECURITIES

None.

Item 4.    MINE SAFETY DISCLOSURES

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

Item 5.OTHER INFORMATION

During the three months ended March 31, 2024, none of our officers or directors adopted or terminated any contract, instruction, or written plan for the purchase or sale of Company securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement".

Item 6.    EXHIBITS

(a)    Exhibits filed or furnished as part of Part II are:

Exhibits	Previously Filed With File Number*	As Exhibit
(2)	Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession
2.1	0001-38086 Form 8-K (filed March 7, 2023)	2.1	—	Transaction Agreement, dated March 6, 2023, by and among Vistra Operations Company LLC, Black Pen Inc. and Energy Harbor Corp.
(3(i))	Articles of Incorporation
3.1	0001-38086 Form 8-K (filed May 4, 2020)	3.1	—	Restated Certificate of Incorporation of Vistra Energy Corp. (now known as Vistra Corp.)
3.2	0001-38086 Form 8-K (filed June 29, 2020)	3.1	—	Certificate of Amendment of the Restated Certificate of Incorporation of Vistra Energy Corp. (now known as Vistra Corp.), effective July 2, 2020
3.3	0001-38086 Form 8-K (filed October 15, 2021)	3.1	—	Series A Preferred Stock Certificate of Designation, filed with the Secretary of State of Delaware on October 14, 2021
3.4	0001-38086 Form 8-K (filed December 13, 2021)	3.1	—	Series B Preferred Stock Certificate of Designation, filed with the Secretary of State of Delaware on December 9, 2021
3.5	0001-38086 Form 8-K (filed January 4, 2024)	3.1	—	Series C Preferred Stock Certificate of Designation filed with the Secretary of State of Delaware on December 29, 2023

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Exhibits	Previously Filed With File Number*	As Exhibit
(3(ii))	By-laws
3.3	001-38086 Form 10-K (Year ended December 31, 2021) (filed February 25, 2022)	3.5	—	Amended and Restated Bylaws of Vistra Corp., effective February 23, 2022
(4)	Instruments Defining the Rights of Security Holders, Including Indentures
4.1	0001-38086 Form 8-K (filed April 9, 2024)	4.1	—	Fourteenth Amendment to Receivables Purchase Agreement, dated as of April 8, 2024, among TXU Receivables, as seller, TXU Retail, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
4.2	0001-38086 Form 8-K (filed April 9, 2024)	4.2	—	Sixth Amendment to Purchase and Sale Agreement, dated as of April 8, 2024, among TXU Receivables, as buyer, TXU Retail, as servicer, certain originators named therein and Credit Agricole Corporate and Investment Bank, as administrator
4.3	**		—	Second Supplemental Indenture for 7.750% Senior Secured Notes due 2031, dated March 29, 2024, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.4	**		—	Fourth Supplemental Indenture for 7.233% Senior Secured Notes due 2028, dated March 29, 2024, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.5	**		—	Sixth Supplemental Indenture for 4.375% Senior Notes due 2029, dated March 29, 2024, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.6	**		—	Twelfth Supplemental Indenture for 5.500% Senior Notes due 2026, dated March 29, 2024, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.7	**		—	Twelfth Supplemental Indenture for 5.625% Senior Notes due 2027, dated March 29, 2024, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.8	**		—	Twelfth Supplemental Indenture for 5.00% Senior Notes due 2027, dated March 29, 2024, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.9	**		—	Sixteenth Supplemental Indenture for 3.55% Senior Secured Notes due 2024, 4.30% Senior Secured Notes due 2029, 3.70% Senior Secured Notes due 2027, 4.875% Senior Secured Notes due 2024, 5.125% Senior Secured Notes due 2025 and 6.950% Senior Secured Notes due 2033, dated March 29, 2024, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee
4.10	0001-38086 Form 8-K (filed April 18, 2024)	4.1	—	Seventeenth Supplemental Indenture, dated as of April 12, 2024, between Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors, and Wilmington Trust, National Association, as Trustee
4.11	0001-38086 Form 8-K (filed April 18, 2024)	4.2	—	Indenture, dated as of April 12, 2024, between Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors, and Wilmington Trust, National Association, as Trustee

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Exhibits	Previously Filed With File Number*	As Exhibit
4.12	0001-38086 Form 8-K (filed April 18, 2024)	4.3	—	Form of Rule 144A Global Security for 6.000% Senior Secured Note due 2034 (included in Exhibit 4.10)
4.13	0001-38086 Form 8-K (filed April 18, 2024)	4.4	—	Form of Rule 144A Global Security for 6.875% Senior Note due 2032 (included in Exhibit 4.11)
4.14	0001-38086 Form 8-K (filed April 18, 2024)	4.5	—	Form of Regulation S Global Security for 6.000% Senior Secured Note due 2034 (included in Exhibit 4.10)
4.15	0001-38086 Form 8-K (filed April 18, 2024)	4.6	—	Form of Regulation S Global Security for 6.875% Senior Note due 2032 (included in Exhibit 4.11)
4.16 +	**		—	First Supplemental Indenture, dated as of June 15, 2009, under the Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009
4.17 +	**		—	Second Supplemental Indenture, dated as of June 30, 2009, under the Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009
4.18 +	**		—	Fifth Supplemental Indenture, dated as of August 15, 2016, under the Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009
4.19 +	**		—	Eighth Supplemental Indenture, dated as of August 15, 2016, under the Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008
4.20 +	**		—	Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009
4.21 +	**		—	Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008
(10)	Material Contracts
10.1	0001-38086 Form 8-K (filed March 7, 2024)	10.1	—	Amended and Restated Limited Liability Company Agreement of Vistra Vision LLC, dated March 1, 2024
10.2	0001-38086 Form 8-K (filed April 1, 2023)	10.1	—	Credit Agreement, dated March 26, 2024, by and among Vistra Zero Operating Company, LLC, the Lenders (as defined in the Credit Agreement) party thereto and Citibank, N.A. (as Administrative Agent and as Collateral Agent)
10.3	0001-38086 Form 8-K (filed April 9, 2024)	10.1	—	Joinder Agreement, dated as of April 8, 2024, among TXU Retail, as seller party agent, Vistra Operations, as guarantor, certain originators named therein, and MUFG, as buyer
(31)	Rule 13a-14(a) / 15d-14(a) Certifications
31.1	**		—	Certification of James A. Burke, principal executive officer of Vistra Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	**		—	Certification of Kristopher E. Moldovan, principal financial officer of Vistra Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(32)	Section 1350 Certifications
32.1	***		—	Certification of James A. Burke, principal executive officer of Vistra Corp., pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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Exhibits	Previously Filed With File Number*	As Exhibit
32.2	***		—	Certification of Kristopher E. Moldovan, principal financial officer of Vistra Corp., pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(95)	Mine Safety Disclosures
95.1	**		—	Mine Safety Disclosures
	XBRL Data Files
101.INS	**		—	The following financial information from Vistra Corp.'s Quarterly Report on Form 10-Q for the period ended March 31, 2024 formatted in Inline XBRL (Extensible Business Reporting Language) includes: (i) the Condensed Consolidated Statements of Operations, (ii) the Condensed Consolidated Statements of Comprehensive Income (Loss), (iii) the Condensed Consolidated Statements of Cash Flows, (iv) the Condensed Consolidated Balance Sheets, (v) the Condensed Consolidated Statement of Changes in Equity and (vi) the Notes to the Condensed Consolidated Financial Statements
101.SCH	**		—	XBRL Taxonomy Extension Schema Document
101.CAL	**		—	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	**		—	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	**		—	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	**		—	XBRL Taxonomy Extension Presentation Linkbase Document
104	**		—	The Cover Page Interactive Data File does not appear in Exhibit 104 because its XBRL tags are embedded within the Inline XBRL document

____________________

*    Incorporated herein by reference

**    Filed herewith

***    Furnished herewith

+    Certain exhibits and schedules to this exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. Vistra agrees to furnish supplementally a copy of any omitted annexes or schedule to the SEC upon its request.

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SIGNATURE

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

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

Date: May 9, 2024

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