vistra-20230630

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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 JUNE 30, 2023

— 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

Warrants

VST.WS.A

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 ☒

As of August 4, 2023, there were 367,570,248 shares of common stock, par value $0.01, outstanding of Vistra Corp.

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TABLE OF CONTENTS


		PAGE
GLOSSARY		ii
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Statements of Operations — Three and Six Months Ended June 30 , 2023 and 2022	1
	Condensed Consolidated Statements of Comprehensive Income (Loss) — Three and Six Months Ended Ju ne 30 , 2023 and 2022	1
	Condensed Consolidated Statements of Cash Flows — Six Months Ended June 30 , 2023 and 2022	2
	Condensed Consolidated Balance Sheets — June 30 , 2023 and December 31, 2022	4
	Notes to Condensed Consolidated Financial Statements	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	56
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	82
Item 4.	Controls and Procedures	87
PART II.	OTHER INFORMATION	88
Item 1.	Legal Proceedings	88
Item 1A.	Risk Factors	88
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	90
Item 3.	Defaults Upon Senior Securities	90
Item 4.	Mine Safety Disclosures	90
Item 5.	Other Information	90
Item 6.	Exhibits	90
SIGNATURE		94

Vistra Corp.'s (Vistra) annual reports, quarterly reports, current reports and any amendments to those reports are made available to the public, free of charge, on the Vistra website at http://www.vistracorp.com, as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended. Additionally, Vistra posts important information, including press releases, investor presentations, sustainability reports, and notices of upcoming events on its website and utilizes its website as a channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under Regulation FD. Investors may be notified of posting to the website by signing up for email alerts and RSS feeds on the "Investor Relations" page of Vistra's website. The information on Vistra's website shall not be deemed a part of, or incorporated by reference into, this quarterly report on Form 10-Q. The representations and warranties contained in any agreement that we have filed as an exhibit to this quarterly report on Form 10-Q, or that we have or may publicly file in the future, may contain representations and warranties that may (i) be made by and to the parties thereto at specific dates, (ii) be subject to exceptions and qualifications contained in separate disclosure schedules, (iii) represent the parties' risk allocation in the particular transaction, or (iv) be qualified by materiality standards that differ from what may be viewed as material for securities law purposes.

This quarterly report on Form 10-Q and other Securities and Exchange Commission filings of Vistra and its subsidiaries occasionally make references to Vistra (or "we," "our," "us" or "the Company"), Luminant, TXU Energy, Ambit, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power or U.S. Gas & Electric, when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with, or otherwise reflected in, the Vistra financial statements for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or vice versa.

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GLOSSARY

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


2022 Form 10-K						Vistra's annual report on Form 10-K for the year ended December 31, 2022, filed with the SEC on March 1, 2023
Ambit						Ambit Holdings, LLC, and/or its subsidiaries (d/b/a Ambit), depending on context
ARO						asset retirement and mining reclamation obligation
CAISO						The California Independent System Operator
CARES Act						Coronavirus Aid, Relief, and Economic Security Act
CCGT						combined cycle gas turbine
CCR						coal combustion residuals
CFTC						U.S. Commodity Futures Trading Commission
CME						Chicago Mercantile Exchange
CO2						carbon dioxide
CPUC						California Public Utilities Commission
Crius						Crius Energy Trust and/or its subsidiaries, 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, wholly owned subsidiaries of Vistra, that are REPs in certain areas of MISO and PJM, respectively, and are engaged in the retail sale of electricity to residential and business customers.
Dynegy Merger						the merger of Dynegy with and into Vistra, with Vistra as the surviving corporation
Dynegy Merger Date						April 9, 2018, the date Vistra and Dynegy completed the transactions contemplated by the Agreement and Plan of Merger, dated as of October 29, 2017, by and between Vistra and Dynegy
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
Energy Harbor						Energy Harbor Corp., and/or its subsidiaries, depending on context
EPA						U.S. Environmental Protection Agency
ERCOT						Electric Reliability Council of Texas, Inc.
ESS						energy storage system
Exchange Act						Securities Exchange Act of 1934, as amended
FERC						U.S. Federal Energy Regulatory Commission
GAAP						generally accepted accounting principles
GHG						greenhouse gas
GWh						gigawatt-hours
Green Finance Framework						Framework adopted by the Company and made available on its website pursuant to which the Company may issue financial instruments to fund new or existing projects that support renewable energy and energy efficiency, with alignment to the Company's environmental, social, and governance strategy
Homefield Energy						Illinois Power Marketing Company (d/b/a Homefield Energy), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of MISO that is engaged in the retail sale of electricity to municipal customers
ICE						Intercontinental Exchange
IEPA						Illinois Environmental Protection Agency
IPCB						Illinois Pollution Control Board
IRA						Inflation Reduction Act of 2022
IRC						Internal Revenue Code of 1986, as amended
IRS						U.S. Internal Revenue Service

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ISO						independent system operator
ISO-NE						ISO New England Inc.
LIBOR						London Interbank Offered Rate, an interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market
load						demand for electricity
LTSA						long-term service agreements for plant maintenance
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
market heat rate						Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier (generally natural gas plants), by the market price of natural gas.
Merger Sub						Black Pen Inc., an indirect, wholly owned subsidiary of Vistra
MISO						Midcontinent Independent System Operator, Inc.
MMBtu						million British thermal units
Moody's						Moody's Investors Service, Inc. (a credit rating agency)
MSHA						U.S. Mine Safety and Health Administration
MW						megawatts
MWh						megawatt-hours
NERC						North American Electric Reliability Corporation
NOX						nitrogen oxide
NRC						U.S. Nuclear Regulatory Commission
NYISO						New York Independent System Operator, Inc.
NYMEX						the New York Mercantile Exchange, a commodity derivatives exchange
Parent						Vistra Corp.
PJM						PJM Interconnection, LLC
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
Public Power						Public Power, LLC (d/b/a Public Power), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of PJM, ISO-NE, NYISO and MISO that is engaged in the retail sale of electricity to residential and business customers
PUCT						Public Utility Commission of Texas
REP						retail electric provider
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
RTO						regional transmission organization
S&P						Standard & Poor's Ratings (a credit rating agency)
SEC						U.S. Securities and Exchange Commission
Securities Act						Securities Act of 1933, as amended
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
SO2						sulfur dioxide

iii

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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
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
TCEQ						Texas Commission on Environmental Quality
TRA						Tax Receivable Agreement, containing certain rights (TRA Rights) to receive payments from Vistra related to certain tax benefits, including benefits realized as a result of certain transactions entered into at Emergence (see Note 8 to the Financial Statements)
TRE						Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with NERC standards and monitors compliance with ERCOT protocols
TriEagle Energy						TriEagle Energy, LP (d/b/a TriEagle Energy, TriEagle Energy Services, Eagle Energy, Energy Rewards, Power House Energy and Viridian Energy), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of ERCOT and PJM that is engaged in the retail sale of electricity to residential and business customers
TXU Energy						TXU Energy Retail Company LLC (d/b/a TXU), an indirect, wholly owned subsidiary of Vistra that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers
U.S.						United States of America
U.S. Gas & Electric						U.S. Gas and Electric, LLC (d/b/a USG&E, Illinois Gas & Electric and ILG&E), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of PJM, ISO-NE, NYISO and MISO that is engaged in the retail sale of electricity to residential and business customers
Value Based Brands						Value Based Brands LLC (d/b/a 4Change Energy, Express Energy and Veteran Energy), an indirect, wholly owned subsidiary of Vistra that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers
Vistra						Vistra Corp. and/or its subsidiaries, depending on context
Vistra Intermediate						Vistra Intermediate Company LLC, a direct, wholly owned subsidiary of Vistra
Vistra Operations						Vistra Operations Company LLC, an indirect, wholly owned subsidiary of Vistra that is the issuer of certain series of notes (see Note 12 to the Financial Statements) and borrower under the Vistra Operations Credit Facilities
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 12 to the Financial Statements)
Vistra Zero						subsidiaries of Vistra engaged in the operation and development of renewables and energy storage assets

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PART I. FINANCIAL INFORMATION

Item 1.FINANCIAL STATEMENTS

VISTRA CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited) (Millions of Dollars, Except Per Share Amounts)


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Operating revenues (Note 5)	$	3,189	$	1,588	$	7,614	$	4,713
Fuel, purchased power costs and delivery fees	(1,475)		(2,162)		(3,645)		(4,441)
Operating costs	(445)		(435)		(866)		(851)
Depreciation and amortization	(369)		(394)		(735)		(824)
Selling, general and administrative expenses	(309)		(280)		(597)		(569)

Impairment of long-lived assets (Note 19)	—		—		(49)		—
Operating income (loss)	591		(1,683)		1,722		(1,972)
Other income (Note 19)	124		71		144		77
Other deductions (Note 19)	(2)		(9)		(5)		(13)
Interest expense and related charges (Note 19)	(100)		(109)		(307)		(116)
Impacts of Tax Receivable Agreement (Note 8)	(14)		(34)		(79)		(115)

Net income (loss) before income taxes	599		(1,764)		1,475		(2,139)
Income tax (expense) benefit (Note 7)	(123)		407		(301)		498
Net income (loss)	$	476	$	(1,357)	$	1,174	$	(1,641)
Net (income) loss attributable to noncontrolling interest	—		(8)		1		(9)
Net income (loss) attributable to Vistra	$	476	$	(1,365)	$	1,175	$	(1,650)
Cumulative dividends attributable to preferred stock	(37)		(37)		(75)		(75)
Net income (loss) attributable to Vistra common stock	$	439	$	(1,402)	$	1,100	$	(1,725)
Weighted average shares of common stock outstanding:
Basic	372,956,476		429,193,031		378,264,434		440,336,286
Diluted	376,794,258		429,193,031		382,416,465		440,336,286
Net income (loss) per weighted average share of common stock outstanding:
Basic	$	1.18	$	(3.27)	$	2.91	$	(3.92)
Diluted	$	1.17	$	(3.27)	$	2.88	$	(3.92)

See Notes to the Condensed Consolidated Financial Statements.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited) (Millions of Dollars)


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Net income (loss)	$	476	$	(1,357)	$	1,174	$	(1,641)
Other comprehensive income, net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax expense of $1, $—, $1 and $—)	4		—		5		—

Total other comprehensive income	4		—		5		—
Comprehensive income (loss)	$	480	$	(1,357)	$	1,179	$	(1,641)
Comprehensive (income) loss attributable to noncontrolling interest	—		(8)		1		(9)
Comprehensive income (loss) attributable to Vistra	$	480	$	(1,365)	$	1,180	$	(1,650)

See Notes to the Condensed Consolidated Financial Statements.

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VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars)
	Six Months Ended June 30,
	2023		2022
Cash flows — operating activities:
Net income (loss)	$	1,174	$	(1,641)
Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:
Depreciation and amortization	941		1,054
Deferred income tax expense (benefit), net	290		(501)
Gain on sale of land	(94)		(5)

Impairment of long-lived and other assets	49		—


Unrealized net (gain) loss from mark-to-market valuations of commodities	(1,139)		2,347
Unrealized net gain from mark-to-market valuations of interest rate swaps	(22)		(171)
Asset retirement obligation accretion expense	17		17
Impacts of Tax Receivable Agreement	79		115
Stock-based compensation	43		34
Bad debt expense	69		65
Other, net	24		6
Changes in operating assets and liabilities:
Margin deposits, net	2,014		(1,893)
Uplift securitization proceeds receivable from ERCOT	—		544
Accrued interest	(4)		13
Accrued taxes	(52)		(62)
Accrued employee incentive	(57)		(38)
Other operating assets and liabilities	(320)		(607)
Cash provided by (used in) operating activities	3,012		(723)
Cash flows — investing activities:
Capital expenditures, including nuclear fuel purchases and LTSA prepayments	(926)		(613)

Proceeds from sales of nuclear decommissioning trust fund securities	251		334
Investments in nuclear decommissioning trust fund securities	(262)		(345)
Proceeds from sales of environmental allowances	47		266
Purchases of environmental allowances	(190)		(258)
Insurance proceeds	9		1
Proceeds from sale of assets	110		14
Other, net	(6)		(8)
Cash used in investing activities	(967)		(609)
Cash flows — financing activities:
Issuances of long-term debt	—		1,498



Repayments/repurchases of debt	(14)		(223)
Net (repayments)/borrowings under accounts receivable financing	(425)		725
Borrowings under Revolving Credit Facility	100		1,500
Repayments under Revolving Credit Facility	(350)		(1,250)
Borrowings under Commodity-Linked Facility	—		2,750
Repayments under Commodity-Linked Facility	(400)		(1,700)
Share repurchases	(552)		(1,194)
Dividends paid to common stockholders	(153)		(152)
Dividends paid to preferred stockholders	(75)		(76)
Debt issuance costs	(6)		(21)

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VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars)
	Six Months Ended June 30,
	2023		2022
Other, net	3		23
Cash (used in) provided by financing activities	(1,872)		1,880
Net change in cash, cash equivalents and restricted cash	173		548
Cash, cash equivalents and restricted cash — beginning balance	525		1,359
Cash, cash equivalents and restricted cash — ending balance	$	698	$	1,907

See Notes to the Condensed Consolidated Financial Statements.

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VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars)
	June 30, 2023		December 31, 2022
ASSETS
Current assets:
Cash and cash equivalents	$	643	$	455
Restricted cash (Note 19)	40		37
Trade accounts receivable — net (Note 19)	1,681		2,059
Income taxes receivable	26		27
Inventories (Note 19)	676		570
Commodity and other derivative contractual assets (Note 16)	3,991		4,538
Margin deposits related to commodity contracts	1,130		3,137
Margin deposits posted under affiliate financing agreement (Note 11)	443		—

Prepaid expense and other current assets	281		293
Total current assets	8,911		11,116
Restricted cash (Note 19)	15		33
Investments (Note 19)	1,915		1,729

Property, plant and equipment — net (Note 19)	12,537		12,554
Operating lease right-of-use assets	54		51

Goodwill (Note 6)	2,583		2,583
Identifiable intangible assets — net (Note 6)	1,912		1,958
Commodity and other derivative contractual assets (Note 16)	665		702
Accumulated deferred income taxes	1,385		1,710
Other noncurrent assets	495		351
Total assets	$	30,472	$	32,787
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (Note 12)	$	—	$	650
Accounts receivable financing (Note 10)	—		425
Long-term debt due currently (Note 12)	437		38
Trade accounts payable	1,076		1,556
Commodity and other derivative contractual liabilities (Note 16)	5,076		6,610
Margin deposits related to commodity contracts	46		39

Accrued taxes other than income	145		199
Accrued interest	156		160
Asset retirement obligations (Note 19)	119		128
Operating lease liabilities	8		8

Other current liabilities	563		524
Total current liabilities	7,626		10,337
Margin deposit financing with affiliate (Note 11)	443		—
Long-term debt, less amounts due currently (Note 12)	11,530		11,933
Operating lease liabilities	49		45

Commodity and other derivative contractual liabilities (Note 16)	1,554		1,726
Accumulated deferred income taxes	1		1
Tax Receivable Agreement obligation (Note 8)	591		514
Asset retirement obligations (Note 19)	2,334		2,309

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VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars)
	June 30, 2023		December 31, 2022
Other noncurrent liabilities and deferred credits (Note 19)	970		1,004
Total liabilities	25,098		27,869
Commitments and Contingencies (Note 13)
Total equity (Note 14):
Preferred stock, number of shares authorized — 100,000,000; Series A (liquidation preference — $1,000; shares outstanding: June 30, 2023 and December 31, 2022— 1,000,000); Series B (liquidation preference — $1,000; shares outstanding: June 30, 2023 and December 31, 2022 — 1,000,000)	2,000		2,000
Common stock (par value — $0.01; number of shares authorized — 1,800,000,000) (shares outstanding: June 30, 2023 — 369,625,544; December 31, 2022 — 389,754,870)	5		5
Treasury stock, at cost (shares: June 30, 2023 — 170,766,019; December 31, 2022 — 147,424,202)	(3,955)		(3,395)
Additional paid-in-capital	9,993		9,928
Retained deficit	(2,696)		(3,643)
Accumulated other comprehensive income	12		7
Stockholders' equity	5,359		4,902
Noncontrolling interest in subsidiary	15		16
Total equity	5,374		4,918
Total liabilities and equity	$	30,472	$	32,787

See Notes to the Condensed Consolidated Financial Statements.

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VISTRA CORP.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Description of Business

References in this report to "we," "our," "us" and "the Company" are to Vistra and/or its subsidiaries, as apparent in the context. See Glossary 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 18 for further information concerning our reportable business segments.

Transaction Agreement

On March 6, 2023, Vistra Operations and Merger Sub entered into a transaction agreement (Transaction Agreement) with Energy Harbor pursuant to which, upon the terms and subject to the conditions thereof, Merger Sub will be merged with and into Energy Harbor, with Energy Harbor surviving as an indirect subsidiary of Vistra (Merger, and collectively with the other transactions contemplated by the Transaction Agreement, the Transactions). The Transaction Agreement, the Merger and the other Transactions were approved by each of Vistra's board of directors (Board) and Energy Harbor's board of directors. See Note 2 for more information concerning the Transaction Agreement.

Winter Storm Uri

In February 2021, a severe winter storm with extremely cold temperatures affected much of the U.S., including Texas. This severe weather resulted in surging demand for power, gas supply shortages, operational challenges for generators, and a significant load shed event that was ordered by ERCOT beginning on February 15, 2021 and continuing through February 18, 2021. Winter Storm Uri had a material adverse impact on our 2021 results of operations and operating cash flows.

Uplift Securitization Proceeds from ERCOT — As part of the 2021 regular Texas legislative sessions and in response to extraordinary costs incurred by electricity market participants during Winter Storm Uri, the Texas legislature passed House Bill (HB) 4492 for ERCOT to obtain financing to distribute to load-serving entities (LSEs) that were uplifted and paid to ERCOT exceptionally high price adders and ancillary service costs during Winter Storm Uri. In October 2021, the PUCT issued a Debt Obligation Order approving $2.1 billion financing and the methodology for allocation of proceeds to the LSEs. In December 2021, ERCOT finalized the amount of allocations to the LSEs, and we received $544 million of proceeds from ERCOT in the second quarter of 2022. The Company accounted for the proceeds we received by analogy to the contribution model within Accounting Standards Codification (ASC) 958-605, Not-for-Profit Entities - Revenue Recognition and the grant model within International Accounting Standard 20, Accounting for Government Grants and Disclosure of Government Assistance, as a reduction to expenses in the statements of operations in the annual period for which the proceeds are intended to compensate. We concluded that the threshold for recognizing a receivable was met in December 2021 as the amounts to be received were determinable and ERCOT was directed by its governing body, the PUCT, to take all actions required to effectuate the $2.1 billion funding approved in the Debt Obligation Order. The final financial impact of Winter Storm Uri continues to be subject to the outcome of litigation arising from the event.

Recent Developments

Dividends Declared — In August 2023, the Vistra Board declared a quarterly dividend of $0.206 per share of common stock that will be paid in September 2023. In August 2023, the Board declared a semi-annual dividend of $40.00 per share of Series A Preferred Stock that will be paid in October 2023.

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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 2022 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. 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 2022 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.

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

In November 2021, the Financial Accounting Standards Board issued ASU 2021-10, Government Assistance (Topic 832) Disclosures by Business Entities about Government Assistance. This standard requires additional annual disclosures when a business receives government assistance and uses a grant or contribution accounting model by analogy to other accounting guidance such as the grant model under International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance (IAS 20) and GAAP ASC 958-605, Not-for-Profit Entities - Revenue Recognition. The standard was effective January 1, 2022 with early adoption permitted. As further discussed in Note 1, we made disclosures in accordance with this guidance when accounting for the Uplift Securitization Proceeds from ERCOT.

Due to the enactment of the IRA, the Company will qualify for tax incentives through eligible construction spending and production. These tax incentives generally provide for refundable or transferable tax credits upon the applicable qualifying event for the credit type, typically production or in-service date. Transferable and refundable production tax credits (PTCs) are included in other noncurrent assets in the condensed consolidated balance sheet and included in revenues in the condensed consolidated statements of operations when receipt of the credit becomes probable. Transferable investment tax credits (ITCs) are included in other noncurrent assets on the condensed consolidated balance sheet with a corresponding reduction to the cost basis of the Company's plant assets when receipt of the credit is reasonably assured, and reduces depreciation expense over the life of the asset. We believe the term reasonable assurance as used in IAS 20 is analogous to the term probable as defined in ASC 450-20 of U.S. GAAP. The Company accounts for the credits we expect to receive by analogy to the grant model within IAS 20, as U.S. GAAP does not address how to account for these tax credits.

2. TRANSACTION AGREEMENT

On March 6, 2023, Vistra Operations and Merger Sub entered into the Transaction Agreement with Energy Harbor pursuant to which, upon the terms and subject to the conditions thereof, Merger Sub will be merged with and into Energy Harbor, with Energy Harbor surviving as an indirect subsidiary of Vistra. The Transaction Agreement, the Merger and the other Transactions were approved by each of Vistra's Board and Energy Harbor's board of directors.

Subject to the terms and conditions of the Transaction Agreement, prior to the consummation of the Merger, Vistra will cause certain of its affiliates to transfer certain of its affiliate entities, including Merger Sub, to a newly formed limited liability company and an indirect wholly owned subsidiary of Vistra (Vistra Vision).

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Subject to the terms and conditions of the Transaction Agreement, at the effective time of the Merger (Effective Time), the issued and outstanding shares of Energy Harbor common stock other than shares that are being exchanged by certain funds and accounts managed by Nuveen Asset Management LLC and certain funds managed by Avenue Capital Management II, L.P. (Rollover Holders) for 15% of the direct or indirect equity interests in Vistra Vision, and certain other shares, each as specified in the Transaction Agreement and the Contribution and Exchange Agreements (as defined below) will be cancelled and extinguished and automatically converted into the right to receive cash consideration per share payable in the Merger. Vistra's transfer of cash and equity in Vistra Vision in exchange for the issued and outstanding shares of Energy Harbor common stock will be covered under the non-recognition provisions of the Internal Revenue Code. The Aggregate Base Transaction Value is defined in the Transaction Agreement to be (a) the Aggregate Cash Consideration Value (defined in the Transaction Agreement to be $3.0 billion), plus (b) for the 15% equity in Vistra Vision, the Aggregate Equity Consideration Value (defined in the Transaction Agreement to be $3.333 billion for the purpose of determining the amount per share to be distributed to Energy Harbor's stockholders), minus (c) certain adjustments as specified in the Transaction Agreement. In addition, in connection with the Merger, Energy Harbor's equity awards will be cancelled for cash based on the per share Merger consideration for the shares underlying such equity awards and Energy Harbor's stockholders (including Rollover Holders and holders of Energy Harbor equity awards) will receive an additional amount of cash paid from Energy Harbor to the extent of Energy Harbor's unrestricted cash on hand as of the closing, subject to certain adjustments as specified in the Transaction Agreement. In addition, Vistra Operations will pay up to $100 million of Energy Harbor's transaction expenses.

Consummation of the Transactions is subject to customary closing conditions, including (a) approval and adoption of the Transaction Agreement and the Transactions by a majority of the outstanding shares of Energy Harbor common stock, Series A Preferred Stock and Series B Preferred Stock entitled to vote thereon, voting together as a single class (Requisite Stockholder Approval), (b) receipt of all requisite regulatory approvals, including approvals of the NRC and the FERC, (c) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and (d) the divestment of Energy Harbor's remaining fossil-fueled assets. In March 2023, Energy Harbor obtained the Requisite Stockholder Approval. We are pursuing all regulatory approvals and anticipate the Transactions will close in the fourth quarter of 2023.

Vistra Vision will combine Energy Harbor's nuclear and retail businesses with Vistra's nuclear and retail businesses and certain of the Vistra Zero renewables and energy storage projects. This combination is expected to create a leading integrated retail electricity and zero-carbon generation company with the second-largest competitive nuclear fleet in the U.S., along with a growing renewables and energy storage portfolio. This transaction is expected to accelerate Vistra's path to a clean energy transition by more than doubling the amount of zero-carbon generation it has online at the time of the Transactions' closing.

Financing Arrangements

In connection with the Transactions, on March 6, 2023, Vistra Operations entered into a debt commitment letter (Commitment Letter) and related fee letters with Citigroup Global Markets Inc. (Citi), BMO Capital Markets Corp. (BMO) and Mizuho Bank, Ltd. (Mizuho, and together with Citi and BMO the Initial Commitment Parties), pursuant to which, and subject to the terms and conditions set forth therein, the Initial Commitment Parties committed to provide (a) up to approximately $3.0 billion in an aggregate principal amount of senior secured bridge loans under a 364-day senior secured bridge loan credit facility (Acquisition Bridge Facility), (b) in the event Vistra Operations did not obtain certain required consents and amendments from the lenders under the Vistra Operations Credit Agreement, a 364-day senior secured term loan B bridge facility in an aggregate principal amount of up to approximately $2.5 billion (TLB Refinancing Bridge Facility) and (c) in the event Vistra Operations did not obtain certain required consents and amendments from the lenders under the Vistra Operations Commodity-Linked Credit Agreement, a replacement commodity-linked revolving credit facility in an aggregate principal amount up to $300 million (Refinancing Commodity-Linked Revolving Credit Facility). Fees related to the Commitment Letter totaled $14 million in the six months ended June 30, 2023, which are capitalized in other noncurrent assets. The proceeds of the loans under the Acquisition Bridge Facility would be used to finance the Transactions and the payment of fees and expenses incurred in connection with the Transactions. On March 29, 2023, the Acquisition Bridge Facility syndication process was completed and the Commitment Letter was amended and restated to include additional lenders as commitment parties (together with the Initial Commitment Parties, the Commitment Parties). Vistra Operations also obtained commitments of the Commitment Parties to provide certain required consents and amendments under the Vistra Operations Credit Agreement and the Vistra Operations Commodity-Linked Credit Agreement resulting in the termination of the commitments for each of the TLB Refinancing Bridge Facility and the Refinancing Commodity-Linked Revolving Credit Facility and reclassification of $6 million of previously capitalized commitment fees to interest expense and related charges. The Acquisition Bridge Facility is subject to customary commitment reductions in the event that certain take-out debt financing is obtained on or prior to the Effective Time, and customary closing conditions, including that substantially concurrently with the initial funding under the applicable facility the Transactions shall be consummated.

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In March 2023, Vistra entered into $750 million of interest rate swaps to hedge a portion of the floating rate component of the expected interest cost associated with the anticipated Transactions debt financings at a weighted average rate of 3.16%. The interest rate swaps are effective December 31, 2023 and expire December 31, 2030.

In June 2023, Vistra reduced the aggregate principal amount of the Acquisition Bridge Facility to $2.0 billion through a combination of financing transactions and cash on hand, resulting in the reclassification of $3 million of previously capitalized commitment fees to interest expense and related charges. Additional fees totaling $5 million were paid in July 2023 on the remaining aggregate principal amount of the Acquisition Bridge Facility.

3. DEVELOPMENT OF GENERATION FACILITIES

Texas Segment Solar Generation and Energy Storage Projects

In connection with our previously announced renewables development plan in Texas, 158 MW of solar generation came online in January and February 2022 and 260 of battery ESS came online in April 2022. Estimated commercial operation dates for the remaining facilities to be developed are expected to be 2024 and beyond, but we will only invest in growth projects if we are confident that the expected returns will meet or exceed internal targets. As of June 30, 2023, we had accumulated approximately $53 million in construction-work-in-process for these remaining Texas segment solar generation projects.

East Segment Solar Generation and Energy Storage Projects

In September 2021, we announced the planned development of up to 300 MW of solar photovoltaic power generation facilities and up to 150 MW of battery ESS at retired or to-be-retired plant sites in Illinois, based on the passage of Illinois Senate Bill 2408, the Energy Transition Act. Estimated commercial operation dates for these facilities range from 2025 to 2026. As of June 30, 2023, we had accumulated approximately $25 million in construction-work-in-process for these East segment solar generation and battery ESS projects.

West Segment Energy Storage Projects

Moss Landing — In June 2018, we announced that, subject to approval by the CPUC, we would enter into a 20-year resource adequacy contract with PG&E to develop a 300 MW battery ESS at our Moss Landing Power Plant site in California (Moss Landing Phase I). The CPUC approved the resource adequacy contract in November 2018. Under the contract, PG&E will pay us a fixed monthly resource adequacy payment, while we will receive the energy revenues and incur the costs from dispatching and charging the ESS. Moss Landing Phase I commenced commercial operations in May 2021.

In May 2020, we announced that, subject to approval by the CPUC, we would enter into a 10-year resource adequacy contract with PG&E to develop an additional 100 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase II). The CPUC approved the resource adequacy contract in August 2020. Moss Landing Phase II commenced commercial operations in July 2021.

In January 2022, we announced that, subject to approval by the CPUC, we would enter into a 15-year resource adequacy and energy settlement contract with PG&E to develop an additional 350 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase III). The CPUC approved the resource adequacy and energy settlement contract in April 2022. Moss Landing Phase III commenced commercial operations in June 2023. As a result of reaching commercial operations, we recognized $141 million of transferable ITCs associated with the project within other noncurrent assets in the condensed consolidated balance sheet.

Moss Landing Outages — In September 2021, Moss Landing Phase I experienced an incident impacting a portion of the battery ESS. A review found the root cause originated in systems separate from the battery system. The facility was offline as we performed the work necessary to return the facility to service. Restoration work on the facility was completed in June 2022. Moss Landing Phases II and III were not affected by this incident.

In February 2022, Moss Landing Phase II experienced an incident impacting a portion of the battery ESS. A review found the root cause originated in systems separate from the battery system. The facility was offline as we performed the work necessary to return the facility to service. Restoration work on the facility was completed in September 2022. Moss Landing Phases I and III were not affected by this incident.

These incidents did not have a material impact on our results of operations.

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4. RETIREMENT OF GENERATION FACILITIES

In 2020, we announced our intention to retire all of our remaining coal generation facilities in Illinois and Ohio, one coal generation facility in Texas and one natural gas facility in Illinois no later than year-end 2027 due to economic challenges, including incremental expenditures that would be required to comply with the CCR rule and ELG rule (see Note 13), and in furtherance of our efforts to significantly reduce our carbon footprint. As previously announced in April 2021, we retired the Joppa generation facilities in September 2022 in order to settle a complaint filed with the Illinois Pollution Control Board (IPCB) by the Sierra Club in 2018. As previously announced in July 2021, we retired the Zimmer coal generation facility in June 2022 due to the inability to secure capacity revenues for the plant in the PJM capacity auction held in May 2021.

As previously announced, we retired the Edwards coal generation facility in January 2023.

Operational results for plants with defined retirement dates are included in our Sunset segment beginning in the quarter when a retirement plan is announced and move to the Asset Closure segment at the beginning of the calendar year the retirement is expected to occur.

Facility

Location

ISO/RTO

Fuel Type

Net Generation Capacity (MW)

Actual or Expected Retirement Date (a)(b)

Segment

Baldwin

Baldwin, IL

MISO

Coal

1,185

By the end of 2025

Sunset

Coleto Creek

Goliad, TX

ERCOT

Coal

650

By the end of 2027

Sunset

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

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

Zimmer

Moscow, OH

PJM

Coal

1,300

Retired June 1, 2022

Asset Closure

Total

7,486

____________

(a)Generation facilities may retire earlier than the end of 2027 if economic or other conditions dictate.

(b)Retirement dates represent the first full day in which a plant does not operate.

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5. REVENUE


	Three Months Ended June 30, 2023
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations		Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	1,843	$	—	$	—	$	—	$	—	$	—	$	—	$	1,843
Retail energy charge in Northeast/Midwest	352		—		—		—		—		—		—		352


Wholesale generation revenue from ISO/RTO	—		182		181		44		53		—		—		460
Capacity revenue from ISO/RTO (a)	—		—		22		—		9		—		—		31
Revenue from other wholesale contracts	—		102		178		38		23		—		—		341
Total revenue from contracts with customers	2,195		284		381		82		85		—		—		3,027
Other revenues:
Intangible amortization	(1)		—		(1)		—		(1)		—		—		(3)
Transferable PTC revenues	—		3		—		—		—		—		—		3
Hedging and other revenues (b)	233		(358)		38		141		108		—		—		162
Affiliate sales (c)	—		262		428		1		122		—		(813)		—
Total other revenues	232		(93)		465		142		229		—		(813)		162
Total revenues	$	2,427	$	191	$	846	$	224	$	314	$	—	$	(813)	$	3,189

____________

(a)Represents net capacity sold in each ISO/RTO. The East segment includes $41 million of capacity sold offset by $19 million of capacity purchased. The Sunset segment includes $18 million of capacity sold offset by $9 million of capacity purchased.

(b)Includes $89 million of unrealized net gains from mark-to-market valuations of commodity positions. See Note 18 for unrealized net gains (losses) by segment.

(c)Texas segment includes $494 million of affiliated unrealized net losses and the East and Sunset segments include $126 million and $48 million, respectively, of affiliated unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.

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	Three Months Ended June 30, 2022
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations		Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	1,757	$	—	$	—	$	—	$	—	$	—	$	—	$	1,757
Retail energy charge in Northeast/Midwest	543		—		—		—		—		—		—		543


Wholesale generation revenue from ISO/RTO	—		(59)		170		53		174		229		—		567
Capacity revenue from ISO/RTO (a)	—		—		(4)		—		22		11		—		29
Revenue from other wholesale contracts	—		146		202		35		38		9		—		430
Total revenue from contracts with customers	2,300		87		368		88		234		249		—		3,326
Other revenues:
Intangible amortization	(1)		—		—		—		(2)		—		—		(3)
Hedging and other revenues (b)	(507)		(453)		(295)		(12)		(347)		(121)		—		(1,735)
Affiliate sales (c)	—		(257)		246		3		36		(11)		(17)		—
Total other revenues	(508)		(710)		(49)		(9)		(313)		(132)		(17)		(1,738)
Total revenues	$	1,792	$	(623)	$	319	$	79	$	(79)	$	117	$	(17)	$	1,588

____________

(a)Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $102 million of capacity purchased offset by $98 million of capacity sold. The Sunset segment includes $24 million of capacity sold offset by $2 million of capacity purchased. The Asset Closure segment includes $11 million of capacity sold.

(b)Includes $2.088 billion of unrealized net losses from mark-to-market valuations of commodity positions. See Note 18 for unrealized net gains (losses) by segment. See Note 18 for unrealized net gains (losses) by segment.

(c)Texas, East, Sunset and Asset Closure segments include $918 million, $151 million, $88 million and $11 million, respectively, of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

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	Six Months Ended June 30, 2023
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations		Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	3,411	$	—	$	—	$	—	$	—	$	—	$	—	$	3,411
Retail energy charge in Northeast/Midwest	778		—		—		—		—		—		—		778
Wholesale generation revenue from ISO/RTO	—		232		401		237		120		—		—		990
Capacity revenue from ISO/RTO (a)	—		—		30		—		27		—		—		57
Revenue from other wholesale contracts	—		209		509		79		99		—		—		896
Total revenue from contracts with customers	4,189		441		940		316		246		—		—		6,132
Other revenues:
Intangible amortization	(1)		—		(2)		—		(1)		—		—		(4)
Transferable PTC revenues	—		5		—		—		—		—		—		5
Hedging and other revenues (b)	589		(246)		424		134		580		—		—		1,481
Affiliate sales (c)	—		1,344		1,293		5		317		—		(2,959)		—
Total other revenues	588		1,103		1,715		139		896		—		(2,959)		1,482
Total revenues	$	4,777	$	1,544	$	2,655	$	455	$	1,142	$	—	$	(2,959)	$	7,614

____________

(a)Represents net capacity sold in each ISO/RTO. The East segment includes $83 million of capacity sold offset by $53 million of capacity purchased. The Sunset segment includes $63 million of capacity sold offset by $36 million of capacity purchased.

(b)Includes $1.366 billion of unrealized net gains from mark-to-market valuations of commodity positions. See Note 18 for unrealized net gains (losses) by segment.

(c)Texas segment includes $309 million of affiliated unrealized net losses and the East and Sunset segments include $521 million and $151 million, respectively, of affiliated unrealized net gains from mark-to-market valuations of commodity positions with the Retail segment.

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	Six Months Ended June 30, 2022
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations		Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	3,162	$	—	$	—	$	—	$	—	$	—	$	—	$	3,162
Retail energy charge in Northeast/Midwest	1,183		—		—		—		—		—		—		1,183
Wholesale generation revenue from ISO/RTO	—		92		572		112		315		393		—		1,484
Capacity revenue from ISO/RTO (a)	—		—		(10)		—		56		27		—		73
Revenue from other wholesale contracts	—		265		445		73		81		21		—		885
Total revenue from contracts with customers	4,345		357		1,007		185		452		441		—		6,787
Other revenues:
Intangible amortization	(1)		—		—		—		(4)		—		—		(5)

Hedging and other revenues (b)	(727)		(451)		13		(40)		(653)		(211)		—		(2,069)
Affiliate sales (c)	—		(1,624)		254		6		8		(28)		1,384		—
Total other revenues	(728)		(2,075)		267		(34)		(649)		(239)		1,384		(2,074)
Total revenues	$	3,617	$	(1,718)	$	1,274	$	151	$	(197)	$	202	$	1,384	$	4,713

____________

(a)Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $238 million of capacity purchased offset by $228 million of capacity sold. The Sunset segment includes $59 million of capacity sold offset by $3 million of capacity purchased. The Asset Closure segment includes $27 million of capacity sold.

(b)Includes $2.447 billion of unrealized net losses from mark-to-market valuations of commodity positions. See Note 18 for unrealized net gains (losses) by segment.

(c)Texas, East, Sunset and Asset Closure segments include $2.928 billion, $660 million, $225 million and $28 million, respectively, of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

Performance Obligations

As of June 30, 2023, we have future 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. Therefore, an obligation exists as of the date of the results of the respective ISO/RTO capacity auction or the contract execution date. These obligations total $195 million, $396 million, $324 million, $206 million and $100 million that will be recognized, in the balance of the year ended December 31, 2023 and the years ending December 31, 2024, 2025, 2026 and 2027, respectively, and $672 million thereafter. Capacity revenues are recognized as capacity is made available to the related ISOs/RTOs or counterparties.

Accounts Receivable

The following table presents trade accounts receivable (net of allowance for uncollectible accounts) relating to both contracts with customers and other activities:


	June 30, 2023		December 31, 2022
Trade accounts receivable from contracts with customers — net	$	1,317	$	1,644
Other trade accounts receivable — net	364		415
Total trade accounts receivable — net	$	1,681	$	2,059

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6. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

Goodwill

As of both June 30, 2023 and December 31, 2022, the carrying value of goodwill totaled $2.583 billion, including $2.461 billion allocated to our Retail reporting unit and $122 million allocated to our Texas Generation reporting unit. Goodwill of $1.944 billion is deductible for tax purposes over 15 years on a straight line basis.

Identifiable Intangible Assets and Liabilities

Identifiable intangible assets are comprised of the following:


	June 30, 2023						December 31, 2022
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationships	$	2,088	$	1,817	$	271	$	2,088	$	1,768	$	320
Software and other technology-related assets	507		286		221		475		258		217
Retail and wholesale contracts	233		215		18		233		209		24
LTSA	18		5		13		18		4		14
Other identifiable intangible assets (a)	59		11		48		50		8		42
Total identifiable intangible assets subject to amortization	$	2,905	$	2,334	571		$	2,864	$	2,247	617
Retail trade names (not subject to amortization)					1,341						1,341

Total identifiable intangible assets					$	1,912					$	1,958

____________

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

Identifiable intangible liabilities are comprised of the following:


Identifiable Intangible Liability	June 30, 2023		December 31, 2022
LTSA	$	123	$	128
Fuel and transportation purchase contracts	9		9
Other identifiable intangible liabilities	1		3
Total identifiable intangible liabilities	$	133	$	140

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Expense related to finite-lived identifiable intangible assets (including the classification in the condensed consolidated statements of operations) consisted of:


Identifiable Intangible Assets	Condensed Consolidated Statements of Operations	Three Months Ended June 30,				Six Months Ended June 30,
		2023		2022		2023		2022
Retail customer relationships	Depreciation and amortization	$	21	$	34	$	49	$	68
Software and other technology-related assets	Depreciation and amortization	15		18		29		36
Retail and wholesale contracts	Operating revenues/fuel, purchased power costs and delivery fees	2		3		4		5
Other identifiable intangible assets	Fuel, purchased power costs and delivery fees	76		98		162		186
Total identifiable intangible assets expense (a)		$	114	$	153	$	244	$	295

___________

(a)Amounts recorded in depreciation and amortization totaled $37 million and $53 million for the three months ended June 30, 2023 and 2022, respectively, and $80 million and $105 million for the six months ended June 30, 2023 and 2022, respectively. Amounts exclude LTSA. Amounts include all expenses associated with environmental allowances including expenses accrued to comply with emissions allowance programs and renewable portfolio standards which are presented in fuel, purchased power costs and delivery fees on our condensed consolidated statements of operations. Emissions allowance obligations are accrued as associated electricity is generated and renewable energy certificate obligations are accrued as retail electricity delivery occurs.

Estimated Amortization of Identifiable Intangible Assets

As of June 30, 2023, the estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as shown below.


Year	Estimated Amortization Expense
2023	$	160
2024	$	111
2025	$	83
2026	$	59
2027	$	36

7. INCOME TAXES

Income Tax Expense

Vistra files a U.S. federal income tax return that includes the results of its consolidated subsidiaries. Vistra is 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.

The calculation of our effective tax rate is as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
Net income (loss) before income taxes	$	599		$	(1,764)		$	1,475		$	(2,139)
Income tax (expense) benefit	$	(123)		$	407		$	(301)		$	498
Effective tax rate	20.5		%	23.1		%	20.4		%	23.3		%

For the three months ended June 30, 2023, the effective tax rate of 20.5% was lower than the U.S. federal statutory rate of 21% due primarily to the release of uncertain tax positions related to the 2018 and 2019 IRS audit closed in the second quarter of 2023 and state income taxes. For the six months ended June 30, 2023, the effective tax rate of 20.4% was lower than the U.S. federal statutory rate of 21% due primarily to the release of uncertain tax positions related to the 2018 and 2019 IRS audit closed in Q2 2023 and state income taxes.

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For the three months ended June 30, 2022, the effective tax rate of 23.1% was higher than the U.S. federal statutory rate of 21% due primarily to expenses such as the nondeductible impacts of the TRA and state income taxes. For the six months ended June 30, 2022, the effective tax rate of 23.3% was higher than the U.S. federal statutory rate of 21% due primarily to expenses such as the nondeductible impacts of the TRA and state income taxes.

Inflation Reduction Act of 2022 (IRA)

In August 2022, the U.S. enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, including a nuclear PTC, a solar PTC, a first-time stand-alone battery storage investment tax credit, a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases. Treasury regulations are expected to define the scope of the legislation in many important respects over the next twelve months. The excise tax on stock repurchases is not expected to have a material impact on our financial statements. Vistra is not subject to the CAMT in the 2023 tax year since it applies only to corporations that have 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 for periods after the law takes effect and for estimating the TRA liability.

Liability for Uncertain Tax Positions

Vistra and its subsidiaries file income tax returns in U.S. federal, state and foreign jurisdictions and are, at times, subject to examinations by the IRS and other taxing authorities. In February 2021, Vistra was notified that the IRS had opened a federal income tax audit for tax years 2018 and 2019 and an employment tax audit for tax year 2018. The federal income tax audit was closed in June 2023 on an agreed basis with immaterial changes. Uncertain tax positions of $35 million were favorably resolved in the second quarter of 2023 upon final closing. Uncertain tax positions totaled zero and $36 million as of June 30, 2023 and December 31, 2022, respectively.

8. 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. 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 (a) 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), (b) the tax basis of all assets acquired in connection with the acquisition of two CCGT natural gas-fueled generation facilities in April 2016 and (c) 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.

Pursuant to the TRA, we issued the TRA Rights for the benefit of the first-lien secured creditors of TCEH entitled to receive such TRA Rights under the Plan of Reorganization. Such TRA Rights are entitled to certain registration rights more fully described in the Registration Rights Agreement (see Note 17).

The following table summarizes the changes to the TRA obligation, reported as other current liabilities and Tax Receivable Agreement obligation in our condensed consolidated balance sheets, for the six months ended June 30, 2023 and 2022:


	Six Months Ended June 30,
	2023		2022
TRA obligation at the beginning of the period	$	522	$	395
Accretion expense	41		32
Changes in tax assumptions impacting timing of payments (a)	38		83
Impacts of Tax Receivable Agreement	79		115

TRA obligation at the end of the period	601		510
Less amounts due currently	(10)		(1)
Noncurrent TRA obligation at the end of the period	$	591	$	509

____________

(a)During the three months ended June 30, 2023, we recorded a decrease to the carrying value of the TRA obligation totaling $7 million as a result of adjustments to forecasted taxable income due to decreases in longer-term commodity price forecasts and additional tax benefits from planned development projects, partially offset by state impacts of internal legal entity restructuring in preparation for the Energy Harbor acquisition. During the six months ended June 30, 2023, we

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recorded an increase to the carrying value of the TRA obligation totaling $38 million as a result of adjustments to forecasted taxable income due to increases in commodity price forecasts and impacts of the CAMT. During the three and six months ended June 30, 2022, we recorded increases to the carrying value of the TRA obligation totaling $17 million and $83 million, respectively, as a result of adjustments to forecasted taxable income due to increases in commodity price forecasts, partially offset by anticipated tax benefits under current laws for planned additional renewable development projects.

As of June 30, 2023, the estimated carrying value of the TRA obligation totaled $601 million, which represents the discounted amount of projected payments under the TRA. The projected payments are based on certain assumptions, including but not limited to (a) the federal corporate income tax rate of 21%, (b) estimates of our taxable income in the current and future years and (c) additional states that Vistra now operates in, including the relevant tax rate and apportionment factor for each state. Our taxable income takes into consideration the current federal tax code, various relevant state tax laws and reflects our current estimates of future results of the business. The estimates of future business results include assumptions related to renewable development projects that Vistra is planning to execute that generate significant tax benefits. These benefits have a material impact on the timing of TRA obligation payments. These assumptions are subject to change, and those changes could have a material impact on the carrying value of the TRA obligation. As of June 30, 2023, the aggregate amount of undiscounted federal and state payments under the TRA is estimated to be approximately $1.4 billion, with more than half of such amount expected to be paid during the next 15 years, and the final payment expected to be made around the year 2056 (if the TRA is not terminated earlier pursuant to its terms).

The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective interest method. Changes in the amount of this obligation resulting from changes to either the timing or amount of TRA payments are recognized in the period of change and measured using the discount rate inherent in the initial fair value of the obligation.

The TRA provides that, in the event that Vistra breaches any of its material obligations under the TRA, or upon certain mergers, asset sales, or other forms of business combination or certain other changes of control, the transfer agent under the TRA may treat such event as an early termination of the TRA, in which case Vistra would be required to make an immediate payment to the holders of the TRA Rights equal to the present value (at a discount rate equal to LIBOR plus 100 basis points) of the anticipated future tax benefits based on certain valuation assumptions.

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9. 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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Net income (loss) attributable to Vistra	$	476	$	(1,365)	$	1,175	$	(1,650)
Less cumulative dividends attributable to Series A Preferred Stock	(20)		(20)		(40)		(40)
Less cumulative dividends attributable to Series B Preferred Stock	(17)		(17)		(35)		(35)
Net income (loss) attributable to common stock — basic	439		(1,402)		1,100		(1,725)
Weighted average shares of common stock outstanding — basic	372,956,476		429,193,031		378,264,434		440,336,286
Net income (loss) per weighted average share of common stock outstanding — basic	$	1.18	$	(3.27)	$	2.91	$	(3.92)
Dilutive securities: Stock-based incentive compensation plan	3,837,782		—		4,152,031		—
Weighted average shares of common stock outstanding — diluted	376,794,258		429,193,031		382,416,465		440,336,286
Net income (loss) per weighted average share of common stock outstanding — diluted	$	1.17	$	(3.27)	$	2.88	$	(3.92)

Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 1,528,026 and 5,567,585 shares for the three months ended June 30, 2023 and 2022, respectively, and 1,589,125 and 8,052,517 shares for the six months ended June 30, 2023 and 2022, respectively.

10. ACCOUNTS RECEIVABLE FINANCING

Accounts Receivable Securitization Program

TXU Energy Receivables Company LLC (RecCo), an indirect subsidiary of Vistra, has an accounts receivable financing facility (Receivables Facility) provided by issuers of asset-backed commercial paper and commercial banks (Purchasers). The Receivables Facility was renewed in July 2023, extending the term of the Receivables Facility to July 2024 and adjusting the commitment of the purchasers to purchase interests in the receivables under the Receivables Facility during all periods to a fixed purchase limit of $750 million from seasonally adjusted commitment limits ranging from $600 million to $750 million.

In connection with the Receivables Facility, TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands 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 limits 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 obligations under the agreements governing the Receivables Facility. Amounts funded by the Purchasers to RecCo are reflected as short-term borrowings on the condensed consolidated balance sheets. Proceeds and repayments under the Receivables Facility are reflected as cash flows from financing activities in our condensed consolidated statements of cash flows. Receivables transferred to the Purchasers remain on Vistra's balance sheet and Vistra reflects a liability equal to the amount advanced by the Purchasers. The Company records interest expense on amounts advanced. TXU Energy continues to service, administer and collect the Receivables on behalf of RecCo and the Purchasers, as applicable.

As of June 30, 2023, there were no outstanding borrowings under the Receivables Facility. As of December 31, 2022, there were $425 million outstanding borrowings under the Receivables Facility and were supported by $1.013 billion of RecCo gross receivables.

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Repurchase Facility

TXU Energy and the other originators under the Receivables Facility have a repurchase facility (Repurchase Facility) that is provided on an uncommitted basis by a commercial bank as buyer (Buyer). In July 2023, the Repurchase Facility was renewed until July 2024 while maintaining the facility size of $125 million. The Repurchase Facility is collateralized by a subordinated note (Subordinated Note) issued by RecCo in favor of TXU Energy for the benefit of Originators under the Receivables Facility and representing a portion of the outstanding balance of the purchase price paid for the Receivables sold by the Originators to RecCo under the Receivables Facility. Under the Repurchase Facility, TXU Energy may request that Buyer transfer funds to TXU Energy in exchange for a transfer of the Subordinated Note, with a simultaneous agreement by TXU Energy to transfer funds to Buyer at a date certain or on demand in exchange for the return of the Subordinated Note (collectively, the Repo Transaction). Each Repo Transaction is expected to have a term of one month, unless terminated earlier on demand by TXU Energy or terminated by Buyer after an event of default.

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

There were no outstanding borrowings under the Repurchase Facility as of both June 30, 2023 and December 31, 2022.

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11. 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 will 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. Fees related to the Facility Agreement transaction totaled $7 million in the six months ended June 30, 2023, which were capitalized as other noncurrent assets.

Under the Facility Agreement, Vistra Operations will have 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 will pay 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 will generally be 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 June 30, 2023, $443 million is the fair value of Eligible Assets held by counterparties to satisfy margin deposit requirements and is reported in our consolidated balance sheets as margin deposits posted under affiliate financing agreement and margin deposit financing with affiliate.

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12. DEBT

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


	June 30, 2023		December 31, 2022
Vistra Operations Credit Facilities	$	2,500	$	2,514
Vistra Operations Senior Secured Notes:
4.875% Senior Secured Notes, due May 13, 2024	400		400
3.550% Senior Secured Notes, due July 15, 2024	1,500		1,500
5.125% Senior Secured Notes, due May 13, 2025	1,100		1,100
3.700% Senior Secured Notes, due January 30, 2027	800		800
4.300% Senior Secured Notes, due July 15, 2029	800		800
Total Vistra Operations Senior Secured Notes	4,600		4,600
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
Total Vistra Operations Senior Unsecured Notes	4,850		4,850





Other:

Equipment Financing Agreements	79		79


Total other long-term debt	79		79
Unamortized debt premiums, discounts and issuance costs	(62)		(72)
Total long-term debt including amounts due currently	11,967		11,971
Less amounts due currently	(437)		(38)
Total long-term debt less amounts due currently	$	11,530	$	11,933

As of June 30, 2023 and December 31, 2022, outstanding short-term borrowings under the Commodity-Linked Facility and the Revolving Credit Facility (described below) totaled zero and $650 million, respectively.

Vistra Operations Credit Facilities and Commodity-Linked Revolving Credit Facility

Vistra Operations Credit Facilities — As of June 30, 2023, the Vistra Operations Credit Facilities consisted of up to $5.675 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) and term loans of $2.5 billion (Term Loan B-3 Facility).

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On April 29, 2022 (April 2022 Amendment Effective Date) and July 18, 2022 (July 2022 Amendment Effective Date), Vistra Operations entered into amendments (Credit Agreement Amendments) to the Vistra Operations Credit Agreement, among Vistra Operations, as borrower, Vistra Intermediate, the guarantors party thereto, Credit Suisse AG, Cayman Island Branch, as administrative agent and collateral agent, and the other parties named therein. Pursuant to the Credit Agreement Amendments, new classes of extended revolving credit commitments maturing in April 2027 were established in aggregate amounts of $2.8 billion and $725 million as of the April 2022 Amendment Effective Date and the July 2022 Amendment Effective Date, respectively. The July 18, 2022 amendment to the Vistra Operations Credit Agreement also provided that Vistra Operations would terminate at least $350 million in Extended Revolving Credit Facility (as defined below) commitments by December 30, 2022 or earlier if Vistra Operations or any guarantor receives proceeds from any capital markets transaction whose primary purpose is designed to enhance the liquidity of Vistra Operations and its guarantors. In accordance with this requirement, effective December 30, 2022, Vistra Operations terminated $350 million in revolving commitments. After giving effect to the Credit Agreement Amendments and the revolving commitment reduction, the aggregate amount of revolving commitments maturing on April 29, 2027 equals $3.175 billion (Extended Revolving Credit Facility), while the $200 million in revolving commitments that matured on June 14, 2023 (Non-Extended Revolving Credit Facility) remained unchanged by the Credit Agreement Amendments. Furthermore, the Credit Agreement Amendments appointed new revolving letter of credit issuers, such that the aggregate amount of revolving letter of credit commitments equals $3.105 billion after giving effect to the Credit Agreement Amendments and the maturity of the Non-Extended Credit Facility on June 14, 2023 in accordance with the terms of the Vistra Operations Credit Agreement.

On April 28, 2023, Vistra Operations entered into an amendment (April 2023 Amendment) to the Vistra Operations Credit Agreement, among Vistra Operations, as borrower, Vistra Intermediate, the guarantors party thereto, Credit Suisse AG, Cayman Island Branch, as administrative agent, and the other parties named therein. Pursuant to the April 2023 Amendment, and in light of a public statement by the supervisor for the administrator of the "LIBOR Rate" identifying June 30, 2023 as the date after which the "LIBOR Rate" will permanently or indefinitely ceased to be published, the "LIBOR Rate" shall, with respect to the term loans under the Vistra Operations Credit Agreement, cease to be applicable after June 30, 2023 and was replaced by the Adjusted Term SOFR Rate, other than as expressly contemplated by the April 2023 Amendment. The Adjusted Term SOFR Rate is the interest rate per annum equal to SOFR plus (a) with respect to an interest period of one month, 0.11% per annum, (b) with respect to an interest period of three months, 0.26% per annum and (c) with respect to an interest period of six months, 0.43% per annum.

Our credit facilities and related available capacity as of June 30, 2023 are presented below.


		June 30, 2023
Credit Facilities	Maturity Date	Facility Limit		Cash Borrowings		Letters of Credit Outstanding		Available Capacity
Extended Revolving Credit Facility (a)	April 29, 2027	$	3,175	$	—	$	1,672	$	1,503


Term Loan B-3 Facility (b)	December 31, 2025	2,500		2,500		—		—
Total Vistra Operations Credit Facilities		$	5,675	$	2,500	$	1,672	$	1,503
Commodity-Linked Facility (c)	October 4, 2023	$	1,350	$	—	$	—	$	326
Total Credit Facilities		$	7,025	$	2,500	$	1,672	$	1,829

___________

(a)Extended Revolving Credit Facility used for general corporate purposes. Cash borrowings under the Extended Revolving Credit Facility are reported in short-term borrowings in our condensed consolidated balance sheets. The full amount of Extended Revolving Credit Facility available capacity can be utilized to issue letters of credit.

(b)Cash borrowings under the Term Loan B-3 Facility are subject to a required scheduled quarterly payment in annual amount equal to 1.00% of the original principal amount with the balance paid at maturity. Amounts paid cannot be reborrowed.

(c)Commodity-Linked Facility (defined below) is used to support our comprehensive hedging strategy. As of June 30, 2023, the borrowing base of $326 million is lower than the facility limit which represents the aggregate commitments of $1.35 billion. The reduction in the borrowing base is due, in part, to the expiration of certain deemed 2023 hedges and would increase in size in a rising commodity price environment in accordance with the terms of the Commodity-Linked Facility. See Commodity-Linked Revolving Credit Facility below for discussion of the borrowing base calculation. Cash borrowings under the Commodity-Linked Facility are reported in short-term borrowings in our condensed consolidated balance sheets.

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Under the Vistra Operations Credit Agreement, the interest applicable to the Extended Revolving Credit Facility is based on SOFR plus a spread that will range from 1.25% to 2.00%, based on the ratings of Vistra Operations' senior secured long-term debt securities, and the fee on any undrawn amounts with respect to the Extended Revolving Credit Facility will range from 17.5 basis points to 35.0 basis points, based on ratings of Vistra Operations' senior secured long-term debt securities. As of June 30, 2023, the applicable interest rate margins for the Extended Revolving Credit Facility and the fee for undrawn amounts relating to such extended commitments were lowered to 1.70% and 26.5 basis points, respectively, related to a sustainability pricing adjustment based on certain sustainability-linked targets and thresholds. As of June 30, 2023, there were no outstanding borrowings under the Extended Revolving Credit Facility. Letters of credit issued under the Extended Revolving Credit Facility bear interest within a spread of 1.25% to 2.00% (based on the ratings of Vistra Operations' senior secured long-term debt securities), which as of June 30, 2023 was reduced to 1.70% as a result of a sustainability pricing adjustment. 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 Non-Extended Revolving Credit Facility matured on June 14, 2023. Under the Vistra Operations Credit Agreement, cash borrowings under the Non-Extended Revolving Credit Facility bore interest based on applicable LIBOR rates, plus a fixed spread of 1.75%. Letters of credit issued under the Non-Extended Revolving Credit Facility bore interest at 1.75%.

Effective July 17, 2023, amounts borrowed under the Term Loan B-3 Facility will bear interest based on applicable Adjusted Term SOFR Rates plus a fixed spread of 1.75%. As of June 30, 2023, the borrowings bear interest on applicable LIBOR rates, plus a spread of 1.75%, and the weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings was 6.93% under the Term Loan B-3 Facility.

Obligations under the Vistra Operations Credit Facilities are secured by a lien covering substantially all of Vistra Operations' (and its subsidiaries') consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra Operations Credit Facilities. The Vistra Operations Credit Agreement includes certain collateral suspension provisions that would take effect upon Vistra Operations achieving unsecured investment grade ratings from two ratings agencies, there being no Term Loans (under and as defined in the Vistra Operations Credit Agreement) then outstanding (or the holders thereof agreeing to release such security interests), and there being no outstanding revolving credit commitments the maturities of which have not been extended to April 29, 2027 (or the holders thereof agreeing to release such security interests), such collateral suspension provisions would continue to be in effect unless and until Vistra Operations no longer holds unsecured investment grade ratings from at least two ratings agencies, at which point collateral reversion provisions would take effect (subject to a 60-day grace period).

The Vistra Operations Credit Facilities also permit certain hedging agreements and cash management agreements to be secured on a pari-passu basis with the Vistra Operations Credit Facilities in the event those hedging agreements and cash management agreements met certain criteria set forth in the Vistra Operations Credit Facilities.

The Vistra Operations Credit Facilities provide for affirmative and negative covenants applicable to Vistra Operations (and its restricted subsidiaries), including affirmative covenants requiring it to provide financial and other information to the agents under the Vistra Operations Credit Facilities and to not change its lines of business, and negative covenants restricting Vistra Operations' (and its restricted subsidiaries') ability to incur additional indebtedness, make investments, dispose of assets, pay dividends, grant liens or take certain other actions, in each case, except as permitted in the Vistra Operations Credit Facilities. Vistra Operations' ability to borrow under the Vistra Operations Credit Facilities is subject to the satisfaction of certain customary conditions precedent set forth therein.

The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties, material breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against Vistra Operations. Solely with respect to the Revolving Credit Facility, and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $300 million) exceed 30% of the revolving commitments), the agreement includes a covenant that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first lien debt compared to an EBITDA calculation defined under the terms of the Vistra Operations Credit Facilities, not to exceed 4.25 to 1.00 (or, during a collateral suspension period, not to exceed 5.50 to 1.00). As of June 30, 2023, we were in compliance with this financial covenant. 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.

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Commodity-Linked Revolving Credit Facility — In order to support our comprehensive hedging strategy, in February 2022, Vistra Operations entered into a $1.0 billion senior secured commodity-linked revolving credit facility (Commodity-Linked Facility) by and among Vistra Operations, Vistra Intermediate, the lenders, joint lead arrangers and joint bookrunners party thereto, and Citibank, N.A., as administrative agent and collateral agent. In May 2022, we entered into an amendment to the Commodity-Linked Facility to increase the aggregate available commitments from $1.0 billion to $2.0 billion and to provide the flexibility, subject to our ability to obtain additional commitments, to further increase the size of the Commodity-Linked Facility by an additional $1.0 billion to a facility size of $3.0 billion. Subsequent amendments in May 2022 and June 2022 increased the aggregate available commitments from $2.0 billion to $2.25 billion. In October 2022, Vistra initiated amendments to the Commodity-Linked Facility to, among other things, (i) extend the maturity date to October 4, 2023 and (ii) reduce the aggregate available commitments to $1.35 billion.

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

Under the Vistra Operations Commodity-Linked Credit Agreement, the interest applicable to the Commodity-Linked Facility is based on SOFR plus a spread that will range from 1.25% to 2.00%, based on the ratings of Vistra Operations' senior secured long-term debt securities, and 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, based on ratings of Vistra Operations' senior secured long-term debt securities. As of June 30, 2023, 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 lowered to 1.70% and 26.5 basis points, respectively, related to a sustainability pricing adjustment based on certain sustainability-linked targets and thresholds. As of June 30, 2023, there were no outstanding borrowings under the Commodity-Linked Facility.

The Vistra Operations Commodity-Linked Credit Agreement includes a covenant, solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings exceeds 30% of the revolving commitments), that requires the consolidated first-lien net leverage ratio, which is based on the ratio of net first lien debt compared to an EBITDA calculation defined under the terms of the Commodity-Linked Facility, not to exceed 4.25 to 1.00 (or, during a collateral suspension period, not to exceed 5.50 to 1.00). Although the period ended June 30, 2023 was not a compliance period, we would have been in compliance with this financial covenant if it was required to be tested at such time.

Interest Rate Swaps — Vistra employs interest rate swaps to hedge our exposure to variable rate debt. As of June 30, 2023, Vistra has entered into the following series of interest rate swap transactions. The rate ranges in the table below reflect the fixed leg of each swap plus an interest margin of 1.75%. The February 2024 and July 2026 swaps were amended in the second quarter of 2023 to reflect the conversion of LIBOR to SOFR.


	Notional Amount	Expiration Date	Rate Range
Swapped to fixed	$3,000	July 2023	3.67	%	-	3.91%
Swapped to variable	$700	July 2023	3.20	%	-	3.23%
Swapped to fixed	$720	February 2024	3.61	%	-	3.72%
Swapped to variable	$720	February 2024	3.20	%	-	3.72%
Swapped to fixed (a)	$3,000	July 2026	4.64	%	-	4.72%
Swapped to variable (a)	$700	July 2026	3.19	%	-	3.24%
Swapped to fixed (b)	$750	December 2030	4.91	%	-	4.92%

____________

(a)Effective from July 2023 through July 2026.

(b)Effective from December 2023 through December 2030. See Note 2.

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During 2019, Vistra entered into $2.12 billion of new interest rate swaps, pursuant to which Vistra will pay a variable rate and receive a fixed rate. The terms of these new swaps were matched against the terms of certain existing swaps, effectively offsetting the hedge of the existing swaps and fixing the out-of-the-money position of such swaps. These matched swaps will settle over time, in accordance with the original contractual terms. Swaps expiring in July 2023 and July 2026 continue to hedge our exposure on $2.30 billion of debt through July 2026. The $750 million of swaps expiring in December 2030 hedge our exposure on a portion of the floating rate component of the expected interest cost associated with the anticipated Transactions debt financings.

Secured Letter of Credit Facilities

In August and September 2020, Vistra entered into uncommitted standby letter of credit facilities that are each secured by a first lien on substantially all of Vistra Operations' (and its subsidiaries') assets (which ranks pari passu with the Vistra Operations Credit Facilities) (each, a Secured LOC Facility and collectively, the Secured LOC Facilities). The Secured LOC Facilities are used for general corporate purposes. In October 2021, September 2022 and October 2022, Vistra entered into additional Secured LOC Facilities which are used for general corporate purposes. As of June 30, 2023, $769 million of letters of credit were outstanding under the Secured LOC Facilities.

Each of the Secured LOC Facilities includes a covenant that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, for certain facilities that include a collateral suspension mechanism, during a collateral suspension period, not to exceed 5.50 to 1.00). As of June 30, 2023, we were in compliance with these financial covenants.

Vistra Operations Senior Secured Notes

In May 2022, Vistra Operations issued $1.5 billion aggregate principal amount of senior secured notes (2022 Senior Secured Notes), consisting of $400 million aggregate principal amount of 4.875% senior secured notes due 2024 (4.875% Senior Secured Notes) and $1.1 billion aggregate principal amount of 5.125% senior secured notes due 2025 (5.125% Senior Secured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act (Senior Secured Notes Offering). The 2022 Senior Secured Notes were sold pursuant to a purchase agreement by and among Vistra Operations, certain direct and indirect subsidiaries of Vistra Operations and Citigroup Global Markets Inc., as representative of the several initial purchasers. The 4.875% Senior Secured Notes mature in May 2024 and the 5.125% Senior Secured Notes mature in May 2025. Interest on the 2022 Senior Secured Notes is payable in cash semiannually in arrears on May 13 and November 13 of each year, beginning in November 2022. Net proceeds from the Senior Secured Notes Offering totaling $1.485 billion, together with cash on hand, were used to pay down borrowings under the Commodity-Linked Facility.

Since 2019, Vistra Operations issued and sold $4.6 billion aggregate principal amount of senior secured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act. The indenture (as may be amended or supplemented from time to time, the Vistra Operations Senior Secured Indenture) governing the 3.550% senior secured notes due 2024, the 3.700% senior secured notes due 2027, the 4.300% senior secured notes due 2029 and the 2022 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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Vistra Operations Senior Unsecured Notes

Since 2018, Vistra Operations has issued and sold $4.85 billion aggregate principal amount of senior unsecured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act. The indentures 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 and the 4.375% senior unsecured notes due 2029 (collectively, as each may be amended or supplemented from time to time, the Vistra Operations Senior Unsecured Indentures) provide for the full and unconditional guarantee by the Guarantor Subsidiaries of the punctual payment of the principal and interest on such notes. The Vistra Operations Senior Unsecured Indentures contain certain covenants and restrictions, including, among others, restrictions on the ability of Vistra Operations and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets.

Debt Repurchase Program

In March 2021, the Board authorized up to $1.8 billion to voluntarily repay or repurchase outstanding debt, which authorization expired in March 2022 (the Prior Authorization). No amounts were repurchased under the Prior Authorization. In October 2022, the Board re-authorized the voluntary repayment or repurchase of up to $1.8 billion of outstanding debt, with such authorization expiring on December 31, 2023 (Current Authorization). As of June 30, 2023, no amounts were repurchased under the Current Authorization.

Other Long-Term Debt

Forward Capacity Agreements — In March 2021, the Company sold a portion of the PJM capacity that cleared for Planning Years 2021-2022 to a financial institution (2021-2022 Forward Capacity Agreement). The buyer in this transaction received capacity payments from PJM during the Planning Years 2021-2022 in the amount of approximately $515 million. In May 2022, the final capacity payment from PJM during the Planning Years 2021-2022 was paid, and the terms of the 2021-2022 Forward Capacity were fulfilled.

Maturities

Long-term debt maturities as of June 30, 2023 are as follows:


	June 30, 2023
Remainder of 2023	$	26
2024	1,940
2025	3,567
2026	1,006
2027	3,402
Thereafter	2,088
Unamortized premiums, discounts and debt issuance costs	(62)
Total long-term debt, including amounts due currently	$	11,967

13. COMMITMENTS AND CONTINGENCIES

Guarantees

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

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Letters of Credit

As of June 30, 2023, we had outstanding letters of credit totaling $2.441 billion as follows:

•$2.136 billion to support commodity risk management collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and collateral postings with ISOs/RTOs;

•$143 million to support battery and solar development projects;

•$27 million to support executory contracts and insurance agreements;

•$89 million to support our REP financial requirements with the PUCT, and

•$46 million for other credit support requirements.

Surety Bonds

As of June 30, 2023, we had outstanding surety bonds totaling $933 million to support performance under various contracts and legal obligations in the normal course of business.

Litigation and Regulatory Proceedings

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

Litigation

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

Illinois Attorney General Complaint Against Illinois Gas & Electric (IG&E) — In May 2022, the Illinois Attorney General filed a complaint against IG&E, a subsidiary we acquired when we purchased Crius in July 2019. The complaint filed in Illinois state court alleges, among other things, that IG&E engaged in improper marketing conduct and overcharged customers. The vast majority of the conduct in question occurred prior to our acquisition of IG&E. In July 2022, we moved to dismiss the complaint, and in October 2022, the district court granted in part our motion to dismiss, barring all claims asserted by the Illinois Attorney General that were outside of the 5-year statute of limitations period, which now limits the period during which claims may be made to start in May 2017 rather than extending back to 2013 as the Illinois Attorney General had alleged in its complaint.

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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 addition, we have also submitted settlement disputes with ERCOT over power prices and other issues during Winter Storm Uri. Following an appeal of the PUCT's March 5, 2021 verbal order and other statements made by the PUCT, the Texas Attorney General, on behalf of the PUCT, its client, represented in a letter agreement filed with the Third Court of Appeals that we and other parties may continue disputing the pricing during Winter Storm Uri through the ERCOT process and, to the extent the outcome of that process comes before the PUCT for review, the PUCT has not prejudged or made a final decision on that matter. We are not able to reasonably estimate the financial statement impact of a repricing as, among other things, the matter is subject to ongoing legal proceedings and, even if we were ultimately successful in the current legal proceeding, the price at which the market would be resettled is not reasonably estimable because that would be subject to further proceedings at ERCOT and the PUCT.

Brazos Electric Cooperative Inc. (Brazos) Bankruptcy — As a result of the lengthy period of peak pricing administratively imposed by the PUCT during Winter Storm Uri, certain market participants within ERCOT were not able to pay their full obligations to ERCOT. Consequently, ERCOT was "short-paid" approximately $2.9 billion, the majority of which was related to Brazos, a Texas-based non-profit electric cooperative corporation that provides wholesale electricity to its members, which, in turn, provide retail electricity to Texas consumers. After applying standard ERCOT market default protocols for the recovery of losses through issuance of default liability to all market participants, we recognized an approximately $189 million default uplift liability in the first quarter of 2021 based on our market share. The $189 million default uplift liability was subsequently reduced to $124 million as ERCOT collected amounts owed from certain defaulting entities through other means, primarily through securitization. In March 2021, Brazos commenced a Chapter 11 bankruptcy case in the U.S. Bankruptcy Court for the Southern District of Texas. As part of the Brazos bankruptcy proceeding, ERCOT filed a claim to recover approximately $1.9 billion from Brazos.

In September 2022, Brazos and ERCOT reached a settlement that provided for material payments to ERCOT for its prior "short-paid" amounts and, importantly, precluded ERCOT from collecting default uplift from market participants for any prepetition amounts owed by Brazos (i.e., it supplants the process to uplift the short-pay claim to market participants), which allowed Vistra to extinguish the remaining $124 million default uplift liability to ERCOT on account of the Brazos short pay. In December 2022, the Brazos plan of reorganization became effective. Accordingly, the $124 million default uplift liability to ERCOT, which was entirely attributable to the Brazos default, was derecognized in the fourth quarter of 2022 and recognized as revenue in the statement of operations.

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 a 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 Houston Court of Appeals to review the MDL court's denial of the motion to dismiss. 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 July 2019, the EPA finalized a rule that repealed the Clean Power Plan (CPP) that had been finalized in 2015 and established new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the Affordable Clean Energy (ACE) rule. The ACE rule developed emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generating units. In response to challenges brought by environmental groups and certain states, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the ACE rule, including the repeal of the CPP, in January 2021 and remanded the rule to the EPA for further action. In June 2022, the U.S. Supreme Court issued an opinion reversing the D.C. Circuit Court's decision, and finding that the EPA exceeded its authority under Section 111 of the Clean Air Act when the EPA set emission requirements in the CPP based on generation shifting. In October 2022, the D.C. Circuit Court issued an amended judgment, denying petitions for review of the ACE rule and challenges to the repeal of the CPP. In addition, the EPA opened a docket seeking input on questions related to the regulation of GHGs under Section 111(d) which closed in March 2023. In May 2023, the EPA released a new proposal regulating power plant GHG emissions, while also proposing to repeal the ACE rule. The new GHG proposal sets limits for (a) new gas-fired combustion turbines, (b) existing coal-, oil- and gas-fired steam generating units, and (c) certain existing gas-fired combustion turbines. The proposed standards are based on technologies such as carbon capture and sequestration/storage (CCS), low-GHG hydrogen co-firing, and natural gas co-firing. Starting in 2030, the proposal would generally require more CO2 emissions control at fossil fuel-fired power plants that operate more frequently and for more years and would phase in increasingly stringent CO2 requirements over time. Under the proposal, states would be required to submit plans to the EPA within 24 months of the rule's effective date 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. Existing steam generating units must start complying with their standards of performance on January 1, 2030. Existing combustion turbine units must start complying with their standards of performance on January 1, 2032, or January 1, 2035, depending on their subcategory. We submitted comments to the EPA on this proposal in August 2023.

Cross-State Air Pollution Rule (CSAPR)

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

In April 2022, prior to the EPA's disapproval of Texas' SIP, the EPA proposed a Federal Implementation Plan (FIP) to address the 2015 ozone NAAQS. We, along with many other companies, trade groups, states and ISOs, including ERCOT, PJM and MISO, filed responsive comments to the EPA's proposal in June 2022, expressing concerns about certain elements of the proposal, particularly those that may result in challenges to electric reliability under certain conditions. In March 2023, the EPA administrator signed its final FIP. The FIP applies to 22 states beginning with the 2023 ozone seasons. States where Vistra operates generation units that would be subject to this rule are Illinois, New Jersey, New York, Ohio, Pennsylvania, Texas, Virginia and West Virginia. Texas would be moved into the revised 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 FIP as to Texas sources pending the resolution of the merits, meaning that Texas will remain in Group 2 and not be subject to any requirements under the FIP at least until the Fifth Circuit Court rules on the merits. In June 2023, the EPA published the final FIP in the Federal Register, which included requirements as to Texas despite the stay of the SIP disapproval by the Fifth Circuit Court. In June 2023, the State of Texas, Luminant and various other parties also filed challenges to the FIP in the Fifth Circuit Court, filed a motion to stay the FIP and confirm venue for this dispute in the Fifth Circuit Court. After the motion to stay and to confirm venue was filed, the EPA signed an interim final rule on June 29, 2023 that confirms the FIP as to Texas is stayed. In July 2023, the Fifth Circuit Court ruled that the FIP challenge would be held in abeyance pending the resolution of the litigation on the SIP disapproval and denied the motion to stay as not needed given the EPA's administrative stay.

Regional Haze — Reasonable Progress and Best Available Retrofit Technology (BART) for Texas

In October 2017, the EPA issued a final rule addressing BART for Texas electricity generation units, with the rule serving as a partial approval of Texas' 2009 SIP and a partial FIP. For SO2, the rule established an intrastate Texas emission allowance trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program. The program includes 39 generating 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.

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 February 2023, the Sierra Club filed suit against the EPA in the Northern District of California to compel them to issue a FIP for Texas. The Sierra Club and the EPA now have a proposed consent decree, which would require the EPA to take final action promulgating a FIP for the nonattainment area by December 13, 2024, unless the EPA approves a SIP by that deadline.

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Effluent Limitation Guidelines (ELGs)

In November 2015, the EPA revised the ELGs for steam electricity generation facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, such as flue gas desulfurization (FGD), fly ash, bottom ash and flue gas mercury control wastewaters. Various parties filed petitions for review of the ELG rule, and the petitions were consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions requesting reconsideration of the ELG rule and administratively stayed the rule's compliance date deadlines. In April 2019, the Fifth Circuit Court vacated and remanded portions of the EPA's ELG rule pertaining to effluent limitations for legacy wastewater and leachate. The EPA published a final rule in October 2020 that extends the compliance date for both FGD and bottom ash transport water to no later than December 2025, as negotiated with the state permitting agency. Additionally, the final rule allows for a retirement exemption that exempts facilities certifying that units will retire by December 2028 provided certain effluent limitations are met. In November 2020, environmental groups petitioned for review of the new ELG revisions, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020. Notifications were made to Texas, Illinois and Ohio state agencies on the retirement exemption for applicable coal plants by the regulatory deadline of October 13, 2021. In March 2023, the EPA published its proposed supplemental ELG rule, which retains the retirement exemption from the 2020 ELG rule and sets new limits for plants that are continuing to operate. The proposed rule also establishes pretreatment standards for combustion residual leachate, and we are currently evaluating the impact of those proposed requirements. We submitted comments on the proposal in May 2023.

Coal Combustion Residuals (CCR)/Groundwater

In August 2018, the D.C. Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR rule, including an applicability exemption for legacy impoundments. In August 2020, the EPA issued a final rule establishing a deadline of April 11, 2021 to cease receipt of waste and initiate closure at unlined CCR impoundments. The final rule allows a generation plant to seek the EPA's approval to extend this deadline if no alternative disposal capacity is available and either a conversion to comply with the CCR rule is underway or retirement will occur by either 2023 or 2028 (depending on the size of the impoundment at issue). Prior to the November 2020 deadline, we submitted applications to the EPA requesting compliance extensions under both conversion and retirement scenarios. In November 2020, environmental groups petitioned for review of this rule in the D.C. Circuit Court, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020. Also, in November 2020, the EPA finalized a rule that would allow an alternative liner demonstration for certain qualifying facilities. In November 2020, we submitted an application for an alternate liner demonstration for one CCR unit at Martin Lake. In August 2021, we submitted a request to transfer our conversion application for the Zimmer facility to a retirement application following the announcement that Zimmer will close by May 31, 2022. In January 2022, the EPA determined that our conversion and retirement applications for our CCR facilities were complete but has not yet proposed action on any of those applications. In addition, in January 2022, the EPA also made a series of public statements, including in a press release, that purported to impose new, more onerous closure requirements for CCR units. The EPA issued these new purported requirements without prior notice and without following the legal requirements for adopting new rules. These new purported requirements announced by the EPA are contrary to existing regulations and the EPA's prior positions. In April 2022, we, along with the Utility Solid Waste Activities Group (USWAG), a trade association of over 130 utility operating companies, energy companies, and certain other industry associations, filed petitions for review with the D.C. Circuit Court and have asked the court to determine that the EPA cannot implement or enforce the new purported requirements because the EPA has not followed the required procedures. The State of Texas and the TCEQ have intervened in support of the petitions filed by the Vistra subsidiaries and USWAG, and various environmental groups have intervened on behalf of the EPA. The parties are awaiting a briefing schedule from the D.C. Circuit Court.

In May 2023, the EPA issued another proposal that further revises the federal CCR rule that would expand coverage of groundwater monitoring and closure requirements to the following two new categories of units: (a) legacy units which are CCR impoundments at inactive sites that ceased receiving waste before October 19, 2015 and (b) so-called "CCR management units" which generally could encompass areas of CCR located at a facility that is currently regulated by the existing CCR rule. CCR Management Units, as defined by the EPA in the proposal, could include any ash deposits, haul roads, and previously closed impoundments and landfills. As part of the proposed rule, the EPA identified 134 CCR management units at 82 different facilities across the country, including six 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 this proposal, if finalized, will have any impact on that site. We are continuing to evaluate what would be required of the CCR management units identified in the proposal should the proposal become final in its current form. We submitted comments in July 2023.

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MISO — In 2012, the Illinois Environmental Protection Agency (IEPA) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities' CCR surface impoundments. These violation notices remain unresolved; however, in 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east, and west fly ash CCR surface impoundments. We have completed closure activities at those ponds at our Baldwin facility.

At our retired Vermilion facility, which was not potentially subject to the EPA's 2015 CCR rule until the aforementioned D.C. Circuit Court decision in August 2018, we submitted proposed corrective action plans involving closure of two CCR surface impoundments (i.e., the old east and the north impoundments) to the IEPA in 2012, and we submitted revised plans in 2014. In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options. In May 2018, Prairie Rivers Network (PRN) filed a citizen suit in federal court in Illinois against Dynegy Midwest Generation, LLC (DMG), alleging violations of the Clean Water Act for alleged unauthorized discharges. In August 2018, we filed a motion to dismiss the lawsuit. In November 2018, the district court granted our motion to dismiss and judgment was entered in our favor. In June 2021, the Seventh Circuit Court affirmed the district court's dismissal of the lawsuit. In April 2019, PRN also filed a complaint against DMG before the IPCB, alleging that groundwater flows allegedly associated with the ash impoundments at the Vermilion site have resulted in exceedances both of surface water standards and Illinois groundwater standards dating back to 1992. We answered that complaint in July 2021. In July 2023, PRN filed an unopposed motion to voluntarily dismiss the case with prejudice, which the IPCB granted in August 2023 and closed the case.

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 June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface impoundments at our retired Vermilion facility, which is owned by our subsidiary DMG, and that notice was referred to the Illinois Attorney General. In June 2021, the Illinois Attorney General and the Vermilion County State Attorney filed a complaint in Illinois state court with an agreed interim consent order which the court subsequently entered. Given the violation notices and the enforcement action, the unique characteristics of the site, and the proximity of the site to the only national scenic river in Illinois, we agreed to enter into the interim consent order to resolve this matter. Per the terms of the agreed interim consent order, DMG is required to evaluate the closure alternatives under the requirements of the newly implemented Illinois Coal Ash regulation (discussed below) and close the site by removal. In addition, the interim consent order requires that during the impoundment closure process, impacted groundwater will be collected before it leaves the site or enters the nearby Vermilion river and, if necessary, DMG will be required to install temporary riverbank protection if the river migrates within a certain distance of the impoundments. The interim order was modified in December 2022 to require certain amendments to the Safety Emergency Response Plan. In June 2023, the Illinois state court approved and entered the final consent order, which included the terms above and a requirement that when IEPA issues a final closure permit for the site, DMG will demolish the power station and submit for approval to construct an on-site landfill within the footprint of the former plant to store and manage the coal ash. These proposed closure costs are reflected in the ARO in our condensed consolidated balance sheets (see Note 19).

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 filed an appeal in the Illinois Fourth Judicial District over certain provisions of the final rule and that case remains pending. Other parties have also filed appeals of certain provisions of the final rule. 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 will be filed for our Baldwin facility in 2023.

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For all of the above matters, if certain corrective action measures, including groundwater treatment or removal of ash, are required at any of our coal-fueled facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows. The Illinois coal ash rule was finalized in April 2021 and does not require removal. However, the rule required us to undertake further site specific evaluations required by each program. We will not know the full range of decommissioning costs, including groundwater remediation, if any, that ultimately may be required under the Illinois rule until permit applications have been approved by the IEPA. However, 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 believe are appropriate based on existing closure requirements and protective of the environment for each location. Once the IEPA acts on our permit applications, we will reassess the decommissioning costs and adjust our ARO liabilities accordingly.

MISO 2015-2016 Planning Resource Auction

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

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

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

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

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Other Matters

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

14. EQUITY

Share Repurchase Programs

In October 2021, we announced that the Board authorized a share repurchase program (Share Repurchase Program) under which up to $2.00 billion of our outstanding shares of common stock may be repurchased. The Share Repurchase Program became effective on October 11, 2021. In August 2022 and March 2023, the Board authorized incremental amounts of $1.25 billion and $1.0 billion, respectively, for repurchases to bring the total authorized under the Share Repurchase Program to $4.25 billion.


	$4.25 Billion Board Authorization
	Total Number of Shares Repurchased	Average Price Paid Per Share		Amount Paid for Shares Repurchased		Amount Available for Additional Repurchases at the End of the Period
Three Months Ended March 31, 2023	13,308,465	$	23.11	$	308
Three Months Ended June 30, 2023	10,144,891	24.39		247

Six Months Ended June 30, 2023 (a)	23,453,356	$	23.66	$	555	$	1,450
July 1, 2023 through August 4, 2023	3,166,429	27.31		86
January 1, 2023 through August 4, 2023	26,619,785	$	24.10	$	641	$	1,364

____________

(a)Shares repurchased include 189,626 of unsettled shares repurchased for $5 million as of June 30, 2023.

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 certificate of designation of the Series A Preferred Stock and the Series B Preferred Stock, respectively.

Preferred Stock

At both June 30, 2023 and December 31, 2022, 1,000,000 shares of Series A Preferred Stock and 1,000,000 shares Series B Preferred Stock were outstanding. The Series A Preferred Stock and the Series B Preferred Stock are not convertible into or exchangeable for any other securities of the Company and have limited voting rights. The Series A Preferred Stock may be redeemed at the option of the Company at any time after the Series A First Reset Date (defined below) and in certain other circumstances prior to the Series A First Reset Date. The Series B Preferred Stock may be redeemed at the option of the Company at any time after the Series B First Reset Date (defined below) and in certain other circumstances prior to the Series B First Reset Date.

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Dividends

Common Stock Dividends — In November 2018, Vistra announced the Board adopted a dividend program which we initiated in the first quarter of 2019. Each dividend under the program is subject to declaration by the Board and, thus, may be subject to numerous factors in existence at the time of any such declaration including, but not limited to, prevailing market conditions, Vistra's results of operations, financial condition and liquidity, Delaware law and any contractual limitations. Quarterly dividends paid per share in 2023 and 2022 are reflected in the table below.

Six Months Ended June 30, 2023

Year Ended December 31, 2022

Board Declaration Date

Payment
Date

Per Share Amount

Board Declaration Date

Payment
Date

Per Share Amount

February 2023

March 2023

0.1975

February 2022

March 2022

0.170

May 2023

June 2023

0.204

May 2022

June 2022

0.177

July 2022

September 2022

0.184

October 2022

December 2022

0.193

In August 2023, the Board declared a quarterly dividend of $0.206 per share of common stock that will be paid in September 2023.

Preferred Stock Dividends — The annual dividend rate on each share of Series A Preferred Stock is 8.0% from the Series A Issuance Date to, but excluding October 15, 2026 (Series A First Reset Date). On and after the Series A First Reset Date, the dividend rate on each share of Series A Preferred Stock shall equal the five-year U.S. Treasury rate as of the most recent reset dividend determination date (subject to a floor of 1.07%), plus a spread of 6.93% per annum. The Series A Preferred Stock has a liquidation preference of $1,000 per share, plus accumulated but unpaid dividends. Cumulative cash dividends on the Series A Preferred Stock are payable semiannually, in arrears, on each April 15 and October 15, commencing on April 15, 2022, when, as and if declared by the Board.

The annual dividend rate on each share of Series B Preferred Stock is 7.0% from the Series B Issuance Date to, but excluding December 15, 2026 (Series B First Reset Date). On and after the Series B First Reset Date, the dividend rate on each share of Series B Preferred Stock shall equal the five-year U.S. Treasury rate as of the most recent reset dividend determination date (subject to a floor of 1.26%), plus a spread of 5.74% per annum. The Series B Preferred Stock has a liquidation preference of $1,000 per share, plus accumulated but unpaid dividends. Cumulative cash dividends on the Series B Preferred Stock are payable semiannually, in arrears, on each June 15 and December 15, commencing on June 15, 2022, when, as and if declared by the Board.

Semiannual dividends paid per share of each respective preferred stock series in 2023 and 2022 are reflected in the table below. Dividends payable are recorded on the Board declaration date.

Series A Preferred Stock

Series B Preferred Stock

Board Declaration Date

Payment
Date

Per Share Amount

Board Declaration Date

Payment
Date

Per Share Amount

February 2022

April 2022

40.00

May 2022

June 2022

35.97

July 2022

October 2022

40.00

October 2022

December 2022

35.00

February 2023

April 2023

40.00

May 2023

June 2023

35.00

In August 2023, the Board declared a semi-annual dividend of $40.00 per share of Series A Preferred Stock that will be paid in October 2023.

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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 June 30, 2023, Vistra Operations can distribute approximately $4.5 billion to Parent under the Vistra Operations Credit Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Parent of approximately $425 million and $350 million, for the three months ended June 30, 2023 and 2022, respectively, and $775 million and $950 million for the six months ended June 30, 2023 and 2022, 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 June 30, 2023, the maximum amount of restricted net assets of Vistra Operations that may not be distributed to Parent totaled approximately $110 million.

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 and the Series B 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) and Series B 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 and the Series B Preferred Stock, respectively.

Warrants

At the Dynegy Merger Date, the Company entered into an agreement whereby the holder of each outstanding warrant previously issued by Dynegy would be entitled to receive, upon paying an exercise price of $35.00 (subject to adjustment from time to time), the number of shares of Vistra common stock that such holder would have been entitled to receive if it had held one share of Dynegy common stock at the closing of the Dynegy Merger, or 0.652 shares of Vistra common stock. Accordingly, upon exercise, a warrant holder would effectively pay $53.68 (subject to adjustment of the exercise price from time to time) per share of Vistra common stock received. In July 2023, in accordance with the terms of the warrant agreement, the exercise price of each warrant was adjusted downward to $32.93 (subject to further adjustment from time to time), or $50.51 (subject to adjustment of the exercise price from time to time) per share of Vistra common stock received. As of June 30, 2023, nine million warrants expiring in 2024 were outstanding. The warrants were included in equity based on their fair value at the Dynegy Merger Date.

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Equity

The following table presents the changes to equity for the three months ended June 30, 2023:


	Preferred Stock		Common Stock (a)		Treasury Stock		Additional Paid-in Capital		Retained Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss)		Total Stockholders' Equity		Noncontrolling Interest in Subsidiary		Total Equity
Balance as of March 31, 2023	$	2,000	$	5	$	(3,706)	$	9,952	$	(3,058)	$	8	$	5,201	$	15	$	5,216
Stock repurchases	—		—		(249)		—		—		—		(249)		—		(249)
Dividends declared on common stock	—		—		—		—		(76)		—		(76)		—		(76)
Dividends declared on preferred stock	—		—		—		—		(38)		—		(38)		—		(38)
Effects of stock-based incentive compensation plans	—		—		—		42		—		—		42		—		42
Net income (loss)	—		—		—		—		476		—		476		—		476

Change in accumulated other comprehensive income (loss)			—		—		—		—		4		4		—		4

Other	—		—		—		(1)		—		—		(1)		—		(1)
Balance as of June 30, 2023	$	2,000	$	5	$	(3,955)	$	9,993	$	(2,696)	$	12	$	5,359	$	15	$	5,374

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The following table presents the changes to equity for the six months ended June 30, 2023:


	Preferred Stock (a)		Common Stock (b)		Treasury Stock		Additional Paid-in Capital		Retained Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss)		Total Stockholders' Equity		Noncontrolling Interest in Subsidiary		Total Equity
Balance as of December 31, 2022	$	2,000	$	5	$	(3,395)	$	9,928	$	(3,643)	$	7	$	4,902	$	16	$	4,918
Stock repurchases	—		—		(560)		—		—		—		(560)		—		(560)
Dividends declared on common stock	—		—		—		—		(153)		—		(153)		—		(153)
Dividends declared on preferred stock	—		—		—		—		(75)		—		(75)		—		(75)
Effects of stock-based incentive compensation plans	—		—		—		66		—		—		66		—		66
Net income (loss)	—		—		—		—		1,175		—		1,175		(1)		1,174

Change in accumulated other comprehensive income	—		—		—		—		—		5		5		—		5

Other	—		—		—		(1)		—		—		(1)		—		(1)
Balance as of June 30, 2023	$	2,000	$	5	$	(3,955)	$	9,993	$	(2,696)	$	12	$	5,359	$	15	$	5,374

____________

(a)Authorized shares totaled 100,000,000 as of June 30, 2023. Outstanding shares of Series A Preferred Stock totaled 1,000,000 as of both June 30, 2023 and December 31, 2022 and outstanding shares of Series B Preferred Stock totaled 1,000,000 as of both June 30, 2023 and December 31, 2022.

(b)Authorized shares totaled 1,800,000,000 as of June 30, 2023. Outstanding common shares totaled 369,625,544 and 389,754,870 as of June 30, 2023 and December 31, 2022, respectively. Treasury shares totaled 170,766,019 and 147,424,202 as of June 30, 2023 and December 31, 2022, respectively.

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The following table presents the changes to equity for the three months ended June 30, 2022:


	Preferred Stock (a)		Common Stock (b)		Treasury Stock		Additional Paid-in Capital		Retained Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss)		Total Stockholders' Equity		Noncontrolling Interest		Total Equity
Balance as of March 31, 2022	$	2,000	$	5	$	(2,170)	$	9,844	$	(2,363)	$	(16)	$	7,300	$	2	$	7,302
Stock repurchases	—		—		(474)		—		—		—		(474)		—		(474)
Dividends declared on common stock	—		—		—		—		(75)		—		(75)		—		(75)
Dividends declared on preferred stock	—		—		—		—		(38)		—		(38)		—		(38)
Effects of stock-based incentive compensation plans	—		—		—		40		—		—		40		—		40
Net income (loss)	—		—		—		—		(1,365)		—		(1,365)		8		(1,357)



Other	—		—		(1)		6		(1)		—		4		1		5
Balance as of June 30, 2022	$	2,000	$	5	$	(2,645)	$	9,890	$	(3,842)	$	(16)	$	5,392	$	11	$	5,403

The following table presents the changes to equity for the six months ended June 30, 2022:


	Preferred Stock (a)		Common Stock (b)		Treasury Stock		Additional Paid-in Capital		Retained Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss)		Total Stockholders' Equity		Noncontrolling Interest in Subsidiary		Total Equity
Balance as of December 31, 2021	$	2,000	$	5	$	(1,558)	$	9,824	$	(1,964)	$	(16)	$	8,291	$	1	$	8,292
Stock repurchases	—		—		(1,086)		—		—		—		(1,086)		—		(1,086)
Dividends declared on common stock	—		—		—		—		(152)		—		(152)		—		(152)
Dividends declared on preferred stock	—		—		—		—		(76)		—		(76)		—		(76)
Effects of stock-based incentive compensation plans	—		—		—		58				—		58		—		58
Net income (loss)	—		—		—		—		(1,650)		—		(1,650)		9		(1,641)



Other	—		—		(1)		8		—		—		7		1		8
Balance as of June 30, 2022	$	2,000	$	5	$	(2,645)	$	9,890	$	(3,842)	$	(16)	$	5,392	$	11	$	5,403

____________

(a)Authorized shares totaled 100,000,000 as of June 30, 2022. Outstanding shares of Series A Preferred Stock totaled 1,000,000 as of both June 30, 2022 and December 31, 2021 and outstanding shares of Series B Preferred Stock totaled 1,000,000 as of both June 30, 2022 and December 31, 2021.

(b)Authorized shares totaled 1,800,000,000 as of June 30, 2022. Outstanding common shares totaled 420,839,230 and 469,072,597 as of June 30, 2022 and December 31, 2021, respectively. Treasury shares totaled 115,372,902 and 63,856,879 as of June 30, 2022 and December 31, 2021, respectively.

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15. FAIR VALUE MEASUREMENTS

We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. We use a mid-market valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs. Our valuation policies and procedures were developed, maintained and validated by a centralized risk management group that reports to the Vistra Chief Financial Officer.

Fair value measurements of derivative assets and liabilities incorporate an adjustment for credit-related nonperformance risk. These nonperformance risk adjustments take into consideration master netting arrangements, credit enhancements and the credit risks associated with our credit standing and the credit standing of our counterparties (see Note 16 for additional information regarding credit risk associated with our derivatives). We utilize credit ratings and default rate factors in calculating these fair value measurement adjustments.

We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:

•Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. Our Level 1 assets and liabilities include CME or ICE (electronic commodity derivative exchanges) futures and options transacted through clearing brokers for which prices are actively quoted. We report the fair value of CME and ICE transactions without taking into consideration margin deposits, with the exception of certain margin amounts related to changes in fair value on certain CME transactions that are legally characterized as settlement of derivative contracts rather than collateral.

•Level 2 valuations utilize 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. We attempt to obtain multiple quotes from brokers that are active in the markets in which we participate and require at least one quote from two brokers to determine a pricing input as observable. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker's publication policy, recent trading volume trends and various other factors.

•Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. Significant unobservable inputs used to develop the valuation models include volatility curves, correlation curves, illiquid pricing delivery periods and locations and credit-related nonperformance risk assumptions. These inputs and valuation models are developed and maintained by employees trained and experienced in market operations and fair value measurements and validated by the Company's risk management group.

With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement.

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


	June 30, 2023										December 31, 2022
	Level 1		Level 2		Level 3 (a)		Reclass (b)		Total		Level 1		Level 2		Level 3 (a)		Reclass (b)		Total
Assets:
Commodity contracts	$	3,153	$	553	$	758	$	44	$	4,508	$	3,512	$	789	$	791	$	13	$	5,105
Interest rate swaps	—		148		—		—		148		—		135		—		—		135
Nuclear decommissioning trust – equity securities (c)	617		—		—		—		617		532		—		—				532
Nuclear decommissioning trust – debt securities (c)	—		678		—				678		—		658		—				658
Sub-total	$	3,770	$	1,379	$	758	$	44	5,951		$	4,044	$	1,582	$	791	$	13	6,430
Assets measured at net asset value (d):
Nuclear decommissioning trust – equity securities (c)									536										458
Total assets									$	6,487									$	6,888
Liabilities:
Commodity contracts	$	3,911	$	723	$	1,878	$	44	$	6,556	$	5,297	$	933	$	2,010	$	13	$	8,253
Interest rate swaps	—		74		—		—		74		—		83		—		—		83
Total liabilities	$	3,911	$	797	$	1,878	$	44	$	6,630	$	5,297	$	1,016	$	2,010	$	13	$	8,336

___________

(a)See table below for description of Level 3 assets and liabilities.

(b)Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or vice versa, as presented in our condensed consolidated balance sheets.

(c)The nuclear decommissioning trust investment is included in the investments line in our condensed consolidated balance sheets. See Note 19.

(d)The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to the amounts presented in our condensed consolidated balance sheets. Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been classified in the fair value hierarchy.

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. Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest to fixed rates. See Note 16 for further discussion regarding derivative instruments.

Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facility. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.

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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 June 30, 2023 and December 31, 2022:


June 30, 2023
	Fair Value
Contract Type (a)	Assets		Liabilities		Total		Valuation Technique	Significant Unobservable Input	Range (b)					Average (b)
Electricity purchases and sales	$	568	$	(1,350)	$	(782)	Income Approach	Hourly price curve shape (c)	$	—		to	$90	$44
									MWh
								Illiquid delivery periods for hub power prices and heat rates (d)	$	40		to	$110	$68
									MWh
Options	—		(401)		(401)		Option Pricing Model	Gas to power correlation (e)	10		%	to	100%	55%
								Power and gas volatility (e)	10		%	to	845%	426%
Financial transmission rights	146		(30)		116		Market Approach (f)	Illiquid price differences between settlement points (g)	$	(30)		to	$25	$(5)
									MWh
Natural gas	25		(87)		(62)		Income Approach	Gas basis and illiquid delivery periods (h)	$	—		to	$30	$13
									MMBtu



Other (i)	19		(10)		9
Total	$	758	$	(1,878)	$	(1,120)


December 31, 2022
	Fair Value
Contract Type (a)	Assets		Liabilities		Total		Valuation Technique	Significant Unobservable Input	Range (b)					Average (b)
Electricity purchases and sales	$	603	$	(1,332)	$	(729)	Income Approach	Hourly price curve shape (c)	$	—		to	$80	$38
									MWh
								Illiquid delivery periods for hub power prices and heat rates (d)	$	25		to	$95	$60
									MWh
Options	—		(483)		(483)		Option Pricing Model	Gas to power correlation (e)	10		%	to	100%	56%
								Power and gas volatility (e)	5		%	to	620%	313%
Financial transmission rights	132		(31)		101		Market Approach (f)	Illiquid price differences between settlement points (g)	$	(35)		to	$10	$(11)
									MWh
Natural gas	20		(155)		(135)		Income Approach	Gas basis (h)	$	—		to	$30	$13
									MMBtu




Other (i)	36		(9)		27
Total	$	791	$	(2,010)	$	(1,219)

____________

(a)Electricity purchase and sales contracts include power and heat rate positions in ERCOT, PJM, ISO-NE, NYISO and MISO regions. The 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. Options consist of physical electricity options, spread options, swaptions and natural gas options.

(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 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 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 gas basis prices and fixed prices.

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

See the table below for discussion of transfers between Level 2 and Level 3 for the three and six months ended June 30, 2023 and 2022.

The following table presents the changes in fair value of the Level 3 assets and liabilities for the three and six months ended June 30, 2023 and 2022.


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Net liability balance at beginning of period	$	(1,225)	$	(629)	$	(1,219)	$	(360)
Total unrealized valuation gains (losses)	127		(572)		51		(1,021)
Purchases, issuances and settlements (a):
Purchases	51		57		100		95
Issuances	(8)		(31)		(13)		(42)
Settlements	(55)		77		(38)		174
Transfers into Level 3 (b)	(15)		38		(29)		39
Transfers out of Level 3 (b)	5		45		28		100


Net change (c)	105		(386)		99		(655)
Net liability balance at end of period	$	(1,120)	$	(1,015)	$	(1,120)	$	(1,015)
Unrealized valuation losses relating to instruments held at end of period	$	(11)	$	(489)	$	(185)	$	(743)

____________

(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 and six months ended June 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. For the three and six months ended June 30, 2022, 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.

(c)Activity excludes change in fair value in the month positions settle. Substantially all changes in values of commodity contracts are reported as operating revenues in our condensed consolidated statements of operations.

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16.COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Strategic Use of Derivatives

We transact in derivative instruments, such as options, swaps, futures and forward contracts, to manage commodity price and interest rate risk. See Note 15 for a discussion of the fair value of derivatives.

Commodity Hedging and Trading Activity — We utilize natural gas and electricity derivatives to reduce exposure to changes in electricity prices primarily to hedge future revenues from electricity sales from our generation assets and 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 gas producers, local distribution companies and energy marketing companies. Unrealized gains and losses arising from changes in the fair value of derivative instruments as well as realized gains and losses upon settlement of the instruments are reported in our condensed consolidated statements of operations in operating revenues and fuel, purchased power costs and delivery fees.

Interest Rate Swaps — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate interest rates to fixed rates, thereby hedging future interest costs and related cash flows. Unrealized gains and losses arising from changes in the fair value of the swaps as well as realized gains and losses upon settlement of the swaps are reported in our condensed consolidated statements of operations in interest expense and related charges. During 2019, Vistra entered into $2.12 billion of new interest rate swaps, pursuant to which Vistra will pay a variable rate and receive a fixed rate. The terms of these new swaps were matched against the terms of certain existing swaps, effectively offsetting the hedge of the existing swaps and fixing the out-of-the-money position of such swaps. These matched swaps will settle over time, in accordance with the original contractual terms. Swaps expiring in July 2023 and July 2026 continue to hedge our exposure on $2.30 billion of debt through July 2026.

In March 2023, Vistra entered into $750 million of interest rate swaps to hedge a portion of the floating rate component of the expected interest cost associated with the anticipated Transactions debt financings (see Note 2). The interest rate swaps are effective December 31, 2023 and expire December 31, 2030.

Financial Statement Effects of Derivatives

Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of derivative contractual assets and liabilities as reported in our condensed consolidated balance sheets as of June 30, 2023 and December 31, 2022. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract.


	June 30, 2023
	Derivative Assets				Derivative Liabilities
	Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total
Current assets	$	3,892	$	87	$	12	$	—	$	3,991
Noncurrent assets	586		61		18		—		665
Current liabilities	(3)		—		(5,032)		(41)		(5,076)
Noncurrent liabilities	(11)		—		(1,510)		(33)		(1,554)
Net assets (liabilities)	$	4,464	$	148	$	(6,512)	$	(74)	$	(1,974)


	December 31, 2022
	Derivative Assets				Derivative Liabilities
	Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total
Current assets	$	4,442	$	92	$	4	$	—	$	4,538
Noncurrent assets	656		43		3		—		702
Current liabilities	(1)		—		(6,562)		(47)		(6,610)
Noncurrent liabilities	(5)		—		(1,685)		(36)		(1,726)
Net assets (liabilities)	$	5,092	$	135	$	(8,240)	$	(83)	$	(3,096)

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As of June 30, 2023 and December 31, 2022, there were no derivative positions accounted for as cash flow or fair value hedges.

The following table presents the pre-tax effect of derivative gains (losses) on net income, including realized and unrealized effects. Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts.


Derivative (condensed consolidated statements of operations presentation)	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Commodity contracts (Operating revenues)	$	(1)	$	(2,180)	$	668	$	(3,007)
Commodity contracts (Fuel, purchased power costs and delivery fees)	(33)		249		(328)		341
Interest rate swaps (Interest expense and related charges)	78		35		50		149
Net gain (loss)	$	44	$	(1,896)	$	390	$	(2,517)

Balance Sheet Presentation of Derivatives

We elect to report derivative assets and liabilities in our condensed consolidated balance sheets on a gross basis without taking into consideration netting arrangements we have with counterparties to those derivatives. We maintain standardized master netting agreements with certain counterparties that allow for the right to offset assets and liabilities and collateral in order to reduce credit exposure between us and the counterparty. These agreements contain specific language related to margin requirements, monthly settlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract counterparty.

Generally, margin deposits that contractually offset these derivative instruments are reported separately in our condensed consolidated balance sheets, with the exception of certain margin amounts related to changes in fair value on CME transactions that are legally characterized as settlement of forward exposure rather than collateral. Margin deposits received from counterparties are primarily used for working capital or other general corporate purposes.

The following tables reconcile our derivative assets and liabilities on a contract basis to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:


	June 30, 2023								December 31, 2022
	Derivative Assets and Liabilities		Offsetting Instruments (a)		Cash Collateral (Received) Pledged (b)		Net Amounts		Derivative Assets and Liabilities		Offsetting Instruments (a)		Cash Collateral (Received) Pledged (b)		Net Amounts
Derivative assets:
Commodity contracts	$	4,464	$	(3,891)	$	(23)	$	550	$	5,092	$	(4,480)	$	(20)	$	592
Interest rate swaps	148		(61)		—		87		135		(64)		—		71
Total derivative assets	4,612		(3,952)		(23)		637		5,227		(4,544)		(20)		663
Derivative liabilities:
Commodity contracts	(6,512)		3,891		674		(1,947)		(8,240)		4,480		1,675		(2,085)
Interest rate swaps	(74)		61		—		(13)		(83)		64		—		(19)
Total derivative liabilities	(6,586)		3,952		674		(1,960)		(8,323)		4,544		1,675		(2,104)
Net amounts	$	(1,974)	$	—	$	651	$	(1,323)	$	(3,096)	$	—	$	1,655	$	(1,441)

____________

(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.

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Derivative Volumes

The following table presents the gross notional amounts of derivative volumes as of June 30, 2023 and December 31, 2022:


	June 30, 2023		December 31, 2022
Derivative type	Notional Volume				Unit of Measure
Natural gas (a)	6,704		6,007		Million MMBtu
Electricity	818,503		754,762		GWh
Financial transmission rights (b)	268,094		225,845		GWh
Coal	44		48		Million U.S. tons
Fuel oil	66		105		Million gallons

Emissions	47		40		Million tons
Renewable energy certificates	32		31		Million certificates

Interest rate swaps – variable/fixed (c)	$	7,470	$	6,720	Million U.S. dollars
Interest rate swaps – fixed/variable (c)	$	2,120	$	2,120	Million U.S. dollars

____________

(a)Represents gross notional forward sales, purchases and options transactions, 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 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 require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies or include cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants.

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


	June 30, 2023		December 31, 2022
Fair value of derivative contract liabilities (a)	$	(1,594)	$	(1,934)
Offsetting fair value under netting arrangements (b)	779		899
Cash collateral and letters of credit	608		253
Liquidity exposure	$	(207)	$	(782)

____________

(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 June 30, 2023, total credit risk exposure to all counterparties related to derivative contracts totaled $5.008 billion (including associated accounts receivable). The net exposure to those counterparties totaled $739 million as of June 30, 2023, after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure totaling $170 million. As of June 30, 2023, the credit risk exposure to the banking and financial sector represented 82% of the total credit risk exposure and 38% of the net exposure.

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Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because all of this exposure is with counterparties with investment grade credit ratings. However, this concentration increases the risk that a default by any of these counterparties would have a material effect on our financial condition, results of operations and liquidity. The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating.

We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.

17.RELATED PARTY TRANSACTIONS

In connection with Emergence, we entered into agreements with certain of our affiliates and with parties who received shares of common stock and TRA Rights in exchange for their claims.

Registration Rights Agreement

Pursuant to the Plan of Reorganization, on the Effective Date, we entered into a Registration Rights Agreement (the RRA) with certain selling stockholders. Pursuant to the RRA, we maintain a registration statement on Form S-3 providing for registration of the resale of the Vistra common stock held by such selling stockholders. In addition, under the terms of the RRA, among other things, if we propose to file certain types of registration statements under the Securities Act with respect to an offering of equity securities, we will be required to use our reasonable best efforts to offer the other parties to the RRA the opportunity to register all or part of their shares on the terms and conditions set forth in the RRA.

Tax Receivable Agreement

On the Effective Date, Vistra entered into the TRA with a transfer agent on behalf of certain former first-lien creditors of TCEH. See Note 8 for discussion of the TRA.

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18.SEGMENT INFORMATION

The operations of Vistra are aligned into six reportable business segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure.

Our Chief Executive Officer is our Chief Operating Decision Maker (CODM). Our CODM reviews the results of these segments separately and allocates resources to the respective segments as part of our strategic operations. A measure of assets is not applicable, as segment assets are not regularly reviewed by the CODM for evaluating performance or allocating resources.

The Retail segment is engaged in retail sales of electricity and natural gas to residential, commercial and industrial customers. Substantially all of these activities are conducted by TXU Energy, Ambit, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric across 19 states in the U.S.

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

The West segment represents results from the CAISO market, including our battery ESS projects at our Moss Landing power plant site (see Note 3).

The Sunset segment consists of generation plants with announced retirement dates after December 31, 2022. 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, 2023.

The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines (see Note 3). The Asset Closure segment also includes results from generation plants we retired in the years ended December 31, 2022 and 2023. 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. We have allocated unrealized gains and losses on the commodity risk management activities attributable to the plants retired in 2022 and 2023.

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

The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1 of our 2022 Form 10-K. Our CODM uses more than one measure to assess segment performance, but primarily focuses on Adjusted EBITDA. While we believe this is a useful metric in evaluating operating performance, it is not a metric defined by U.S. GAAP and may not be comparable to non-GAAP metrics presented by other companies. Adjusted EBITDA is most comparable to consolidated net income (loss) prepared based on U.S. GAAP. 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.

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Three Months Ended	Retail		Texas		East		West		Sunset		Asset Closure		Corporate and Other (b)		Eliminations		Consolidated
Operating revenues (a):
June 30, 2023	$	2,427	$	191	$	846	$	224	$	314	$	—	$	—	$	(813)	$	3,189
June 30, 2022	1,792		(623)		319		79		(79)		117		—		(17)		1,588
Depreciation and amortization:
June 30, 2023	$	(22)	$	(129)	$	(167)	$	(19)	$	(15)	$	—	$	(17)	$	—	$	(369)
June 30, 2022	(36)		(146)		(179)		11		(16)		(11)		(17)		—		(394)
Operating income (loss):
June 30, 2023	$	822	$	(648)	$	275	$	152	$	64	$	(26)	$	(48)	$	—	$	591
June 30, 2022	910		(1,706)		(661)		24		(155)		(63)		(32)		—		(1,683)
Net income (loss) (b):
June 30, 2023	$	812	$	(626)	$	275	$	164	$	62	$	67	$	(278)	$	—	$	476
June 30, 2022	898		(1,638)		(662)		25		(155)		(58)		233		—		(1,357)



Six Months Ended	Retail		Texas		East		West		Sunset		Asset Closure		Corporate and Other (b)		Eliminations		Consolidated
Operating revenues (a):
June 30, 2023	$	4,777	$	1,544	$	2,655	$	455	$	1,142	$	—	$	—	$	(2,959)	$	7,614
June 30, 2022	3,617		(1,718)		1,274		151		(197)		202		—		1,384		4,713
Depreciation and amortization:
June 30, 2023	$	(51)	$	(259)	$	(328)	$	(34)	$	(29)	$	—	$	(34)	$	—	$	(735)
June 30, 2022	(72)		(269)		(358)		(31)		(32)		(28)		(34)		—		(824)
Operating income (loss):
June 30, 2023	$	234	$	(79)	$	1,019	$	199	$	489	$	(55)	$	(85)	$	—	$	1,722
June 30, 2022	3,342		(3,684)		(788)		(37)		(555)		(176)		(74)		—		(1,972)
Net income (loss) (b):
June 30, 2023	$	217	$	(42)	$	1,020	$	216	$	486	$	40	$	(763)	$	—	$	1,174
June 30, 2022	3,326		(3,610)		(791)		(36)		(556)		(170)		196		—		(1,641)
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures:
June 30, 2023	$	1	$	246	$	49	$	6	$	42	$	—	$	30	$	—	$	374
June 30, 2022	—		228		18		25		11		—		24		—		306

__________________

(a)The following unrealized net gains (losses) from mark-to-market valuations of commodity positions are included in operating revenues:


Three Months Ended	Retail		Texas		East		West		Sunset		Asset Closure		Corporate and Other		Eliminations (1)		Consolidated
June 30, 2023	$	24	$	(673)	$	202	$	104	$	103	$	8	$	—	$	321	$	89
June 30, 2022	(667)		(1,652)		(649)		(33)		(257)		4		—		1,166		$	(2,088)
Six Months Ended	Retail		Texas		East		West		Sunset		Asset Closure		Corporate and Other		Eliminations (1)		Consolidated
June 30, 2023	$	165	$	(305)	$	1,145	$	116	$	580	$	25	$	—	$	(360)	$	1,366
June 30, 2022	(1,037)		(3,625)		(849)		(79)		(643)		(52)		—		3,838		$	(2,447)

___________________

(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.

(b)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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19.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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Interest paid/accrued	$	157	$	147	$	313	$	273
Unrealized mark-to-market net gains on interest rate swaps	(63)		(45)		(22)		(171)
Amortization of debt issuance costs, discounts and premiums	6		7		12		13

Capitalized interest	(11)		(8)		(21)		(14)
Other	11		8		25		15
Total interest expense and related charges	$	100	$	109	$	307	$	116

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 12, was 4.72% and 4.05% as of June 30, 2023 and 2022.

Other Income and Deductions


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Other income:
Insurance settlements (a)	$	8	$	62	$	9	$	63

Gain on sale of land (b)	93		5		94		5
Interest income	12		2		26		2
All other	11		2		15		7
Total other income	$	124	$	71	$	144	$	77
Other deductions:





All other	2		9		5		13
Total other deductions	$	2	$	9	$	5	$	13

____________

(a)For both the three and six months ended June 30, 2023, reported in the West segment. For the three months ended June 30, 2022, reported in the Texas segment. For the six months ended June 30, 2022, $62 million reported in the Texas segment and $1 million reported in the Corporate and Other non-segment.

(b)For both the three and six months ended June 30, 2023, $93 million reported in the Asset Closure segment. For the six months ended June 30, 2023, $1 million reported in the Texas segment. For both the three and six months ended June 30, 2022, reported in the Asset Closure segment.

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Restricted Cash


	June 30, 2023				December 31, 2022
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets

Amounts related to remediation escrow accounts	$	40	$	15	$	37	$	33



Total restricted cash	$	40	$	15	$	37	$	33

Trade Accounts Receivable


	June 30, 2023		December 31, 2022
Wholesale and retail trade accounts receivable	$	1,734	$	2,124
Allowance for uncollectible accounts	(53)		(65)
Trade accounts receivable — net	$	1,681	$	2,059

N9210 {V} Gross trade accounts receivable as of June 30, 2023 and December 31, 2022 include unbilled retail revenues of $711 million and $607 million, respectively.

Allowance for Uncollectible Accounts Receivable


	Six Months Ended June 30,
		2023		2022
Allowance for uncollectible accounts receivable at beginning of period		$	65	$	45
Increase for bad debt expense		69		65
Decrease for account write-offs		(81)		(58)

Allowance for uncollectible accounts receivable at end of period		$	53	$	52

Inventories by Major Category


	June 30, 2023		December 31, 2022
Materials and supplies	$	281	$	274
Fuel stock	363		252
Natural gas in storage	32		44
Total inventories	$	676	$	570

Investments


	June 30, 2023		December 31, 2022
Nuclear plant decommissioning trust	$	1,831	$	1,648
Assets related to employee benefit plans	30		30
Land	41		41
Miscellaneous other	13		10
Total investments	$	1,915	$	1,729

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Nuclear Decommissioning Trust

Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs 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 trust fund. Income and expense, including gains and losses associated with the trust fund assets and the 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. If funds recovered from Oncor's customers held in the trust fund are determined to be inadequate to decommission the Comanche Peak nuclear generation plant, Oncor would be required to collect all additional amounts from its customers, with no obligation from Vistra, provided that Vistra complied with PUCT rules and regulations regarding decommissioning trusts. A summary of the fair market value of investments in the fund follows:


	June 30, 2023		December 31, 2022
Debt securities (a)	$	678	$	658
Equity securities (b)	1,153		990
Total	$	1,831	$	1,648

____________

(a)The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody's. The debt securities are heavily weighted with government and municipal bonds and investment grade corporate bonds. The debt securities had an average coupon rate of 2.94% and 2.64% as of June 30, 2023 and December 31, 2022, respectively, and an average maturity of 11 years as of both June 30, 2023 and December 31, 2022.

(b)The investment objective for 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.

Debt securities held as of June 30, 2023 mature as follows: $258 million in one to five years, $142 million in five to 10 years and $278 million after 10 years.

The following table summarizes proceeds from sales of securities and investments in new securities.


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Proceeds from sales of securities	$	132	$	236	$	251	$	334
Investments in securities	$	(137)	$	(242)	$	(262)	$	(345)

Property, Plant and Equipment


	June 30, 2023		December 31, 2022
Power generation and structures	$	17,113	$	16,597
Land	572		584
Office and other equipment	154		163
Total	17,839		17,344
Less accumulated depreciation	(6,159)		(5,753)
Net of accumulated depreciation	11,680		11,591
Finance lease right-of-use assets (net of accumulated depreciation)	166		173
Nuclear fuel (net of accumulated amortization of $133 million and $152 million)	336		268
Construction work in progress	355		522
Property, plant and equipment — net	$	12,537	$	12,554

Depreciation expenses totaled $332 million and $341 million for the three months ended June 30, 2023 and 2022, respectively, and $655 million and $719 million for six months ended June 30, 2023 and 2022, respectively.

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Asset Retirement and Mining Reclamation Obligations (ARO)

These liabilities 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. There is no earnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through the regulatory process as part of delivery fees charged by Oncor.

As of June 30, 2023, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.715 billion, which is lower than the fair value of the assets contained in the nuclear decommissioning trust. Since the costs to ultimately decommission that plant are recoverable through the regulatory rate making process as part of Oncor's delivery fees, a corresponding regulatory liability has been recorded to our condensed consolidated balance sheet of $116 million in other noncurrent liabilities and deferred credits.

The following table summarizes the changes to these obligations, reported as AROs (current and noncurrent liabilities) in our condensed consolidated balance sheets, for the six months ended June 30, 2023 and 2022.


	Six Months Ended June 30, 2023								Six Months Ended June 30, 2022
	Nuclear Plant Decom- missioning		Mining Land Reclamation		Coal Ash and Other		Total		Nuclear Plant Decom- missioning		Mining Land Reclamation		Coal Ash and Other		Total
Liability at beginning of period	$	1,688	$	284	$	465	$	2,437	$	1,635	$	320	$	495	$	2,450
Additions:
Accretion	27		6		11		44		26		7		10		43
Adjustment for change in estimates	—		4		9		13		—		(2)		5		3


Reductions:
Payments	—		(33)		(8)		(41)		—		(37)		(9)		(46)


Liability at end of period	1,715		261		477		2,453		1,661		288		501		2,450
Less amounts due currently	—		(90)		(29)		(119)		—		(98)		(14)		(112)
Noncurrent liability at end of period	$	1,715	$	171	$	448	$	2,334	1,661		190		487		2,338

Other Noncurrent Liabilities and Deferred Credits

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


	June 30, 2023		December 31, 2022
Retirement and other employee benefits	$	234	$	237
Winter Storm Uri impact (a)	28		35
Identifiable intangible liabilities (Note 6)	133		140
Regulatory liability (b)	116		—
Finance lease liabilities	232		237
Uncertain tax positions, including accrued interest	—		13
Liability for third-party remediation	20		37

Accrued severance costs	38		36
Other accrued expenses	169		269
Total other noncurrent liabilities and deferred credits	$	970	$	1,004

____________

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

(b)As of June 30, 2023, the fair value of the assets contained in the nuclear decommissioning trust was higher than the carrying value of our ARO related to our nuclear generation plant decommissioning and recorded as a regulatory liability of $116 million in other noncurrent liabilities and deferred credits. As of December 31, 2022, the carrying value of our ARO related to our nuclear generation plant decommissioning was higher than the fair value of the assets contained in the nuclear decommissioning trust and recorded as a regulatory asset of $40 million in other noncurrent assets.

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Fair Value of Debt


		June 30, 2023				December 31, 2022
Long-term debt (see Note 12):	Fair Value Hierarchy	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt under the Vistra Operations Credit Facilities	Level 2	$	2,504	$	2,497	$	2,519	$	2,486
Vistra Operations Senior Notes	Level 2	9,388		8,862		9,378		8,830


Equipment Financing Agreements	Level 3	75		70		74		72

We determine fair value in accordance with accounting standards as discussed in Note 15. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services, such as Bloomberg.

Supplemental Cash Flow Information

The following table reconciles cash, cash equivalents and restricted cash reported in our condensed consolidated statements of cash flows to the amounts reported in our condensed consolidated balance sheets as of June 30, 2023 and December 31, 2022:


	June 30, 2023		December 31, 2022
Cash and cash equivalents	$	643	$	455
Restricted cash included in current assets	40		37
Restricted cash included in noncurrent assets	15		33
Total cash, cash equivalents and restricted cash	$	698	$	525

The following table summarizes our supplemental cash flow information for the six months ended June 30, 2023 and 2022:


	Six Months Ended June 30,
	2023		2022
Cash payments related to:
Interest paid	$	322	$	264
Capitalized interest	(21)		(14)
Interest paid (net of capitalized interest)	$	301	$	250

For the six months ended June 30, 2023 and 2022, we paid state income taxes of $19 million and $18 million respectively, and received state income tax refunds of $9 million and $8 million, respectively.

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

The discussion below, as well as other portions of this quarterly report on Form 10-Q, contain forward-looking statements within the meaning of Section 27A of the Securities Act, Section 21E of the Exchange Act and the Private Securities Litigation Reform Act of 1995. In addition, management may make forward-looking statements orally or in other writing, including, but not limited to, in press releases, quarterly earnings calls, executive presentations, in the annual report to stockholders and in other filings with the SEC. Readers can usually identify these forward-looking statements by the use of such words as may," "will," "should,” “likely,” “plans,” “projects,” “expects,” “anticipates,” “believes” or similar words. These statements involve a number of risks and uncertainties. Actual results could materially differ from those anticipated by such forward-looking statements. For more discussion about risk factors that could cause or contribute to such differences, see Part II, Item 7 "Management’s Discussion and Analysis of Financial Condition and Results of Operations" and Part I, Item 1A "Risk Factors" in the Company's 2022 Form 10-K and any updates contained herein. Forward-looking statements reflect the information only as of the date on which they are made. The Company does not undertake any obligation to update any forward-looking statements to reflect future events, developments, or other information. If Vistra does update one or more forward-looking statements, no inference should be drawn that additional updates will be made regarding that statement or any other forward-looking statements. This discussion is intended to clarify and focus on our results of operations, certain changes in our financial position, liquidity, capital structure and business developments for the periods covered by the condensed consolidated financial statements included under Part I, Item 1 of this quarterly report on Form 10-Q for the three and six months ended June 30, 2023. This discussion should be read in conjunction with those condensed consolidated financial statements and the related notes and is qualified by reference to them.

The following discussion and analysis of our financial condition and results of operations for the three and six months ended June 30, 2023 and 2022 should be read in conjunction with our condensed consolidated financial statements and the notes to those statements.

All dollar amounts in the tables in the following discussion and analysis are stated in millions of U.S. dollars unless otherwise indicated.

Critical Accounting Policies and Estimates

The Company's discussion and analysis of its financial position and results of operations is based upon its condensed consolidated financial statements. The preparation of these condensed consolidated financial statements requires estimation and judgment that affect the reported amounts of revenue, expenses, assets and liabilities. The Company bases its estimates on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the accounting for assets and liabilities that are not readily apparent from other sources. If the estimates differ materially from actual results, the impact on the condensed consolidated financial statements may be material. The Company's critical accounting policies are disclosed in our 2022 Form 10-K.

Business

Operating Segments

Vistra has six reportable segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. See Note 18 to the Financial Statements for further information concerning our reportable business segments.

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Significant Activities and Events and Items Influencing Future Performance

Transaction Agreement

On March 6, 2023, Vistra Operations and Merger Sub entered into a Transaction Agreement with Energy Harbor pursuant to which, upon the terms and subject to the conditions thereof, Merger Sub will be merged with and into Energy Harbor, with Energy Harbor surviving as an indirect subsidiary of Vistra. The Transaction Agreement, the Merger and the other Transactions were approved by each of Vistra's Board and Energy Harbor's board of directors. See Note 2 to the Financial Statements for more information concerning the Transaction Agreement.

Climate Change, Investments in Clean Energy and CO2 Reductions

Environmental Regulations — We are subject to extensive environmental regulation by governmental authorities, including the EPA and the environmental regulatory bodies of states in which we operate. Environmental regulations could have a material impact on our business, such as certain corrective action measures that may be required under the CCR rule and the ELG rule (see Note 13 to the Financial Statements). However, such rules and the regulatory environment are continuing to evolve and change, and we cannot predict the ultimate effect that such changes may have on our business.

Emissions Reductions — Vistra is targeting to achieve a 60% reduction in Scope 1 and Scope 2 CO2 equivalent emissions by 2030 as compared to a 2010 baseline, with a long-term goal to achieve net-zero carbon emissions by 2050, assuming necessary advancements in technology and supportive market constructs and public policy. In furtherance of Vistra's efforts to meet its net-zero target, Vistra expects to deploy multiple levers to transition the Company to operating with net-zero emissions.

Green Finance Framework — In December 2021, we announced the publication of our Green Finance Framework, which allows us to issue green financial instruments to fund new or existing projects that support renewable energy and energy efficiency with alignment to our ESG strategy.

Solar Generation and Energy Storage Projects —

•In September 2020, we announced the planned development, at a cost of approximately $850 million, of up to 668 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas. Of this planned development in Texas, 158 MW of solar generation and the 260 MW battery ESS came online in 2022.

•In September 2021, we announced the planned development, at a cost of approximately $550 million, of up to 300 MW of solar photovoltaic power generation facilities and up to 150 MW of battery ESS at retired or to-be-retired plant sites in Illinois, based on the passage of Illinois Senate Bill 2408, the Energy Transition Act.

•In January 2022, we announced that, subject to approval by the CPUC, we would enter into a 15-year resource adequacy contract with PG&E to develop an additional 350 MW battery ESS at our Moss Landing Power Plant site. The CPUC approved the resource adequacy and energy settlement contract in April 2022. This battery ESS entered commercial operations in June 2023.

We will only invest in these growth projects if we are confident in the expected returns. See Note 3 to the Financial Statements for a summary of our solar and battery ESS projects.

CO2 Reductions — In June 2022, September 2022 and January 2023, we retired the Zimmer coal-fueled generation facility, the Joppa generation facilities and the Edwards coal-fueled generation facility, respectively. See Note 4 to the Financial Statements for a summary of our planned generation retirements.

Comanche Peak Nuclear Plant License Renewal

In October 2022, we announced the submission of our application to the NRC for license renewal at our two-unit Comanche Peak Nuclear Plant. The current licenses for Units 1 and 2 extend into 2030 and 2033, respectively, and we are applying to renew the licenses into 2050 and 2053, respectively.

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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 a nuclear PTC, a solar PTC, a first-time stand-alone battery storage investment tax credit, a 15% CAMT on book income of certain large corporations, and a 1% excise tax on net stock repurchases. Treasury regulations are expected to define the scope of the legislation in many important respects over the next twelve months. The excise tax on stock repurchases is not expected to have a material impact on our financial statements. Vistra is not subject to the CAMT in the 2023 tax year since it only applies to corporations that have 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 for periods after the law takes effect and for estimating the TRA liability. See Note 1 for our accounting policy related to refundable and transferable PTCs and ITCs.

Macroeconomic Conditions

With forward power and natural gas curves increasing materially in 2022, we have increased our hedging for future periods. As of June 30, 2023, we have hedged approximately 86% of our expected generation volumes on average for the balance of 2023 through 2025 (with approximately 98% hedged for the balance of 2023 and approximately 95% hedged for 2024).

The industry continues to experience supply chain constraints that have reduced the availability and increased the costs of certain fuels, such as coal, reduced the availability of certain equipment and supply relevant to construction of renewables projects, and increased the lead time to procure certain materials necessary to maintain 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 experienced throughout 2022 drove increases in interest rates, resulting in increased expected refinancing or borrowing costs, including project financing for our development projects.

Winter Storm Uri

In February 2021, a severe winter storm with extremely cold temperatures affected much of the U.S., including Texas. This severe weather resulted in surging demand for power, gas supply shortages, operational challenges for generators, and a significant load shed event that was ordered by ERCOT beginning on February 15, 2021 and continuing through February 18, 2021. Winter Storm Uri had a material adverse impact on our results of operations and operating cash flows in 2021.

The weather event resulted in a $2.2 billion negative impact on the Company's pre-tax earnings in the year ended December 31, 2021 after taking into account approximately $544 million in securitization proceeds Vistra received from ERCOT as further described in Note 1 to the Financial Statements. The primary drivers of the loss were the need to procure power in ERCOT at market prices at or near the price cap due to lower output from our natural gas-fueled power plants driven by natural gas deliverability issues and our coal-fueled power plants driven by coal fuel handling challenges, high fuel costs, and high retail load costs.

Vistra has taken various actions to improve its risk profile for future weather-driven volatility events, including investing in improvements to further harden its coal fuel handling capabilities and to further weatherize its ERCOT fleet for even colder temperatures and longer durations; carrying more backup generation into the peak seasons after accounting for weatherization investments and ERCOT market improvements implemented going forward; contracting for incremental gas storage to support its gas fleet; adding additional dual fuel capabilities at its gas steam units and increasing fuel oil inventory at its existing dual fuel sites; participating in processes with the PUCT and ERCOT for registration of gas infrastructure as critical resources with the transmission and distribution utilities and for enhanced winterization of both gas and power assets in the state; and engaging in processes to evaluate potential market reforms.

Dividend Program

In November 2018, we announced that the Board had adopted a dividend program, which we initiated in the first quarter of 2019. See Note 14 to the Financial Statements for more information about our dividend program.

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Share Repurchase Program

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 in October 2021. In August 2022 and March 2023, the Board authorized incremental amounts of $1.25 billion and $1.0 billion, respectively, for repurchases to bring the total authorized under the Share Repurchase Program to $4.25 billion. We expect to complete repurchases under the current $4.25 billion Share Repurchase Program by the end of 2024.


	$4.25 Billion Board Authorization
	Total Number of Shares Repurchased	Average Price Paid Per Share		Amount Paid for Shares Repurchased		Amount Available for Additional Repurchases at the End of the Period
Three Months Ended March 31, 2023	13,308,465	$	23.11	$	308
Three Months Ended June 30, 2023	10,144,891	24.39		247

Six Months Ended June 30, 2023	23,453,356	$	23.66	$	555	$	1,450
July 1, 2023 through August 4, 2023	3,166,429	27.31		86
January 1, 2023 through August 4, 2023	26,619,785	$	24.10	$	641	$	1,364

Since the Share Repurchase Program became effective in October 2021 through August 4, 2023, 124,420,697 shares of our common stock were repurchased for approximately $2.886 billion at an average price of $23.20 per share of common stock.

See Note 14 to the Financial Statements for more information concerning the Share Repurchase Program.

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 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 will 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.

See Note 11 for additional details of the collateral financing agreement with affiliate.

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. See Note 12 to the Financial Statements for details of our debt activity, including the April 2023 Amendment to the Vistra Operations Credit Agreement, and Note 10 to the Financial Statements for details of our accounts receivable financing.

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Power Price, Natural Gas Price and Market Heat Rate Exposure

Estimated hedging levels for generation volumes in our Texas, East, West and Sunset segments as of June 30, 2023 were as follows:


	2023		2024
Nuclear/Renewable/Coal Generation:
Texas	99	%	97	%
Sunset	96	%	61	%
Gas Generation:
Texas	100	%	92	%
East	96	%	96	%
West	97	%	88	%

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 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 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 June 30, 2023.


	Balance 2023		2024
Texas:
Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price	$	1	$	4
Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price	$	—	$	(3)
Gas Generation: $1.00/MWh increase in spark spread	$	—	$	4
Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	(3)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	(3)	$	(5)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	1	$	7
East:
Gas Generation: $1.00/MWh increase in spark spread	$	2	$	3
Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	(2)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	1	$	(3)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	(1)	$	3
West:
Gas Generation: $1.00/MWh increase in spark spread	$	—	$	1
Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	(1)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	1	$	1
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	(1)	$	(1)
Sunset:
Coal Generation: $2.50/MWh increase in power price	$	2	$	26
Coal Generation: $2.50/MWh decrease in power price	$	—	$	(25)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	—	$	(12)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	—	$	12

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RESULTS OF OPERATIONS

In the three and six months ended June 30, 2023, our operating segments delivered strong operating performance with a disciplined focus on cost management, while generating and selling essential electricity in a safe and reliable manner. Our performance reflected the effectiveness of our comprehensive hedging strategy and the value we were able to lock in as forward power and gas curves moved up materially in 2022. We believe remaining long-dated hedges position us to significantly benefit operating results through the remainder of 2023 and beyond, supporting the continued execution of our share repurchase and overall capital allocation strategy.

Consolidated Financial Results — Three and Six Months Ended June 30, 2023 Compared to Three and Six Months Ended June 30, 2022


	Three Months Ended June 30,				Favorable (Unfavorable) $ Change		Six Months Ended June 30,				Favorable (Unfavorable) $ Change
	2023		2022				2023		2022
Operating revenues	$	3,189	$	1,588	$	1,601	$	7,614	$	4,713	$	2,901
Fuel, purchased power costs and delivery fees	(1,475)		(2,162)		687		(3,645)		(4,441)		796
Operating costs	(445)		(435)		(10)		(866)		(851)		(15)
Depreciation and amortization	(369)		(394)		25		(735)		(824)		89
Selling, general and administrative expenses	(309)		(280)		(29)		(597)		(569)		(28)

Impairment of long-lived assets	—		—		—		(49)		—		(49)
Operating income (loss)	591		(1,683)		2,274		1,722		(1,972)		3,694
Other income	124		71		53		144		77
Other deductions	(2)		(9)		7		(5)		(13)		8
Interest expense and related charges	(100)		(109)		9		(307)		(116)		(191)
Impacts of Tax Receivable Agreement	(14)		(34)		20		(79)		(115)		36

Income (loss) before income taxes	599		(1,764)		2,363		1,475		(2,139)		3,547
Income tax (expense) benefit	(123)		407		(530)		(301)		498		(799)
Net income (loss)	$	476	$	(1,357)	$	1,833	$	1,174	$	(1,641)	$	2,748

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	Three Months Ended June 30, 2023
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	2,427	$	191	$	846	$	224	$	314	$	—	$	(813)	$	3,189
Fuel, purchased power costs and delivery fees	(1,352)		(444)		(299)		(32)		(161)		—		813		(1,475)
Operating costs	(28)		(235)		(87)		(14)		(63)		(18)		—		(445)
Depreciation and amortization	(22)		(129)		(167)		(19)		(15)		—		(17)		(369)
Selling, general and administrative expenses	(203)		(31)		(18)		(7)		(11)		(8)		(31)		(309)


Operating income (loss)	822		(648)		275		152		64		(26)		(48)		591
Other income	—		16		1		8		—		95		4		124
Other deductions	—		—		—		—		(1)		—		(1)		(2)
Interest expense and related charges	(10)		6		—		4		(1)		(2)		(97)		(100)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(14)		(14)

Income (loss) before income taxes	812		(626)		276		164		62		67		(156)		599
Income tax expense	—		—		(1)		—		—		—		(122)		(123)
Net income (loss)	$	812	$	(626)	$	275	$	164	$	62	$	67	$	(278)	$	476


	Three Months Ended June 30, 2022
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	1,792	$	(623)	$	319	$	79	$	(79)	$	117	$	(17)	$	1,588
Fuel, purchased power costs and delivery fees	(616)		(697)		(713)		(51)		14		(116)		17		(2,162)
Operating costs	(35)		(208)		(73)		(11)		(65)		(43)		—		(435)
Depreciation and amortization	(36)		(146)		(179)		11		(16)		(11)		(17)		(394)
Selling, general and administrative expenses	(195)		(32)		(15)		(4)		(9)		(10)		(15)		(280)


Operating income (loss)	910		(1,706)		(661)		24		(155)		(63)		(32)		(1,683)
Other income	—		63		—		—		—		6		2		71
Other deductions	(8)		(1)		—		—		—		—		—		(9)
Interest expense and related charges	(4)		6		(1)		1		—		(1)		(110)		(109)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(34)		(34)

Income (loss) before income taxes	898		(1,638)		(662)		25		(155)		(58)		(174)		(1,764)
Income tax benefit	—		—		—		—		—		—		407		407
Net income (loss)	$	898	$	(1,638)	$	(662)	$	25	$	(155)	$	(58)	$	233	$	(1,357)

Operating income (loss) increased $2.274 billion to operating income of $591 million in the three months ended June 30, 2023 compared to the three months ended June 30, 2022. Results for the three months ended June 30, 2023 were favorably impacted by $54 million in pre-tax unrealized mark-to-market gains on derivative positions due to power and natural gas forward market curves moving down slightly in the three months ended June 30, 2023 compared to $1.987 billion in pre-tax unrealized mark-to-market losses on commodity derivative positions due to power and natural gas forward market curves moving up materially in the three months ended June 30, 2022.

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For the three months ended June 30, 2023, other income totaled $124 million driven by a gain of $89 million from the sale of property in Freestone County, Texas. For the three months ended June 30, 2022, other income totaled $71 million driven by insurance proceeds of $62 million. See Note 19 to the Financial Statements.

Interest expense and related charges decreased $9 million to $100 million in the three months ended June 30, 2023 compared to the three months ended June 30, 2022 driven by unrealized mark-to-market gains on interest rate swaps of $63 million in 2023 compared to $45 million in 2022 due to increased notional as a result of the execution of new swaps in the three months ended June 30, 2023 compared to the three months ended June 30, 2022, partially offset by an increase in interest paid/accrued of $10 million driven by higher effective interest rates in 2023. See Notes 12 and 19 to the Financial Statements.

For the three months ended June 30, 2023 and 2022, the impacts of the TRA resulted in expense of $14 million and $34 million, respectively. See Note 8 to the Financial Statements for discussion of the impacts of the TRA obligation.

For the three months ended June 30, 2023, income tax expense totaled $123 million and the effective tax rate was 20.5%. For the three months ended June 30, 2022, income tax benefit totaled $407 million, and the effective tax rate was 23.1%. See Note 7 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.


	Six Months Ended June 30, 2023
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	4,777	$	1,544	$	2,655	$	455	$	1,142	$	—	$	(2,959)	$	7,614
Fuel, purchased power costs and delivery fees	(4,042)		(839)		(1,119)		(180)		(423)		(1)		2,959		(3,645)
Operating costs	(56)		(463)		(152)		(29)		(128)		(38)		—		(866)
Depreciation and amortization	(51)		(259)		(328)		(34)		(29)		—		(34)		(735)
Selling, general and administrative expenses	(394)		(62)		(37)		(13)		(24)		(16)		(51)		(597)

Impairment of long-lived assets	—		—		—		—		(49)		—		—		(49)
Operating income (loss)	234		(79)		1,019		199		489		(55)		(85)		1,722
Other income	—		28		2		9		1		98		6		144
Other deductions	—		(1)		—		—		(2)		—		(2)		(5)
Interest expense and related charges	(17)		10		—		8		(2)		(3)		(303)		(307)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(79)		(79)

Income (loss) before income taxes	217		(42)		1,021		216		486		40		(463)		1,475
Income tax expense	—		—		(1)		—		—		—		(300)		(301)
Net income (loss)	$	217	$	(42)	$	1,020	$	216	$	486	$	40	$	(763)	$	1,174

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	Six Months Ended June 30, 2022
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	3,617	$	(1,718)	$	1,274	$	151	$	(197)	$	202	$	1,384	$	4,713
Fuel, purchased power costs and delivery fees	248		(1,223)		(1,541)		(124)		(181)		(236)		(1,384)		(4,441)
Operating costs	(68)		(409)		(130)		(23)		(127)		(93)		(1)		(851)
Depreciation and amortization	(72)		(269)		(358)		(31)		(32)		(28)		(34)		(824)
Selling, general and administrative expenses	(383)		(65)		(33)		(10)		(18)		(21)		(39)		(569)


Operating income (loss)	3,342		(3,684)		(788)		(37)		(555)		(176)		(74)		(1,972)
Other income	—		64		—		—		—		8		5		77
Other deductions	(11)		(1)		—		—		—		(1)		—		(13)
Interest expense and related charges	(5)		11		(3)		1		(1)		(1)		(118)		(116)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(115)		(115)

Income (loss) before income taxes	3,326		(3,610)		(791)		(36)		(556)		(170)		(302)		(2,139)
Income tax benefit	—		—		—		—		—		—		498		498
Net income (loss)	$	3,326	$	(3,610)	$	(791)	$	(36)	$	(556)	$	(170)	$	196	$	(1,641)

Operating income (loss) increased $3.694 billion to operating income of $1.722 billion in the six months ended June 30, 2023 compared to the six months ended June 30, 2022. Results for the six months ended June 30, 2023 were favorably impacted by $1.139 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 six months ended June 30, 2023 compared to $2.347 billion in pre-tax unrealized mark-to-market losses on commodity derivative positions due to power and natural gas forward market curves moving up materially in the six months ended June 30, 2022.

For the six months ended June 30, 2023, other income totaled $144 million driven by a gain of $89 million from the sale of property in Freestone County, Texas. For the six months ended June 30, 2022, other income totaled $77 million driven by insurance proceeds of $63 million. See Note 19 to the Financial Statements.

Interest expense and related charges increased $191 million to $307 million in the six months ended June 30, 2023 compared to the six months ended June 30, 2022 driven by unrealized mark-to-market gains on interest rate swaps of $22 million in 2023 compared to $171 million in 2022 due to less volatility in interest rates in the six months ended June 30, 2023 compared to the six months ended June 30, 2022 and an increase in interest paid/accrued of $40 million driven by higher effective interest rates in 2023. See Note 19 to the Financial Statements.

For the six months ended June 30, 2023 and 2022, the impacts of the TRA resulted in expense of $79 million and $115 million, respectively. See Note 8 to the Financial Statements for discussion of the impacts of the TRA obligation.

For the six months ended June 30, 2023, income tax expense totaled $301 million and the effective tax rate was 20.4%. For the six months ended June 30, 2022, income tax benefit totaled $498 million, and the effective tax rate was 23.3%. See Note 7 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

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Discussion of Adjusted EBITDA

Non-GAAP Measures — 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 with our GAAP results and the accompanying reconciliations to corresponding GAAP financial measures included in the tables below, may provide a more complete understanding of factors and trends affecting our business. These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are, by definition, an incomplete understanding of Vistra and must be considered in conjunction with GAAP measures. In addition, non-GAAP financial measures are not standardized; therefore, it may not be possible to compare these financial measures with other companies' non-GAAP financial measures having the same or similar names. We strongly encourage investors to review our consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

EBITDA and Adjusted EBITDA — We believe EBITDA and Adjusted EBITDA provide meaningful representations of our operating performance. We consider EBITDA as another way to measure financial performance on an ongoing basis. Adjusted EBITDA is meant to reflect the operating performance of our segments for the period presented. We define EBITDA as earnings (loss) before interest expense, income tax expense (benefit) and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA adjusted to exclude (i) gains or losses on the sale or retirement of depreciable assets, (ii) the impacts of mark-to-market changes on derivatives, (iii) the impact of impairment charges, (iv) certain amounts associated with fresh-start reporting, acquisitions, dispositions, transition costs or restructurings, (v) non-cash compensation expense, (vi) impacts from the Tax Receivable Agreement and (vii) other nonrecurring or unusual items.

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.

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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Adjusted EBITDA — Three and Six Months Ended June 30, 2023 Compared to Three and Six Months Ended June 30, 2022


	Three Months Ended June 30,				Favorable (Unfavorable) $ Change		Six Months Ended June 30,				Favorable (Unfavorable) $ Change
	2023		2022				2023		2022
Net income (loss)	$	476	$	(1,357)	$	1,833	$	1,174	$	(1,641)	$	2,815
Income tax expense (benefit)	123		(407)		530		301		(498)		799
Interest expense and related charges (a)	100		109		(9)		307		116		191
Depreciation and amortization (b)	388		412		(24)		777		864		(87)
EBITDA before Adjustments	1,087		(1,243)		2,330		2,559		(1,159)		3,718
Unrealized net (gain) loss resulting from commodity hedging transactions (c)	(54)		1,987		(2,041)		(1,139)		2,347		(3,486)
Generation plant retirement expenses	1		—		1		1		6		(5)
Fresh start/purchase accounting impacts	3		—		3		4		—		4
Impacts of Tax Receivable Agreement	14		34		(20)		79		115		(36)

Non-cash compensation expenses	21		17		4		43		34		9
Transition and merger expenses	15		3		12		17		20		(3)
Impairment of long-lived assets	—		—		—		49		—		49


PJM capacity performance default impacts (d)	(12)		—		(12)		8		—		8
Winter Storm Uri impacts (e)	(5)		(62)		57		(38)		(116)		78
Other, net	(3)		1		(4)		(3)		31		(34)
Adjusted EBITDA	$	1,067	$	737	$	330	$	1,580	$	1,278	$	302

____________

(a)Includes unrealized mark-to-market net gains on interest rate swaps of $63 million and $22 million for the three and six months ended June 30, 2023, respectively, and unrealized mark-to-market net gains on interest rate swaps of $45 million and $171 million for the three and six months ended June 30, 2022, respectively.

(b)Includes nuclear fuel amortization in the Texas segment of $19 million and $18 million for the three months ended June 30, 2023 and 2022, respectively, and $42 million and $40 million for the six months ended June 30, 2023 and 2022, respectively.

(c)Net pre-tax unrealized mark-to-market gains on commodity hedging transactions were driven by a decrease in power and natural gas price curves during the three and six months ended June 30, 2023. Net pre-tax unrealized mark-to-market losses on commodity hedging transactions were driven by an increase in power and natural gas forward market curves during the three and six months ended June 30, 2022.

(d)For the three months ended June 30, 2023, 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. For the six months ended June 30, 2023, represents estimate of anticipated market participant defaults on PJM capacity performance penalties due to extreme magnitude of penalties associated with Winter Storm Elliott, which amounts have been and will continue to be withheld by PJM from our net bonus position during 2023.

(e)For the three and six months ended June 30, 2023, includes reductions to Adjusted EBITDA reflecting bill credit applications of $5 million and $39 million, respectively. For the three and six months ended June 30, 2022, includes reductions to Adjusted EBITDA reflecting default uplift charges of $12 million and $56 million, respectively, attributable to ERCOT receiving payments that reduced the market wide default balance, and bill credit applications of $53 million and $66 million, respectively. In 2021, an adjustment for future bill credits was recorded related to large commercial and industrial customers that curtailed their usage during Winter Storm Uri. These amounts reverse and impact Adjusted EBITDA in future periods as the credits are applied to customer bills. The Company believes the inclusion of the bill credits as a reduction to Adjusted EBITDA in the years in which such bill credits are applied more accurately reflects its operating performance.

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	Three Months Ended June 30, 2023
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	$	812	$	(626)	$	275	$	164	$	62	$	67	$	(278)	$	476
Income tax expense	—		—		1		—		—		—		122		123
Interest expense and related charges (a)	10		(6)		—		(4)		1		2		97		100
Depreciation and amortization (b)	22		148		167		19		15		—		17		388
EBITDA before Adjustments	844		(484)		443		179		78		69		(42)		1,087
Unrealized net (gain) loss resulting from hedging transactions	(347)		693		(226)		(117)		(49)		(8)		—		(54)
Generation plant retirement expenses	—		—		—		—		3		(2)		—		1
Fresh start/purchase accounting impacts	1		—		1		—		1		—		—		3
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		14		14

Non-cash compensation expenses	—		—		—		—		—		—		21		21
Transition and merger expenses	—		—		—		—		—		—		15		15



PJM capacity performance default impacts (c)	—		—		(9)		—		(3)		—		—		(12)
Winter Storm Uri impacts (d)	(5)		—		—		—		—		—		—		(5)
Other, net	5		(2)		2		1		10		—		(19)		(3)
Adjusted EBITDA	$	498	$	207	$	211	$	63	$	40	$	59	$	(11)	$	1,067

____________

(a)Includes $63 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $19 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.


	Three Months Ended June 30, 2022
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	$	898	$	(1,638)	$	(662)	$	25	$	(155)	$	(58)	$	233	$	(1,357)
Income tax benefit	—		—		—		—		—		—		(407)		(407)
Interest expense and related charges (a)	4		(6)		1		(1)		—		1		110		109
Depreciation and amortization (b)	36		164		179		(11)		16		11		17		412
EBITDA before Adjustments	938		(1,480)		(482)		13		(139)		(46)		(47)		(1,243)
Unrealized net (gain) loss resulting from hedging transactions	(500)		1,665		645		28		124		25		—		1,987
Generation plant retirement expenses	—		—		—		—		1		(1)		—		—

Impacts of Tax Receivable Agreement	—		—		—		—		—		—		34		34

Non-cash compensation expenses	—		—		—		—		—		—		17		17
Transition and merger expenses	3		—		—		—		—		—		—		3



Winter Storm Uri impacts (c)	(52)		(10)		—		—		—		—		—		(62)
Other, net	14		6		1		(1)		(7)		3		(15)		1
Adjusted EBITDA	$	403	$	181	$	164	$	40	$	(21)	$	(19)	$	(11)	$	737

____________

(a)Includes $45 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $18 million in Texas segment.

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(c)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.


	Six Months Ended June 30, 2023
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	$	217	$	(42)	$	1,020	$	216	$	486	$	40	$	(763)	$	1,174
Income tax expense	—		—		1		—		—		—		300		301
Interest expense and related charges (a)	17		(10)		—		(8)		2		3		303		307
Depreciation and amortization (b)	51		301		328		34		29		—		34		777
EBITDA before Adjustments	285		249		1,349		242		517		43		(126)		2,559
Unrealized net (gain) loss resulting from hedging transactions	212		346		(1,149)		(135)		(388)		(25)		—		(1,139)
Generation plant retirement expenses	—		—		—		—		3		(2)		—		1
Fresh start/purchase accounting impacts	1		(1)		3		—		1		—		—		4
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		79		79

Non-cash compensation expenses	—		—		—		—		—		—		43		43
Transition and merger expenses	(2)		1		—		—		1		—		17		17
Impairment of long-lived assets	—		—		—		—		49		—		—		49


PJM capacity performance default impacts (c)	—		—		6		—		2		—		—		8
Winter Storm Uri impacts (d)	(39)		1		—		—		—		—		—		(38)
Other, net	12		(6)		3		2		18		2		(34)		(3)
Adjusted EBITDA	$	469	$	590	$	212	$	109	$	203	$	18	$	(21)	$	1,580

____________

(a)Includes $22 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $42 million in the Texas segment.

(c)Represents estimate of anticipated market participant defaults on PJM capacity performance penalties due to extreme magnitude of penalties associated with Winter Storm Elliott, which amounts have been and will continue to be withheld by PJM from our net bonus position during 2023.

(d)Includes the application of bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri. We estimate remaining bill credit amounts to be applied in future periods are for the remainder of 2023 (approximately $14 million), 2024 (approximately $11 million) and 2025 (approximately $25 million).

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	Six Months Ended June 30, 2022
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	$	3,326	$	(3,610)	$	(791)	$	(36)	$	(556)	$	(170)	$	196	$	(1,641)
Income tax benefit	—		—		—		—		—		—		(498)		(498)
Interest expense and related charges (a)	5		(11)		3		(1)		1		1		118		116
Depreciation and amortization (b)	72		309		358		31		32		28		34		864
EBITDA before Adjustments	3,403		(3,312)		(430)		(6)		(523)		(141)		(150)		(1,159)
Unrealized net (gain) loss resulting from hedging transactions	(2,805)		3,696		738		71		537		110		—		2,347
Generation plant retirement expenses	—		—		—		—		5		1		—		6

Impacts of Tax Receivable Agreement	—		—		—		—		—		—		115		115

Non-cash compensation expenses	—		—		—		—		—		—		34		34
Transition and merger expenses	9		—		1		—		—		—		10		20



Winter Storm Uri impacts (c)	(64)		(52)		—		—		—		—		—		(116)
Other, net	23		19		3		1		3		11		(29)		31
Adjusted EBITDA	$	566	$	351	$	312	$	66	$	22	$	(19)	$	(20)	$	1,278

____________

(a)Includes $171 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $40 million in Texas segment.

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Retail Segment — Three and Six Months Ended June 30, 2023 Compared to Three and Six Months Ended June 30, 2022


	Three Months Ended June 30,						Favorable (Unfavorable) Change		Six Months Ended June 30,						Favorable (Unfavorable) Change
	2023			2022					2023			2022
Operating revenues:
Revenues in ERCOT	$	1,969		$	1,913		$	56	$	3,692		$	3,465		$	227
Revenues in Northeast/Midwest	435			547			(112)		921			1,190			(269)
Amortization expense	(1)			(1)			—		(1)			(1)			—
Unrealized net gains (losses) on hedging activities	24			(667)			691		165			(1,037)			1,202
Total operating revenues	2,427			1,792			635		4,777			3,617			1,160
Fuel, purchased power costs and delivery fees:
Purchases from affiliates	(1,134)			(1,183)			49		(2,598)			(2,453)			(145)
Unrealized net gains (losses) on hedging activities with affiliates (a)	321			1,166			(845)		(360)			3,838			(4,198)
Unrealized net gains (losses) on hedging activities	2			1			1		(17)			4			(21)
Delivery fees	(513)			(563)			50		(1,010)			(1,074)			64
Other costs	(28)			(37)			9		(57)			(67)			10
Total fuel, purchased power costs and delivery fees	(1,352)			(616)			(736)		(4,042)			248			(4,290)










Net income (loss)	$	812		$	898		$	(86)	$	217		$	3,326		$	(3,109)













Adjusted EBITDA	$	498		$	403		$	95	$	469		$	566		$	(97)

Retail sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT	17,086			16,823			263		32,068			31,036			1,032
Sales volumes in Northeast/Midwest	6,200			8,326			(2,126)		12,030			17,432			(5,402)
Total retail electricity sales volumes	23,286			25,149			(1,863)		44,098			48,468			(4,370)
Weather (North Texas average) - percent of normal (b):
Cooling degree days	101.9		%	123.5		%			103.7		%	119.3		%
Heating degree days	67.4		%	28.4		%			81.7		%	111.8		%

____________

(a)Includes unrealized net gains/(losses) from mark-to-market valuations of commodity positions with the Texas, East and Sunset segments.

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

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The following table presents changes in net income (loss) and Adjusted EBITDA for the three and six months ended June 30, 2023 compared to the three and six months ended June 30, 2022.


	Three Months Ended June 30, 2023 Compared to 2022		Six Months Ended June 30, 2023 Compared to 2022
Higher margins driven by seasonality of power costs	122		$	6
Winter Storm Uri impact, including bill credits	49		28
Lower margins due to mild weather in 2023	(64)		(108)
Other primarily driven by higher selling costs and bad debt expense due to higher revenues in ERCOT	(12)		(23)
Change in Adjusted EBITDA	$	95	$	(97)
Unfavorable impact of unrealized net losses on hedging activities	(153)		(3,017)
Bill credits and other costs related to Winter Storm Uri	(47)		(25)
Decrease in depreciation and amortization expenses	14		21
Change in other expenses	5		9
Change in Net income (loss)	$	(86)	$	(3,109)

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Generation — Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022


	Three Months Ended June 30,
	Texas						East						West						Sunset
	2023			2022			2023			2022			2023			2022			2023			2022
Operating revenues:
Electricity sales	$	105		$	369		$	321		$	573		$	118		$	111		$	129		$	33
Capacity revenue from ISO/RTO	—			—			22			(4)			—			—			9			22
Sales to affiliates	756			660			302			397			2			1			74			125
Rolloff of unrealized net gains (losses) representing positions settled in the current period	102			(63)			67			(105)			(21)			2			(48)			33
Unrealized net gains (losses) on hedging activities	(281)			(671)			9			(393)			126			(37)			103			(202)
Unrealized net gains (losses) on hedging activities with affiliates	(494)			(918)			126			(151)			(1)			2			48			(88)
Other revenues	3			—			(1)			2			—			—			(1)			(2)
Operating revenues	191			(623)			846			319			224			79			314			(79)
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs	(342)			(582)			(304)			(709)			(44)			(55)			(106)			(118)
Fuel for generation facilities and purchased power costs from affiliates	8			(3)			(8)			1			—			—			—			2
Unrealized gains (losses) from hedging activities	(20)			(11)			24			4			13			5			(54)			131
Unrealized gains (losses) on hedging activities with affiliates	—			(2)			—			—			—			—			—			2
Ancillary and other costs	(90)			(99)			(11)			(9)			(1)			(1)			(1)			(3)
Fuel, purchased power costs and delivery fees	(444)			(697)			(299)			(713)			(32)			(51)			(161)			14











Net income (loss)	$	(626)		$	(1,638)		$	275		$	(662)		$	164		$	25		$	62		$	(155)















Adjusted EBITDA	$	207		$	181		$	211		$	164		$	63		$	40		$	40		$	(21)
Production volumes (GWh):
Natural gas facilities	10,949			7,749			13,909			11,418			733			869
Lignite and coal facilities	6,189			5,363															2,801			4,571
Nuclear facilities	4,034			4,137
Solar facilities	237			263
Capacity factors:
CCGT facilities	58.8		%	43.7		%	57.1		%	48.0		%	32.8		%	37.7		%
Lignite and coal facilities	73.6		%	63.8		%													28.0		%	45.7		%
Nuclear facilities	77.0		%	78.9		%
Weather - percent of normal (a):
Cooling degree days	98.8		%	129.6		%	65.7		%	96.2		%	30.2		%	101.7		%	108.0		%	126.0		%
Heating degree days	90.4		%	17.6		%	88.6		%	95.0		%	188.1		%	127.5		%	81.7		%	96.9		%

____________

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

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	Three Months Ended June 30,					Three Months Ended June 30,
	2023		2022			2023		2022
Market pricing					Average Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)	$	36.53	$	63.08	PJM West Hub	$	35.40	$	93.27
					AEP Dayton Hub	$	34.88	$	94.06
Average NYMEX Henry Hub natural gas price ($/MMBtu)	$	2.12	$	7.40	NYISO Zone C	$	24.02	$	50.24
					Massachusetts Hub	$	32.58	$	73.29
Average natural gas price (a):					Indiana Hub	$	40.02	$	95.15
TetcoM3 ($/MMBtu)	$	1.50	$	6.78	Northern Illinois Hub	$	30.04	$	84.99
Algonquin Citygates ($/MMBtu)	$	2.02	$	7.19	CAISO NP15	$	33.57	$	69.55

___________

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

(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 changes in net income (loss) and Adjusted EBITDA for the three months ended June 30, 2023 compared to the three months ended June 30, 2022.


	Three Months Ended June 30, 2023 Compared to 2022
	Texas		East		West		Sunset
Favorable change in revenue net of fuel	$	107	$	63	$	19	$	61

Favorable/(unfavorable) change in other operating costs	(27)		(13)		(3)		4
Favorable/(unfavorable) change in selling, general and administrative expenses	3		(3)		(1)		(4)
Other	(57)		—		8		—
Change in Adjusted EBITDA	$	26	$	47	$	23	$	61
Favorable/(unfavorable) change in depreciation and amortization	16		12		(30)		1
Change in unrealized net gains on hedging activities	972		871		145		173

Generation plant retirement, transition and merger expenses	—		—		—		(2)
Fresh start/purchase accounting impacts	—		(1)		—		(1)
PJM capacity performance default impacts	—		9		—		3
Winter Storm Uri impact (ERCOT default uplift)	(10)		—		—		—
Other (including interest expenses)	8		(1)		1		(18)
Change in Net income (loss)	$	1,012	$	937	$	139	$	217

The favorable change in Texas segment results was driven by lower unrealized hedging losses due to less material increases in power prices in the three months ended June 30, 2023 compared to the three months ended June 30, 2022. The change in Texas segment results was also driven by higher revenue net of fuel in the three months ended June 30, 2023 compared to the three months ended June 30, 2022 due to strong generation performance during periods of higher pricing and the effectiveness of our comprehensive hedging strategy.

The favorable changes in East, West and Sunset segment results were primarily driven by unrealized hedging gains due to decreases in forward power prices in the three months ended June 30, 2023 compared to unrealized hedging losses due to increases in power prices in the three months ended June 30, 2022.

The change in East segment results was also driven by higher revenue net of fuel in the three months ended June 30, 2023 compared to the three months ended June 30, 2022 due primarily to higher energy margins reflecting the effectiveness of our comprehensive hedging strategy driving higher realized energy margins.

The change in West segment results was driven by higher revenue net of fuel in the three months ended June 30, 2023 compared to the three months ended June 30, 2022 due to higher margins and increased output from battery ESS assets which were partially offline in 2022 (see Note 3).

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The change in Sunset segment results was also driven by higher revenue net of fuel in the three months ended June 30, 2023 compared to the three months ended June 30, 2022 due primarily to the effectiveness of our comprehensive hedging strategy.

Generation — Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022


	Six Months Ended June 30,
	Texas						East						West						Sunset
	2023			2022			2023			2022			2023			2022			2023			2022
Operating revenues:
Electricity sales	$	191		$	603		$	710		$	1,218		$	331		$	227		$	370		$	162
Capacity revenue from ISO/RTO	—			—			30			(10)			—			—			27			56
Sales to affiliates	1,653			1,304			772			914			8			3			166			232
Rolloff of unrealized net gains (losses) representing positions settled in the current period	279			188			423			(69)			29			(2)			(63)			76
Unrealized net gains (losses) on hedging activities	(275)			(885)			201			(120)			90			(80)			492			(494)
Unrealized net gains (losses) on hedging activities with affiliates	(309)			(2,928)			521			(660)			(3)			3			151			(225)
Other revenues	5			—			(2)			1			—			—			(1)			(4)
Operating revenues	1,544			(1,718)			2,655			1,274			455			151			1,142			(197)
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs	(665)			(993)			(1,090)			(1,638)			(197)			(129)			(229)			(282)
Fuel for generation facilities and purchased power costs from affiliates	8			(3)			(8)			1			—			—			—			1
Unrealized gains (losses) from hedging activities	(41)			(66)			4			110			19			8			(192)			102
Unrealized gains (losses) from hedging activities with affiliates	—			(5)			—			1			—			—			—			4
Ancillary and other costs	(141)			(156)			(25)			(15)			(2)			(3)			(2)			(6)
Fuel, purchased power costs and delivery fees	(839)			(1,223)			(1,119)			(1,541)			(180)			(124)			(423)			(181)











Net income (loss)	$	(42)		$	(3,610)		$	1,020		$	(791)		$	216		$	(36)		$	486		$	(556)















Adjusted EBITDA	$	590		$	351		$	212		$	312		$	109		$	66		$	203		$	22
Production volumes (GWh):
Natural gas facilities	17,174			13,650			28,494			25,754			2,276			2,065
Lignite and coal facilities	11,160			11,733															6,317			10,523
Nuclear facilities	9,261			9,360
Solar facilities	391			429
Capacity factors:
CCGT facilities	47.0		%	38.9		%	59.6		%	54.7		%	51.3		%	45.8		%
Lignite and coal facilities	66.7		%	70.2		%													31.8		%	52.9		%
Nuclear facilities	88.8		%	89.8		%
Weather - percent of normal (a):
Cooling degree days	102.9		%	122.9		%	65.6		%	96.0		%	29.0		%	100.9		%	108.0		%	126.0		%
Heating degree days	81.5		%	128.1		%	85.1		%	99.4		%	154.4		%	98.1		%	86.1		%	103.7		%

____________

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

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	Six Months Ended June 30,					Six Months Ended June 30,
	2023		2022			2023		2022
Market pricing					Average Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)	$	29.29	$	50.07	PJM West Hub	$	35.87	$	75.68
					AEP Dayton Hub	$	34.27	$	72.45
Average NYMEX Henry Hub natural gas price ($/MMBtu)	$	2.40	$	6.01	NYISO Zone C	$	27.49	$	61.32
					Massachusetts Hub	$	42.28	$	94.11
Average natural gas price (a):					Indiana Hub	$	37.77	$	75.53
TetcoM3 ($/MMBtu)	$	2.21	$	6.75	Northern Illinois Hub	$	29.81	$	64.72
Algonquin Citygates ($/MMBtu)	$	3.57	$	10.41	CAISO NP15	$	66.72	$	60.06

___________

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

(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 changes in net income (loss) and Adjusted EBITDA for the six months ended June 30, 2023 compared to the six months ended June 30, 2022.


	Six Months Ended June 30, 2023 Compared to 2022
	Texas		East		West		Sunset

Favorable/(unfavorable) change in revenue net of fuel	$	345	$	(74)	$	41	$	191

Unfavorable change in other operating costs	(54)		(22)		(6)		(3)
Favorable/(unfavorable) change in selling, general and administrative expenses	12		(4)		(1)		(8)
Other	(64)		—		9		1
Change in Adjusted EBITDA	$	239	$	(100)	$	43	$	181
Favorable/(unfavorable) change in depreciation and amortization	8		30		(3)		3
Change in unrealized net gains on hedging activities	3,350		1,887		206		925
Impairment of long-lived assets	—		—		—		(49)
Generation plant retirement expenses	—		—		—		2
Fresh start/purchase accounting impacts	1		(3)		—		(1)


PJM capacity performance default impacts	—		(6)		—		(2)
Winter Storm Uri impact (ERCOT default uplift)	(53)		—		—		—
Other (including interest expenses)	23		3		6		(17)
Change in Net income (loss)	$	3,568	$	1,811	$	252	$	1,042

The favorable change in Texas segment results was primarily driven by lower unrealized hedging losses due to decreases in forward power prices in the six months ended June 30, 2023 compared to the six months ended June 30, 2022. The change in Texas segment results was also driven by higher revenue net of fuel in the six months ended June 30, 2023 compared to the six months ended June 30, 2022 due to strong generation performance during periods of higher pricing and the effectiveness of our comprehensive hedging strategy.

The favorable changes in East, West and Sunset segment results were primarily driven by unrealized hedging gains due to decreases in forward power prices in the six months ended June 30, 2023 compared to unrealized hedging losses due to increases in power prices in the six months ended June 30, 2022.

The change in East segment results was also driven by lower revenue net of fuel in the six months ended June 30, 2023 compared to the six months ended June 30, 2022 due primarily to higher-than-expected migration of customers to default service providers at rates below prevailing wholesale market prices in the first quarter of 2023.

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The change in West segment results was driven by higher revenue net of fuel in the six months ended June 30, 2023 compared to the six months ended June 30, 2022 due to increased output from battery ESS assets which were partially offline in 2022 (see Note 3).

The change in Sunset segment results was also driven by higher revenue net of fuel in the six months ended June 30, 2023 compared to the six months ended June 30, 2022 due primarily to the effectiveness of our comprehensive hedging strategy. A $49 million impairment of assets related to our Kincaid generation facility was recognized in the first quarter of 2023. See Note 19 to the Financial Statements for more information concerning the impairment.

Asset Closure Segment — Three and Six Months Ended June 30, 2023 Compared to Three and Six Months Ended June 30, 2022


	Three Months Ended June 30,				Favorable (Unfavorable) Change		Six Months Ended June 30,				Favorable (Unfavorable) Change
	2023		2022				2023		2022
Operating revenues	$	—	$	117	$	(117)	$	—	$	202	$	(202)
Fuel, purchased power costs and delivery fees	—		(116)		116		(1)		(236)		235
Operating costs	$	(18)	$	(43)	$	25	$	(38)	$	(93)	$	55
Depreciation and amortization	—		(11)		11		—		(28)		28
Selling, general and administrative expenses	(8)		(10)		2		(16)		(21)		5


Operating loss	(26)		(63)		37		(55)		(176)		121
Other income	95		6		89		98		8		90
Other deductions	—		—		—		—		(1)		1
Interest expense and related charges	(2)		(1)		(1)		(3)		(1)		(2)

Income (loss) before income taxes	67		(58)		125		40		(170)		210

Net income (loss)	$	67	$	(58)	$	125	$	40	$	(170)	$	210











Adjusted EBITDA	$	59	$	(19)	$	78	$	18	$	(19)	$	37
Production volumes (GWh)	—		3,308		(3,308)		—		7,204		(7,204)

For the three and six months ended June 30, 2022, results and volumes for the Asset Closure segment include those from Edwards generation plant that we retired on January 1, 2023, and include unrealized hedging losses related to coal and power derivatives of $9 million and $42 million in the three and six months ended June 30, 2022, respectively. Operating costs for the three and six months ended June 30, 2023 and 2022 also include ongoing costs associated with the decommissioning and reclamation of retired plants and mines. Other income for the three and six months ended June 30, 2023, includes a gain of $89 million from the sale of property in Freestone County, Texas. Results were also favorably impacted in the three and six months ended June 30, 2023 compared to the three and six months ended June 30, 2022 by the retirements of the Zimmer, Joppa and Edwards generation plants on June 1, 2022, September 1, 2022 and January 1, 2023, respectively.

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

The table below summarizes the changes in commodity contract assets and liabilities for the six months ended June 30, 2023 and 2022. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $1.139 billion in unrealized net gains and $2.347 billion in unrealized net losses for the six months ended June 30, 2023 and 2022, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.


	Six Months Ended June 30,
	2023		2022
Commodity contract net liability at beginning of period	$	(3,148)	$	(866)
Settlements/termination of positions (a)	799		319
Changes in fair value of positions in the portfolio (b)	340		(2,666)

Other activity (c)	(39)		37
Commodity contract net liability at end of period	$	(2,048)	$	(3,176)

____________

(a)Represents reversals of previously recognized unrealized gains/(losses) upon settlement/termination (offsets realized gains and 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)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.

Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair values as of June 30, 2023, 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 June 30, 2023
Source of fair value	Less than 1 year		1-3 years		4-5 years		Excess of 5 years		Total
Prices actively quoted	$	(462)	$	(298)	$	2	$	—	$	(758)
Prices provided by other external sources	(108)		(62)		—		—		(170)
Prices based on models	(265)		(541)		(164)		(150)		(1,120)
Total	$	(835)	$	(901)	$	(162)	$	(150)	$	(2,048)

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FINANCIAL CONDITION

Operating Cash Flows

Cash provided by operating activities totaled $3.012 billion for the six months ended June 30, 2023 and cash used in operating activities totaled $723 million for the six months ended June 30, 2022. The favorable change of $3.735 billion was primarily driven by a decrease in net margin deposits of $2.014 billion in the six months ended June 30, 2023 as compared to an increase in net margin deposits of $1.893 billion in the six months ended June 30, 2022 related to commodity contracts which support our comprehensive hedging strategy, including the impacts of cash margin deposits returned and replaced with amounts posted under an affiliate financing agreement (see Note 11 to the Financial Statements), partially offset by $544 million of securitization proceeds from ERCOT in 2022 (see Note 1 to the Financial Statements).

Depreciation and amortization expense reported as a reconciling adjustment in the condensed consolidated statements of cash flows exceeds the amount reported in the condensed consolidated statements of operations by $206 million and $230 million for the six months ended June 30, 2023 and 2022, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the condensed consolidated statements of operations consistent with industry practice, and amortization of intangible net assets and liabilities that are reported in various other condensed consolidated statements of operations line items including operating revenues and fuel and purchased power costs and delivery fees.

Investing Cash Flows

Cash used in investing activities totaled $967 million and $609 million for the six months ended June 30, 2023 and 2022, respectively. The increase of $358 million was driven by a $313 million increase in capital expenditures due primarily to continued development of our solar and energy storage generation facilities (see Note 3 to the Financial Statements) and $151 million in higher net purchases of environmental allowances, partially offset by $96 million in higher proceeds from the sale of assets driven by our sale of property in Freestone County, Texas in 2023.


	Six Months Ended June 30,				Increase (Decrease)
	2023		2022
Capital expenditures, including LTSA prepayments	$	(407)	$	(293)	$	(114)
Nuclear fuel purchases	(117)		(117)		—
Growth and development expenditures	(402)		(203)		(199)
Total capital expenditures	(926)		(613)		(313)
Net sales (purchases) of environmental allowances	(143)		8		(151)
Net sales of (investments in) nuclear decommissioning trust fund securities	(11)		(11)		—

Proceeds from sales of assets	110		14		96
Other investing activity	3		(7)		10
Cash used in investing activities	$	(967)	$	(609)	$	(358)

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Financing Cash Flows

Cash used in financing activities totaled $1.872 billion in the six months ended June 30, 2023 and cash provided by financing activities totaled $1.880 billion for the six months ended June 30, 2022. The $3.752 billion increase in cash used was primarily driven by (a) $1.075 billion of net repayments of short-term debt and accounts receivable financing in the six months ended June 30, 2023 compared to $2.025 billion of net borrowings of short-term debt and accounts receivable financing in the six months ended June 30, 2022 driven by changes in collateral posting requirements and (b) $1.5 billion principal amount of senior secured notes issued in May 2022, partially offset by lower share repurchases in 2023.


	Six Months Ended June 30,				Increase (Decrease)
	2023		2022
Share repurchases	$	(552)	$	(1,194)	$	642
Issuances of senior secured notes in May 2022 (see Note 12)	—		1,498		(1,498)
Net long-term borrowings (repayments), including the forward capacity agreements	(14)		(223)		209
Net short-term borrowings (repayments)	(650)		1,300		(1,950)
Net borrowings (repayments) under the accounts receivable financing facilities	(425)		725		(1,150)
Dividends paid to common stockholders	(153)		(152)		(1)
Dividends paid to preferred stockholders	(75)		(76)		1
Other financing activity	(3)		2		(5)
Cash used in financing activities	$	(1,872)	$	1,880	$	(3,752)

Debt Activity

The maturities of our long-term debt are relatively modest until 2024. See Note 10 to the Financial Statements for details of the Receivables Facility and Repurchase Facility and Note 12 to the Financial Statements for details of the Vistra Operations Credit Facilities, the Commodity-Linked Facility and other long-term debt.

Available Liquidity

The following table summarizes changes in available liquidity for the six months ended June 30, 2023:


	June 30, 2023		December 31, 2022		Change
Cash and cash equivalents	$	643	$	455	$	188
Vistra Operations Credit Facilities — Revolving Credit Facility	1,503		1,236		267
Vistra Operations — Commodity-Linked Facility (a)	326		808		(482)
Total available liquidity (b)(c)	$	2,472	$	2,499	$	(27)

____________

(a)As of both June 30, 2023 and December 31, 2022, the borrowing bases are less than the facility limit of $1.35 billion. As of June 30, 2023, available capacity reflects the borrowing base of $326 million and no cash borrowings. As of December 31, 2022, available capacity reflects the borrowing base of $1.208 billion less $400 million in cash borrowings. The reduction in the borrowing base is due, in part, to the expiration of certain deemed 2023 hedges and would increase in size in a rising commodity price environment in accordance with the terms of the Commodity-Linked Facility.

(b)Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See Note 10 to the Financial Statements for detail on our accounts receivable financing.

(c)Excludes any additional letters of credit that may be issued under the Secured LOC Facilities. See Note 12 to the Financial Statements for detail on our Secured LOC Facilities.

The $27 million decrease in available liquidity for the six months ended June 30, 2023 was primarily driven by (a) a $482 million decrease in availability under the Commodity-Linked Facility, primarily due to a reduction of the borrowing base of $882 million due to a decrease in commodity prices and partially offset by the repayment of $400 million in borrowings under the facility, (b) a $425 million decrease in net cash borrowings under the accounts receivable financing facilities and (c) the maturity of $200 million of commitments under the Non-Extended Revolving Credit Facility, partially offset by cash provided by operations and a $217 million decrease in letters of credit outstanding under the Revolving Credit Facility.

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

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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 11 to the Financial Statements) and other forms of credit support to satisfy such collateral posting obligations. See Note 12 to the Financial Statements for discussion of the Vistra Operations Credit Facilities and the Commodity-Linked Facility.

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

As of June 30, 2023, we received or posted cash and letters of credit for commodity hedging activities as follows:

•$1.573 billion in cash or Eligible Assets have been posted with counterparties as compared to $3.137 billion posted as of December 31, 2022;

•$46 million in cash has been received from counterparties as compared to $39 million received as of December 31, 2022;

•$2.136 billion in letters of credit have been posted with counterparties as compared to $2.314 billion posted as of December 31, 2022; and

•$74 million in letters of credit have been received from counterparties as compared to $74 million received as of December 31, 2022.

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 do not expect to make federal income tax payments due to Vistra's NOL carryforwards. We expect to make approximately $32 million in state income tax payments, offset by $4 million in state tax refunds, and $10 million in TRA payments in the next 12 months.

For the six months ended June 30, 2023, there were no federal income tax payments, $19 million in state income tax payments, $9 million in state income tax refunds and no TRA payments.

Financial Covenants

The Vistra Operations Credit Agreement and the Vistra Operations Commodity-Linked Credit Agreement each includes a covenant, solely with respect to the Revolving Credit Facility and the Commodity-Linked Facility and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit exceed 30% of the revolving commitments, provided that solely with respect to the Revolving Credit Facility only such amounts in excess of $300 million are taken into account for purposes of determining whether a compliance period is in effect), that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, during a collateral suspension period, 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, not to exceed 5.50 to 1.00). As of June 30, 2023, we were in compliance with the Vistra Operations Credit Agreement and Secured LOC Facilities financial covenants. Although the period ended June 30, 2023 was not a compliance period for the Vistra Operations Commodity-Linked Credit Agreement, we would have been in compliance with this financial covenant if it was required to be tested at such time.

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See Note 12 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 June 30, 2023, Vistra has posted letters of credit in the amount of $89 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 $594 million in the form of letters of credit, $30 million in the form of a surety bond and $2 million of cash as of June 30, 2023 (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 $300 million 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 $2.500 billion and zero, respectively, as of June 30, 2023.

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 and TriEagle, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), 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, 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.

Guarantees

See Note 13 to the Financial Statements for discussion of guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 13 to the Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

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

Item 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Risk Oversight

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

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

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Commodity Price Risk

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

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

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

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

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


	Six Months Ended June 30, 2023		Year Ended December 31, 2022
Month-end average VaR	$	243	$	489
Month-end high VaR	$	423	$	686
Month-end low VaR	$	172	$	283

The month-end high VaR risk measure in 2023 is currently lower than the prior year due to lower prices and higher hedge levels.

Interest Rate Risk

As of June 30, 2023, 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 $2 million taking into account the interest rate swaps discussed in Note 12 to Financial Statements.

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 16 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 $1.960 billion as of June 30, 2023.

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As of June 30, 2023, Retail segment credit exposure totaled approximately $1.348 billion, including $1.292 billion of trade accounts receivable and $56 million related to derivatives. Cash deposits and letters of credit held as collateral for these receivables totaled $52 million, resulting in a net exposure of $1.296 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 June 30, 2023, aggregate Texas, East, Sunset and Asset Closure segments credit exposure totaled $612 million including $501 million related to derivative assets and $111 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 credit exposure was $546 million, as seen in the following table that presents the distribution of credit exposure by counterparty credit quality as of June 30, 2023. 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
Investment grade	$	519	$	22	$	497
Below investment grade or no rating	93		44		49
Totals	$	612	$	66	$	546

Significant (i.e., 10% or greater) concentration of credit exposure exists with two counterparties, which represented an aggregate $235 million, or 43%, of our total net exposure as of June 30, 2023. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the counterparties' credit ratings, the counterparties' market role and deemed creditworthiness and the importance of our business relationship with the 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.

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.

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FORWARD-LOOKING STATEMENTS

This report and other presentations made by us contain "forward-looking statements." All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that may occur in the future, including (without limitation) such matters as activities related to our financial or operational projections, capital allocation, capital expenditures, liquidity, dividend policy, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our businesses and operations (often, but not always, through the use of words or phrases such as "intends," "plans," "will likely," "unlikely," "expected," "anticipated," "estimated," "should," "may," "projection," "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 under Part II, Item 1A Risk Factors and Part I, Item 2 Management's Discussion and Analysis of Financial Condition and Results of Operations in this quarterly report on Form 10-Q and the following important factors, among others, that could cause our actual results to differ materially from those projected in or implied by such forward-looking statements:

•our ability to consummate the acquisition of Energy Harbor;

•the actions and decisions of judicial and regulatory authorities;

•prohibitions and other restrictions on our operations due to the terms of our agreements;

•prevailing federal, state and local governmental policies and regulatory actions, including those of the legislatures and other government actions of states in which we operate, the U.S. Congress, the FERC, the NERC, the TRE, the public utility commissions of states and locales in which we operate, CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM, the RCT, the NRC, the EPA, the environmental regulatory bodies of states in which we operate, the MSHA and the CFTC, with respect to, among other things:

▪allowed prices;

▪industry, market and rate structure;

▪purchased power and recovery of investments;

▪operations of nuclear generation facilities;

▪operations of fossil-fueled generation facilities;

▪operations of mines;

▪acquisition and disposal of assets and facilities;

▪development, construction and operation of facilities;

▪decommissioning costs;

▪present or prospective wholesale and retail competition;

▪changes in federal, state and local tax laws, rates and policies, including additional regulation, interpretations, amendments, or technical corrections to The Tax Cuts and Jobs Act of 2017 and/or the IRA;

▪changes in and compliance with environmental and safety laws and policies, including the Coal Combustion Residuals Rule, National Ambient Air Quality Standards, the Cross-State Air Pollution Rule, the Mercury and Air Toxics Standard, regional haze program implementation and GHG and other climate change initiatives, and

▪clearing over-the-counter derivatives through exchanges and posting of cash collateral therewith;

•expectations regarding, or impacts of, environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts, and other laws and regulations that we are, or could become, subject to, which could increase our costs, result in an impairment of our assets, cause us to limit or terminate the operation of certain of our facilities, or otherwise negatively impact our financial results or stock price;

•legal and administrative proceedings and settlements;

•general industry trends;

•economic conditions, including the impact of any inflationary period, recession or economic downturn;

•investor sentiment relating to climate change and utilization of fossil fuels in connection with power generation could reduce demand for, or increase potential volatility in the market price of, our common stock;

•the severity, magnitude and duration of pandemics, including the COVID-19 pandemic, and the resulting effects on our results of operations, financial condition and cash flows;

•the severity, magnitude and duration of extreme weather events, drought and limitations on access to water, and other weather conditions and natural phenomena, contingencies and uncertainties relating thereto, most of which are difficult to predict and many of which are beyond our control, and the resulting effects on our results of operations, financial condition and cash flows;

•acts of sabotage, geopolitical conflicts, wars, or terrorist, cybersecurity, cybercriminal, or cyber-espionage threats or activities;

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•risk of contract performance claims by us or our counterparties, and risks of, or costs associated with, pursuing or defending such claims;

•our ability to collect trade receivables from counterparties in the amount or at the time expected, if at all;

•our ability to attract, retain and profitably serve customers;

•restrictions on or prohibitions of competitive retail pricing or direct-selling businesses;

•adverse publicity associated with our retail products or direct selling businesses, including our ability to address the marketplace and regulators regarding our compliance with applicable laws;

•changes in wholesale electricity prices or energy commodity prices, including the price of natural gas;

•changes in prices of transportation of natural gas, coal, fuel oil and other refined products;

•sufficiency of, access to, and costs associated with coal, fuel oil, natural gas, and uranium inventories and transportation and storage thereof;

•changes in the ability of counterparties and suppliers to provide or deliver commodities, materials, or services as needed;

•beliefs and assumptions about the benefits of state- or federal-based subsidies to our market competition, and the corresponding impacts on us, including if such subsidies are disproportionately available to our competitors;

•the effects of, or changes to, market design and the power, ancillary services and capacity procurement processes in the markets in which we operate;

•changes in market heat rates in the CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM electricity markets;

•our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heat rates and interest rates;

•population growth or decline, or changes in market supply or demand and demographic patterns;

•our ability to mitigate forced outage risk, including managing risk associated with Capacity Performance in PJM and performance incentives in ISO-NE;

•efforts to identify opportunities to reduce congestion and improve busbar power prices;

•access to adequate transmission facilities to meet changing demands;

•changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;

•changes in operating expenses, liquidity needs and capital expenditures;

•commercial bank market and capital market conditions and the potential impact of disruptions in U.S. and international credit markets;

•access to capital, the attractiveness of the cost and other terms of such capital and the success of financing and refinancing efforts, including availability of funds in capital markets;

•our ability to maintain prudent financial leverage and achieve our capital allocation, performance, and cost-saving initiatives and objectives;

•our ability to generate sufficient cash flow to make principal and interest payments in respect of, or refinance, our debt obligations;

•our expectation that we will continue to pay (i) a consistent aggregate cash dividend amount to common stockholders on a quarterly basis and (ii) the applicable semiannual cash dividend to the Series A Preferred Stock and Series B Preferred Stock stockholders, respectively;

•our expectation that we will continue to make repurchases under, and the possibility that we may fail to realize the anticipated benefits of, our share repurchase program, and the possibility that the program may be suspended, discontinued or not completed prior to its termination;

•our ability to implement and successfully execute upon our strategic and growth initiatives, including the completion and integration of mergers, acquisitions and/or joint venture activity, the identification and completion of sales and divestitures activity, and the completion and commercialization of our other business development and construction projects;

•competition for new energy development and other business opportunities;

•inability of various counterparties to meet their obligations with respect to our financial instruments;

•counterparties' collateral demands and other factors affecting our liquidity position and financial condition;

•changes in technology (including large-scale electricity storage) used by and services offered by us;

•changes in electricity transmission that allow additional power generation to compete with our generation assets;

•our ability to attract and retain qualified employees;

•significant changes in our relationship with our employees, including the availability of qualified personnel, and the potential adverse effects if labor disputes or grievances were to occur or changes in laws or regulations relating to independent contractor status;

•changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits, pension and other postretirement employee benefits, and future funding requirements related thereto, including joint and several liability exposure under ERISA;

•hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resulting from such hazards;

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•the impact of our obligations under the TRA;

•our ability to optimize our assets through targeted investment in cost-effective technology enhancements and operations performance initiatives;

•our ability to effectively and efficiently plan, prepare for and execute expected asset retirements and reclamation obligations and the impacts thereof;

•our ability to successfully complete the integration of businesses acquired by Vistra and our ability to successfully capture the full amount of projected operational and financial synergies relating to such transactions, and

•actions by credit rating agencies.

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.

INDUSTRY AND MARKET INFORMATION

Certain industry and market data and other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including certain data published by CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM, the environmental regulatory bodies of states in which we operate and NYMEX. We did not commission any of these publications, reports or other sources. Some data is also based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sources listed above. Industry publications, reports and other sources generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of these studies, publications, reports and other sources is reliable, we have not independently investigated or verified the information contained or referred to therein and make no representation as to the accuracy or completeness of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we do not know what assumptions were used in preparing such forecasts. Statements regarding industry and market data and other statistical information used throughout this report involve risks and uncertainties and are subject to change based on various factors.

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 June 30, 2023. 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, 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) 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 13 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 2022 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.

The Transactions are subject to a number of conditions which, if not satisfied or waived, would delay the Transactions or adversely impact our ability to complete the Transactions on the terms set forth in the Transaction Agreement or at all.

The completion of the Transactions is subject to the satisfaction or waiver of a number of conditions, including (a) receipt of all requisite regulatory approvals, including approvals of the NRC and the FERC, (b) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and (c) the divestment of Energy Harbor's remaining fossil assets. These closing conditions may not be fulfilled in a timely manner or at all, and, accordingly, the Transactions may not be completed.

If we are unable to complete the Transactions, we still will incur and will remain liable for significant transaction costs, including legal, accounting, advisory and other costs relating to the Transactions. Also, depending upon the reasons for not completing the Transactions, we may be required to pay Energy Harbor a termination fee of $225 million. If such a termination fee is payable, the payment could affect Vistra's share price and the overall cash flows of the Company.

Failure to consummate the Transactions as currently contemplated or at all could adversely affect the price of Vistra's common stock and our future business and financial results.

The completion of the Transactions is subject to the satisfaction or waiver of a number of conditions. We cannot guarantee when or if these conditions will be satisfied or that the Transactions will be successfully completed. If the Transactions are not consummated, or are consummated on different terms than as contemplated by the Transaction Agreement, we could be adversely affected and subject to a variety of risks associated with the failure to consummate the Transactions, or to consummate the Transactions as contemplated by the Transaction Agreement, including:

•our stockholders may be prevented from realizing the anticipated potential benefits of the Transactions;

•the market price of our common stock could decline significantly;

•reputational harm due to the adverse public perception of any failure to successfully complete the Transactions;

•under certain circumstances, we may be required to pay Energy Harbor a termination fee of up to $225 million or reimburse Energy Harbor's expenses up to $20 million; and

•the attention of our management and employees may be diverted from their day-to-day business and operational matters and our relationships with our customers and suppliers may be disrupted as a result of efforts relating to attempting to consummate the Transactions.

Any delay in the consummation of the Transactions, any uncertainty about the consummation of the Transactions on terms other than those contemplated by the Transaction Agreement and any failure to consummate the Transactions could adversely affect our business, financial results and common stock price.

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Following the completion of the Transactions, we may be unable to successfully integrate Energy Harbor's businesses with Vistra's nuclear and retail businesses and its Vistra Zero renewable and energy storage projects or realize the anticipated synergies and other expected benefits of the Transactions on the anticipated timeframe or at all.

The Transactions involve the combination of Energy Harbor's nuclear and retail businesses with Vistra's nuclear and retail businesses and Vistra Zero renewables and energy storage projects under a newly-formed subsidiary holding company, Vistra Vision. This new combination expects to benefit from certain cost savings, operating efficiencies and a growing renewables and energy storage portfolio, some of which will take time to realize. We will be required to devote significant management attention and resources to the integration of our and Energy Harbor's business practices and operations into Vistra Vision. The potential difficulties we may encounter in building Vistra Vision include the following:

•the inability to successfully combine our nuclear, retail, renewables and battery storage business and Energy Harbor's nuclear and retail businesses in a manner that permits Vistra Vision to achieve the cost savings anticipated to result from the Transactions, which would result in the anticipated benefits of the Transactions not being realized in the timeframe currently anticipated or at all;

•the complexities associated with maintaining the second-largest competitive nuclear fleet in the U.S.;

•the complexities of combining two companies with different histories, geographic footprints and asset mixes;

•the complexities in combining two companies with separate technology systems;

•potential unknown liabilities and unforeseen increased expenses, delays or conditions associated with the Transactions;

•failure to perform by third-party service providers who provide key services for the combined company; and

•performance shortfalls as a result of the diversion of management’s attention caused by completing the Transactions and integrating the companies' operations.

For all these reasons, it is possible that the integration process could result in the distraction of our management, the disruption of our ongoing business or inconsistencies in operations, services, standards, controls, policies and procedures, any of which could adversely affect our ability to maintain relationships with operators, vendors and employees, to achieve the anticipated benefits of the Transactions, or could otherwise materially and adversely affect its business and financial results.

In consummating the Transactions, Vistra Operations will take on a significant amount of indebtedness. As a result, it may be more difficult for Vistra Operations to pay or refinance its debts or take other actions, and Vistra Operations may need to divert its cash flow from operations (including cash flow from the new Vistra Vision entity) to debt service payments.

Vistra Operations will have significant indebtedness following completion of the Transactions. Initially a substantial portion of such indebtedness will be subject to rising changes in interest rates. In addition, subject to the limits contained in the documents governing such indebtedness, Vistra Operations may be able to incur significant additional debt from time to time to finance working capital, capital expenditures, investments or acquisitions, or for other purposes. If the combined company does so, the risks related to its high level of debt could intensify. The amount of such indebtedness could have material adverse consequences for Vistra Operations, including:

•hindering its ability to adjust to changing market, industry or economic conditions;

•limiting its ability to access the capital markets to raise additional equity or refinance maturing debt on favorable terms or to fund future working capital, capital expenditures, acquisitions or emerging businesses or other general corporate purposes;

•limiting the amount of free cash flow available for future operations, acquisitions, dividends, stock repurchases or other uses;

•making it more vulnerable to economic or industry downturns, including interest rate increases; and

•placing it at a competitive disadvantage compared to less leveraged competitors.

Moreover, to respond to competitive challenges, Vistra Operations may be required to raise significant additional capital to execute its business strategy. Vistra Operations' ability to arrange additional financing will depend on, among other factors, its financial position and performance, as well as prevailing market conditions and other factors beyond its control. Even if Vistra Operations is able to obtain additional financing, its credit ratings could be adversely affected, which could raise its borrowing costs and limit its future access to capital and its ability to satisfy its obligations under its indebtedness.

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

The following table provides information about our repurchase of equity securities that are registered by us pursuant to Section 12 of the Exchange Act, as amended, during the quarter ended June 30, 2023.


	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)
April 1 - April 30, 2023	4,303,418	$	24.17	4,303,418	$	1,593
May 1 - May 31, 2023	3,292,012	$	24.08	3,292,012	$	1,514
June 1 - June 30, 2023	2,549,461	$	25.17	2,549,461	$	1,450
For the quarter ended June 30, 2023	10,144,891	$	24.39	10,144,891	$	1,450

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 and March 2023, the Board authorized incremental amounts of $1.25 billion and $1.0 billion, respectively, for repurchases to bring the total authorized under the Share Repurchase Program to $4.25 billion. We expect to complete repurchases under the Share Repurchase Program by the end of 2024.

Under the Share Repurchase Program, any purchases of shares of the Company's stock may be repurchased from time to time 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 certificate of designation of the Series A Preferred Stock and the Series B Preferred Stock, respectively.

See Note 14 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 June 30, 2023, 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".

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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(ii))	By-laws

3.3	001-38086 Form 10-K (Year ended December 31, 2021) (filed February 25, 2022)	3.5	—	Amended and Restated Bylaws of Vistra Corp., effective February 23, 2022

(4)	Instruments Defining the Rights of Security Holders, Including Indentures

4.1	0001-38086 Form 8-K (filed June 22, 2023)	4.1	—	Facility Agreement, dated June 15, 2023, among Palomino Funding Trust I, Vistra Operations Company LLC, the subsidiary guarantors party thereto and Bank of New York Mellon Trust Company, N.A., as senior secured notes trustee

4.2	0001-38086 Form 8-K (filed June 22, 2023)	4.2	—	Amended and Restated Declaration of Trust of Palomino Funding Trust I, dated June 15, 2023, among Vistra Operations Company LLC, as depositor, The Bank of New York Mellon Trust Company, N.A., as trustee, BNY Mellon Trust of Delaware, as Delaware trustee, and Vistra Operations Company LLC, solely for the purposes of Sections 5.10(b) and (f), Sections 5.17(b), (d), (e) and (f) and Section 10.4(c)

4.3	0001-38086 Form 8-K (filed June 22, 2023)	4.3	—	Indenture, dated June 15, 2023, between Vistra Operations Company LLC, as issuer, and The Bank of New York Mellon Trust Company, N.A., as trustee

4.4	0001-38086 Form 8-K (filed June 22, 2023)	4.4	—	Supplemental Indenture, dated June 15, 2023, between Vistra Operations Company LLC, as issuer, the subsidiary guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee

4.5	0001-38086 Form 8-K (filed June 22, 2023)	4.5	—	Form of 7.233% Senior Secured Notes due 2028 (included in Exhibit 4.4)

4.6	0001-38086 Form 8-K (filed July 17, 2023)	4.1	—	Thirteenth Amendment to Receivables Purchase Agreement, dated as of July 11, 2023, 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

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Exhibits	Previously Filed With File Number*	As Exhibit
(10)	Material Contracts

10.1	**	10.1	—	Thirteenth Amendment to the Credit Agreement, dated April 27, 2023, by and among Vistra Operations Company LLC (as Borrower), Vistra Intermediate Company LLC (as Holdings), the other Credit Parties (as defined in the Credit Agreement) party thereto, financial institutions, Revolving Credit Lenders, and Revolving Letter of Credit Issuers (in each case as defined in the Credit Agreement) party thereto, and Credit Suisse AG, Cayman Islands Branch (as Administrative Agent and as Collateral Agent)

10.2	0001-38086 Form 8-K (filed July 17, 2023)	10.1	—	Amendment No. 4 to Master Framework Agreement, dated as of July 11, 2023, 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

10.3	0001-38086 Form 8-K (filed July 17, 2023)	10.2	—	Amendment No. 3 to Master Repurchase Agreement, dated as of July 11, 2023, by and among TXU Energy Retail Company LLC, as seller and MUFG Bank, Ltd., as buyer

(31)	Rule 13a-14(a) / 15d-14(a) Certifications

31.1	**		—	Certification of James A. Burke, principal executive officer of Vistra Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2	**		—	Certification of Kristopher E. Moldovan, principal financial officer of Vistra Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

(32)	Section 1350 Certifications

32.1	***		—	Certification of James A. Burke, principal executive officer of Vistra Corp., pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2	***		—	Certification of Kristopher E. Moldovan, principal financial officer of Vistra Corp., pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

(95)	Mine Safety Disclosures

95.1	**		—	Mine Safety Disclosures

	XBRL Data Files

101.INS	**		—	The following financial information from Vistra Corp.'s Quarterly Report on Form 10-Q for the period ended June 30, 2023 formatted in Inline XBRL (Extensible Business Reporting Language) includes: (i) the Condensed Consolidated Statements of Operations, (ii) the Condensed Consolidated Statements of Comprehensive Income (Loss), (iii) the Condensed Consolidated Statements of Cash Flows, (iv) the Condensed Consolidated Balance Sheets and (v) 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

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____________________

* Incorporated herein by reference

** Filed herewith

*** Furnished herewith

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SIGNATURE

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

Vistra Corp.

By:

/s/ CHRISTY DOBRY

Name:

Christy Dobry

Title:

Senior Vice President and Controller

(Principal Accounting Officer)

Date: August 9, 2023