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, 2022~~MARCH 31, 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 2, 2022,~~May 4, 2023, there were ~~416,348,199~~373,027,363 shares of common stock, par value $0.01, outstanding of Vistra Corp.

Table of Contents

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~~March 31 , ~~2022~~202 3 and ~~2021~~202 2	1
	Condensed Consolidated Statements of Comprehensive Income (Loss) — Three ~~and Six~~ Months Ended ~~June 30~~March 31 , ~~2022~~202 3 and ~~2021~~202 2	1
	Condensed Consolidated Statements of Cash Flows — ~~Six~~Three Months Ended ~~June 30~~March 31 , ~~2022~~202 3 and ~~2021~~202 2	2
	Condensed Consolidated Balance Sheets — ~~June 30~~March 31 , ~~2022~~202 3 and December 31, ~~2021~~202 2	43
	Notes to Condensed Consolidated Financial Statements	65
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	5048
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	7668
Item 4.	Controls and Procedures	8173
PART II.	OTHER INFORMATION	8274
Item 1.	Legal Proceedings	8274
Item 1A.	Risk Factors	8274
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	8276
Item 3.	Defaults Upon Senior Securities	8276
Item 4.	Mine Safety Disclosures	8376
Item 5.	Other Information	8376
Item 6.	Exhibits	8376
SIGNATURE		8679

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.

Table of Contents

GLOSSARY

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


~~2021~~2022 Form 10-K						Vistra's annual report on Form 10-K for the year ended December 31, ~~2021,~~2022, filed with the SEC on ~~February 25, 2022~~March 1, 2023
Ambit ~~or Ambit Energy~~						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

Table of Contents


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

~~Table of Contents~~


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						~~the merger~~Black Pen Inc., an indirect, wholly owned subsidiary of ~~Dynegy with and into~~ Vistra ~~with Vistra as the surviving corporation~~
~~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~~
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						~~Vistra Preferred Inc.~~
~~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 ~~PrefCo~~Vistra Preferred Inc. (PrefCo) in exchange for all of PrefCo's authorized preferred stock, consisting of 70,000 shares, par value $0.01 per share
~~Preferred Stock~~						~~Vistra's Series A Preferred Stock and Series B Preferred Stock~~
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
~~SG&A~~						~~selling, general and administrative~~
SO2						sulfur dioxide

iii

Table of Contents


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

~~iii~~

~~Table of Contents~~


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 78 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, Inc. (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 1011 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 1011 to the Financial Statements)
Vistra Zero						Vistra Zero LLC

Table of Contents

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,					Three Months Ended March 31,
		2022		2021		2022		2021				2023		2022
Operating revenues (Note 4)		$	1,588	$	2,565	$	4,713	$	5,772
Operating revenues (Note 5)										Operating revenues (Note 5)		$	4,425	$	3,125
Fuel, purchased power costs and delivery fees	Fuel, purchased power costs and delivery fees	(2,162)		(1,320)		(4,441)		(6,065)		Fuel, purchased power costs and delivery fees		(2,170)		(2,279)
Operating costs	Operating costs	(435)		(429)		(851)		(801)		Operating costs		(421)		(416)
Depreciation and amortization	Depreciation and amortization	(394)		(464)		(824)		(887)		Depreciation and amortization		(366)		(430)
Selling, general and administrative expenses	Selling, general and administrative expenses	(280)		(252)		(569)		(502)		Selling, general and administrative expenses		(288)		(288)

Impairment of long-lived assets (Note 17)		—		(38)		—		(38)
Impairment of long-lived assets (Note 18)										Impairment of long-lived assets (Note 18)		(49)		—
Operating income (loss)	Operating income (loss)	(1,683)		62		(1,972)		(2,521)		Operating income (loss)		1,131		(288)
Other income (Note 17)		71		36		77		92
Other deductions (Note 17)		(9)		(2)		(13)		(7)
Interest expense and related charges (Note 17)		(109)		(135)		(116)		(164)
Impacts of Tax Receivable Agreement (Note 7)		(34)		(41)		(115)		(4)
Other income (Note 18)										Other income (Note 18)		20		5
Other deductions (Note 18)										Other deductions (Note 18)		(3)		(4)
Interest expense and related charges (Note 18)										Interest expense and related charges (Note 18)		(207)		(7)
Impacts of Tax Receivable Agreement (Note 8)										Impacts of Tax Receivable Agreement (Note 8)		(65)		(81)

Net loss before income taxes		(1,764)		(80)		(2,139)		(2,604)
Income tax benefit (Note 6)		407		115		498		600
Net income (loss) before income taxes										Net income (loss) before income taxes		876		(375)
Income tax (expense) benefit (Note 7)										Income tax (expense) benefit (Note 7)		(178)		91
Net income (loss)	Net income (loss)	$	(1,357)	$	35	$	(1,641)	$	(2,004)	Net income (loss)		$	698	$	(284)
Net (income) loss attributable to noncontrolling interest	Net (income) loss attributable to noncontrolling interest	(8)		1		(9)		(2)		Net (income) loss attributable to noncontrolling interest		1		(1)
Net income (loss) attributable to Vistra	Net income (loss) attributable to Vistra	$	(1,365)	$	36	$	(1,650)	$	(2,006)	Net income (loss) attributable to Vistra		$	699	$	(285)
Cumulative dividends attributable to preferred stock	Cumulative dividends attributable to preferred stock	(37)		—		(75)		—		Cumulative dividends attributable to preferred stock		(38)		(38)
Net income (loss) attributable to Vistra common stock	Net income (loss) attributable to Vistra common stock	$	(1,402)	$	36	$	(1,725)	$	(2,006)	Net income (loss) attributable to Vistra common stock		$	661	$	(323)
Weighted average shares of common stock outstanding:	Weighted average shares of common stock outstanding:									Weighted average shares of common stock outstanding:
Basic	Basic	429,193,031		486,022,633		440,336,286		485,364,606		Basic		383,631,369		451,603,354
Diluted	Diluted	429,193,031		487,366,226		440,336,286		485,364,606		Diluted		387,553,379		451,603,354
Net income (loss) per weighted average share of common stock outstanding:	Net income (loss) per weighted average share of common stock outstanding:									Net income (loss) per weighted average share of common stock outstanding:
Basic	Basic	$	(3.27)	$	0.07	$	(3.92)	$	(4.13)	Basic		$	1.72	$	(0.72)
Diluted	Diluted	$	(3.27)	$	0.07	$	(3.92)	$	(4.13)	Diluted		$	1.71	$	(0.72)

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,					Three Months Ended March 31,
		2022		2021		2022		2021				2023		2022
Net income (loss)	Net income (loss)	$	(1,357)	$	35	$	(1,641)	$	(2,004)	Net income (loss)		$	698	$	(284)
Other comprehensive income, net of tax effects:	Other comprehensive income, net of tax effects:									Other comprehensive income, net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax expense of $—, $1, $— and $1)		—		1		—		3
Effects related to pension and other retirement benefit obligations (net of tax expense of $— and $—)										Effects related to pension and other retirement benefit obligations (net of tax expense of $— and $—)		1		—

Total other comprehensive income	Total other comprehensive income	—		1		—		3		Total other comprehensive income		1		—
Comprehensive income (loss)	Comprehensive income (loss)	$	(1,357)	$	36	$	(1,641)	$	(2,001)	Comprehensive income (loss)		$	699	$	(284)
Comprehensive (income) loss attributable to noncontrolling interest	Comprehensive (income) loss attributable to noncontrolling interest	(8)		1		(9)		(2)		Comprehensive (income) loss attributable to noncontrolling interest		1		(1)
Comprehensive income (loss) attributable to Vistra	Comprehensive income (loss) attributable to Vistra	$	(1,365)	$	37	$	(1,650)	$	(2,003)	Comprehensive income (loss) attributable to Vistra		$	700	$	(285)

See Notes to the Condensed Consolidated Financial Statements.

Table of Contents

VISTRA CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited) (Millions of Dollars)
Six Months Ended June 30,
2022 2021
Cash flows — operating activities:
Net loss $ (1,641) $ (2,004)
Adjustments to reconcile net loss to cash used in operating activities:
Depreciation and amortization 1,054 969
Deferred income tax benefit, net (501) (626)
Impairment of long-lived assets — 38
Unrealized net loss from mark-to-market valuations of commodities 2,347 182
Unrealized net gain from mark-to-market valuations of interest rate swaps (171) (79)
Asset retirement obligation accretion expense 17 19
Impacts of Tax Receivable Agreement 115 4
Stock-based compensation 34 25
Other, net 66 56
Changes in operating assets and liabilities:
Margin deposits, net (1,893) (240)
Uplift securitization proceeds receivable from ERCOT 544 —
Accrued interest 13 8
Accrued taxes (62) (75)
Accrued employee incentive (38) (107)
Other operating assets and liabilities (607) 773
Cash used in operating activities (723) (1,057)
Cash flows — investing activities:
Capital expenditures, including nuclear fuel purchases and LTSA prepayments (613) (546)
Proceeds from sales of nuclear decommissioning trust fund securities 334 267
Investments in nuclear decommissioning trust fund securities (345) (277)
Proceeds from sales of environmental allowances 266 64
Purchases of environmental allowances (258) (173)
Insurance proceeds 1 63
Proceeds from sale of assets 14 8
Other, net (8) 19
Cash used in investing activities (609) (575)
Cash flows — financing activities:
Issuances of long-term debt 1,498 1,250
Borrowings under Commodity-Linked Facility 2,750 —
Repayments under Commodity-Linked Facility (1,700) —
Borrowings under Term Loan A — 1,250
Repayment under Term Loan A — (1,250)
Proceeds from forward capacity agreement — 500
Repayments/repurchases of debt (223) (101)
Net borrowings under accounts receivable financing 725 361
Borrowings under Revolving Credit Facility 1,500 1,300
Repayments under Revolving Credit Facility (1,250) (1,300)
Share repurchases (1,194) (175)
Dividends paid to common stockholders (152) (147)
Dividends paid to preferred stockholders (76) —
Debt tender offer and other financing fees (21) (13)

~~Table of Contents~~

VISTRA CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited) (Millions of Dollars)
Six Months Ended June 30,
2022 2021
Other, net 23 (4)
Cash provided by financing activities 1,880 1,671
Net change in cash, cash equivalents and restricted cash 548 39
Cash, cash equivalents and restricted cash — beginning balance 1,359 444
Cash, cash equivalents and restricted cash — ending balance $ 1,907 $ 483

~~See Notes to the Condensed Consolidated Financial Statements.~~

~~Table of Contents~~

VISTRA CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited) (Millions of Dollars)
June 30,
2022 December 31,
2021
ASSETS
Current assets:
Cash and cash equivalents $ 1,871 $ 1,325
Restricted cash (Note 17) 25 21
Trade accounts receivable — net (Note 17) 1,790 1,397
Income taxes receivable 18 15
Inventories (Note 17) 601 610
Commodity and other derivative contractual assets (Note 14) 7,457 2,513
Margin deposits related to commodity contracts 3,160 1,263
Uplift securitization proceeds receivable from ERCOT (Note 1) — 544
Prepaid expense and other current assets 231 195
Total current assets 15,153 7,883
Restricted cash (Note 17) 11 13
Investments (Note 17) 1,715 2,049
Property, plant and equipment — net (Note 17) 12,784 13,056
Operating lease right-of-use assets 40 40
Goodwill (Note 5) 2,583 2,583
Identifiable intangible assets — net (Note 5) 2,042 2,146
Commodity and other derivative contractual assets (Note 14) 924 250
Accumulated deferred income taxes 1,818 1,302
Other noncurrent assets 398 361
Total assets $ 37,468 $ 29,683
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (Note 10) $ 1,300 $ —
Accounts receivable financing (Note 9) 725 —
Long-term debt due currently (Note 10) 41 254
Trade accounts payable 1,472 1,515
Commodity and other derivative contractual liabilities (Note 14) 9,934 3,023
Margin deposits related to commodity contracts 43 39
Accrued taxes other than income 145 207
Accrued interest 156 143
Asset retirement obligations (Note 17) 112 104
Operating lease liabilities 6 5
Other current liabilities 565 553
Total current liabilities 14,499 5,843
Long-term debt, less amounts due currently (Note 10) 11,949 10,477
Operating lease liabilities 37 38
Commodity and other derivative contractual liabilities (Note 14) 1,650 804
Tax Receivable Agreement obligation (Note 7) 509 394
Asset retirement obligations (Note 17) 2,338 2,346
Other noncurrent liabilities and deferred credits (Note 17) 1,083 1,489
Total liabilities 32,065 21,391

~~Table of Contents~~

VISTRA CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited) (Millions of Dollars)
June 30,
2022 December 31,
2021
Commitments and Contingencies (Note 11) 0 0
Total equity (Note 12):
Preferred stock, number of shares authorized — 100,000,000; Series A (liquidation preference — $1,000; shares outstanding: June 30, 2022 and December 31, 2021— 1,000,000); Series B (liquidation preference — $1,000; shares outstanding: June 30, 2022 and December 31, 2021 — 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, 2022 — 420,839,230; December 31, 2021 — 469,072,597)
5 5
Treasury stock, at cost (shares: June 30, 2022 — 115,372,902; December 31, 2021 — 63,856,879) (2,645) (1,558)
Additional paid-in-capital 9,890 9,824
Retained deficit (3,842) (1,964)
Accumulated other comprehensive loss (16) (16)
Stockholders' equity 5,392 8,291
Noncontrolling interest in subsidiary 11 1
Total equity 5,403 8,292
Total liabilities and equity $ 37,468 $ 29,683


VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars)
	Three Months Ended March 31,
	2023		2022
Cash flows — operating activities:
Net income (loss)	$	698	$	(284)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation and amortization	477		542
Deferred income tax expense (benefit), net	181		(84)

Impairment of long-lived and other assets	49		—


Unrealized net (gain) loss from mark-to-market valuations of commodities	(1,085)		360
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps	41		(126)
Asset retirement obligation accretion expense	9		9
Impacts of Tax Receivable Agreement	65		81
Stock-based compensation	22		14
Bad debt expense	35		30
Other, net	8		2
Changes in operating assets and liabilities:
Margin deposits, net	1,227		210

Accrued interest	(47)		(62)
Accrued taxes	(91)		(98)
Accrued employee incentive	(79)		(59)
Other operating assets and liabilities	(75)		56
Cash provided by operating activities	1,435		591
Cash flows — investing activities:
Capital expenditures, including nuclear fuel purchases and LTSA prepayments	(484)		(373)

Proceeds from sales of nuclear decommissioning trust fund securities	119		98
Investments in nuclear decommissioning trust fund securities	(125)		(103)
Proceeds from sales of environmental allowances	35		7
Purchases of environmental allowances	(61)		(116)
Insurance proceeds	3		1
Proceeds from sale of assets	2		3
Other, net	(2)		3
Cash used in investing activities	(513)		(480)
Cash flows — financing activities:




Repayments/repurchases of debt	(7)		(132)
Net borrowings under accounts receivable financing	175		500
Borrowings under Revolving Credit Facility	100		—
Repayments under Revolving Credit Facility	(350)		—

Repayments under Commodity-Linked Facility	(400)		—
Share repurchases	(301)		(710)
Dividends paid to common stockholders	(77)		(77)


Other, net	(14)		6
Cash used in financing activities	(874)		(413)
Net change in cash, cash equivalents and restricted cash	48		(302)
Cash, cash equivalents and restricted cash — beginning balance	525		1,359
Cash, cash equivalents and restricted cash — ending balance	$	573	$	1,057

See Notes to the Condensed Consolidated Financial Statements.

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VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars)
	March 31, 2023		December 31, 2022
ASSETS
Current assets:
Cash and cash equivalents	$	518	$	455
Restricted cash (Note 18)	23		37
Trade accounts receivable — net (Note 18)	1,464		2,059
Income taxes receivable	24		27
Inventories (Note 18)	629		570
Commodity and other derivative contractual assets (Note 15)	4,589		4,538
Margin deposits related to commodity contracts	1,919		3,137

Prepaid expense and other current assets	346		293
Total current assets	9,512		11,116
Restricted cash (Note 18)	32		33
Investments (Note 18)	1,832		1,729

Property, plant and equipment — net (Note 18)	12,611		12,554
Operating lease right-of-use assets	50		51

Goodwill (Note 6)	2,583		2,583
Identifiable intangible assets — net (Note 6)	1,940		1,958
Commodity and other derivative contractual assets (Note 15)	763		702
Accumulated deferred income taxes	1,475		1,710
Other noncurrent assets	319		351
Total assets	$	31,117	$	32,787
LIABILITIES AND EQUITY
Current liabilities:
Short-term borrowings (Note 11)	$	—	$	650
Accounts receivable financing (Note 10)	600		425
Long-term debt due currently (Note 11)	38		38
Trade accounts payable	1,005		1,556
Commodity and other derivative contractual liabilities (Note 15)	5,646		6,610
Margin deposits related to commodity contracts	48		39

Accrued taxes other than income	107		199
Accrued interest	113		160
Asset retirement obligations (Note 18)	139		128
Operating lease liabilities	8		8

Other current liabilities	458		524
Total current liabilities	8,162		10,337
Long-term debt, less amounts due currently (Note 11)	11,930		11,933
Operating lease liabilities	45		45

Commodity and other derivative contractual liabilities (Note 15)	1,794		1,726
Accumulated deferred income taxes	1		1
Tax Receivable Agreement obligation (Note 8)	578		514
Asset retirement obligations (Note 18)	2,308		2,309

Other noncurrent liabilities and deferred credits (Note 18)	1,083		1,004
Total liabilities	25,901		27,869

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VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars)
	March 31, 2023		December 31, 2022
Commitments and Contingencies (Note 12)
Total equity (Note 13):
Preferred stock, number of shares authorized — 100,000,000; Series A (liquidation preference — $1,000; shares outstanding: March 31, 2023 and December 31, 2022— 1,000,000); Series B (liquidation preference — $1,000; shares outstanding: March 31, 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: March 31, 2023 — 378,648,599; December 31, 2022 — 389,754,870)	5		5
Treasury stock, at cost (shares: March 31, 2023 — 160,425,501; December 31, 2022 — 147,424,202)	(3,706)		(3,395)
Additional paid-in-capital	9,952		9,928
Retained deficit	(3,058)		(3,643)
Accumulated other comprehensive loss	8		7
Stockholders' equity	5,201		4,902
Noncontrolling interest in subsidiary	15		16
Total equity	5,216		4,918
Total liabilities and equity	$	31,117	$	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 6six reportable segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. See Note 1617 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

~~Share Repurchase Program~~ — On August 4, 2022, the Board authorized an incremental $1.25 billion for repurchases under the Share Repurchase Program. Including the original Board authorization, approximately $1.65 billion remains available for share repurchases under the Share Repurchase Program as of August 4, 2022. We expect to complete repurchases under the Share Repurchase Program by the end of 2023.

Dividends Declared — In ~~July 2022,~~May 2023, the Vistra Board declared a quarterly dividend of ~~$0.184~~$0.204 per share of common stock that will be paid in ~~September 2022.~~June 2023. In ~~July 2022,~~May 2023, the Board declared a semi-annual dividend of ~~$40.00~~$35.00 per share of Series AB Preferred Stock that will be paid in ~~October 2022.~~

~~Accounts Receivable Financing~~ ~~— In July 2022, certain subsidiaries of the Company entered into amendments to the Receivables Facility and Repurchase Facility, respectively, extending the terms of each facility to July~~June 2023. Additionally, the amendment to the Receivables Facility adjusted the commitment of the purchasers to purchase interests in the receivables under the Receivables Facility during certain periods to align with the peak retail season and increasing the commitments by $25 million for the settlement periods through December 2022 as compared to the prior year periods (see Note 9).

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~~Vistra Operations Credit Agreement Amendment~~ — In July 2022, the Vistra Operations Credit Agreement was amended to, among other things, (i) establish a new class of extended revolving credit commitments in an aggregate amount of $725 million and maturing April 29, 2027, (ii) require Vistra Operations to terminate at least $350 million in revolving commitments maturing April 29, 2027 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, and (iii) appoint certain additional revolving letter of credit issuers. See Note 10 for details of the Vistra Operations Credit Agreement amendment.

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 ~~2021~~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 ~~2021~~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 at 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 current 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 current 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.

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 transaction’s 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 three months ended March 31, 2023, which were capitalized in other noncurrent liabilities and other deferred credits. 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. 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 permanent 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 effectively fix the SOFR component of the interest cost associated with the anticipated Transactions financings at a weighted average rate of 3.16%. The interest rate swaps are effective December 31, 2023 and expire December 31, 2030.

3. DEVELOPMENT OF GENERATION FACILITIES

Texas Segment Solar Generation and Energy Storage Projects

~~We have~~In September 2020, we announced the planned development of up to 768 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas. ~~The first~~Of this planned development in Texas, 158 MW of solar generation came online in January and February 2022 and the battery ESS came online in April 2022. Estimated commercial operation dates for the remaining facilities ~~range from summer~~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 ~~2024 to the end of 2026. At June 30, 2022,~~March 31, 2023, we had accumulated approximately ~~$152~~$49 million in construction-work-in-process for these remaining Texas segment solar generation ~~projects, including costs for our Emerald Grove solar facility which reached substantial completion in July 2022.~~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 ~~2023~~2024 to 2025. As of March 31, 2023, we had accumulated approximately $19 million in construction-work-in-process for these East segment solar generation and battery ESS projects.

West Segment Energy Storage Projects

~~Oakland~~ — In June 2019, East Bay Community Energy (EBCE) signed a ten-year contract to receive resource adequacy capacity from the planned development of a 20 MW battery ESS at our Oakland Power Plant site in California. In April 2020, the project received necessary approvals from EBCE and from Pacific Gas and Electric Company (PG&E). The contract was amended to increase the capacity of the planned development to a 36.25 MW battery ESS. In April 2020, the concurrent Local Area Reliability Service (LARS) agreement to ensure grid reliability as part of the Oakland Clean Energy Initiative was signed, but required California Public Utilities Commission (CPUC) approval. PG&E did not receive CPUC approval as of April 15, 2021. On April 16, 2021, Vistra terminated the LARS agreement with PG&E. We are continuing development of the Oakland battery ESS project while seeking another contractual arrangement that will allow the investment to move forward.

~~Table of Contents~~

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 is expected to enter commercial operations in the summer of 2023. ~~At June 30, 2022,~~As of March 31, 2023, we had accumulated approximately ~~$32~~$466 million in construction-work-in-process for Moss Landing Phase III.

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 ~~Phase~~Phases II ~~was~~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 ~~Phase~~Phases I ~~was~~and III were not affected by this incident.

~~We have continued restoration work on the facilities and have restored approximately 393 MW (or 98% of the 400 MW capacity) at June 30, 2022.~~

~~We do~~These incidents did not ~~expect these incidents to~~ 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, 1one coal generation facility in Texas and 1one 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 ~~11)~~12), and in furtherance of our efforts to significantly reduce our carbon footprint. InAs previously announced in April 2021, we ~~announced we would retire~~retired the Joppa generation facilities byin September 1, 2022 in order to settle a complaint filed with the Illinois Pollution Control Board (IPCB) by the Sierra Club in 2018. ~~We had previously announced that Joppa would retire no later than the end of 2027.~~ 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.

8As previously announced, we retired the Edwards coal generation facility in January 2023.

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

Facility

Location

ISO/RTO

Fuel Type

Net Generation Capacity (MW)

Actual or Expected Retirement Date (a)

Segment

Baldwin

Baldwin, IL

MISO

Coal

1,185

By the end of 2025

Sunset

Coleto Creek

Goliad, TX

ERCOT

Coal

650

By the end of 2027

Sunset

Edwards

Bartonville, IL

MISO

Coal

585

Retired January 1, 2023

~~Sunset~~Asset Closure

Joppa

Joppa, IL

MISO

Coal

802

ByRetired September 1, 2022

Asset Closure

Joppa

Joppa, IL

MISO

Natural Gas

221

ByRetired 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.

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5. REVENUE

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 53 220 183 — 567
Capacity revenue from ISO/RTO (a) — — (4) — 25 8 — 29
Revenue from other wholesale contracts — 146 202 35 38 9 — 430
Total revenue from contracts with customers 2,300 87 368 88 283 200 — 3,326
Other revenues:
Intangible amortization (1) — — — (2) — — (3)
Hedging and other revenues (b) (507) (453) (295) (12) (389) (79) — (1,735)
Affiliate sales (c) — (257) 246 3 25 — (17) —
Total other revenues (508) (710) (49) (9) (366) (79) (17) (1,738)
Total revenues $ 1,792 $ (623) $ 319 $ 79 $ (83) $ 121 $ (17) $ 1,588


	Three Months Ended March 31, 2023
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations		Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	1,568	$	—	$	—	$	—	$	—	$	—	$	—	$	1,568
Retail energy charge in Northeast/Midwest	427		—		—		—		—		—		—		427
Wholesale generation revenue from ISO/RTO	—		50		220		193		67		—		—		530
Capacity revenue from ISO/RTO (a)	—		—		8		—		19		—		—		27
Revenue from other wholesale contracts	—		107		331		41		76		—		—		555
Total revenue from contracts with customers	1,995		157		559		234		162		—		—		3,107
Other revenues:
Intangible amortization	(1)		—		(1)		—		(1)		—		—		(3)
Transferable PTC revenues	—		2		—		—		—		—		—		2
Hedging and other revenues (b)	356		112		386		(7)		472		—		—		1,319
Affiliate sales (c)	—		1,082		865		4		195		—		(2,146)		—
Total other revenues	355		1,196		1,250		(3)		666		—		(2,146)		1,318
Total revenues	$	2,350	$	1,353	$	1,809	$	231	$	828	$	—	$	(2,146)	$	4,425

____________

(a)Represents net capacity sold ~~(purchased)~~ in each ISO/RTO. The East segment includes ~~$102~~$42 million of capacity ~~purchased~~sold offset by ~~$98~~$34 million of capacity ~~sold.~~purchased. The Sunset segment includes $2$46 million of capacity ~~purchased~~sold offset by $27 million of capacity ~~sold. The Asset Closure segment includes $8 million of capacity sold.~~purchased.

(b)Includes ~~$2.088~~$1.277 billion of unrealized net ~~losses~~gains from mark-to-market valuations of commodity ~~position,~~positions, including Retail segment unrealized net ~~losses~~gains of ~~$414~~$153 million due to the discontinuance of normal purchases ~~or normal~~and sales (NPNS) accounting on a retail electric contract portfolio ~~where~~in the second quarter of 2022 as physical settlement is no longer considered probable throughout the contract ~~term as we opportunistically monetized certain positions.~~term. See Note 1617 for unrealized net gains (losses) by segment.

(c)Texas, East and Sunset segments include ~~$918~~$185 million, ~~$151~~$394 million and ~~$99~~$103 million, respectively, of affiliated unrealized net ~~losses from mark-to-market valuations of commodity positions with the Retail segment.~~

~~Table of Contents~~

Three Months Ended June 30, 2021
Retail Texas East West Sunset Asset
Closure Eliminations Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT $ 1,417 $ — $ — $ — $ — $ — $ — $ 1,417
Retail energy charge in Northeast/Midwest 504 — — — — — — 504
Wholesale generation revenue from ISO/RTO — 128 96 31 129 56 — 440
Capacity revenue from ISO/RTO (a) — — 2 — 32 11 — 45
Revenue from other wholesale contracts — 56 130 24 44 — — 254
Total revenue from contracts with customers 1,921 184 228 55 205 67 — 2,660
Other revenues:
Intangible amortization (2) — 73 — (2) — — 69
Hedging and other revenues (b) — (8) 131 (7) (172) (108) — (164)
Affiliate sales (c) — (644) 73 — (38) — 609 —
Total other revenues (2) (652) 277 (7) (212) (108) 609 (95)
Total revenues $ 1,919 $ (468) $ 505 $ 48 $ (7) $ (41) $ 609 $ 2,565

~~____________~~

~~(a)~~Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $119 million of capacity sold offset by $117 million of capacity purchased. The Sunset segment includes $33 million of capacity sold offset by $1 million of capacity purchased. The Asset Closure segment includes $11 million of capacity sold.

~~(b)Includes $343 million of unrealized net losses from mark-to-market valuations of commodity positions. See Note 16 for unrealized net~~ gains ~~(losses) by segment.~~

~~(c)Texas, East and Sunset segments include $952 million, $263 million and $121 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, 2022																	Three Months Ended March 31, 2022
		Retail		Texas		East		West		Sunset		Asset Closure		Eliminations		Consolidated			Retail		Texas		East		West		Sunset		Asset Closure		Eliminations		Consolidated
Revenue from contracts with customers:	Revenue from contracts with customers:																	Revenue from contracts with customers:
Retail energy charge in ERCOT	Retail energy charge in ERCOT	$	3,162	$	—	$	—	$	—	$	—	$	—	$	—	$	3,162	Retail energy charge in ERCOT	$	1,405	$	—	$	—	$	—	$	—	$	—	$	—	$	1,405
Retail energy charge in Northeast/Midwest	Retail energy charge in Northeast/Midwest	1,183		—		—		—		—		—		—		1,183		Retail energy charge in Northeast/Midwest	639		—		—		—		—		—		—		639
Wholesale generation revenue from ISO/RTO	Wholesale generation revenue from ISO/RTO	—		92		572		112		390		318		—		1,484		Wholesale generation revenue from ISO/RTO	—		151		402		58		141		164		—		916
Capacity revenue from ISO/RTO (a)	Capacity revenue from ISO/RTO (a)	—		—		(10)		—		63		20		—		73		Capacity revenue from ISO/RTO (a)	—		—		(6)		—		33		16		—		43
Revenue from other wholesale contracts	Revenue from other wholesale contracts	—		265		445		73		81		21		—		885		Revenue from other wholesale contracts	—		120		243		39		44		12		—		458
Total revenue from contracts with customers	Total revenue from contracts with customers	4,345		357		1,007		185		534		359		—		6,787		Total revenue from contracts with customers	2,044		271		639		97		218		192		—		3,461
Other revenues:	Other revenues:																	Other revenues:
Intangible amortization	Intangible amortization	(1)		—		—		—		(4)		—		—		(5)		Intangible amortization	—		—		—		—		(2)		—		—		(2)

Hedging and other revenues (b)	Hedging and other revenues (b)	(727)		(451)		13		(40)		(733)		(131)		—		(2,069)		Hedging and other revenues (b)	(219)		—		309		(28)		(306)		(90)		—		(334)
Affiliate sales (c)	Affiliate sales (c)	—		(1,624)		254		6		(20)		—		1,384		—		Affiliate sales (c)	—		(1,366)		7		3		(28)		(17)		1,401		—
Total other revenues	Total other revenues	(728)		(2,075)		267		(34)		(757)		(131)		1,384		(2,074)		Total other revenues	(219)		(1,366)		316		(25)		(336)		(107)		1,401		(336)
Total revenues	Total revenues	$	3,617	$	(1,718)	$	1,274	$	151	$	(223)	$	228	$	1,384	$	4,713	Total revenues	$	1,825	$	(1,095)	$	955	$	72	$	(118)	$	85	$	1,401	$	3,125

____________

(a)Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes ~~$238~~$136 million of capacity purchased offset by ~~$228~~$130 million of capacity sold. The Sunset segment includes $3$35 million of capacity ~~purchased~~sold offset by ~~$66~~$2 million of capacity ~~sold.~~purchased. The Asset Closure segment includes ~~$20~~$16 million of capacity sold.

(b)Includes ~~$2.447 billion~~$358 million of unrealized net losses from mark-to-market valuations of commodity positions, including Retail segment unrealized net losses of $414 million due to the discontinuance of NPNS accounting on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract term as we opportunistically monetized certain positions. See Note 1617 for unrealized net gains (losses) by segment.

(c)Texas, East, Sunset and ~~Sunset~~Asset Closure segments include ~~$2.928~~$2.011 billion, ~~$660~~$509 million, $136 million and ~~$253~~$17 million, respectively, of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

~~Table of Contents~~

Six Months Ended June 30, 2021
Retail Texas East West Sunset Asset
Closure Eliminations Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT $ 2,565 $ — $ — $ — $ — $ — $ — $ 2,565
Retail energy charge in Northeast/Midwest 1,091 — — — — — — 1,091
Wholesale generation revenue from ISO/RTO — 3,374 252 69 808 100 — 4,603
Capacity revenue from ISO/RTO (a) — — (2) — 61 21 — 80
Revenue from other wholesale contracts — 2,084 293 46 101 1 — 2,525
Total revenue from contracts with customers 3,656 5,458 543 115 970 122 — 10,864
Other revenues:
Intangible amortization (3) — 74 — (8) — — 63
Hedging and other revenues (b) 16 (4,450) 195 (36) (739) (141) — (5,155)
Affiliate sales (c) — (393) 418 2 26 — (53) —
Total other revenues 13 (4,843) 687 (34) (721) (141) (53) (5,092)
Total revenues $ 3,669 $ 615 $ 1,230 $ 81 $ 249 $ (19) $ (53) $ 5,772

~~____________~~

~~(a)~~Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $230 million of capacity purchased offset by $228 million of capacity sold. The Sunset segment includes $1 million of capacity purchased offset by $62 million of capacity sold. The Asset Closure segment includes $21 million of capacity sold.

~~(b)Includes $285 million of unrealized net losses from mark-to-market valuations of commodity positions. See Note 16 for unrealized net gains (losses) by segment.~~

~~(c)~~Texas, East and Sunset segments include $1.625 billion, $347 million and $154 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, 2022,~~March 31, 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 ~~$216~~$346 million, ~~$467~~$382 million, ~~$278~~$275 million, ~~$179~~$167 million and ~~$111~~$100 million that will be recognized, in the balance of the year ended December 31, ~~2022~~2023 and the years ending December 31, ~~2023,~~ 2024, 2025, 2026 and ~~2026,~~2027, respectively, and ~~$735~~$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, 2022		December 31, 2021			March 31, 2023		December 31, 2022
Trade accounts receivable from contracts with customers — net	Trade accounts receivable from contracts with customers — net	$	1,503	$	1,087	Trade accounts receivable from contracts with customers — net	$	1,152	$	1,644
Other trade accounts receivable — net	Other trade accounts receivable — net	287		310		Other trade accounts receivable — net	312		415
Total trade accounts receivable — net	Total trade accounts receivable — net	$	1,790	$	1,397	Total trade accounts receivable — net	$	1,464	$	2,059

1211

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5.6. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

Goodwill

AtAs of both ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021,~~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, 2022						December 31, 2021							March 31, 2023						December 31, 2022
Identifiable Intangible Asset	Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net		Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship		$	2,085	$	1,699	$	386	$	2,083	$	1,631	$	452
Retail customer relationships														Retail customer relationships	$	2,088	$	1,796	$	292	$	2,088	$	1,768	$	320
Software and other technology-related assets	Software and other technology-related assets	452		233		219		421		206		215		Software and other technology-related assets	488		271		217		475		258		217
Retail and wholesale contracts	Retail and wholesale contracts	233		203		30		248		206		42		Retail and wholesale contracts	233		212		21		233		209		24
Contractual service agreements (a)		20		4		16		23		2		21
LTSA														LTSA	18		4		14		18		4		14
Other identifiable intangible assets ~~(b)~~(a)	Other identifiable intangible assets ~~(b)~~(a)	57		7		50		95		20		75		Other identifiable intangible assets ~~(b)~~(a)	64		9		55		50		8		42
Total identifiable intangible assets subject to amortization	Total identifiable intangible assets subject to amortization	$	2,847	$	2,146	701		$	2,870	$	2,065	805		Total identifiable intangible assets subject to amortization	$	2,891	$	2,292	599		$	2,864	$	2,247	617
Retail trade names (not subject to amortization)	Retail trade names (not subject to amortization)					1,341						1,341		Retail trade names (not subject to amortization)					1,341						1,341

Total identifiable intangible assets	Total identifiable intangible assets					$	2,042					$	2,146	Total identifiable intangible assets					$	1,940					$	1,958

____________

(a)At June 30, 2022, amounts related to contractual service agreements that have become liabilities due to amortization of the economic impacts of the intangibles have been removed from both the gross carrying amount and accumulated amortization.

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

Identifiable intangible liabilities are comprised of the following:


Identifiable Intangible Liability	Identifiable Intangible Liability	June 30, 2022		December 31, 2021		Identifiable Intangible Liability	March 31, 2023		December 31, 2022
Contractual service agreements		$	129	$	125
Purchase and sale of power and capacity		4		8
LTSA						LTSA	$	128	$	128
Fuel and transportation purchase contracts	Fuel and transportation purchase contracts	11		14		Fuel and transportation purchase contracts	9		9
Other identifiable intangible liabilities						Other identifiable intangible liabilities	2		3
Total identifiable intangible liabilities	Total identifiable intangible liabilities	$	144	$	147	Total identifiable intangible liabilities	$	139	$	140

~~Table of Contents~~

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

Identifiable Intangible Assets and Liabilities Condensed Consolidated Statements of Operations Three Months Ended June 30, Six Months Ended June 30,
2022 2021 2022 2021
Retail customer relationship Depreciation and amortization $ 34 $ 50 $ 68 $ 98
Software and other technology-related assets Depreciation and amortization 18 20 36 38
Retail and wholesale contracts/purchase and sale/fuel and transportation contracts Operating revenues/fuel, purchased power costs and delivery fees 3 (69) 5 (61)
Other identifiable intangible assets Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization 98 48 186 105
Total intangible asset expense (a) $ 153 $ 49 $ 295 $ 180


Identifiable Intangible Assets	Condensed Consolidated Statements of Operations	Three Months Ended March 31,
			2023		2022
Retail customer relationships	Depreciation and amortization		$	28	$	34
Software and other technology-related assets	Depreciation and amortization		15		17
Retail and wholesale contracts	Operating revenues/fuel, purchased power costs and delivery fees		2		2
Other identifiable intangible assets	Fuel, purchased power costs and delivery fees		86		89
Total identifiable intangible assets expense (a)			$	131	$	142

___________

(a)Amounts recorded in depreciation and amortization totaled ~~$53~~$43 million and ~~$70~~$52 million for the three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021, respectively, and $105 million and $138 million for the six months ended June 30, 2022 and 2021,~~ respectively. Amounts exclude ~~contractual services agreements.~~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.

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Estimated Amortization of Identifiable Intangible Assets ~~and Liabilities~~

As of ~~June 30, 2022,~~March 31, 2023, the estimated aggregate amortization expense of identifiable intangible assets ~~and liabilities~~ for each of the next five fiscal years is as shown below.


Year	Year	Estimated Amortization Expense		Year	Estimated Amortization Expense
2022		$	173
2023	2023	$	152	2023	$	161
2024	2024	$	103	2024	$	112
2025	2025	$	77	2025	$	84
2026	2026	$	52	2026	$	61
2027				2027	$	37

6.7. 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,
2022 2021 2022 2021
Net loss before income taxes $ (1,764) $ (80) $ (2,139) $ (2,604)
Income tax benefit $ 407 $ 115 $ 498 $ 600
Effective tax rate 23.1 % 143.8 % 23.3 % 23.0 %


	Three Months Ended March 31,
		2023			2022
Net income (loss) before income taxes		$	876		$	(375)
Income tax (expense) benefit		$	(178)		$	91
Effective tax rate		20.3		%	24.3		%

For the three months ended ~~June 30,~~March 31, 2023, the effective tax rate of 20.3% was lower than the U.S. federal statutory rate of 21% due primarily to state income taxes.

For the three months ended March 31, 2022, the effective tax rate of ~~23.1%~~24.3% 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. 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.

~~Table~~Inflation Reduction Act of ~~Contents~~

For the three months ended June 30, 2021, the effective tax rate of 143.8% 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, including the impact of a decrease in our state valuation allowances primarily due to newly enacted state tax legislation. For the six months ended June 30, 2021, the effective tax rate of 23.0% 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.

~~Coronavirus Aid, Relief, and Economic Security Act (CARES Act) and Final Section 163(j) Regulations~~2022 (IRA)

In ~~response to~~August 2022, the ~~global pandemic related to COVID-19,~~U.S. enacted the ~~CARES Act was signed into law in March 2020. The CARES Act provides numerous relief provisions for~~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 taxpayers, including modification of the utilization limitations on net operating losses, favorable expansion of the deduction for business interest expense under IRC Section 163(j) (Section 163(j)), the ability to accelerate timing of refundable alternative minimum tax ~~(AMT) credits and the temporary suspension~~(CAMT) on book income of certain ~~payment requirements for~~large corporations, and a 1% excise tax on net stock repurchases. Treasury regulations are expected to define the ~~employer portion~~scope of ~~social security taxes. Additionally,~~ the ~~final Section 163(j) regulations were issued~~legislation in ~~July 2020 and provided~~many important respects over the next twelve months. The excise tax on stock repurchases is not expected to have a ~~critical correction~~material impact on our financial statements. Vistra is not subject to the ~~proposed regulations with respect to the computation of adjusted taxable income. As of January 1, 2022, certain provisions~~CAMT in the ~~final Section 163(j) regulations~~2023 tax year since it applies only to corporations that have ~~sunset, including~~a three-year average annual adjusted financial statement income in excess of $1 billion. We have taken the ~~addback~~CAMT and relevant extensions or expansions of ~~depreciation and amortization~~existing tax credits applicable to ~~adjusted taxable income. As a result, under~~projects in our immediate development pipeline into account when forecasting cash taxes for periods after the law ~~as currently drafted, Vistra's deductible business interest expense will be significantly limited~~takes effect and for estimating the 2022 tax year. Vistra remains active in legislative monitoring and advocacy efforts to support a legislative solution to reinstate and make permanent the addback of depreciation and amortization to adjusted taxable income. Vistra is also utilizing the CARES Act payroll deferral mechanism to defer the payment of approximately $22 million from 2020 to 2021 and 2022. We paid approximately half of the previously deferred taxes in December 2021.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. ~~In the second quarter of 2022, the employment~~The federal income tax audit ~~for~~is in its final stages and Vistra expects final closing on an agreed basis with immaterial changes in the first half of 2023. It is reasonably possible $35 million of the uncertain tax ~~year 2018 was closed with no adjustment. Crius is currently under audit by~~positions could be favorably resolved within the ~~IRS for the tax years 2015 and 2016.~~next 12 months upon final closing. Uncertain tax positions totaled ~~$39~~$35 million and ~~$38~~$36 million at ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, respectively.

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8. TAX RECEIVABLE AGREEMENT OBLIGATION

On the Effective Date, Vistra entered into ~~a tax receivable agreement (the TRA)~~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 2two 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 ~~15)~~16).

~~Table of Contents~~

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~~three months ended ~~June 30, 2022~~March 31, 2023 and ~~2021:~~2022:


		Six Months Ended June 30,					Three Months Ended March 31,
		2022		2021			2023		2022
TRA obligation at the beginning of the period	TRA obligation at the beginning of the period	$	395	$	450	TRA obligation at the beginning of the period	$	522	$	395
Accretion expense	Accretion expense	32		32		Accretion expense	20		15
Changes in tax assumptions impacting timing of payments (a)	Changes in tax assumptions impacting timing of payments (a)	83		(28)		Changes in tax assumptions impacting timing of payments (a)	45		66
Impacts of Tax Receivable Agreement	Impacts of Tax Receivable Agreement	115		4		Impacts of Tax Receivable Agreement	65		81

TRA obligation at the end of the period	TRA obligation at the end of the period	510		454		TRA obligation at the end of the period	587		476
Less amounts due currently	Less amounts due currently	(1)		(3)		Less amounts due currently	(9)		(1)
Noncurrent TRA obligation at the end of the period	Noncurrent TRA obligation at the end of the period	$	509	$	451	Noncurrent TRA obligation at the end of the period	$	578	$	475

____________

(a)During the three ~~and six~~ months ended ~~June 30,~~March 31, 2023 and 2022, we recorded increases to the carrying value of the TRA obligation totaling ~~$17~~$45 million and ~~$83~~$66 million, respectively, as a result of adjustments to forecasted taxable income due to increases in longer-term commodity price forecasts, partially offset by anticipated tax benefits under current laws for planned additional renewable development projects. During the three months ended June 30, 2021, we recorded an increase to the carrying value of the TRA obligation totaling $26 million as a result of adjustments to forecasted taxable income. During the six months ended June 30, 2021, we recorded a decrease to the carrying value of the TRA obligation totaling $28 million as a result of adjustments to forecasted taxable income including the financial impacts of Winter Storm Uri.forecasts.

As of ~~June 30, 2022,~~March 31, 2023, the estimated carrying value of the TRA obligation totaled ~~$510~~$587 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, 2022,~~March 31, 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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8.9. 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,					Three Months Ended March 31,
		2022		2021		2022		2021				2023		2022
Net income (loss) attributable to Vistra	Net income (loss) attributable to Vistra	$	(1,365)	$	36	$	(1,650)	$	(2,006)	Net income (loss) attributable to Vistra		$	699	$	(285)
Less cumulative dividends attributable to Series A Preferred Stock	Less cumulative dividends attributable to Series A Preferred Stock	(20)		—		(40)		—		Less cumulative dividends attributable to Series A Preferred Stock		(20)		(20)
Less cumulative dividends attributable to Series B Preferred Stock	Less cumulative dividends attributable to Series B Preferred Stock	(17)		—		(35)		—		Less cumulative dividends attributable to Series B Preferred Stock		(18)		(18)
Net income (loss) attributable to common stock — basic	Net income (loss) attributable to common stock — basic	(1,402)		36		(1,725)		(2,006)		Net income (loss) attributable to common stock — basic		661		(323)
Weighted average shares of common stock outstanding — basic	Weighted average shares of common stock outstanding — basic	429,193,031		486,022,633		440,336,286		485,364,606		Weighted average shares of common stock outstanding — basic		383,631,369		451,603,354
Net income (loss) per weighted average share of common stock outstanding — basic	Net income (loss) per weighted average share of common stock outstanding — basic	$	(3.27)	$	0.07	$	(3.92)	$	(4.13)	Net income (loss) per weighted average share of common stock outstanding — basic		$	1.72	$	(0.72)
Dilutive securities: Stock-based incentive compensation plan	Dilutive securities: Stock-based incentive compensation plan	—		1,343,593		—		—		Dilutive securities: Stock-based incentive compensation plan		3,922,010		—
Weighted average shares of common stock outstanding — diluted	Weighted average shares of common stock outstanding — diluted	429,193,031		487,366,226		440,336,286		485,364,606		Weighted average shares of common stock outstanding — diluted		387,553,379		451,603,354
Net income (loss) per weighted average share of common stock outstanding — diluted	Net income (loss) per weighted average share of common stock outstanding — diluted	$	(3.27)	$	0.07	$	(3.92)	$	(4.13)	Net income (loss) per weighted average share of common stock outstanding — diluted		$	1.71	$	(0.72)

Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled ~~5,567,585~~3,859,165 and ~~14,433,851~~9,776,484 shares for the three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021, respectively, and 8,052,517 and 15,734,553 shares for the six months ended June 30, 2022 and 2021,~~ respectively.

9.10. 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 2022, extending the term of the Receivables Facility to July 2023, adjusting the commitment of the purchasers to purchase interests in the receivables under the Receivables Facility during certain periods to align with the peak retail season ~~and increasing~~which increased the commitments by $25 million for the settlement periods through December 2022 as compared to prior ~~year~~ periods, as follows: (i) $625 million beginning with the settlement date in July 2022 until the settlement date in August 2022, (ii) $750 million from the settlement date in August 2022 until the settlement date in November 2022, (iii) $625 million from the settlement date in November 2022 until the settlement date in December 2022, and (iv) $600 million from the settlement date in December 2022 and thereafter for the remaining term of the Receivables Facility.

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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, 2022,~~March 31, 2023, outstanding borrowings under the Receivables Facility totaled $600 million and were supported by ~~$1.096 billion~~$842 million of RecCo gross receivables. As of December 31, ~~2021,~~2022, there were no$425 million outstanding borrowings under the Receivables ~~Facility.~~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~~August 2022, the Repurchase Facility was renewed until July 2023 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 Transactions). Each Transaction is expected to have a term of one month, unless terminated earlier on demand by TXU Energy or terminated by Buyer after an event of default.

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

~~As of June 30, 2022,~~There were no outstanding borrowings under the Repurchase Facility ~~totaled $125 million. There were no outstanding borrowings at~~as of both March 31, 2023 and December 31, ~~2021.~~2022.

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~~10.~~11. DEBT

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


		June 30, 2022		December 31, 2021			March 31, 2023		December 31, 2022
Vistra Operations Credit Facilities	Vistra Operations Credit Facilities	$	2,529	$	2,543	Vistra Operations Credit Facilities	$	2,507	$	2,514
Vistra Operations Senior Secured Notes:	Vistra Operations Senior Secured Notes:					Vistra Operations Senior Secured Notes:
4.875% Senior Secured Notes, due May 13, 2024	4.875% Senior Secured Notes, due May 13, 2024	400		—		4.875% Senior Secured Notes, due May 13, 2024	400		400
3.550% Senior Secured Notes, due July 15, 2024	3.550% Senior Secured Notes, due July 15, 2024	1,500		1,500		3.550% Senior Secured Notes, due July 15, 2024	1,500		1,500
5.125% Senior Secured Notes, due May 13, 2025	5.125% Senior Secured Notes, due May 13, 2025	1,100		—		5.125% Senior Secured Notes, due May 13, 2025	1,100		1,100
3.700% Senior Secured Notes, due January 30, 2027	3.700% Senior Secured Notes, due January 30, 2027	800		800		3.700% Senior Secured Notes, due January 30, 2027	800		800
4.300% Senior Secured Notes, due July 15, 2029	4.300% Senior Secured Notes, due July 15, 2029	800		800		4.300% Senior Secured Notes, due July 15, 2029	800		800
Total Vistra Operations Senior Secured Notes	Total Vistra Operations Senior Secured Notes	4,600		3,100		Total Vistra Operations Senior Secured Notes	4,600		4,600
Vistra Operations Senior Unsecured Notes:	Vistra Operations Senior Unsecured Notes:					Vistra Operations Senior Unsecured Notes:
5.500% Senior Unsecured Notes, due September 1, 2026	5.500% Senior Unsecured Notes, due September 1, 2026	1,000		1,000		5.500% Senior Unsecured Notes, due September 1, 2026	1,000		1,000
5.625% Senior Unsecured Notes, due February 15, 2027	5.625% Senior Unsecured Notes, due February 15, 2027	1,300		1,300		5.625% Senior Unsecured Notes, due February 15, 2027	1,300		1,300
5.000% Senior Unsecured Notes, due July 31, 2027	5.000% Senior Unsecured Notes, due July 31, 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	4.375% Senior Unsecured Notes, due May 15, 2029	1,250		1,250		4.375% Senior Unsecured Notes, due May 15, 2029	1,250		1,250
Total Vistra Operations Senior Unsecured Notes	Total Vistra Operations Senior Unsecured Notes	4,850		4,850		Total Vistra Operations Senior Unsecured Notes	4,850		4,850

Other:	Other:					Other:
Forward Capacity Agreements		—		213

Equipment Financing Agreements	Equipment Financing Agreements	90		92		Equipment Financing Agreements	79		79

Other		3		6

Total other long-term debt	Total other long-term debt	93		311		Total other long-term debt	79		79
Unamortized debt premiums, discounts and issuance costs	Unamortized debt premiums, discounts and issuance costs	(82)		(73)		Unamortized debt premiums, discounts and issuance costs	(68)		(72)
Total long-term debt including amounts due currently	Total long-term debt including amounts due currently	11,990		10,731		Total long-term debt including amounts due currently	11,968		11,971
Less amounts due currently	Less amounts due currently	(41)		(254)		Less amounts due currently	(38)		(38)
Total long-term debt less amounts due currently	Total long-term debt less amounts due currently	$	11,949	$	10,477	Total long-term debt less amounts due currently	$	11,930	$	11,933

As of ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, outstanding short-term ~~borrowings totaled $1.3 billion and zero, respectively, and includes outstanding~~ borrowings under the Commodity-Linked Facility and the Revolving Credit Facility (described below). totaled zero and $650 million, respectively.

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Vistra Operations Credit Facilities and Commodity-Linked Revolving Credit Facility

Vistra Operations Credit Facilities — As of ~~June 30, 2022,~~March 31, 2023, the Vistra Operations Credit Facilities consisted of up to ~~$5.529~~$5.882 billion in senior secured, first-lien revolving credit commitments and outstanding term loans, which consisted of revolving credit commitments of up to ~~$3.0~~$3.375 billion (Revolving Credit Facility) and term loans of ~~$2.529~~$2.507 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, and the maturity date was extended from June 14, 2023 to April 29, 2027. After giving effect to the Credit Agreement Amendments, the aggregate amount of revolving commitments maturing on April 29, 2027 equals $3.525 billion (Extended Revolving Credit Facility), while the $200 million in revolving commitments maturing on June 14, 2023 (Non-Extended Revolving Credit Facility) remain unchanged by the Credit Agreement Amendments.respectively. The July 18, 2022 amendment to the Vistra Operations Credit Agreement also provides that Vistra Operations will terminate at least $350 million in Extended Revolving Credit Facility 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 maturing on June 14, 2023 (Non-Extended Revolving Credit Facility) remain unchanged by the Credit Agreement Amendments. Furthermore, the Credit Agreement Amendments ~~appoint~~appointed new revolving letter of credit issuers, such that the aggregate amount of revolving letter of credit commitments equals $3.245 billion after giving effect to the Credit Agreement Amendments. Fees and expenses related to the Credit Agreement Amendments totaled $1 million in both the three and six months ended June 30, 2022, which were capitalized as a reduction in the carrying amount of the debt, and additional fees and expenses totaling $7 million were incurred in July 2022.

In March 2021, Vistra Operations borrowed $1.0 billion principal amount under the Term Loan A Facility. In April 2021, Vistra Operations borrowed an additional $250 million principal amount under the Term Loan A Facility. Proceeds from the Term Loan A Facility, together with cash on hand, were used to repay certain amounts outstanding under the Revolving Credit Facility. Borrowings under the Term Loan A Facility were reported in short-term borrowings in our condensed consolidated balance sheet. In May 2021, Vistra Operations used the proceeds from the issuance of the Vistra Operations 4.375% senior unsecured notes due 2029 (described below), together with cash on hand, to repay the $1.250 billion borrowings under the Term Loan A Facility. We recorded an extinguishment loss of $1 million on the transaction in the six months ended June 30, 2021.

Our credit facilities and related available capacity as of ~~June 30, 2022~~March 31, 2023 are presented below.


			June 30, 2022										March 31, 2023
Credit Facilities	Credit Facilities	Maturity Date	Facility Limit		Cash Borrowings		Letters of Credit Outstanding		Available Capacity		Credit Facilities	Maturity Date	Facility Limit		Cash Borrowings		Letters of Credit Outstanding		Available Capacity
Extended Revolving Credit Facility (a)	Extended Revolving Credit Facility (a)	April 29, 2027	$	2,800	$	233	$	2,223	$	344	Extended Revolving Credit Facility (a)	April 29, 2027	$	3,175	$	—	$	1,301	$	1,874
Non-Extended Revolving Credit Facility (b)	Non-Extended Revolving Credit Facility (b)	June 14, 2023	200		17		159		24		Non-Extended Revolving Credit Facility (b)	June 14, 2023	200		—		82		118

Term Loan B-3 Facility (c)	Term Loan B-3 Facility (c)	December 31, 2025	2,529		2,529		—		—		Term Loan B-3 Facility (c)	December 31, 2025	2,507		2,507		—		—
Total Vistra Operations Credit Facilities	Total Vistra Operations Credit Facilities		$	5,529	$	2,779	$	2,382	$	368	Total Vistra Operations Credit Facilities		$	5,882	$	2,507	$	1,383	$	1,992
Commodity-Linked Facility (d)	Commodity-Linked Facility (d)	October 5, 2022	$	2,250	$	1,050			$	1,200	Commodity-Linked Facility (d)	October 4, 2023	$	1,350	$	—	$	—	$	169
Total Credit Facilities	Total Credit Facilities		$	7,779	$	3,829	$	2,382	$	1,568	Total Credit Facilities		$	7,232	$	2,507	$	1,383	$	2,161

___________

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

(c)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.

(d)Commodity-Linked Facility (defined below) used to support our comprehensive hedging strategy. ~~Facility limit and available capacity assume~~As of March 31, 2023, the borrowing base ~~equals~~of $169 million is lower than the facility limit which represents the aggregate commitments of ~~$2.25~~$1.35 billion. The reduction in the borrowing base is due to a decrease in commodity prices 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.

2017

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Under the Vistra Operations Credit Agreement, the interest applicable to the Extended Revolving Credit Facility is based on a term Secured Overnight Financing Rate (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 had been revised to 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, 2022,~~March 31, 2023, there ~~was $233 million~~were no outstanding borrowings under the Extended Revolving Credit ~~Facility with a weighted average interest rate was 3.26%.~~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 March 31, 2023 was 1.75%. The applicable interest rate margins for the Extended Revolving Credit Facility and the fee for undrawn amounts relating to such extended commitments may further be adjusted from time to time dependent upon the Company's performance relative to certain sustainability-linked targets and ~~thresholds, as further described in the Vistra Operations Credit Agreement.~~thresholds.

Under the Vistra Operations Credit Agreement, cash borrowings under the Non-Extended Revolving Credit Facility bear interest based on applicable LIBOR rates, plus a fixed spread of 1.75%. As of ~~June 30, 2022,~~March 31, 2023, there ~~was $17 million~~were no outstanding borrowings under the Non-Extended Revolving Credit ~~Facility with weighted average rate of 3.35%.~~Facility. Letters of credit issued under the Non-Extended Revolving Credit Facility bear interest of 1.75%.

Amounts borrowed under the Term Loan B-3 Facility ~~bears~~bear interest based on applicable LIBOR rates plus fixed spreads of 1.75%. As of ~~June 30, 2022,~~March 31, 2023, the weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings was ~~3.39%~~6.56% under the Term Loan B-3 Facility. The Vistra Operations Credit Facilities also provide for certain additional fees payable to the agents and lenders, including fronting fees with respect to outstanding letters of credit and availability fees payable with respect to any unused portion of the available Non-Extended Revolving Credit Facility.

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 cease 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 shall be replaced by the Adjusted Term SOFR Rate (as defined in the April 2023 Amendment), other than as expressly contemplated by the April 2023 Amendment.

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, provided that the amount of loans outstanding under the Vistra Operations Credit Facilities that may be secured by a lien covering certain principal properties of the Company is expressly limited by the terms of 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 to be secured on a pari-passu basis with the Vistra Operations Credit Facilities in the event those hedging 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.

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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, ~~a total net leverage ratio~~ not to exceed 5.50 to 1.00). As of ~~June 30, 2022,~~March 31, 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. ~~Fees and expenses related~~In October 2022, Vistra initiated amendments to the ~~facility totaled $2 million~~Commodity-Linked Facility to, among other things, (i) extend the maturity date to October 4, 2023 and ~~$4 million in~~(ii) reduce the ~~three and six months ended June 30, 2022, respectively, which were capitalized as a reduction in the carrying amount of the debt.~~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.

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 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 March 31, 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, 2022,~~March 31, 2023, Vistra has entered into the following series of interest rate swap transactions.


		Notional Amount	Expiration Date	Rate Range					Notional Amount	Expiration Date	Rate Range
Swapped to fixed	Swapped to fixed	$3,000	July 2023	3.67	%	-	3.91%	Swapped to fixed	$3,000	July 2023	3.67	%	-	3.91%
Swapped to variable	Swapped to variable	$700	July 2023	3.20	%	-	3.23%	Swapped to variable	$700	July 2023	3.20	%	-	3.23%
Swapped to fixed	Swapped to fixed	$720	February 2024	3.71	%	-	3.72%	Swapped to fixed	$720	February 2024	3.71	%	-	3.72%
Swapped to variable	Swapped to variable	$720	February 2024	3.20	%	-	3.20%	Swapped to variable	$720	February 2024	3.20	%	-	3.20%
Swapped to fixed (a)	Swapped to fixed (a)	$3,000	July 2026	4.72	%	-	4.79%	Swapped to fixed (a)	$3,000	July 2026	4.72	%	-	4.79%
Swapped to variable		$700	July 2026	3.28	%	-	3.33%
Swapped to variable (a)								Swapped to variable (a)	$700	July 2026	3.28	%	-	3.33%
Swapped to fixed (b)								Swapped to fixed (b)	$750	December 2030	3.16	%	-	3.17%

____________

(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. The remaining existing swaps continue to hedge our exposure on $2.30 billion of debt through July 2026.

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 an additional Secured LOC ~~Facility~~Facilities which ~~will also be~~are used for general corporate purposes. As of ~~June 30, 2022, $519~~March 31, 2023, $780 million of letters of credit were outstanding under the Secured LOC Facilities.

22Each 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 March 31, 2023, we were in compliance with these financial covenants.

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Vistra Operations Senior Secured Notes

In May 2022, Vistra Operations issued $1.5 billion aggregate principal amount of senior secured notes ~~(May 2022~~(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 ~~May~~ 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 ~~May~~ 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. ~~Fees and expenses related to the offering totaled $16 million in both the three and six months ended June 30, 2022, which were capitalized as a reduction in the carrying amount of the debt.~~

InSince 2019, Vistra Operations issued and sold ~~$3.1~~$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 ~~May~~ 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

In May 2021, Vistra Operations issued and sold $1.25 billion aggregate principal amount of 4.375% senior unsecured notes due 2029 in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act. The 4.375% senior unsecured notes due 2029 were sold pursuant to a purchase agreement by and among Vistra Operations, the Guarantor Subsidiaries and J.P. Morgan Securities LLC, as representative of the several initial purchasers. The 4.375% senior unsecured notes mature in May 2029, with interest payable in arrears on May 1 and November 1 beginning November 1, 2021 with interest accrued from May 10, 2021. Net proceeds, together with cash on hand, were used to repay all amounts outstanding under the Term Loan A Facility and to pay fees and expenses of $15 million related to the offering.

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. Through June 30,~~debt, which authorization expired in March 2022 no(the Prior Authorization). No amounts ~~had been~~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 March ~~2021 authorization.~~31, 2023, no amounts were repurchased under the Current Authorization.

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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.

On the Merger Date, the Company assumed the obligation of Dynegy's agreements under which a portion of the PJM capacity that cleared for Planning Years 2018-2019, 2019-2020 and 2020-2021 was sold to a financial institution (Legacy Forward Capacity Agreements, and, together with the 2021-2022 Forward Capacity Agreement, the Forward Capacity Agreements). In May 2021, the final capacity payment from PJM during the Planning Years 2020-2021 was paid, and the terms of the Legacy Forward Capacity were fulfilled.

Maturities

Long-term debt maturities at ~~June 30, 2022~~March 31, 2023 are as follows:


		June 30, 2022			March 31, 2023
Remainder of 2022		$	26
2023		40
Remainder of 2023				Remainder of 2023	$	33
2024	2024	1,940		2024	1,940
2025	2025	3,570		2025	3,567
2026	2026	1,006		2026	1,006
2027				2027	3,402
Thereafter	Thereafter	5,490		Thereafter	2,088
Unamortized premiums, discounts and debt issuance costs	Unamortized premiums, discounts and debt issuance costs	(82)		Unamortized premiums, discounts and debt issuance costs	(68)
Total long-term debt, including amounts due currently	Total long-term debt, including amounts due currently	$	11,990	Total long-term debt, including amounts due currently	$	11,968

~~11.~~12. 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

At ~~June 30, 2022,~~March 31, 2023, we had outstanding letters of credit totaling ~~$2.901~~$2.163 billion as follows:

•$~~2.565~~1.826 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;

•$~~174~~177 million to support battery and solar development projects;

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

•$7487 million to support our REP financial requirements with the PUCT, and

•$6146 million for other credit support requirements.

Surety Bonds

At ~~June 30, 2022,~~March 31, 2023, we had outstanding surety bonds totaling ~~$591~~$933 million to support performance under various contracts and legal obligations in the normal course of business.

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Litigation and Regulatory Proceedings

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

Litigation

Gas Index Pricing Litigation — We, through our subsidiaries, and ~~other companies have been~~another company remain named as defendants in ~~lawsuits~~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. We now remain as a defendant in only 1 action, which is a consolidated putative class action lawsuit pending in federal court in Wisconsin where a class has been certified and an interlocutory appeal has been filed inIn 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. We filed our opening brief in June 2021, and response briefs were filed in September 2021. Oral argument was held in April 2022. In our brief, we argue that the prior PUCT rushed to adopt a rule that dramatically raised the price of electricity in ERCOT, but in doing so failed to follow any of the rulemaking procedures required for the PUCT to undertake an emergency rulemaking, and we have asked the court to vacate this rule. Other parties also ~~filed briefs in support of~~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.

~~Koch Disputes~~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, weBrazos 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 lawsuit in Texas state court against Odessa-Ector Power Partners, L.P., Koch Resources, LLC, Koch AG & Energy Solutions, LLC, and Koch Energy Services, LLC (Koch) seeking equitable relief in which we contested the amount of the February 2021 earnout payment under the terms of the 2017 asset purchase agreement (APA) with Koch. Koch subsequently filed its own related lawsuit in Delaware Chancery Court, and the Delaware Chancery Court ruled that all claims relatedclaim to the APA dispute (including our equitable claims) would proceed in Delaware. We contested Koch's demand for $286 million for the February 2021 earnout payment as an unjust windfall and inconsistent with the parties' intent when they entered into the APA in 2017. In the three months ended March 31, 2021, we recorded a $286 million liability in other noncurrent liabilities and deferred credits in our condensed consolidated balance sheets. In March 2021, we also filed a lawsuit in New York state court against Koch for breach of contract and ineffective notice of force majeure related to Koch's failure to deliver contracted-for quantities of gas during Winter Strom Uri, which Koch removed to federal court. In November 2021, the disputes we had with Koch were resolved to the parties' mutual satisfaction and all the lawsuits have been dismissed. The matter was resolved within the amount that was reserved and was paid in the second quarter of 2022.recover approximately $1.9 billion from Brazos.

25In 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.

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Regulatory Investigations and Other Litigation Matters — Following the events of Winter Storm Uri, various regulatory bodies, including ERCOT, the ERCOT Independent Market Monitor, the Texas Attorney General, the FERC and the NRC initiated investigations or issued requests for information of various parties related to the significant load shed event that occurred during the event as well as operational challenges for generators arising from the event, including performance and fuel and supply issues. We responded to all those investigatory requests. In addition, a large number of personal injury and wrongful death lawsuits related to Winter Storm Uri have been, and continue to be, filed in various Texas state courts against us and numerous generators, transmission and distribution utilities, retail and electric providers, as well as ERCOT. We and other defendants requested that all pretrial proceedings in these personal injury cases be consolidated and transferred to a single multi-district litigation (MDL) pretrial judge. In June 2021, the MDL panel granted the request to consolidate all these cases into 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 ~~100~~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.

~~Climate Change~~

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~~In January 2021, the Biden administration issued a series of Executive Orders, including one titled~~ ~~Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis~~ (the Environment Executive Order) which directed agencies, including the EPA, to review various agency actions promulgated during the prior administration and take action where the previous administration's action conflicts with national objectives. Several of the EPA agency actions discussed below are now subject to this review.

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 ~~October 2021, the U.S. Supreme Court granted four petitions for certiorari of the D.C. Circuit Court's decision and consolidated the cases for review. 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. Additionally, in January 2021, the EPA, just prior to the transition to the Biden administration, issued a final rule setting forth a significant contribution finding for the purpose of regulating GHG emissions from new, modified, or reconstructed electric utility generating units. In ~~April 2021,~~October 2022, the D.C. Circuit Court ~~granted the EPA's unopposed motion~~issued an amended judgment, denying petitions for ~~voluntary vacatur and remand~~review of the ~~GHG significant contribution rule.~~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 on March 27, 2023 and has indicated its intent to issue a new proposal in Spring 2023.

Cross-State Air Pollution Rule (CSAPR)

In ~~April 2022,~~October 2015, the EPA ~~proposed a~~ revised ~~version of~~ the ~~CSAPR to address the 2015~~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). ~~The rule would apply~~As required under the CAA, in October 2018, the State of Texas submitted a State Implementation Plan (SIP) to ~~25 states beginning~~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, ~~ozone seasons. States where Vistra operates generation units~~the EPA disapproved Texas' SIP and the State of Texas, Luminant, certain trade groups, and others challenged that ~~would be subject to this proposed rule are Illinois, New Jersey, New York, Ohio, Pennsylvania, Texas, Virginia and West Virginia. The revised Group 3 trading program (previously established~~disapproval in the ~~Revised CSAPR Update Rule) would include emission budgets that~~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 ~~says are achievable through existing controls installed at power plants. Starting in 2026,~~moved to transfer our challenges to the ~~budgets would be based~~D.C. Circuit Court or have those challenges dismissed. Briefing on ~~levels achieved through installation~~the stay motion was completed on April 24, 2023.

In April 2022, prior to the EPA's disapproval of ~~selective catalytic reduction (SCR) controls at~~Texas' SIP, the ~~approximately 20% of large coal-fueled power plants that do not currently have such controls. Starting in 2025,~~EPA proposed a Federal Implementation Plan (FIP) to address the budgets would be updated annually to account for source retirements. Starting in 2024, the rule would also impose a daily emissions rate limit for coal-fired units with existing controls and would impose such a limit for units installing new controls in 2027.2015 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, but it has not yet been published in the Federal Register and is not yet effective. The FIP would apply 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 ~~expected~~intended to ~~finalize~~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. On May 1, 2023, the Fifth Circuit Court granted our motion to stay the EPA's disapproval of Texas' SIP pending a ~~rule by early 2023. We cannot predict~~decision on the ~~outcome~~merits and denied the EPA's motion to transfer our challenge to the D.C. Circuit Court. As a result of the ~~final rule or~~stay, we do not believe the ~~effects~~EPA has authority to implement the FIP as to Texas sources pending the resolution of the ~~final rule~~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 ~~operations of our generation fleet.~~the merits.

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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 ~~State Implementation Plan (SIP)~~SIP and a partial ~~Federal Implementation Plan (FIP).~~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 ~~BART rule is subject to the Environment Executive Order discussed above, and the~~ EPA has stated it is starting a proceeding for reconsideration of the BART ~~rule.~~rule, which we expect in Spring 2023. The challenges in the D.C. Circuit Court have been held in abeyance pending the EPA's action on reconsideration. On May 4, 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 will be submitting comments to the EPA on this proposal in July 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 ~~U.S. Court of Appeals for the~~ Fifth Circuit (Fifth Circuit Court). Subsequently, in October 2017, the Fifth Circuit Court granted the EPA's motion to hold the case in abeyance considering the EPA's representation that it intended to revisit the nonattainment rule. In December 2017, the TCEQ submitted a petition for reconsideration to the EPA.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 August 2020, the EPA issued a Finding of Failure for Texas to submit an attainment plan.~~ 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.

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 August 2017, the EPA announced that its reconsideration of the ELG rule would be limited to a review of the effluent limitations applicable to FGD and bottom ash wastewaters and the agency subsequently postponed the earliest compliance dates in the ELG rule for the application of effluent limitations for FGD and bottom ash wastewaters. Based on these administrative developments, the Fifth Circuit Court agreed to sever and hold in abeyance challenges to those effluent limitations. The remainder of the case proceeded, and 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. ~~In July 2021, the EPA announced its intent to revise the ELG rule and moved to hold the 2020 ELG revision litigation in abeyance pending the EPA's completion of its reconsideration rulemaking.~~ 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. Comments on the proposed rule are due by May 30, 2023.

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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 ~~intend to ask~~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. Briefing on the matter has been suspended while the D.C. Circuit Court makes a determination on the EPA's motion to consolidate these challenges with additional challenges that were filed in February 2023 regarding the EPA's decision regarding a facility in Ohio.

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 2two 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 ~~DMG,~~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, but stated that PRN may refile.~~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, and this matter ~~remains in the very early stages.~~is currently abated.

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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. These proposed closure costs are reflected in the ARO in our condensed consolidated balance sheets (see Note ~~17)~~18).

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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. We filed our opening brief in October 2021.~~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 3three of our sites in January 2022 and ~~1 additional site~~five of our sites in July 2022. ~~Additional~~One additional closure construction ~~permit applications~~application will be filed for our Baldwin facility in ~~August 2022.~~2023.

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

MISO 2015-2016 Planning Resource Auction

In May 2015, 3three 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 1one 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.

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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.

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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. ~~With the issuance of the order, this matter has been resolved in Dynegy's favor. The~~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 ~~have~~ 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. ~~We have filed a request for rehearing of~~Although the ~~June 2022 order and will vigorously defend our position. While~~ 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. The Company intends to reply substantively to this submission, and to vigorously defend its position, consistent with the FERC's scheduling orders.

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.

~~12.~~13. EQUITY

Share Repurchase Programs

In October 2021, we announced that the Board ~~has~~ authorized a ~~new~~ share repurchase program (Share Repurchase Program) under which up to ~~$2.0~~$2.00 billion of our outstanding shares of common stock may be repurchased. The Share Repurchase Program became effective on October 11, ~~2021, at which time it superseded~~2021. In August 2022 and March 2023, the ~~2020 Share Repurchase Program (described below)~~Board authorized incremental amounts of $1.25 billion and ~~any authorization remaining as of such date. We intend~~$1.0 billion, respectively, for repurchases to ~~use~~bring the net proceeds from the Series A Offering (described below) to repurchase shares of our outstanding common stock. In the three months ended June 30, 2022, 19,100,259 shares of our common stock were repurchasedtotal authorized under the Share Repurchase Program for approximately $474 million at an average price of $24.83 per share of common stock. In the six months ended June 30, 2022, 46,661,160 shares of our common stock were repurchased under the Share Repurchase Program for approximately $1.086 billion at an average price of $23.28 per share of common stock (sharesto $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 (a)	13,308,465	$	23.11	$	308	$	1,697
April 1, 2023 through May 4, 2023	5,555,721	24.04		133
January 1, 2023 through May 4, 2023	18,864,186	$	23.38	$	441	$	1,564

____________

(a)Shares repurchased include ~~320,000~~385,253 of unsettled shares repurchased for $7$9 million as of June 30, 2022). As of June 30, 2022, approximately $505 million was available for additional repurchases under the Share Repurchase Program. From July 1, 2022 through August 2, 2022, 4,530,102 of our common stock had been repurchased under the Share Repurchase Program for $105 million at an average price per share of common stock of $23.06, and at August 2, 2022, approximately $400 million was available for repurchase under the Share Repurchase Program.March 31, 2023.

Table of ~~August 4, 2022. We expect to complete repurchases under the Share Repurchase Program by the end of 2023.~~Contents

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.

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In September 2020, we announced that the Board authorized a share repurchase program (2020 Share Repurchase Program) under which up to $1.5 billion of our outstanding shares of common stock may be repurchased. The 2020 Share Repurchase Program was effective on January 1, 2021. No shares were repurchased in the three months ended June 30, 2021. In the six months ended June 30, 2021, 8,658,153 shares of our common stock were repurchased under the 2020 Share Repurchase Program for approximately $175 million at an average price of $20.21 per share of common stock. The 2020 Share Repurchase Program was superseded by the Share Repurchase Program in October 2021.

Preferred Stock

~~On October 15, 2021 (Series A Issuance Date), we issued~~At both March 31, 2023 and December 31, 2022, 1,000,000 shares of Series A Preferred Stock ~~in a private offering (Series A Offering). The net proceeds of the Series A Offering were approximately $990 million, after deducting underwriting commissions~~ and ~~offering expenses. We intend to use the net proceeds from the Series A Offering to repurchase shares of our outstanding common stock under the Share Repurchase Program (described above).~~

~~On December 10, 2021 (Series B Issuance Date), we issued~~ 1,000,000 shares of Series B Preferred Stock ~~in a private offering (Series B Offering). The net proceeds of the Series B Offering~~ were approximately $985 million, after deducting underwriting commissions and offering expenses. We intend to use the net proceeds from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments.

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.

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.

Three Months Ended March 31, 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 2022

June 2022

0.177

July 2022

September 2022

0.184

October 2022

December 2022

0.193

In February 2021, April 2021, July 2021 and October 2021, the Board declared quarterly dividends of $0.15 per share of common stock that were paid in March 2021, June 2021, September 2021 and December 2021, respectively.

~~In February 2022 and~~ May ~~2022, the Board declared quarterly dividends of $0.17 and $0.177 per share of common stock that were paid in March 2022 and June 2022, respectively. In July 2022,~~2023, the Board declared a quarterly dividend of ~~$0.184~~$0.204 per share of common stock that will be paid in ~~September 2022.~~June 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.

In February 2022, the Board declared a semi-annual dividend of $40.00 per share of Series A Preferred Stock that was paid in April 2022. In July 2022, the Board declared a semi-annual dividend of $40.00 per share of Series A Preferred Stock that will be paid in October 2022.

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

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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

In May ~~2022,~~2023, the Board declared a semi-annual dividend of ~~$35.97 (including amounts accrued from December 10, 2021 to December 15, 2021)~~$35.00 per share of Series B Preferred Stock that ~~was~~will be paid in June ~~2022.~~2023.

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, 2022,~~March 31, 2023, Vistra Operations can distribute approximately $4.4 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 $350 million and ~~$100~~$600 million ~~during~~for the three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021, respectively, and $950 million and $330 million for the six months ended June 30, 2022 and 2021,~~ 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, 2022,~~March 31, 2023, all of the restricted net assets of Vistra Operations may be distributed to Parent.

In addition to the restrictions under the Vistra Operations Credit Agreement, under applicable Delaware law, we are only permitted to make distributions either out of "surplus," which is defined as the excess of our net assets above our capital (the aggregate par value of all outstanding shares of our stock), or out of net profits for the fiscal year in which the distribution is declared or the prior fiscal year.

Under the terms of the Series A Preferred Stock 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 January 2022, in accordance with the terms of the warrant agreement, the exercise price of each warrant was adjusted downward to $34.00 (subject to further adjustment from time to time), or $52.15 (subject to adjustment of the exercise price from time to time) per share of Vistra common stock received. As of ~~June 30, 2022, 9000000~~March 31, 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, 2022:~~March 31, 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			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 at March 31, 2022		$	2,000	$	5	$	(2,170)	$	9,844	$	(2,363)	$	(16)	$	7,300	$	2	$	7,302
Balance at December 31, 2022																				Balance at December 31, 2022	$	2,000	$	5	$	(3,395)	$	9,928	$	(3,643)	$	7	$	4,902	$	16	$	4,918
Stock repurchases	Stock repurchases	—		—		(474)		—		—		—		(474)		—		(474)		Stock repurchases	—		—		(311)		—		—		—		(311)		—		(311)

Dividends declared on common stock	Dividends declared on common stock	—		—		—		—		(75)		—		(75)		—		(75)		Dividends declared on common stock	—		—		—		—		(77)		—		(77)		—		(77)
Dividends declared on preferred stock	Dividends declared on preferred stock	—		—		—		—		(38)		—		(38)		—		(38)		Dividends declared on preferred stock	—		—		—		—		(37)		—		(37)		—		(37)
Effects of stock-based incentive compensation plans	Effects of stock-based incentive compensation plans	—		—		—		40		—		—		40		—		40		Effects of stock-based incentive compensation plans	—		—		—		24		—		—		24		—		24
Net income (loss)	Net income (loss)	—		—		—		—		(1,365)		—		(1,365)		8		(1,357)		Net income (loss)	—		—		—		—		699		—		699		(1)		698

Change in accumulated other comprehensive income																				Change in accumulated other comprehensive income	—		—		—		—		—		1		1		—		1

Other		—		—		(1)		6		(1)				4		1		5
Balance at June 30, 2022		$	2,000	$	5	$	(2,645)	$	9,890	$	(3,842)	$	(16)	$	5,392	$	11	$	5,403
Balance at March 31, 2023																				Balance at March 31, 2023	$	2,000	$	5	$	(3,706)	$	9,952	$	(3,058)	$	8	$	5,201	$	15	$	5,216

~~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 at 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 at 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 at ~~June 30, 2022.~~March 31, 2023. Outstanding shares of Series A Preferred Stock totaled 1,000,000 at both ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 and outstanding shares of Series B Preferred Stock totaled 1,000,000 at both ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021.~~2022.

(b)Authorized shares totaled 1,800,000,000 at ~~June 30, 2022.~~March 31, 2023. Outstanding common shares totaled ~~420,839,230~~378,648,599 and ~~469,072,597~~389,754,870 at ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, respectively. Treasury shares totaled ~~115,372,902~~160,425,501 and ~~63,856,879~~147,424,202 at ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, respectively.

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The following table presents the changes to equity for the three months ended ~~June 30, 2021:~~March 31, 2022:


		Common Stock (a)		Treasury Stock		Additional Paid-in Capital		Retained Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss)		Total Stockholders' Equity		Noncontrolling Interest		Total Equity			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 at March 31, 2021		$	5	$	(1,148)	$	9,805	$	(2,516)	$	(46)	$	6,100	$	(7)	$	6,093

Balance at December 31, 2021																		Balance at December 31, 2021	$	2,000	$	5	$	(1,558)	$	9,824	$	(1,964)	$	(16)	$	8,291	$	1	$	8,292
Stock repurchases																		Stock repurchases	—		—		(612)		—		—		—		(612)		—		(612)

Dividends declared on common stock	Dividends declared on common stock	—		—		—		(73)		—		(73)		—		(73)		Dividends declared on common stock	—		—		—		—		(77)		—		(77)		—		(77)
Dividends declared on preferred stock																		Dividends declared on preferred stock	—		—		—		—		(37)		—		(37)		—		(37)
Effects of stock-based incentive compensation plans	Effects of stock-based incentive compensation plans	—		—		10		—		—		10		—		10		Effects of stock-based incentive compensation plans	—		—		—		18				—		18		—		18
Net income (loss)	Net income (loss)	—		—		—		36		—		36		(1)		35		Net income (loss)	—		—		—		—		(285)		—		(285)		1		(284)

Change in accumulated other comprehensive income (loss)		—		—		—		—		1		1		—		1

Other	Other	—		—		1		1		—		2		—		2		Other	—		—		—		2		—		—		2		—		2
Balance at June 30, 2021		$	5	$	(1,148)	$	9,816	$	(2,552)	$	(45)	$	6,076	$	(8)	$	6,068
Balance at March 31, 2022																		Balance at March 31, 2022	$	2,000	$	5	$	(2,170)	$	9,844	$	(2,363)	$	(16)	$	7,300	$	2	$	7,302

~~The following table presents the changes to equity for the six months ended June 30, 2021:~~

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 at
December 31, 2020
$ 5 $ (973) $ 9,786 $ (399) $ (48) $ 8,371 $ (10) $ 8,361
Stock repurchases — (175) — — — (175) — (175)
Dividends declared on common stock — — — (147) — (147) — (147)
Effects of stock-based incentive compensation plans — — 27 — 27 — 27
Net income (loss) — — — (2,006) — (2,006) 2 (2,004)
Change in accumulated other comprehensive income (loss) — — — — 3 3 — 3
Other — — 3 — — 3 — 3
Balance at June 30, 2021 $ 5 $ (1,148) $ 9,816 $ (2,552) $ (45) $ 6,076 $ (8) $ 6,068

~~________________~~____________

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

(b)Authorized shares totaled 1,800,000,000 at ~~June 30, 2021.~~March 31, 2022. Outstanding common shares totaled ~~482,468,556~~438,694,982 and ~~489,305,888~~469,072,597 at ~~June 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, respectively. Treasury shares totaled ~~49,701,377~~95,887,643 and ~~41,043,224~~63,856,879 at ~~June 30, 2021~~March 31, 2022 and December 31, ~~2020,~~2021, respectively.

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~~13.~~14. 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 1415 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.

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•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, 2022										December 31, 2021											March 31, 2023										December 31, 2022
		Level 1		Level 2		Level 3 (a)		Reclass (b)		Total		Level 1		Level 2		Level 3 (a)		Reclass (b)		Total			Level 1		Level 2		Level 3 (a)		Reclass (b)		Total		Level 1		Level 2		Level 3 (a)		Reclass (b)		Total
Assets:	Assets:																					Assets:
Commodity contracts	Commodity contracts	$	5,625	$	1,487	$	1,196	$	26	$	8,334	$	1,408	$	889	$	442	$	5	$	2,744	Commodity contracts	$	3,638	$	797	$	779	$	49	$	5,263	$	3,512	$	789	$	791	$	13	$	5,105
Interest rate swaps	Interest rate swaps	—		47		—		—		47		—		19		—		—		19		Interest rate swaps	—		87		—		2		89		—		135		—		—		135
Nuclear decommissioning trust – equity securities (c)	Nuclear decommissioning trust – equity securities (c)	555		—		—		—		555		724		—		—				724		Nuclear decommissioning trust – equity securities (c)	571		—		—		—		571		532		—		—				532
Nuclear decommissioning trust – debt securities (c)	Nuclear decommissioning trust – debt securities (c)	—		626		—				626		—		679		—				679		Nuclear decommissioning trust – debt securities (c)	—		687		—				687		—		658		—				658
Sub-total	Sub-total	$	6,180	$	2,160	$	1,196	$	26	9,562		$	2,132	$	1,587	$	442	$	5	4,166		Sub-total	$	4,209	$	1,571	$	779	$	51	6,610		$	4,044	$	1,582	$	791	$	13	6,430
Assets measured at net asset value (d):	Assets measured at net asset value (d):																					Assets measured at net asset value (d):
Nuclear decommissioning trust – equity securities (c)	Nuclear decommissioning trust – equity securities (c)									446										557		Nuclear decommissioning trust – equity securities (c)									492										458
Total assets	Total assets									$	10,008									$	4,723	Total assets									$	7,102									$	6,888
Liabilities:	Liabilities:																					Liabilities:
Commodity contracts	Commodity contracts	$	7,327	$	1,946	$	2,211	$	26	$	11,510	$	2,153	$	650	$	802	$	5	$	3,610	Commodity contracts	$	4,803	$	506	$	2,004	$	49	$	7,362	$	5,297	$	933	$	2,010	$	13	$	8,253
Interest rate swaps	Interest rate swaps	—		74		—		—		74		—		217		—		—		217		Interest rate swaps	—		76		—		2		78		—		83		—		—		83
Total liabilities	Total liabilities	$	7,327	$	2,020	$	2,211	$	26	$	11,584	$	2,153	$	867	$	802	$	5	$	3,827	Total liabilities	$	4,803	$	582	$	2,004	$	51	$	7,440	$	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 ~~other~~ investments line in our condensed consolidated balance sheets. See Note ~~17.~~18.

(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.

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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 1415 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.

~~Table of Contents~~

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 at ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021:~~2022:


June 30, 2022
March 31, 2023																						March 31, 2023
		Fair Value																							Fair Value
Contract Type (a)	Contract Type (a)	Assets		Liabilities		Total		Valuation Technique		Significant Unobservable Input		Range (b)									Average (b)	Contract Type (a)			Assets				Liabilities			Total				Valuation Technique					Significant Unobservable Input					Range (b)											Average (b)
Electricity purchases and sales	Electricity purchases and sales	$	891	$	(1,457)	$	(566)	Income Approach		Hourly price curve shape (c)		$	—		to		$75				$37	Electricity purchases and sales			$	611			$	(1,435)		$	(824)			Income Approach					Hourly price curve shape (c)					$	—		to		$80						$40
											MWh																											MWh
										Illiquid delivery periods for hub power prices and heat rates (d)		$	45		to		td20				$83																							Illiquid delivery periods for hub power prices and heat rates (d)					$	40	to			$80					$59
											MWh																																MWh
Options	Options	—		(541)		(541)			Option Pricing Model			Gas to power correlation (e)					10	%	to		100%			56%		Options			—			(415)					(415)					Option Pricing Model							Gas to power correlation (e)					10		%	to		100%		57%
										Power and gas volatility (e)		5		%	to		570%				287%																Power and gas volatility (e)								5	%	to			620%					314%
Financial transmission rights	Financial transmission rights	166		(47)		119		Market Approach (f)		Illiquid price differences between settlement points (g)		$	(15)		to		td0				$(2)	Financial transmission rights			135					(27)			108				Market Approach (f)					Illiquid price differences between settlement points (g)					$	(35)		to		td0						$(11)
											MWh																												MWh
Natural gas	Natural gas	89		(156)		(67)			Income Approach		Gas basis and illiquid delivery periods (h)				$	—	to		td5				$7		Natural gas			13			(112)				(99)					Income Approach							Gas basis and illiquid delivery periods (h)					$	—		to			$30		td3
										MMBtu																								MMBtu

Coal		36		—		36		Income Approach				Probability of default (i)					—%		to		40%			20			%
									Recovery rate (j)		—%	to			40%				20	%

Other ~~(k)~~(i)	Other ~~(k)~~(i)	14		(10)		4																Other ~~(k)~~(i)			20				(15)			5
Total	Total	$	1,196	$	(2,211)	$	(1,015)															Total			$	779			$	(2,004)		$	(1,225)


December 31, 2021
December 31, 2022																						December 31, 2022
		Fair Value																							Fair Value
Contract Type (a)	Contract Type (a)	Assets		Liabilities		Total		Valuation Technique		Significant Unobservable Input		Range (b)									Average (b)	Contract Type (a)			Assets				Liabilities			Total				Valuation Technique					Significant Unobservable Input					Range (b)											Average (b)
Electricity purchases and sales	Electricity purchases and sales	$	204	$	(470)	$	(266)	Income Approach		Hourly price curve shape (c)		$	—		to		$60				$30	Electricity purchases and sales			$	603			$	(1,332)		$	(729)			Income Approach					Hourly price curve shape (c)					$	—		to		$80						$38
											MWh																											MWh
										Illiquid delivery periods for hub power prices and heat rates (d)		$	20		to		td40				$80																							Illiquid delivery periods for hub power prices and heat rates (d)					$	25	to			$95					$60
											MWh																																MWh
Options	Options	1		(209)		(208)			Option Pricing Model			Gas to power correlation (e)					10	%	to		100%			56%		Options			—			(483)					(483)					Option Pricing Model							Gas to power correlation (e)					10		%	to		100%		56%
										Power and gas volatility (e)		5		%	to		490%				248%																Power and gas volatility (e)								5	%	to			620%					313%
Financial transmission rights	Financial transmission rights	122		(34)		88		Market Approach (f)		Illiquid price differences between settlement points (g)		$	(30)		to		td0				$(9)	Financial transmission rights			132					(31)			101				Market Approach (f)					Illiquid price differences between settlement points (g)					$	(35)		to		td0						$(11)
											MWh																												MWh
Natural gas	Natural gas	29		(86)		(57)			Income Approach		Gas basis (h)				$	(1)	to		td6				$8		Natural gas			20			(155)				(135)					Income Approach							Gas basis (h)					$	—		to			$30		td3
										MMBtu																								MMBtu
Coal		61		—		61		Income Approach				Probability of default (i)					—%		to		40%			20			%
									Recovery rate (j)		—%	to			40%				20	%

Other ~~(k)~~(i)	Other ~~(k)~~(i)	25		(3)		22																Other ~~(k)~~(i)			36				(9)			27
Total	Total	$	442	$	(802)	$	(360)															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.

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

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

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(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.

(i)~~Estimate of the range of probabilities of default based on past experience, the length of the contract, and both the Company's and the counterparty's credit ratings.~~

~~(j)Estimate of the default recovery rate based on historical corporate rates.~~

~~(k)~~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, 2022~~March 31, 2023 and ~~2021.~~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, 2022~~March 31, 2023 and ~~2021.~~2022.


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended March 31,
		2022		2021		2022		2021				2023		2022
Net asset (liability) balance at beginning of period		$	(629)	$	204	$	(360)	$	22
Total unrealized valuation gains (losses) (a)		(572)		(16)		(1,021)		174
Net liability balance at beginning of period										Net liability balance at beginning of period		$	(1,219)	$	(360)
Total unrealized valuation losses (a)										Total unrealized valuation losses (a)		(76)		(449)
Purchases, issuances and settlements (b):	Purchases, issuances and settlements (b):									Purchases, issuances and settlements (b):
Purchases	Purchases	57		23		95		40		Purchases		49		37
Issuances	Issuances	(31)		(4)		(42)		(10)		Issuances		(5)		(10)
Settlements	Settlements	77		(146)		174		(166)		Settlements		17		97
Transfers into Level 3 (c)	Transfers into Level 3 (c)	38		—		39		2		Transfers into Level 3 (c)		(14)		1
Transfers out of Level 3 (c)	Transfers out of Level 3 (c)	45		(15)		100		(16)		Transfers out of Level 3 (c)		23		55

Net change (d)	Net change (d)	(386)		(158)		(655)		24		Net change (d)		(6)		(269)
Net asset (liability) balance at end of period		$	(1,015)	$	46	$	(1,015)	$	46
Unrealized valuation gains (losses) relating to instruments held at end of period		$	(489)	$	3	$	(743)	$	49
Net liability balance at end of period										Net liability balance at end of period		$	(1,225)	$	(629)
Unrealized valuation losses relating to instruments held at end of period										Unrealized valuation losses relating to instruments held at end of period		$	(159)	$	(354)

____________

(a)~~During both~~For the three ~~and six~~ months ended ~~June 30, 2022,~~March 31, 2023 includes a net ~~loss~~gains of ~~$178~~$84 million recognized due to the discontinuance of NPNS accounting on a retail electric contract portfolio in the second quarter of 2022 where physical settlement is no longer considered probable throughout the contract ~~term as we opportunistically monetized certain positions.~~term.

(b)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.

(c)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, 2022,~~March 31, 2023, transfers into Level 3 primarily consist of power derivatives where forward pricing inputs have become unobservable and transfers out of Level 3 primarily consist of power ~~and coal~~ derivatives where forward pricing inputs have become observable. For the three ~~and six~~ months ended ~~June 30, 2021,~~March 31, 2022, transfers out of Level 3 primarily consist of ~~gas and~~ power derivatives where forward pricing inputs have become observable.

(d)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.

3835

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~~14.~~15.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 1314 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. The remaining existing swaps 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 effectively fix the SOFR component of the interest cost associated with the anticipated Transaction financings (see Note 2). The interest rate swaps are effective December 31, 2023 and expire December 31, 2030.

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Financial Statement Effects of Derivatives

Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of derivative contractual assets and liabilities as reported in our condensed consolidated balance sheets at ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021.~~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. During ~~both~~ the three ~~and six~~ months ended ~~June 30, 2022, a~~March 31, 2023, net ~~loss~~unrealized gains of ~~$414~~$153 million ~~was~~were recognized in operating revenues due to the discontinuance of NPNS accounting on a retail electric contract portfolio in the second quarter of 2022 where physical settlement is no longer considered probable throughout the contract ~~term as we opportunistically monetized certain positions.~~term. These amounts are reflected in commodity contracts derivative liabilities at ~~June 30,~~March 31, 2023 and December 31, 2022.


		June 30, 2022											March 31, 2023
		Derivative Assets				Derivative Liabilities							Derivative Assets				Derivative Liabilities
		Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total			Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total
Current assets	Current assets	$	7,410	$	39	$	8	$	—	$	7,457	Current assets	$	4,493	$	78	$	16	$	2	$	4,589
Noncurrent assets	Noncurrent assets	913		8		3		—		924		Noncurrent assets	745		9		9		—		763
Current liabilities	Current liabilities	(7)		—		(9,904)		(23)		(9,934)		Current liabilities	(23)		—		(5,580)		(43)		(5,646)
Noncurrent liabilities	Noncurrent liabilities	(8)		—		(1,591)		(51)		(1,650)		Noncurrent liabilities	(1)		—		(1,758)		(35)		(1,794)
Net assets (liabilities)	Net assets (liabilities)	$	8,308	$	47	$	(11,484)	$	(74)	$	(3,203)	Net assets (liabilities)	$	5,214	$	87	$	(7,313)	$	(76)	$	(2,088)


		December 31, 2021											December 31, 2022
		Derivative Assets				Derivative Liabilities							Derivative Assets				Derivative Liabilities
		Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total			Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total
Current assets	Current assets	$	2,496	$	14	$	3	$	—	$	2,513	Current assets	$	4,442	$	92	$	4	$	—	$	4,538
Noncurrent assets	Noncurrent assets	244		5		1		—		250		Noncurrent assets	656		43		3		—		702
Current liabilities	Current liabilities	—		—		(2,964)		(59)		(3,023)		Current liabilities	(1)		—		(6,562)		(47)		(6,610)
Noncurrent liabilities	Noncurrent liabilities	(1)		—		(645)		(158)		(804)		Noncurrent liabilities	(5)		—		(1,685)		(36)		(1,726)
Net assets (liabilities)	Net assets (liabilities)	$	2,739	$	19	$	(3,605)	$	(217)	$	(1,064)	Net assets (liabilities)	$	5,092	$	135	$	(8,240)	$	(83)	$	(3,096)

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At ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021,~~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)	Derivative (condensed consolidated statements of operations presentation)	Three Months Ended June 30,				Six Months Ended June 30,				Derivative (condensed consolidated statements of operations presentation)	Three Months Ended March 31,
		2022		2021		2022		2021				2023		2022
Commodity contracts (Operating revenues)	Commodity contracts (Operating revenues)	$	(2,180)	$	(183)	$	(3,007)	$	(98)	Commodity contracts (Operating revenues)		$	669	$	(827)
Commodity contracts (Fuel, purchased power costs and delivery fees)	Commodity contracts (Fuel, purchased power costs and delivery fees)	249		74		341		115		Commodity contracts (Fuel, purchased power costs and delivery fees)		(295)		92
Interest rate swaps (Interest expense and related charges)	Interest rate swaps (Interest expense and related charges)	35		(22)		149		53		Interest rate swaps (Interest expense and related charges)		(28)		114
Net gain (loss)	Net gain (loss)	$	(1,896)	$	(131)	$	(2,517)	$	70	Net gain (loss)		$	346	$	(621)

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.

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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, 2022								December 31, 2021									March 31, 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 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:	Derivative assets:																	Derivative assets:
Commodity contracts	Commodity contracts	$	8,308	$	(7,362)	$	(30)	$	916	$	2,739	$	(2,051)	$	(27)	$	661	Commodity contracts	$	5,214	$	(4,608)	$	(30)	$	576	$	5,092	$	(4,480)	$	(20)	$	592
Interest rate swaps	Interest rate swaps	47		(43)		—		4		19		(19)		—		—		Interest rate swaps	87		(47)		—		40		135		(64)		—		71
Total derivative assets	Total derivative assets	8,355		(7,405)		(30)		920		2,758		(2,070)		(27)		661		Total derivative assets	5,301		(4,655)		(30)		616		5,227		(4,544)		(20)		663
Derivative liabilities:	Derivative liabilities:																	Derivative liabilities:
Commodity contracts	Commodity contracts	(11,484)		7,362		1,881		(2,241)		(3,605)		2,051		784		(770)		Commodity contracts	(7,313)		4,608		1,038		(1,667)		(8,240)		4,480		1,675		(2,085)
Interest rate swaps	Interest rate swaps	(74)		43		—		(31)		(217)		19		—		(198)		Interest rate swaps	(76)		47		—		(29)		(83)		64		—		(19)
Total derivative liabilities	Total derivative liabilities	(11,558)		7,405		1,881		(2,272)		(3,822)		2,070		784		(968)		Total derivative liabilities	(7,389)		4,655		1,038		(1,696)		(8,323)		4,544		1,675		(2,104)
Net amounts	Net amounts	$	(3,203)	$	—	$	1,851	$	(1,352)	$	(1,064)	$	—	$	757	$	(307)	Net amounts	$	(2,088)	$	—	$	1,008	$	(1,080)	$	(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 at ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021:~~2022:


		June 30, 2022		December 31, 2021				March 31, 2023		December 31, 2022
Derivative type	Derivative type	Notional Volume				Unit of Measure	Derivative type	Notional Volume				Unit of Measure
Natural gas (a)	Natural gas (a)	7,266		4,701		Million MMBtu	Natural gas (a)	6,477		6,007		Million MMBtu
Electricity	Electricity	716,650		440,236		GWh	Electricity	818,519		754,762		GWh
Financial transmission rights (b)	Financial transmission rights (b)	247,006		224,876		GWh	Financial transmission rights (b)	213,784		225,845		GWh
Coal	Coal	53		25		Million U.S. tons	Coal	47		48		Million U.S. tons
Fuel oil	Fuel oil	109		87		Million gallons	Fuel oil	67		105		Million gallons

Emissions	Emissions	71		18		Million tons	Emissions	43		40		Million tons
Renewable energy certificates	Renewable energy certificates	30		32		Million certificates	Renewable energy certificates	31		31		Million certificates

Interest rate swaps – variable/fixed (c)	Interest rate swaps – variable/fixed (c)	$	6,720	$	6,720	Million U.S. dollars	Interest rate swaps – variable/fixed (c)	$	7,470	$	6,720	Million U.S. dollars
Interest rate swaps – fixed/variable (c)	Interest rate swaps – fixed/variable (c)	$	2,120	$	2,120	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 ~~July 2026.~~December 2030.

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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, 2022		December 31, 2021			March 31, 2023		December 31, 2022
Fair value of derivative contract liabilities (a)	Fair value of derivative contract liabilities (a)	$	(2,817)	$	(1,200)	Fair value of derivative contract liabilities (a)	$	(1,515)	$	(1,934)
Offsetting fair value under netting arrangements (b)	Offsetting fair value under netting arrangements (b)	1,757		660		Offsetting fair value under netting arrangements (b)	866		899
Cash collateral and letters of credit	Cash collateral and letters of credit	436		95		Cash collateral and letters of credit	328		253
Liquidity exposure	Liquidity exposure	$	(624)	$	(445)	Liquidity exposure	$	(321)	$	(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. At ~~June 30, 2022,~~March 31, 2023, total credit risk exposure to all counterparties related to derivative contracts totaled ~~$8.695~~$5.610 billion (including associated accounts receivable). The net exposure to those counterparties totaled ~~$1.012 billion~~$711 million at ~~June 30, 2022,~~March 31, 2023, after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure ~~to ERCOT~~ totaling ~~$178~~$172 million. At ~~June 30, 2022,~~March 31, 2023, the credit risk exposure to the banking and financial sector represented ~~84%~~82% of the total credit risk exposure and ~~24%~~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.

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~~15.~~16.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 78 for discussion of the TRA.

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~~16.~~17.SEGMENT INFORMATION

The operations of Vistra are aligned into 6six 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, ~~respectively,~~ and includes operations in the PJM, ISO-NE and NYISO markets. We determined it was appropriate to aggregate results from these markets into 1one reportable segment, East, given similar economic characteristics.

The West segment represents results from the CAISO market, including our ~~development of~~ battery ESS projects at our Moss Landing ~~and Oakland~~ power plant ~~sites~~site (see Note 2)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, ~~2022.~~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 ~~plan to retire~~retired in the ~~year~~years ended December 31, ~~2022.~~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 ~~scheduled to be~~ retired in ~~2022.~~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 ~~2021~~2022 Form 10-K. Our CODM uses more than one measure to assess segment performance, ~~including segment net income (loss), which~~but primarily focuses on Adjusted EBITDA. While we believe this is ~~the measure~~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, 2022 $ 1,792 $ (623) $ 319 $ 79 $ (83) $ 121 $ — $ (17) $ 1,588
June 30, 2021 1,919 (468) 505 48 (7) (41) — 609 2,565
Depreciation and amortization:
June 30, 2022 $ (36) $ (146) $ (179) $ 11 $ (18) $ (9) $ (17) $ — $ (394)
June 30, 2021 (54) (159) (193) (10) (26) (4) (18) — (464)
Operating income (loss):
June 30, 2022 $ 910 $ (1,706) $ (661) $ 24 $ (168) $ (50) $ (32) $ — $ (1,683)
June 30, 2021 1,811 (1,167) (95) (18) (249) (194) (26) — 62
Net income (loss):
June 30, 2022 $ 898 $ (1,638) $ (662) $ 25 $ (168) $ (45) $ 233 $ — $ (1,357)
June 30, 2021 1,810 (1,138) (100) (13) (246) (192) (86) — 35
Six Months ended Retail Texas East West Sunset Asset Closure Corporate and Other (b) Eliminations Consolidated
Operating revenues (a):
June 30, 2022 $ 3,617 $ (1,718) $ 1,274 $ 151 $ (223) $ 228 $ — $ 1,384 $ 4,713
June 30, 2021 3,669 615 1,230 81 249 (19) — (53) 5,772
Depreciation and amortization:
June 30, 2022 $ (72) $ (269) $ (358) $ (31) $ (37) $ (23) $ (34) $ — $ (824)
June 30, 2021 (107) (283) (389) (15) (51) (8) (34) — (887)
Operating income (loss):
June 30, 2022 $ 3,342 $ (3,684) $ (788) $ (37) $ (618) $ (113) $ (74) $ — $ (1,972)
June 30, 2021 1,905 (3,723) (92) (52) (246) (258) (55) — (2,521)
Net income (loss) (b):
June 30, 2022 $ 3,326 $ (3,610) $ (791) $ (36) $ (619) $ (107) $ 196 $ — $ (1,641)
June 30, 2021 1,898 (3,656) (99) (44) (241) (239) 377 — (2,004)
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures:
June 30, 2022 $ — $ 228 $ 18 $ 25 $ 11 $ — $ 24 $ — $ 306
June 30, 2021 — 142 26 2 11 4 21 — 206


















Three Months ended	Retail		Texas		East		West		Sunset		Asset Closure		Corporate and Other (b)		Eliminations		Consolidated
Operating revenues (a):
March 31, 2023	$	2,350	$	1,353	$	1,809	$	231	$	828	$	—	$	—	$	(2,146)	$	4,425
March 31, 2022	1,825		(1,095)		955		72		(118)		85		—		1,401		3,125
Depreciation and amortization:
March 31, 2023	$	(29)	$	(130)	$	(161)	$	(15)	$	(14)	$	—	$	(17)	$	—	$	(366)
March 31, 2022	(36)		(123)		(179)		(42)		(16)		(17)		(17)		—		(430)
Operating income (loss):
March 31, 2023	$	(588)	$	569	$	744	$	47	$	425	$	(29)	$	(37)	$	—	$	1,131
March 31, 2022	2,432		(1,977)		(126)		(61)		(400)		(113)		(43)		—		(288)
Net income (loss) (b):
March 31, 2023	$	(595)	$	584	$	745	$	52	$	424	$	(27)	$	(485)	$	—	$	698
March 31, 2022	2,428		(1,972)		(128)		(61)		(400)		(112)		(39)		—		(284)
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures:
March 31, 2023	$	1	$	102	$	23	$	2	$	15	$	—	$	14	$	—	$	157
March 31, 2022	—		139		5		19		3		—		14		—		180

__________________

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

Three months ended Retail (1) Texas East West Sunset Asset Closure Corporate and Other Eliminations (2) Consolidated
June 30, 2022 $ (667) $ (1,652) $ (649) $ (33) $ (290) $ 37 $ — $ 1,166 $ (2,088)
June 30, 2021 (18) (1,116) (148) (35) (259) (103) — 1,336 $ (343)
Six Months ended Retail (1) Texas East West Sunset Asset Closure Corporate and Other Eliminations (2) Consolidated
June 30, 2022 $ (1,037) $ (3,625) $ (849) $ (79) $ (725) $ 30 $ — $ 3,838 $ (2,447)
June 30, 2021 (22) (1,657) (183) (88) (330) (131) — 2,126 $ (285)





Three Months ended	Retail (1)		Texas		East		West		Sunset		Asset Closure		Corporate and Other		Eliminations (2)		Consolidated
March 31, 2023	$	140	$	368	$	943	$	12	$	477	$	17	$	—	$	(680)	$	1,277
March 31, 2022	(369)		(1,973)		(200)		(47)		(386)		(56)		—		2,673		$	(358)

___________________

(1)For ~~both~~ the three ~~and six~~ months ended ~~June 30, 2022,~~March 31, 2023, Retail segment includes unrealized net ~~losses~~gains of ~~$414~~$153 million due to the discontinuance of NPNS accounting on a retail electric contract portfolio in the second quarter of 2022 where physical settlement is no longer considered probable throughout the contract ~~term as we opportunistically monetized certain positions.~~term.

(2)Amounts attributable to generation segments offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results.

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(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).

~~17.~~18.SUPPLEMENTARY FINANCIAL INFORMATION

Impairment of Long-Lived Assets

In the ~~second~~first quarter of ~~2021,~~2023, we recognized an impairment loss of ~~$38~~$49 million related to our ~~Zimmer~~Kincaid generation facility in ~~Ohio~~Illinois as a result of a significant decrease in the ~~estimated useful life~~projected operating margins of the facility, ~~reflecting~~primarily driven by a decrease in ~~the economic forecast of the facility and the inability to secure capacity revenues for the plant in the PJM capacity auction held in May 2021.~~projected power prices. The impairment is reported in our ~~Asset Closure~~Sunset segment and includes write-downs of property, plant and equipment of ~~$33~~$45 million, write-downs of inventory of $2 million and write-downs of ~~inventory~~operating lease right-of-use assets of ~~$5 million in the second quarter of 2021.~~$2 million.

In determining the fair value of the impaired asset group, we utilized the income approach described in ASC 820, Fair Value Measurement.

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Interest Expense and Related Charges


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended March 31,
		2022		2021		2022		2021				2023		2022
Interest paid/accrued	Interest paid/accrued	$	147	$	118	$	273	$	230	Interest paid/accrued		$	156	$	126
Unrealized mark-to-market net (gains) losses on interest rate swaps	Unrealized mark-to-market net (gains) losses on interest rate swaps	(45)		9		(171)		(79)		Unrealized mark-to-market net (gains) losses on interest rate swaps		41		(126)
Amortization of debt issuance costs, discounts and premiums	Amortization of debt issuance costs, discounts and premiums	7		9		13		14		Amortization of debt issuance costs, discounts and premiums		6		6
Debt extinguishment loss		—		1		—		1

Capitalized interest	Capitalized interest	(8)		(10)		(14)		(18)		Capitalized interest		(10)		(6)
Other	Other	8		8		15		16		Other		14		7
Total interest expense and related charges	Total interest expense and related charges	$	109	$	135	$	116	$	164	Total interest expense and related charges		$	207	$	7

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note ~~10,~~11, was ~~4.05%~~4.70% and ~~3.89%~~3.94% at ~~June 30, 2022~~March 31, 2023 and ~~2021.~~2022.

Other Income and Deductions


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended March 31,
		2022		2021		2022		2021				2023		2022
Other income:	Other income:									Other income:
Insurance settlements (a)	Insurance settlements (a)	$	62	$	27	$	63	$	65	Insurance settlements (a)		$	1	$	1
Gain on settlement of rail transportation disputes (b)		—		—		—		15
Sale of land (b)		5		1		5		1

Interest income	Interest income	2		—		2		—		Interest income		14		—
All other	All other	2		8		7		11		All other		5		4
Total other income	Total other income	$	71	$	36	$	77	$	92	Total other income		$	20	$	5
Other deductions:	Other deductions:									Other deductions:

All other	All other	9		2		13		7		All other		3		4
Total other deductions	Total other deductions	$	9	$	2	$	13	$	7	Total other deductions		$	3	$	4

____________

(a)For the three months ended ~~June 30, 2022,~~March 31, 2023, reported in the ~~Texas~~West 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.~~ For the three months ended ~~June 30, 2021, reported in the Texas segment. For the six months ended June 30, 2021, $63 million reported in the Texas segment and $2 million~~March 31, 2022, reported in the Corporate and Other non-segment.

~~(b)Reported in the Asset Closure segment.~~

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Restricted Cash


		June 30, 2022				December 31, 2021					March 31, 2023				December 31, 2022
		Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets			Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets

Amounts related to remediation escrow accounts	Amounts related to remediation escrow accounts	$	25	$	11	$	21	$	13	Amounts related to remediation escrow accounts	$	23	$	32	$	37	$	33

Total restricted cash	Total restricted cash	$	25	$	11	$	21	$	13	Total restricted cash	$	23	$	32	$	37	$	33

Trade Accounts Receivable


		June 30, 2022		December 31, 2021			March 31, 2023		December 31, 2022
Wholesale and retail trade accounts receivable	Wholesale and retail trade accounts receivable	$	1,842	$	1,442	Wholesale and retail trade accounts receivable	$	1,517	$	2,124
Allowance for uncollectible accounts	Allowance for uncollectible accounts	(52)		(45)		Allowance for uncollectible accounts	(53)		(65)
Trade accounts receivable — net	Trade accounts receivable — net	$	1,790	$	1,397	Trade accounts receivable — net	$	1,464	$	2,059

Gross trade accounts receivable at ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 included unbilled retail revenues of ~~$633~~$474 million and ~~$426~~$607 million, respectively.

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Allowance for Uncollectible Accounts Receivable


		Six Months Ended June 30,					Three Months Ended March 31,
		2022		2021				2023		2022
Allowance for uncollectible accounts receivable at beginning of period	Allowance for uncollectible accounts receivable at beginning of period	$	45	$	45	Allowance for uncollectible accounts receivable at beginning of period		$	65	$	45
Increase for bad debt expense	Increase for bad debt expense	65		55		Increase for bad debt expense		35		29
Decrease for account write-offs	Decrease for account write-offs	(58)		(49)		Decrease for account write-offs		(47)		(25)

Allowance for uncollectible accounts receivable at end of period	Allowance for uncollectible accounts receivable at end of period	$	52	$	51	Allowance for uncollectible accounts receivable at end of period		$	53	$	49

Inventories by Major Category


		June 30, 2022		December 31, 2021			March 31, 2023		December 31, 2022
Materials and supplies	Materials and supplies	$	264	$	260	Materials and supplies	$	277	$	274
Fuel stock	Fuel stock	276		314		Fuel stock	328		252
Natural gas in storage	Natural gas in storage	61		36		Natural gas in storage	24		44
Total inventories	Total inventories	$	601	$	610	Total inventories	$	629	$	570

Investments


		June 30, 2022		December 31, 2021			March 31, 2023		December 31, 2022
Nuclear plant decommissioning trust	Nuclear plant decommissioning trust	$	1,627	$	1,960	Nuclear plant decommissioning trust	$	1,750	$	1,648
Assets related to employee benefit plans	Assets related to employee benefit plans	41		42		Assets related to employee benefit plans	30		30
Land	Land	42		44		Land	41		41
Miscellaneous other	Miscellaneous other	5		3		Miscellaneous other	11		10
Total investments	Total investments	$	1,715	$	2,049	Total investments	$	1,832	$	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 ~~asset~~liability reported in other noncurrent ~~assets)~~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, 2022		December 31, 2021			March 31, 2023		December 31, 2022
Debt securities (a)	Debt securities (a)	$	626	$	679	Debt securities (a)	$	687	$	658
Equity securities (b)	Equity securities (b)	1,001		1,281		Equity securities (b)	1,063		990
Total	Total	$	1,627	$	1,960	Total	$	1,750	$	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 ~~2.62%~~of 2.69% and ~~2.54%~~2.64% at ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, respectively, and an average maturity of ~~12 years and 10~~11 years at ~~June 30, 2022~~both March 31, 2023 and December 31, ~~2021, respectively.~~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 at ~~June 30, 2022~~March 31, 2023 mature as follows: ~~$221~~$260 million in one to five years, ~~$149~~$148 million in five to 10 years and ~~$256~~$279 million after 10 years.

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


		Three Months Ended June 30,				Six Months Ended June 30,					Three Months Ended March 31,
		2022		2021		2022		2021				2023		2022
Proceeds from sales of securities	Proceeds from sales of securities	$	236	$	134	$	334	$	267	Proceeds from sales of securities		$	119	$	98
Investments in securities	Investments in securities	$	(242)	$	(139)	$	(345)	$	(277)	Investments in securities		$	(125)	$	(103)

Property, Plant and Equipment


		June 30, 2022		December 31, 2021			March 31, 2023		December 31, 2022
Power generation and structures	Power generation and structures	$	16,599	$	16,195	Power generation and structures	$	16,647	$	16,597
Land	Land	589		608		Land	584		584
Office and other equipment	Office and other equipment	190		183		Office and other equipment	160		163
Total	Total	17,378		16,986		Total	17,391		17,344
Less accumulated depreciation	Less accumulated depreciation	(5,368)		(4,801)		Less accumulated depreciation	(6,019)		(5,753)
Net of accumulated depreciation	Net of accumulated depreciation	12,010		12,185		Net of accumulated depreciation	11,372		11,591
Finance lease right-of-use assets (net of accumulated depreciation)	Finance lease right-of-use assets (net of accumulated depreciation)	171		173		Finance lease right-of-use assets (net of accumulated depreciation)	169		173
Nuclear fuel (net of accumulated amortization of $106 million and $125 million)		259		212
Nuclear fuel (net of accumulated amortization of $175 million and $152 million)						Nuclear fuel (net of accumulated amortization of $175 million and $152 million)	285		268
Construction work in progress	Construction work in progress	344		486		Construction work in progress	785		522
Property, plant and equipment — net	Property, plant and equipment — net	$	12,784	$	13,056	Property, plant and equipment — net	$	12,611	$	12,554

Depreciation expenses totaled ~~$341~~$323 million and ~~$394~~$378 million for three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021, respectively, and $719 million and $749 million for six months ended June 30, 2022 and 2021,~~ 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, 2022 and December 31, 2021, asbestos removal liabilities totaled zero and $3 million, respectively. We have also identified conditional AROs for asbestos removal and disposal, which are specific to certain generation assets.

At ~~June 30, 2022,~~March 31, 2023, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled ~~$1.661~~$1.701 billion, which is ~~higher~~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 ~~asset~~liability has been recorded to our condensed consolidated balance sheet of ~~$34~~$49 million in other noncurrent ~~assets.~~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~~three months ended ~~June 30, 2022~~March 31, 2023 and ~~2021.~~2022.


		Six Months Ended June 30, 2022								Six Months Ended June 30, 2021									Three Months Ended March 31, 2023								Three Months Ended March 31, 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			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	Liability at beginning of period	$	1,635	$	320	$	495	$	2,450	$	1,585	$	359	$	492	$	2,436	Liability at beginning of period	$	1,688	$	284	$	465	$	2,437	$	1,635	$	320	$	495	$	2,450
Additions:	Additions:																	Additions:
Accretion	Accretion	26		7		10		43		25		8		11		44		Accretion	13		3		6		22		13		3		6		22
Adjustment for change in estimates	Adjustment for change in estimates	—		(2)		5		3		—		1		4		5		Adjustment for change in estimates	—		2		4		6		—		—		2		2

Reductions:	Reductions:																	Reductions:
Payments	Payments	—		(37)		(9)		(46)		—		(28)		(8)		(36)		Payments	—		(16)		(2)		(18)		—		(18)		(5)		(23)

Liability at end of period	Liability at end of period	1,661		288		501		2,450		1,610		340		499		2,449		Liability at end of period	1,701		273		473		2,447		1,648		305		498		2,451
Less amounts due currently	Less amounts due currently	—		(98)		(14)		(112)		—		(87)		(16)		(103)		Less amounts due currently	—		(111)		(28)		(139)		—		(88)		(16)		(104)
Noncurrent liability at end of period	Noncurrent liability at end of period	$	1,661	$	190	$	487	$	2,338	1,610		253		483		2,346		Noncurrent liability at end of period	$	1,701	$	162	$	445	$	2,308	1,648		217		482		2,347

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Other Noncurrent Liabilities and Deferred Credits

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


		June 30, 2022		December 31, 2021			March 31, 2023		December 31, 2022
Retirement and other employee benefits	Retirement and other employee benefits	$	276	$	276	Retirement and other employee benefits	$	237	$	237
Winter Storm Uri impact (a)	Winter Storm Uri impact (a)	170		261		Winter Storm Uri impact (a)	29		35
Identifiable intangible liabilities (Note 5)		144		147
Identifiable intangible liabilities (Note 6)						Identifiable intangible liabilities (Note 6)	139		140
Regulatory liability (b)	Regulatory liability (b)	—		325		Regulatory liability (b)	49		—
Finance lease liabilities	Finance lease liabilities	238		235		Finance lease liabilities	235		237
Uncertain tax positions, including accrued interest	Uncertain tax positions, including accrued interest	13		13		Uncertain tax positions, including accrued interest	15		13
Liability for third-party remediation	Liability for third-party remediation	18		17		Liability for third-party remediation	36		37

Accrued severance costs	Accrued severance costs	36		39		Accrued severance costs	34		36
Other accrued expenses	Other accrued expenses	188		176		Other accrued expenses	309		269
Total other noncurrent liabilities and deferred credits	Total other noncurrent liabilities and deferred credits	$	1,083	$	1,489	Total other noncurrent liabilities and deferred credits	$	1,083	$	1,004

____________

(a)Includes ~~the allocation of ERCOT default uplift charges and~~ future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri.

~~Table of Contents~~

(b)As of ~~June 30,~~March 31, 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 $49 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 ~~$34~~$40 million in other noncurrent assets. As of December 31, 2021, 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 $325 million in other noncurrent liabilities and deferred credits.

Fair Value of Debt

June 30, 2022 December 31, 2021
Long-term debt (see Note 10): Fair Value Hierarchy Carrying Amount Fair
Value Carrying Amount Fair
Value
Long-term debt under the Vistra Operations Credit Facilities Level 2 $ 2,534 $ 2,409 $ 2,549 $ 2,518
Vistra Operations Senior Notes Level 2 9,368 8,781 7,880 8,193
Forward Capacity Agreements Level 3 — — 211 211
Equipment Financing Agreements Level 3 85 85 85 85
Building Financing Level 2 — — 3 3
Other debt Level 3 3 3 3 3


		March 31, 2023				December 31, 2022
Long-term debt (see Note 11):	Fair Value Hierarchy	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt under the Vistra Operations Credit Facilities	Level 2	$	2,511	$	2,492	$	2,519	$	2,486
Vistra Operations Senior Notes	Level 2	9,382		8,926		9,378		8,830


Equipment Financing Agreements	Level 3	75		71		74		72

We determine fair value in accordance with accounting standards as discussed in Note ~~13.~~14. 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 at ~~June 30, 2022~~March 31, 2023 and December 31, ~~2021:~~2022:


		June 30, 2022		December 31, 2021			March 31, 2023		December 31, 2022
Cash and cash equivalents	Cash and cash equivalents	$	1,871	$	1,325	Cash and cash equivalents	$	518	$	455
Restricted cash included in current assets	Restricted cash included in current assets	25		21		Restricted cash included in current assets	23		37
Restricted cash included in noncurrent assets	Restricted cash included in noncurrent assets	11		13		Restricted cash included in noncurrent assets	32		33
Total cash, cash equivalents and restricted cash	Total cash, cash equivalents and restricted cash	$	1,907	$	1,359	Total cash, cash equivalents and restricted cash	$	573	$	525

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The following table summarizes our supplemental cash flow information for the ~~six~~three months ended ~~June 30, 2022~~March 31, 2023 and ~~2021:~~2022:

Six Months Ended June 30,
2022 2021
Cash payments related to:
Interest paid $ 264 $ 230
Capitalized interest (14) (18)
Interest paid (net of capitalized interest) $ 250 $ 212
Income taxes paid (refunds received) (a) $ 10 $ 35

~~____________~~


	Three Months Ended March 31,
	2023		2022
Cash payments related to:
Interest paid	$	212	$	190
Capitalized interest	(10)		(6)
Interest paid (net of capitalized interest)	$	202	$	184

~~(a)~~

For the ~~six~~three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021,~~ we paid state income taxes of ~~$18~~$1 million and ~~$37~~$1 million, respectively, and received state income tax refunds of $8$7 million and ~~$2 million,~~zero, 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,~~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 2021~~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, 2022.~~March 31, 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,~~March 31, 2023 and 2022 ~~and 2021~~ 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 ~~2021~~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 1617 to the Financial Statements for further information concerning our reportable business segments.

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~~CEO Transition~~

In March 2022, Vistra announced that the Board had named Jim Burke as its next Chief Executive Officer (CEO), effective August 1, 2022. Mr. Burke, who previously served as President and Chief Financial Officer, also joined the Company's Board upon assuming his new role. Vistra's previous CEO and director, Curt Morgan, will serve as a special advisor to Mr. Burke and the Board until April 30, 2023. The transition from Mr. Morgan to Mr. Burke was a product of the Company's formal succession planning process. In July 2022, the Company announced the appointment of Kris Moldovan as the Company's Executive Vice President and Chief Financial Officer, effective August 1, 2022.

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~~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 1112 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 ~~January 2022,~~September 2020, we announced ~~that, subject~~the planned development, at a cost of approximately $850 million, of up to ~~approval by~~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 ~~CPUC, we would enter into a 15-year resource adequacy contract with PG&E to develop an additional 350~~260 MW battery ESS ~~at our Moss Landing Power Plant site. The CPUC approved the resource adequacy contract~~came online in ~~April~~ 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 ~~September 2020,~~January 2022, we announced that, subject to approval by the ~~planned development, at~~CPUC, we would enter into a ~~cost of approximately $850 million, of up~~15-year resource adequacy contract with PG&E to ~~768 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~~develop an additional 350 MW battery ESS ~~came online~~at our Moss Landing Power Plant site. The CPUC approved the resource adequacy and energy settlement contract in April 2022. This battery ESS is expected to enter commercial operations in the ~~first six months~~summer of ~~2022.~~ 2023.

We will only invest in these growth projects if we are confident in the expected returns. See Note 23 to the Financial Statements for a summary of our solar and battery ~~energy storage~~ESS projects.

CO2 Reductions — In ~~April 2021,~~June 2022, September 2022 and January 2023, we ~~announced we would retire~~retired the Zimmer coal-fueled generation facility, the Joppa generation facilities ~~by September 1, 2022,~~ and ~~in June 2022, we retired~~ the ~~Zimmer coal~~Edwards coal-fueled generation ~~facility.~~facility, respectively. See Note 34 to the Financial Statements for a summary of our planned generation retirements.

~~Moss Landing Outages~~Comanche Peak Nuclear Plant License Renewal

In ~~September 2021, Moss Landing Phase I experienced an incident impacting a portion~~October 2022, we announced the submission of our application to the ~~battery ESS. A review found~~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 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. Moss Landing Phase II was 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. Moss Landing Phase I was not affected by this incident.

~~We have continued restoration work on the facilities~~licenses into 2050 and ~~have restored approximately 393 MW (or 98% of the 400 MW capacity) at June 30, 2022.~~

~~We do not expect these incidents to have a material impact on our results of operations.~~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 March 31, 2023, we have hedged approximately 86% of our expected generation volumes on average for the balance of 2023 through 2025 (with approximately 99% hedged for the balance of 2023 and approximately 96% 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.~~flows in 2021.

~~The weather event resulted in a $2.9 billion negative impact on the Company's pre-tax earnings in the six months ended June 30, 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 ~~below.~~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.

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 charged 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 ERCOT's $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 in proceeds from ERCOT in the second quarter of 2022. 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. Accordingly, we recognized the $544 million in expected proceeds as an expense reduction in the fourth quarter of 2021 within fuel, purchased power costs and delivery fees in our consolidated statements of operation. The final financial impact of Winter Storm Uri continues to be subject to the outcome of litigation arising from the event.

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 1213 to the Financial Statements for more information about our dividend program.

~~Preferred Stock Offerings~~

In October 2021, we issued 1,000,000 shares of Series A Preferred Stock in a private offering (Offering). The net proceeds of the Offering were approximately $990 million, after deducting underwriting commissions and offering expenses. We intend to use the net proceeds from the Offering to repurchase shares of our outstanding common stock under the Share Repurchase Program (discussed below).

In December 2021, we issued 1,000,000 shares of Series B Preferred Stock in a private offering (Series B Offering) under our Green Finance Framework. The net proceeds of the Series B Offering were approximately $985 million, after deducting underwriting commissions and offering expenses. We intend to use the proceeds from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments.

~~See Note 12 to the Financial Statements for more information concerning the Series A Preferred Stock and the Series B Preferred Stock.~~

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Share Repurchase Program

In October 2021, we announced that the Board had authorized a ~~new~~ 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. ~~The~~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 ~~superseded~~to $4.25 billion. We expect to complete repurchases under the ~~$1.5~~current $4.25 billion ~~share repurchase program previously announced in September 2020 (2020~~ Share Repurchase ~~Program). In~~Program by the ~~six months ended June 30, 2022, 46,661,160~~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	$	1,697
April 1, 2023 through May 4, 2023	5,555,721	24.04		133
January 1, 2023 through May 4, 2023	18,864,186	$	23.38	$	441	$	1,564

Since the Share Repurchase Program became effective in October 2021 through May 4, 2023, 116,665,098 shares of our common stock were repurchased ~~under the Share Repurchase Program~~ for approximately ~~$1.086~~$2.686 billion at an average price of $23.28 per share of common stock (shares repurchased include 320,000 of unsettled shares repurchased for $7 million as of June 30, 2022). As of June 30, 2022, approximately $505 million was available for additional repurchases under the Share Repurchase Program. From July 1, 2022 through August 2, 2022, 4,530,102 of our common stock had been repurchased under the Share Repurchase Program for $105 million at an average price per share of common stock of $23.06, and at August 2, 2022, $400 million was available for repurchase under the Share Repurchase Program. Since inception, 70,521,627 shares of our common stock were repurchased under the Share Repurchase Program for approximately $1.6 billion at an average price of $22.68$23.02 per share of common stock.

On August 4, 2022, the Board authorized an incremental $1.25 billion for repurchases under the Share Repurchase Program. Including the original Board authorization, approximately $1.65 billion remains available for share repurchases under the Share Repurchase Program as of August 4, 2022. We expect to complete repurchases under the Share Repurchase Program by the end of 2023. See Note 1213 to the Financial Statements for more information concerning the Share Repurchase ~~Program and the 2020 Share Repurchase~~ Program.

~~Macroeconomic Conditions~~

Global market demand, geopolitical events and high natural gas price volatility have resulted in increased market prices for energy, and we expect these conditions to persist, in particular in the near term. Due in large part to the Russia and Ukraine conflict as well as other factors, we have experienced substantial shifts in commodity prices, which in turn have (i) facilitated our comprehensive hedging strategy which we believe has positioned us to lock in significant revenues and Adjusted EBITDA opportunities in 2023 and beyond, (ii) led to significant mark-to-market impacts on forward commodity derivative instruments, and (iii) combined with our comprehensive hedging strategy, resulted in significant increases in our collateral posting obligations and required liquidity to support these net liabilities. See also ~~Financial Condition~~ ~~for further discussion of our collateral posting obligations and liquidity management activities.~~

Accordingly, with forward power and natural gas curves increasing materially in 2022, we have increased our hedging for future periods. As of June 30, 2022, we have hedged over 60% of our expected generation volumes on average for the three-year period 2023 to 2025 (with approximately 80% hedged for 2023).

Changes to the geopolitical situation and the inflationary environment, among other factors, have also created supply chain constraints that have reduced the availability of certain fuels, such as coal, as well as reduced the availability of certain equipment and supply relevant to construction of renewables projects. We are proactively managing through 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 from 2022 to 2023. In addition, depending on the final passage of the recently proposed Inflation Reduction Act, our Vistra Zero development projects could see enhanced returns from the impact of this legislation.

Additionally, we are closely monitoring developments of the Russia and Ukraine conflict including sanctions (or potential sanctions) against Russian energy exports and Russian nuclear fuel supply and enrichment activities, as well as actions by Russia to limit energy deliveries, which may further impact commodity prices in Europe and globally. Our 2022 refueling has not been affected by the Russia and Ukraine conflict. We work with a diverse set of global nuclear fuel cycle suppliers to procure our nuclear fuel, and therefore, we expect to have enough nuclear fuel to support all our refueling needs for the next few years. We are taking affirmative action by including mitigating strategies in our procurement portfolio to ensure we can secure the nuclear fuel needed to continue to operate our nuclear facility. If imports from Russia were banned, U.S. nuclear power generators could be in jeopardy of not being able to refuel all reactors.

~~Table of Contents~~

Debt Activity

We remain committed to a strong balance sheet and have ~~stated~~continued to state our objective to reduce our consolidated net leverage. We also intend to ~~continue to simplify and optimize our capital structure,~~ maintain adequate liquidity and pursue opportunities to refinance our long-term debt to extend ~~maturities and/or reduce ongoing interest expense. While~~maturities. See Note 11 to the ~~financial impacts resulting from Winter Storm Uri~~Financial Statements for details of our debt activity, including the April 2023 Amendment to the Vistra Operations Credit Agreement, and ~~higher margining requirements as a result of increasing power prices have caused an increase in our consolidated net leverage, the Company remains committed to a strong balance sheet. See~~ Note 10 to the Financial Statements for details of our ~~debt activity and Note 9 to the Financial Statements for details of our~~ accounts receivable financing.

~~Vistra Operations Credit Agreement Amendments~~ — In April 2022 and July 2022, the Vistra Operations Credit Agreement was amended to, among other things, (i) establish new classes of extended revolving credit commitments in aggregate amounts of $2.8 billion and $725 million as of April 2022 and July 2022, respectively, and the maturity date was extended from June 14, 2023 to April 29, 2027, (ii) require Vistra Operations to terminate at least $350 million in revolving commitments maturing April 29, 2027 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, and (iii) appoint certain additional revolving letter of credit issuers. See Note 10 to the Financial Statements for details of the Vistra Operations Credit Agreement amendments.

~~Commodity-Linked Revolving Credit Facility~~ — In February 2022, Vistra Operations entered into a credit agreement 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. The Credit Agreement provides for a senior secured commodity-linked revolving credit facility (the Commodity-Linked Facility). Vistra Operations intends to use the liquidity 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.

In order to support our comprehensive hedging strategy, in May 2022, we entered into an amendment to our 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 under the Commodity-Linked Facility from $2.0 billion to $2.25 billion.

~~See Note 10 to the Financial Statements for more information concerning the Commodity-Linked Facility.~~

Power Price, Natural Gas Price and Market Heat Rate Exposure

Estimated hedging levels for generation volumes in our Texas, East, West and Sunset segments at ~~June 30, 2022~~March 31, 2023 were as follows:


		2022		2023			2023		2024
Nuclear/Renewable/Coal Generation:	Nuclear/Renewable/Coal Generation:					Nuclear/Renewable/Coal Generation:
Texas	Texas	95	%	85	%	Texas	98	%	97	%
Sunset	Sunset	97	%	75	%	Sunset	94	%	61	%
Gas Generation:	Gas Generation:					Gas Generation:
Texas	Texas	87	%	52	%	Texas	97	%	91	%
East	East	95	%	89	%	East	95	%	84	%
West	West	96	%	92	%	West	100	%	81	%

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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, 2022.~~March 31, 2023.

Balance 2022 2023
Texas:
Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price $ 3 $ 18
Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price $ (3) $ (17)
Gas Generation: $1.00/MWh increase in spark spread $ 4 $ 20
Gas Generation: $1.00/MWh decrease in spark spread $ (3) $ (19)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ 1 $ (19)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price $ (1) $ 13
East:
Gas Generation: $1.00/MWh increase in spark spread $ 2 $ 6
Gas Generation: $1.00/MWh decrease in spark spread $ (1) $ (4)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ (1) $ 6
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price $ 1 $ (6)
West:
Gas Generation: $1.00/MWh increase in spark spread $ — $ —
Gas Generation: $1.00/MWh decrease in spark spread $ — $ —
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ — $ 1
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price $ — $ (1)
Sunset:
Coal Generation: $2.50/MWh increase in power price $ 1 $ 13
Coal Generation: $2.50/MWh decrease in power price $ (1) $ (12)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ 1 $ (10)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ (1) $ 10

~~PJM Auction Results~~

In June 2022, Vistra reported its results from PJM's Reliability Pricing Model (RPM) auction results for planning year 2023-2024, and the table below lists clearing price per MW-day and our cleared capacity volumes by zone:

Clearing Price per MW-day East Segment MW Cleared Sunset Segment MW Cleared Total
MW Cleared
RTO zone $ 34.13 2,890 — 2,890
ComEd zone $ 34.13 1,151 408 1,559
DEOK zone $ 34.13 11 924 935
EMAAC zone $ 49.49 828 — 828
MAAC zone $ 49.49 545 — 545
ATSI zone $ 34.13 112 — 112
Total $ 37.20 5,537 1,332 6,869


	Balance 2023		2024
Texas:
Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price	$	2	$	4
Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price	$	(2)	$	(3)
Gas Generation: $1.00/MWh increase in spark spread	$	2	$	4
Gas Generation: $1.00/MWh decrease in spark spread	$	(1)	$	(4)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	(4)	$	(15)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	—	$	9
East:
Gas Generation: $1.00/MWh increase in spark spread	$	3	$	9
Gas Generation: $1.00/MWh decrease in spark spread	$	(1)	$	(8)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	(2)	$	(10)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	2	$	10
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	$	4	$	24
Coal Generation: $2.50/MWh decrease in power price	$	(2)	$	(21)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	(3)	$	(13)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	3	$	13

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RESULTS OF OPERATIONS

In the three ~~and six~~ months ended ~~June 30, 2022,~~March 31, 2023, our operating segments delivered ~~strong~~solid 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 stability of our integrated model, including a diversified generation fleet, retail and commercial and hedging activities in support of our integrated business. ~~Notably,~~As part of our comprehensive hedging strategy, we hedged longer-dated revenues and fuel costs to reduce risk and lock in value as forward power and gas curves moved up materially, and we believe this has positioned us to significantly benefit operating results in 2023 and beyond. In addition, we executed on our share repurchase strategy.

Consolidated Financial Results — Three ~~and Six~~ Months Ended ~~June 30, 2022~~March 31, 2023 Compared to Three ~~and Six~~ Months Ended ~~June 30, 2021~~March 31, 2022


		Three Months Ended June 30,				Favorable (Unfavorable) $ Change				Six Months Ended June 30,								Favorable (Unfavorable) $ Change							Three Months Ended March 31,				Favorable (Unfavorable) $ Change
		2022		2021				2022				2021												2023		2022
Operating revenues	Operating revenues	$	1,588	$	2,565			$	(977)			$	4,713			$	5,772				$	(1,059)	Operating revenues						$	4,425	$	3,125	$	1,300
Fuel, purchased power costs and delivery fees	Fuel, purchased power costs and delivery fees	(2,162)		(1,320)		(842)				(4,441)				(6,065)				1,624		Fuel, purchased power costs and delivery fees							(2,170)		(2,279)		109
Operating costs	Operating costs	(435)		(429)		(6)				(851)				(801)				(50)		Operating costs							(421)		(416)		(5)
Depreciation and amortization	Depreciation and amortization	(394)		(464)		70				(824)				(887)				63		Depreciation and amortization							(366)		(430)		64
Selling, general and administrative expenses	Selling, general and administrative expenses	(280)		(252)		(28)				(569)				(502)				(67)		Selling, general and administrative expenses							(288)		(288)		—

Impairment of long-lived assets	Impairment of long-lived assets	—		(38)		38				—				(38)				38		Impairment of long-lived assets							(49)		—		(49)
Operating income (loss)	Operating income (loss)	(1,683)		62		(1,745)				(1,972)				(2,521)				549		Operating income (loss)							1,131		(288)		1,419
Other income	Other income	71		36		35				77				92				(15)		Other income							20		5		15
Other deductions	Other deductions	(9)		(2)		(7)				(13)				(7)				(6)		Other deductions							(3)		(4)		1
Interest expense and related charges	Interest expense and related charges	(109)		(135)		26				(116)				(164)				48		Interest expense and related charges							(207)		(7)		(200)
Impacts of Tax Receivable Agreement	Impacts of Tax Receivable Agreement	(34)		(41)		7				(115)				(4)				(111)		Impacts of Tax Receivable Agreement							(65)		(81)		16

Income (loss) before income taxes	Income (loss) before income taxes	(1,764)		(80)		(1,684)				(2,139)				(2,604)				465		Income (loss) before income taxes							876		(375)		1,251
Income tax benefit		407		115		292				498				600				(102)
Income tax (expense) benefit																				Income tax (expense) benefit							(178)		91		(269)
Net income (loss)	Net income (loss)	$	(1,357)	$	35	$	(1,392)			$	(1,641)			$	(2,004)			$	363	Net income (loss)							$	698	$	(284)	$	982

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 $ (83) $ 121 $ (17) $ 1,588
Fuel, purchased power costs and delivery fees (616) (697) (713) (51) 17 (119) 17 (2,162)
Operating costs (35) (208) (73) (11) (74) (34) — (435)
Depreciation and amortization (36) (146) (179) 11 (18) (9) (17) (394)
Selling, general and administrative expenses (195) (32) (15) (4) (10) (9) (15) (280)
Operating income (loss) 910 (1,706) (661) 24 (168) (50) (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 (168) (45) (174) (1,764)
Income tax benefit — — — — — — 407 407
Net income (loss) $ 898 $ (1,638) $ (662) $ 25 $ (168) $ (45) $ 233 $ (1,357)

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Three Months Ended June 30, 2021
Retail Texas East West Sunset Asset
Closure Eliminations / Corporate and Other Vistra
Consolidated
Operating revenues $ 1,919 $ (468) $ 505 $ 48 $ (7) $ (41) $ 609 $ 2,565
Fuel, purchased power costs and delivery fees 150 (333) (319) (38) (139) (32) (609) (1,320)
Operating costs (29) (184) (69) (10) (69) (68) — (429)
Depreciation and amortization (54) (159) (193) (10) (26) (4) (18) (464)
Selling, general and administrative expenses (175) (23) (19) (8) (8) (11) (8) (252)
Impairment of long-lived assets — — — — — (38) — (38)
Operating income (loss) 1,811 (1,167) (95) (18) (249) (194) (26) 62
Other income 1 27 — — 3 2 3 36
Other deductions — (2) — — — — — (2)
Interest expense and related charges (2) 4 (5) 5 — — (137) (135)
Impacts of Tax Receivable Agreement — — — — — — (41) (41)
Income (loss) before income taxes 1,810 (1,138) (100) (13) (246) (192) (201) (80)
Income tax benefit — — — — — — 115 115
Net income (loss) $ 1,810 $ (1,138) $ (100) $ (13) $ (246) $ (192) $ (86) $ 35


	Three Months Ended March 31, 2023
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	2,350	$	1,353	$	1,809	$	231	$	828	$	—	$	(2,146)	$	4,425
Fuel, purchased power costs and delivery fees	(2,690)		(395)		(820)		(148)		(262)		(1)		2,146		(2,170)
Operating costs	(28)		(228)		(65)		(15)		(65)		(20)		—		(421)
Depreciation and amortization	(29)		(130)		(161)		(15)		(14)		—		(17)		(366)
Selling, general and administrative expenses	(191)		(31)		(19)		(6)		(13)		(8)		(20)		(288)

Impairment of long-lived assets	—		—		—		—		(49)		—		—		(49)
Operating income (loss)	(588)		569		744		47		425		(29)		(37)		1,131
Other income	—		12		1		1		1		3		2		20
Other deductions	—		(1)		—		—		(1)		—		(1)		(3)
Interest expense and related charges	(7)		4		—		4		(1)		(1)		(206)		(207)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(65)		(65)

Income (loss) before income taxes	(595)		584		745		52		424		(27)		(307)		876
Income tax expense	—		—		—		—		—		—		(178)		(178)
Net income (loss)	$	(595)	$	584	$	745	$	52	$	424	$	(27)	$	(485)	$	698

~~Consolidated results decreased $1.745~~


	Three Months Ended March 31, 2022
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	1,825	$	(1,095)	$	955	$	72	$	(118)	$	85	$	1,401	$	3,125
Fuel, purchased power costs and delivery fees	864		(526)		(828)		(73)		(195)		(120)		(1,401)		(2,279)
Operating costs	(33)		(201)		(57)		(12)		(62)		(50)		(1)		(416)
Depreciation and amortization	(36)		(123)		(179)		(42)		(16)		(17)		(17)		(430)
Selling, general and administrative expenses	(188)		(32)		(17)		(6)		(9)		(11)		(25)		(288)


Operating income (loss)	2,432		(1,977)		(126)		(61)		(400)		(113)		(43)		(288)
Other income	—		1		—		—		—		2		2		5
Other deductions	(3)		(1)		—		—		—		—		—		(4)
Interest expense and related charges	(1)		5		(2)		—		—		(1)		(8)		(7)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(81)		(81)

Income (loss) before income taxes	2,428		(1,972)		(128)		(61)		(400)		(112)		(130)		(375)
Income tax benefit	—		—		—		—		—		—		91		91
Net income (loss)	$	2,428	$	(1,972)	$	(128)	$	(61)	$	(400)	$	(112)	$	(39)	$	(284)

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Operating income (loss) increased $1.419 billion to an operating ~~loss~~income of ~~$1.683~~$1.131 billion in the three months ended ~~June 30, 2022~~March 31, 2023 compared to the three months ended ~~June 30, 2021. The change~~March 31, 2022. Results for the three months ended March 31, 2023 were favorably impacted by $1.085 billion in ~~results is primarily driven by a $1.709 billion~~ pre-tax ~~increase~~unrealized mark-to-market gains on derivative positions due to power and natural gas forward market curves moving down in the three months ended March 31, 2023 compared to $360 million in pre-tax unrealized mark-to-market losses on commodity ~~hedging transactions which was driven by a material increase in forward~~derivative positions due to power and natural gas ~~price~~forward market curves ~~during~~moving up in the three months ended ~~June 30, 2022 and a~~March 31, 2022. Included within these unrealized mark-to-market changes are pre-tax net unrealized ~~loss~~gains of ~~$414~~$153 million recorded in the three months ended March 31, 2023 due to the second quarter of 2022 discontinuance of NPNS accounting ~~as of June 30, 2022~~ on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract term as we opportunistically monetized certain positions. We believe the increase in forward power and natural gas prices has positioned us to significantly benefit operating results in 2023 and beyond.term.

Interest expense and related charges ~~decreased $26~~increased $200 million to ~~$109~~$207 million in the three months ended ~~June 30, 2022~~March 31, 2023 compared to the three months ended ~~June 30, 2021~~March 31, 2022 driven by ~~unrealized mark-to-market gains on interest rate swaps of $45 million in 2022 compared to~~ unrealized mark-to-market losses on interest rate swaps of $9$41 million in ~~2021. The change~~2023 compared to $126 million in ~~unrealized results is driven by an increase~~gains in 2022 due to less volatility in interest rates ~~during~~in the three months ended ~~June 30, 2022. This favorable variance is partially offset by~~March 31, 2023 compared to the three months ended March 31, 2022 and an increase in interest paid/accrued of ~~$29~~$30 million driven by higher ~~average borrowings during the three months ended June 30, 2022.~~effective interest rates in 2023. See Note 1718 to the Financial Statements.

For the three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021,~~ the ~~Impacts~~impacts of the ~~Tax Receivable Agreement totaled~~TRA resulted in expense of ~~$34~~$65 million and ~~$41~~$81 million, respectively. See Note 78 to the Financial Statements for discussion of the impacts of the ~~Tax Receivable Agreement~~TRA obligation.

For the three months ended ~~June 30, 2022,~~March 31, 2023, income tax ~~benefit~~expense totaled ~~$407~~$178 million and the effective tax rate was ~~23.1%~~20.3%. For the three months ended ~~June 30, 2021,~~March 31, 2022, income tax benefit totaled ~~$115~~$91 million, and the effective tax rate was ~~143.8%~~24.3%. See Note 67 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

~~Table of Contents~~

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 $ (223) $ 228 $ 1,384 $ 4,713
Fuel, purchased power costs and delivery fees 248 (1,223) (1,541) (124) (196) (221) (1,384) (4,441)
Operating costs (68) (409) (130) (23) (142) (78) (1) (851)
Depreciation and amortization (72) (269) (358) (31) (37) (23) (34) (824)
Selling, general and administrative expenses (383) (65) (33) (10) (20) (19) (39) (569)
Operating income (loss) 3,342 (3,684) (788) (37) (618) (113) (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) (619) (107) (302) (2,139)
Income tax benefit — — — — — — 498 498
Net income (loss) $ 3,326 $ (3,610) $ (791) $ (36) $ (619) $ (107) $ 196 $ (1,641)

Six Months Ended June 30, 2021
Retail Texas East West Sunset Asset
Closure Eliminations / Corporate and Other Vistra
Consolidated
Operating revenues $ 3,669 $ 615 $ 1,230 $ 81 $ 249 $ (19) $ (53) $ 5,772
Fuel, purchased power costs and delivery fees (1,250) (3,651) (773) (86) (299) (59) 53 (6,065)
Operating costs (60) (364) (123) (17) (129) (108) — (801)
Depreciation and amortization (107) (283) (389) (15) (51) (8) (34) (887)
Selling, general and administrative expenses (347) (40) (37) (15) (16) (26) (21) (502)
Impairment of long-lived assets — — — — — (38) — (38)
Operating income (loss) 1,905 (3,723) (92) (52) (246) (258) (55) (2,521)
Other income 1 64 — — 4 19 4 92
Other deductions (4) (4) — — 1 — — (7)
Interest expense and related charges (4) 7 (7) 8 — — (168) (164)
Impacts of Tax Receivable Agreement — — — — — — (4) (4)
Income (loss) before income taxes 1,898 (3,656) (99) (44) (241) (239) (223) (2,604)
Income tax benefit — — — — — — 600 600
Net income (loss) $ 1,898 $ (3,656) $ (99) $ (44) $ (241) $ (239) $ 377 $ (2,004)

~~Table of Contents~~

Operating loss decreased $549 million to $1.972 billion in the six months ended June 30, 2022 compared to the six months ended June 30, 2021. The change in results is driven by the $2.9 billion realized loss associated with Winter Storm Uri in the first quarter of 2021. Partially offsetting the Winter Storm Uri impact, results were unfavorably impacted by a $2.165 billion increase in pre-tax unrealized mark-to-market losses on derivative positions. Power and natural gas forward market curves moved up during the six months ended June 30, 2022 driving pre-tax unrealized mark-to-market losses on commodity hedging transactions. Additionally, a pre-tax net unrealized loss of $414 million was recorded due to the discontinuance of NPNS accounting as of June 30, 2022 on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract term as we opportunistically monetized certain positions. We believe the increase in forward power and natural gas prices has positioned us to significantly benefit operating results in 2023 and beyond.

Interest expense and related charges decreased $48 million to $116 million in the six months ended June 30, 2022 compared to the six months ended June 30, 2021 driven by unrealized mark-to-market gains on interest rate swaps of $171 million in 2022 compared to $79 million in 2021 which is due to a more significant rise in interest rates in the six months ended June 30, 2022, partially offset by an increase in interest paid/accrued of $43 million driven by higher average borrowings in 2022. See Note 17 to the Financial Statements.

For the six months ended June 30, 2022 and 2021, the Impacts of the Tax Receivable Agreement totaled expense of $115 million and $4 million, respectively. See Note 7 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement obligation.

For the six months ended June 30, 2022, income tax benefit totaled $498 million and the effective tax rate was 23.3%. For the six months ended June 30, 2021, income tax benefit totaled $600 million, and the effective tax rate was 23.0%. See Note 6 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

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 certain 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 ~~material~~ 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).

5955

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Adjusted EBITDA — Three ~~and Six~~ Months Ended ~~June 30, 2022~~March 31, 2023 Compared to Three ~~and Six~~ Months Ended ~~June 30, 2021~~March 31, 2022


		Three Months Ended June 30,				Favorable (Unfavorable) $ Change				Six Months Ended June 30,								Favorable (Unfavorable) $ Change							Three Months Ended March 31,				Favorable (Unfavorable) $ Change
		2022		2021				2022				2021												2023		2022
Net income (loss)	Net income (loss)	$	(1,357)	$	35			$	(1,392)			$	(1,641)			$	(2,004)				$	363	Net income (loss)						$	698	$	(284)	$	982
Income tax benefit		(407)		(115)		(292)				(498)				(600)				102
Income tax expense (benefit)																				Income tax expense (benefit)							178		(91)		269
Interest expense and related charges (a)	Interest expense and related charges (a)	109		135		(26)				116				164				(48)		Interest expense and related charges (a)							207		7		200
Depreciation and amortization (b)	Depreciation and amortization (b)	412		484		(72)				864				927				(63)		Depreciation and amortization (b)							389		452		(63)
EBITDA before Adjustments	EBITDA before Adjustments	(1,243)		539		(1,782)				(1,159)				(1,513)				354		EBITDA before Adjustments							1,472		84		1,388
Unrealized net loss resulting from commodity hedging transactions (c)		1,987		278		1,709				2,347				182				2,165
Unrealized net (gain) loss resulting from commodity hedging transactions (c)																				Unrealized net (gain) loss resulting from commodity hedging transactions (c)							(1,085)		360		(1,445)
Generation plant retirement expenses	Generation plant retirement expenses	—		15		(15)				6				15				(9)		Generation plant retirement expenses							1		6		(5)
Fresh start/purchase accounting impacts	Fresh start/purchase accounting impacts	—		(79)		79				—				(79)				79		Fresh start/purchase accounting impacts							3		—		3
Impacts of Tax Receivable Agreement	Impacts of Tax Receivable Agreement	34		41		(7)				115				4				111		Impacts of Tax Receivable Agreement							65		81		(16)

Non-cash compensation expenses	Non-cash compensation expenses	17		12		5				34				29				5		Non-cash compensation expenses							22		17		5
Transition and merger expenses	Transition and merger expenses	3		1		2				20				(13)				33		Transition and merger expenses							1		17		(16)
Impairment of long-lived assets	Impairment of long-lived assets	—		38		(38)				—				38				(38)		Impairment of long-lived assets							49		—		49

Winter Storm Uri impact (d)		(62)		(35)		(27)				(116)				900				(1,016)
PJM capacity performance default impacts (d)																				PJM capacity performance default impacts (d)							20		—		20
Winter Storm Uri impacts (e)																				Winter Storm Uri impacts (e)							(33)		(54)		21
Other, net	Other, net	1		1		—				31				7				24		Other, net							(2)		30		(32)
Adjusted EBITDA	Adjusted EBITDA	$	737	$	811	$	(74)			$	1,278			$	(430)			$	1,708	Adjusted EBITDA							$	513	$	541	$	(28)

____________

(a)Includes unrealized mark-to-market net ~~gains on interest rate swaps of $45 million and unrealized mark-to-market~~ losses on interest rate swaps of $9$41 million for the three months ended ~~June 30, 2022 and 2021, respectively,~~March 31, 2023 and unrealized mark-to-market net gains on interest rate swaps of ~~$171 million and $79~~$126 million for the ~~six~~three months ended ~~June 30, 2022 and 2021, respectively.~~March 31, 2022.

(b)Includes nuclear fuel amortization in the Texas segment of ~~$18~~$23 million and ~~$20~~$22 million for the three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021, respectively, and $40 million and $40 million for the six months ended June 30, 2022 and 2021,~~ respectively.

(c)Net pre-tax unrealized mark-to-market ~~losses~~gains on commodity ~~and~~ hedging transactions were driven by ~~the increase~~a decrease in power and natural gas ~~forward market~~price curves during the three ~~and six~~ months ended ~~June 30, 2022.~~March 31, 2023. Additionally, awe recorded pre-tax net unrealized ~~loss~~gains of ~~$414~~$153 million ~~was recorded~~in the three months ended March 31, 2023 due to the second quarter of 2022 discontinuance of NPNS accounting ~~as of June 30, 2022~~ on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract ~~term as we opportunistically monetized certain positions.~~term.

(d)~~For the six months ended June 30, 2021, includes the following~~Represents initial estimate of ~~the~~anticipated market participant defaults on PJM capacity performance penalties due to extreme magnitude of penalties associated with Winter Storm ~~Uri impacts,~~Elliott, which ~~we believe are not reflective of our operating performance: the allocation of ERCOT default uplift charges which~~amounts are expected to be ~~paid over several decades under current protocols, accrual~~withheld by PJM from our net bonus position during 2023.

(e)For the three months ended March 31, 2023, includes reductions to Adjusted EBITDA reflecting bill credit applications of ~~Koch earn-out amounts~~$34 million. For the three months ended March 31, 2022, includes reductions to Adjusted EBITDA reflecting default uplift charges of $42 million, attributable to ERCOT receiving payments that ~~we paid in~~reduced the ~~second quarter~~market wide default balance, and bill credit applications of ~~2022, future bill credits related to Winter Storm Uri and Winter Storm Uri related legal fees and other costs. The~~$12 million. In 2021, an adjustment for future bill credits ~~relates~~was recorded related to large commercial and industrial customers that curtailed their usage during Winter Storm Uri and will 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. Accordingly, for the three and six months ended June 30, 2022 and the three months ended June 30, 2021, includes reductions to Adjusted EBITDA attributable to bill credit applications of $53 million, $66 million and $50 million, respectively. Also includes a reduction to Adjusted EBITDA related to a reduction in the allocation of ERCOT default uplift charges of $12 million and $56 million for the three and six months ended June 30, 2022, respectively, attributable to ERCOT receiving payments that reduced the market wide default balance.

~~Table of Contents~~

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 $ (168) $ (45) $ 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) 18 9 17 412
EBITDA before Adjustments 938 (1,480) (482) 13 (150) (35) (47) (1,243)
Unrealized net (gain) loss resulting from hedging transactions (500) 1,665 645 28 140 9 — 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 $ (16) $ (24) $ (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.~~

~~(c)~~Includes the application of future 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 are expected to be paid over several decades under current protocols.

Three Months Ended June 30, 2021
Retail Texas East West Sunset Asset
Closure Eliminations / Corporate and Other Vistra
Consolidated
Net income (loss) $ 1,810 $ (1,138) $ (100) $ (13) $ (246) $ (192) $ (86) $ 35
Income tax benefit — — — (115) (115)
Interest expense and related charges (a) 2 (4) 5 (5) — — 137 135
Depreciation and amortization (b) 54 179 193 10 26 4 18 484
EBITDA before Adjustments 1,866 (963) 98 (8) (220) (188) (46) 539
Unrealized net (gain) loss resulting from hedging transactions (1,318) 1,093 133 27 248 95 — 278
Generation plant retirement expenses — — — — (1) 15 1 15
Fresh start/purchase accounting impacts 2 (1) (73) — (4) (3) — (79)
Impacts of Tax Receivable Agreement — — — — — — 41 41
Non-cash compensation expenses — — — — — — 12 12
Transition and merger expenses 3 — — — — — (2) 1
Impairment of long-lived assets — — — — — 38 — 38
Winter Storm Uri impacts (c) (47) 12 — — — — — (35)
Other, net 4 3 2 2 2 — (12) 1
Adjusted EBITDA $ 510 $ 144 $ 160 $ 21 $ 25 $ (43) $ (6) $ 811

~~____________~~

~~(a)Includes $9 million of unrealized mark-to-market net losses on interest rate swaps.~~

~~(b)Includes nuclear fuel amortization of $20 million in Texas segment.~~

~~Table of Contents~~

~~(c)~~Includes the following of the Winter Storm Uri impacts, which we believe are not reflective of our operating performance: future bill credits related to Winter Storm Uri, partially offset by the allocation of additional ERCOT default uplift charges, which are expected to be paid over several decades under current protocols, and Winter Storm Uri related legal fees and other costs. The adjustment for future bill credits relates to large commercial and industrial customers that curtailed their usage during Winter Storm Uri and willUri. 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.

Table of Contents


		Six Months Ended June 30, 2022																	Three Months Ended March 31, 2023
		Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated			Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	Net income (loss)	$	3,326	$	(3,610)	$	(791)	$	(36)	$	(619)	$	(107)	$	196	$	(1,641)	Net income (loss)	$	(595)	$	584	$	745	$	52	$	424	$	(27)	$	(485)	$	698
Income tax benefit		—		—		—		—		—		—		(498)		(498)
Income tax expense																		Income tax expense	—		—		—		—		—		—		178		178
Interest expense and related charges (a)	Interest expense and related charges (a)	5		(11)		3		(1)		1		1		118		116		Interest expense and related charges (a)	7		(4)		—		(4)		1		1		206		207
Depreciation and amortization (b)	Depreciation and amortization (b)	72		309		358		31		37		23		34		864		Depreciation and amortization (b)	29		153		161		15		14		—		17		389
EBITDA before Adjustments	EBITDA before Adjustments	3,403		(3,312)		(430)		(6)		(581)		(83)		(150)		(1,159)		EBITDA before Adjustments	(559)		733		906		63		439		(26)		(84)		1,472
Unrealized net (gain) loss resulting from hedging transactions	Unrealized net (gain) loss resulting from hedging transactions	(2,805)		3,696		738		71		605		42		—		2,347		Unrealized net (gain) loss resulting from hedging transactions	559		(346)		(923)		(18)		(340)		(17)		—		(1,085)
Generation plant retirement expenses	Generation plant retirement expenses	—		—		—		—		5		1		—		6		Generation plant retirement expenses	—		—		—		—		—		—		1		1

Fresh start/purchase accounting impacts																		Fresh start/purchase accounting impacts	1		(1)		2		—		1		—		—		3
Impacts of Tax Receivable Agreement	Impacts of Tax Receivable Agreement	—		—		—		—		—		—		115		115		Impacts of Tax Receivable Agreement	—		—		—		—		—		—		65		65

Non-cash compensation expenses	Non-cash compensation expenses	—		—		—		—		—		—		34		34		Non-cash compensation expenses	—		—		—		—		—		—		22		22
Transition and merger expenses	Transition and merger expenses	9		—		1		—		—		—		10		20		Transition and merger expenses	(2)		—		—		—		1		—		2		1
Impairment of long-lived assets																		Impairment of long-lived assets	—		—		—		—		49		—		—		49

Winter Storm Uri impacts (c)		(64)		(52)		—		—		—		—		—		(116)
PJM capacity performance default impacts (c)																		PJM capacity performance default impacts (c)	—		—		14		—		6		—		—		20
Winter Storm Uri impacts (d)																		Winter Storm Uri impacts (d)	(34)		1		—		—		—		—		—		(33)
Other, net	Other, net	23		19		3		1		4		10		(29)		31		Other, net	6		(4)		2		1		8		2		(17)		(2)
Adjusted EBITDA	Adjusted EBITDA	$	566	$	351	$	312	$	66	$	33	$	(30)	$	(20)	$	1,278	Adjusted EBITDA	$	(29)	$	383	$	1	$	46	$	164	$	(41)	$	(11)	$	513

____________

(a)Includes ~~$171~~$41 million of unrealized mark-to-market net losses on interest rate swaps.

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

(c)Represents initial estimate of anticipated market participant defaults on PJM capacity performance penalties due to extreme magnitude of penalties associated with Winter Storm Elliott, which amounts are expected 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 $21 million), 2024 (approximately $9 million) and 2025 (approximately $25 million).

Table of Contents


	Three Months Ended March 31, 2022
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	$	2,428	$	(1,972)	$	(128)	$	(61)	$	(400)	$	(112)	$	(39)	$	(284)
Income tax benefit	—		—		—		—		—		—		(91)		(91)
Interest expense and related charges (a)	1		(5)		2		—		1		—		8		7
Depreciation and amortization (b)	36		145		179		42		16		17		17		452
EBITDA before Adjustments	2,465		(1,832)		53		(19)		(383)		(95)		(105)		84
Unrealized net (gain) loss resulting from hedging transactions	(2,306)		2,031		93		44		413		85		—		360
Generation plant retirement expenses	—		—		—		—		4		2		—		6

Impacts of Tax Receivable Agreement	—		—		—		—		—		—		81		81

Non-cash compensation expenses	—		—		—		—		—		—		17		17
Transition and merger expenses	6		—		1		—		—		—		10		17



Winter Storm Uri impacts (c)	(12)		(42)		—		—		—		—		—		(54)
Other, net	10		14		1		—		10		8		(13)		30
Adjusted EBITDA	$	163	$	171	$	148	$	25	$	44	$	—	$	(10)	$	541

____________

(a)Includes $126 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of ~~$40~~$22 million in Texas segment.

(c)~~Includes~~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 ~~are~~were expected to be paid over several decades under ~~current protocols. We estimate bill credit amounts to be applied in future periods are for~~protocols existing at the ~~remainder~~time of ~~2022 (approximately $82 million), 2023 (approximately $44 million), 2024 (approximately $39 million) and 2025 (approximately $1 million).~~the storm.

~~Table of Contents~~

Six Months Ended June 30, 2021
Retail Texas East West Sunset Asset
Closure Eliminations / Corporate and Other Vistra
Consolidated
Net income (loss) $ 1,898 $ (3,656) $ (99) $ (44) $ (241) $ (239) $ 377 $ (2,004)
Income tax benefit — — — — — — (600) (600)
Interest expense and related charges (a) 4 (7) 7 (8) — — 168 164
Depreciation and amortization (b) 107 323 389 15 51 8 34 927
EBITDA before Adjustments 2,009 (3,340) 297 (37) (190) (231) (21) (1,513)
Unrealized net (gain) loss resulting from hedging transactions (2,101) 1,615 153 80 315 120 — 182
Generation plant retirement expenses — — — — — 15 — 15
Fresh start/purchase accounting impacts 3 (2) (74) — (3) (3) — (79)
Impacts of Tax Receivable Agreement — — — — — — 4 4
Non-cash compensation expenses — — — — — — 29 29
Transition and merger expenses 3 — — — — (15) (1) (13)
Impairment of long-lived assets — — — — — 38 — 38
Winter Storm Uri impacts (c) 384 514 — — 1 — 1 900
Other, net 12 5 4 2 4 — (20) 7
Adjusted EBITDA $ 310 $ (1,208) $ 380 $ 45 $ 127 $ (76) $ (8) $ (430)

~~____________~~

~~(a)Includes $79 million of unrealized mark-to-market net gains on interest rate swaps.~~

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

~~(c)~~Includes the following of the Winter Storm Uri impacts, which we believe are not reflective of our operating performance: the allocation of ERCOT default uplift charges which are expected to be paid over several decades under current protocols, accrual of Koch earn-out amounts that we paid in the second quarter of 2022, future bill credits related to Winter Storm Uri and Winter Storm Uri related legal fees and other costs. The adjustment for future bill credits relates to large commercial and industrial customers that curtailed their usage during Winter Storm Uri and will 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.

6358

Table of Contents

Retail Segment — Three ~~and Six~~ Months Ended ~~June 30, 2022~~March 31, 2023 Compared to Three ~~and Six~~ Months Ended ~~June 30, 2021~~March 31, 2022


		Three Months Ended June 30,						Favorable (Unfavorable) Change			Six Months Ended June 30,							Favorable (Unfavorable) Change					Three Months Ended March 31,					Favorable (Unfavorable) Change
		2022			2021					2022				2021								2023		2022
Operating revenues:	Operating revenues:																				Operating revenues:
Revenues in ERCOT	Revenues in ERCOT	$	1,913		$	1,434		$	479		$	3,465			$	2,604		$	861	Revenues in ERCOT					$	1,723		$	1,551		$	172
Revenues in Northeast/Midwest	Revenues in Northeast/Midwest	547			504			43			1,190				1,091			99		Revenues in Northeast/Midwest					487			643			(156)
Amortization expense	Amortization expense	(1)			(2)			1			(1)				(3)			2		Amortization expense					(1)			—			(1)
Unrealized net losses on hedging activities (a)		(667)			(17)			(650)			(1,037)				(23)			(1,014)
Unrealized net gains (losses) on hedging activities (a)																				Unrealized net gains (losses) on hedging activities (a)					141			(369)			510
Total operating revenues	Total operating revenues	1,792			1,919			(127)			3,617				3,669			(52)		Total operating revenues					2,350			1,825			525
Fuel, purchased power costs and delivery fees:	Fuel, purchased power costs and delivery fees:																			Fuel, purchased power costs and delivery fees:
Purchases from affiliates	Purchases from affiliates	(1,183)			(726)			(457)			(2,453)				(2,177)			(276)		Purchases from affiliates					(1,465)			(1,271)			(194)
Unrealized net gains on hedging activities with affiliates (b)		1,166			1,336			(170)			3,838				2,126			1,712
Unrealized net gains (losses) on hedging activities with affiliates (b)																				Unrealized net gains (losses) on hedging activities with affiliates (b)					(680)			2,673			(3,353)
Unrealized net gains (losses) on hedging activities	Unrealized net gains (losses) on hedging activities	1			—			1			4				(3)			7		Unrealized net gains (losses) on hedging activities					(19)			2			(21)
Delivery fees	Delivery fees	(563)			(436)			(127)			(1,074)				(877)			(197)		Delivery fees					(497)			(511)			14
Other costs ~~(c)~~	Other costs ~~(c)~~	(37)			(24)			(13)			(67)				(319)			252		Other costs ~~(c)~~					(29)			(29)			—
Total fuel, purchased power costs and delivery fees	Total fuel, purchased power costs and delivery fees	(616)			150			(766)			248				(1,250)			1,498		Total fuel, purchased power costs and delivery fees					(2,690)			864			(3,554)

Net income		$	898		$	1,810		$	(912)		$	3,326			$	1,898		$	1,428
Net income (loss)																				Net income (loss)					$	(595)		$	2,428		$	(3,023)

Adjusted EBITDA	Adjusted EBITDA	$	403		$	510		$	(107)		$	566			$	310		$	256	Adjusted EBITDA					$	(29)		$	163		$	(192)

Retail sales volumes (GWh):	Retail sales volumes (GWh):																			Retail sales volumes (GWh):
Retail electricity sales volumes:	Retail electricity sales volumes:																			Retail electricity sales volumes:
Sales volumes in ERCOT	Sales volumes in ERCOT	16,823			13,636			3,187			31,036				26,483			4,553		Sales volumes in ERCOT					14,982			14,213			769
Sales volumes in Northeast/Midwest	Sales volumes in Northeast/Midwest	8,326			8,474			(148)			17,432				17,524			(92)		Sales volumes in Northeast/Midwest					5,830			9,106			(3,276)
Total retail electricity sales volumes	Total retail electricity sales volumes	25,149			22,110			3,039			48,468				44,007			4,461		Total retail electricity sales volumes					20,812			23,319			(2,507)
Weather (North Texas average) - percent of normal (d):
Cooling degree days		139.8		%	80.6		%				136.2		%		79.3		%
Weather (North Texas average) - percent of normal (c):																				Weather (North Texas average) - percent of normal (c):

Heating degree days	Heating degree days	27.7		%	127.1		%				111.2		%		117.1		%			Heating degree days					82.8		%	118.1		%

____________

(a)~~For both~~Includes pre-tax unrealized net gains of $153 million for the three ~~and six~~ months ended ~~June 30, 2022, Retail segment includes unrealized net losses of $414 million~~March 31, 2023 recognized due to the second quarter of 2022 discontinuance of NPNS accounting on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract ~~term as we opportunistically monetized certain positions.~~term.

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

(c)~~For~~Reflects cooling degree or heating degree days for the ~~six months ended June 30, 2021, includes $162 million of future bill credits to large commercial and industrial customers.~~

~~(d)~~region based on Weather data is obtained from Weatherbank, Inc. For the three and six months ended June 30, 2022, normal is defined as the average over the 10-year period from June 2012 to June 2021. For the three and six months ended June 30, 2021, normal is defined as the average over the 10-year period from June 2011 to June 2020.Services International (WSI) data.

The following table presents changes in net income (loss) and Adjusted EBITDA for the three months ended March 31, 2023 compared to the three months ended March 31, 2022.


	Three Months Ended March 31, 2023 Compared to 2022
Lower margins driven by seasonality of power costs	$	(116)
Winter Storm Uri impact, including bill credits	(21)
Lower margins due to mild weather in 2023	(43)
Other primarily driven by higher bad debt expense due to higher revenues in ERCOT	(12)
Change in Adjusted EBITDA	$	(192)
Unfavorable impact of unrealized net losses on hedging activities	(2,865)
Bill credits and other costs related to Winter Storm Uri	22
Decrease in depreciation and amortization expenses	7
Change in other expenses	5
Change in Net income	$	(3,023)

Table of Contents

~~The following table presents changes in net income and Adjusted EBITDA for the three and six months ended June 30, 2022 compared to the three and six months ended June 30, 2021.~~

Three Months Ended June 30, 2022
Compared to 2021 Six Months Ended
June 30, 2022
Compared to 2021
Winter Storm Uri, including bill credits $ (16) $ 498
Higher/(lower) seasonal commodity costs 3 (111)
Lower margins reflecting self-help gains in 2021 partially offset by favorable weather in 2022 (65) (89)
Other driven by higher bad debt expense and revenue-based taxes due to higher revenues in 2022 (29) (42)
Change in Adjusted EBITDA $ (107) $ 256
Favorable/(unfavorable) impact of unrealized net gains on hedging activities (818) 704
Future bill credits and other costs related to Winter Storm Uri 5 448
Decrease in depreciation and amortization expenses 18 35
Change in transition and merger and other expenses (10) (15)
Change in net income $ (912) $ 1,428

~~Table of Contents~~

Generation — Three Months Ended ~~June 30, 2022~~March 31, 2023 Compared to Three Months Ended ~~June 30, 2021~~March 31, 2022


		Three Months Ended June 30,																									Three Months Ended March 31,
		Texas						East						West						Sunset							Texas						East						West						Sunset
		2022			2021			2022			2021			2022			2021			2022			2021				2023			2022			2023			2022			2023			2022			2023			2022
Operating revenues:	Operating revenues:																									Operating revenues:
Electricity sales	Electricity sales	$	369		$	340		$	573		$	241		$	111		$	82		$	59		$	140		Electricity sales	$	86		$	234		$	388		$	644		$	213		$	116		$	241		$	129
Capacity revenue from ISO/RTO	Capacity revenue from ISO/RTO	—			—			(4)			2			—			—			25			32			Capacity revenue from ISO/RTO	—			—			8			(6)			—			—			19			33
Sales to affiliates	Sales to affiliates	660			308			397			337			1			—			125			82			Sales to affiliates	897			644			471			516			6			2			92			108
Rolloff of unrealized net gains (losses) representing positions settled in the current period	Rolloff of unrealized net gains (losses) representing positions settled in the current period	(63)			(129)			(105)			(23)			2			(6)			37			3			Rolloff of unrealized net gains (losses) representing positions settled in the current period	175			251			357			37			50			(4)			(14)			43
Unrealized net losses on hedging activities		(671)			(35)			(393)			138			(37)			(29)			(228)			(141)
Unrealized net gains (losses) on hedging activities																										Unrealized net gains (losses) on hedging activities	8			(213)			192			272			(36)			(43)			388			(293)
Unrealized net gains (losses) on hedging activities with affiliates	Unrealized net gains (losses) on hedging activities with affiliates	(918)			(952)			(151)			(263)			2			—			(99)			(121)			Unrealized net gains (losses) on hedging activities with affiliates	185			(2,011)			394			(509)			(2)			1			103			(136)
Other revenues	Other revenues	—			—			2			73			—			1			(2)			(2)			Other revenues	2			—			(1)			1			—			—			(1)			(2)
Operating revenues	Operating revenues	(623)			(468)			319			505			79			48			(83)			(7)			Operating revenues	1,353			(1,095)			1,809			955			231			72			828			(118)
Fuel, purchased power costs and delivery fees:	Fuel, purchased power costs and delivery fees:																									Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs	Fuel for generation facilities and purchased power costs	(582)			(310)			(709)			(326)			(55)			(44)			(132)			(148)			Fuel for generation facilities and purchased power costs	(322)			(410)			(786)			(929)			(153)			(74)			(123)			(166)
Fuel for generation facilities and purchased power costs from affiliates	Fuel for generation facilities and purchased power costs from affiliates	(3)			(1)			1			—			—			—			2			—			Fuel for generation facilities and purchased power costs from affiliates	—			—			—			—			—			—			—			(1)
Unrealized gains (losses) from hedging activities	Unrealized gains (losses) from hedging activities	(11)			23			4			15			5			8			148			11			Unrealized gains (losses) from hedging activities	(22)			(55)			(20)			106			6			3			(137)			(29)
Unrealized net gains (losses) on hedging activities with affiliates		(2)			—			—			—			—			—			2			—
Unrealized gains (losses) from hedging activities with affiliates																										Unrealized gains (losses) from hedging activities with affiliates	—			(3)			—			1			—			—			—			2
Ancillary and other costs	Ancillary and other costs	(99)			(45)			(9)			(8)			(1)			(2)			(3)			(2)			Ancillary and other costs	(51)			(58)			(14)			(6)			(1)			(2)			(2)			(1)
Fuel, purchased power costs and delivery fees	Fuel, purchased power costs and delivery fees	(697)			(333)			(713)			(319)			(51)			(38)			17			(139)			Fuel, purchased power costs and delivery fees	(395)			(526)			(820)			(828)			(148)			(73)			(262)			(195)

Net loss		$	(1,638)		$	(1,138)		$	(662)		$	(100)		$	25		$	(13)		$	(168)		$	(246)
Net income (loss)																										Net income (loss)	$	584		$	(1,972)		$	745		$	(128)		$	52		$	(61)		$	424		$	(400)

Adjusted EBITDA	Adjusted EBITDA	$	181		$	144		$	164		$	160		$	40		$	21		$	(16)		$	25		Adjusted EBITDA	$	383		$	171		$	1		$	148		$	46		$	25		$	164		$	44
Production volumes (GWh):	Production volumes (GWh):																									Production volumes (GWh):
Natural gas facilities	Natural gas facilities	7,749			6,698			11,418			12,143			869			1,101									Natural gas facilities	6,225			5,901			14,585			14,336			1,543			1,196
Lignite and coal facilities	Lignite and coal facilities	5,363			5,580															5,219			6,540			Lignite and coal facilities	4,971			6,370															3,516			5,952
Nuclear facilities	Nuclear facilities	4,137			4,879																					Nuclear facilities	5,227			5,223
Solar facilities	Solar facilities	263			126																					Solar facilities	154			166
Capacity factors:	Capacity factors:																									Capacity factors:
CCGT facilities	CCGT facilities	43.7		%	37.9		%	48.0		%	49.9		%	37.7		%	49.4		%							CCGT facilities	35.0		%	34.1		%	62.2		%	61.5		%	70.1		%	53.9		%
Lignite and coal facilities	Lignite and coal facilities	63.8		%	66.4		%													46.3		%	58.0		%	Lignite and coal facilities	59.8		%	76.6		%													35.6		%	60.2		%
Nuclear facilities	Nuclear facilities	82.3		%	97.1		%																			Nuclear facilities	100.9		%	100.8		%
Weather - percent of normal (a):	Weather - percent of normal (a):																									Weather - percent of normal (a):
Cooling degree days		129.6		%	88.5		%	96.2		%	126.5		%	101.7		%	101.7		%	126.0		%	119.0		%

Heating degree days	Heating degree days	17.6		%	148.6		%	95.0		%	94.1		%	127.5		%	96.9		%	96.9		%	95.4		%	Heating degree days	81.1		%	133.5		%	84.4		%	100.4		%	148.7		%	93.1		%	86.9		%	104.9		%

____________

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

6660

Table of Contents


		Three Months Ended June 30,								Three Months Ended June 30,								Three Months Ended March 31,									Three Months Ended March 31,
		2022		2021						2022				2021				2023				2022					2023				2022
Market pricing	Market pricing							Average Market On-Peak Power Prices ($MWh) (b):								Market pricing										Average Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)	Average ERCOT North power price ($/MWh)	$	63.08	$	35.91			PJM West Hub		$	93.27			$	33.71	Average ERCOT North power price ($/MWh)		$	21.98			$	36.91			PJM West Hub	$	36.35			$	58.10
								AEP Dayton Hub		$	94.06			$	35.35											AEP Dayton Hub	$	33.65			$	50.83
Average NYMEX Henry Hub natural gas price ($/MMBtu)	Average NYMEX Henry Hub natural gas price ($/MMBtu)	$	7.40	$	2.88			NYISO Zone C		$	50.24			$	22.43	Average NYMEX Henry Hub natural gas price ($/MMBtu)		$	2.68			$	4.60			NYISO Zone C	$	30.96			$	72.41
						Massachusetts Hub		$	73.29			$	33.85							Massachusetts Hub				$	51.98		$	114.92
Average natural gas price (a):	Average natural gas price (a):							Indiana Hub		$	95.15			$	35.32				Average natural gas price (a):								Indiana Hub		$	35.52			$	55.92
TetcoM3 ($/MMBtu)	TetcoM3 ($/MMBtu)	$	6.78			$	2.32			Northern Illinois Hub		$	84.99			$	32.07		TetcoM3 ($/MMBtu)	$	2.93			$	6.73		Northern Illinois Hub		$	29.58			$	44.45
Algonquin Citygates ($/MMBtu)	Algonquin Citygates ($/MMBtu)	$	7.19	$	2.49			CAISO NP15		$	69.55			$	42.76	Algonquin Citygates ($/MMBtu)		$	5.13			$	13.67			CAISO NP15	$	100.31			$	50.43

___________

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

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

The following table presents changes in net income (loss) and Adjusted EBITDA for the three months ended ~~June 30, 2022~~March 31, 2023 compared to the three months ended ~~June 30, 2021.~~March 31, 2022.


		Three Months Ended June 30, 2022 Compared to 2021									Three Months Ended March 31, 2023 Compared to 2022
		Texas		East		West		Sunset			Texas		East		West		Sunset

Favorable/(unfavorable) change in revenue net of fuel	Favorable/(unfavorable) change in revenue net of fuel	$	(13)	$	4	$	19	$	(30)	Favorable/(unfavorable) change in revenue net of fuel	$	238	$	(137)	$	22	$	131
Winter Storm Uri impact		47		—		—		—

Unfavorable change in other operating costs	Unfavorable change in other operating costs	(25)		(4)		(1)		(18)		Unfavorable change in other operating costs	(28)		(8)		(3)		(7)
Favorable/(unfavorable) change in selling, general and administrative expenses	Favorable/(unfavorable) change in selling, general and administrative expenses	(4)		4		1		—		Favorable/(unfavorable) change in selling, general and administrative expenses	2		(2)		2		(5)
Other	Other	32		—		—		7		Other	—		—		—		1
Change in Adjusted EBITDA	Change in Adjusted EBITDA	$	37	$	4	$	19	$	(41)	Change in Adjusted EBITDA	$	212	$	(147)	$	21	$	120
Favorable change in depreciation and amortization		15		14		21		8
Change in unrealized net losses on hedging activities		(572)		(512)		(1)		108

Generation plant retirement, transition and merger expenses		—		—		—		(2)
Favorable/(unfavorable) change in depreciation and amortization										Favorable/(unfavorable) change in depreciation and amortization	(8)		18		27		2
Change in unrealized net gains on hedging activities										Change in unrealized net gains on hedging activities	2,377		1,016		62		753
Impairment of long-lived assets										Impairment of long-lived assets	—		—		—		(49)
Generation plant retirement expenses										Generation plant retirement expenses	—		—		—		4
Fresh start/purchase accounting impacts	Fresh start/purchase accounting impacts	(1)		(73)		—		(4)		Fresh start/purchase accounting impacts	1		(2)		—		(1)

Winter Storm Uri impact (ERCOT default uplift and Koch earn-out)		22		—		—		—
Other (including interest and COVID-19 related expenses)		(1)		5		(1)		9

PJM capacity performance default impacts										PJM capacity performance default impacts	—		(14)		—		(6)
Winter Storm Uri impact (ERCOT default uplift)										Winter Storm Uri impact (ERCOT default uplift)	(43)		—		—		—
Other (including interest expenses)										Other (including interest expenses)	17		2		3		1
Change in Net income (loss)	Change in Net income (loss)	$	(500)	$	(562)	$	38	$	78	Change in Net income (loss)	$	2,556	$	873	$	113	$	824

The favorable changes in Texas, 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 March 31, 2023 compared to unrealized hedging losses due to increases in power prices in the three months ended March 31, 2022.

The change in Texas ~~and East~~ segment results was ~~primarily~~also driven by higher ~~unrealized hedging losses~~revenue net of fuel in the three months ended ~~June 30, 2022 versus~~March 31, 2023 compared to the three months ended ~~June 30, 2021~~March 31, 2022 due to ~~material increases~~strong generation performance during periods of higher pricing and the effectiveness of our comprehensive hedging strategy.

The change in ~~forward power prices in 2022. The increase in operating costs are due to summer readiness expenses and inflationary pressures~~East segment results was also driven by lower revenue net of fuel in the three months ended ~~June 30, 2022.~~March 31, 2023 compared to the three months ended March 31, 2022 due primarily to higher-than-expected migration of customers to default service providers at rates below prevailing wholesale market prices and lower capacity revenues.

The change in West segment results was driven by higher ~~realized energy margins in CAISO~~revenue net of fuel in the three months ended ~~June 30, 2022 versus~~March 31, 2023 compared to the three months ended ~~June 30, 2021.~~

~~The change in Sunset segment results was driven by lower unrealized hedging losses in the three months ended June 30,~~March 31, 2022 ~~versus the three months ended June 30, 2021~~ due to ~~unrealized gains on forward lignite~~higher generation volumes and ~~coal purchases as forward prices increased in the three months ended June 30, 2022, partially offset by a favorable change in revenue net of fuel.~~

~~Table of Contents~~

~~Generation~~ — ~~Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021~~

Six Months Ended June 30,
Texas East West Sunset
2022 2021 2022 2021 2022 2021 2022 2021
Operating revenues:
Electricity sales $ 603 $ 1,040 $ 1,218 $ 575 $ 227 $ 167 $ 211 $ 345
Capacity revenue from ISO/RTO — — (10) (2) — — 63 61
Sales to affiliates 1,304 1,232 914 765 3 2 232 181
Rolloff of unrealized net gains (losses) representing positions settled in the current period 188 (154) (69) 32 (2) (11) 86 (25)
Unrealized net gains (losses) on hedging activities (885) 122 (120) 132 (80) (77) (558) (151)
Unrealized net gains (losses) on hedging activities with affiliates (2,928) (1,625) (660) (347) 3 — (253) (154)
Other revenues — — 1 75 — — (4) (8)
Operating revenues (1,718) 615 1,274 1,230 151 81 (223) 249
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs (993) (1,982) (1,638) (785) (129) (92) (311) (310)
Fuel for generation facilities and purchased power costs from affiliates (3) (1) 1 — — — 1 (1)
Unrealized (gains) losses from hedging activities (66) 42 110 30 8 8 116 16
Unrealized (gains) losses from hedging activities with affiliates (5) — 1 — — — 4 —
Ancillary and other costs (156) (1,710) (15) (18) (3) (2) (6) (4)
Fuel, purchased power costs and delivery fees (1,223) (3,651) (1,541) (773) (124) (86) (196) (299)
Net loss $ (3,610) $ (3,656) $ (791) $ (99) $ (36) $ (44) $ (619) $ (241)
Adjusted EBITDA $ 351 $ (1,208) $ 312 $ 380 $ 66 $ 45 $ 33 $ 127
Production volumes (GWh):
Natural gas facilities 13,650 13,545 25,754 26,021 2,065 2,363
Lignite and coal facilities 11,733 11,472 11,868 13,576
Nuclear facilities 9,360 10,089
Solar facilities 429 222
Capacity factors:
CCGT facilities 38.9 % 38.2 % 54.7 % 54.7 % 45.8 % 53.3 %
Lignite and coal facilities 70.2 % 68.6 % 52.9 % 60.5 %
Nuclear facilities 93.7 % 101.0 %
Weather - percent of normal (a):
Cooling degree days 122.9 % 85.8 % 96.0 % 126.3 % 100.9 % 99.0 % 126.0 % 119.0 %
Heating degree days 128.1 % 122.9 % 99.4 % 96.0 % 98.1 % 108.2 % 103.7 % 94.8 %

~~____________~~

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

~~Table of Contents~~

Six Months Ended
June 30, Six Months Ended
June 30,
2022 2021 2022 2021
Market pricing Average Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price
($/MWh) $ 50.07 $ 262.05 PJM West Hub $ 75.68 $ 34.20
AEP Dayton Hub $ 72.45 $ 35.04
Average NYMEX Henry Hub natural gas price ($/MMBtu) $ 6.01 $ 3.13 NYISO Zone C $ 61.32 $ 25.88
Massachusetts Hub $ 94.11 $ 44.07
Average natural gas price (a): Indiana Hub $ 75.53 $ 40.16
TetcoM3 ($/MMBtu) $ 6.75 $ 2.79 Northern Illinois Hub $ 64.72 $ 32.52
Algonquin Citygates ($/MMBtu) $ 10.41 $ 3.97 CAISO NP15 $ 60.06 $ 43.76

~~___________~~

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

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

~~The following table presents changes in net income (loss) and Adjusted EBITDA for the six months ended June 30, 2022 compared to the six months ended June 30, 2021.~~

Six Months Ended June 30, 2022 Compared to 2021
Texas East West Sunset
Favorable/(unfavorable) change in revenue net of fuel $ 79 $ (17) $ 24 $ (57)
Winter Storm Uri impact 1,548 (50) — (17)
Unfavorable change in other operating costs (52) (8) (6) (25)
Favorable/(unfavorable) change in selling, general and administrative expenses (14) 5 3 (4)
Other (2) 2 — 9
Change in Adjusted EBITDA $ 1,559 $ (68) $ 21 $ (94)
Favorable/(unfavorable) change in depreciation and amortization 14 31 (16) 14
Change in unrealized net losses on hedging activities (2,081) (585) 9 (290)
Generation plant retirement expenses — — — (5)
Fresh start/purchase accounting impacts (2) (74) — (3)
Winter Storm Uri impact (ERCOT default uplift and Koch earn-out) 566 — — 1
Other (including interest and COVID-19 related expenses) (10) 4 (6) (1)
Change in Net income (loss) $ 46 $ (692) $ 8 $ (378)

The change in Texas segment results was primarily driven by the Winter Storm Uri impacts in 2021, partially offset by higher unrealized hedging losses in the six months ended June 30, 2022 versus the six months ended June 30, 2021 due to increases in forward power prices. The increase in operating costs are due to summer readiness expenses and inflationary pressures in the six months ended June 30, 2022.

The change in East segment results was driven by higher unrealized hedging losses in the six months ended June 30, 2022 versus the six months ended June 30, 2021 due to increases in forward power prices, partially offset by favorable Winter Storm Uri impacts recognized in the six months ended June 30, 2021.

The change in West segment results was driven by higher depreciation and amortization in the six months ended June 30, 2022 versus the six months ended June 30, 2021 reflecting battery ESS projects placed in service during summer 2021 (see Note 2 to the Financial Statements), partially offset by a favorable change in revenue net of fuel driven by higher realized energy margins.

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The change in Sunset segment results was also driven by higher ~~unrealized hedging losses in the six months ended June 30, 2022 versus the six months ended June 30, 2021 due to increases in forward power prices and an unfavorable change in~~ revenue net of ~~fuel.~~fuel in the three months ended March 31, 2023 compared to the three months ended March 31, 2022 due to the effectiveness of our comprehensive hedging strategy. A $49 million impairment of assets related to our Kincaid generation facility was recognized in the three months ended March 31, 2023. See Note 18 to the Financial Statements for more information concerning the impairment.

Asset Closure Segment — Three ~~and Six~~ Months Ended ~~June 30, 2022~~March 31, 2023 Compared to Three ~~and Six~~ Months Ended ~~June 30, 2021~~March 31, 2022


		Three Months Ended June 30,				Favorable (Unfavorable) Change				Six Months Ended June 30,								Favorable (Unfavorable) Change							Three Months Ended March 31,				Favorable (Unfavorable) Change
		2022		2021				2022				2021												2023		2022
Operating revenues	Operating revenues	$	121	$	(41)			$	162			$	228			$	(19)				$	247	Operating revenues						$	—	$	85	$	(85)
Fuel, purchased power costs and delivery fees	Fuel, purchased power costs and delivery fees	(119)		(32)		(87)				(221)				(59)				(162)		Fuel, purchased power costs and delivery fees							(1)		(120)		119
Operating costs	Operating costs	$	(34)	$	(68)	$	34			$	(78)			$	(108)			$	30	Operating costs							$	(20)	$	(50)	$	30
Depreciation and amortization	Depreciation and amortization	(9)		(4)		(5)				(23)				(8)				(15)		Depreciation and amortization							—		(17)		17
Selling, general and administrative expenses	Selling, general and administrative expenses	(9)		(11)		2				(19)				(26)				7		Selling, general and administrative expenses							(8)		(11)		3

Impairment of long-lived assets		—		(38)		38				—				(38)				38

Operating loss	Operating loss	(50)		(194)		144				(113)				(258)				145		Operating loss							(29)		(113)		84
Other income	Other income	6		2		4				8				19				(11)		Other income							3		2		1
Other deductions		—		—		—				(1)				—				(1)

Interest expense and related charges	Interest expense and related charges	(1)		—		(1)				(1)				—				(1)		Interest expense and related charges							(1)		(1)		—

Loss before income taxes		(45)		(192)		147				(107)				(239)				132
Income (loss) before income taxes																				Income (loss) before income taxes							(27)		(112)		85

Net loss	Net loss	$	(45)	$	(192)	$	147			$	(107)			$	(239)			$	132	Net loss							$	(27)	$	(112)	$	85

Adjusted EBITDA	Adjusted EBITDA	$	(24)	$	(43)	$	19			$	(30)			$	(76)			$	46	Adjusted EBITDA							$	(41)	$	—	$	(41)
Production volumes (GWh)	Production volumes (GWh)	2,660		2,055		605				5,859				3,552				2,307		Production volumes (GWh)							—		3,896		(3,896)

~~Results~~For the three months ended March 31, 2022, results and volumes for the Asset Closure segment include those from ~~the Zimmer and Joppa~~Edwards generation ~~plants~~plant that we retired ~~in May 2022~~on January 1, 2023, and ~~plan~~include unrealized hedging losses of $33 million related to ~~retire in September 2022, respectively.~~coal and power derivatives. Operating costs for the three ~~and six~~ months ended ~~June 30,~~March 31, 2023 and 2022 ~~and 2021~~ also include ongoing costs associated with the decommissioning and reclamation of retired plants and mines. The ~~change~~decrease in ~~Asset Closure segment results for both the three and six months ended June 30, 2022 is primarily due to severance and impairment expense recorded~~net losses in the three months ended ~~June 30, 2021, in connection with plant closure announcements (see Note 3~~March 31, 2023 compared to the ~~Financial Statements).~~three months ended March 31, 2022 is driven 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~~three months ended ~~June 30, 2022~~March 31, 2023 and ~~2021.~~2022. The net change in these assets and liabilities, excluding "other activity" as described below, reflects ~~$2.347~~$1.085 billion in unrealized net gains and ~~$182~~$360 million in unrealized net losses ~~respectively,~~ for the ~~six~~three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021,~~ respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.


		Six Months Ended June 30,					Three Months Ended March 31,
		2022		2021			2023		2022
Commodity contract net liability at beginning of period	Commodity contract net liability at beginning of period	$	(866)	$	(75)	Commodity contract net liability at beginning of period	$	(3,148)	$	(866)
Settlements/termination of positions (a)	Settlements/termination of positions (a)	319		(199)		Settlements/termination of positions (a)	711		375
Changes in fair value of positions in the portfolio (b)	Changes in fair value of positions in the portfolio (b)	(2,666)		17		Changes in fair value of positions in the portfolio (b)	374		(735)

Other activity (c)	Other activity (c)	37		(52)		Other activity (c)	(36)		(96)
Commodity contract net liability at end of period	Commodity contract net liability at end of period	$	(3,176)	$	(309)	Commodity contract net liability at end of period	$	(2,099)	$	(1,322)

____________

(a)Represents reversals of previously recognized unrealized ~~gains and losses~~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~~ 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.

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Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair values at ~~June 30, 2022,~~March 31, 2023, scheduled by the source of fair value and contractual settlement dates of the underlying positions.


		Maturity dates of unrealized commodity contract net liability at June 30, 2022											Maturity dates of unrealized commodity contract net liability at March 31, 2023
Source of fair value	Source of fair value	Less than 1 year		1-3 years		4-5 years		Excess of 5 years		Total		Source of fair value	Less than 1 year		1-3 years		4-5 years		Excess of 5 years		Total
Prices actively quoted	Prices actively quoted	$	(1,205)	$	(469)	$	(28)	$	—	$	(1,702)	Prices actively quoted	$	(862)	$	(305)	$	2	$	—	$	(1,165)
Prices provided by other external sources	Prices provided by other external sources	(357)		(103)		1		—		(459)		Prices provided by other external sources	233		58		—		—		291
Prices based on models	Prices based on models	(434)		(365)		(141)		(75)		(1,015)		Prices based on models	(162)		(650)		(232)		(181)		(1,225)
Total	Total	$	(1,996)	$	(937)	$	(168)	$	(75)	$	(3,176)	Total	$	(791)	$	(897)	$	(230)	$	(181)	$	(2,099)

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FINANCIAL CONDITION

Operating Cash Flows

Cash ~~used in~~provided by operating activities totaled ~~$723~~$1.435 billion and $591 million for the ~~six~~three months ended ~~June 30,~~March 31, 2023 and 2022, ~~compared to cash used in operating activities of $1.057 billion for the six months ended June 30, 2021.~~respectively. The favorable change of ~~$334~~$844 million was primarily driven by ~~lower cash from operations~~a decrease in ~~2021 due to Winter Storm Uri impacts and $544 million~~net margin deposits of ~~securitization proceeds from ERCOT in 2022 (see Note 1 to the Financial Statements), partially offset by $1.653~~$1.227 billion in ~~higher margin deposits~~the first quarter of 2023 as compared to $210 million in the first quarter of 2022 related to commodity contracts which support our comprehensive hedging strategy.

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 ~~$230~~$111 million and ~~$82~~$112 million for the ~~six~~three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021,~~ 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 ~~$609~~$513 million and ~~$575~~$480 million for the ~~six~~three months ended ~~June 30,~~March 31, 2023 and 2022, respectively. The increase of $33 million was driven by a $111 million increase in capital expenditures due primarily to continued development of our solar and ~~2021, respectively. Capital expenditures totaled $613~~energy storage generation facilities (see Note 3 to the Financial Statements), partially offset by $83 million ~~and $546 million for the six months ended June 30, 2022 and 2021, respectively, and consisted of the following:~~

Six Months Ended June 30,
2022 2021
Capital expenditures, including LTSA prepayments $ 293 $ 273
Nuclear fuel purchases $ 117 $ 15
Growth and development expenditures $ 203 $ 258
Capital expenditures $ 613 $ 546

~~Cash used~~ in ~~investing activities for the six months ended June 30, 2022 and 2021 also reflected net sales of environmental allowances of $8 million and~~lower net purchases of environmental allowances of $109 million, respectively. In the six months ended June 30, 2022 and 2021, we received insurance proceeds for reimbursement of capital expenditures of $1 million and $63 million, respectively.allowances.


	Three Months Ended March 31,				Increase (Decrease)
	2023		2022
Capital expenditures, including LTSA prepayments	$	(202)	$	(153)	$	(49)
Nuclear fuel purchases	(64)		(103)		39
Growth and development expenditures	(218)		(117)		(101)
Total capital expenditures	(484)		(373)		(111)
Net sales (purchases) of environmental allowances	(26)		(109)		83
Net sales of (investments in) nuclear decommissioning trust fund securities	(6)		(5)		(1)
Insurance proceeds related to capital activity	3		1		2
Proceeds from sales of assets	2		3		(1)
Other investing activity	(2)		3		(5)
Cash used in investing activities	$	(513)	$	(480)	$	(33)

Financing Cash Flows

Cash ~~provided by~~used in financing activities totaled ~~$1.880 billion~~$874 million and ~~$1.671 billion~~$413 million for the ~~six~~three months ended ~~June 30,~~March 31, 2023 and 2022, ~~and 2021,~~ respectively. The ~~change~~$461 million increase in cash used was primarily driven ~~by:~~

•by $650 million of short-term debt repayments in the ~~issuance of $1.498 billion principal amount of Vistra Operations senior secured notes in May 2022;~~

•~~net borrowings of $1.050 billion under the Commodity-Linked Facility in 2022; and~~

•~~net borrowings of $725 million under the accounts receivable financing facilities in 2022 compared to net borrowings of $361 million in 2021.~~

~~These increases in cash provided by financing activities are~~three months ended March 31, 2023, partially offset ~~by:~~by lower share repurchases.

•~~the issuance of $1.250 billion principal amount of Vistra Operations senior unsecured notes in May 2021;~~

•$1.194 billion in cash paid for share repurchases in 2022, including $114 million of unsettled share repurchases accrued as of December 31, 2021 and excluding $7 million of unsettled share repurchases accrued as of June 30, 2022, compared to $175 million in cash paid in 2021;

•~~$500 million in cash received from the sale of a portion of the PJM capacity that cleared for Planning Years 2021-2022 in 2021; and~~

•~~dividends of $76 million paid to preferred stockholders in 2022.~~


	Three Months Ended March 31,				Increase (Decrease)
	2023		2022
Share repurchases	$	(301)	$	(710)	$	409

Net long-term borrowings (repayments), including the forward capacity agreements	(7)		(132)		125
Net short-term borrowings (repayments)	(650)		—		(650)
Net borrowings (repayments) under the accounts receivable financing facilities	175		500		(325)
Dividends paid to common stockholders	(77)		(77)		—

Other financing activity	(14)		6		(20)
Cash used in financing activities	$	(874)	$	(413)	$	(461)

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Debt Activity

The maturities of our long-term debt are relatively modest until 2024. See Note 910 to the Financial Statements for details of the Receivables Facility and Repurchase Facility and Note 1011 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~~three months ended ~~June 30, 2022:~~March 31, 2023:


		June 30, 2022		December 31, 2021		Change			March 31, 2023		December 31, 2022		Change
Cash and cash equivalents	Cash and cash equivalents	$	1,871	$	1,325	$	546	Cash and cash equivalents	$	518	$	455	$	63
Vistra Operations Credit Facilities — Revolving Credit Facility	Vistra Operations Credit Facilities — Revolving Credit Facility	368		1,254		(886)		Vistra Operations Credit Facilities — Revolving Credit Facility	1,992		1,236		756
Vistra Operations — Commodity-Linked Facility (a)	Vistra Operations — Commodity-Linked Facility (a)	1,200		—		1,200		Vistra Operations — Commodity-Linked Facility (a)	169		808		(639)
Total available liquidity ~~(b)~~(c)	Total available liquidity ~~(b)~~(c)	$	3,439	$	2,579	$	860	Total available liquidity ~~(b)~~(c)	$	2,679	$	2,499	$	180

____________

(a)~~Assumes~~As of both March 31, 2023 and December 31, 2022, the borrowing bases are less than the facility limit of $1.35 billion. As of March 31, 2023, available capacity reflects the borrowing base ~~equals~~of $169 million and no cash borrowings. As of December 31, 2022, available capacity reflects the ~~aggregate commitments~~borrowing base of ~~$2.25 billion.~~$1.208 billion less $400 million in cash borrowings. The reduction in the borrowing base is due to a decrease in commodity prices 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 910 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 11 to the Financial Statements for detail on our Secured LOC Facilities.

The ~~$860~~$180 million increase in available liquidity for the ~~six~~three months ended ~~June 30, 2022~~March 31, 2023 was primarily driven by ~~$1.498 billion principal amount~~cash provided by operations, a $506 million decrease in letters of ~~Vistra Operations senior secured notes issued, $1.05 billion in net borrowings~~credit outstanding under the ~~new Commodity-Linked~~Revolving Credit Facility and ~~$725~~a $175 million decrease in net cash borrowings under the accounts receivable financing facilities, partially offset by ~~cash used~~a $639 million decrease in operations, including the change in margin deposits related to commodity contracts, $1.194 billion in cash paid for share repurchases, $613 million of capital expenditures (including LTSA prepayments, nuclear fuel and development and growth expenditures), a $911 million increase in letters of credit outstandingavailability under the ~~Revolving Credit~~Commodity-Linked Facility, ~~$152~~primarily due to a reduction of the borrowing base of $1.039 billion due to a decrease in commodity prices and partially offset by the repayment of $400 million in ~~dividends paid to common stockholders and $76 million in dividends paid to preferred stockholders.~~borrowings under the 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.

Higher commodity market prices combined with our comprehensive hedging strategy have resulted in significantly increased collateral posting obligations during the first six months of 2022. The majority of this collateral relates to hedges in place through 2023 and is expected to be returned as we satisfy our obligations under those contracts. As of August 3, 2022, Vistra had approximately $4.5 billion of cash and availability under its credit facilities to meet its liquidity needs. The Company believes it has additional alternatives to maintain access to liquidity, including drawing upon available liquidity, accessing additional sources of capital, or reducing capital expenditures, planned voluntary debt repayments or operating costs.

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 and other forms of credit support to satisfy such collateral posting obligations. See Note 1011 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.

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At ~~June 30, 2022,~~March 31, 2023, we received or posted cash and letters of credit for commodity hedging ~~and trading~~ activities as follows:

•$~~3.160~~1.919 billion in cash has been posted with counterparties as compared to ~~$1.263~~$3.137 billion posted at December 31, ~~2021;~~2022;

•$4348 million in cash has been received from counterparties as compared to $39 million received at December 31, ~~2021;~~2022;

•$~~2.565~~1.826 billion in letters of credit have been posted with counterparties as compared to ~~$1.558~~$2.314 billion posted at December 31, ~~2021;~~2022; and

•$49122 million in letters of credit have been received from counterparties as compared to ~~$35~~$74 million received at December 31, ~~2021.~~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 ~~$45~~$29 million in state income tax payments, offset by $5$6 million in state tax refunds, and $1$9 million in TRA payments in the next 12 months.

For the ~~six~~three months ended ~~June 30, 2022,~~March 31, 2023, there were no federal income tax payments, ~~$18~~$1 million in state income tax payments, $8$7 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 ~~(in excess of $300 million)~~ exceed 30% of the revolving ~~commitments)~~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 ~~total~~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 ~~million~~ to 1.00). As of ~~June 30, 2022,~~March 31, 2023, we were in compliance with ~~this~~these financial ~~covenant.~~covenants.

See Note 1011 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, at ~~June 30, 2022,~~March 31, 2023, Vistra has posted letters of credit in the amount of ~~$74~~$87 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 ~~$574~~$536 million in the form of letters of credit, ~~$20~~$30 million in the form of a surety bond and ~~$26~~$2 million of cash at ~~June 30, 2022~~March 31, 2023 (which is subject to daily adjustments based on settlement activity with the ISOs/RTOs).

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Material Cross Default/Acceleration Provisions

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

~~Table of Contents~~

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. Such a default would allow the lenders to accelerate the maturity of outstanding balances under such facilities, which totaled approximately ~~$2.779~~$2.507 billion at ~~June 30, 2022.~~March 31, 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 and the Vistra Operations Senior Secured Indenture, 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 Vistra Operations Credit Facilities, the Receivables Facility, the Commodity-Linked Facility and other current or future documents evidencing any indebtedness for borrowed money by the applicable borrower or issuer, as the case may be, and the applicable Guarantor Subsidiaries party thereto.

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

The Receivables Facility contains a cross-default provision. The cross-default provision applies, among other instances, if TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands and TriEagle, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), fails to make a payment of principal or interest on any indebtedness that is outstanding in a principal amount of at least $300 million, or, in the case of TXU Energy or any of the other Originators, in a principal amount of at least $50 million, 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 under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more, may result in a termination of the Secured LOC Facilities.

Under the Commodity-Linked Facility, 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 Commodity-Linked Facility.

Guarantees

See Note 1112 to the Financial Statements for discussion of guarantees.

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COMMITMENTS AND CONTINGENCIES

See Note 1112 to the Financial Statements for discussion of commitments and contingencies.

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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.

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.

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


		Six Months Ended June 30, 2022		Year Ended December 31, 2021			Three Months Ended March 31, 2023		Year Ended December 31, 2022
Month-end average VaR	Month-end average VaR	$	587	$	424	Month-end average VaR	$	279	$	489
Month-end high VaR	Month-end high VaR	$	686	$	684	Month-end high VaR	$	423	$	686
Month-end low VaR	Month-end low VaR	$	448	$	222	Month-end low VaR	$	194	$	283

The month-end high VaR risk measure in ~~2022~~2023 is ~~consistent with~~currently lower than the prior ~~year.~~year due to lower prices and higher hedge levels.

Interest Rate Risk

At ~~June 30, 2022,~~March 31, 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 1011 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 1415 to the Financial Statements for further discussion of this exposure.

Credit Exposure — Our gross credit exposure (excluding collateral impacts) associated with retail and wholesale trade accounts receivable and net derivative assets arising from commodity contracts and hedging and trading activities totaled ~~$2.353~~$1.789 billion at ~~June 30, 2022.~~March 31, 2023.

At ~~June 30, 2022,~~March 31, 2023, Retail segment credit exposure totaled approximately ~~$1.252~~$1.080 billion, including ~~$1.239~~$1.021 billion of trade accounts receivable and ~~$13~~$59 million related to derivatives. Cash deposits and letters of credit held as collateral for these receivables totaled ~~$69~~$51 million, resulting in a net exposure of ~~approximately $1.183~~$1.029 billion. Allowances for uncollectible accounts receivable are established for the ~~potential~~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.

At ~~June 30, 2022,~~March 31, 2023, aggregate Texas, East, Sunset and Asset Closure segments credit exposure totaled ~~$1.098 billion~~$709 million including ~~$890~~$533 million related to derivative assets and ~~$208~~$176 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 ~~$1.014 billion,~~$585 million, as seen in the following table that presents the distribution of credit exposure by counterparty credit quality at ~~June 30, 2022.~~March 31, 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			Exposure Before Credit Collateral		Credit Collateral		Net Exposure
Investment grade	Investment grade	$	557	$	30	$	527	Investment grade	$	560	$	24	$	536
Below investment grade or no rating	Below investment grade or no rating	541		54		487		Below investment grade or no rating	149		100		49
Totals	Totals	$	1,098	$	84	$	1,014	Totals	$	709	$	124	$	585

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Significant (i.e., 10% or greater) concentration of credit exposure exists with ~~four~~two counterparties, which represented an aggregate ~~$545~~$274 million, or ~~54%~~46%, of our total net exposure at ~~June 30, 2022.~~March 31, 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;~~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;

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•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, 2022.~~March 31, 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 1112 to the Financial Statements regarding legal proceedings.

Item 1A.RISK FACTORS

~~There~~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 ~~2021~~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, 2022.~~March 31, 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, 2022 6,315,304 $ 24.57 6,315,304 $ 824
May 1 - May 31, 2022 8,406,950 $ 25.37 8,406,950 $ 610
June 1 - June 30, 2022 4,378,005 $ 24.14 4,378,005 $ 505
For the quarter ended June 30, 2022 19,100,259 $ 24.83 19,100,259 $ 505


	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of a Publicly Announced Program	Maximum Dollar Amount of Shares that may yet be Purchased under the Program (in millions)
January 1 - January 31, 2023	4,796,396	$	22.46	4,796,396	$	897
February 1 - February 28, 2023	4,542,171	$	22.95	4,542,171	$	793
March 1 - March 31, 2023	3,969,898	$	24.07	3,969,898	$	1,697
For the quarter ended March 31, 2023	13,308,465	$	23.11	13,308,465	$	1,697

In October 2021, we announced that the Board had authorized a ~~new~~ 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. The Share Repurchase Program supersedes the $1.5 billion share repurchase program previously announced in September 2020, which had $1.325 billion of remaining authorization as of September 30, 2021. As an initial step in our broader capital allocation plan, we intend to use all of the net proceeds from our October 2021 Series A Preferred Stock offering to repurchase shares of our outstanding common stock.

OnIn August 4, 2022 and March 2023, the Board authorized an incremental amounts of $1.25 billion and $1.0 billion, respectively, for repurchases ~~under~~to bring the ~~Share Repurchase Program. Including the original Board authorization, approximately $1.65 billion remains available for share repurchases~~total authorized under the Share Repurchase Program ~~as of August 4, 2022.~~to $4.25 billion. We expect to complete repurchases under the Share Repurchase Program by the end of ~~2023.~~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 1213 to the Financial Statements for more information concerning the Share Repurchase Program.

Item 3.DEFAULTS UPON SENIOR SECURITIES

None.

~~Table of Contents~~

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

None.

Table of Contents

Item 6. EXHIBITS

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


Exhibits	Exhibits	Previously Filed With File Number*	As Exhibit			Exhibits	Previously Filed With File Number*	As Exhibit

(2)						(2)	Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession

2.1						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))	(3(i))	Articles of Incorporation				(3(i))	Articles of Incorporation

3.1	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.)	3.1	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	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	3.2	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	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	3.3	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	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	3.4	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))	(3(ii))	By-laws				(3(ii))	By-laws

3.3	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	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 May 16, 2022)	4.1	—	Eleventh Supplemental Indenture, dated as of May 13, 2022, among Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors (as defined therein), and Wilmington Trust, National Association, as Trustee

4.2		0001-38086 Form 8-K (filed May 16, 2022)	4.2	—	Form of Rule 144A Global Security for 4.875% Senior Note due 2024 (included in Exhibit 4.1)

4.3		0001-38086 Form 8-K (filed May 16, 2022)	4.3	—	Form of Regulation S Global Security for 4.875% Senior Note due 2024 (included in Exhibit 4.1)

4.4		0001-38086 Form 8-K (filed May 16, 2022)	4.4	—	Form of Rule 144A Global Security for 5.125% Senior Note due 202 5 (included in Exhibit 4.1)
(10)						(10)	Material Contracts

10.1						10.1	0001-38086 Form 8-K (filed March 7, 2023)	10.1	—	Form of Support Agreement, dated March 6, 2023

10.2						10.2	0001-38086 Form 8-K (filed March 7, 2023)	10.2	—	Form of Contribution and Exchange Agreement, dated March 6, 2023

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

31.1						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						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)						(32)	Section 1350 Certifications

32.1						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						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)						(95)	Mine Safety Disclosures

95.1						95.1	**		—	Mine Safety Disclosures

8377

Table of Contents

Exhibits Previously Filed With File Number*
As
Exhibit
4.5 0001-38086
Form 8-K
(filed May 16, 2022) 4.5 —
Form of Regulation S Global Security for 5.125% Senior Note due 202 5 (included in Exhibit 4.1)
4.6 0001-38086
Form 8-K
(filed July 15, 2022) 4.1 —
Twelfth Amendment to Receivables Purchase Agreement, dated as of July 11, 2022, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator
(10) Material Contracts
10.1 0001-38086
Form 8-K
(filed May 5, 2022) 10.1 —
Eleventh Amendment to the Credit Agreement, dated April 29, 2022, 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, the other Credit Parties (as defined in the Credit Agreement) party thereto, the Lenders (as defined in the Credit Agreement) party thereto, the financial institutions providing 2022 New Revolving Credit Commitments (as defined in the Credit Agreement), the Revolving Credit Lenders providing 2022 Extended Revolving Credit Commitments (as defined in the Credit Agreement), the Revolving Letter of Credit Issuers (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 May 16, 2022) 10.1 —
Purchase Agreement, dated May 10, 2022, by and among Vistra Operations Company LLC and Citigroup Global Markets Inc, on behalf of itself and the several Initial Purchases named in Schedule I to the Purchase Agreement
10.3 ** —
First Amendment to Credit Agreement, dated as of May 5, 2022, among Vistra Operations Company LLC, as Borrower, Vistra Intermediate Company LLC, as Holdings, Citibank, N.A., as Administrative Agent and as Collateral Agent, and the other lenders party thereto
10.4 ** —
Second Amendment to Credit Agreement, dated as of May 26, 2022, among Vistra Operations Company LLC, as Borrower, Vistra Intermediate Company LLC, as Holdings, Citibank, N.A., as Administrative Agent and as Collateral Agent, and the other lenders party thereto
10.5 ** —
Third Amendment to Credit Agreement, dated as of June 8, 2022, among Vistra Operations Company LLC, as Borrower, Vistra Intermediate Company LLC, as Holdings, Citibank, N.A., as Administrative Agent and as Collateral Agent, and the other lenders party thereto
10.6 ** —
Amended and Restated Employment Agreement, dated as of May 5, 2022, by and among Stephanie Zapata Moore, Vistra Corp. and Vistra Corporate Services Company
10.7 ** —
Amended and Restated Employment Agreement, dated as of May 5, 2022, between Carrie Lee Kirby, Vistra Corp. and Vistra Corporate Services Company
10.8 ** —
Amended and Restated Employment Agreement, dated as of May 5, 2022, between Scott A. Hudson, Vistra Corp. and Vistra Corporate Services Company
10.9 ** —
Amended and Restated Employment Agreement, dated as of May 5, 2022, between Stephen J. Muscato, Vistra Corp. and Vistra Corporate Services Company

~~Table of Contents~~

Exhibits Previously Filed With File Number*
As
Exhibit
10.10 0001-38086
Form 8-K
(filed July 15, 2022) 10.1 —
Amendment No. 3 to Master Framework Agreement, dated as of July 11, 2022, by and among TXU Energy Retail Company LLC, as seller and seller party agent, certain originators name d therein, Vistra Operations Company LLC, as guarantor, 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, 2022 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

Exhibits

Previously Filed With File Number*

Exhibit

XBRL Data Files

101.INS

—

The following financial information from Vistra Corp.'s Quarterly Report on Form 10-Q for the period ended March 31, 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

____________________

* Incorporated herein by reference

** Filed herewith

*** Furnished herewith

8578

Table of Contents

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 5, 2022~~May 9, 2023

8679


	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		220		183		—		567
Capacity revenue from ISO/RTO (a)	—		—		(4)		—		25		8		—		29
Revenue from other wholesale contracts	—		146		202		35		38		9		—		430
Total revenue from contracts with customers	2,300		87		368		88		283		200		—		3,326
Other revenues:
Intangible amortization	(1)		—		—		—		(2)		—		—		(3)
Hedging and other revenues (b)	(507)		(453)		(295)		(12)		(389)		(79)		—		(1,735)
Affiliate sales (c)	—		(257)		246		3		25		—		(17)		—
Total other revenues	(508)		(710)		(49)		(9)		(366)		(79)		(17)		(1,738)
Total revenues	$	1,792	$	(623)	$	319	$	79	$	(83)	$	121	$	(17)	$	1,588


	Three Months Ended June 30, 2021
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations		Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	1,417	$	—	$	—	$	—	$	—	$	—	$	—	$	1,417
Retail energy charge in Northeast/Midwest	504		—		—		—		—		—		—		504


Wholesale generation revenue from ISO/RTO	—		128		96		31		129		56		—		440
Capacity revenue from ISO/RTO (a)	—		—		2		—		32		11		—		45
Revenue from other wholesale contracts	—		56		130		24		44		—		—		254
Total revenue from contracts with customers	1,921		184		228		55		205		67		—		2,660
Other revenues:
Intangible amortization	(2)		—		73		—		(2)		—		—		69
Hedging and other revenues (b)	—		(8)		131		(7)		(172)		(108)		—		(164)
Affiliate sales (c)	—		(644)		73		—		(38)		—		609		—
Total other revenues	(2)		(652)		277		(7)		(212)		(108)		609		(95)
Total revenues	$	1,919	$	(468)	$	505	$	48	$	(7)	$	(41)	$	609	$	2,565


		June 30, 2022				December 31, 2021
Long-term debt (see Note 10):	Fair Value Hierarchy	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt under the Vistra Operations Credit Facilities	Level 2	$	2,534	$	2,409	$	2,549	$	2,518
Vistra Operations Senior Notes	Level 2	9,368		8,781		7,880		8,193

Forward Capacity Agreements	Level 3	—		—		211		211
Equipment Financing Agreements	Level 3	85		85		85		85
Building Financing	Level 2	—		—		3		3
Other debt	Level 3	3		3		3		3


	Balance 2022		2023
Texas:
Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price	$	3	$	18
Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price	$	(3)	$	(17)
Gas Generation: $1.00/MWh increase in spark spread	$	4	$	20
Gas Generation: $1.00/MWh decrease in spark spread	$	(3)	$	(19)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	1	$	(19)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	(1)	$	13
East:
Gas Generation: $1.00/MWh increase in spark spread	$	2	$	6
Gas Generation: $1.00/MWh decrease in spark spread	$	(1)	$	(4)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	(1)	$	6
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	1	$	(6)
West:
Gas Generation: $1.00/MWh increase in spark spread	$	—	$	—
Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	—
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	—	$	1
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	—	$	(1)
Sunset:
Coal Generation: $2.50/MWh increase in power price	$	1	$	13
Coal Generation: $2.50/MWh decrease in power price	$	(1)	$	(12)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	1	$	(10)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	(1)	$	10


	Clearing Price per MW-day		East Segment MW Cleared	Sunset Segment MW Cleared	Total MW Cleared
RTO zone	$	34.13	2,890	—	2,890
ComEd zone	$	34.13	1,151	408	1,559
DEOK zone	$	34.13	11	924	935
EMAAC zone	$	49.49	828	—	828
MAAC zone	$	49.49	545	—	545
ATSI zone	$	34.13	112	—	112
Total	$	37.20	5,537	1,332	6,869


	Three Months Ended June 30, 2022 Compared to 2021		Six Months Ended June 30, 2022 Compared to 2021
Winter Storm Uri, including bill credits	$	(16)	$	498
Higher/(lower) seasonal commodity costs	3		(111)
Lower margins reflecting self-help gains in 2021 partially offset by favorable weather in 2022	(65)		(89)
Other driven by higher bad debt expense and revenue-based taxes due to higher revenues in 2022	(29)		(42)
Change in Adjusted EBITDA	$	(107)	$	256
Favorable/(unfavorable) impact of unrealized net gains on hedging activities	(818)		704
Future bill credits and other costs related to Winter Storm Uri	5		448
Decrease in depreciation and amortization expenses	18		35
Change in transition and merger and other expenses	(10)		(15)
Change in net income	$	(912)	$	1,428