Vistra (VST) 10-Q 2024 Q3 Quarterly report

0001692819vistra:MartinLakeSteamElectricStationMembersrt:MaximumMember2023-05-012023-05-31

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 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 November 4, 2024
Common stock, par value $0.01 per share	340,226,219

TABLE OF CONTENTS

				PAGE
Glossary of Terms and Abbreviations				i
Forward-Looking Statements				v
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
		Condensed Consolidated Statements of Operations		1
		Condensed Consolidated Statements of Comprehensive Income		1
		Condensed Consolidated Statements of Cash Flows		2
		Condensed Consolidated Balance Sheets		4
		Condensed Consolidated Statements of Changes in Equity		6
		Notes to Condensed Consolidated Financial Statements		8
			1. Business, Basis of Presentation and Significant Accounting Policies	8
			2. Acquisitions	10
			3. Retirement of Generation Facilities	13
			4. Revenue	14
			5. Income Taxes	18
			6. Earnings Per Share	20
			7. Goodwill and Identifiable Intangible Assets and Liabilities	20
			8. Collateral Financing Agreement with Affiliate	22
			9. Debt, Credit Facilities and Financings	23
			10. Commodity and Other Derivative Contractual Assets and Liabilities	31
			11. Fair Value Measurements	34
			12. Tax Receivable Agreement Obligation	38
			13. Asset Retirement Obligations (ARO)	39
			14. Commitments and Contingencies	40
			15. Equity	50
			16. Segment Information	52
			17. Supplementary Financial Information	55
Item 2.	Management's Discussion and Analysis of Financial Condition, and Results of Operations			59
		Significant Activities and Events, and Items Influencing Future Performance		59
		Results of Operations		63
		Financial Condition		76
		Commitments and Contingencies		81
		Changes in Accounting Standards		81
Item 3.	Quantitative and Qualitative Disclosures About Market Risk			82
Item 4.	Controls and Procedures			85
PART II.	OTHER INFORMATION			86
Item 1.		Legal Proceedings		86
Item 1A.		Risk Factors		86
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds		87
Item 3.		Defaults Upon Senior Securities		88
Item 4.		Mine Safety Disclosures		88
Item 5.		Other Information		88
Item 6.		Exhibits		88
SIGNATURE				91

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.
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 9 to the Financial Statements) and borrower under the Vistra Operations Credit Facilities
Vistra Vision	Vistra Vision LLC, an indirect subsidiary of Vistra
Vistra Zero	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
FERC	U.S. Federal Energy Regulatory Commission
IEPA	Illinois Environmental Protection Agency
IPCB	Illinois Pollution Control Board

ii

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
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

iii

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	Amended and Restated Tax Receivable Agreement, containing certain rights (TRA Rights) to receive payments from Vistra related to certain tax benefits, including benefits realized as a result of certain transactions entered into at Emergence (see Note 12 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 9 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, including potential nuclear PTCs, capital allocation, capital expenditures, liquidity, dividend policy, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our businesses and operations, including potential transactions with large load facilities at our nuclear and gas plants (often, but not always, through the use of words or phrases such as "intends," "plans," "potential," "will likely," "unlikely," "believe," "expect," "anticipated," "estimate," "should," "could," "may," "projection," "forecast," "target," "goal," "objective" and "outlook"), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and risks 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 September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Operating revenues (Note 4)	$	6,288	$	4,086	$	13,187	$	11,701
Fuel, purchased power costs and delivery fees	(2,207)		(2,109)		(5,520)		(5,754)
Operating costs	(616)		(411)		(1,742)		(1,277)
Depreciation and amortization	(466)		(375)		(1,306)		(1,109)
Selling, general and administrative expenses	(411)		(357)		(1,137)		(953)
Impairment of long-lived assets (Note 17)	—		—		—		(49)
Operating income	2,588		834		3,482		2,559
Other income (Note 17)	139		32		292		174
Other deductions (Note 17)	(3)		(3)		(10)		(9)
Interest expense and related charges (Note 17)	(332)		(143)		(743)		(450)
Impacts of Tax Receivable Agreement (Note 12)	—		(49)		(5)		(128)
Net income before income taxes	2,392		671		3,016		2,146
Income tax expense (Note 5)	(555)		(169)		(694)		(470)
Net income	$	1,837	$	502	$	2,322	$	1,676
Net (income) loss attributable to noncontrolling interest	51		—		(104)		1
Net income attributable to Vistra	$	1,888	$	502	$	2,218	$	1,677
Cumulative dividends attributable to preferred stock	(48)		(37)		(144)		(112)
Net income attributable to Vistra common stock	$	1,840	$	465	$	2,074	$	1,565
Weighted average shares of common stock outstanding:
Basic	342,969,916		366,570,040		346,315,125		374,323,466
Diluted	350,203,692		372,149,099		353,805,937		379,102,358
Net income per weighted average share of common stock outstanding:
Basic	$	5.36	$	1.27	$	5.99	$	4.18
Diluted	$	5.25	$	1.25	$	5.86	$	4.13

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited) (Millions of Dollars)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Net income	$	1,837	$	502	$	2,322	$	1,676
Other comprehensive income, net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax expense (benefit) of $—, $—, $— and $1)	1		(2)		1		3
Total other comprehensive income	1		(2)		1		3
Comprehensive income	$	1,838	$	500	$	2,323	$	1,679
Comprehensive (income) loss attributable to noncontrolling interest	51		—		(104)		1
Comprehensive income attributable to Vistra	$	1,889	$	500	$	2,219	$	1,680

See Notes to Condensed Consolidated Financial Statements

1

VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars)
	Nine Months Ended September 30,
	2024		2023
Cash flows — operating activities:
Net income	$	2,322	$	1,676
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	1,891		1,442
Deferred income tax expense, net	666		437
Gain on sale of land	—		(95)
Impairment of long-lived assets	—		49
Unrealized net gain from mark-to-market valuations of commodities	(1,725)		(855)
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps	26		(65)
Unrealized net gain from nuclear decommissioning trusts	(133)		—
Asset retirement obligation accretion expense	84		26
Impacts of Tax Receivable Agreement	5		128
Gain on TRA repurchase and tender offers	(10)		—
Bad debt expense	132		131
Stock-based compensation	76		63
Other, net	(9)		39
Changes in operating assets and liabilities:
Margin deposits, net	855		2,271
Accrued interest	11		(47)
Accrued taxes	(40)		(38)
Accrued employee incentive	(78)		(23)
Other operating assets and liabilities	(863)		(567)
Cash provided by operating activities	3,210		4,572
Cash flows — investing activities:
Capital expenditures, including nuclear fuel purchases and LTSA prepayments	(1,648)		(1,262)
Energy Harbor acquisition (net of cash acquired)	(3,065)		—
Proceeds from sales of nuclear decommissioning trust fund securities	1,573		478
Investments in nuclear decommissioning trust fund securities	(1,590)		(495)
Proceeds from sales of environmental allowances	147		59
Purchases of environmental allowances	(511)		(277)
Proceeds from sale of property, plant and equipment, including nuclear fuel	137		111
Other, net	(2)		4
Cash used in investing activities	(4,959)		(1,382)
Cash flows — financing activities:
Issuances of long-term debt	2,200		1,750
Repayments/repurchases of debt	(2,269)		(21)
Net borrowings (repayments) under accounts receivable financing	750		(425)
Borrowings under Revolving Credit Facility	50		100
Repayments under Revolving Credit Facility	(50)		(350)
Borrowings under Commodity-Linked Facility	1,802		—
Repayments under Commodity-Linked Facility	(1,802)		(400)
Debt issuance costs	(32)		(29)
Stock repurchases	(1,021)		(866)
Dividends paid to common stockholders	(230)		(228)
Dividends paid to preferred stockholders	(98)		(75)

See Notes to Condensed Consolidated Financial Statements

2

VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars)
	Nine Months Ended September 30,
	2024		2023
Dividends paid to noncontrolling interest in subsidiary	(15)		—
TRA Repurchase and tender offer — return of capital	(122)		—
Other, net	(13)		54
Cash used in financing activities	(850)		(490)
Net change in cash, cash equivalents and restricted cash	(2,599)		2,700
Cash, cash equivalents and restricted cash — beginning balance	3,539		525
Cash, cash equivalents and restricted cash — ending balance	$	940	$	3,225

See Notes to Condensed Consolidated Financial Statements

3

VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars, Except Share Data)
	September 30, 2024		December 31, 2023
ASSETS
Current assets:
Cash and cash equivalents	$	905	$	3,485
Restricted cash (Note 17)	29		40
Trade accounts receivable — net (Note 4)	2,179		1,674
Income taxes receivable	20		6
Inventories (Note 17)	949		740
Commodity and other derivative contractual assets (Note 10)	2,854		3,645
Margin deposits related to commodity contracts	519		1,244
Margin deposits posted under affiliate financing agreement (Note 8)	451		439
Prepaid expense and other current assets	625		364
Total current assets	8,531		11,637
Restricted cash (Note 17)	6		14
Investments (Note 17)	4,520		2,035
Property, plant and equipment — net (Note 17)	18,388		12,432
Operating lease right-of-use assets	109		50
Goodwill (Note 7)	2,802		2,583
Identifiable intangible assets — net (Note 7)	2,157		1,864
Commodity and other derivative contractual assets (Note 10)	886		577
Accumulated deferred income taxes	—		1,223
Other noncurrent assets	479		551
Total assets	$	37,878	$	32,966
LIABILITIES AND EQUITY
Current liabilities:
Accounts receivable financing (Note 9)	$	750	$	—
Long-term debt due currently (Note 9)	785		2,286
Trade accounts payable	1,291		1,147
Commodity and other derivative contractual liabilities (Note 10)	3,563		5,258
Margin deposits related to commodity contracts	175		45
Accrued taxes other than income	199		203
Accrued interest	222		206
Asset retirement obligations (Note 13)	102		124
Operating lease liabilities	13		7
Other current liabilities	560		547
Total current liabilities	7,660		9,823
Margin deposits financing with affiliate (Note 8)	451		439
Long-term debt, less amounts due currently (Note 9)	13,945		12,116
Operating lease liabilities	99		48
Commodity and other derivative contractual liabilities (Note 10)	1,141		1,688
Accumulated deferred income taxes	839		1
Tax Receivable Agreement obligation (Note 12)	15		164
Asset retirement obligations (Note 13)	3,884		2,414
Other noncurrent liabilities and deferred credits (Note 17)	1,191		951
Total liabilities	29,225		27,644

See Notes to Condensed Consolidated Financial Statements

4

VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars, Except Share Data)
	September 30, 2024		December 31, 2023
Commitments and Contingencies (Note 14)
Redeemable noncontrolling interest (Note 2)	3,198		—
Total equity (Note 15):
Preferred stock, number of shares authorized — 100,000,000; Series A (liquidation preference — $1,000; shares outstanding: September 30, 2024 and December 31, 2023— 1,000,000); Series B (liquidation preference — $1,000; shares outstanding: September 30, 2024 and December 31, 2023 — 1,000,000); Series C (liquidation preference — $1,000; shares outstanding: September 30, 2024 — 476,066 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: September 30, 2024 — 340,717,442; December 31, 2023 — 351,457,016)	5		5
Treasury stock, at cost (shares: September 30, 2024 — 207,378,586; December 31, 2023 — 192,178,156)	(5,684)		(4,662)
Additional paid-in-capital	9,396		10,095
Retained deficit	(759)		(2,613)
Accumulated other comprehensive income	7		6
Stockholders' equity	5,441		5,307
Noncontrolling interest in subsidiary	14		15
Total equity	5,455		5,322
Total liabilities, redeemable noncontrolling interest and equity	$	37,878	$	32,966

See Notes to Condensed Consolidated Financial Statements

5

VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) (Millions of Dollars)
	Preferred Stock		Common Stock		Treasury Stock		Additional Paid-In Capital		Retained Deficit		Accumulated Other Comprehensive Income		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
Stock repurchases	—		—		(331)		—		—		—		(331)		—		(331)
Effects of stock-based incentive compensation plans	—		—		—		40		—		—		40		—		40
Net income	—		—		—		—		365		—		365		102		467
Dividends declared on common stock	—		—		—		—		(77)		—		(77)		—		(77)
Dividends declared on preferred stock	—		—		—		—		(59)		—		(59)		—		(59)
Dividends to noncontrolling interest	—		—		—		—		—		—		—		(15)		(15)
Other	—		—		—		(1)		—		—		(1)		(1)		(2)
Balances at June 30, 2024	$	2,476	$	5	$	(5,278)	$	10,917	$	(2,533)	$	6	$	5,593	$	1,714	$	7,307
Stock repurchases	—		—		(406)		—		—		—		(406)		—		(406)
Effects of stock-based incentive compensation plans	—		—		—		28		—		—		28		—		28
Net income (loss)	—		—		—		—		1,888		—		1,888		(51)		1,837
Dividends declared on common stock	—		—		—		—		(76)		—		(76)		—		(76)
Dividends declared on preferred stock	—		—		—		—		(39)		—		(39)		—		(39)
Change in accumulated other comprehensive income	—		—		—		—		—		1		1		—		1
Modification of noncontrolling interest to redeemable noncontrolling interest (a)	—		—		—		(1,539)		—		—		(1,539)		(1,659)		(3,198)
Other	—		—		—		(10)		1		—		(9)		10		1
Balances at September 30, 2024	$	2,476	$	5	$	(5,684)	$	9,396	$	(759)	$	7	$	5,441	$	14	$	5,455

____________

(a)See Note 2 for additional information regarding activity associated with noncontrolling interest.

See Notes to Condensed Consolidated Financial Statements

6

VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (CONTINUED) (Unaudited) (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	—		—		—		—		—		1		1		—		1
Balances at March 31, 2023	$	2,000	$	5	$	(3,706)	$	9,952	$	(3,058)	$	8	$	5,201	$	15	$	5,216
Stock repurchases	—		—		(249)		—		—		—		(249)		—		(249)
Effects of stock-based incentive compensation plans	—		—		—		42		—		—		42		—		42
Net income	—		—		—		—		476		—		476		—		476
Dividends declared on common stock	—		—		—		—		(76)		—		(76)		—		(76)
Dividends declared on preferred stock	—		—		—		—		(38)		—		(38)		—		(38)
Change in accumulated other comprehensive income	—		—		—		—		—		4		4		—		4
Other	—		—		—		(1)		—		—		(1)		—		(1)
Balances at June 30, 2023	$	2,000	$	5	$	(3,955)	$	9,993	$	(2,696)	$	12	$	5,359	$	15	$	5,374
Stock repurchases	—		—		(323)		—		—		—		(323)		—		(323)
Effects of stock-based incentive compensation plans	—		—		—		81		—		—		81		—		81
Net income	—		—		—		—		502		—		502		—		502
Dividends declared on common stock	—		—		—		—		(75)		—		(75)		—		(75)
Dividends declared on preferred stock	—		—		—		—		(37)		—		(37)		—		(37)
Change in accumulated other comprehensive income	—		—		—		—		—		(2)		(2)		—		(2)
Other	—		—		—		1		—		—		1		—		1
Balances at September 30, 2023	$	2,000	$	5	$	(4,278)	$	10,075	$	(2,306)	$	10	$	5,506	$	15	$	5,521

See Notes to Condensed Consolidated Financial Statements

7

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 16 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. Certain prior period amounts have been reclassified to conform with the current year presentation.

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.

8

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 Accounting Standards Update (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. The ASU will result in additional disclosures, but the Company does not expect the adoption to have a material impact on our consolidated financial statements.

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 the adoption to have a material impact on our consolidated financial statements.

9

Expense Disaggregation Disclosures

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

Recent Developments

Nuclear PTCs

The IRA introduced a PTC for nuclear energy under Internal Revenue Code Section 45U that is available to existing nuclear units from 2024 through 2032. All our nuclear units qualify for this credit, which is based on the amount of electricity sold during the taxable year and is subject to a phase-out based on annual gross receipts. While we believe we meet the conditions for earning the nuclear PTC, we are awaiting guidance from the U.S. Treasury and IRS on the implementation of IRC Section 45U, particularly on the definition of gross receipts including the treatment of hedges, among other key components to industry interpretations of the definition. The forthcoming guidance could have a significant impact on our estimate of PTC revenues. The amount of nuclear PTCs recorded could have a material impact on our 2024 financial statements.

Tax Credit Transfer Agreement

In October 2024, we sold $156 million of transferable ITCs we recognized as a result of the Moss Landing Phase III site reaching commercial operations in June 2023, as well as $8 million and $3 million of PTCs generated at our Emerald Grove and Brightside solar facilities in 2023, respectively. Vistra received cash consideration from the sale in October 2024.

Debt and Financing Activity

See Note 9 for information on amendments to the Revolving Credit Facility and the Commodity-Linked Facility in October 2024.

Share Repurchase Program

In October 2024, the Board authorized $1.0 billion for additional repurchases under the Share Repurchase Program (see Note 15).

2.    ACQUISITIONS

Energy Harbor Business Combination

On March 1, 2024 (Merger Date), pursuant to a transaction agreement dated March 6, 2023 (Transaction Agreement), (i) Vistra Operations transferred certain of its subsidiary entities into Vistra Vision, (ii) Black Pen Inc., a wholly owned subsidiary of Vistra, merged with and into Energy Harbor, (iii) Energy Harbor became a wholly-owned subsidiary of Vistra Vision, and (iv) affiliates of Nuveen Asset Management, LLC (Nuveen) and Avenue Capital Management II, L.P. (Avenue) exchanged a portion of the Energy Harbor shares held by Nuveen and Avenue for a 15% equity interest of Vistra Vision (collectively, Energy Harbor Merger). The Energy Harbor Merger 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 the condensed consolidated financial statements beginning as of the Merger Date.

10

The following table summarizes the acquisition date fair value of Energy Harbor associated with the Energy Harbor Merger on the Merger Date:

	Consideration
	(in millions)
Cash consideration	$	3,100
15% of the fair value of net assets contributed to Vistra Vision by Vistra (a)	1,496
Total purchase price	4,596
Fair value of noncontrolling interest in Energy Harbor (b)	811
Acquisition date fair value of Energy Harbor	$	5,407

____________

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

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

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

Provisional fair value measurements were made for acquired assets and liabilities in the first quarter of 2024 and adjustments to those measurements were made in the second and third quarters of 2024. Additional adjustments 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:

	Updated Fair Value as of September 30, 2024		Measurement Period Adjustments recorded through September 30, 2024
	(in millions)
Cash and cash equivalents	$	35	$	5
Trade accounts receivables, inventories, prepaid expenses and other current assets	548		10
Investments (a)	2,021		—
Property, plant and equipment (b)	5,746		126
Identifiable intangible assets (c)	444		16
Commodity and other derivative contractual assets (d)	123		(17)
Other noncurrent assets	6		(2)
Total identifiable assets acquired	8,923		138
Trade accounts payable and other current liabilities	283		20
Long-term debt, including amounts due currently	413		—
Commodity and other derivative contractual liabilities (d)	173		(6)
Accumulated deferred income taxes	1,395		31
Asset retirement obligations (e)	1,368		—
Identifiable intangible liabilities	87		14
Other noncurrent liabilities and deferred credits	16		4
Total identifiable liabilities assumed	3,735		63
Identifiable net assets acquired	5,188		75
Goodwill (f)	219		(75)
Net assets acquired	$	5,407

____________

(a)Investments represent securities held in nuclear decommissioning trusts (NDT) for the purpose of funding the future retirement and decommissioning of the PJM nuclear generation facilities. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC. They are valued using a market approach (Level 1 or Level 2 depending on security).

(b)Acquired property, plant and equipment are valued using a combination of an income approach and a market approach. The income approach utilized a discounted cash flow analysis based upon a debt-free, free cash flow model (Level 3).

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(c)Includes acquired nuclear fuel supply contracts valued based on contractual cash flow projections over approximately five years compared with cash flows based on current market prices with the resulting difference discounted to present value (Level 3). Also includes acquired retail customer relationships which are valued based on discounted cash flow analysis of acquired customers and estimated attrition rates (Level 3).

(d)Acquired derivatives are valued using the methods described in Note 11 (Level 1, Level 2 or Level 3). Contracts with terms that were not at current market prices are also valued using a discounted cash flow analysis (Level 3).

(e)Asset retirement obligations are valued using a discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning methods and are based on decommissioning cost studies (Level 3).

(f)The excess of the consideration transferred over the fair value of identifiable assets acquired and liabilities assumed is recorded as goodwill. Goodwill represents expected synergies to be generated 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 and nine months ended September 30, 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 September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(in millions)
Revenues	$	6,288	$	4,872	$	13,911	$	13,456
Net income	$	1,837	$	379	$	2,411	$	1,109

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

Acquisition costs incurred in the Energy Harbor Merger totaled $1 million and $8 million for the three months ended September 30, 2024 and 2023, respectively, and $25 million and $21 million for the nine months ended September 30, 2024 and 2023, respectively, and are classified as selling, general and administrative expenses in the condensed consolidated statements of operations.

Acquisition of Non-Controlling Interest

On September 18, 2024 (the UPA Transaction Date), Vistra Operations and Vistra Vision Holdings I LLC, an indirect wholly owned subsidiary of Vistra Operations (Vistra Vision Holdings), entered into separate Unit Purchase Agreements (the UPAs) with each of Nuveen and Avenue, pursuant to which Vistra Vision Holdings has agreed to purchase each of Nuveen's and Avenue's combined 15% noncontrolling interest in Vistra Vision for $3.248 billion in cash, not including the adjustment for dividends of $165 million (collectively, the Transaction). If Nuveen and Avenue receive less than $165 million in dividend distributions from Vistra Vision for the remainder of 2024, then the purchase price payable on the Closing Date will be adjusted upward by the difference, and if they receive distributions in excess of $165 million, then the purchase price payable at the Closing Date will be adjusted downward by the difference. Total scheduled payments under the UPAs are $3.413 billion. The Transaction is expected to close on December 31, 2024 (the Closing Date), subject to the satisfaction of certain closing conditions, at which time Vistra Vision Holdings will own 100% of the equity interests in Vistra Vision.

12

In accordance with the UPAs, the payments to Nuveen and Avenue will be paid in multiple installments through December 31, 2026. Vistra Vision Holdings' obligation to pay the purchase price will be guaranteed by Vistra Operations and certain of its subsidiaries that guarantee Vistra Operations' unsecured notes. Cash payments including estimated dividends for the remainder of 2024 and thereafter are expected as follows:

	September 30, 2024
	(in millions)
Remainder of 2024	$	1,345
2025	1,114
2026	954
2027	—
2028	—
Thereafter	—
Total scheduled payments under the UPAs	$	3,413

The UPAs are subject to certain closing conditions outside our control and therefore represent conditional redemption obligations that require us to reflect the Transaction as redeemable noncontrolling interest within the mezzanine section of the condensed consolidated balance sheet. We accounted for the Transaction on the UPA Transaction Date as follows:

Fair value of redeemable noncontrolling interest (a)	$	3,198
Carrying value of NCI (b)	$	(1,659)
Additional paid-in-capital	$	(1,539)

____________

(a)Fair value represents the total scheduled payments under the UPAs of $3.413 billion discounted at 6%.

(b)Represents the carrying value of Nuveen's and Avenue's combined 15% noncontrolling interest in Vistra Vision at the UPA Transaction Date.

Upon satisfaction of all closing conditions, remaining payment obligations will be reflected as a financing obligation on the consolidated balance sheets.

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 moved 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)	Announced Retirement Date (a)	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 (b)	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 announced dates if economic or other conditions dictate.

(b)Following the retirement of Coleto Creek as a coal-fueled plant, the Company intends to repower it as a gas-fueled plant.

13

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 September 30, 2024
	Retail		Texas		East (a)		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Consolidated
	(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	2,500	$	—	$	—	$	—	$	—	$	—	$	—	$	2,500
Retail energy charge in Northeast/Midwest (a)	1,051		—		—		—		—		—		—		1,051
Wholesale generation revenue from ISO/RTO	—		95		251		51		123		—		—		520
Capacity revenue from ISO/RTO (b)	—		—		18		—		—		—		—		18
Revenue from other wholesale contracts	—		94		76		58		23		—		1		252
Total revenue from contracts with customers	3,551		189		345		109		146		—		1		4,341
Other revenues:
Intangible amortization	1		—		—		—		(1)		—		—		—
Transferable PTC revenues (c)	—		4		—		—		—		—		—		4
Hedging and other revenues (d)	681		827		188		132		103		1		11		1,943
Intersegment sales (e)	18		3,084		991		1		221		—		(4,315)		—
Total other revenues	700		3,915		1,179		133		323		1		(4,304)		1,947
Total revenues	$	4,251	$	4,104	$	1,524	$	242	$	469	$	1	$	(4,303)	$	6,288

____________

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

(b)Represents net capacity sold in each ISO/RTO. The East segment includes $30 million of capacity sold offset by $12 million of capacity purchased. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs and delivery fees in the condensed consolidated statement of operations includes capacity purchased of $44 million offset by $28 million of capacity sold within the East segment.

(c)Represents transferable PTCs generated from qualifying solar assets during the period.

(d)Includes $1.960 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
	(in millions)
September 30, 2024	$	308	$	2,711	$	340	$	99	$	82	$	2	$	—	$	(1,582)	$	1,960

___________________

(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.

(e)Texas, East, Sunset and West segments include $1.456 billion, $57 million, $68 million and $1 million, respectively, of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.

14

	Three Months Ended September 30, 2023
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Consolidated
	(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	2,667	$	—	$	—	$	—	$	—	$	—	$	—	$	2,667
Retail energy charge in Northeast/Midwest	464		—		—		—		—		—		—		464
Wholesale generation revenue from ISO/RTO	—		697		354		79		159		—		—		1,289
Capacity revenue from ISO/RTO (a)	—		—		12		—		8		—		—		20
Revenue from other wholesale contracts	—		202		75		50		22		—		—		349
Total revenue from contracts with customers	3,131		899		441		129		189		—		—		4,789
Other revenues:
Intangible amortization	1		—		—		—		(1)		—		—		—
Transferable PTC revenues	—		3		—		—		—		—		—		3
Hedging and other revenues (b)	251		(987)		(135)		215		(51)		—		1		(706)
Intersegment sales (c)	—		1,602		345		—		87		—		(2,034)		—
Total other revenues	252		618		210		215		35		—		(2,033)		(703)
Total revenues	$	3,383	$	1,517	$	651	$	344	$	224	$	—	$	(2,033)	$	4,086

____________

(a)Represents net capacity sold in each ISO/RTO. The East segment includes $32 million of capacity sold offset by $20 million of capacity purchased. The Sunset segment includes $8 million of capacity sold. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs and delivery fees in the condensed consolidated statement of operations includes capacity purchased of $7 million offset by $8 million of capacity sold within the East segment.

(b)Includes $345 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
	(in millions)
September 30, 2023	$	(70)	$	(380)	$	(128)	$	176	$	(118)	$	8	$	—	$	167	$	(345)

___________________

(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 $78 million, $81 million and $8 million, respectively, of intersegment unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

15

	Nine Months Ended September 30, 2024
	Retail (a)		Texas		East (a)		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Consolidated
	(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	6,241	$	—	$	—	$	—	$	—	$	—	$	—	$	6,241
Retail energy charge in Northeast/Midwest (a)	2,705		—		—		—		—		—		—		2,705
Wholesale generation revenue from ISO/RTO	—		213		621		168		288		—		—		1,290
Capacity revenue from ISO/RTO (b)	—		—		50		—		4		—		—		54
Revenue from other wholesale contracts	—		325		211		171		101		—		1		809
Total revenue from contracts with customers	8,946		538		882		339		393		—		1		11,099
Other revenues:
Intangible amortization	—		—		—		—		(3)		—		—		(3)
Transferable PTC revenues (c)	—		9		—		—		—		—		—		9
Hedging and other revenues (d)	924		283		200		385		277		1		12		2,082
Intersegment sales (e)	43		3,886		2,272		5		428		—		(6,634)		—
Total other revenues	967		4,178		2,472		390		702		1		(6,622)		2,088
Total revenues	$	9,913	$	4,716	$	3,354	$	729	$	1,095	$	1	$	(6,621)	$	13,187

____________

(a)Includes six months of revenues associated with operations acquired in the Energy Harbor Merger.

(b)Represents net capacity sold in each ISO/RTO. The East segment includes $90 million of capacity sold offset by $40 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 the condensed consolidated statement of operations includes capacity purchased of $88 million offset by $47 million of capacity sold within the East segment.

(c)Represents transferable PTCs generated from qualifying solar assets during the period.

(d)Includes $1.571 billion of unrealized net gains from mark-to-market valuations of commodity positions.

Nine Months Ended	Retail		Texas		East		West		Sunset		Asset Closure		Corporate and Other		Eliminations (1)		Consolidated
	(in millions)
September 30, 2024	$	(3)	$	1,436	$	259	$	320	$	35	$	8	$	—	$	(484)	$	1,571

___________________

(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.

(e)Texas and Sunset segments include $547 million and $48 million, respectively, of intersegment unrealized net gains and East segment includes $114 million of intersegment unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

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	Nine Months Ended September 30, 2023
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Consolidated
	(in millions)
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	6,079	$	—	$	—	$	—	$	—	$	—	$	—	$	6,079
Retail energy charge in Northeast/Midwest	1,242		—		—		—		—		—		—		1,242
Wholesale generation revenue from ISO/RTO	—		929		756		316		279		—		—		2,280
Capacity revenue from ISO/RTO (a)	—		—		42		—		35		—		—		77
Revenue from other wholesale contracts	—		411		584		128		123		—		—		1,246
Total revenue from contracts with customers	7,321		1,340		1,382		444		437		—		—		10,924
Other revenues:
Intangible amortization	—		—		(2)		—		(2)		—		—		(4)
Transferable PTC revenues	—		8		—		—		—		—		—		8
Hedging and other revenues (b)	840		(1,233)		288		349		528		—		1		773
Intersegment sales (c)	—		2,946		1,637		6		403		—		(4,992)		—
Total other revenues	840		1,721		1,923		355		929		—		(4,991)		777
Total revenues	$	8,161	$	3,061	$	3,305	$	799	$	1,366	$	—	$	(4,991)	$	11,701

____________

(a)Represents net capacity sold in each ISO/RTO. The East segment includes $115 million of capacity sold offset by $73 million of capacity purchased. The Sunset segment includes $71 million of capacity sold offset by $36 million of capacity purchased. Net capacity purchased in each ISO/RTO included in fuel, purchased power costs and delivery fees in the condensed consolidated statement of operations includes capacity purchased of $68 million offset by $58 million of capacity sold within the East segment.

(b)Includes $1.020 billion of unrealized net gains from mark-to-market valuations of commodity positions.

Nine Months Ended	Retail		Texas		East		West		Sunset		Asset Closure		Corporate and Other		Eliminations (1)		Consolidated
	(in millions)
September 30, 2023	$	95	$	(686)	$	1,017	$	293	$	462	$	32	$	—	$	(193)	$	1,020

___________________

(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 segment includes $388 million of intersegment net losses and East and Sunset segments include $440 million and $144 million, respectively, of intersegment unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.

Performance Obligations

As of September 30, 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
	(in millions)
Remaining performance obligations	$	138	$	1,112	$	797	$	273	$	122	$	610	$	3,052

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Trade Accounts Receivable

	September 30, 2024		December 31, 2023
	(in millions)
Wholesale and retail trade accounts receivable	$	2,267	$	1,735
Allowance for uncollectible accounts	(88)		(61)
Trade accounts receivable — net	$	2,179	$	1,674
Trade accounts receivable from contracts with customers — net	$	1,792	$	1,239
Other trade accounts receivable — net	387		435
Trade accounts receivable — net	$	2,179	$	1,674

Gross trade accounts receivable as of September 30, 2024 and December 31, 2023 include unbilled retail revenues of $917 million and $614 million, respectively.

Allowance for Uncollectible Accounts Receivable

	Nine Months Ended September 30,
		2024		2023
		(in millions)
Allowance for uncollectible accounts receivable at beginning of period		$	61	$	65
Increase for bad debt expense		132		131
Decrease for account write-offs		(105)		(110)
Allowance for uncollectible accounts receivable at end of period		$	88	$	86

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 September 30,						Nine Months Ended September 30,
	2024			2023			2024			2023
	(in millions)
Net income before income taxes	$	2,392		$	671		$	3,016		$	2,146
Income tax expense	$	(555)		$	(169)		$	(694)		$	(470)
Effective tax rate	23.2		%	25.2		%	23.0		%	21.9		%

We evaluate and update our annual effective income tax rate on an interim basis based on current and forecasted earnings and tax laws.

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

For the three months ended September 30, 2023, the effective tax rate of 25.2% was higher than the U.S. federal statutory rate of 21% due primarily to state income taxes. For the nine months ended September 30, 2023, the effective tax rate of 21.9% was higher than the U.S. federal statutory rate of 21% due primarily to state income taxes, partially offset by the release of uncertain tax positions related to the 2018 and 2019 IRS audit closed in the second quarter of 2023.

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Inflation Reduction Act of 2022 (IRA)

In August 2022, the U.S. enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases. We do not expect Vistra to be subject to the CAMT in the 2024 tax year as it applies only to corporations with a three-year average annual adjusted financial statement income in excess of $1 billion. We have taken the CAMT and relevant extensions or expansions of existing tax credits applicable to projects in our immediate development pipeline into account when forecasting cash taxes. See Note 1 for discussion of the nuclear PTC introduced by the IRA.

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 June 2023 we recognized $154 million of transferable ITCs associated with the project in other noncurrent assets in the condensed consolidated balance sheet. In September 2024, we recognized an additional $2 million of transferable ITCs associated with the project and reclassified the $156 million of credits to other current assets. In October 2024, these credits were sold for cash consideration (see Note 1).

Final Section 163(j) Regulations

The final Section 163(j) regulations, which limits qualified deductions for business interest expense, were issued in July 2020 and provided a critical correction to the proposed regulations regarding the computation of adjusted taxable income. As of January 1, 2022, certain provisions in the final Section 163(j) regulations have sunset, including the add-back of depreciation and amortization to adjusted taxable income. As a result, under the law as currently enacted, Vistra's deductible business interest expense was significantly limited for the 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 add-back of depreciation and amortization to adjusted taxable income.

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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 September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(in millions, except share data)
Net income attributable to Vistra	$	1,888	$	502	$	2,218	$	1,677
Less cumulative dividends attributable to Series A Preferred Stock	(20)		(20)		(60)		(60)
Less cumulative dividends attributable to Series B Preferred Stock	(17)		(17)		(52)		(52)
Less cumulative dividends attributable to Series C Preferred Stock	(11)		—		(32)		—
Net income attributable to common stock — basic and diluted	1,840		465		$	2,074	$	1,565
Weighted average shares of common stock outstanding:
Basic	342,969,916		366,570,040		346,315,125		374,323,466
Dilutive securities: Stock-based incentive compensation plan	7,233,776		5,579,059		7,490,812		4,778,892
Diluted	350,203,692		372,149,099		353,805,937		379,102,358
Net income per weighted average share of common stock outstanding:
Basic	$	5.36	$	1.27	$	5.99	$	4.18
Diluted	$	5.25	$	1.25	$	5.86	$	4.13

Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 531 and 17,847 for the three months ended September 30, 2024 and 2023, respectively, and 11,210 and 1,491,299 shares for the nine months ended September 30, 2024 and 2023, respectively.

7.    GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

Goodwill

As of September 30, 2024 and December 31, 2023, the carrying value of goodwill totaled $2.802 billion and $2.583 billion, respectively.

	Retail Segment		Texas Segment
	Retail Reporting Unit (a)		Texas Generation Reporting Unit		Total Goodwill
	(in millions)
Balance at December 31, 2023	$	2,461	$	122	$	2,583
Goodwill recorded in connection with the Energy Harbor Merger (b)					219
Balance at September 30, 2024	$	2,461	$	122	$	2,802

____________

(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.

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Identifiable Intangible Assets and Liabilities

Identifiable intangible assets are comprised of the following:

	September 30, 2024						December 31, 2023
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
	(in millions)
Retail customer relationships	$	2,173	$	1,948	$	225	$	2,088	$	1,866	$	222
Software and other technology-related assets	581		277		304		536		315		221
Retail and wholesale contracts	503		312		191		233		217		16
Long-term service agreements	18		5		13		18		5		13
Other identifiable intangible assets (a)	95		12		83		62		11		51
Total identifiable intangible assets subject to amortization	$	3,370	$	2,554	816		$	2,937	$	2,414	523
Retail trade names (not subject to amortization)					1,341						1,341
Total identifiable intangible assets					$	2,157					$	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	September 30, 2024		December 31, 2023
	(in millions)
Long-term service agreements	$	111	$	122
Power and fuel purchase contracts	52		9
Total identifiable intangible liabilities	$	163	$	131

Expense related to finite-lived identifiable intangible assets and liabilities (including the classification in the condensed consolidated statements of operations) are comprised of the following:

Identifiable Intangible Assets/Liabilities	Condensed Consolidated Statements of Operations	Three Months Ended September 30,				Nine Months Ended September 30,
		2024		2023		2024		2023
		(in millions)
Retail customer relationships	Depreciation and amortization	$	29	$	25	$	82	$	74
Software and other technology-related assets	Depreciation and amortization	15		15		43		44
Retail and wholesale contracts	Operating revenues/fuel, purchased power costs and delivery fees	(5)		—		(9)		6
Other identifiable intangible assets	Fuel, purchased power costs and delivery fees	131		99		327		261
Total identifiable intangible assets expense, net (a)		$	170	$	139	$	443	$	385

___________

(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 the condensed consolidated statements of operations. Emissions allowance obligations are accrued as associated electricity is generated and renewable energy certificate obligations are accrued as retail electricity delivery occurs.

21

Estimated Amortization of Identifiable Intangible Assets

As of September 30, 2024, the estimated aggregate amortization expense of identifiable intangible assets, excluding environmental allowances, for each of the next five fiscal years is as shown below.

Year	Estimated Amortization Expense
	(in millions)
2024	$	313
2025	$	222
2026	$	158
2027	$	63
2028	$	42

8.    COLLATERAL FINANCING AGREEMENT WITH AFFILIATE

On June 15, 2023, Vistra Operations entered into a facility agreement (Facility Agreement) with a Delaware trust formed by the Company (the Trust) that sold 450,000 pre-capitalized trust securities (P-Caps) redeemable May 17, 2028 for an initial purchase price of $450 million. The Trust is not consolidated by Vistra. The Trust invested the proceeds from the sale of the P-Caps in a portfolio of either (a) U.S. Treasury securities (Treasuries) or (b) Treasuries and/or principal and interest strips of Treasuries (Treasury Strips, and together with the Treasuries and cash denominated in U.S. dollars, the Eligible Assets). At the direction of Vistra Operations, the Eligible Assets held by the Trust can be (i) delivered to one or more designated subsidiaries of Vistra Operations in order to allow such subsidiaries to use the Eligible Assets to meet certain posting obligations with counterparties, and/or (ii) pledged as collateral support for a letter of credit program.

Under the Facility Agreement, Vistra Operations has the right (Issuance Right), from time to time, to require the Trust to purchase from Vistra Operations up to $450 million aggregate principal amount of Vistra Operations' 7.233% Senior Secured Notes due 2028 (7.233% Senior Secured Notes) in exchange for the delivery of all or a portion of the Treasuries and Treasury Strips corresponding to the portion of the issuance right exercised at such time.

The Trust will terminate at any time prior to May 17, 2028 and distribute the 7.233% Senior Secured Notes to the holders of the P-Caps if its sole assets consist of 7.233% Senior Secured Notes that Vistra Operations is no longer entitled to repurchase.

Vistra Operations pays a facility fee (Facility Fee) to the Trust payable on each May 17 and November 17, commencing on November 17, 2023, to and including May 17, 2028 (each, a Distribution Date), and on certain other dates as provided in the Facility Agreement. The Facility Fee is generally calculated at a rate of 3.3608% per annum, applied to the maximum amount of 7.233% Senior Secured Notes that Vistra Operations could issue and sell to the Trust under the Facility Agreement as of the close of business on the business day immediately preceding the applicable Distribution Date.

As of September 30, 2024 and December 31, 2023, the fair value of Eligible Assets held by counterparties to satisfy current and future margin deposit requirements totaled $451 million and $439 million, respectively, and are reported in the condensed consolidated balance sheets as margin deposits posted under affiliate financing agreement and margin deposits financing with affiliate.

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9.    DEBT, CREDIT FACILITIES AND FINANCINGS

Amounts in the table below represent the categories of debt obligations incurred by the Company.

	September 30, 2024		December 31, 2023
	(in millions)
Long-term debt, including amounts due currently:
Non-recourse debt	$	697	$	—
Recourse debt	14,173		14,517
Long -term debt before unamortized premiums, discounts and issuance costs	14,870		14,517
Unamortized premiums, discounts and issuance costs	(140)		(115)
Long-term debt including debt due currently	$	14,730	$	14,402
Accounts receivable financing	$	750	$	—

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Long-Term Debt

Amounts in the table below represent the categories of long-term debt obligations, including amounts due currently, incurred by the Company.

	September 30, 2024		December 31, 2023
	(in millions)
Vistra Operations Credit Facilities, Term Loan B-3 Facility due December 20, 2030	$	2,481	$	2,500
Vistra Zero Credit Facility, Term Loan B Facility due April 30, 2031	697		—
Vistra Operations Senior Secured Notes:
4.875% Senior Secured Notes, due May 13, 2024	—		400
3.550% Senior Secured Notes, due July 15, 2024	—		1,500
5.125% Senior Secured Notes, due May 13, 2025	744		1,100
3.700% Senior Secured Notes, due January 30, 2027	800		800
4.300% Senior Secured Notes, due July 15, 2029	800		800
6.950% Senior Secured Notes, due October 15, 2033	1,050		1,050
6.000% Senior Secured Notes, due April 15, 2034	500		—
Total Vistra Operations Senior Secured Notes	3,894		5,650
Energy Harbor Revenue Bonds:
3.375% Revenue Bond, due August 1, 2029	100		—
4.750% Revenue Bonds, due June 1, 2033 and July 1, 2033	285		—
3.750% Revenue Bond, due October 1, 2047	46		—
Total Energy Harbor Revenue Bonds	431		—
Vistra Operations Senior Unsecured Notes:
5.500% Senior Unsecured Notes, due September 1, 2026	1,000		1,000
5.625% Senior Unsecured Notes, due February 15, 2027	1,300		1,300
5.000% Senior Unsecured Notes, due July 31, 2027	1,300		1,300
4.375% Senior Unsecured Notes, due May 15, 2029	1,250		1,250
7.750% Senior Unsecured Notes, due October 15, 2031	1,450		1,450
6.875% Senior Unsecured Notes, due April 15, 2032	1,000		—
Total Vistra Operations Senior Unsecured Notes	7,300		6,300
Other:
Equipment Financing Agreements	67		67
Total other long-term debt	67		67
Unamortized debt premiums, discounts and issuance costs	(140)		(115)
Total long-term debt including amounts due currently	14,730		14,402
Less amounts due currently	(785)		(2,286)
Total long-term debt less amounts due currently	$	13,945	$	12,116

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Long-Term Debt Maturities

Long-term debt maturities as of September 30, 2024 are as follows:

	September 30, 2024
	(in millions)
Remainder of 2024	$	20
2025	786
2026	1,038
2027	3,434
2028	34
Thereafter	9,558
Unamortized premiums, discounts and debt issuance costs	(140)
Total long-term debt, including amounts due currently	$	14,730

Credit Facilities

Our credit facilities and related available capacity as of September 30, 2024 are presented below.

		September 30, 2024
Credit Facilities	Maturity Date	Facility Limit		Cash Borrowings (Short-Term)		Cash Borrowings (Long-Term)		Letters of Credit Outstanding		Available Capacity
		(in millions)
Revolving Credit Facility	April 29, 2027	$	3,175	$	—	$	—	$	718	$	2,457
Term Loan B-3 Facility	December 20, 2030	2,481		—		2,481		—		—
Total Vistra Operations Credit Facilities		$	5,656	$	—	$	2,481	$	718	$	2,457
Vistra Operations Commodity-Linked Facility	October 2, 2024	1,575		—		—		—		633
Vistra Zero Term Loan B Facility	April 30, 2031	697		—		697		—		—
Total credit facilities		$	7,928	$	—	$	3,178	$	718	$	3,090

Vistra Operations Credit Facilities

As of September 30, 2024, the Vistra Operations Credit Facilities consisted of up to $5.656 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 up to $2.940 billion, and term loans of $2.481 billion (Term Loan B-3 Facility). The Revolving Credit Facility is used for general corporate purposes. In October 2024, Vistra Operations amended the Revolving Credit Facility which, among other things, increased revolving credit commitments to $3.440 billion and extended the maturity date to October 11, 2029.

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 September 30, 2024, after taking into account sustainability pricing adjustments based on certain sustainability-linked targets and thresholds, the applicable interest rate margins for the Revolving Credit Facility and the fee for undrawn amounts relating to such commitments were 1.725% and 27.0 basis points, respectively, and the applicable interest rate margin for the letters of credit issued under the Revolving Credit facility was 1.725%. 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 10) on outstanding borrowings of $2.481 billion was 6.85% as of September 30, 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 October 11, 2029 (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, for periods prior to the October 2024 amendment, was applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $300 million) exceeded 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 September 30, 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 September 30, 2024, the borrowing base of $633 million is lower than the facility limit which represents the aggregate commitments of $1.575 billion. In October 2024, Vistra Operations amended the Commodity-Linked Facility which, among other things, increased the aggregate available commitments to $1.75 billion and extended the maturity date to October 1, 2025.

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

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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 September 30, 2024, after taking into account sustainability pricing adjustments based on certain sustainability-linked targets and thresholds, 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 1.725% and 27.0 basis points, respectively.

The Vistra Operations Commodity-Linked Credit Agreement includes a covenant, solely during a compliance period (which, for periods prior to the October 2024 amendment, in general, was applicable when the aggregate revolving borrowings exceeded 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 Non-recourse 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 were 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. Fees and expenses related to entering the agreement totaling $8 million and a discount totaling $4 million were capitalized as reductions in the carrying amount of the debt.

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 $697 million was 7.60% as of September 30, 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.

Letter of Credit Facilities

Vistra Operations Secured Letter of Credit Facilities

Between August 2020 and July 2024, we entered into uncommitted standby letter of credit facilities with various banks (each, a Secured LOC Facility and collectively, the Secured LOC Facilities). The Secured LOC Facilities are secured by a first lien on substantially all of Vistra Operations' (and certain of its subsidiaries') assets (which ranks pari passu with the Vistra Operations Credit Facilities). The Secured LOC Facilities may be renewed annually and are used for general corporate purposes. As of September 30, 2024, $1.162 billion 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 Facilities

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

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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). The Energy Harbor LOC Facility was terminated in April 2024.

Vistra Operations Senior Secured Notes

In May 2024 and July 2024, the 4.875% senior secured notes due May 2024 and the 3.550% senior secured notes due July 2024, respectively, were repaid at maturity.

In April 2024, Vistra Operations issued $500 million aggregate principal amount of 6.000% senior secured notes due 2034 (6.000% Senior Secured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act. The 6.000% Senior Secured Notes provide 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, were to be used for general corporate purposes, including to refinance outstanding indebtedness (including the senior secured debt maturities in May 2024 and July 2024). Fees and expenses related to the offering, including commissions and the original issue discount, totaled $6 million and were capitalized as a reduction in the carrying amount of the debt.

Since 2019, Vistra Operations has issued and sold its 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 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, the 6.950% senior secured notes due 2033 and the 6.000% 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, were to be used for general corporate purposes, including to refinance outstanding indebtedness (including the senior secured debt maturities in May 2024 and July 2024). Fees and expenses related to the offering totaled $12 million and were capitalized as a reduction in the carrying amount of the debt.

Since 2018, Vistra Operations has issued and sold its 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, the 7.750% senior unsecured notes due 2031 and the 6.875% 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.

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Other Debt Activity

Senior Secured Notes Tender Offer

In January 2024, Vistra Operations used the net proceeds from (i) the December 2023 issuances of the 6.950% senior secured notes due 2033 and 7.750% senior unsecured notes due 2031 and (ii) cash on hand, to fund a cash tender offer (Senior Secured Notes Tender Offer) to purchase for cash $759 million aggregate principal amount of certain notes, including $58 million of 4.875% senior secured notes due 2024, $345 million of 3.550% senior secured notes due 2024 and $356 million of the 5.125% senior secured notes due 2025. We recorded an extinguishment gain of $6 million on the transaction in the first quarter of 2024.

Debt Repurchase Program

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.

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). 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. The Receivables Facility was renewed and amended in July 2024, extending the term of the Receivables Facility to July 2025.

In connection with the Receivables Facility, TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands, Energy Harbor LLC and TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), each sell and/or contribute, subject to certain exclusions, all of its receivables (other than any receivables excluded pursuant to the terms of the Receivables Facility), arising from the sale of electricity to its customers and related rights (Receivables), to RecCo, a consolidated, wholly owned, bankruptcy-remote, direct subsidiary of TXU Energy. RecCo, in turn, is subject to certain conditions, and may draw under the Receivables Facility up to the limit described above to fund its acquisition of the Receivables from the Originators. RecCo has granted a security interest on the Receivables and all related assets for the benefit of the Purchasers under the Receivables Facility and Vistra Operations has agreed to guarantee the performance of the obligations of the Originators and TXU Energy, as the servicer, under the agreements governing the Receivables Facility. Amounts funded by the Purchasers to RecCo are reflected as short-term borrowings in the condensed consolidated balance sheets. Proceeds and repayments under the Receivables Facility are reflected as cash flows from financing activities in the condensed consolidated statements of cash flows. Receivables transferred to the Purchasers remain on Vistra's balance sheet and Vistra reflects a liability equal to the amount advanced by the Purchasers. The Company records interest expense on amounts advanced. TXU Energy continues to service, administer and collect the Receivables on behalf of RecCo and the Purchasers, as applicable.

As of September 30, 2024, outstanding borrowings under the Receivables Facility totaled $750 million and were supported by $1.645 billion of RecCo gross receivables. As of December 31, 2023, there were no outstanding borrowings under the Receivables Facility.

Repurchase Facility

TXU Energy and the other Originators under the Receivables Facility have a repurchase facility (Repurchase Facility) that is provided on an uncommitted basis by a commercial bank as buyer (Buyer). In July 2024, the Repurchase Facility was renewed until July 2025 while maintaining the facility size of $125 million. The Repurchase Facility is collateralized by a subordinated note (Subordinated Note) issued by RecCo in favor of TXU Energy for the benefit of Originators under the Receivables Facility and representing a portion of the outstanding balance of the purchase price paid for the Receivables sold by the Originators to RecCo under the Receivables Facility. Under the Repurchase Facility, TXU Energy may request that Buyer transfer funds to TXU Energy in exchange for a transfer of the Subordinated Note, with a simultaneous agreement by TXU Energy to transfer funds to Buyer at a date certain or on demand in exchange for the return of the Subordinated Note (collectively, the Repo Transaction). Each Repo Transaction is expected to have a term of one month, unless terminated earlier on demand by TXU Energy or terminated by Buyer after an event of default.

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

There were no outstanding borrowings under the Repurchase Facility as of both September 30, 2024 and December 31, 2023.

10.    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 September 30, 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 11 for a discussion of the fair value of derivatives.

Commodity Hedging and Trading Activity

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 (commodity contracts). 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 the 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 by converting floating-rate interest to fixed rates. 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 the condensed consolidated statements of operations in interest expense and related charges.

As of September 30, 2024, Vistra has entered into the following interest rate swaps:

	Notional Amount	Expiration Date	Rate Range (c)
	(in millions, except percentages)
Swapped to fixed (a)	$3,000	July 2026	4.89	%	-	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%.

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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 the condensed consolidated balance sheets as of September 30, 2024 and December 31, 2023.

	September 30, 2024
	Derivative Assets				Derivative Liabilities
	Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total
	(in millions)
Current assets	$	2,826	$	25	$	3	$	—	$	2,854
Noncurrent assets	849		1		36		—		886
Current liabilities	(5)		—		(3,542)		(16)		(3,563)
Noncurrent liabilities	(6)		—		(1,115)		(20)		(1,141)
Net assets (liabilities)	$	3,664	$	26	$	(4,618)	$	(36)	$	(964)

	December 31, 2023
	Derivative Assets				Derivative Liabilities
	Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total
	(in millions)
Current assets	$	3,585	$	53	$	7	$	—	$	3,645
Noncurrent assets	565		11		1		—		577
Current liabilities	(1)		—		(5,233)		(24)		(5,258)
Noncurrent liabilities	(5)		—		(1,659)		(24)		(1,688)
Net assets (liabilities)	$	4,144	$	64	$	(6,884)	$	(48)	$	(2,724)

The following table presents the pre-tax realized and unrealized effect of derivative gains (losses) on net income. Amount represents changes in fair value of open 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)	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(in millions)
Commodity contracts (Operating revenues)	$	1,206	$	(1,118)	$	399	$	(450)
Commodity contracts (Fuel, purchased power costs and delivery fees)	(128)		48		(24)		(280)
Interest rate swaps (Interest expense and related charges)	(73)		51		7		101
Net gain (loss)	$	1,005	$	(1,019)	$	382	$	(629)

Balance Sheet Presentation of Derivatives

We elect to report derivative assets and liabilities in the 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 the 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:

	September 30, 2024								December 31, 2023
	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
	(in millions)
Derivative assets:
Commodity contracts	$	3,664	$	(2,750)	$	(169)	$	745	$	4,144	$	(3,519)	$	(26)	$	599
Interest rate swaps	26		(15)		—		11		64		(28)		—		36
Total derivative assets	3,690		(2,765)		(169)		756		4,208		(3,547)		(26)		635
Derivative liabilities:
Commodity contracts	(4,618)		2,750		316		(1,552)		(6,884)		3,519		970		(2,395)
Interest rate swaps	(36)		15		—		(21)		(48)		28		—		(20)
Total derivative liabilities	(4,654)		2,765		316		(1,573)		(6,932)		3,547		970		(2,415)
Net amounts	$	(964)	$	—	$	147	$	(817)	$	(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 September 30, 2024 and December 31, 2023:

	September 30, 2024		December 31, 2023
Derivative type	Notional Volume				Unit of Measure
Natural gas (a)	4,775		5,335		Million MMBtu
Electricity	786,155		800,001		GWh
Financial transmission rights (b)	243,755		250,895		GWh
Coal	33		35		Million U.S. tons
Fuel oil	16		3		Million gallons
Emissions	62		24		Million U.S. tons
Renewable energy certificates	28		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:

	September 30, 2024		December 31, 2023
	(in millions)
Fair value of derivative contract liabilities (a)	$	(1,369)	$	(1,890)
Offsetting fair value under netting arrangements (b)	720		692
Cash collateral and letters of credit	441		854
Liquidity exposure	$	(208)	$	(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 September 30, 2024, total credit risk exposure to all counterparties related to derivative contracts totaled $4.077 billion (including associated accounts receivable). The net exposure to those counterparties totaled $827 million as of September 30, 2024, after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure from any single counterparty totaling $250 million. As of September 30, 2024, the credit risk exposure to the banking and financial sector represented 75% of the total credit risk exposure and 25% 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.

11.    FAIR VALUE MEASUREMENTS

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

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

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

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

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

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Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

	September 30, 2024										December 31, 2023
	Level 1		Level 2		Level 3		Reclass (a)		Total		Level 1		Level 2		Level 3		Reclass (a)		Total
	(in millions)
Assets:
Commodity contracts (b)	$	2,205	$	464	$	995	$	50	$	3,714	$	2,886	$	628	$	630	$	14	$	4,158
Interest rate swaps (b)	—		26		—		—		26		—		64		—		—		64
NDTs – equity securities (c) (d)	1,537		—		—				1,537		638		—		—				638
NDTs – debt securities (c) (e)	74		2,031		—				2,105		—		734		—				734
Sub-total	$	3,816	$	2,521	$	995	$	50	7,382		$	3,524	$	1,426	$	630	$	14	5,594
Assets measured at net asset value (f):
NDTs – equity securities (c) (d) (f)									802										579
Total assets									$	8,184									$	6,173
Liabilities:
Commodity contracts	$	2,359	$	747	$	1,512	$	50	$	4,668	$	3,815	$	1,395	$	1,674	$	14	$	6,898
Interest rate swaps	—		36		—		—		36		—		48		—		—		48
Total liabilities	$	2,359	$	783	$	1,512	$	50	$	4,704	$	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 the condensed consolidated balance sheets.

(b)See Note 10 for definitions of commodity contracts and interest rate swaps.

(c)NDT assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facilities. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT. The NDT investments are included in investments in the condensed consolidated balance sheets.

(d)The investment objective for NDT equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index for U.S. equity investments and the MSCI EAFE Index for non-U.S. equity investments.

(e)The investment objective for NDT debt securities is to invest in a diversified, high quality, tax efficient portfolio. The debt securities are weighted with government and investment grade corporate bonds. Other investable debt securities include, but are not limited to, municipal bonds, high yield bonds, securitized bonds, non-U.S. developed bonds, emerging market bonds, loans and treasury inflation-protected securities. The debt securities had an average coupon rate of 3.96% and 3.19% as of September 30, 2024 and December 31, 2023, respectively, and an average maturity of 8 years and 11 years as of both September 30, 2024 and December 31, 2023. NDT debt securities held as of September 30, 2024 mature as follows: $1.011 billion in one to five years, $616 million in five to 10 years and $478 million after 10 years.

(f)Net asset value is a practical expedient used for the classification of assets that do not have readily determinable fair values and therefore are not classified in the fair value hierarchy. This amount is presented to permit reconciliation of this table to the amounts presented in the condensed consolidated balance sheets.

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The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations as of September 30, 2024 and December 31, 2023:

September 30, 2024
	Fair Value
Contract Type (a)	Assets		Liabilities		Total, Net		Valuation Technique	Significant Unobservable Input	Range (b)			Average (b)
	(in millions)
Electricity purchases and sales	$	773	$	(1,235)	$	(462)	Income Approach	Hourly price curve shape (c)	$—	to	$95	$48
									MWh
								Illiquid delivery periods for hub power prices and Heat Rates (d)	$20	to	$115	$68
									MWh
Options	11		(173)		(162)		Option Pricing Model	Natural gas to power correlation (e)	10%	to	100%	55%
								Power and natural gas volatility (e)	5%	to	710%	359%
Financial transmission rights/Congestion revenue rights	176		(32)		144		Market Approach (f)	Illiquid price differences between settlement points (g)	$(35)	to	$20	$(7)
									MWh
Natural gas	23		(65)		(42)		Income Approach	Natural gas basis (h)	$—	to	$10	$4
									MMBtu
								Illiquid delivery periods (i)	$—	to	$5	$4
									MMBtu
Other (j)	12		(7)		5
Total	$	995	$	(1,512)	$	(517)

December 31, 2023
	Fair Value
Contract Type (a)	Assets		Liabilities		Total, Net		Valuation Technique	Significant Unobservable Input	Range (b)			Average (b)
	(in millions)
Electricity purchases and sales	$	449	$	(1,273)	$	(824)	Income Approach	Hourly price curve shape (c)	$—	to	$85	$44
									MWh
								Illiquid delivery periods for hub power prices and Heat Rates (d)	$30	to	$110	$71
									MWh
Options	1		(237)		(236)		Option Pricing Model	Natural gas to power correlation (e)	10%	to	100%	55%
								Power and natural gas volatility (e)	10%	to	870%	441%
Financial transmission rights/Congestion revenue rights	157		(34)		123		Market Approach (f)	Illiquid price differences between settlement points (g)	$(85)	to	$25	$(30)
									MWh
Natural gas	9		(112)		(103)		Income Approach	Natural gas basis (h)	$—	to	$15	$6
									MMBtu
								Illiquid delivery periods (i)	$—	to	$5	$4
									MMBtu
Other (j)	14		(18)		(4)
Total	$	630	$	(1,674)	$	(1,044)

____________

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(a)(i) Electricity purchase and sales contracts include power and Heat Rate positions in ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO regions, (ii) Options consist of physical electricity options, spread options and natural gas options, (iii) Forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points are referred to as congestion revenue rights (CRRs) in ERCOT and financial transmission rights (FTRs) in PJM, ISO-NE, NYISO and MISO regions, and (iv) Natural gas contracts include swaps and forward contracts.

(b)The range of the inputs may be influenced by factors such as time of day, delivery period, season and location. The average represents the arithmetic average of the underlying inputs and is not weighted by the related fair value or notional amount.

(c)Primarily based on the historical range of forward average hourly ERCOT North Hub and ERCOT South and West Zone prices.

(d)Primarily based on historical forward ERCOT and PJM power prices and ERCOT Heat Rate variability.

(e)Primarily based on the historical forward correlation and volatility within ERCOT and PJM.

(f)While we use the market approach, there is insufficient market data for the inputs to the valuation to consider the valuation liquid.

(g)Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones.

(h)Primarily based on the historical forward PJM and Northeast natural gas basis prices and fixed prices.

(i)Primarily based on the historical forward natural gas fixed prices.

(j)Other includes contracts for coal and environmental allowances.

The following table presents the changes in fair value of 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 September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(in millions)
Net liability balance at beginning of period	$	(1,104)	$	(1,120)	$	(1,044)	$	(1,219)
Total unrealized valuation gains (losses)	482		(548)		194		(498)
Purchases, issuances and settlements (a):
Purchases	62		53		193		153
Issuances	(7)		(6)		(24)		(19)
Settlements	57		158		196		120
Transfers into Level 3 (b)	5		(38)		(15)		(50)
Transfers out of Level 3 (b)	(12)		217		(4)		229
Net liabilities assumed in connection with the Energy Harbor Merger	—		—		(13)		—
Net change	587		(164)		527		(65)
Net liability balance at end of period	$	(517)	$	(1,284)	$	(517)	$	(1,284)
Unrealized valuation gains (losses) relating to instruments held at end of period	$	361	$	(486)	$	(114)	$	(734)

____________

(a)Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received, including CRRs and FTRs.

(b)Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. For the three months ended September 30, 2024, transfers into Level 3 primarily consist of natural gas 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. For the nine months ended September 30, 2024, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power and natural gas derivatives where forward pricing inputs have become observable. For the three months ended September 30, 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. For the nine months ended September 30, 2023, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become observable.

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Assets and Liabilities Recorded on a Non-Recurring Basis

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

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

12.    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)
Other repurchases	(161,274)
TRA Rights outstanding as of September 30, 2024 (d)	8,033,789

____________

(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 the condensed consolidated balance sheets:

	Nine Months Ended September 30,
	2024		2023
	(in millions)
TRA obligation at the beginning of the period	$	171	$	522
Accretion expense	6		62
Changes in tax assumptions impacting timing of payments	(1)		66
Impacts of Tax Receivable Agreement	5		128
Repurchase/tender of TRA Rights	(161)		—
TRA obligation at the end of the period	15		650
Less amounts due currently	—		(10)
Noncurrent TRA obligation at the end of the period	$	15	$	640

13.    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 14 for a discussion of proposed and final regulations which could result in additional AROs if enacted as proposed and/or if decommissioning timing and cost estimates are revised based on potential applicability of the rules.

The following table summarizes the changes to our current and noncurrent ARO liabilities:

	Nine Months Ended September 30, 2024						Nine Months Ended September 30, 2023
	Nuclear Plant Decommissioning		Land Reclamation, Coal Ash and Other		Total		Nuclear Plant Decommissioning		Land Reclamation, Coal Ash and Other		Total
	(in millions)
Liability at beginning of period	$	1,742	$	796	$	2,538	$	1,688	$	749	$	2,437
Additions:
Accretion (a)	95		31		126		40		26		66
Adjustment for change in estimates	—		18		18		—		30		30
Adjustment for obligations assumed through acquisition	1,368		—		1,368		—		—		—
Reductions:
Payments	—		(64)		(64)		—		(60)		(60)
Liability at end of period	3,205		781		3,986		1,728		745		2,473
Less amounts due currently	—		(102)		(102)		—		(123)		(123)
Noncurrent liability at end of period	$	3,205	$	679	$	3,884	$	1,728	$	622	$	2,350

____________

(a)For the nine months ended September 30, 2024, nuclear plant decommissioning accretion includes $53 million of accretion expense recognized in operating costs in the condensed consolidated statements of operations and $42 million reflected as a change in regulatory liability in the condensed consolidated balance sheets. For the nine months ended September 30, 2023, nuclear plant decommissioning accretion reflected as a change in regulatory liability in the condensed consolidated balance sheets.

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Nuclear Decommissioning AROs

AROs for nuclear generation decommissioning relate to the Comanche Peak plant in ERCOT and the facilities acquired from Energy Harbor which include the Beaver Valley, Perry and Davis-Besse plants in PJM (the PJM nuclear facilities). To estimate our nuclear decommissioning obligations we use a discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning methods and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates.

As of September 30, 2024, the carrying value of our ARO related to our Comanche Peak plant decommissioning estimate totaled $1.783 billion, which is lower than the fair value of the assets contained in the Comanche Peak NDT of $2.253 billion. The difference between the carrying value of the ARO and the NDT represents a regulatory liability of $470 million that has been recorded to the condensed consolidated balance sheets in other noncurrent liabilities and deferred credits since any excess funds in the NDT after decommissioning our Comanche Peak plant would be refunded to Oncor.

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

14.    COMMITMENTS AND CONTINGENCIES

Guarantees

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

Letters of Credit

As of September 30, 2024, we had outstanding letters of credit totaling $2.380 billion as follows:

•$2.013 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;

•$227 million to support battery and solar development projects;

•$25 million to support executory contracts and insurance agreements;

•$95 million to support our REP financial requirements with the PUCT; and

•$20 million for other credit support requirements.

Surety Bonds

As of September 30, 2024, we had outstanding surety bonds totaling $1.464 billion to support performance under various contracts and legal obligations in the normal course of business.

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Litigation and Regulatory Proceedings

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

Litigation

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

Illinois Attorney General Complaint Against Illinois Gas & Electric (IG&E) — In May 2022, the Illinois Attorney General filed a complaint against IG&E, a subsidiary we acquired when we purchased Crius Energy Trust in July 2019. The complaint filed in Illinois state court alleges, among other things, that IG&E engaged in improper marketing conduct and overcharged customers. The vast majority of the conduct in question occurred prior to our acquisition of IG&E. In July 2022, we moved to dismiss the complaint, and in October 2022, the district court granted in part our motion to dismiss, barring all claims asserted by the Illinois Attorney General that were outside of the 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.

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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 June 2024, the Texas Supreme Court issued a decision reversing the Third Court of Appeals and finding that the pricing orders were lawful.

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.

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Greenhouse Gas Emissions (GHG)

In May 2023, the EPA released a proposal regulating power plant GHG emissions, while also proposing to repeal the Affordable Clean Energy (ACE) rule that had been finalized by the EPA in July 2019. In May 2024, the EPA published a final GHG rule that repealed the ACE rule and sets limits for (a) new natural gas-fired combustion turbines and (b) existing coal-, oil- and natural gas-fired steam generation units. The standards are based on technologies such as carbon capture and sequestration/storage (CCS) and natural gas co-firing. 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. Following finalization of the rule in May 2024, 17 petitions for review from various states, industry groups and companies were filed in the D.C. Circuit Court along with multiple motions to stay the rule. We are participating in an industry coalition challenging the rule. In July 2024, the D.C. Circuit Court denied the motions to stay and a number of parties subsequently filed an emergency request with the U.S. Supreme Court to stay the rule which was denied in October 2024. Oral argument on the merits of the legal challenges to the rule will be held in December 2024 before the D.C. Circuit Court.

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

In October 2015, the EPA revised the primary and secondary ozone National Ambient Air Quality Standards (NAAQS) to lower the 8-hour standard for ozone emissions during ozone season (May to September). As required under the CAA, in October 2018, the State of Texas submitted a State Implementation Plan (SIP) to the EPA demonstrating that emissions from Texas sources do not contribute significantly to nonattainment in, or interfere with maintenance by, any other state with respect to the revised ozone NAAQS. In February 2023, the EPA disapproved Texas' SIP and the State of Texas, Luminant, certain trade groups, and others challenged that disapproval in the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court). In March 2023, those same parties filed motions to stay the EPA's SIP disapproval in the Fifth Circuit Court, and the EPA moved to transfer our challenges to the D.C. Circuit Court or have those challenges dismissed.

In April 2022, prior to the EPA's disapproval of Texas' SIP, the EPA proposed a Federal Implementation Plan (FIP) to address the 2015 ozone NAAQS. We, along with many other companies, trade groups, states and ISOs, including ERCOT, PJM and MISO, filed responsive comments to the EPA's proposal in June 2022, expressing concerns about certain elements of the proposal, particularly those that may result in challenges to electric reliability under certain conditions. In March 2023, the EPA administrator signed its final FIP, called the Good Neighbor Plan (GNP). The FIP applied to 22 states beginning with the 2023 ozone seasons. States where Vistra operates generation units that would be subject to this rule are Illinois, New Jersey, New York, Ohio, Pennsylvania, Texas, Virginia and West Virginia. Texas would be moved into the revised (and more restrictive) Group 3 trading program previously established in the Revised CSAPR Update Rule that includes emission budgets for 2023 that the EPA says are achievable through existing controls installed at power plants. Allowances will be limited under the program and will be further reduced beginning in ozone season 2026 to a level that is intended to reduce operating time of coal-fueled power plants during ozone season or force coal plants to retire, particularly those that do not have selective catalytic reduction systems such as our Martin Lake power plant.

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In May 2023, the Fifth Circuit Court granted our motion to stay the EPA's disapproval of Texas' SIP pending a decision on the merits and denied the EPA's motion to transfer our challenge to the D.C. Circuit Court. As a result of the stay, we do not believe the EPA has authority to implement the GNP FIP as to Texas sources pending the resolution of the merits, meaning that Texas will remain in Group 2 and not be subject to any requirements under the GNP FIP at least until the Fifth Circuit Court rules on the merits. Oral argument was heard in December 2023 before the Fifth Circuit Court. In June 2023, the EPA published the final FIP in the Federal Register, which included requirements as to Texas despite the stay of the SIP disapproval by the Fifth Circuit Court. In June 2023, the State of Texas, Luminant and various other parties also filed challenges to the GNP FIP in the Fifth Circuit Court, filed a motion to stay the FIP and confirm venue for this dispute in the Fifth Circuit Court. After the motion to stay and to confirm venue was filed, the EPA signed an interim final rule on June 29, 2023 that confirms the GNP FIP as to Texas is stayed. In July 2023, the Fifth Circuit Court ruled that the GNP FIP challenge would be held in abeyance pending the resolution of the litigation on the SIP disapproval and denied the motion to stay as not needed given the EPA's administrative stay. In a related action brought by other states and parties challenging the GNP FIP, in June 2024, the U.S. Supreme Court granted a stay of the GNP FIP pending a review of the merits by the D.C. Circuit Court and any further appeal to the U.S. Supreme Court. As a result, the GNP FIP is now stayed for all covered states until the courts resolve the legality of the FIP.

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. Based on 2020-2022 design value associated with the rule, we have just five plants (Oakland (California), Calumet (Illinois), Liberty (Pennsylvania), Miami Fort (Ohio) and Lake Hubbard (Texas)) operating in areas where the air quality monitoring data are currently exceeding the new PM2.5 standard. We have previously announced that our Miami Fort generation facility will close by the end of 2027. States will have to develop a plan (by late 2027 at the earliest) to get those areas into attainment and there would be a possibility that additional controls would be required for those sites. However, before the state begins this planning process, the designation process will occur within two years from the issuance of the final rule. The states develop recommendations about the boundaries of the nonattainment counties and the EPA must finalize the designations including the boundaries of each nonattainment area.

Effluent Limitation Guidelines (ELGs)

In November 2015, the EPA revised the ELGs for steam electricity generation facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, such as flue gas desulfurization (FGD), fly ash, bottom ash and flue gas mercury control wastewaters. Various parties filed petitions for review of the ELG rule, and the petitions were consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions requesting reconsideration of the ELG rule and administratively stayed the rule's compliance date deadlines. In April 2019, the Fifth Circuit Court vacated and remanded portions of the EPA's ELG rule pertaining to effluent limitations for legacy wastewater and leachate. The EPA published a final rule in October 2020 that extends the compliance date for both FGD and bottom ash transport water to no later than December 2025, as negotiated with the state permitting agency. Additionally, the final rule allows for a retirement exemption that exempts facilities certifying that units will retire by December 2028 provided certain effluent limitations are met. In November 2020, environmental groups petitioned for review of the new ELG revisions, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020. Notifications were made to Texas, Illinois and Ohio state agencies on the retirement exemption for applicable coal plants by the regulatory deadline of October 13, 2021. In May 2024, the EPA published 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 facilities that permanently cease coal combustion by 2028. We are reviewing the rule for impact but believe it will require additional treatment costs for legacy wastewaters during pond closure activities and combustion residual leachate. At this time, we don't expect the impact of these additional treatment costs to be material. A number of parties have since challenged the rule and that case is pending in the U.S. Court of Appeals for the Eighth Circuit. We are not a party to that litigation.

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Coal Combustion Residuals (CCR) Rule Revisions and Extension Applications

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

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

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. 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 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 intervened in support of the petitions filed by the Vistra subsidiaries and USWAG, and various environmental groups have intervened on behalf of the EPA. In June 2024, the D.C. Circuit Court dismissed the petitions filed challenging the EPA's January 2022 statements because it found the statements did not amend the existing CCR regulations, and thus the D.C. Circuit Court did not have jurisdiction to review them.

Legacy CCR Rulemaking

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

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.

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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 Illinois Coal Ash regulation (discussed below) and close the site by removal. In addition, the interim consent order requires that during the impoundment closure process, impacted groundwater will be collected before it leaves the site or enters the nearby Vermilion river and, if necessary, DMG will be required to install temporary riverbank protection if the river migrates within a certain distance of the impoundments. The interim order was modified in December 2022 to require certain amendments to the Safety Emergency Response Plan. In June 2023, the Illinois state court approved and entered the final consent order, which included the terms above and a requirement that when IEPA issues a final closure permit for the site, DMG will demolish the power station and submit for approval to construct an on-site landfill within the footprint of the former plant to store and manage the coal ash. These proposed closure costs are reflected in the ARO in the condensed consolidated balance sheets (see Note 17).

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.

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.

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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. In June 2024, the FERC issued an order for an evidentiary hearing (or a trial before a FERC administrative law judge) to determine what the FERC cited as "disputed issues of material fact" that it believes cannot be resolved on the existing record and, in October 2024, issued an order dismissing our request for rehearing of the June 2024 order. We will continue to vigorously defend our position.

Other Matters

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

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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 September 30, 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 each (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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15.    EQUITY

Share Repurchase Program

In October 2021, we announced that the Board authorized a share repurchase program (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.

The initial authorization (effective on October 11, 2021) of the Share Repurchase Program allowed for the repurchase of up to $2.0 billion of our outstanding shares of common stock. 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. As of September 30, 2024 $5.75 billion of our common stock has been authorized for repurchase under our Share Repurchase Program of which approximately $1.236 billion was available for additional repurchases under the Share Repurchase Program. In October 2024, the Board authorized an incremental amount of $1.0 billion.

In the three months ended September 30, 2024, 4,849,061 shares of our common stock were repurchased for approximately $402 million at an average price of $82.90 per share of common stock. In the nine months ended September 30, 2024, 14,934,631 shares of our common stock were repurchased for approximately $1.014 billion at an average price of $67.92 per share of common stock. Shares repurchased include 52,833 of unsettled shares for $6 million as of September 30, 2024.

In the three months ended September 30, 2023, 10,550,307 shares of our common stock were repurchased for approximately $320 million at an average price of $30.36 per share of common stock. In the nine months ended September 30, 2023, 34,003,663 shares of our common stock were repurchased for approximately $875 million at an average price of $25.74 per share of common stock.

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.

Series A Preferred Stock

The Series A Preferred Stock may be redeemed at the option of the Company at any time after October 15, 2026 (Series A First Reset Date) and in certain other circumstances prior to the Series A First Reset Date.

The annual dividend rate on each share of Series A Preferred Stock is 8.0% of the liquidation preference from the issuance date (October 15, 2021) to, but excluding, the 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.

Series B Preferred Stock

The Series B Preferred Stock may be redeemed at the option of the Company at any time after December 15, 2026 (Series B First Reset Date) and in certain other circumstances prior to the Series B First Reset Date.

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The annual dividend rate on each share of Series B Preferred Stock is 7.0% of liquidation preference from the issuance date (December 10, 2021) to, but excluding, the 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.

Series C Preferred Stock

The Series C Preferred Stock may be redeemed at the option of the Company at any time after January 15, 2029 (Series C First Reset Date) and in certain other circumstances prior to the Series C First Reset Date.

The annual dividend rate on each share of Series C Preferred Stock is 8.875% of liquidation preference from the issuance date (December 29, 2023) to, but excluding, the 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.

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.

Nine Months Ended September 30, 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 2024	June 2024	$	0.2175	May 2023	June 2023	$	0.2040
July 2024	September 2024	$	0.2195	August 2023	September 2023	$	0.2060
				November 2023	December 2023	$	0.2130

In October 2024, the Board declared a quarterly dividend of $0.2215 per share of common stock that will be paid in December 2024.

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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.

Nine Months Ended September 30, 2024				Year Ended December 31, 2023
Board Declaration Date	Payment Date	Per Share Amount		Board Declaration Date	Payment Date	Per Share Amount
Series A Preferred Stock:				Series A Preferred Stock:
February 2024	April 2024	$	40.00	February 2023	April 2023	$	40.00
				August 2023	October 2023	$	40.00
Series B Preferred Stock:				Series B Preferred Stock:
May 2024	June 2024	$	35.00	May 2023	June 2023	$	35.00
				November 2023	December 2023	$	35.00
Series C Preferred Stock:
May 2024	July 2024	$	48.32

In July 2024, the Board declared a semi-annual dividend of $40.00 per share on Series A Preferred Stock that was paid in October 2024. In October 2024, the Board declared (i) a semi-annual dividend of $35.00 per share on Series B Preferred Stock that will be paid in December 2024 and (ii) a semi-annual dividend of $44.375 per share on the Series C Preferred Stock that will be paid in January 2025.

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 September 30, 2024, Vistra Operations can distribute approximately $6.8 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 $515 million and $280 million for the three months ended September 30, 2024 and 2023, respectively, and $1.505 billion and $1.055 billion for the nine months ended September 30, 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 September 30, 2024, all 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.

16.    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.

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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 16 states and the District of Columbia.

The Texas and East segments are engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel production and fuel logistics management. The Texas segment represents results from Vistra's electricity generation operations in the ERCOT market, other than assets that are now part of the Sunset or Asset Closure segments. The East segment represents results from Vistra's electricity generation operations in the Eastern Interconnection of the U.S. electric grid, other than assets that are now part of the Sunset or Asset Closure segments, and includes operations in the PJM, ISO-NE and NYISO markets. We determined it was appropriate to aggregate results from these markets into one reportable segment, East, given similar economic characteristics. The West segment represents results from the CAISO market, including our battery ESS projects at our Moss Landing power plant site.

The Sunset segment consists of generation plants with announced retirement dates after December 31, 2024. Separately reporting the Sunset segment differentiates operating plants with announced retirement plans from our other operating plants in the Texas, East and West segments. We have allocated unrealized gains and losses on the commodity risk management activities to the Sunset segment for the generation plants that have announced retirement dates after December 31, 2024.

The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines (see Note 3). Upon movement of generation plant assets to either the Sunset or Asset Closure segments, prior year results are retrospectively adjusted, if the effects are material, for comparative purposes. Separately reporting the Asset Closure segment provides management with better information related to the performance and earnings power of Vistra's ongoing operations and facilitates management's focus on minimizing the cost associated with decommissioning and reclamation of retired plants and mines.

Corporate and Other represents the remaining non-segment operations consisting primarily of general corporate expenses, interest, taxes and other expenses related to our support functions that provide shared services to our operating segments.

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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	Retail		Texas		East		West		Sunset		Asset Closure		Corporate and Other (a)		Eliminations		Consolidated
	(in millions)
Operating revenues:
September 30, 2024	$	4,251	$	4,104	$	1,524	$	242	$	469	$	1	$	—	$	(4,303)	$	6,288
September 30, 2023	3,383		1,517		651		344		224		—		1		(2,034)		4,086
Depreciation and amortization:
September 30, 2024	$	(31)	$	(153)	$	(223)	$	(22)	$	(20)	$	—	$	(17)	$	—	$	(466)
September 30, 2023	(26)		(132)		(161)		(22)		(16)		—		(18)		—		(375)
Operating income (loss):
September 30, 2024	$	(1,210)	$	3,215	$	362	$	151	$	168	$	(24)	$	(74)	$	—	$	2,588
September 30, 2023	247		429		29		256		(42)		(23)		(62)		—		834
Net income (loss):
September 30, 2024	$	(1,226)	$	3,249	$	468	$	153	$	163	$	(18)	$	(952)	$	—	$	1,837
September 30, 2023	245		438		29		264		(44)		(17)		(413)		—		502
Nine Months Ended	Retail		Texas		East		West		Sunset		Asset Closure		Corporate and Other (a)		Eliminations		Consolidated
	(in millions)
Operating revenues:
September 30, 2024	$	9,913	$	4,716	$	3,354	$	729	$	1,095	$	1	$	1	$	(6,622)	$	13,187
September 30, 2023	8,161		3,061		3,305		799		1,366		—		1		(4,992)		11,701
Depreciation and amortization:
September 30, 2024	$	(85)	$	(418)	$	(631)	$	(64)	$	(58)	$	—	$	(50)	$	—	$	(1,306)
September 30, 2023	(78)		(390)		(488)		(56)		(45)		—		(52)		—		(1,109)
Operating income (loss):
September 30, 2024	$	271	$	2,265	$	507	$	427	$	301	$	(73)	$	(216)	$	—	$	3,482
September 30, 2023	481		350		1,048		456		447		(78)		(145)		—		2,559
Net income (loss):
September 30, 2024	$	232	$	2,327	$	693	$	430	$	296	$	(64)	$	(1,592)	$	—	$	2,322
September 30, 2023	462		396		1,049		481		442		23		(1,177)		—		1,676
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures:
September 30, 2024	$	3	$	583	$	203	$	15	$	21	$	—	$	39	$	—	$	864
September 30, 2023	1		366		77		10		61		—		44		—		559

_____________

(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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17.    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 September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(in millions)
Interest expense	$	244	$	161	$	702	$	474
Unrealized mark-to-market net (gains) losses on interest rate swaps	84		(43)		26		(65)
Amortization of debt issuance costs, discounts and premiums	9		7		25		19
Facility Fee expense	3		—		11		—
Debt extinguishment gain	—		—		(6)		—
Capitalized interest	(20)		(7)		(52)		(28)
Other	12		25		37		50
Total interest expense and related charges	$	332	$	143	$	743	$	450

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 10, was 5.52% and 5.57% as of September 30, 2024 and 2023, respectively.

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Other Income and Deductions

	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(in millions)
Other income:
NDT net income (a)	$	95	$	—	$	170	$	—
Insurance settlements (b)	21		12		22		21
Gain on sale of land (c)	5		1		6		95
Gain on TRA repurchases (d)	—		—		10		—
Interest income	9		16		50		42
All other	9		3		34		16
Total other income	$	139	$	32	$	292	$	174
Other deductions:
All other	3		3		$	10	$	9
Total other deductions	$	3	$	3	$	10	$	9

____________

(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)For three and nine months ended September 30, 2024, $20 million reported in the Texas segment, and $1 million and $2 million reported in the West segment, respectively. For the three and nine months ended September 30, 2023, $8 million and $17 million, respectively, reported in the West segment and $4 million and $4 million, respectively, reported in the Asset Closure segment.

(c)For the three and nine months ended September 30, 2024 and the three months ended September 30, 2023, amounts reported in the Asset Closure segment. For the nine months ended September 30, 2023, $94 million reported in the Asset Closure segment and $1 million reported in the Texas segment.

(d)Reported in Corporate and Other.

Restricted Cash

	September 30, 2024				December 31, 2023
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
	(in millions)
Amounts related to remediation escrow accounts	$	29	$	6	$	40	$	14
Total restricted cash	$	29	$	6	$	40	$	14

Inventories by Major Category

	September 30, 2024		December 31, 2023
	(in millions)
Materials and supplies	$	534	$	289
Fuel stock	383		420
Natural gas in storage	32		31
Total inventories	$	949	$	740

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Investments

	September 30, 2024		December 31, 2023
	(in millions)
Nuclear decommissioning trusts (Note 13)	$	4,444	$	1,951
Assets related to employee benefit plans	18		28
Land investments	42		42
Other investments	16		14
Total investments	$	4,520	$	2,035

Property, Plant and Equipment

	September 30, 2024		December 31, 2023
	(in millions)
Power generation and structures	$	22,527	$	17,297
Land	603		572
Office and other equipment	163		159
Total	23,293		18,028
Less accumulated depreciation	(7,583)		(6,657)
Net of accumulated depreciation	15,710		11,371
Finance lease right-of-use assets (net of accumulated depreciation)	155		160
Nuclear fuel (net of accumulated amortization of $389 million and $120 million)	1,398		379
Construction work in progress	1,125		522
Property, plant and equipment — net	$	18,388	$	12,432

Depreciation expenses totaled $421 million and $335 million for the three months ended September 30, 2024 and 2023, respectively, and $1.179 billion and $989 million for nine months ended September 30, 2024 and 2023, respectively.

Other Noncurrent Liabilities and Deferred Credits

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

	September 30, 2024		December 31, 2023
	(in millions)
Retirement and other employee benefits	$	239	$	247
Winter Storm Uri impact (a)	1		26
Identifiable intangible liabilities (Note 7)	163		131
Regulatory liability (b)	470		209
Finance lease liabilities	220		227
Liability for third-party remediation	8		17
Accrued severance costs	35		36
Other accrued expenses	55		58
Total other noncurrent liabilities and deferred credits	$	1,191	$	951

____________

(a)Includes future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri.

(b)As of September 30, 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 $470 million and $209 million, respectively, in other noncurrent liabilities and deferred credits.

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Fair Value of Debt

		September 30, 2024				December 31, 2023
Long-term debt (see Note 9):	Fair Value Hierarchy	Carrying Amount		Fair Value		Carrying Amount		Fair Value
		(in millions)
Long-term debt under the Vistra Operations Credit Facilities	Level 2	$	2,441	$	2,478	$	2,456	$	2,500
Vistra Zero Term Loan B Facility	Level 2	685		696		—		—
Vistra Operations Senior Notes	Level 2	11,124		11,429		11,881		11,752
Energy Harbor Revenue Bonds	Level 2	414		446		—		—
Equipment Financing Agreements	Level 3	66		66		65		62

We determine fair value in accordance with accounting standards as discussed in Note 11. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services, such as Bloomberg.

Supplemental Cash Flow Information

The following table reconciles cash, cash equivalents and restricted cash reported in the condensed consolidated statements of cash flows to the amounts reported in the condensed consolidated balance sheets as of September 30, 2024 and December 31, 2023:

	September 30, 2024		December 31, 2023
	(in millions)
Cash and cash equivalents	$	905	$	3,485
Restricted cash included in current assets	29		40
Restricted cash included in noncurrent assets	6		14
Total cash, cash equivalents and restricted cash	$	940	$	3,539

The following table summarizes our supplemental cash flow information for the nine months ended September 30, 2024 and 2023. See Note 2 for other non-cash investing and financing activity related to the Energy Harbor Merger.

	Nine Months Ended September 30,
	2024		2023
	(in millions)
Cash payments related to:
Interest paid	$	709	$	527
Capitalized interest	(52)		(28)
Interest paid (net of capitalized interest)	$	657	$	499

For the nine months ended September 30, 2024 and 2023, we paid federal income tax of $2 million and zero, respectively, paid state income taxes of $52 million and $31 million respectively, and received state tax refunds of $8 million and $12 million, respectively.

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

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

Significant Activities and Events and Items Influencing Future Performance

Acquisition of Noncontrolling Interest

On September 18, 2024 (the UPA Transaction Date), Vistra Operations and Vistra Vision Holdings I LLC, an indirect wholly owned subsidiary of Vistra Operations (Vistra Vision Holdings), entered into separate Unit Purchase Agreements (the UPAs) with each of Nuveen and Avenue, pursuant to which Vistra Vision Holdings has agreed to purchase each of Nuveen's and Avenue's combined 15% noncontrolling interest in Vistra Vision for $3.248 billion in cash subject to adjustment based on Vistra Vision cash distributions paid prior to closing (collectively, the Transaction). The Transaction is expected to close on December 31, 2024 (the Closing Date), subject to the satisfaction of certain closing conditions, at which time Vistra Vision Holdings will own 100% of the equity interests in Vistra Vision. See Note 2 to the Financial Statements for more information concerning the redeemable noncontrolling interest.

Comanche Peak Nuclear Plant License Renewal

In July 2024, our application for license renewal at our two-unit Comanche Peak Nuclear Plant was approved by the NRC. The licenses for Units 1 and 2 now extend into 2050 and 2053, respectively, an additional 20 years beyond our original licenses.

Planned Gas-Fueled Dispatchable Power in ERCOT

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

•Building up to 860 MW of advanced simple-cycle peaking plants to be located in west Texas to support the increasing power needs of the region, including the state's oil and gas industry.

•Repowering the coal-fueled Coleto Creek Power Plant near Goliad, Texas, set to retire in 2027 to comply with EPA rules, as a natural-gas fueled plant with up to 600 MW of capacity.

•Completing upgrades at existing natural gas-fueled plants that will add more than 500 MW of summer capacity and 100 MW of winter capacity.

The announcement is based on market reforms that policymakers passed in the 2023 Texas legislative session and that ERCOT and the PUCT are currently implementing. These market reforms are focused on grid reliability and proper market signals, and if successfully implemented have the potential to offer the regulatory framework needed to provide Vistra the confidence to make the long-term investments in these capacity projects. In addition, in July 2024, we filed applications with the PUCT under the Texas Energy Fund loan program seeking financing for the 860 MW of new advanced simple-cycle peaking plants referenced above. In August 2024, the PUCT notified Vistra that an application for one of its west Texas advanced simple-cycle peaking plants was selected for due diligence as part of the Texas Energy Fund loan program. An invitation to due diligence does not mean an applicant is awarded a loan. Vistra's decision to move forward with the new west Texas gas plant project is contingent upon supportive market reforms, approval of our Texas Energy Fund loan application, and other factors, including state and federal environmental regulations and long-term wholesale trends that continue to support gas generation.

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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. The IRA also implements a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases. The section 45U nuclear PTC is available to existing nuclear facilities from 2024 through 2032 and provides a federal tax credit of up to $15/MWh, subject to phase out as power prices increase above $25/MWh (each subject to annual inflation adjustments). Treasury regulations are expected to further define the scope of the legislation in many important respects in the coming 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 International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance. As discussed in Note 1, we have not recognized any revenues or receivables related to the IRC Section 45U credits through September 30, 2024, as we await U.S. Treasury and Internal Revenue service guidance on how to interpret gross receipts in the calculation of the nuclear PTC. This guidance could have a significant impact on our estimates. Assuming an interpretation of gross receipts which excludes hedges from the calculation, our total PTC revenues for 2024 could be approximately $500 million. The amount of nuclear PTCs we record could be material to our 2024 results. 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."

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.

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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 September 30, 2024, we have repurchased an aggregate 98% of the initial issuance of TRA Rights upon Emergence, of which 8,033,789 TRA Rights remain outstanding. See Note 12 to the Financial Statements for details of the TRA and Note 15 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 (such as an on-shore manufacturing) and new demand sources (such as 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 are in various discussions with interested counterparties for the potential sale of power from our nuclear and gas facilities pursuant to long-term agreements to supply large load facilities. Such potential transactions are subject to certain risks and uncertainties, including potential regulatory review and/or approval and adverse legislative action, which could impact the timing of, and our ability to consummate, a potential transaction.

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 future non-recourse financing for our development projects and future refinancing expected in connection with debt due in 2025 and beyond.

We continue to closely monitor 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. The Prohibiting Russian Uranium Imports Act (PRUI Act) was approved by Congress and signed into law by President Biden and took effect on August 11, 2024. The PRUI Act prohibits importation of Russian uranium; however, the Department of Energy can issue waivers (subject to decreasing annual caps) until December 31, 2027 if there is no alternate source of low-enriched uranium available to keep U.S. nuclear reactors operating or is in the national interest. Additionally, passage of the PRUI Act enabled the allocation of $2.72 billion in federal funding to ramp up production of domestic uranium fuel. 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 impacting our refuel schedules. 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 through 2029. We continue to take affirmative action by building strategic inventory and deploying mitigating strategies in our procurement portfolio to ensure we can secure the nuclear fuel needed to continue to operate our nuclear facilities through potential Russian supply disruption.

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Capacity Markets — PJM Auction Results

In July 2024, Vistra reported its results from PJM's Reliability Pricing Model (RPM) auction results for planning year 2025-2026, and the table below lists clearing price per MW-day and our cleared capacity volumes by zone:

	Clearing Price per MW-day		East Segment MW Cleared	Sunset Segment MW Cleared	Total MW Cleared
RTO zone	$	269.92	3,774	—	3,774
ComEd zone	$	269.92	1,189	967	2,156
DEOK zone	$	269.92	111	835	946
EMAAC zone	$	269.92	656	—	656
MAAC zone	$	269.92	471	—	471
ATSI zone	$	269.92	2,044	—	2,044
DOM zone	$	444.26	208	—	208
Total			8,453	1,802	10,255

Critical Accounting Policies and Estimates

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

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RESULTS OF OPERATIONS

Net income increased $1.335 billion to Net income of $1.837 billion in the three months ended September 30, 2024 compared to the three months ended September 30, 2023. Net income increased $0.646 billion to Net income of $2.322 billion for the nine months ended September 30, 2024 compared to the nine months ended September 30, 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 the condensed consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

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

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Vistra Consolidated Financial Results — Three Months Ended September 30, 2024 Compared to the Three Months Ended September 30, 2023

The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the three months ended September 30, 2024:

	Three Months Ended September 30, 2024
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
	(in millions)
Operating revenues	$	4,251	$	4,104	$	1,524	$	242	$	469	$	1	$	(4,303)	$	6,288
Fuel, purchased power costs and delivery fees	(5,117)		(461)		(685)		(46)		(200)		(1)		4,303		(2,207)
Operating costs	(47)		(237)		(234)		(16)		(67)		(14)		(1)		(616)
Depreciation and amortization	(31)		(153)		(223)		(22)		(20)		—		(17)		(466)
Selling, general and administrative expenses	(266)		(38)		(20)		(7)		(14)		(10)		(56)		(411)
Operating income (loss)	(1,210)		3,215		362		151		168		(24)		(74)		2,588
Other income	—		24		98		1		—		8		8		139
Other deductions	—		(1)		—		—		(1)		(1)		—		(3)
Interest expense and related charges	(16)		11		8		1		(4)		(1)		(331)		(332)
Income (loss) before income taxes	(1,226)		3,249		468		153		163		(18)		(397)		2,392
Income tax expense	—		—		—		—		—		—		(555)		(555)
Net income (loss)	$	(1,226)	$	3,249	$	468	$	153	$	163	$	(18)	$	(952)	$	1,837
Income tax expense	—		—		—		—		—		—		555		555
Interest expense and related charges (a)	16		(11)		(8)		(1)		4		1		331		332
Depreciation and amortization (b)	31		181		318		22		20		—		17		589
EBITDA before Adjustments	(1,179)		3,419		778		174		187		(17)		(49)		3,313
Unrealized net (gain) loss resulting from hedging transactions	1,275		(2,705)		(239)		(101)		(83)		(2)		—		(1,855)
Fresh start/purchase accounting impacts	1		1		(4)		—		—		—		—		(2)
Non-cash compensation expenses	—		—		—		—		—		—		23		23
Transition and merger expenses	—		1		1		—		—		—		23		25
Decommissioning-related activities (c)	—		7		(73)		—		2		—		—		(64)
ERP system implementation expenses	1		1		—		—		—		1		—		3
Other, net	4		(2)		1		3		(1)		1		(22)		(16)
Adjusted EBITDA	$	102	$	722	$	464	$	76	$	105	$	(17)	$	(25)	$	1,427

____________

(a)Includes $84 million of unrealized mark-to-market net losses on interest rate swaps.

(b)Includes nuclear fuel amortization of $28 million and $95 million, respectively, in Texas and East segments.

(c)Represents net of all NDT income (loss) of the PJM nuclear facilities, ARO accretion expense for operating assets and ARO remeasurement impacts for operating assets.

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The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the three months ended September 30, 2023:

	Three Months Ended September 30, 2023
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
	(in millions)
Operating revenues	$	3,383	$	1,517	$	651	$	344	$	224	$	—	$	(2,033)	$	4,086
Fuel, purchased power costs and delivery fees	(2,837)		(707)		(376)		(46)		(176)		(1)		2,034		(2,109)
Operating costs	(36)		(217)		(65)		(14)		(63)		(15)		(1)		(411)
Depreciation and amortization	(26)		(132)		(161)		(22)		(16)		—		(18)		(375)
Selling, general and administrative expenses	(237)		(32)		(20)		(6)		(11)		(7)		(44)		(357)
Operating income (loss)	247		429		29		256		(42)		(23)		(62)		834
Other income	—		4		—		8		—		7		13		32
Other deductions	—		—		—		—		(2)		—		(1)		(3)
Interest expense and related charges	(2)		5		—		—		—		(1)		(145)		(143)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(49)		(49)
Income (loss) before income taxes	245		438		29		264		(44)		(17)		(244)		671
Income tax expense	—		—		—		—		—		—		(169)		$	(169)
Net income (loss)	$	245	$	438	$	29	$	264	$	(44)	$	(17)	$	(413)	$	502
Income tax expense	—		—		—		—		—		—		169		169
Interest expense and related charges (a)	2		(5)		—		—		—		1		145		143
Depreciation and amortization (b)	26		158		161		22		16		—		18		401
EBITDA before Adjustments	273		591		190		286		(28)		(16)		(81)		1,215
Unrealized net (gain) loss resulting from hedging transactions	(97)		356		125		(203)		110		(8)		—		283
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		49		49
Non-cash compensation expenses	—		—		—		—		—		—		21		21
Transition and merger expenses	—		—		—		—		—		—		22		22
PJM capacity performance default (c)	—		—		(3)		—		4		—		—		1
Winter Storm Uri impacts (d)	(8)		1		—		—		—		—		—		(7)
Other, net	5		2		3		4		16		—		(25)		5
Adjusted EBITDA	$	173	$	950	$	315	$	87	$	102	$	(24)	$	(14)	$	1,589

____________

(a)Includes $43 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $26 million in the Texas segment.

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

(d)Includes the application of bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri.

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GAAP operating income increased $1.754 billion to operating income of $2.588 billion in the three months ended September 30, 2024 compared to the three months ended September 30, 2023. The primary favorable drivers for the increase are (i) a $2.138 billion change in unrealized mark-to-market activity as results for the three months ended September 30, 2024 were favorably impacted by $1.855 billion in pre-tax unrealized mark-to-market gains on derivative positions due to power and natural gas forward market curves moving down in the the three months ended September 30, 2023 compared to $283 million in pre-tax unrealized mark-to-market losses on derivative positions due to power forward market curves moving up in Texas in the three months ended September 30, 2023 and (ii) addition of the Energy Harbor assets in East. See further information on our derivative results in Energy-Related Commodity Contracts and Mark-to-Market Activities below. These favorable variances are partially offset by lower realized generation margins in Texas due to fewer scarcity pricing events compared to 2023 and a decrease in retail operating income which is driven by a shift in the seasonality of margins on retail contracts as summer supply costs increased compared to 2023, partially offset by the addition of Energy Harbor retail.

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

	Three Months Ended September 30,
	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	22,193		22,643
Sales volumes in Northeast/Midwest	17,864		7,935
Total retail electricity sales volumes	40,057		30,578
Production volumes (GWh):
Natural gas facilities					15,152		15,635		17,135		16,976		996		1,465
Lignite and coal facilities					6,105		6,743										5,908		5,038
Nuclear facilities					5,217		5,210		8,677
Solar facilities					233		247
Capacity factors:
CCGT facilities					78.3	%	77.2	%	70.5	%	69.2	%	44.2	%	65.0	%
Lignite and coal facilities					71.8	%	79.3	%									58.4	%	49.8	%
Nuclear facilities					98.5	%	98.3	%	97.1	%
Weather - percent of normal (a):
Cooling degree days	100%		122	%	102	%	121	%	96	%	97	%	98	%	93	%	99	%	112	%
Heating degree days	—	%	—	%	—	%	—	%	71	%	102	%	—	%	—	%	22	%	—	%

____________

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

66

	Three Months Ended September 30,					Three Months Ended September 30,
	2024		2023			2024		2023
Market pricing					Average Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)	$	26.94	$	109.32	PJM West Hub	$	50.03	$	42.93
					AEP Dayton Hub	$	41.07	$	40.00
Average NYMEX Henry Hub natural gas price ($/MMBtu)	$	2.08	$	2.58	NYISO Zone C	$	39.70	$	35.46
					Massachusetts Hub	$	46.19	$	39.88
Average natural gas price (a):					Indiana Hub	$	40.71	$	42.99
TetcoM3 ($/MMBtu)	$	1.50	$	1.39	Northern Illinois Hub	$	37.82	$	39.36
Algonquin Citygates ($/MMBtu)	$	1.75	$	1.93	CAISO NP15	$	44.92	$	59.65

___________

(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.

The following table presents additional changes to Net income (loss) and Adjusted EBITDA for the three months ended September 30, 2024 compared to the three months ended September 30, 2023.

	Three Months Ended September 30, 2024 Compared to 2023
	Retail (a)		Texas		East (a)		West		Sunset
	(in millions)
Favorable change in realized revenue net of fuel in East driven by addition of Energy Harbor. Unfavorable change in Texas driven by lack of scarcity pricing in 2024 as compared to 2023	$	—	$	(228)	$	295	$	—	$	8
Lower margins driven by increase in power supply costs	(20)		—		—		—		—
Unfavorable change in weather impacts	(29)
Favorable impact of less Winter Storm Uri bill credits applied	6		—		—		—		—
Increase in operating costs due primarily to addition of Energy Harbor in East	—		(13)		(146)		(2)		(3)
Change in SG&A and other	(28)		13		—		(9)		(2)
Change in Adjusted EBITDA	$	(71)	$	(228)	$	149	$	(11)	$	3
Unfavorable change in depreciation and amortization driven primarily by addition of Energy Harbor assets in East	(5)		(23)		(157)		—		(4)
Change in unrealized net gains (losses) on hedging activities (b)	(1,372)		3,061		364		(102)		193
Decommissioning related activities	—		(7)		73		—		(2)
PJM capacity performance default impacts	—		—		(3)		—		4
Other (including interest expenses)	(23)		8		13		2		13
Change in Net income (loss)	$	(1,471)	$	2,811	$	439	$	(111)	$	207

___________

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

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

For the three months ended September 30, 2024, other income totaled $139 million driven by NDT net gains of $95 million, insurance proceeds of $21 million and interest income of $9 million. For the three months ended September 30, 2023, other income totaled $32 million driven by interest income of $16 million and insurance settlements of $12 million.

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Consolidated interest expense and related charges increased $189 million in the three months ended September 30, 2024 compared to the three months ended September 30, 2023 due to (i) unrealized mark-to-market losses on interest rate swaps of $84 million in 2024 compared to unrealized mark-to-market gains on interest rate swaps of $43 million in 2023 due to a decrease in interest rates in the three months ended September 30, 2024 compared to an increase in interest rates in the three months ended September 30, 2023 and (ii) an increase in interest paid/accrued of $83 million driven by higher average borrowings and rates in 2024. See Note 17 to the Financial Statements.

Vistra Consolidated Financial Results — Nine Months Ended September 30, 2024 Compared to the Nine Months Ended September 30, 2023

The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the nine months ended September 30, 2024:

	Nine Months Ended September 30, 2024
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
	(in millions)
Operating revenues	$	9,913	$	4,716	$	3,354	$	729	$	1,095	$	1	$	(6,621)	$	13,187
Fuel, purchased power costs and delivery fees	(8,724)		(1,189)		(1,559)		(167)		(501)		(2)		6,622		(5,520)
Operating costs	(118)		(732)		(596)		(54)		(199)		(41)		(2)		(1,742)
Depreciation and amortization	(85)		(418)		(631)		(64)		(58)		—		(50)		(1,306)
Selling, general and administrative expenses	(715)		(112)		(61)		(17)		(36)		(31)		(165)		(1,137)
Impairment of long-lived assets	—		—		—		—		—		—		—		—
Operating income (loss)	271		2,265		507		427		301		(73)		(216)		3,482
Other income	—		32		179		2		—		14		65		292
Other deductions	(1)		(3)		—		—		(2)		(2)		(2)		(10)
Interest expense and related charges	(38)		33		7		1		(3)		(3)		(740)		(743)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(5)		(5)
Income (loss) before income taxes	232		2,327		693		430		296		(64)		(898)		3,016
Income tax expense	—		—		—		—		—		—		(694)		(694)
Net income (loss)	$	232	$	2,327	$	693	$	430	$	296	$	(64)	$	(1,592)	$	2,322
Income tax expense	—		—		—		—		—		—		694		694
Interest expense and related charges (a)	38		(33)		(7)		(1)		3		3		740		743
Depreciation and amortization (b)	85		498		820		64		58		—		50		1,575
EBITDA before Adjustments	355		2,792		1,506		493		357		(61)		(108)		5,334
Unrealized net (gain) loss resulting from commodity hedging transactions	489		(1,452)		(404)		(308)		(42)		(8)		—		(1,725)
Fresh start/purchase accounting impacts	—		1		(10)		—		2		—		(14)		(21)
Impacts of Tax Receivable Agreement (c)	—		—		—		—		—		—		(5)		(5)
Non-cash compensation expenses	—		—		—		—		—		—		76		76
Transition and merger expenses	2		1		7		—		—		—		75		85
Decommissioning-related activities (d)	—		17		(116)		1		6		—		—		(92)
ERP system implementation expenses	7		6		3		1		2		2		—		21
Other, net	10		4		2		7		(7)		1		(85)		(68)
Adjusted EBITDA	$	863	$	1,369	$	988	$	194	$	318	$	(66)	$	(61)	$	3,605

____________

(a)Includes $26 million of unrealized mark-to-market net losses on interest rate swaps.

(b)Includes nuclear fuel amortization of $80 million and $189 million, respectively, in Texas and East segments.

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(c)Includes $10 million gain recognized on the repurchase of TRA Rights in the nine months ended September 30, 2024 (see Note 12 to the Financial Statements).

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

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The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the nine months ended September 30, 2023:

	Nine Months Ended September 30, 2023
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
	(in millions)
Operating revenues	$	8,161	$	3,061	$	3,305	$	799	$	1,366	$	—	$	(4,991)	$	11,701
Fuel, purchased power costs and delivery fees	(6,879)		(1,546)		(1,494)		(226)		(599)		(2)		4,992		(5,754)
Operating costs	(93)		(680)		(218)		(43)		(190)		(52)		(1)		(1,277)
Depreciation and amortization	(78)		(390)		(488)		(56)		(45)		—		(52)		(1,109)
Selling, general and administrative expenses	(630)		(95)		(57)		(18)		(36)		(24)		(93)		(953)
Impairment of long-lived assets	—		—		—		—		(49)		—		—		(49)
Operating income (loss)	481		350		1,048		456		447		(78)		(145)		2,559
Other income	—		32		2		17		1		105		17		174
Other deductions	—		(1)		—		—		(4)		—		(4)		(9)
Interest expense and related charges	(19)		15		—		8		(2)		(4)		(448)		(450)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(128)		(128)
Income (loss) before income taxes	462		396		1,050		481		442		23		(708)		2,146
Income tax expense	—		—		(1)		—		—		—		(469)		(470)
Net income (loss)	$	462	$	396	$	1,049	$	481	$	442	$	23	$	(1,177)	$	1,676
Income tax expense	—		—		1		—		—		—		469		470
Interest expense and related charges (a)	19		(15)		—		(8)		2		4		448		450
Depreciation and amortization (b)	78		458		488		56		45		—		52		1,177
EBITDA before Adjustments	559		839		1,538		529		489		27		(208)		3,773
Unrealized net (gain) loss resulting from commodity hedging transactions	114		703		(1,024)		(338)		(278)		(32)		—		(855)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		128		128
Non-cash compensation expenses	—		—		—		—		—		—		63		63
Transition and merger expenses	(2)		1		—		—		1		—		39		39
Impairment of long-lived assets	—		—		—		—		49		—		—		49
PJM capacity performance default impacts (c)	—		—		3		—		6		—		—		9
Winter Storm Uri impacts (d)	(46)		2		—		—		—		—		—		(44)
Other, net	17		(5)		9		5		38		(1)		(57)		6
Adjusted EBITDA	$	642	$	1,540	$	526	$	196	$	305	$	(6)	$	(35)	$	3,168

____________

(a)Includes $65 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $68 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.

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GAAP operating income increased $923 million to operating income of $3.482 billion in the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023. The primary driver for the increase is an $870 million change in unrealized mark-to-market activity as results for the nine months ended September 30, 2024 were favorably impacted by $1.725 billion in pre-tax unrealized mark-to-market gains on derivative positions in the nine months ended September 30, 2024 compared to $855 million in pre-tax unrealized mark-to-market gains on commodity derivative positions due to power and natural gas forward market curves moving down more significantly in the nine months ended September 30, 2024 as compared to the nine months ended September 30, 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 nine months ended September 30, 2024, compared to the nine months ended September 30, 2023 were impacted by additional factors including:

Favorable impacts:

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

•Expiration of legacy Vistra default service contracts in the East segment which resulted in higher-than-expected migration of customers at rates below prevailing wholesale market prices in the nine months ended September 30, 2023. Similar contracts acquired from Energy Harbor are reflected in the Retail segment and are a driver of the favorable 2024 Retail results.

Unfavorable impacts:

•Decreases in capacity revenues primarily in the Sunset segment.

•Increase in interest expense driven by higher average borrowings and unrealized mark to market losses on interest rate swaps.

•Increase in depreciation and amortization expense driven by addition of assets acquired from Energy Harbor.

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

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

	Nine Months Ended September 30,
	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	57,234		54,711
Sales volumes in Northeast/Midwest	44,105		19,965
Total retail electricity sales volumes	101,339		74,676
Production volumes (GWh):
Natural gas facilities					34,504		32,809		44,267		45,470		2,921		3,741
Lignite and coal facilities					15,686		17,903										14,122		11,355
Nuclear facilities					15,260		14,471		18,438
Solar facilities					605		638
Capacity factors:
CCGT facilities					60.6	%	57.1	%	60.7	%	62.8	%	43.5	%	55.9	%
Lignite and coal facilities					62.0	%	71.0	%									46.9	%	37.9	%
Nuclear facilities					96.7	%	92.0	%	88.7	%
Weather - percent of normal (a):
Cooling degree days	107	%	115	%	108	%	114	%	105	%	89	%	91	%	78	%	100	%	110	%
Heating degree days	86	%	82	%	89	%	82	%	85	%	85	%	121	%	154	%	84	%	86	%

____________

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

	Nine Months Ended September 30,					Nine Months Ended September 30,
	2024		2023			2024		2023
Market pricing					Average Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)	$	25.75	$	56.26	PJM West Hub	$	41.24	$	38.20
					AEP Dayton Hub	$	36.37	$	36.16
Average NYMEX Henry Hub natural gas price ($/MMBtu)	$	2.19	$	2.46	NYISO Zone C	$	36.62	$	30.12
					Massachusetts Hub	$	42.77	$	41.49
Average natural gas price (a):					Indiana Hub	$	38.16	$	39.49
TetcoM3 ($/MMBtu)	$	1.98	$	1.94	Northern Illinois Hub	$	32.39	$	32.96
Algonquin Citygates ($/MMBtu)	$	2.56	$	3.02	CAISO NP15	$	38.93	$	64.35

___________

(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 nine months ended September 30, 2024, other income totaled $292 million driven by NDT net gains of $170 million, interest income of $50 million, insurance proceeds of $22 million and a gain of $10 million on TRA repurchases. For the nine months ended September 30, 2023, other income totaled $174 million driven by a gain of $89 million from the sale of property in Freestone County, Texas, interest income of $42 million and insurance settlements of $21 million.

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Consolidated interest expense and related charges increased $293 million in the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 primarily due to (i) an increase in interest paid/accrued of $228 million driven by higher average borrowings and rates in 2024 and (ii) unrealized mark-to-market losses on interest rate swaps of $26 million in 2024 compared to unrealized mark-to-market gains on interest rate swaps of $65 million in 2023 due to a decrease in interest rates in the nine months ended September 30, 2024 compared to an increase in interest rates in the nine months ended September 30, 2023. See Note 17 to the Financial Statements.

The following table presents additional changes to Net income (loss) and Adjusted EBITDA for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023.

	Nine Months Ended September 30, 2024 Compared to 2023
	Retail (a)		Texas		East (a)		West		Sunset
	(in millions)
Favorable change in realized revenue net of fuel in East driven by addition of Energy Harbor and rolloff of negative margin default service contracts. Unfavorable change in Texas is driven by a decrease in realized margins due to lack of scarcity pricing events compared to 2023	$	—	$	(132)	$	780	$	19	$	19
Higher retail margins driven by increase in customers, favorable power supply cost, and addition of Energy Harbor retail contracts	260		—		—		—		—
Favorable impact of less Winter Storm Uri bill credits applied	35		—		—		—		—
Increase in plant operating costs due primarily to addition of Energy Harbor in East	—		(34)		(319)		(10)		(6)
Change in SG&A and other primarily due to increase in retail costs related to Energy Harbor	(74)		(5)		1		(11)		—
Change in Adjusted EBITDA	$	221	$	(171)	$	462	$	(2)	$	13
Unfavorable change in depreciation and amortization driven primarily by addition of Energy Harbor assets in East	(7)		(40)		(332)		(8)		(13)
Change in unrealized net gains (losses) on hedging activities (b)	(375)		2,155		(620)		(30)		(236)
Impairment of long-lived assets	—		—		—		—		49
Decommissioning related activities	—		(17)		116		(1)		(6)
PJM capacity performance default impacts	—		—		3		—		6
Winter Storm Uri impact	(46)		2		—		—		—
Other (including interest expenses)	(23)		2		15		(10)		41
Change in Net income (loss)	$	(230)	$	1,931	$	(356)	$	(51)	$	(146)

___________

(a)    Includes amounts associated with operations acquired in the Energy Harbor Merger beginning March 1, 2024.

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

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Asset Closure Segment — Three and Nine Months Ended September 30, 2024 Compared to Three and Nine Months Ended September 30, 2023

	Three Months Ended September 30,				Favorable (Unfavorable) Change		Nine Months Ended September 30,				Favorable (Unfavorable) Change
	2024		2023				2024		2023
	(in millions)
Operating revenues	$	1	$	—	$	1	$	1	$	—	$	1
Fuel, purchased power costs and delivery fees	(1)		(1)		—		$	(2)	$	(2)	$	—
Operating costs	$	(14)	$	(15)	$	1	(41)		(52)		11
Selling, general and administrative expenses	(10)		(7)		(3)		(31)		(24)		(7)
Operating loss	(24)		(23)		(1)		(73)		(78)		5
Other income	8		7		1		14		105		(91)
Other deductions	(1)		—		(1)		(2)		—		(2)
Interest expense and related charges	(1)		(1)		—		(3)		(4)		1
Income (loss) before income taxes	(18)		(17)		(1)		(64)		23		(87)
Net income (loss)	$	(18)	$	(17)	$	(1)	$	(64)	$	23	$	(87)
Adjusted EBITDA	$	(18)	$	(24)	$	6	$	(68)	$	(6)	$	(62)

GAAP and Adjusted EBITDA results for the three and nine months ended September 30, 2024 are unfavorable compared to the three and nine months ended September 30, 2023 primarily due to other income of $89 million from the gain on sale of property in Freestone County, Texas in the second quarter of 2023.

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 three quarters of 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. In the East segment, the margins we were able to lock in with hedges for the three and nine months ended September 30, 2024 are higher than the three and nine months ended September 30, 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 Texas segment, we materially benefited in the third quarter of 2023 as we were able to sell additional power in times of scarcity when real-time prices were high. There have been minimal scarcity events and periods of high pricing in Texas in 2024 and that is the primary driver of the unfavorable change in realized revenue net of fuel. 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. In the first three quarters of 2024, we saw a decrease in forward power prices in all our generation segments compared to our hedged positions which drove material unrealized gains in those segments, partially offset by unrealized losses in our retail segment. In the first three quarters of 2023, the non-Texas generation segments also experienced a decrease in forward power prices compared to our hedged positions which resulted in unrealized gains in those segments partially offset by unrealized losses in our retail segment. In Texas, forward power prices materially increased in the three and nine months ended September 30, 2023 which resulted in unrealized losses in Texas partially offset by unrealized gains in the retail segment.

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The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2024 and 2023. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $1.725 billion and $855 million in unrealized net gains for the nine months ended September 30, 2024 and 2023, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.

	Nine Months Ended September 30,
	2024		2023
	(in millions)
Commodity contract net liability as of January 1	$	(2,740)	$	(3,148)
Settlements/termination of positions (a)	1,350		1,585
Changes in fair value of positions in the portfolio (b)	375		(730)
Acquired commodity contracts (c)	(50)		—
Other activity (d)	111		(108)
Commodity contract net liability as of September 30	$	(954)	$	(2,401)

____________

(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 September 30, 2024, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

	Maturity dates of unrealized commodity contract net liability as of September 30, 2024
Source of Fair Value	Less than 1 year		1-3 years		4-5 years		Excess of 5 years		Total
	(in millions)
Prices actively quoted	$	(187)	$	4	$	29	$		$	(154)
Prices provided by other external sources	$	(369)	$	86	$		$		$	(283)
Prices based on models	$	(195)	$	(363)	$	38	$	3	$	(517)
Total	$	(751)	$	(273)	$	67	$	3	$	(954)

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 September 30, 2024 were as follows:

	Balance of
	2024		2025
Nuclear/Renewable/Coal Generation:
Texas	100	%	100	%
East	100	%	66	%
Sunset	100	%	90	%
Natural Gas Generation:
Texas	100	%	100	%
East	100	%	98	%
West	100	%	99	%

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Financial Condition

Cash Flows

Operating Cash Flows

Cash provided by operating activities totaled $3.210 billion and $4.572 billion in the nine months ended September 30, 2024 and 2023, respectively. The unfavorable change of $1.362 billion was primarily driven by a smaller decrease in net margin deposits (returns of cash related to commodity contracts which support our hedging strategy) as $855 million was returned in the nine months ended September 30, 2024 as compared to $2.271 billion returned in the nine months ended September 30, 2023. This unfavorable variance is partially offset by an increase in cash from realized operating income primarily due to the addition of Energy Harbor.

Depreciation and amortization — Depreciation and amortization expense, as 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 $585 million and $333 million for the nine months ended September 30, 2024 and 2023, respectively. This difference represents amortization of nuclear fuel, which is reported as fuel costs in the condensed consolidated statements of operations consistent with industry practice, as well as the amortization of intangible net assets and liabilities. These are reported under various line items in the other condensed consolidated statements of operations, including operating revenues, fuel and purchased power costs, and delivery fees (see Note 7 to the Financial Statements).

Investing Cash Flows

Cash used in investing activities totaled $4.959 billion and $1.382 billion in the nine months ended September 30, 2024 and 2023, respectively. The increase of $3.577 billion was driven primarily by (a) $3.1 billion used to fund the Energy Harbor Merger and (b) a $386 million increase in capital expenditures driven by higher nuclear fuel purchases.

	Nine Months Ended September 30,				Increase (Decrease)
	2024		2023
	(in millions)
Capital expenditures, including LTSA prepayments	$	(602)	$	(575)	$	(27)
Nuclear fuel purchases	(445)		(174)		(271)
Growth and development expenditures	(601)		(513)		(88)
Total capital expenditures	(1,648)		(1,262)		(386)
Energy Harbor acquisition (net of cash acquired)	(3,065)		—		(3,065)
Net purchases of environmental allowances	(364)		(218)		(146)
Proceeds from sales of property, plant and equipment, including nuclear fuel	137		111		26
Other investing activity	(19)		(13)		(6)
Cash used in investing activities	$	(4,959)	$	(1,382)	$	(3,577)

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Financing Cash Flows

Cash used in financing activities totaled $850 million and $490 million in the nine months ended September 30, 2024 and 2023, respectively. In both periods, the primary driver of the net outflows is share repurchases and dividends partially offset by net new borrowings as detailed below.

	Nine Months Ended September 30,				Increase (Decrease)
	2024		2023
	(in millions)
Share repurchases	$	(1,021)	$	(866)	$	(155)
Issuances of long-term debt	2,200		1,750		450
Other net long-term borrowings (repayments)	(2,269)		(21)		(2,248)
Net short-term borrowings (repayments)	—		(650)		650
Net borrowings (repayments) under the accounts receivable financing facilities	750		(425)		1,175
Dividends paid to common stockholders	(230)		(228)		(2)
Dividends paid to preferred stockholders	(98)		(75)		(23)
Dividends paid to noncontrolling interest in subsidiary	(15)		—		(15)
TRA Repurchase and tender offer — return of capital	(122)		—		(122)
Other financing activity	(45)		25		(70)
Cash used in financing activities	$	(850)	$	(490)	$	(360)

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.

Increases in interest rates have resulted in, and will likely continue to result in, increased borrowing costs.

See Note 9 to the Financial Statements for details of the Receivables Facility, Repurchase Facility, Vistra Operations Credit Facilities, Commodity-Linked Facility and other long-term debt.

Available Liquidity

The following table summarizes changes in available liquidity for the nine months ended September 30, 2024:

	September 30, 2024		December 31, 2023		Change
	(in millions)
Cash and cash equivalents (a)	$	905	$	3,485	$	(2,580)
Vistra Operations Credit Facilities — Revolving Credit Facility (b)	2,457		1,213		1,244
Vistra Operations — Commodity-Linked Facility (c)	633		1,101		(468)
Total available liquidity (d)(e)	$	3,995	$	5,799	$	(1,804)

____________

(a)See the condensed consolidated statements of cash flows in the Financial Statements and Cash Flows above for details of the decrease in cash and cash equivalents for the nine months ended September 30, 2024. The decrease includes $3.1 billion that was used to fund the Energy Harbor Merger.

(b)The increase in availability for the nine months ended September 30, 2024 was driven by a $1.244 billion decrease in letters of credit outstanding under the facility. In October 2024, Vistra Operations amended the Revolving Credit Facility which, among other things, increased the revolving credit commitments to $3.440 billion and extended the maturity date to October 11, 2029.

(c)As of both September 30, 2024 and December 31, 2023, the borrowing bases are less than the facility limit of $1.575 billion. As of September 30, 2024, available capacity reflects the borrowing base of $633 million and no cash borrowings. As of December 31, 2023, available capacity reflects the borrowing base of $1.101 billion and no cash borrowings. In October 2024, Vistra Operations amended the Commodity-Linked Facility which, among other things, increased the aggregate available commitments to $1.75 billion and extended the maturity date to October 1, 2025.

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(d)Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See Note 9 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 or the Alternative LOC Facilities. See Note 9 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, including the upcoming payments associated with the acquisition of the noncontrolling interest in Vistra Vision discussed in Note 2 to the Financial Statements. 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, $4.3 billion in 2025-2026, $1.6 billion in 2027-2028 and $1.2 billion thereafter.

Capital Expenditures

Estimated 2024 capital expenditures and nuclear fuel purchases as of November 4, 2024 total approximately $2.053 billion and include:

•$808 million for investments in generation and mining facilities;

•$707 million for solar and energy storage development;

•$361 million for nuclear fuel purchases; and

•$177 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, February 2024 and October 2024, the Board authorized incremental amounts of $1.25 billion, $1.0 billion, $1.5 billion and $1.0 billion, respectively, for repurchases to bring the total authorized under the Share Repurchase Program to $6.75 billion as of November 4, 2024.

The following table provides information about our repurchases of common stock for the period between January 1, 2024 and November 4, 2024:

	$6.750 billion Board Authorization
	Total Number of Shares Repurchased	Average Price Paid Per Share		Amount Paid for Shares Repurchased		Amount Available for Additional Repurchases at the End of the Period
	(in millions, except share amounts and price paid per share)
Three Months Ended March 31, 2024	6,138,773	$	46.21	$	284
Three Months Ended June 30, 2024	3,946,797	83.31		328
Three Months Ended September 30, 2024 (a)	4,849,061	82.90		402
Nine Months Ended September 30, 2024	14,934,631	$	67.92	$	1,014	$	1,236
October 1, 2024 through November 4, 2024	500,151	126.44		63
January 1, 2024 through November 4, 2024 (b)	15,434,782	$	69.82	$	1,077	$	2,173

____________

(a)Shares repurchased include 52,833 of unsettled shares for $6 million as of September 30, 2024.

(b)In October 2024, the Board authorized $1.0 billion for additional repurchases under the Share Repurchase Program.

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Liquidity Effects of Commodity Hedging and Trading Activities

We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. We use cash, letters of credit, Eligible Assets (see Note 8 to the Financial Statements) and other forms of credit support to satisfy such collateral posting obligations. See Note 9 to the Financial Statements for discussion of the Vistra Operations Credit Facilities, the Commodity-Linked Facility, the Secured LOC Facilities and the Alternative LOC Facilities.

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

As of September 30, 2024, we received or posted cash, letters of credit, and Eligible Assets for commodity hedging and trading activities as follows:

•$970 million in cash and Eligible Assets have been posted with counterparties as compared to $1.244 billion posted as of December 31, 2023;

•$175 million in cash has been received from counterparties as compared to $45 million received as of December 31, 2023;

•$2.013 billion in letters of credit have been posted with counterparties as compared to $2.408 billion posted as of December 31, 2023; and

•$143 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 $25 million in federal income tax payments, $60 million in state income tax payments and $1 million in TRA payments, offset by $3 million in state tax refunds.

For the nine months ended September 30, 2024, there were $2 million in federal income tax payments, $52 million in state income tax payments, $8 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, for periods prior to the October 2024 amendments, in general, was applicable when the aggregate revolving borrowings and issued revolving letters of credit exceeded 30% of the revolving commitments, provided that solely with respect to the Revolving Credit Facility only such amounts in excess of $300 million were taken into account for purposes of determining whether a compliance period was 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 September 30, 2024, we were in compliance with the Vistra Operations Credit Agreement, Vistra Operations Commodity-Linked Credit Agreement and Secured LOC Facilities financial covenants.

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See Note 9 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 September 30, 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 $585 million in the form of letters of credit, $81 million in the form of a surety bond and $3 million of cash as of September 30, 2024 (which is subject to daily adjustments based on settlement activity with the ISOs/RTOs).

Material Cross Default/Acceleration Provisions

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

A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the 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 $2.481 billion and zero, respectively, as of September 30, 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.

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

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

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

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

Under the Vistra Operations Senior Unsecured Indenture and the Vistra Operations Senior Secured Indenture governing the 7.750% Senior Unsecured Notes, the 6.875% Senior Unsecured Notes, the 6.950% Senior Secured Notes and the 6.000% Senior Secured Notes, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount that exceeds the greater of 1.5% of total assets and $600 million may result in a cross default under the respective notes and other current or future documents evidencing any indebtedness for borrowed money by the applicable borrower or issuer, as the case may be, and the applicable Guarantor Subsidiaries party thereto.

A default by Vistra Zero 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 $697 million as of September 30, 2024.

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

Guarantees

See Note 14 to the Financial Statements for discussion of guarantees.

Commitments and Contingencies

See Note 14 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.

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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.

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.

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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.

	Nine Months Ended September 30, 2024		Year Ended December 31, 2023
	(in millions)
Month-end average VaR	$	274	$	190
Month-end high VaR	$	371	$	423
Month-end low VaR	$	196	$	115

The month-end average VaR risk measure increased in 2024 due to higher volumes following the Energy Harbor Merger.

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 September 30, 2024.

	Balance of 2024		2025
	(in millions)
Texas:
Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price	$	8	$	12
Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price	$	—	$	—
Natural Gas Generation: $1.00/MWh increase in spark spread	$	—	$	—
Natural Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	—
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	(1)	$	12
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	1	$	(12)
East:
Nuclear Generation: $2.50/MWh increase in power price	$	12	$	40
Nuclear Generation: $2.50/MWh decrease in power price	$	—	$	(19)
Natural Gas Generation: $1.00/MWh increase in spark spread	$	—	$	1
Natural Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	(1)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	(1)	$	(20)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	1	$	20
West:
Natural Gas Generation: $1.00/MWh increase in spark spread	$	—	$	—
Natural Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	—
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
Sunset:
Coal Generation: $2.50/MWh increase in power price	$	—	$	6
Coal Generation: $2.50/MWh decrease in power price	$	—	$	(7)
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

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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 September 30, 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 10 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 10 to the Financial Statements for further discussion of this exposure.

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 $2.919 billion as of September 30, 2024.

As of September 30, 2024, Retail segment credit exposure totaled approximately $1.913 billion, including $1.902 billion of trade accounts receivable and $11 million related to derivatives. Cash deposits and letters of credit held as collateral for these receivables totaled $69 million, resulting in a net exposure of $1.844 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 September 30, 2024, aggregate Texas, East, Sunset and Asset Closure segments credit exposure totaled $1.006 billion including $889 million related to derivative assets and $117 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 $744 million, as seen in the following table that presents the distribution of credit exposure by counterparty credit quality as of September 30, 2024. Credit collateral includes cash and letters of credit but excludes other credit enhancements such as guarantees or liens on assets.

	Exposure Before Credit Collateral		Credit Collateral		Net Exposure
	(in millions)
Investment grade	$	706	$	172	$	534
Below investment grade or no rating	300		90		210
Totals	$	1,006	$	262	$	744

Significant (i.e., 10% or greater) concentration of credit exposure exists with one counterparty, which represents an aggregate $250 million, or 34%, of our total net exposure as of September 30, 2024. We view exposure to this counterparty to be within an acceptable level of risk tolerance due to the counterparty's credit ratings, the counterparty's market role and deemed creditworthiness and the importance of our business relationship with the counterparty. 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.

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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 September 30, 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 14 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 license for the unit at the Perry Facility will expire in 2026, and is pending a license renewal application 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 September 30, 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)
July 1 - July 31, 2024	1,515,716	$	81.11	1,515,716	$	1,515
August 1 - August 31, 2024	1,718,010	$	79.95	1,718,010	$	1,377
September 1 - September 30, 2024	1,615,335	$	87.71	1,615,335	$	1,236
For the quarter ended September 30, 2024	4,849,061	$	82.90	4,849,061	$	1,236

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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, February 2024 and October 2024, the Board authorized incremental amounts of $1.25 billion, $1.0 billion, $1.5 billion and $1.0 billion, respectively, for repurchases to bring the total authorized under the Share Repurchase Program to $6.75 billion as of November 4, 2024. We expect to complete repurchases under the Share Repurchase Program by the end of 2026.

See Note 15 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 September 30, 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

88

Exhibits	Previously Filed With File Number*	As Exhibit
(3(ii))	By-laws
3.6	0001-38086 Form 8-K (filed November 5, 2024)	3.1	—	Amended and Restated Bylaws of Vistra Corp., effective October 30, 2024
(4)	Instruments Defining the Rights of Security Holders, Including Indentures
4.1	0001-38086 Form 8-K (filed July 12, 2024)	4.1	—	Fifteenth Amendment to Receivables Purchase Agreement, dated as of July 11, 2024, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
(10)	Material Contracts
10.1	0001-38086 Form 8-K (filed July 12, 2024)	10.1	—	Amendment No. 5 to Master Framework Agreement, dated as of July 11, 2024, by and among TXU Energy Retail Company LLC, as seller and seller party agent, certain originators name therein, Vistra Operations Company LLC, as guarantor, and MUFG Bank, Ltd., as buyer
10.2	0001-38086 Form 8-K (filed July 12, 2024)	10.2	—	Amendment No. 4 to Master Repurchase Agreement, dated as of July 11, 2024, by and among TXU Energy Retail Company LLC, as seller and MUFG Bank, Ltd., as buyer
10.3	0001-38086 Form 8-K (filed September 24, 2024)	10.1	—	Unit Purchase Agreement, dated September 18, 2024, by and among Vistra Operations Company LLC, Vistra Vision Holdings I LLC, and VV Aggregator Holdings 1 LLC
10.4	0001-38086 Form 8-K (filed September 24, 2024)	10.2	—	Unit Purchase Agreement, dated September 18, 2024, by and among Vistra Operations Company LLC, Vistra Vision Holdings I LLC, and certain funds and accounts advised by Nuveen Asset Management, LLC
10.5	**		—	Eighth Amendment to Credit Agreement, dated as of October 2, 2024, among Vistra Operations Company LLC, as Borrower, Vistra Intermediate Company LLC, as Holdings, Citibank, N.A., as Administrative Agent and as Collateral Agent, and the other lenders party thereto
10.6	**		—	Sixteenth Amendment to the Credit Agreement, dated October 11, 2024, by and among Vistra Operations Company LLC (as Borrower), Vistra Intermediate Company LLC (as Holdings), the guarantors party thereto, the revolving credit lenders and revolving letter of credit issuers party thereto, and Citibank, N.A. (as Administrative Agent and as Collateral Agent)
(31)	Rule 13a-14(a) / 15d-14(a) Certifications
31.1	**		—	Certification of James A. Burke, principal executive officer of Vistra Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	**		—	Certification of Kristopher E. Moldovan, principal financial officer of Vistra Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(32)	Section 1350 Certifications
32.1	***		—	Certification of James A. Burke, principal executive officer of Vistra Corp., pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	***		—	Certification of Kristopher E. Moldovan, principal financial officer of Vistra Corp., pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

89

Exhibits	Previously Filed With File Number*	As Exhibit
(95)	Mine Safety Disclosures
95.1	**		—	Mine Safety Disclosures
	XBRL Data Files
101.INS	**		—	The following financial information from Vistra Corp.'s Quarterly Report on Form 10-Q for the period ended September 30, 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, (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

90

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: November 7, 2024

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