vistra-20210930

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2021

— 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 November 2, 2021, there were 482,627,520 shares of common stock, par value $0.01, outstanding of Vistra Corp.

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TABLE OF CONTENTS


		PAGE
GLOSSARY		ii
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Statements of Operations — Three and Nine Months Ended September 30, 2021 and 2020	1
	Condensed Consolidated Statements of Comprehensive Income (Loss) — Three and Nine Months Ended September 30, 2021 and 2020	1
	Condensed Consolidated Statements of Cash Flows — Nine Months Ended September 30, 2021 and 2020	2
	Condensed Consolidated Balance Sheets — September 30, 2021 and December 31, 2020	3
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	48
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	74
Item 4.	Controls and Procedures	79
PART II.	OTHER INFORMATION	80
Item 1.	Legal Proceedings	80
Item 1A.	Risk Factors	80
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	81
Item 3.	Defaults Upon Senior Securities	81
Item 4.	Mine Safety Disclosures	81
Item 5.	Other Information	81
Item 6.	Exhibits	81
SIGNATURE		85

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

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

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GLOSSARY

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


2020 Form 10-K						Vistra's annual report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 26, 2021
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.
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
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
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
IRC						Internal Revenue Code of 1986, as amended
IRS						U.S. Internal Revenue Service
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

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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						the merger 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
NELP						Northeast Energy, LP, a joint venture between Dynegy Northeast Generation GP, Inc. and Dynegy Northeast Associates LP, Inc., both indirect subsidiaries of Vistra, and certain subsidiaries of NextEra Energy, Inc. Prior to the NELP Transaction, NELP indirectly owned Bellingham NEA facility and the Sayreville facility.
NELP Transaction						a transaction among Dynegy Northeast Generation GP, Inc., Dynegy Northeast Associates LP, Inc. and certain subsidiaries of NextEra Energy, Inc. wherein the indirect subsidiaries of Vistra redeemed their ownership interest in NELP partnership in exchange for 100% ownership interest in NJEA, the entity which owns the Sayreville facility
NERC						North American Electric Reliability Corporation
NJEA						North Jersey Energy Associates, A Limited Partnership
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
OPEB						postretirement employee benefits other than pensions
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., 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 in exchange for all of PrefCo's authorized preferred stock, consisting of 70,000 shares, par value $0.01 per share
Public Power						Public Power, LLC (d/b/a Public Power), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of PJM, ISO-NE, NYISO and MISO that is engaged in the retail sale of electricity to residential and business customers
PUCT						Public Utility Commission of Texas
REP						retail electric provider
RCT						Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas, and has jurisdiction over oil and natural gas exploration and production, permitting and inspecting intrastate pipelines, and overseeing natural gas utility rates and compliance
RTO						regional transmission organization
S&P						Standard & Poor's Ratings (a credit rating agency)
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

iii

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SEC						U.S. Securities and Exchange Commission
Securities Act						Securities Act of 1933, as amended
SG&A						selling, general and administrative
SO2						sulfur dioxide
Tax Matters Agreement						Tax Matters Agreement, dated as of the Effective Date, by and among Energy Future Holdings Corp. (EFH Corp.), Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and EFH Merger Co. LLC
TCEH						Texas Competitive Electric Holdings Company LLC, a direct, wholly owned subsidiary of Energy Future Competitive Holdings Company LLC, and, prior to the Effective Date, the parent company of our predecessor, depending on context, that were engaged in electricity generation and wholesale and retail energy market activities, and whose major subsidiaries included Luminant and TXU Energy
TCEQ						Texas Commission on Environmental Quality
TRA						Tax Receivables 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 7 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
TWh						terawatt-hours
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. Effective July 2, 2020, Vistra Energy Corp. changed its name to Vistra Corp.
Vistra Intermediate						Vistra Intermediate Company LLC, a direct, wholly owned subsidiary of Vistra
Vistra Operations						Vistra Operations Company LLC, an indirect, wholly owned subsidiary of Vistra that is the issuer of certain series of notes (see Note 10 to the Financial Statements) and borrower under the Vistra Operations Credit Facilities
Vistra Operations Credit Facilities						Vistra Operations senior secured financing facilities (see Note 10 to the Financial Statements)

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PART I. FINANCIAL INFORMATION

Item 1.FINANCIAL STATEMENTS

VISTRA CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Operating revenues (Note 4)	$	2,991	$	3,552	$	8,763	$	8,919
Fuel, purchased power costs and delivery fees	(1,763)		(1,469)		(7,827)		(3,832)
Operating costs	(372)		(457)		(1,173)		(1,249)
Depreciation and amortization	(468)		(410)		(1,355)		(1,284)
Selling, general and administrative expenses	(269)		(268)		(771)		(755)

Impairment of long-lived assets (Note 17)	—		(272)		(38)		(356)
Operating income (loss)	119		676		(2,401)		1,443
Other income (Note 17)	16		8		108		19
Other deductions (Note 17)	(5)		—		(13)		(35)
Interest expense and related charges (Note 17)	(124)		(101)		(288)		(541)
Impacts of Tax Receivable Agreement (Note 7)	35		58		31		44
Equity in earnings of unconsolidated investment	—		—		—		4
Income (loss) before income taxes	41		641		(2,563)		934
Income tax (expense) benefit (Note 6)	(31)		(199)		569		(283)
Net income (loss)	$	10	$	442	$	(1,994)	$	651
Net (income) loss attributable to noncontrolling interest	(3)		1		(6)		14
Net income (loss) attributable to Vistra	$	7	$	443	$	(2,000)	$	665
Weighted average shares of common stock outstanding:
Basic	482,516,965		488,824,580		483,150,213		488,484,441
Diluted	484,494,546		491,025,940		483,150,213		490,914,478
Net income (loss) per weighted average share of common stock outstanding:
Basic	$	0.01	$	0.91	$	(4.14)	$	1.36
Diluted	$	0.01	$	0.90	$	(4.14)	$	1.35

See Notes to the Condensed Consolidated Financial Statements.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited) (Millions of Dollars)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Net income (loss)	$	10	$	442	$	(1,994)	$	651
Other comprehensive income (loss), net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax (expense) benefit of $(4), $1, $(5) and $8)	14		(4)		17		(26)

Total other comprehensive income (loss)	14		(4)		17		(26)
Comprehensive income (loss)	$	24	$	438	$	(1,977)	$	625
Comprehensive (income) loss attributable to noncontrolling interest	(3)		1		(6)		14
Comprehensive income (loss) attributable to Vistra	$	21	$	439	$	(1,983)	$	639

See Notes to the Condensed Consolidated Financial Statements.

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VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars)
	Nine Months Ended September 30,
	2021		2020
Cash flows — operating activities:
Net income (loss)	$	(1,994)	$	651
Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:
Depreciation and amortization	1,551		1,512
Deferred income tax expense (benefit), net	(587)		264

Impairment of long-lived assets (Note 17)	38		356
Loss on disposal of investment in NELP (Note 17)	—		29

Unrealized net (gain) loss from mark-to-market valuations of commodities	771		(444)
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps	(92)		181
Asset retirement obligation accretion expense	27		33
Impacts of Tax Receivable Agreement (Note 7)	(31)		(44)
Stock-based compensation	36		46
Other, net	79		115
Changes in operating assets and liabilities:
Margin deposits, net	(767)		60
Accrued interest	(55)		(97)
Accrued taxes	(63)		(35)
Accrued employee incentive	(86)		(20)
Other operating assets and liabilities	680		(257)
Cash provided by (used in) operating activities	(493)		2,350
Cash flows — investing activities:
Capital expenditures, including nuclear fuel purchases and LTSA prepayments	(790)		(838)

Proceeds from sales of nuclear decommissioning trust fund securities (Note 17)	366		291
Investments in nuclear decommissioning trust fund securities (Note 17)	(382)		(307)
Proceeds from sales of environmental allowances	102		91
Purchases of environmental allowances	(247)		(210)
Insurance proceeds	74		15
Proceeds from sale of assets	7		23
Other, net	27		8
Cash used in investing activities	(843)		(927)
Cash flows — financing activities:
Issuances of long-term debt (Note 10)	1,250		—
Borrowings under Term Loan A (Note 10)	1,250		—
Repayment under Term Loan A (Note 10)	(1,250)		—
Proceeds from forward capacity agreement (Note 10)	500		—
Repayments/repurchases of debt (Note 10)	(234)		(955)
Net borrowings under accounts receivable financing (Note 9)	175		175
Borrowings under Revolving Credit Facility (Note 10)	1,300		1,075
Repayments under Revolving Credit Facility (Note 10)	(1,300)		(1,425)
Share repurchases (Note 12)	(175)		—
Dividends paid to stockholders (Note 12)	(219)		(198)
Debt tender offer and other financing fees (Note 10)	(13)		(17)
Other, net	(5)		(3)
Cash provided by (used in) financing activities	1,279		(1,348)

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VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars)
	Nine Months Ended September 30,
	2021		2020
Net change in cash, cash equivalents and restricted cash	(57)		75
Cash, cash equivalents and restricted cash — beginning balance	444		475
Cash, cash equivalents and restricted cash — ending balance	$	387	$	550

See Notes to the Condensed Consolidated Financial Statements.


VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars)
	September 30, 2021		December 31, 2020
ASSETS
Current assets:
Cash and cash equivalents	$	351	$	406
Restricted cash (Note 17)	22		19
Trade accounts receivable — net (Note 17)	1,529		1,279
Income taxes receivable	7		—
Inventories (Note 17)	471		515
Commodity and other derivative contractual assets (Note 14)	4,187		748
Margin deposits related to commodity contracts	1,048		257
Prepaid expense and other current assets	231		205
Total current assets	7,846		3,429
Restricted cash (Note 17)	14		19
Investments (Note 17)	1,915		1,759

Property, plant and equipment — net (Note 17)	13,100		13,499
Operating lease right-of-use assets	35		45

Goodwill (Note 5)	2,583		2,583
Identifiable intangible assets — net (Note 5)	2,229		2,446
Commodity and other derivative contractual assets (Note 14)	454		258
Accumulated deferred income taxes	1,421		838
Other noncurrent assets	335		332
Total assets	$	29,932	$	25,208
LIABILITIES AND EQUITY
Current liabilities:

Accounts receivable financing (Note 9)	475		300
Long-term debt due currently (Note 10)	382		95
Trade accounts payable	1,172		880
Commodity and other derivative contractual liabilities (Note 14)	4,948		789
Margin deposits related to commodity contracts	57		33
Accrued income taxes	—		16
Accrued taxes other than income	163		210
Accrued interest	76		131
Asset retirement obligations (Note 17)	110		103
Operating lease liabilities	5		8

Other current liabilities	534		471
Total current liabilities	7,922		3,036

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VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars)
	September 30, 2021		December 31, 2020
Long-term debt, less amounts due currently (Note 10)	10,493		9,235
Operating lease liabilities	33		40

Commodity and other derivative contractual liabilities (Note 14)	896		624
Accumulated deferred income taxes	1		1
Tax Receivable Agreement obligation (Note 7)	416		447
Asset retirement obligations (Note 17)	2,326		2,333

Other noncurrent liabilities and deferred credits (Note 17)	1,814		1,131
Total liabilities	23,901		16,847
Commitments and Contingencies (Note 11)
Total equity (Note 12):
Common stock (par value — $0.01; number of shares authorized — 1,800,000,000) (shares outstanding: September 30, 2021 — 482,551,344; December 31, 2020 — 489,305,888)	5		5
Treasury stock, at cost (shares: September 30, 2021 — 49,701,377; December 31, 2020 — 41,043,224)	(1,148)		(973)
Additional paid-in-capital	9,829		9,786
Retained deficit	(2,619)		(399)
Accumulated other comprehensive loss	(31)		(48)
Stockholders' equity	6,036		8,371
Noncontrolling interest in subsidiary	(5)		(10)
Total equity	6,031		8,361
Total liabilities and equity	$	29,932	$	25,208

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 power generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity and natural gas to end users.

Vistra has six reportable segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. See Note 16 for further information concerning reportable business segments.

Winter Storm Uri

In February 2021, a severe winter storm with extremely cold temperatures affected much of the U.S., including Texas. Winter Storm Uri had a material adverse impact on our results of operations and operating cash flows. 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. The final financial impact of Winter Storm Uri continues to be subject to the outcome of potential litigation and legislative actions arising from the event, or any corrective action taken by the State of Texas, ERCOT, the RCT or the PUCT to resettle pricing across any portion of the supply chain (i.e. fuel supply, wholesale pricing of generation, or allocating the financial impacts of market-wide load shed ratably across all retail market participants), that is currently being considered or may be considered by any such parties.

In September 2021, the PUCT approved a settlement agreement among ERCOT, PUCT staff and certain ERCOT market participants who are parties to the PUCT proceeding in which ERCOT has applied for an order to finance, administer and distribute to eligible ERCOT market participants the securitization provided for under Texas House Bill 4492 (HB 4492). HB 4492 authorizes ERCOT to securitize up to $2.1 billion of certain costs allocated by ERCOT to load-serving entities (LSEs) during Winter Storm Uri. HB 4492, and final terms related thereto, are subject to the final financing order issued in October 2021, together with ERCOT obtaining sufficient financing related thereto. Though the final allocations will be determined following the completion of an administrative process, including final determination of which LSEs will participate in or opt out of the program, we expect to receive approximately $500 million of proceeds.

COVID-19 Pandemic

In March 2020, the World Health Organization categorized the novel coronavirus (COVID-19) as a pandemic, and the U.S. Government declared the COVID-19 outbreak a national emergency. The U.S. government has deemed electricity generation, transmission and distribution as “critical infrastructure” providing essential services during this global emergency. As a provider of critical infrastructure, Vistra has an obligation to provide critically needed power to homes, businesses, hospitals and other customers. Vistra remains focused on protecting the health and well-being of its employees and the communities in which it operates while assuring the continuity of its business operations.

The Company's condensed consolidated financial statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impact of COVID-19 on the assumptions and estimates used and determined that there have been no material adverse impacts on the Company's results of operations for the three or nine months ended September 30, 2021.

In response to the global pandemic related to COVID-19, the CARES Act was signed into law in March 2020. See Note 6 for a summary of certain anticipated tax-related impacts of the CARES Act to the Company.

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Recent Developments

Series A Preferred Stock Offering — On October 15, 2021, we issued of 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 (see Note 12). See Note 12 for more information concerning the Series A Preferred Stock.

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 2020 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 2020 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.

The Company determined that depreciation expense on certain property, plant, and equipment assets was calculated incorrectly in prior years as a result of incorrectly assigned useful lives to these assets, which resulted in a misstatement to depreciation expense and accumulated depreciation. Additionally, an error was identified related to assets that were incorrectly retired prior to the end of their useful lives. The Company identified that depreciation expense and accumulated depreciation was understated by $23 million, $39 million and $3 million for the years ended December 31, 2018, 2019, and 2020, respectively, and overstated by $20 million for the six-month period ended June 30, 2021. In order to correct for the misstatements, the Company recorded an out-of-period adjustment to depreciation expense of $45 million for the three months ended September 30, 2021. The Company evaluated the effects of this out-of-period adjustment, both qualitatively and quantitatively, and concluded that this adjustment was not material to the Company's financial position or results of operations for the current or any prior periods.

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.

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2. DEVELOPMENT OF GENERATION FACILITIES

Texas Segment Solar Generation and Energy Storage Projects

In September 2020, we announced the planned development of up to 668 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas. Estimated commercial operation dates for these facilities range from first quarter of 2022 to fourth quarter of 2023. At September 30, 2021, we had accumulated approximately $204 million in construction-work-in-process for these Texas segment solar generation and battery ESS 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 to 2025.

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.

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). PG&E filed its application with the CPUC in June 2018 and 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). PG&E filed its application with the CPUC in May 2020 and the CPUC approved the resource adequacy contract in August 2020. Moss Landing Phase II commenced commercial operations in July 2021.

The total development costs for Moss Landing Phases I and II totaled approximately $600 million.

Moss Landing Phase I Outage — On September 4, 2021, Moss Landing Phase I experienced an incident impacting a portion of the battery ESS. An initial review has found that only a small, single-digit percentage of batteries at the facility were impacted. The facility will be offline as the company continues to safely advance its root cause analysis and perform the work necessary to return the facility to service. We do not currently have an estimated return to service date for the facility. Moss Landing Phase II was not affected and remains operational. We do not expect the incident to have a material impact on our results of operations.

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3. RETIREMENT OF GENERATION FACILITIES

In September and December 2020, we announced our intention to retire all of our remaining coal generation facilities in Illinois and Ohio, one coal generation facility in Texas and one natural gas facility in Illinois no later than year-end 2027 due to economic challenges, including incremental expenditures that would be required to comply with the CCR rule and ELG rule (see Note 11), and in furtherance of our efforts to significantly reduce our carbon footprint. Expected plant retirement expenses of $43 million, driven by severance cost, were accrued in the three months ended September 30, 2020 in operating costs of our Sunset segment. In April 2021, we announced we would retire the Joppa generation facilities by September 1, 2022 in order to settle a complaint filed with the Illinois Pollution Control Board (IPCB) by the Sierra Club in 2018 (see Note 11). We had previously announced that Joppa would retire no later than the end of 2027. In July 2021, we announced we would retire the Zimmer coal generation facility by May 31, 2022 due to the inability to secure capacity revenues for the plant in the latest PJM capacity auction held in May 2021. We had previously announced that Zimmer would retire no later than the end of 2027.

In September 2019, we announced the settlement of a lawsuit alleging violations of opacity and particulate matter limits at our Edwards coal generation facility in Illinois. As part of the settlement, which was approved by the U.S. District Court for the Central District of Illinois in November 2019, we will retire the Edwards facility by the end of 2022.

Operational results for plants with planned retirements are included in our Sunset segment beginning in the quarter when a retirement plan is announced. See Note 17 for discussion of impairments recorded in connection with these announcements.

Name

Location

ISO/RTO

Fuel Type

Net Generation Capacity (MW)

Expected Retirement Date (a)

Baldwin

Baldwin, IL

MISO

Coal

1,185

By the end of 2025

Coleto Creek

Goliad, TX

ERCOT

Coal

650

By the end of 2027

Edwards

Bartonville, IL

MISO

Coal

585

By the end of 2022

Joppa

Joppa, IL

MISO

Coal

802

By September 1, 2022

Joppa

Joppa, IL

MISO

Natural Gas

221

By September 1, 2022

Kincaid

Kincaid, IL

PJM

Coal

1,108

By the end of 2027

Miami Fort

North Bend, OH

PJM

Coal

1,020

By the end of 2027

Newton

Newton, IL

MISO/PJM

Coal

615

By the end of 2027

Zimmer

Moscow, OH

PJM

Coal

1,300

By May 31, 2022

Total

7,486

____________

(a)Generation facilities may retire earlier than expected dates if economic or other conditions dictate.

In December 2020, we announced the retirement of our 83 MW Wharton natural gas facility in Texas due to its age, cost profile and small scale, as well as low power prices, limited operational windows and substantial costs to repair, maintain and upgrade the facility. Operational results for the Wharton facility are included in the Asset Closure segment. The previously announced retirement of our 244 MW Trinidad natural gas facility in Texas was rescinded in April 2021.

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4. REVENUE


	Three Months Ended September 30, 2021
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations		Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	1,896	$	—	$	—	$	—	$	—	$	—	$	—	$	1,896
Retail energy charge in Northeast/Midwest	624		—		—		—		—		—		—		624


Wholesale generation revenue from ISO/RTO	—		211		191		89		322		—		—		813
Capacity revenue from ISO/RTO (a)	—		—		(13)		1		51		—		—		39
Revenue from other wholesale contracts	—		88		167		29		46		—		—		330
Total revenue from contracts with customers	2,520		299		345		119		419		—		—		3,702
Other revenues:
Intangible amortization	2		—		—		—		(2)		—		—		—
Hedging and other revenues (b)	(362)		(7)		222		(30)		(534)		—		—		(711)
Affiliate sales (c)	—		551		(59)		1		(5)		—		(488)		—
Total other revenues	(360)		544		163		(29)		(541)		—		(488)		(711)
Total revenues	$	2,160	$	843	$	508	$	90	$	(122)	$	—	$	(488)	$	2,991

____________

(a)Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $117 million of capacity purchased offset by $104 million of capacity sold.

(b)Includes $861 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 segment includes $527 million of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

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	Three Months Ended September 30, 2020
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations		Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	1,824	$	—	$	—	$	—	$	—	$	—	$	—	$	1,824
Retail energy charge in Northeast/Midwest	683		—		—		—		—		—		—		683


Wholesale generation revenue from ISO/RTO	—		125		78		37		165		1		—		406
Capacity revenue from ISO/RTO (a)	—		—		(25)		—		40		—		—		15
Revenue from other wholesale contracts	—		68		183		16		43		—		—		310
Total revenue from contracts with customers	2,507		193		236		53		248		1		—		3,238
Other revenues:
Intangible amortization	7		—		1		—		(4)		—		—		4
Hedging and other revenues (b)	7		230		57		30		(14)		—		—		310
Affiliate sales	—		1,118		350		1		69		—		(1,538)		—
Total other revenues	14		1,348		408		31		51		—		(1,538)		314
Total revenues	$	2,521	$	1,541	$	644	$	84	$	299	$	1	$	(1,538)	$	3,552

____________

(a)Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $137 million of capacity purchased offset by $112 million of capacity sold.

(b)Includes $287 million of unrealized net gains from mark-to-market valuations of commodity positions. See Note 16 for unrealized net gains (losses) by segment.


	Nine Months Ended September 30, 2021
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations		Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	4,460	$	—	$	—	$	—	$	—	$	—	$	—	$	4,460
Retail energy charge in Northeast/Midwest	1,715		—		—		—		—		—		—		1,715
Wholesale generation revenue from ISO/RTO	—		3,585		442		158		1,230		—		—		5,415
Capacity revenue from ISO/RTO (a)	—		—		(14)		1		133		—		—		120
Revenue from other wholesale contracts	—		2,172		459		75		148		—		—		2,854
Total revenue from contracts with customers	6,175		5,757		887		234		1,511		—		—		14,564
Other revenues:
Intangible amortization	(1)		—		74		—		(10)		—		—		63
Hedging and other revenues (b)	(345)		(4,457)		418		(66)		(1,414)		—		—		(5,864)
Affiliate sales (c)	—		158		359		3		22		—		(542)		—
Total other revenues	(346)		(4,299)		851		(63)		(1,402)		—		(542)		(5,801)
Total revenues	$	5,829	$	1,458	$	1,738	$	171	$	109	$	—	$	(542)	$	8,763

____________

(a)Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $345 million of capacity purchased offset by $332 million of capacity sold.

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(b)Includes $1,146 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 segment includes $2.153 billion of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.


	Nine Months Ended September 30, 2020
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations		Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	4,489	$	—	$	—	$	—	$	—	$	—	$	—	$	4,489
Retail energy charge in Northeast/Midwest	1,862		—		—		—		—		—		—		1,862
Wholesale generation revenue from ISO/RTO	—		283		177		83		305		1		—		849
Capacity revenue from ISO/RTO (a)	—		—		(34)		—		124		—		—		90
Revenue from other wholesale contracts	—		183		508		40		146		—		—		877
Total revenue from contracts with customers	6,351		466		651		123		575		1		—		8,167
Other revenues:
Intangible amortization	(1)		—		1		—		(16)		—		—		(16)
Hedging and other revenues (b)	35		529		25		85		92		2		—		768
Affiliate sales	—		2,250		1,168		3		212		—		(3,633)		—
Total other revenues	34		2,779		1,194		88		288		2		(3,633)		752
Total revenues	$	6,385	$	3,245	$	1,845	$	211	$	863	$	3	$	(3,633)	$	8,919

____________

(a)Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes $412 million of capacity purchased offset by $378 million of capacity sold.

(b)Includes $418 million of unrealized net gains from mark-to-market valuations of commodity positions. See Note 16 for unrealized net gains (losses) by segment.

Performance Obligations

As of September 30, 2021, 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 $226 million, $649 million, $301 million, $206 million and $98 million that will be recognized, in the balance of the year ended December 31, 2021 and the years ending December 31, 2022, 2023, 2024 and 2025, respectively, and $484 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:


	September 30, 2021		December 31, 2020
Trade accounts receivable from contracts with customers — net	$	1,377	$	1,169
Other trade accounts receivable — net	152		110
Total trade accounts receivable — net	$	1,529	$	1,279

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5. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

Goodwill

At both September 30, 2021 and December 31, 2020, 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:


	September 30, 2021						December 31, 2020
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	2,082	$	1,581	$	501	$	2,082	$	1,434	$	648
Software and other technology-related assets	410		197		213		414		186		228
Retail and wholesale contracts	248		199		49		272		204		68
Contractual service agreements (a)	31		—		31		51		1		50
Other identifiable intangible assets (b)	80		20		60		96		19		77
Total identifiable intangible assets subject to amortization	$	2,851	$	1,997	854		$	2,915	$	1,844	1,071
Retail trade names (not subject to amortization)					1,374						1,374
Mineral interests (not currently subject to amortization)					1						1
Total identifiable intangible assets					$	2,229					$	2,446

____________

(a)At September 30, 2021, 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	September 30, 2021		December 31, 2020
Contractual service agreements	$	125	$	129
Purchase and sale of power and capacity	10		87
Fuel and transportation purchase contracts	15		73
Total identifiable intangible liabilities	$	150	$	289

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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 September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020
Retail customer relationship	Depreciation and amortization	$	49	$	62	$	147	$	214
Software and other technology-related assets	Depreciation and amortization	20		19		58		56
Retail and wholesale contracts/purchase and sale/fuel and transportation contracts	Operating revenues/fuel, purchased power costs and delivery fees	1		(4)		(60)		11
Other identifiable intangible assets	Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization	91		66		196		162
Total intangible asset expense (a)		$	161	$	143	$	341	$	443

___________

(a)Amounts recorded in depreciation and amortization totaled $70 million and $82 million for the three months ended September 30, 2021 and 2020, respectively and $208 million and $272 million for the nine months ended September 30, 2021 and 2020. Amounts exclude contractual services agreements. Amounts include all expenses associated with environmental allowances including expenses accrued to comply with emissions allowance programs and renewable portfolio standards which are presented in fuel, purchased power costs and delivery fees on our condensed consolidated statements of operations. Emissions allowance obligations are accrued as associated electricity is generated and renewable energy certificate obligations are accrued as retail electricity delivery occurs.

Estimated Amortization of Identifiable Intangible Assets and Liabilities

As of September 30, 2021, the estimated aggregate amortization expense of identifiable intangible assets and liabilities for each of the next five fiscal years is as shown below.


Year	Estimated Amortization Expense
2021	$	212
2022	$	192
2023	$	137
2024	$	88
2025	$	63

6. INCOME TAXES

Income Tax Expense

The calculation of our effective tax rate is as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Income (loss) before income taxes	$	41		$	641		$	(2,563)		$	934
Income tax (expense) benefit	$	(31)		$	(199)		$	569		$	(283)
Effective tax rate	75.6		%	31.0		%	22.2		%	30.3		%

For the three months ended September 30, 2021, the effective tax rate of 75.6% was higher than the U.S. federal statutory rate of 21% due primarily to nondeductible impacts of the TRA, additional valuation allowance against certain state net operating losses, and state income taxes. For the nine months ended September 30, 2021, the effective tax rate of 22.2% was higher than the U.S. federal statutory rate of 21% due primarily to nondeductible impacts of the TRA and state income taxes.

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For the three months ended September 30, 2020, the effective tax rate of 31.0% was higher that the U.S. federal statutory rate of 21% due primarily to nondeductible impacts of the TRA and state income taxes, including the impact of an increase in the valuation allowance on a portion of state net operating losses. For the nine months ended September 30, 2020, the effective tax rate of 30.3% was higher than the U.S. federal statutory rate of 21% due primarily to nondeductible impacts of the TRA and state income taxes.

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

In response to the global pandemic related to COVID-19, the CARES Act was signed into law in March 2020. The CARES Act provides numerous relief provisions for 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 of certain payment requirements for the employer portion of social security taxes. Additionally, the final Section 163(j) regulations were issued in July 2020 and provided a critical correction to the proposed regulations with respect to the computation of adjusted taxable income. Vistra expects to receive an approximate $265 million increase in interest expense deduction in the 2021 tax year under the final Section 163(j) regulations. We do not anticipate a material impact to the effective tax rate from this impact. Vistra also utilized the CARES Act payroll deferral mechanism to defer the payment of approximately $20 million from 2020 to 2021 and 2022. We expect to pay approximately half of the previously deferred taxes in December 2021.

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. Crius is currently under audit by the IRS for the tax years 2015 and 2016. Uncertain tax positions totaled $39 million at both September 30, 2021 and December 31, 2020.

7. TAX RECEIVABLE AGREEMENT OBLIGATION

On the Effective Date, Vistra entered into a tax receivable agreement (the TRA) with a transfer agent on behalf of certain former first-lien creditors of TCEH. The TRA generally provides for the payment by us to holders of TRA Rights of 85% of the amount of cash savings, if any, in U.S. federal and state income tax that we realize in periods after Emergence as a result of (a) certain transactions consummated pursuant to the Plan of Reorganization (including the step-up in tax basis in our assets resulting from the PrefCo Preferred Stock Sale), (b) the tax basis of all assets acquired in connection with the acquisition of two CCGT natural gas-fueled generation facilities in April 2016 and (c) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA, plus interest accruing from the due date of the applicable tax return.

Pursuant to the TRA, we issued the TRA Rights for the benefit of the first-lien secured creditors of TCEH entitled to receive such TRA Rights under the Plan of Reorganization. Such TRA Rights are entitled to certain registration rights more fully described in the Registration Rights Agreement (see Note 15).

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 nine months ended September 30, 2021 and 2020:


	Nine Months Ended September 30,
	2021		2020
TRA obligation at the beginning of the period	$	450	$	455
Accretion expense	48		50
Changes in tax assumptions impacting timing of payments (a)	(79)		(94)
Impacts of Tax Receivable Agreement	(31)		(44)

TRA obligation at the end of the period	419		411
Less amounts due currently	(3)		—
Noncurrent TRA obligation at the end of the period	$	416	$	411

____________

(a)During the three months ended September 30, 2021, we recorded a decrease to the carrying value of the TRA obligation totaling $51 million as a result of adjustments to forecasted taxable income and anticipated tax benefits available under

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current tax laws for planned additional renewable development projects, particularly in light of the recent passage of Illinois' coal-to-solar legislation. During the nine months ended September 30, 2021, we recorded a decrease to the carrying value of the TRA obligation totaling $79 million as a result of adjustments to forecasted taxable income, including the financial impacts of Winter Storm Uri, and anticipated tax benefits available under current tax laws for planned additional renewable development projects. During the three and nine months ended September 30, 2020, we recorded decreases of $74 million and $94 million, respectively, to the carrying value of the TRA obligation as a result of adjustments to forecasted taxable income, including the impacts of the CARES Act, and changes to Section 163(j) percentage limitation amount, the impacts from the issuance of final Section 163(j) regulations and the anticipated tax benefits from renewable development projects.

As of September 30, 2021, the estimated carrying value of the TRA obligation totaled $419 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. These assumptions are subject to change, and those changes could have a material impact on the carrying value of the TRA obligation. As of September 30, 2021, 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.

8. EARNINGS PER SHARE

Basic earnings per share available to common stockholders are based on the weighted average number of common shares outstanding during the period. Diluted earnings per share is calculated using the treasury stock method and includes the effect of all potential issuances of common shares under stock-based incentive compensation arrangements.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Net income (loss) attributable to common stock — basic	$	7	$	443	$	(2,000)	$	665
Weighted average shares of common stock outstanding — basic	482,516,965		488,824,580		483,150,213		488,484,441
Net income (loss) per weighted average share of common stock outstanding — basic	$	0.01	$	0.91	$	(4.14)	$	1.36
Dilutive securities: Stock-based incentive compensation plan	1,977,581		2,201,360		—		2,430,037
Weighted average shares of common stock outstanding — diluted	484,494,546		491,025,940		483,150,213		490,914,478
Net income (loss) per weighted average share of common stock outstanding — diluted	$	0.01	$	0.90	$	(4.14)	$	1.35

Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 12,851,055 and 13,778,275 in the three months ended September 30, 2021 and 2020, respectively, and 15,223,763 and 12,471,806 shares for the nine months ended September 30, 2021 and 2020, respectively.

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9. 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 2021, extending the term of the Receivables Facility to July 2022, with the ability to borrow $600 million beginning with the settlement date in July 2021 until the settlement date in August 2021, $725 million from the settlement date in August 2021 until the settlement date in November 2021 and $600 million from the settlement date in November 2021 and thereafter for the remaining term of the Receivables Facility.

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 September 30, 2021, outstanding borrowings under the Receivables Facility totaled $475 million and were supported by $954 million of RecCo gross receivables. As of December 31, 2020, outstanding borrowings under the Receivables Facility totaled $300 million and were supported by $735 million of RecCo gross receivables.

Repurchase Facility

In October 2020, TXU Energy and the other originators under the Receivables Facility entered into a $125 million repurchase facility (Repurchase Facility) that is provided on an uncommitted basis by a commercial bank as buyer (Buyer). In July 2021, the Repurchase Facility was renewed until August 2021 and increased from $125 million to $150 million. In August 2021, the Repurchase Facility was renewed until July 2022 and the facility size was decreased from $150 million to $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.

There were no outstanding borrowings at both September 30, 2021 and December 31, 2020.

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10. LONG-TERM DEBT

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


	September 30, 2021		December 31, 2020
Vistra Operations Credit Facilities	$	2,550	$	2,572
Vistra Operations Senior Secured Notes:
3.550% Senior Secured Notes, due July 15, 2024	1,500		1,500
3.700% Senior Secured Notes, due January 30, 2027	800		800
4.300% Senior Secured Notes, due July 15, 2029	800		800
Total Vistra Operations Senior Secured Notes	3,100		3,100
Vistra Operations Senior Unsecured Notes:
5.500% Senior Unsecured Notes, due September 1, 2026	1,000		1,000
5.625% Senior Unsecured Notes, due February 15, 2027	1,300		1,300
5.000% Senior Unsecured Notes, due July 31, 2027	1,300		1,300
4.375% Senior Secured Notes, due May 15, 2029	1,250		—
Total Vistra Operations Senior Unsecured Notes	4,850		3,600





Other:
Forward Capacity Agreements	343		45
Equipment Financing Agreements	105		68
8.82% Building Financing due semiannually through February 11, 2022 (a)	3		10
Other	3		3
Total other long-term debt	454		126
Unamortized debt premiums, discounts and issuance costs (b)	(79)		(68)
Total long-term debt including amounts due currently	10,875		9,330
Less amounts due currently	(382)		(95)
Total long-term debt less amounts due currently	$	10,493	$	9,235

____________

(a)Obligation related to a corporate office space finance lease. This obligation will be funded by amounts held in an escrow account that is reflected in current assets in our condensed consolidated balance sheets.

(b)Includes impact of recording debt assumed in the Merger at fair value.

Vistra Operations Credit Facilities

At September 30, 2021, the Vistra Operations Credit Facilities consisted of up to $5.275 billion in senior secured, first-lien revolving credit commitments and outstanding term loans, which consisted of revolving credit commitments of up to $2.725 billion, including a $2.35 billion letter of credit sub-facility (Revolving Credit Facility) and term loans of $2.550 billion (Term Loan B-3 Facility).

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 nine months ended September 30, 2021.

In March 2020, Vistra Operations repurchased and cancelled $100 million principal amount of Term Loan B-3 Facility borrowings at a weighted average price of $93.875. We recorded an extinguishment gain of $6 million on the transaction in the nine months ended September 30, 2020.

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During the nine months ended September 30, 2021, we borrowed $1.3 billion and repaid $1.3 billion under the Revolving Credit Facility, with proceeds from the borrowings used for general corporate purposes.

The Vistra Operations Credit Facilities and related available capacity at September 30, 2021 are presented below.


		September 30, 2021
Vistra Operations Credit Facilities	Maturity Date	Facility Limit		Cash Borrowings		Letters of Credit Outstanding		Available Capacity
Revolving Credit Facility (a)	June 14, 2023	$	2,725	$	—	$	1,005	$	1,720

Term Loan B-3 Facility (b)	December 31, 2025	2,550		2,550		—		—
Total Vistra Operations Credit Facilities		$	5,275	$	2,550	$	1,005	$	1,720

___________

(a)Revolving Credit Facility used for general corporate purposes. The Facility includes a $2.35 billion letter of credit sub-facility. Letters of credit outstanding reduce our available capacity. Cash borrowings under the Revolving Credit Facility are reported in short-term borrowings in our condensed consolidated balance sheets.

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

At September 30, 2021, cash borrowings under the Revolving Credit Facility would bear interest based on applicable LIBOR rates, plus a fixed spread of 1.75%, and there were no outstanding borrowings. Letters of credit issued under the Revolving Credit Facility bear interest of 1.75%. Amounts borrowed under the Term Loan B-3 Facility bears interest based on applicable LIBOR rates plus fixed spreads of 1.75%. At September 30, 2021, the weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings was 1.83%. 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 Revolving Credit Facility.

Obligations under the Vistra Operations Credit Facilities are secured by a lien covering substantially all of Vistra Operations' (and its subsidiaries') consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra Operations Credit Facilities, 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 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.

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. Although the period ended September 30, 2021 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. 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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Interest Rate Swaps — Vistra employs interest rate swaps to hedge our exposure to variable rate debt. As of September 30, 2021, Vistra has entered into the following series of interest rate swap transactions.


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

____________

(a)Effective from July 2023 through July 2026.

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. At September 30, 2021, $354 million of letters of credit were outstanding under the Secured LOC Facilities. In October 2021, Vistra entered into an additional Secured LOC Facility which will also be used for general corporate purposes.

Alternate Letter of Credit Facility

At September 30, 2021, $250 million of letters of credit were outstanding under a $250 million alternate letter of credit facility. The facility is to be used for general corporate purposes and matures in December 2021.

Vistra Operations Senior Secured Notes

In 2019, Vistra Operations issued and sold $3.1 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 and the 4.300% senior secured notes due 2029 (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 $1.250 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 April 2020, the Company's board of directors (Board) authorized up to $1.0 billion to repay or repurchase additional outstanding debt. Through February 2021, approximately $666 million had been repurchased under the authorization. In March 2021, the Board authorized up to $1.8 billion to repay or repurchase additional outstanding debt, which authorization superseded any amounts that remained outstanding under any previous authorizations. Through September 30, 2021, no debt had been repurchased under the March 2021 authorization.

Vistra Senior Unsecured Notes

June 2020 Redemption — In June 2020, Vistra redeemed the entire $500 million aggregate principal amount outstanding of 5.875% senior notes at a redemption price equal to 100.979% of the aggregate principal amount thereof, plus accrued and unpaid interest to, but excluding, the date of redemption. We recorded an extinguishment gain of $3 million on the transaction in the nine months ended September 30, 2020.

January 2020 Redemption — In January 2020, Vistra redeemed the entire $81 million aggregate principal amount outstanding of 8.000% senior notes at a redemption price equal to 104.0% of the aggregate principal amount thereof, plus accrued and unpaid interest to, but excluding, the date of redemption. We recorded an extinguishment gain of $2 million on the transaction in the nine months ended September 30, 2020.

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 will receive capacity payments from PJM during the Planning Years 2021-2022 in the amount of approximately $515 million. We will continue to be subject to the performance obligations as well as any associated performance penalties and bonus payments for those planning years. As a result, this transaction is accounted for as a debt issuance with an implied interest rate of approximately 4.25%.

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.

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Maturities

Long-term debt maturities at September 30, 2021 are as follows:


	September 30, 2021
Remainder of 2021	$	151
2022	257
2023	40
2024	1,540
2025	2,470
Thereafter	6,496
Unamortized premiums, discounts and debt issuance costs	(79)
Total long-term debt, including amounts due currently	$	10,875

11. COMMITMENTS AND CONTINGENCIES

Guarantees

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

Letters of Credit

At September 30, 2021, we had outstanding letters of credit totaling $1.609 billion as follows:

•$1.316 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;

•$129 million to support battery and solar development projects;

•$29 million to support executory contracts and insurance agreements;

•$74 million to support our REP financial requirements with the PUCT, and

•$61 million for other credit support requirements.

Surety Bonds

At September 30, 2021, we had outstanding surety bonds totaling $502 million to support performance under various contracts and legal obligations in the normal course of business.

Litigation and Regulatory Proceedings

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

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Gas Index Pricing Litigation — We, through our subsidiaries, and other companies are named as defendants in several lawsuits 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 remain as defendants in two consolidated putative class actions (Wisconsin) and one individual action (Kansas) both pending in federal court in those states. In the Kansas action, in June 2021, the U.S. Court of Appeals for the Tenth Circuit affirmed the district court's 2019 denial of summary judgment (for reasons different from those of the district court), but also limited the type of damages the plaintiff in that action might be able to recover and remanded the case for further proceedings.

Wood River Rail Dispute — In November 2017, Dynegy Midwest Generation, LLC (DMG) received notification that BNSF Railway Company and Norfolk Southern Railway Company were initiating dispute resolution related to DMG's suspension of its Wood River Rail Transportation Agreement with the railroads. In March 2018, BNSF Railway Company (BNSF) and Norfolk Southern Railway Company (NS) filed a demand for arbitration. In March 2021, the parties entered into a confidential settlement to resolve this matter and the Coffeen matter discussed below. In connection with that settlement, BNSF and NS dismissed with prejudice their arbitration disputes for Wood River and Coffeen and these matters are fully resolved.

Coffeen and Duck Creek Rail Disputes — In April 2020, IPH, LLC (IPH) received notification that BNSF and NS were initiating dispute resolution related to IPH's suspension of its Coffeen Rail Transportation Agreement with the railroads, and Illinois Power Resources Generating, LLC (IPRG), received notification that BNSF was initiating dispute resolution related to IPRG's suspension of its Duck Creek Rail Transportation Agreement with BNSF. In November 2019, IPH and IPRG sent suspension notices to the railroads asserting that the Illinois Multi-Pollutant Standards (MPS) rule requirement to retire at least 2,000 megawatts of generation (see discussion below) was a change-in-law under the agreement that rendered continued operation of the plants no longer economically feasible. In addition, IPH and IPRG asserted that the MPS rule's retirement requirement also qualified as a force majeure event under the agreements excusing performance. In March 2021, we entered into a confidential settlement agreement with BNSF to resolve the Duck Creek matter and a separate confidential settlement agreement with BNSF and NS to resolve the Coffeen and Wood River matter discussed above. BNSF has dismissed with prejudice the Duck Creek arbitration dispute and this matter is now fully resolved. The settlement of these rail disputes did not have a material impact on our financial statements.

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. 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 our challenge to the PUCT's orders. 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 the PUCT has not prejudged or made a final decision on whether to reprice and that we and other parties may continue disputing the pricing through the ERCOT process.

Koch Disputes — In March 2021, we 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 pursuant to which we purchased our Odessa gas power plant for $350 million. Koch subsequently filed its own related lawsuit in Delaware Chancery Court. The APA dispute will now proceed in Delaware Chancery Court which will consider all our equitable and other claims, including our claim contesting 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. Because Koch is seeking a $286 million payment in the lawsuit, we have recorded a liability of that amount in other noncurrent liabilities and deferred credits in our condensed consolidated balance sheets. However, we will defend the case vigorously and believe that it is reasonably possible we will prevail in litigation and will not be required to pay Koch this amount.

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In addition, in March 2021, we filed a lawsuit in New York state court against Koch for breach of contract and ineffective force majeure for Koch's failure to deliver gas during the event pursuant to a gas supply contract with them, as well as a claim for unjust enrichment by selling gas to others at higher prices rather than fulfilling their contract obligations to us. Koch has removed that case to New York federal court.

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 are responding to all those investigatory requests. In addition, a number of personal injury and wrongful death lawsuits related to Winter Storm Uri have been 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.

Climate Change

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

In August 2015, the EPA finalized rules to address GHG emissions from electricity generation units, referred to as the Clean Power Plan, including rules for existing facilities that would establish state-specific emissions rate goals to reduce nationwide CO2 emissions. Various parties filed petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court). In July 2019, petitioners filed a joint motion to dismiss in light of the EPA's issuance of the rule that replaced the Clean Power Plan, the Affordable Clean Energy rule, discussed below. In September 2019, the D.C. Circuit Court granted petitioners' motion to dismiss and dismissed all of the petitions challenging the Clean Power Plan as moot.

In July 2019, the EPA finalized a rule to repeal the Clean Power Plan, with 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. The ACE rule set a deadline of July 2022 for states to submit their plans for regulating GHG emissions from existing facilities. States where we operate coal plants (i.e., Texas, Illinois and Ohio) began to develop their state plans to comply with the rule. Environmental groups and certain states filed petitions for review of the ACE rule and the repeal of the Clean Power Plan in the D.C. Circuit Court, and the D.C. Circuit Court heard argument on those issues in October 2020. In January 2021, the D.C. Circuit Court vacated the ACE rule and remanded the rule to the EPA for further action. In its decision, the D.C. Circuit Court concluded that the EPA's basis for repealing the Clean Power Plan and adopting the ACE rule was not supported by the Clean Air Act. In April 2021, the State of West Virginia and certain other parties filed a petition for writ of certiorari with the U.S. Supreme Court of the D.C. Circuit Court's decision, and in June 2021, the State of North Dakota also filed a petition for writ of certiorari. In October 2021, the U.S. Supreme Court granted four petitions for certiorari and consolidated the cases for review. Additionally, in December 2018, the EPA issued proposed revisions to the emission standards for new, modified and reconstructed units. Vistra submitted comments on that proposed rulemaking in March 2019. 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. The final rule excludes sectors from future regulation where GHG emissions make up less than three percent of U.S. GHG emissions. The final rule did not set any specific emission limits for new, modified, or reconstructed electric utility generating units. In April 2021, the D.C. Circuit Court granted the EPA's unopposed motion for voluntary vacatur and remand of the GHG significant contribution rule. The ACE rule and the rule on significant contribution are subject to the Environment Executive Order discussed above.

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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) and a partial Federal Implementation Plan (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 our 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. The retirements of our Monticello, Big Brown and Sandow 4 plants have enhanced our ability to comply with this BART rule for SO2. For NOX, the rule adopted the CSAPR's ozone program as BART and for particulate matter, the rule approved Texas's SIP that determines that no electricity generation units are subject to BART for particulate matter. Various parties filed a petition challenging the rule in the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court) as well as a petition for reconsideration filed with the EPA. Luminant intervened on behalf of the EPA in the Fifth Circuit Court action. In March 2018, the Fifth Circuit Court abated its proceedings pending conclusion of the EPA's reconsideration process. 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. In October 2020, environmental groups petitioned for review of this rule in both the D.C. Circuit Court and the Fifth Circuit Court. In December 2020, a panel of the Fifth Circuit Court consolidated the challenges to the BART final rule and issued an order transferring the case to the D.C. Circuit Court. We challenged that decision, but the Fifth Circuit Court denied reconsideration and denied our motion for leave to seek review of that denial by the full court. We are in compliance with the rule. 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.

Affirmative Defenses During Malfunctions

In May 2015, the EPA finalized a rule requiring 36 states, including Texas, Illinois and Ohio, to remove or replace either EPA-approved exemptions or affirmative defense provisions for excess emissions during upset events and unplanned maintenance and startup and shutdown events, referred to as the SIP Call. Various parties (including Luminant, the State of Texas and the State of Ohio) filed petitions for review of the EPA's final rule, and all of those petitions were consolidated in the D.C. Circuit Court. In April 2017, the D.C. Circuit Court ordered the case to be held in abeyance. In April 2019, the EPA Region 6 proposed a rule to withdraw the SIP Call with respect to the Texas affirmative defense provisions. We submitted comments on that proposed rulemaking in June 2019. In February 2020, the EPA issued the final rule withdrawing the Texas SIP Call. Following the issuance of the final rule for Texas, we moved to dismiss our challenge to the SIP Call, which was granted by the court. In April 2020, a group of environmental petitioners, including the Sierra Club, filed a petition in the D.C. Circuit Court challenging the EPA's action with respect to Texas. In October 2020, the EPA issued new guidance on the inclusion of startup, shutdown and malfunction (SSM) provisions in SIPs, which is intended to supersede the policy in the multi-state SIP Call. The guidance provides that the SIPs may contain provisions for SSM events if certain conditions are met. The EPA SSM guidance is subject to the Environment Executive Order discussed above. In April 2021, environmental groups petitioned the EPA for reconsideration and rulemaking regarding the EPA's rules withdrawing the SSM SIP Call for certain states, including Texas. In September 2021, the EPA issued a memorandum withdrawing the October 2020 memorandum addressing SSM provisions in SIPs and re-implementing the prior (2015) policy. In the 2021 memorandum, the EPA indicated it will revisit the SIP Call withdrawal for Texas that was finalized in 2020. We cannot predict the outcome of any rulemaking initiated under the new SSM policy.

Illinois Multi-Pollutant Standards (MPS)

In August 2019, changes proposed by the Illinois Pollution Control Board to the MPS rule, which places NOX, SO2 and mercury emissions limits on our coal plants located in MISO went into effect. Under the revised MPS rule, our allowable SO2 and NOX emissions from the MISO fleet are 48% and 42% lower, respectively, than prior to the rule changes. The revised MPS rule requires the continuous operation of existing selective catalytic reduction (SCR) control systems during the ozone season, requires SCR-controlled units to meet an ozone season NOX emission rate limit, and set an additional, site-specific annual SO2 limit for our Joppa Power Station. Additionally, in 2019, the Company retired its Havana, Hennepin, Coffeen and Duck Creek plants thereby fully complying with the MPS rule's requirement to retire at least 2,000 MW of our generation in MISO.

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SO2 Designations for Texas

In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Big Brown, Monticello and Martin Lake generation plants. The final designations require Texas to develop nonattainment plans for these areas. In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court. 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. In August 2019, the EPA issued a proposed Error Correction Rule for all three areas, which, if finalized, would revise its previous nonattainment designations and each area at issue would be designated unclassifiable. In September 2019, we submitted comments in support of the proposed Error Correction Rule. In April 2020, the Sierra Club filed suit to compel the EPA to issue a Finding of Failure to submit an attainment plan with respect to the three areas in Texas. In August 2020, the EPA issued a Finding of Failure for Texas to submit an attainment plan. In September 2020, the EPA proposed a "Clean Data" determination for the areas surrounding the retired Big Brown and Monticello plants, which was finalized in May 2021, 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 with the matter likely being fully briefed by March 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 will not reduce emission limits until January 2022, and any reductions will be those necessary to meet the NAAQS. Once finalized, the TCEQ's SIP action will be submitted to the EPA for review and approval.

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 from November 1, 2018 to November 1, 2020. Based on these administrative developments, the Fifth Circuit Court agreed to sever and hold in abeyance challenges to 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. In November 2019, the EPA issued a proposal that would extend the compliance deadline for FGD wastewater to no later than December 31, 2025 and maintains the December 31, 2023 compliance date for bottom ash transport water. The proposal also creates new sub-categories of facilities with more flexible FGD compliance options, including a retirement exemption to 2028 and a low utilization boiler exemption. The proposed rule also modified some of the FGD final effluent limitations. We filed comments on the proposal in January 2020. The EPA published the final rule in October 2020. The final rule extends the compliance date for both FGD and bottom ash transport water to no later than December 2025, as negotiated with the state permitting agency. Additionally, the final rule allows for a retirement exemption that exempts facilities certifying that units will retire by December 2028 provided certain effluent limitations are met. In November 2020, environmental groups petitioned for review of the new ELG revisions, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020. Notifications were made to Texas, Illinois and Ohio state agencies on the retirement exemption for applicable coal plants by the regulatory deadline of October 13, 2021. The litigation is in abeyance pending the EPA's reconsideration of the ELG revisions finalized in 2020.

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Coal Combustion Residuals/Groundwater

In July 2018, the EPA published a final rule, which became effective in August 2018, that amends certain provisions of the CCR rule that the agency issued in 2015. Among other changes, the 2018 revisions extended closure deadlines to October 31, 2020, related to the aquifer location restriction and groundwater monitoring requirements. Also, 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 December 2019, the EPA issued a proposed rule containing a revised closure deadline for unlined CCR impoundments and new procedures for seeking extensions of that revised closure deadline. We filed comments on the proposal in January 2020. In August 2020, the EPA issued a rule finalizing the December 2019 proposal, 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 alternate liner demonstration for one CCR unit at Martin Lake. In October 2020, the EPA published an advanced notice of proposed rulemaking requesting information to inform the EPA in the development of a rule to address legacy impoundments that existed prior to the 2015 CCR regulation as required by the August 2018 D.C. Circuit Court decision. We filed comments on this proposal in February 2021. The EPA has completed its review under the Environmental Executive Order of the rules on revised closure deadlines and alternative liner demonstrations. The EPA determined that the most environmentally protective course is to implement the rules. In August 2021, we submitted a request to transfer our conversion application for the Zimmer facility to a retirement application following announcement that Zimmer will close by May 31, 2022. The EPA has not yet acted on any of our conversion or retirement applications.

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 are working towards implementation of those closure plans.

At our retired Vermilion facility, which was not subject to the EPA's 2015 CCR rule until the aforementioned D.C. Circuit Court decision in August 2018, we submitted proposed corrective action plans involving closure of two CCR surface impoundments (i.e., the old east and the north impoundments) to the IEPA in 2012, and we submitted revised plans in 2014. In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options. In May 2018, Prairie Rivers Network (PRN) filed a citizen suit in federal court in Illinois against 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 U.S. Court of Appeals for the Seventh Circuit affirmed the district court's dismissal of the lawsuit, but stated that PRN may refile. 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. In July 2021, we answered that complaint, and this matter is in the very early stages.

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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. These proposed closure costs are reflected in the ARO in our condensed consolidated balance sheets (see Note 17). In September 2021, PRN filed a motion to intervene in this enforcement action. In October 2021, the court granted PRN narrow discretionary intervention.

In December 2018, the Sierra Club filed a complaint with the IPCB alleging the disposal and storage of coal ash at the Coffeen, Edwards and Joppa generation facilities are causing exceedances of the applicable groundwater standards. In April 2021, we entered into a settlement agreement with the Sierra Club to resolve this matter. As part of that agreement, we agreed to close the Joppa Power Plant by September 1, 2022. This matter is now fully resolved.

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. In March 2020, the IEPA issued its proposed rule. Under the proposed rule, 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 proposed rule does not mandate closure by removal at any site. Public hearings for the proposed rule were held in August 2020 and September 2020. The rule was finalized and became effective in April 2021. 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. 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.

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 will require us to undertake further site specific evaluations which are underway. 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 submitted and approved by the IEPA. However, the currently anticipated CCR surface impoundment and landfill closure costs, as contained in our AROs, reflect the costs of closure methods that meet the requirements and 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, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 planning resource auction (PRA) conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc., the Illinois Attorney General and Southwestern Electric Cooperative, Inc. (Complainants), challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO planning resource auction structure going forward. Complainants also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the PRA. The Independent Market Monitor for MISO (MISO IMM), which was responsible for monitoring the PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the remedies sought by the Complainants. We filed our answer to these complaints explaining that we complied fully with the terms of the MISO tariff in connection with the PRA and disputing the allegations. The Illinois Industrial Energy Consumers filed a related complaint at 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.

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

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

In July 2019, FERC issued an order denying the remaining issues raised by the complaints and noted that the investigation into Dynegy was closed. 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 request for rehearing was denied by 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 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 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 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 FERC for further proceedings on that issue.

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. 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 billion of our outstanding shares of common stock may be repurchased. The Share Repurchase Program became effective on October 11, 2021, at which time it superseded the Prior Share Repurchase Program (described below) and any authorization remaining as of such date. We intend to use the net proceeds from the Offering (described below) to repurchase shares of our outstanding common stock. We expect to complete repurchases under the Share Repurchase Program by the end of 2022.

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.

In September 2020, we announced that the Board authorized a share repurchase program (Prior Share Repurchase Program) under which up to $1.5 billion of our outstanding shares of common stock may be repurchased. The Prior Share Repurchase Program became effective on January 1, 2021. No shares were repurchased in the three months ended September 30, 2021. In the nine months ended September 30, 2021, 8,658,153 shares of our common stock were repurchased under the Prior Share Repurchase Program for approximately $175 million (including related fees and expenses) at an average price of $20.21 per share of common stock. As of September 30, 2021, approximately $1.325 billion was available for additional repurchases under the Prior Share Repurchase Program, which amount has been superseded by the Share Repurchase Program.

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Series A Preferred Stock

On October 15, 2021 (Issuance Date), we issued of 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 (described above).

The Series A Preferred Stock is not convertible into or exchangeable for any other securities of the Company and has limited voting rights. The Series A Preferred Stock may be redeemed at the option of the Company at any time after the First Reset Date (defined below) and in certain other circumstances prior to the First Reset Date.

Dividends

Common Stock — 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.

In February 2020, April 2020, July 2020 and October 2020, the Board declared quarterly dividends of $0.135 per share that were paid in March 2020, June 2020, September 2020 and December 2020, respectively.

In February 2021, April 2021 and July 2021, the Board declared a quarterly dividend of $0.15 per share that was paid in March 2021, June 2021 and September 2021, respectively. In October 2021, the Board declared a quarterly dividend of $0.15 per share that will be paid in December 2021.

Preferred Stock — The annual dividend rate on each share of Series A Preferred Stock is 8.0% from the Issuance Date to, but excluding October 15, 2026 (First Reset Date). On and after the 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.

Dividend Restrictions

The Credit Facilities Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of September 30, 2021, Vistra Operations can distribute approximately $6.3 billion to Parent under the Credit Facilities 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 $75 million and $255 million during the three months ended September 30, 2021 and 2020, respectively, and $405 million and $1.105 billion during the nine months ended September 30, 2021 and 2020, respectively. Additionally, Vistra Operations may make distributions to Parent in amounts sufficient for Parent to make any payments required under the TRA or the Tax Matters Agreement or, to the extent arising out of Parent's ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses. As of September 30, 2021, all of the restricted net assets of Vistra Operations may be distributed to Parent.

In addition to the restrictions under the Credit Facilities 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, 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) 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.

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Warrants

At the 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 Merger, or 0.652 shares of Vistra common stock. Accordingly, upon exercise, a warrant holder would effectively pay $53.68 (subject to adjustment of the exercise price from time to time) per share of Vistra common stock received. In July 2021, in accordance with the terms of the warrant agreement, the exercise price of each warrant was adjusted downward to $34.54 (subject to further adjustment from time to time), or $52.98 (subject to adjustment of the exercise price from time to time) per share of Vistra common stock received. As of September 30, 2021, nine million warrants expiring in 2024 were outstanding. The warrants were included in equity based on their fair value at the Merger Date.

Equity

The following table presents the changes to equity for the three months ended September 30, 2021:


	Common Stock (a)		Treasury Stock		Additional Paid-in Capital		Retained Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss)		Total Stockholders' Equity		Noncontrolling Interest		Total Equity
Balance at June 30, 2021	$	5	$	(1,148)	$	9,816	$	(2,552)	$	(45)	$	6,076	$	(8)	$	6,068
Stock repurchases	—		—		—		—		—		—		—		—

Dividends declared on common stock	—		—		—		(72)		—		(72)		—		(72)
Effects of stock-based incentive compensation plans	—		—		12		—		—		12		—		12
Net income (loss)	—		—		—		7		—		7		3		10

Change in accumulated other comprehensive income (loss)	—		—		—		—		14		14		—		14

Other	—		—		1		(2)		—		(1)		—		(1)
Balance at September 30, 2021	$	5	$	(1,148)	$	9,829	$	(2,619)	$	(31)	$	6,036	$	(5)	$	6,031

The following table presents the changes to equity for the nine months ended September 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	—		—		—		(219)		—		(219)		—		(219)
Effects of stock-based incentive compensation plans	—		—		39		—		—		39		—		39
Net income (loss)	—		—		—		(2,000)		—		(2,000)		6		(1,994)

Change in accumulated other comprehensive income (loss)	—		—		—		—		17		17		—		17

Other	—		—		4		(1)		—		3		(1)		2
Balance at September 30, 2021	$	5	$	(1,148)	$	9,829	$	(2,619)	$	(31)	$	6,036	$	(5)	$	6,031

________________

(a)Authorized shares totaled 1,800,000,000 at September 30, 2021. Outstanding common shares totaled 482,551,344 and 489,305,888 at September 30, 2021 and December 31, 2020, respectively. Treasury shares totaled 49,701,377 and 41,043,224 at September 30, 2021 and December 31, 2020, respectively.

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The following table presents the changes to equity for the three months ended September 30, 2020:


	Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss)		Total Stockholders' Equity		Noncontrolling Interest		Total Equity
Balance at June 30, 2020	$	5	$	(973)	$	9,754	$	(678)	$	(52)	$	8,056	$	(12)	$	8,044


Dividends declared on common stock	—		—		—		(66)		—		(66)		—		(66)
Effects of stock-based incentive compensation plans	—		—		18		—		—		18		—		18
Net income	—		—		—		443		—		443		(1)		442

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

Other	—		—		(1)		(2)		—		(3)		—		(3)
Balance at September 30, 2020	$	5	$	(973)	$	9,771	$	(303)	$	(56)	$	8,444	$	(13)	$	8,431

The following table presents the changes to equity for the nine months ended September 30, 2020:


	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, 2019	$	5	$	(973)	$	9,721	$	(764)	$	(30)	$	7,959	$	1	$	7,960


Dividends declared on common stock	—		—		—		(198)		—		(198)		—		(198)
Effects of stock-based incentive compensation plans	—		—		48		—		—		48		—		48
Net income (loss)	—		—		—		665		—		665		(14)		651
Adoption of accounting standard	—		—		—		(4)		—		(4)		—		(4)
Change in accumulated other comprehensive income (loss)	—		—		—		—		(26)		(26)		—		(26)

Other	—		—		2		(2)		—		—		—		—
Balance at September 30, 2020	$	5	$	(973)	$	9,771	$	(303)	$	(56)	$	8,444	$	(13)	$	8,431

________________

(a)Authorized shares totaled 1,800,000,000 at September 30, 2020. Outstanding common shares totaled 488,874,505 and 487,698,111 at September 30, 2020 and December 31, 2019, respectively. Treasury shares totaled 41,043,224 at both September 30, 2020 and December 31, 2019.

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13. 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 14 for additional information regarding credit risk associated with our derivatives). We utilize credit ratings and default rate factors in calculating these fair value measurement adjustments.

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

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

•Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means, and other valuation inputs such as interest rates and yield curves observable at commonly quoted intervals. We attempt to obtain multiple quotes from brokers that are active in the markets in which we participate and require at least one quote from two brokers to determine a pricing input as observable. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker's publication policy, recent trading volume trends and various other factors.

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

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

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


	September 30, 2021										December 31, 2020
	Level 1		Level 2		Level 3 (a)		Reclass (b)		Total		Level 1		Level 2		Level 3 (a)		Reclass (b)		Total
Assets:
Commodity contracts	$	2,881	$	1,165	$	440	$	116	$	4,602	$	452	$	201	$	205	$	76	$	934
Interest rate swaps	—		39		—		—		39		—		72		—		—		72
Nuclear decommissioning trust – equity securities (c)	671		—		—				671		623		—		—				623
Nuclear decommissioning trust – debt securities (c)	—		654		—				654		—		618		—				618
Sub-total	$	3,552	$	1,858	$	440	$	116	5,966		$	1,075	$	891	$	205	$	76	2,247
Assets measured at net asset value (d):
Nuclear decommissioning trust – equity securities (c)									502										433
Total assets									$	6,468									$	2,680
Liabilities:
Commodity contracts	$	3,519	$	1,265	$	664	$	116	$	5,564	$	578	$	172	$	183	$	76	$	1,009
Interest rate swaps	—		280		—		—		280		—		404		—		—		404
Total liabilities	$	3,519	$	1,545	$	664	$	116	$	5,844	$	578	$	576	$	183	$	76	$	1,413

___________

(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.

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

Commodity contracts consist primarily of natural gas, electricity, coal and emissions agreements and include financial instruments entered into for economic hedging purposes as well as physical contracts that have not been designated as normal purchases or sales. Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest to fixed rates. See Note 14 for further discussion regarding derivative instruments.

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

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The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations at September 30, 2021 and December 31, 2020:


September 30, 2021
	Fair Value
Contract Type (a)	Assets		Liabilities		Total		Valuation Technique	Significant Unobservable Input	Range (b)					Average (b)
Electricity purchases and sales	$	283	$	(462)	$	(179)	Income Approach	Hourly price curve shape (c)	$	—		to	$60	$30
									MWh
								Illiquid delivery periods for hub power prices and heat rates (d)	$	20		to	$160	$90
									MWh
Options	16		(97)		(81)		Option Pricing Model	Gas to power correlation (e)	10		%	to	100%	55%
								Power and gas volatility (e)	5		%	to	500%	248%
Financial transmission rights	81		(29)		52		Market Approach (f)	Illiquid price differences between settlement points (g)	$	(30)		to	$15	$(6)
									MWh
Natural gas	17		(70)		(53)		Income Approach	Gas basis (h)	$	—		to	$15	$6
									MMBtu

Coal	28		—		28		Income Approach	Probability of default (i)	—%			to	40%	20	%
								Recovery rate (j)	—%			to	40%	20	%
Other (k)	15		(6)		9
Total	$	440	$	(664)	$	(224)


December 31, 2020
	Fair Value
Contract Type (a)	Assets		Liabilities		Total		Valuation Technique	Significant Unobservable Input	Range (b)					Average (b)
Electricity purchases and sales	$	61	$	(90)	$	(29)	Income Approach	Hourly price curve shape (c)	$	—		to	$85	$43
									MWh
								Illiquid delivery periods for ERCOT hub power prices and heat rates (d)	$	25		to	$125	$75
									MWh
Options	38		(56)		(18)		Option Pricing Model	Gas to power correlation (e)	30		%	to	100%	64%
								Power and gas volatility (e)	5		%	to	665%	336%
Financial transmission rights	92		(16)		76		Market Approach (f)	Illiquid price differences between settlement points (g)	$	(5)		to	$50	$22
									MWh
Natural gas	7		(14)		(7)		Income Approach	Gas basis (h)	$	(1)		to	$—	$—
									MMBtu
Coal	1		(5)		(4)		Income Approach	Probability of default (i)	—%			to	40%	20	%
								Recovery rate (j)	—%			to	40%	20	%


Other (k)	6		(2)		4
Total	$	205	$	(183)	$	22

____________

(a)Electricity purchase and sales contracts include power and heat rate positions in ERCOT, PJM, ISO-NE, NYISO and MISO regions. The forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points are referred to as congestion revenue rights (CRRs) in ERCOT and financial transmission rights (FTRs) in PJM, ISO-NE, NYISO and MISO regions. Options consist of physical electricity options, spread options, swaptions and natural gas options.

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

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

(d)Primarily based on historical forward ERCOT and PJM power prices and ERCOT heat rate variability.

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(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.

(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 environmental allowances.

See the table below for discussion of transfers between Level 2 and Level 3 for the three and nine months ended September 30, 2021 and 2020.

The following table presents the changes in fair value of the Level 3 assets and liabilities for the three and nine months ended September 30, 2021 and 2020.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Net asset (liability) balance at beginning of period	$	46	$	114	$	22	$	(74)
Total unrealized valuation gains (losses) (a)	(174)		(22)		—		77
Purchases, issuances and settlements (b):
Purchases	33		39		73		129
Issuances	(12)		(6)		(22)		(12)
Settlements	(72)		(20)		(238)		(68)
Transfers into Level 3 (c)	(28)		4		(26)		3
Transfers out of Level 3 (c)	(17)		7		(33)		61


Net change (d)	(270)		2		(246)		190
Net asset balance at end of period	$	(224)	$	116	$	(224)	$	116
Unrealized valuation gains (losses) relating to instruments held at end of period	$	(224)	$	(12)	$	(240)	$	119

____________

(a)During both the three and nine months ended September 30, 2021, includes a net loss of $263 million due to the discontinuance of normal purchase and sale accounting on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract 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 months ended September 30, 2021, transfers into Level 3 primarily consist of gas 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 nine months ended September 30, 2020, transfers out of Level 3 primarily consist of gas, power and coal 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 (excluding the net liabilities assumed in connection with the Merger) are reported as operating revenues in our condensed consolidated statements of operations.

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14.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 13 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.

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 September 30, 2021 and December 31, 2020. 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 nine months ended September 30, 2021, a net loss of $357 million was recognized in operating revenues due to the discontinuance of normal purchase and sale accounting on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract term. These amounts are reflected in commodity contracts derivative liabilities at September 30, 2021.


	September 30, 2021
	Derivative Assets				Derivative Liabilities
	Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total
Current assets	$	4,106	$	19	$	62	$	—	$	4,187
Noncurrent assets	424		20		10		—		454
Current liabilities	(15)		—		(4,861)		(72)		(4,948)
Noncurrent liabilities	(29)		—		(659)		(208)		(896)
Net assets (liabilities)	$	4,486	$	39	$	(5,448)	$	(280)	$	(1,203)


	December 31, 2020
	Derivative Assets				Derivative Liabilities
	Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total
Current assets	$	665	$	19	$	64	$	—	$	748
Noncurrent assets	197		53		8		—		258
Current liabilities	(1)		—		(717)		(71)		(789)
Noncurrent liabilities	(3)		—		(288)		(333)		(624)
Net assets (liabilities)	$	858	$	72	$	(933)	$	(404)	$	(407)

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At September 30, 2021 and December 31, 2020, there were no derivative positions accounted for as cash flow or fair value hedges.

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


Derivative (condensed consolidated statements of operations presentation)	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Commodity contracts (Operating revenues)	$	(919)	$	147	$	(1,017)	$	410
Commodity contracts (Fuel, purchased power costs and delivery fees)	333		18		448		(40)
Interest rate swaps (Interest expense and related charges)	(1)		(2)		53		(209)
Net gain (loss)	$	(587)	$	163	$	(516)	$	161

Balance Sheet Presentation of Derivatives

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

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

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


	September 30, 2021								December 31, 2020
	Derivative Assets and Liabilities		Offsetting Instruments (a)		Cash Collateral (Received) Pledged (b)		Net Amounts		Derivative Assets and Liabilities		Offsetting Instruments (a)		Cash Collateral (Received) Pledged (b)		Net Amounts
Derivative assets:
Commodity contracts	$	4,486	$	(3,947)	$	(49)	$	490	$	858	$	(667)	$	(11)	$	180
Interest rate swaps	39		(39)		—		—		72		(72)		—		—
Total derivative assets	4,525		(3,986)		(49)		490		930		(739)		(11)		180
Derivative liabilities:
Commodity contracts	(5,448)		3,947		681		(820)		(933)		667		138		(128)
Interest rate swaps	(280)		39		—		(241)		(404)		72		—		(332)
Total derivative liabilities	(5,728)		3,986		681		(1,061)		(1,337)		739		138		(460)
Net amounts	$	(1,203)	$	—	$	632	$	(571)	$	(407)	$	—	$	127	$	(280)

____________

(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 September 30, 2021 and December 31, 2020:


	September 30, 2021		December 31, 2020
Derivative type	Notional Volume				Unit of Measure
Natural gas (a)	5,030		5,264		Million MMBtu
Electricity	437,475		438,863		GWh
Financial transmission rights (b)	210,432		217,350		GWh
Coal	32		20		Million U.S. tons
Fuel oil	106		176		Million gallons

Emissions	32		8		Million tons
Renewable energy certificates	31		18		Million certificates

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

____________

(a)Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas transactions.

(b)Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within regions.

(c)Includes notional amounts of interest rate swaps with maturity dates through July 2026.

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:


	September 30, 2021		December 31, 2020
Fair value of derivative contract liabilities (a)	$	(1,706)	$	(679)
Offsetting fair value under netting arrangements (b)	1,069		262
Cash collateral and letters of credit	52		35
Liquidity exposure	$	(585)	$	(382)

____________

(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 September 30, 2021, total credit risk exposure to all counterparties related to derivative contracts totaled $4.754 billion (including associated accounts receivable). The net exposure to those counterparties totaled $603 million at September 30, 2021, after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $51 million. At September 30, 2021, the credit risk exposure to the banking and financial sector represented 83% of the total credit risk exposure and 20% 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.

15.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 Registration Rights Agreement) with certain selling stockholders providing for registration of the resale of the Vistra common stock held by such selling stockholders.

In December 2016, we filed a Form S-1 registration statement with the SEC to register for resale the shares of Vistra common stock held by certain significant stockholders pursuant to the Registration Rights Agreement, which was declared effective by the SEC in May 2017. The registration statement was amended in March 2018. Pursuant to the Registration Rights Agreement, in June 2018, we filed a post-effective amendment to the Form S-1 registration statement on Form S-3, which was declared effective by the SEC in July 2018. Among other things, under the terms of the Registration Rights Agreement:

•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 Registration Rights Agreement the opportunity to register all or part of their shares on the terms and conditions set forth in the Registration Rights Agreement; and

•the selling stockholders received the right, subject to certain conditions and exceptions, to request that we file registration statements or amend or supplement registration statements, with the SEC for an underwritten offering of all or part of their respective shares of Vistra common stock (a Demand Registration), and the Company is required to cause any such registration statement or amendment or supplement (a) to be filed with the SEC promptly and, in any event, on or before the date that is 45 days, in the case of a registration statement on Form S-1, or 30 days, in the case of a registration statement on Form S-3, after we receive the written request from the relevant selling stockholders to effectuate the Demand Registration (as defined in the Registration Rights Agreement) and (b) to become effective as promptly as reasonably practicable and in any event no later than 120 days after it is initially filed.

All expenses of registration under the Registration Rights Agreement, including the legal fees of one counsel retained by or on behalf of the selling stockholders, will be paid by us.

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 7 for discussion of the TRA.

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16.SEGMENT INFORMATION

The operations of Vistra are aligned into six reportable business segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. In the third quarter of 2020, Vistra updated its reportable segments to reflect changes in how the Company's Chief Operating Decision Maker (CODM) makes operating decisions, assesses performance and allocates resources. Management believes the revised reportable segments provide enhanced transparency into the Company's long-term sustainable assets and its commitment to managing the retirement of economically and environmentally challenged plants. The following is a summary of the updated segments:

•The Sunset segment represents plants with announced retirement plans that were previously reported in the ERCOT, PJM and MISO segments As we announced significant plant closures in the third quarter of 2020, management believes it is important to have a segment which differentiates between operating plants with defined retirement plans and operating plants without defined retirement plans.

•The East segment represents 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 PJM, ISO-NE and NYISO that were previously reported in the PJM and NY/NE segments, respectively.

•The West segment represents Vistra's electricity generation operations in CAISO and was previously reported in the Corporate and Other non-segment. As reflected by the Moss Landing and Oakland ESS projects (see Note 2), the Company expects to expand its operations in the West segment.

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 the ERCOT market and was referred to as the ERCOT segment prior to the third quarter of 2020. The East segment represents results from the PJM, ISO-NE and NYISO markets. We determined it was appropriate to aggregate results from these markets into one reportable segment, East, given similar economic characteristics.

The West segment represents results from the CAISO market, including our development of battery ESS projects at our Moss Landing and Oakland power plant sites (see Note 2).

The Sunset segment consists of generation plants with announced retirement plans. 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 plans.

The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines (see Note 3). 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 not allocated any unrealized gains or losses on the commodity risk management activities to the Asset Closure segment for the generation plants that were retired in 2018, 2019 and 2020.

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. Our CODM uses more than one measure to assess segment performance, including segment net income (loss), which is the measure most comparable to consolidated net income (loss) prepared based on U.S. GAAP. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at market prices. Certain shared services costs are allocated to the segments.

Three months ended

Retail

Texas

East

West

Sunset

Asset Closure

Corporate and Other (c)

Eliminations

Consolidated

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Operating revenues (a):
September 30, 2021	$	2,160	$	843	$	508	$	90	$	(122)	$	—	$	—	$	(488)	$	2,991
September 30, 2020	2,521		1,541		644		84		299		1		—		(1,538)		3,552
Depreciation and amortization (b):
September 30, 2021	$	(53)	$	(179)	$	(164)	$	(15)	$	(40)	$	—	$	(17)	$	—	$	(468)
September 30, 2020	(67)		(107)		(181)		(5)		(22)		(11)		(17)		—		(410)
Operating income (loss):
September 30, 2021	$	782	$	(4)	$	(228)	$	(19)	$	(380)	$	(6)	$	(26)	$	—	$	119
September 30, 2020	110		908		102		25		(370)		(65)		(34)		—		676
Net income (loss):
September 30, 2021	$	779	$	4	$	(233)	$	(18)	$	(375)	$	(6)	$	(141)	$	—	$	10
September 30, 2020	109		908		100		29		(368)		(60)		(276)		—		442



Nine Months ended	Retail		Texas		East		West		Sunset		Asset Closure		Corporate and Other (b)		Eliminations		Consolidated
Operating revenues (a):
September 30, 2021	$	5,829	$	1,458	$	1,738	$	171	$	109	$	—	$	—	$	(542)	$	8,763
September 30, 2020	6,385		3,245		1,845		211		863		3		—		(3,633)		8,919
Depreciation and amortization (b):
September 30, 2021	$	(160)	$	(462)	$	(553)	$	(30)	$	(99)	$	—	$	(51)	$	—	$	(1,355)
September 30, 2020	(229)		(340)		(540)		(14)		(101)		(12)		(48)		—		(1,284)
Operating income (loss):
September 30, 2021	$	2,689	$	(3,726)	$	(321)	$	(71)	$	(851)	$	(39)	$	(82)	$	—	$	(2,401)
September 30, 2020	440		1,482		150		42		(475)		(95)		(101)		—		1,443
Net income (loss):
September 30, 2021	$	2,677	$	(3,651)	$	(332)	$	(62)	$	(841)	$	(20)	$	235	$	—	$	(1,994)
September 30, 2020	433		1,484		119		49		(469)		(89)		(876)		—		651
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures:
September 30, 2021	$	1	$	214	$	39	$	7	$	29	$	—	$	62	$	—	$	352
September 30, 2020	1		245		55		1		46		—		53		—		401

___________

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


Three months ended	Retail		Texas		East		West		Sunset		Asset Closure		Corporate and Other		Eliminations (1)		Consolidated
September 30, 2021	$	(383)	$	(697)	$	(303)	$	(46)	$	(549)	$	—	$	—	$	1,117	$	(861)
September 30, 2020	(8)		79		23		5		(133)		—		—		321		$	287
Nine Months ended	Retail		Texas		East		West		Sunset		Asset Closure		Corporate and Other		Eliminations (1)		Consolidated
September 30, 2021	$	(406)	$	(2,354)	$	(486)	$	(135)	$	(1,009)	$	—	$	—	$	3,244	$	(1,146)
September 30, 2020	(12)		462		9		4		(172)		—		—		127		$	418

____________

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

(b)See Note 1 for information related to an immaterial out-of-period adjustment to correct depreciation expense and accumulated depreciation related to prior periods. Substantially all of the understated depreciation expense for the years ended December 31, 2018, 2019 and 2020 relates to the Texas segment, and the overstated depreciation expense for the six month period ended June 30, 2021 relates entirely to the East segment.

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(c)Income tax expense is not reflected in net income of the segments but is reflected entirely in Corporate and Other net income.

17.SUPPLEMENTARY FINANCIAL INFORMATION

Impairment of Long-Lived Assets

In the second quarter of 2021, we recognized an impairment loss of $38 million related to our Zimmer generation Facility in Ohio as a result of a significant decrease in the estimated useful life of the facilities, reflecting a decrease in the economic forecast of the facility and the inability to secure capacity revenues for the plant in the latest PJM capacity auction held in May 2021. The impairments are reported in our Sunset segment and include a $33 million write-down of property, plant and equipment and a $5 million write-down of inventory.

In the third quarter of 2020, we recognized impairment losses of $173 million related to our Kincaid coal generation facility in Illinois and $99 million related to our Zimmer coal generation facility in Ohio, each as a result of a significant decrease in the estimated useful life of the facility, reflecting our recently announced plan to retire both facilities by the end of 2027 in response to the final CCR rule (see Notes 3 and 11). The impairment losses are reported in our Sunset segment and include a $260 million write-down of property, plant and equipment and a $12 million write-down of inventory.

In the first quarter of 2020, we recognized an impairment loss of $52 million related to our Joppa/EEI coal generation facility in Illinois as a result of a significant decrease in the estimated useful life of the facility, reflecting a decrease in the economic forecast of the facility and changes to the operating assumption based on lower forecasted wholesale electricity prices. We also recorded a $32 million impairment to a capacity contract which was linked in part to the Joppa/EEI facility and therefore determined to have a significant decrease in estimated useful life. The impairments are reported in our Sunset segment and include a $45 million write-down of property, plant and equipment, a $32 million write-down of intangible assets and a $7 million write-down of inventory.

In determining the fair value of the impaired assets, we equally weighted a market approach based on transactions of similar assets and an income approach discounting our projected cash flows through the respective plant retirement dates.

Interest Expense and Related Charges


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Interest paid/accrued	$	124	$	113	$	354	$	362
Unrealized mark-to-market net (gains) losses on interest rate swaps	(13)		(11)		(92)		181
Amortization of debt issuance costs, discounts and premiums	9		5		23		12
Debt extinguishment (gain) loss	—		(6)		1		(17)
Capitalized interest	(4)		(5)		(22)		(14)
Other	8		5		24		17
Total interest expense and related charges	$	124	$	101	$	288	$	541

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 10, was 3.89% and 3.88% at September 30, 2021 and 2020.

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Other Income and Deductions


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Other income:


Insurance settlement (a)	$	9	$	1	$	74	$	6

Gain on settlement of rail transportation disputes (b)	—		—		15		—
Sale of land (c)	1		6		2		6
Interest income	—		—		—		1
All other	6		1		17		6
Total other income	$	16	$	8	$	108	$	19
Other deductions:


Loss on disposal of investment in NELP (d)	$	—	$	—	$	—	$	29


All other	5		—		13		6
Total other deductions	$	5	$	—	$	13	$	35

____________

(a)For the three months ended September 30, 2021, $5 million reported in the Sunset segment and $4 million reported in the Texas segment. For the three months ended September 30, 2020, reported in the Texas segment. For the nine months ended September 30, 2021, $67 million reported in the Texas segment, $5 million reported in the Sunset segment and $2 million reported in the Corporate and Other non-segment. For the nine months ended September 30, 2020, $3 million reported in the Corporate and Other non-segment and $3 million reported in the Texas segment.

(b)Reported in the Asset Closure segment.

(c)For the three and nine months ended September 30, 2021, reported in the Asset Closure segment. For the three and nine months ended September 30, 2020, reported in the Texas segment.

(d)Reported in the East segment.

Restricted Cash


	September 30, 2021				December 31, 2020
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets

Amounts related to remediation escrow accounts	$	22	$	14	$	19	$	19






Total restricted cash	$	22	$	14	$	19	$	19

Trade Accounts Receivable


	September 30, 2021		December 31, 2020
Wholesale and retail trade accounts receivable	$	1,588	$	1,324
Allowance for uncollectible accounts	(59)		(45)
Trade accounts receivable — net	$	1,529	$	1,279

Gross trade accounts receivable at September 30, 2021 and December 31, 2020 included unbilled retail revenues of $460 million and $468 million, respectively.

Allowance for Uncollectible Accounts Receivable


	Nine Months Ended September 30,
	2021		2020
Allowance for uncollectible accounts receivable at beginning of period	$	45	$	42
Increase for bad debt expense	86		85
Decrease for account write-offs	(72)		(69)

Allowance for uncollectible accounts receivable at end of period	$	59	$	58

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Inventories by Major Category


	September 30, 2021		December 31, 2020
Materials and supplies	$	260	$	260
Fuel stock	173		236
Natural gas in storage	38		19
Total inventories	$	471	$	515

Investments


	September 30, 2021		December 31, 2020
Nuclear plant decommissioning trust	$	1,827	$	1,674
Assets related to employee benefit plans	41		41
Land	44		44
Miscellaneous other	3		—
Total investments	$	1,915	$	1,759

Nuclear Decommissioning Trust

Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor Electric Delivery Company LLC's (Oncor) customers as a delivery fee surcharge over the life of the plant and deposited by Vistra (and prior to the Effective Date, a subsidiary of TCEH) in the trust fund. Income and expense, including gains and losses associated with the trust fund assets and the decommissioning liability are offset by a corresponding change in a regulatory asset/liability (currently a regulatory liability reported in other noncurrent liabilities and deferred credits) that will ultimately be settled through changes in Oncor's delivery fees rates. If funds recovered from Oncor's customers held in the trust fund are determined to be inadequate to decommission the Comanche Peak nuclear generation plant, Oncor would be required to collect all additional amounts from its customers, with no obligation from Vistra, provided that Vistra complied with PUCT rules and regulations regarding decommissioning trusts. A summary of the fair market value of investments in the fund follows:


	September 30, 2021		December 31, 2020
Debt securities (a)	$	654	$	618
Equity securities (b)	1,173		1,056
Total	$	1,827	$	1,674

____________

(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 2.60% and 2.91% at September 30, 2021 and December 31, 2020, respectively, and an average maturity of nine years and ten years at September 30, 2021 and December 31, 2020, respectively.

(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 September 30, 2021 mature as follows: $246 million in one to five years, $194 million in five to 10 years and $214 million after 10 years.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Proceeds from sales of securities	$	99	$	67	$	366	$	291
Investments in securities	$	(105)	$	(73)	$	(382)	$	(307)

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Property, Plant and Equipment


	September 30, 2021		December 31, 2020
Power generation and structures	$	16,079	$	15,222
Land	615		617
Office and other equipment	177		173
Total	16,871		16,012
Less accumulated depreciation	(4,556)		(3,614)
Net of accumulated depreciation	12,315		12,398
Finance lease right-of-use assets (net of accumulated depreciation)	175		182
Nuclear fuel (net of accumulated amortization of $153 million and $91 million)	191		207
Construction work in progress	419		712
Property, plant and equipment — net	$	13,100	$	13,499

Depreciation expenses totaled $398 million and $328 million for the three months ended September 30, 2021 and 2020, respectively, and $1.147 billion and $1.012 billion for nine months ended September 30, 2021 and 2020, respectively. See Note 1 for information related to an out-of-period adjustment due to an immaterial correction of prior periods.

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. We have also identified conditional AROs for asbestos removal and disposal, which are specific to certain generation assets. As of September 30, 2021 and December 31, 2020, removal liabilities totaled $6 million and zero, respectively.

At September 30, 2021, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.623 billion, which is lower than the fair value of the assets contained in the nuclear decommissioning trust. Since the costs to ultimately decommission that plant are recoverable through the regulatory rate making process as part of Oncor's delivery fees, a corresponding regulatory liability has been recorded to our condensed consolidated balance sheet of $204 million in other noncurrent liabilities and deferred credits.

The following table summarizes the changes to these obligations, reported as AROs (current and noncurrent liabilities) in our condensed consolidated balance sheets, for the nine months ended September 30, 2021 and 2020.


	Nine Months Ended September 30, 2021								Nine Months Ended September 30, 2020
	Nuclear Plant Decom- missioning		Mining Land Reclamation		Coal Ash and Other		Total		Nuclear Plant Decom- missioning		Mining Land Reclamation		Coal Ash and Other		Total
Liability at beginning of period	$	1,585	$	359	$	492	$	2,436	$	1,320	$	410	$	508	$	2,238
Additions:
Accretion	38		12		15		65		34		15		18		67
Adjustment for change in estimates	—		(16)		10		(6)		219		(10)		36		245


Reductions:
Payments	—		(48)		(11)		(59)		—		(48)		(34)		(82)


Liability at end of period	1,623		307		506		2,436		1,573		367		528		2,468
Less amounts due currently	—		(88)		(22)		(110)		—		(98)		(17)		(115)
Noncurrent liability at end of period	$	1,623	$	219	$	484	$	2,326	1,573		269		511		2,353

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Other Noncurrent Liabilities and Deferred Credits

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


	September 30, 2021		December 31, 2020
Retirement and other employee benefits	$	296	$	312
Winter Storm Uri impact (a)	670		—
Identifiable intangible liabilities (Note 5)	150		289
Regulatory liability	204		89
Finance lease liabilities	234		206
Uncertain tax positions, including accrued interest	13		12
Liability for third-party remediation	21		31

Accrued severance costs	40		54
Other accrued expenses	186		138
Total other noncurrent liabilities and deferred credits	$	1,814	$	1,131

____________

(a)Includes the allocation of ERCOT default uplift charges, accrual of Koch earn-out disputed amounts (see Note 11) and future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri.

Fair Value of Debt


		September 30, 2021				December 31, 2020
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	$	2,556	$	2,531	$	2,579	$	2,565
Vistra Operations Senior Notes	Level 2	7,877		8,241		6,634		7,204

Forward Capacity Agreements	Level 3	338		338		45		45
Equipment Financing Agreements	Level 3	97		97		59		59
Building Financing	Level 2	4		4		10		10
Other debt	Level 3	3		3		3		3

We determine fair value in accordance with accounting standards as discussed in Note 13. 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 September 30, 2021 and December 31, 2020:


	September 30, 2021		December 31, 2020
Cash and cash equivalents	$	351	$	406
Restricted cash included in current assets	22		19
Restricted cash included in noncurrent assets	14		19
Total cash, cash equivalents and restricted cash	$	387	$	444

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The following table summarizes our supplemental cash flow information for the nine months ended September 30, 2021 and 2020:


	Nine Months Ended September 30,
	2021		2020
Cash payments related to:
Interest paid	$	425	$	468
Capitalized interest	(22)		(14)
Interest paid (net of capitalized interest)	$	403	$	454
Income taxes paid (refunds received) (a)	$	44	$	(11)

Noncash investing and financing activities:

Disposition of investment in NELP	$	—	$	123
Acquisition of investment in NJEA	$	—	$	90

____________

(a)For the nine months ended September 30, 2021 and 2020, we paid state income taxes of $46 million and $32 million, respectively, received federal tax refunds of zero and $37 million, respectively, and received state tax refunds of $2 million and $6 million, respectively.

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

The discussion below, as well as other portions of this quarterly report on Form 10-Q, contain forward-looking statements within the meaning of Section 27A of the Securities Act, Section 21E of the Exchange Act and the Private Securities Litigation Reform Act of 1995. In addition, management may make forward-looking statements orally or in other writing, including, but not limited to, in press releases, quarterly earnings calls, executive presentations, in the annual report to stockholders and in other filings with the SEC. Readers can usually identify these forward-looking statements by the use of such words as “may,” “will,” “should,” “likely,” “plans,” “projects,” “expects,” “anticipates,” “believes” or similar words. These statements involve a number of risks and uncertainties. Actual results could materially differ from those anticipated by such forward-looking statements. For more discussion about risk factors that could cause or contribute to such differences, see Part II, Item 7 "Management’s Discussion and Analysis of Financial Condition and Results of Operations" and Part I, Item 1A "Risk Factors" in the Company’s 2020 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 consolidated financial statements included under Part I, Item 1 of this quarterly report on Form 10-Q for the three and nine months ended September 30, 2021. This discussion should be read in conjunction with those 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 nine months ended September 30, 2021 and 2020 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 consolidated financial statements. The preparation of these 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 consolidated financial statements may be material. The Company's critical accounting policies are disclosed in our 2020 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 16 to the Financial Statements for further information concerning the updates to our reportable business segments.

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Significant Activities and Events and Items Influencing Future Performance

Winter Storm Uri

In February 2021, the U.S. experienced an unprecedented Winter Storm Uri, bringing extreme cold temperatures to the central U.S., including Texas. On February 12, 2021, the Governor of Texas declared a state of disaster for all 254 counties in the State in response to the then-forecasted weather conditions. The declaration certified that severe winter weather posed an imminent threat due to prolonged freezing temperatures, heavy snow, and freezing rain statewide. On February 14, 2021, President Biden issued a federal emergency declaration for all 254 Texas counties.

As part of its annual winter season preparations, our power plant teams executed a significant winter preparedness strategy, which included installing windbreaks and large radiant heaters to supplement existing freeze protection and insulation and performing preventative maintenance on freeze protection equipment such as the insulation and automatic circuitry designed to keep pipes at the power plants from freezing. In addition, in anticipation of Winter Storm Uri we took additional steps to prepare, including procuring additional demineralized water supply trailers to ensure sufficient water availability to run for extended periods and verifying that freeze protection circuits were operational.

This severe weather resulted in surging demand for power, gas supply shortages, operational challenges for generators, and a significant load shed event (i.e., involuntary outages to customers across the system for varying periods of time) that was ordered by ERCOT beginning on February 15, 2021 and continuing through February 18, 2021. Despite these challenges, we estimate that our fleet generated approximately 25 to 30% of the power on the grid during the height of the outages, as compared to our approximately 18% market share.

The weather event resulted in a $2.9 billion negative impact on the Company's pre-tax earnings in the nine months ended September 30, 2021 (see 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.

The final amount of the storm impact is subject to legislative actions that may be taken, such as legislation passed in the Texas Legislature's 87th Session. Securitization bills SB 1580 and HB 1520 may impact the total amount of balances owed by electric cooperatives to the market. The PUCT is required to issue financing orders related to those bills that authorizes financing associated with this legislation to defaulting market participants. The potential impact of this legislation is subject to uncertainty as the final details associated with the securitization bills will be determined through the potential approval of the financing orders.

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In addition, the final amount of the storm impact continues to be subject to the outcome of potential litigation arising from this event (including any litigation that we may pursue or be a party to); or any corrective action taken by the State of Texas, ERCOT, the RCT, or the PUCT to resettle pricing across any portion of the supply chain that is currently being considered or may be considered by any such parties. There have already been several announced efforts by the state and federal governments and regulatory agencies to investigate and determine the causes of this event and its impact on consumers. We have received a civil investigative demand from the Attorney General of Texas as well as requests for information from ERCOT related to this event and may receive additional inquiries. We are cooperating with these entities and are working to respond to these requests. Those efforts may result in changes in regulations that impact our industry including but not limited to additional requirements for winterization of various facets of the electricity supply chain including generation, transmission, and fuel supply; improvements in coordination among the various participants in the electricity and natural gas supply chains during any future event; potential revisions to the way in which the ERCOT market compensates and incentivizes the continued operation of assets that only run during times of scarcity; and potential changes to the types of plans permitted to be marketed to residential customers. We are continuing to monitor this situation as it develops. The full impact of litigation or any legislative or regulatory changes or actions (including enforcement actions that may be brought against various market participants) that may occur as a result of the event could have a material impact on our business, financial condition, results of operations, or cash flows, but cannot be estimated at this time. See Note 11 to the Financial Statements for further discussion of these matters.

The fundamentals of the Company remain strong. As described under Available Liquidity, the Company has total available liquidity of $2.071 billion as of September 30, 2021, consisting of cash on hand and available capacity under our Revolving Credit Facility. In addition, the maturities of our long-term debt are relatively modest until 2023. If the Company experienced a significant reduction in revenues or increases in costs or collateral requirements, such as a result of Winter Storm Uri, the Company believes it would have 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.

In response to the storm, Vistra committed to donate $5 million to assist Texas communities and individuals meet their most pressing needs, including support for food banks and food pantries, critical needs, bill payment assistance, and more. Vistra also assured residential customers across its retail brands that they will not see any near-term impact on their rates due to the winter weather event, though bills may increase due to high usage during the cold weather period in February.

In response to the storm, Vistra has taken or intends to take 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.

Investments in Clean Energy and CO2 Reductions

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, we announced the planned development, at a cost of approximately $850 million, of up to 668 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas. We will only invest in these growth projects if we are confident in the expected returns. See Note 2 to the Financial Statements for a summary of our solar and battery energy storage projects.

In September 2020 and December 2020, we announced our intention to retire (a) all of our remaining coal generation facilities in Illinois and Ohio, (b) one coal generation facility in Texas and (c) two natural gas facilities in Illinois and Texas 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 to the Financial Statements), and in furtherance of our efforts to significantly reduce our carbon footprint. In April 2021, we announced we would retire the Joppa generation facilities by September 1, 2022, and in July 2021, we announced we would retire the Zimmer coal generation facility by May 31, 2022. See Note 3 to the Financial Statements for a summary of these planned generation retirements.

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Moss Landing Phase I Outage

On September 4, 2021, Moss Landing Phase I experienced an incident impacting a portion of the battery ESS. An initial review has found that only a small, single digit-percentage of batteries at the facility were impacted. The facility will be offline as the company continues to safely advance its root cause analysis and perform the work necessary to return the facility to service. We do not currently have an estimated return to service date for the facility. Moss Landing Phase II was not affected and remains operational. We do not expect the incident to have a material impact on our results of operations.

Mining Reclamation Award

On October 14, 2021, the Office of Surface Mining Reclamation and Enforcement (OSM) announced Luminant as a recipient of its 2021 Excellence in Surface Coal Mining Reclamation Award for the work done to reclaim and restore previously mined land at its Monticello-Winfield Mine. The award recognizes companies that achieve the most exemplary coal mine reclamation in the nation. Luminant has a long history of environmental stewardship, reclaiming land long before being required under federal or state law.

COVID-19 Pandemic

With the global outbreak of the novel coronavirus (COVID-19) and the declaration of a pandemic by the World Health Organization on March 11, 2020, the U.S. government has deemed electricity generation, transmission and distribution as "critical infrastructure" providing essential services during this global emergency. As a provider of critical infrastructure, Vistra has an obligation to provide critically needed power to homes, businesses, hospitals and other customers. Vistra remains focused on protecting the health and well-being of its employees and the communities in which it operates while assuring the continuity of its business operations.

We have updated and implemented our company-wide pandemic plan to address specific aspects of the COVID-19 pandemic to guide our emergency response, business continuity, and the precautionary measures we are taking on behalf of employees and the public. We will continue to monitor developments affecting both our workforce and our customers, and we have taken, and will continue to take, health and safety measures that we determine are necessary in order to mitigate the impacts. To date, as a result of these business continuity measures, the Company has not experienced material disruptions in our operations due to COVID-19.

See Note 6 to the Financial Statements for a summary of certain tax-related impacts of the CARES Act to the Company.

The COVID-19 pandemic has presented potential new risks to the Company's business. Although there have been logistical and other challenges to date, there has been no material adverse impact on the Company's nine months ended September 30, 2021 results of operations. The situation surrounding COVID-19 remains fluid and the potential for a material impact on the Company's results of operations, financial condition and liquidity increases the longer the virus impacts the level of economic activity in the U.S. and globally. As a result, COVID-19 may have a range of impacts on the Company's operations, the full extent and scope of which are currently unknown. See Part I, Item 1A Risk Factors — The outbreak of COVID-19, or the future outbreak of any other highly infectious or contagious diseases, could have a material and adverse effect on our business, financial condition, and results of operations in our 2020 Form 10-K.

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

Series A Preferred Stock Offering

On October 15, 2021, we issued of 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). See Note 12 to the Financial Statements for more information concerning the Series A 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 on October 11, 2012. The Share Repurchase Program supersedes the $1.5 billion share repurchase program previously announced in September 2020 (Prior Share Repurchase Program). We intend to use the net proceeds from the Preferred Stock Offering to repurchase shares of our outstanding common stock. We expect to complete repurchases under the Share Repurchase Program by the end of 2022. See Note 12 to the Financial Statements for more information concerning the Share Repurchase Program and the Prior Share Repurchase Program, including shares repurchased.

Debt Activity

We have stated 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 the financial impacts resulting from Winter Storm Uri 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 long-term debt activity and Note 9 to the Financial Statements for details of our accounts receivable financing.

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 September 30, 2021 were as follows:


	2021		2022
Nuclear/Renewable/Coal Generation:
Texas	97	%	85	%
Sunset	100	%	93	%
Gas Generation:
Texas	89	%	53	%
East	98	%	89	%
West	100	%	92	%

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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 September 30, 2021.


	Balance 2021		2022
Texas:
Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price	$	1	$	18
Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price	$	(1)	$	(18)
Gas Generation: $1.00/MWh increase in spark spread	$	1	$	20
Gas Generation: $1.00/MWh decrease in spark spread	$	(1)	$	(18)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	1	$	(22)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	(1)	$	15
East:
Gas Generation: $1.00/MWh increase in spark spread	$	—	$	6
Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	(4)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	—	$	(3)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	—	$	3
West:
Gas Generation: $1.00/MWh increase in spark spread	$	—	$	1
Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	—


Sunset:
Coal Generation: $2.50/MWh increase in power price	$	—	$	7
Coal Generation: $2.50/MWh decrease in power price	$	—	$	(5)

PJM Auction Results

In June 2021, Vistra reported its results from PJM's Reliability Pricing Model (RPM) auction results for planning year 2022-2023, 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	$	50.00	2,967	—	2,967
ComEd zone	$	68.96	1,255	649	1,904
DEOK zone	$	71.69	99	870	969
MAAC zone	$	95.79	548	—	548
EMAAC zone	$	97.86	831	—	831
ATSI zone	$	50.00	—	—	—
Total	$	66.90	5,700	1,519	7,219

Our capacity sales in PJM, net of purchases, for planning year 2022-2023, are as follows:


	East Segment		Sunset Segment		Total
Total capacity sold, net (MW)	5,700		1,519		7,219


Average price per MW-day	$	68.54	$	70.52	$	68.95

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RESULTS OF OPERATIONS

Consolidated Financial Results — Three and Nine Months Ended September 30, 2021 Compared to Three and Nine Months Ended September 30, 2020


	Three Months Ended September 30,				Favorable (Unfavorable) $ Change		Nine Months Ended September 30,				Favorable (Unfavorable) $ Change
	2021		2020				2021		2020
Operating revenues	$	2,991	$	3,552	$	(561)	$	8,763	$	8,919	$	(156)
Fuel, purchased power costs and delivery fees	(1,763)		(1,469)		(294)		(7,827)		(3,832)		(3,995)
Operating costs	(372)		(457)		85		(1,173)		(1,249)		76
Depreciation and amortization	(468)		(410)		(58)		(1,355)		(1,284)		(71)
Selling, general and administrative expenses	(269)		(268)		(1)		(771)		(755)		(16)

Impairment of long-lived assets	—		(272)		272		(38)		(356)		318
Operating income (loss)	119		676		(557)		(2,401)		1,443		(3,844)
Other income	16		8		8		108		19		89
Other deductions	(5)		—		(5)		(13)		(35)		22
Interest expense and related charges	(124)		(101)		(23)		(288)		(541)		253
Impacts of Tax Receivable Agreement	35		58		(23)		31		44		(13)
Equity in earnings of unconsolidated investment	—		—		—		—		4		(4)
Income (loss) before income taxes	41		641		(600)		(2,563)		934		(3,497)
Income tax (expense) benefit	(31)		(199)		168		569		(283)		852
Net income (loss)	$	10	$	442	$	(432)	$	(1,994)	$	651	$	(2,645)


	Three Months Ended September 30, 2021
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	2,160	$	843	$	508	$	90	$	(122)	$	—	$	(488)	$	2,991
Fuel, purchased power costs and delivery fees	(1,095)		(482)		(496)		(78)		(100)		—		488		(1,763)
Operating costs	(38)		(163)		(57)		(9)		(104)		(1)		—		(372)
Depreciation and amortization	(53)		(179)		(164)		(15)		(40)		—		(17)		(468)
Selling, general and administrative expenses	(192)		(23)		(19)		(7)		(14)		(5)		(9)		(269)


Operating income (loss)	782		(4)		(228)		(19)		(380)		(6)		(26)		119
Other income	1		7		—		—		7		1		—		16
Other deductions	—		(2)		—		—		(1)		—		(2)		(5)
Interest expense and related charges	(2)		3		(5)		1		(1)		(1)		(119)		(124)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		35		35

Income (loss) before income taxes	781		4		(233)		(18)		(375)		(6)		(112)		41
Income tax expense	(2)		—		—		—		—		—		(29)		(31)
Net income (loss)	$	779	$	4	$	(233)	$	(18)	$	(375)	$	(6)	$	(141)	$	10

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	Three Months Ended September 30, 2020
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	2,521	$	1,541	$	644	$	84	$	299	$	1	$	(1,538)	$	3,552
Fuel, purchased power costs and delivery fees	(2,119)		(328)		(295)		(38)		(227)		—		1,538		(1,469)
Operating costs	(35)		(180)		(54)		(8)		(133)		(47)		—		(457)
Depreciation and amortization	(67)		(107)		(181)		(5)		(22)		(11)		(17)		(410)
Selling, general and administrative expenses	(190)		(18)		(12)		(8)		(15)		(8)		(17)		(268)

Impairment of long-lived assets	—		—		—		—		(272)		—		—		(272)
Operating income (loss)	110		908		102		25		(370)		(65)		(34)		676
Other income	1		1		—		1		—		5		—		8
Other deductions	—		(3)		—		—		3		—		—		—
Interest expense and related charges	(2)		2		(2)		3		(1)		—		(101)		(101)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		58		58

Income (loss) before income taxes	109		908		100		29		(368)		(60)		(77)		641
Income tax expense	—		—		—		—		—		—		(199)		(199)
Net income (loss)	$	109	$	908	$	100	$	29	$	(368)	$	(60)	$	(276)	$	442

In the three months ended September 30, 2021, our operating segments delivered strong operating performance with a disciplined focus on cost management while generating and selling essential electricity in a safe and reliable manner during a period of mild weather. 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, to produce results in line with management's expectations.

Consolidated results decreased $557 million to operating income of $119 million in the three months ended September 30, 2021 compared to the three months ended September 30, 2020. The change in results is driven by $589 million in pre-tax unrealized losses on commodity hedging transactions in 2021 compared to $321 million in pre-tax unrealized gains on commodity heading transactions in 2020, partially offset by a $272 million impairment of long-lived assets related to our Kincaid and Zimmer generation facilities in 2020 (see Note 17 to the Financial Statements). Power, natural gas and coal forward market curves moved up during the three months ended September 30, 2021, driving these net pre-tax unrealized losses on commodity hedging transactions.

Depreciation expense for the three months ended September 30, 2021 includes a $45 million immaterial out-of-period adjustment to correct for the net understatement of depreciation expense related to prior periods. See Note 1 to the Financial Statements.

Interest expense and related charges increased $23 million to $124 million in the three months ended September 30, 2021 compared to the three months ended September 30, 2020 driven by $11 million higher interest paid/accrued and a $6 million debt extinguishment gain in 2020. See Note 17 to the Financial Statements.

For the three months ended September 30, 2021 and 2020, the Impacts of the Tax Receivable Agreement totaled income of $35 million and $58 million, respectively. See Note 7 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement Obligation.

For the three months ended September 30, 2021, income tax expense totaled $31 million and the effective tax rate was 75.6%. For the three months ended September 30, 2020, income tax expense totaled $199 million and the effective tax rate was 31.0%. See Note 6 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

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	Nine Months Ended September 30, 2021
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	5,829	$	1,458	$	1,738	$	171	$	109	$	—	$	(542)	$	8,763
Fuel, purchased power costs and delivery fees	(2,345)		(4,133)		(1,269)		(164)		(458)		—		542		(7,827)
Operating costs	(96)		(527)		(181)		(26)		(323)		(19)		(1)		(1,173)
Depreciation and amortization	(160)		(462)		(553)		(30)		(99)		—		(51)		(1,355)
Selling, general and administrative expenses	(539)		(62)		(56)		(22)		(42)		(20)		(30)		(771)

Impairment of long-lived assets	—		—		—		—		(38)		—		—		(38)
Operating income (loss)	2,689		(3,726)		(321)		(71)		(851)		(39)		(82)		(2,401)
Other income	1		72		—		—		11		20		4		108
Other deductions	(4)		(7)		—		—		—		—		(2)		(13)
Interest expense and related charges	(7)		10		(11)		9		(1)		(1)		(287)		(288)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		31		31

Income (loss) before income taxes	2,679		(3,651)		(332)		(62)		(841)		(20)		(336)		(2,563)
Income tax (expense) benefit	(2)		—		—		—		—		—		571		569
Net income (loss)	$	2,677	$	(3,651)	$	(332)	$	(62)	$	(841)	$	(20)	$	235	$	(1,994)

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	Nine Months Ended September 30, 2020
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	6,385	$	3,245	$	1,845	$	211	$	863	$	3	$	(3,633)	$	8,919
Fuel, purchased power costs and delivery fees	(5,133)		(805)		(897)		(115)		(515)		—		3,633		(3,832)
Operating costs	(94)		(560)		(192)		(22)		(314)		(66)		(1)		(1,249)
Depreciation and amortization	(229)		(340)		(540)		(14)		(101)		(12)		(48)		(1,284)
Selling, general and administrative expenses	(489)		(58)		(66)		(18)		(52)		(20)		(52)		(755)

Impairment of long-lived assets	—		—		—		—		(356)		—		—		(356)
Operating income (loss)	440		1,482		150		42		(475)		(95)		(101)		1,443
Other income	1		3		1		1		4		8		1		19
Other deductions	—		(7)		(30)		—		4		(2)		—		(35)
Interest expense and related charges	(8)		6		(6)		6		(2)		—		(537)		(541)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		44		44
Equity in earnings of unconsolidated investment	—		—		4		—		—		—		—		4
Income (loss) before income taxes	433		1,484		119		49		(469)		(89)		(593)		934
Income tax expense	—		—		—		—		—		—		(283)		(283)
Net income (loss)	$	433	$	1,484	$	119	$	49	$	(469)	$	(89)	$	(876)	$	651

Consolidated results decreased $3.844 billion to a net operating loss of $2.401 billion in the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020. The change in results is driven by the Winter Storm Uri impacts, including 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. Results were also adversely impacted by $771 million in pre-tax unrealized losses on commodity hedging transactions in 2021 compared to $444 million in pre-tax unrealized gains on commodity hedging transactions in 2020. Power, natural gas and coal forward market curves moved up during the nine months ended September 30, 2021, driving these net pre-tax unrealized losses on commodity hedging transactions.

Depreciation expense for the nine months ended September 30, 2021 includes an immaterial out-of-period adjustment to correct for the net understatement of depreciation expense related to prior periods. See Note 1 to the Financial Statements.

Interest expense and related charges decreased $253 million to $288 million in the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020 driven by $92 million in unrealized mark-to-market gains on interest rate swaps in 2021 compared to $181 million in unrealized mark-to-market losses on interest rate swaps in 2020. See Note 17 to the Financial Statements.

For the nine months ended September 30, 2021 and 2020, the Impacts of the Tax Receivable Agreement totaled income of $31 million and $44 million, respectively. See Note 7 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement Obligation.

For the nine months ended September 30, 2021, income tax benefit totaled $569 million and the effective tax rate was 22.2%. For the nine months ended September 30, 2020, income tax expense totaled $283 million and the effective tax rate was 30.3%. See Note 6 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

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Discussion of Adjusted EBITDA

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

EBITDA and Adjusted EBITDA — We believe EBITDA and Adjusted EBITDA provide meaningful representations of our operating performance. We consider EBITDA as another way to measure financial performance on an ongoing basis. Adjusted EBITDA is meant to reflect the operating performance of our segments for the period presented. We define EBITDA as earnings (loss) before interest expense, income tax expense (benefit) and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA adjusted to exclude (i) gains or losses on the sale or retirement of 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).

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Adjusted EBITDA — Three and Nine Months Ended September 30, 2021 Compared to Three and Nine Months Ended September 30, 2020


	Three Months Ended September 30,				Favorable (Unfavorable) $ Change		Nine Months Ended September 30,				Favorable (Unfavorable) $ Change
	2021		2020				2021		2020
Net income (loss)	$	10	$	442	$	(432)	$	(1,994)	$	651	$	(2,645)
Income tax expense (benefit)	31		199		(168)		(569)		283		(852)
Interest expense and related charges (a)	124		101		23		288		541		(253)
Depreciation and amortization (b)	489		431		58		1,416		1,341		75
EBITDA before Adjustments	654		1,173		(519)		(859)		2,816		(3,675)
Unrealized net (gain) loss resulting from hedging transactions	589		(321)		910		771		(444)		1,215
Generation plant retirement expenses	5		43		(38)		19		43		(24)
Fresh start/purchase accounting impacts	(17)		—		(17)		(96)		34		(130)
Impacts of Tax Receivable Agreement	(35)		(58)		23		(31)		(44)		13

Non-cash compensation expenses	11		16		(5)		40		46		(6)
Transition and merger expenses	(2)		(2)		—		(17)		17		(34)
Impairment of long-lived assets	2		272		(270)		40		356		(316)
Loss on disposal of investment in NELP	—		—		—		—		29		(29)
COVID-19-related expenses (c)	1		3		(2)		6		18		(12)
Winter Storm Uri impact (d)	(33)		—		(33)		866		—		866
Other, net	(2)		11		(13)		5		14		(9)
Adjusted EBITDA	$	1,173	$	1,137	$	36	$	744	$	2,885	$	(2,141)

____________

(a)Includes unrealized mark-to-market net gains on interest rate swaps of $13 million and $11 million for the three months ended September 30, 2021 and 2020, respectively, and unrealized mark-to-market net gains on interest rate swaps of $92 million and unrealized mark-to-market net losses on interest rate swaps of $181 million for the nine months ended September 30, 2021 and 2020, respectively.

(b)Includes nuclear fuel amortization in the Texas segment of $21 million and $20 million for the three months ended September 30, 2021 and 2020, respectively, and $61 million and $57 million for the nine months ended September 30, 2021 and 2020, respectively.

(c)Includes material and supplies and other incremental costs related to our COVID-19 response.

(d)For the nine months ended September 30, 2021, includes the following amounts, which we believe are not reflective of our operating performance: $194 million for allocation of ERCOT default uplift charges which are expected to be paid over more than 90 years under current protocols (net present value of $45 million applying a 4.25% discount rate); accrual of Koch earn-out disputed amounts of $286 million that the Company is contesting and does not believe should be paid; $386 million for future bill credits related to Winter Storm Uri as further described below 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 during Winter Storm Uri and will reverse and impact Adjusted EBITDA in future periods as the credits are applied to customer bills. We estimate the amounts to be applied in future periods are for the remainder of 2021 (approximately $43 million), 2022 (approximately $185 million), 2023 (approximately $84 million), 2024 (approximately $18 million) and 2025 (approximately $8 million). 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.

Consistent with the Company's hedging practices to provide a more predictable financial performance over time, Adjusted EBITDA totaled $1.173 billion and $1.137 billion for the three months ended September 30, 2021 and 2020, respectively, despite significant moves in commodity prices during the period.

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	Three Months Ended September 30, 2021
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	$	779	$	4	$	(233)	$	(18)	$	(375)	$	(6)	$	(141)	$	10
Income tax expense	2		—		—		—		—		—		29		31
Interest expense and related charges (a)	2		(3)		5		(1)		1		1		119		124
Depreciation and amortization (b)	53		200		164		15		40		—		17		489
EBITDA before Adjustments	836		201		(64)		(4)		(334)		(5)		24		654
Unrealized net (gain) loss resulting from hedging transactions	(739)		654		254		39		381		—		—		589
Generation plant retirement expenses	—		—		—		—		4		—		1		5
Fresh start/purchase accounting impacts	(2)		(2)		—		—		(13)		—		—		(17)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(35)		(35)

Non-cash compensation expenses	—		—		—		—		—		—		11		11
Transition and merger expenses	(4)		—		—		—		—		—		2		(2)
Impairment of long lived assets	—		2		—		—		—		—		—		2

COVID-19-related expenses (c)	—		1		—		—		—		—		—		1
Winter Storm Uri impacts (d)	(31)		(2)		—		—		—		—		—		(33)
Other, net	5		4		3		1		(2)		1		(14)		(2)
Adjusted EBITDA	$	65	$	858	$	193	$	36	$	36	$	(4)	$	(11)	$	1,173

____________

(a)Includes $13 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $21 million in Texas segment.

(c)Includes material and supplies and other incremental costs related to our COVID-19 response.

(d)Includes bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri as the credits are applied to customer bills and a small reduction in ERCOT default uplift charges, partially offset by ongoing Winter Storm Uri related legal fees and other costs.


	Three Months Ended September 30, 2020
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	$	109	$	908	$	100	$	29	$	(368)	$	(60)	$	(276)	$	442
Income tax expense	—		—								—		199		199
Interest expense and related charges (a)	2		(2)		2		(3)		1		—		101		101
Depreciation and amortization (b)	67		127		181		5		22		12		17		431
EBITDA before Adjustments	178		1,033		283		31		(345)		(48)		41		1,173
Unrealized net (gain) loss resulting from hedging transactions	(316)		(78)		(40)		(9)		122		—		—		(321)
Generation plant retirement expenses	—		—		—		—		43		—		—		43
Fresh start/purchase accounting impacts	(6)		—		6		—		—		—		—		—
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(58)		(58)

Non-cash compensation expenses	—		—		—		—		—		—		16		16
Transition and merger expenses	1		—		(5)		—		—		—		2		(2)
Impairment of long-lived assets	—		—		—		—		272		—		—		272

COVID-19-related expenses (c)	—		2		—		—		1		—		—		3
Other, net	3		15		1		1		—		2		(11)		11
Adjusted EBITDA	$	(140)	$	972	$	245	$	23	$	93	$	(46)	$	(10)	$	1,137

Table of Contents

____________

(a)Includes $11 million of unrealized mark-to-market net gains on interest rate swaps.

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

(c)Includes material and supplies and other incremental costs related to our COVID-19 response.


	Nine Months Ended September 30, 2021
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	$	2,677	$	(3,651)	$	(332)	$	(62)	$	(841)	$	(20)	$	235	$	(1,994)
Income tax expense (benefit)	2		—		—		—		—		—		(571)		(569)
Interest expense and related charges (a)	7		(10)		11		(9)		1		1		287		288
Depreciation and amortization (b)	160		523		553		30		99		—		51		1,416
EBITDA before Adjustments	2,846		(3,138)		232		(41)		(741)		(19)		2		(859)
Unrealized net (gain) loss resulting from hedging transactions	(2,840)		2,269		407		120		815		—		—		771
Generation plant retirement expenses	—		—		—		—		19		—		—		19
Fresh start/purchase accounting impacts	1		(3)		(74)		—		(20)		—		—		(96)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(31)		(31)

Non-cash compensation expenses	—		—		—		—		—		—		40		40
Transition and merger expenses	(2)		—		—		—		—		(15)		—		(17)
Impairment of long-lived assets	—		2		—		—		38		—		—		40

COVID-19-related expenses (c)	—		3		1		—		1		—		1		6
Winter Storm Uri impacts (d)	354		511		—		—		1		—		—		866
Other, net	17		6		7		2		2		2		(31)		5
Adjusted EBITDA	$	376	$	(350)	$	573	$	81	$	115	$	(32)	$	(19)	$	744

____________

(a)Includes $92 million of unrealized mark-to-market net gains on interest rate swaps.

(b)Includes nuclear fuel amortization of $61 million in Texas segment.

(c)Includes material and supplies and other incremental costs related to our COVID-19 response.

(d)Includes the following amounts, which we believe are not reflective of our operating performance: $194 million for allocation of ERCOT default uplift charges which are expected to be paid over more than 90 years under current protocols (net present value of $45 million applying a 4.25% discount rate); accrual of Koch earn-out disputed amounts of $286 million that the Company is contesting and does not believe should be paid; $386 million for future bill credits related to Winter Storm Uri as further described below 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 during Winter Storm Uri and will reverse and impact Adjusted EBITDA in future periods as the credits are applied to customer bills. We estimate the amounts to be applied in future periods are for the remainder of 2021 (approximately $43 million), 2022 (approximately $185 million), 2023 (approximately $84 million), 2024 (approximately $18 million) and 2025 (approximately $8 million). 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


	Nine Months Ended September 30, 2020
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	$	433	$	1,484	$	119	$	49	$	(469)	$	(89)	$	(876)	$	651
Income tax expense	—		—		—		—		—		—		283		283
Interest expense and related charges (a)	8		(6)		6		(6)		2		—		537		541
Depreciation and amortization (b)	229		397		540		14		101		12		48		1,341
EBITDA before Adjustments	670		1,875		665		57		(366)		(77)		(8)		2,816
Unrealized net (gain) loss resulting from hedging transactions	(114)		(449)		(37)		(1)		157		—		—		(444)
Generation plant retirement expenses	—		—		—		—		43		—		—		43
Fresh start/purchase accounting impacts	1		(4)		23		—		14		—		—		34
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(44)		(44)

Non-cash compensation expenses	—		—		—		—		—		—		46		46
Transition and merger expenses	8		1		1		—		—		(3)		10		17
Impairment of long-lived assets	—		—		—		—		356		—		—		356
Loss on disposal of investment in NELP	—		—		29		—		—		—		—		29
COVID-19-related expenses (c)	—		12		2		—		3		—		1		18

Other, net	7		17		8		3		2		2		(25)		14
Adjusted EBITDA	$	572	$	1,452	$	691	$	59	$	209	$	(78)	$	(20)	$	2,885

____________

(a)Includes $181 million of unrealized mark-to-market net losses on interest rate swaps.

(b)Includes nuclear fuel amortization of $57 million in Texas segment.

(c)Includes material and supplies and other incremental costs related to our COVID-19 response.

Retail Segment — Three and Nine Months Ended September 30, 2021 Compared to Three and Nine Months Ended September 30, 2020


	Three Months Ended September 30,				Favorable (Unfavorable) Change		Nine Months Ended September 30,				Favorable (Unfavorable) Change
	2021		2020				2021		2020
Operating revenues:
Revenues in ERCOT	$	1,917	$	1,839	$	78	$	4,521	$	4,536	$	(15)
Revenues in Northeast/Midwest	624		683		(59)		1,715		1,862		(147)
Amortization expense	2		7		(5)		(1)		(1)		—
Unrealized net losses on hedging activities (a)	(383)		(8)		(375)		(406)		(12)		(394)
Total operating revenues	2,160		2,521		(361)		5,829		6,385		(556)
Fuel, purchased power costs and delivery fees:
Purchases from affiliates	(1,607)		(1,859)		252		(3,784)		(3,761)		(23)
Unrealized net gains (losses) on hedging activities with affiliates	1,117		323		794		3,244		127		3,117
Unrealized net gains (losses) on hedging activities	5		1		4		2		(1)		3
Delivery fees	(595)		(570)		(25)		(1,472)		(1,446)		(26)
Other costs (b)	(15)		(14)		(1)		(335)		(52)		(283)
Total fuel, purchased power costs and delivery fees	(1,095)		(2,119)		1,024		(2,345)		(5,133)		2,788










Net income	$	779	$	109	$	670	$	2,677	$	433	$	2,244

Table of Contents


	Three Months Ended September 30,						Favorable (Unfavorable) Change		Nine Months Ended September 30,						Favorable (Unfavorable) Change
	2021			2020					2021			2020
Adjusted EBITDA	$	65		$	(140)		$	205	$	376		$	572		$	(196)

Retail sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT	17,732			16,573			1,159		44,215			41,547			2,668
Sales volumes in Northeast/Midwest	10,034			11,103			(1,069)		27,558			28,640			(1,082)
Total retail electricity sales volumes	27,766			27,676			90		71,773			70,187			1,586
Weather (North Texas average) - percent of normal (c):
Cooling degree days	91.2		%	89.0		%			86.9		%	91.0		%
Heating degree days	—		%	—		%			117.1		%	88.0		%

____________

(a)During both the three and nine months ended September 30, 2021, a net loss of $(357) million was recognized in operating revenues due to the discontinuance of normal purchase and sale accounting on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract term.

(b)For the nine months ended September 30, 2021, includes $162 million of future bill credits to large commercial and industrial customers.

(c)Weather data is obtained from Weatherbank, Inc. For the three and nine months ended September 30, 2021, normal is defined as the average over the 10-year period from September 2011 to September 2020. For the three and nine months ended September 30, 2020, normal is defined as the average over the 10-year period from September 2010 to September 2019.

Net income increased by $670 million to $779 million and Adjusted EBITDA increased by $205 million to $65 million in the three months ended September 30, 2021 compared to the three months ended September 30, 2020. Net income increased by $2.244 billion to $2.677 billion and Adjusted EBITDA decreased by $196 million to $376 million in the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020.


	Three Months Ended September 30, 2021 Compared to 2020		Nine Months Ended September 30, 2021 Compared to 2020
Monetization of certain commercial positions	$	30	$	145
Winter Storm Uri, including bill credits	13		(551)
Higher margins	167		246
Other driven by higher SG&A	(5)		(36)
Change in Adjusted EBITDA	$	205	$	(196)
Favorable impact of higher unrealized net gains on hedging activities	423		2,726
Future bill credits and other costs related to Winter Storm Uri	31		(354)
Decrease in depreciation and amortization expenses	14		69
Change in transition and merger and other expenses	(3)		(1)
Change in net income	$	670	$	2,244

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Generation — Three Months Ended September 30, 2021 Compared to Three Months Ended September 30, 2020


	Three Months Ended September 30,
	Texas						East						West						Sunset
	2021			2020			2021			2020			2021			2020			2021			2020
Operating revenues:
Electricity sales	$	462		$	155		$	411		$	210		$	134		$	78		$	265		$	280
Capacity revenue from ISO/RTO	—			—			(13)			(25)			1			—			51			40
Sales to affiliates	1,078			1,307			413			436			1			1			113			116
Rolloff of unrealized net gains (losses) representing positions settled in the current period	(17)			138			(56)			41			55			4			69			(41)
Unrealized net gains (losses) on hedging activities	(153)			129			225			67			(101)			1			(500)			(44)
Unrealized net (losses) on hedging activities with affiliates	(527)			(188)			(472)			(85)			—			—			(118)			(48)
Other revenues	—			—			—			—			—			—			(2)			(4)
Operating revenues	843			1,541			508			644			90			84			(122)			299
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs	(458)			(293)			(536)			(301)			(84)			(41)			(265)			(235)
Fuel for generation facilities and purchased power costs from affiliates	1			2			1			(4)			—			—			(1)			1
Unrealized gains (losses) from hedging activities	43			(1)			49			19			7			4			168			11
Unrealized net losses on hedging activities with affiliates	—			—			—			(2)			—			—			—			—
Ancillary and other costs	(68)			(36)			(10)			(7)			(1)			(1)			(2)			(4)
Fuel, purchased power costs and delivery fees	(482)			(328)			(496)			(295)			(78)			(38)			(100)			(227)










Net income (loss)	$	4		$	908		$	(233)		$	100		$	(18)		$	29		$	(375)		$	(368)













Adjusted EBITDA	$	858		$	972		$	193		$	245		$	36		$	23		$	36		$	93
Production volumes (GWh):
Natural gas facilities	9,597			10,722			14,760			16,248			1,635			1,347
Lignite and coal facilities	7,969			7,226															11,454			9,510
Nuclear facilities	5,254			5,270
Solar/Battery facilities	135			133									—
Capacity factors:
CCGT facilities	52.7		%	58.7		%	60.7		%	66.4		%	72.6		%	59.7		%
Lignite and coal facilities	93.7		%	85.0		%													71.2		%	59.2		%
Nuclear facilities	103.5		%	103.8		%
Weather - percent of normal (a):
Cooling degree days	92.4		%	96.0		%	101.3		%	108.0		%	94.5		%	114.0		%	109.6		%	102.0		%
Heating degree days	—		%	—		%	37.2		%	144.0		%	—		%	—		%	47.7		%	98.0		%

___________

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

Table of Contents


	Three Months Ended September 30,					Three Months Ended September 30,
	2021		2020			2021		2020
Market pricing					Average Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)	$	38.64	$	24.87	PJM West Hub	$	51.37	$	28.35
					AEP Dayton Hub	$	50.29	$	28.44
Average NYMEX Henry Hub natural gas price ($/MMBtu)	$	4.27	$	1.95	NYISO Zone C	$	43.95	$	23.09
					Massachusetts Hub	$	52.69	$	27.22
Average natural gas price (a):					Indiana Hub	$	51.59	$	29.84
TetcoM3 ($/MMBtu)	$	3.75	$	1.45	Northern Illinois Hub	$	48.19	$	25.80
Algonquin Citygates ($/MMBtu)	$	3.86	$	1.52

___________

(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 September 30, 2021 compared to the three months ended September 30, 2020.


	Three Months Ended September 30, 2021 Compared to 2020
	Texas		East		West		Sunset

Favorable/(unfavorable) change in revenue net of fuel	$	(144)	$	(44)	$	14	$	(49)
Winter Storm Uri impact	(3)		—		—		—
Favorable/(unfavorable) change in other operating costs	26		(6)		(1)		(11)
Favorable change in selling, general and administrative expenses	5		1		1		6
Other (a)	2		(3)		(1)		(3)
Change in Adjusted EBITDA	$	(114)	$	(52)	$	13	$	(57)
Favorable/(unfavorable) change in depreciation and amortization	(73)		17		(10)		(18)
Change in unrealized net losses on hedging activities	(732)		(294)		(48)		(259)
Impairment of long-lived assets	(2)		—		—		272
Generation plant retirement expenses	—		—		—		39
Fresh start/purchase accounting impacts	2		6		—		13
Transition and merger expenses	—		(5)		—		—
Winter Storm Uri impact (ERCOT default uplift and legal disputes)	2		—		—		—
Other (including interest and COVID-19 related expenses)	13		(5)		(2)		3
Change in Net income (loss)	$	(904)	$	(333)	$	(47)	$	(7)

___________

(a) For the three months ended September 30, 2021, includes insurance proceeds of $5 million in the Sunset segment and $4 million in the Texas segment.

The change in Texas segment results was driven by lower revenue net of fuel, unrealized hedging losses in current year versus unrealized hedging gains in prior year and higher depreciation expense.

The change in East segment results was driven by lower revenue net of fuel and unrealized hedging losses in current year versus unrealized hedging gains in prior year.

The change in West segment results was driven by unrealized hedging losses in current year versus unrealized hedging gains in prior year, partially offset by a favorable change in revenue net of fuel.

The change in Sunset segment results was driven by lower revenue net of fuel, higher operating costs and larger unrealized hedging losses in current year versus prior year.

Table of Contents

Generation — Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020


	Nine Months Ended September 30,
	Texas						East						West						Sunset
	2021			2020			2021			2020			2021			2020			2021			2020
Operating revenues:
Electricity sales	$	1,502		$	598		$	986		$	582		$	302		$	204		$	701		$	641
Capacity revenue from ISO/RTO	—			—			(14)			(34)			1			—			133			124
Sales to affiliates	2,310			2,185			1,178			1,287			3			3			294			286
Rolloff of unrealized net gains (losses) representing positions settled in the current period	(170)			74			(24)			138			44			(21)			15			(173)
Unrealized net gains (losses) on hedging activities	(31)			322			357			(10)			(179)			25			(752)			75
Unrealized net gains (losses) on hedging activities with affiliates	(2,153)			66			(819)			(119)			—			—			(272)			(74)
Other revenues	—			—			74			1			—			—			(10)			(16)
Operating revenues	1,458			3,245			1,738			1,845			171			211			109			863
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs	(2,439)			(695)			(1,321)			(888)			(176)			(110)			(644)			(527)
Fuel for generation facilities and purchased power costs from affiliates	(1)			5			—			(8)			—			—			(2)			2
Unrealized gains (losses) from hedging activities	85			(13)			79			28			15			(3)			194			15

Ancillary and other costs	(1,778)			(102)			(27)			(29)			(3)			(2)			(6)			(5)
Fuel, purchased power costs and delivery fees	(4,133)			(805)			(1,269)			(897)			(164)			(115)			(458)			(515)










Net income (loss)	$	(3,651)		$	1,484		$	(332)		$	119		$	(62)		$	49		$	(841)		$	(469)













Adjusted EBITDA	$	(350)		$	1,452		$	573		$	691		$	81		$	59		$	115		$	209
Production volumes (GWh):
Natural gas facilities	23,142			27,111			40,781			41,682			3,998			3,755
Lignite and coal facilities	19,441			18,717															28,582			20,696
Nuclear facilities	15,343			15,045
Solar/Battery facilities	357			341									3
Capacity factors:
CCGT facilities	43.1		%	50.7		%	56.7		%	57.8		%	59.8		%	56.1		%
Lignite and coal facilities	77.1		%	74.2		%													60.0		%	43.4		%
Nuclear facilities	101.8		%	99.8		%
Weather - percent of normal (a):
Cooling degree days	89.8		%	98.0		%	107.2		%	106.0		%	95.5		%	126.0		%	112.1		%	103.0		%
Heating degree days	122.9		%	81.0		%	95.3		%	93.0		%	108.2		%	91.0		%	94.4		%	89.0		%

____________

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

Table of Contents


	Nine Months Ended September 30,					Nine Months Ended September 30,
	2021		2020			2021		2020
Market pricing					Average Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)	$	186.71	$	20.25	PJM West Hub	$	39.95	$	23.91
					AEP Dayton Hub	$	40.15	$	24.06
Average NYMEX Henry Hub natural gas price ($/MMBtu)	$	3.52	$	1.82	NYISO Zone C	$	31.94	$	19.26
					Massachusetts Hub	$	46.96	$	24.06
Average natural gas price (a):					Indiana Hub	$	43.99	$	26.23
TetcoM3 ($/MMBtu)	$	3.11	$	1.55	Northern Illinois Hub	$	37.77	$	22.12
Algonquin Citygates ($/MMBtu)	$	3.93	$	1.75

___________

(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 nine months ended September 30, 2021 compared to the nine months ended September 30, 2020.


	Nine Months Ended September 30, 2021 Compared to 2020
	Texas		East		West		Sunset

Favorable/(unfavorable) change in revenue net of fuel	$	(362)	$	(160)	$	31	$	(88)
Winter Storm Uri impact	(1,551)		50		—		17
Favorable/(unfavorable) change in other operating costs	42		(9)		(5)		(33)
Change in selling, general and administrative expenses	68		5		(4)		17
Other (a)	1		(4)		—		(7)
Change in Adjusted EBITDA	$	(1,802)	$	(118)	$	22	$	(94)
Favorable/(unfavorable) change in depreciation and amortization	(126)		(13)		(16)		2
Change in unrealized net losses on hedging activities	(2,718)		(444)		(121)		(658)
Impairment of long-lived assets	(2)		—		—		318
Generation plant retirement expenses	—		—		—		24
Fresh start/purchase accounting impacts	(1)		97		—		34
Transition and merger expenses	1		1		—		—
Loss on disposal of investment in NELP	—		29		—		—
Winter Storm Uri impact (ERCOT default uplift and legal disputes)	(511)		—		—		(1)
Other (including interest and COVID-19 related expenses)	24		(3)		4		3
Change in Net income (loss)	$	(5,135)	$	(451)	$	(111)	$	(372)

___________

(a) For the nine months ended September 30, 2021, includes insurance proceeds of $67 million in the Texas segment and $5 million in the Sunset segment.

The change in Texas segment results was primarily driven by the Winter Storm Uri impacts, including 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, lower margins from our natural gas-fueled power plants due to extremely high fuel costs, and, to a lesser extent, operational challenges associated with Winter Storm Uri and unrealized hedging losses in current year versus unrealized hedging gains in prior year, partially offset by insurance proceeds received in 2021.

The change in East segment results was driven by lower revenue net of fuel, loss on disposal of equity method investment in NELP for 100% ownership of NJEA (see Note 17 to the Financial Statements) in 2020, and unrealized hedging losses in current year versus unrealized hedging gains in prior year.

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The change in West segment results was driven by unrealized hedging losses in current year versus unrealized gains in prior year, partially offset by a favorable change in revenue net of fuel.

The change in Sunset segment results was driven by larger unrealized hedging losses in current year versus prior year and lower margins due to lower realized prices and higher operating costs, partially offset by higher impairment of long-lived assets and generation plant retirement expenses related to our Joppa/EEI, Kincaid and Zimmer coal generation facilities in 2020.

Asset Closure Segment — Three and Nine Months Ended September 30, 2021 Compared to Three and Nine Months Ended September 30, 2020


	Three Months Ended September 30,				Favorable (Unfavorable) Change		Nine Months Ended September 30,				Favorable (Unfavorable) Change
	2021		2020				2021		2020
Operating revenues	$	—	$	1	$	(1)	$	—	$	3	$	(3)

Operating costs	(1)		(47)		46		$	(19)	$	(66)	$	47
Depreciation and amortization	—		(11)		11		—		(12)		12
Selling, general and administrative expenses	(5)		(8)		3		(20)		(20)		—


Operating loss	(6)		(65)		59		(39)		(95)		56
Other income	1		5		(4)		20		8		12
Other deductions	—		—		—		—		(2)		2
Interest expense and related charges	(1)		—		(1)		(1)		—		(1)

Loss before income taxes	(6)		(60)		54		(20)		(89)		69

Net loss	$	(6)	$	(60)	$	54	$	(20)	$	(89)	$	69







Adjusted EBITDA	$	(4)	$	(46)	$	42	$	(32)	$	(78)	$	46

Operating costs for the three and nine months ended September 30, 2021 and 2020 included ongoing costs associated with the decommissioning and reclamation of retired plants and mines. The nine months ended September 30, 2021 includes a gain on the settlement of rail transportation disputes (see Note 17 to the Financial Statements).

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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 nine months ended September 30, 2021 and 2020. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $771 million in unrealized net losses and $444 million in unrealized net gains for the nine months ended September 30, 2021 and 2020, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.


	Nine Months Ended September 30,
	2021		2020
Commodity contract net liability at beginning of period	$	(75)	$	(279)
Settlements/termination of positions (a)	(202)		74
Changes in fair value of positions in the portfolio (b)	(569)		370

Other activity (c)	(116)		7
Commodity contract net asset (liability) at end of period	$	(962)	$	172

____________

(a)Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). The nine months ended September 30, 2021 and 2020 include reversals of $1 million and $7 million, respectively, of previously recorded unrealized losses related to commodity contracts acquired in the Merger, Crius acquisition and Ambit acquisition. The nine months ended September 30, 2020 includes reversal of $1 million of previously recorded losses related to Vistra beginning balances. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.

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

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

Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair values at September 30, 2021, scheduled by the source of fair value and contractual settlement dates of the underlying positions.


	Maturity dates of unrealized commodity contract net liability at September 30, 2021
	Less than 1 year		1-3 years		4-5 years		Excess of 5 years		Total
Prices actively quoted	$	(554)	$	(85)	$	1	$	—	$	(638)
Prices provided by other external sources	(13)		(90)		5		(2)		(100)
Prices based on models	(57)		2		(80)		(89)		(224)
Total	$	(624)	$	(173)	$	(74)	$	(91)	$	(962)

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FINANCIAL CONDITION

Operating Cash Flows

Cash used in operating activities totaled $493 million for the nine months ended September 30, 2021 compared to cash provided by operating activities of $2.350 billion for the nine months ended September 30, 2020. The unfavorable change of $2.843 billion was primarily driven by lower cash from operations due to Winter Storm Uri impacts and higher cash margin deposits posted with third-parties.

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 $196 million and $228 million for the nine months ended September 30, 2021 and 2020, 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 $843 million and $927 million for the nine months ended September 30, 2021 and 2020, respectively. Capital expenditures totaled $790 million and $838 million for the nine months ended September 30, 2021 and 2020, respectively, and consisted of the following:


	Nine Months Ended September 30,
	2021		2020
Capital expenditures, including LTSA prepayments	$	437	$	439
Nuclear fuel purchases	$	30	$	69
Growth and development expenditures	$	323	$	330
Capital expenditures	$	790	$	838

Cash used in investing activities also reflected net purchases of environmental allowances of $145 million and $119 million for the nine months ended September 30, 2021 and 2020, respectively. In the nine months ended September 30, 2021 and 2020, we also received insurance proceeds of $74 million and $15 million, respectively.

Financing Cash Flows

Cash provided by financing activities totaled $1.279 billion in the nine months ended September 30, 2021 compared to cash used of $1.348 billion for the nine months ended September 30, 2020. The change was primarily driven by:

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

•redemption of $747 million principal amount of outstanding of Vistra unsecured senior notes in 2020;

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

•net borrowings of $175 million under the accounts receivable financing facilities in 2021;

•net repayment of $350 million in short-term borrowings under the Revolving Credit Facility in 2020;

•repayment of $100 million of term loans under the Vistra Operations Credit Facility in March 2020;

partially offset by $175 million in cash paid for share repurchases in 2021.

Debt Activity

See Note 9 to the Financial Statements for details of the Receivables Facility and Repurchase Facility and Note 10 to the Financial Statements for details of the Vistra Operations Credit Facilities and other long-term debt.

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Available Liquidity

The following table summarizes changes in available liquidity for the nine months ended September 30, 2021:


	September 30, 2021		December 31, 2020		Change
Cash and cash equivalents	$	351	$	406	$	(55)
Vistra Operations Credit Facilities — Revolving Credit Facility	1,720		1,988		(268)
Vistra Operations — Alternate Letter of Credit Facility	—		5		(5)
Total available liquidity (a)	$	2,071	$	2,399	$	(328)

____________

(a)Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See Note 9 to the Financial Statements for detail on our accounts receivable financing.

The $328 million decrease in available liquidity for the nine months ended September 30, 2021 was primarily driven by cash used in operations, including higher cash margin deposits posted with third parties, $790 million of capital expenditures (including LTSA prepayments, nuclear fuel and development and growth expenditures), $175 million in cash paid for share repurchases, $219 million in dividends paid to stockholders and a $268 million increase in letters of credit outstanding under the Revolving Credit Facility, partially offset by cash received from the issuance of $1.250 billion principal amount of Vistra Operations senior unsecured notes in May 2021, $500 million in cash received from the sale of a portion of the PJM capacity that cleared for Planning Years 2021-2022 and $175 million in net cash borrowings under the accounts receivable financing facilities.

If the Company experienced a significant reduction in revenues or increases in costs or collateral requirements, such as a result of Winter Storm Uri, the Company believes it would have 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.

Based upon our current internal financial forecasts, we believe that we will have 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.

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 10 to the Financial Statements for discussion of the Vistra Operations Credit Facilities.

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

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At September 30, 2021, we received or posted cash and letters of credit for commodity hedging and trading activities as follows:

•$1.048 billion in cash has been posted with counterparties as compared to $257 million posted at December 31, 2020;

•$57 million in cash has been received from counterparties as compared to $33 million received at December 31, 2020;

•$1.316 billion in letters of credit have been posted with counterparties as compared to $878 million posted at December 31, 2020; and

•$27 million in letters of credit have been received from counterparties as compared to $18 million received at December 31, 2020.

See Collateral Support Obligations below for information related to collateral posted in accordance with 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 loss position in 2021 and use of NOL carryforwards. We expect to make approximately $31 million in state income tax payments, offset by $9 million in state tax refunds, and $2 million in TRA payments in the next 12 months.

For the nine months ended September 30, 2021, there were no federal income tax payments, $46 million in state income tax payments, $2 million in state income tax refunds and no TRA payments.

Financial Covenants

The Credit Facilities Agreement includes a covenant, 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), that requires the consolidated first-lien net leverage ratio not exceed 4.25 to 1.00. Although the period ended September 30, 2021 was not a compliance period, we would have been in compliance with this financial covenant if it was required to be tested at such date.

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

Collateral Support Obligations

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

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, at September 30, 2021, Vistra has posted letters of credit in the amount of $74 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 $384 million in the form of letters of credit, $20 million in the form of a surety bond and $1 million of cash at September 30, 2021 (which is subject to daily adjustments based on settlement activity with the ISOs/RTOs).

Material Cross Default/Acceleration Provisions

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

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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 $2.550 billion at September 30, 2021.

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 Alternate LOC Facilities, 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 Alternate 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 Alternate LOC Facilities.

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.

Guarantees

See Note 11 to the Financial Statements for discussion of guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 11 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 valuation, VaR and other risk measurement metrics.

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

Commodity Price Risk

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

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

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

Parametric processes are used to calculate VaR and are considered by management to be the most effective way to estimate changes in a portfolio's value based on assumed market conditions for liquid markets. The use of 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.


	Nine Months Ended September 30, 2021		Year Ended December 31, 2020
Month-end average VaR	$	474	$	234
Month-end high VaR	$	684	$	361
Month-end low VaR	$	280	$	164

The increase in the month-end high VaR risk measure in 2021 is primarily driven by a larger net open position, higher forward prices and an increase in volatility compared to the prior year.

Interest Rate Risk

At September 30, 2021, the potential reduction of annual pre-tax 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 $7 million taking into account the interest rate swaps discussed in Note 10 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 14 to the Financial Statements for further discussion of this exposure.

Credit Exposure — Our gross credit exposure (excluding collateral impacts) associated with retail and wholesale trade accounts receivable and net derivative assets arising from commodity contracts and hedging and trading activities totaled $1.829 billion at September 30, 2021.

At September 30, 2021, Retail segment credit exposure totaled approximately $1.155 billion of trade accounts receivable. Cash deposits and letters of credit held as collateral for these receivables totaled $60 million, resulting in a net exposure of approximately $1.095 billion. Allowances for uncollectible accounts receivable are established for the potential 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 September 30, 2021, aggregate Texas, East and Sunset segments credit exposure totaled $674 million including $523 million related to derivative assets and $151 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 and Sunset segments exposure was $619 million, the majority of which is with investment grade customers as seen in the following table that presents the distribution of credit exposure at September 30, 2021. Credit collateral includes cash and letters of credit but excludes other credit enhancements such as guarantees or liens on assets.


	Exposure Before Credit Collateral		Credit Collateral		Net Exposure
Investment grade	$	379	$	46	$	333
Below investment grade or no rating	295		9		286
Totals	$	674	$	55	$	619

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At September 30, 2021, we had no concentration (i.e., 10% or greater) of credit exposure with any counterparties. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts such as margin deposits are owed to the counterparties or delays in receipts of expected settlements owed to us.

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

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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:

•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;

▪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 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 (including Winter Storm Uri), 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, wars or terrorist or cybersecurity threats or activities;

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

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•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 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, and natural gas inventories and transportation and storage thereof;

•changes in the ability of vendors to provide or deliver commodities 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 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, particularly in ERCOT, MISO and PJM;

•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 a comparable cash dividend on a quarterly basis;

•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;

•the impact of our obligations under the TRA;

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

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

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

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•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 September 30, 2021. 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 11 to the Financial Statements regarding legal proceedings.

Item 1A.RISK FACTORS

There have been no material changes to the risk factors discussed in Part I, Item 1A Risk Factors in our 2020 Form 10-K, except as set forth below.

Holders of our preferred stock may have interests and rights that are different from our common stockholders.

We are permitted under our certificate of incorporation to issue up to 100,000,000 shares of preferred stock. We can issue shares of our preferred stock in one or more series and can set the terms of the preferred stock without seeking any further approval from our common stockholders. Any preferred stock that we issue may rank ahead of our common stock in terms of dividend priority or liquidation premiums and may have greater voting rights than our common stock, which could dilute the value of our common stock to current stockholders and could adversely affect the market price of our common stock. As of October 15, 2021 (Initial Issuance Date), 1,000,000 shares of Series A Preferred Stock are issued and outstanding. The Series A Preferred Stock represents a perpetual equity interest in the Company and, unlike our indebtedness, will not give rise to a claim for payment of a principal amount at a particular date; provided, the Company may redeem the Series A Preferred Stock at the specified times (or upon certain specified events) at the applicable redemption price set forth in the certificate of designation of the Series A Preferred Stock (Certificate of Designation). The Series A Preferred Stock is not convertible into or exchangeable for any other securities of the Company. Upon the liquidation, dissolution or winding up of the Company, whether voluntary or involuntary, after payment or provision for payment of the debts and other liabilities of the Company, the holders of Series A Preferred Stock will be entitled to receive, pro rata and in preference to the holders of any other capital stock, an amount per share equal to $1,000 plus accrued and unpaid dividends thereon, if any.

Unless we have received the affirmative vote or consent of the holders of at least two-thirds of the outstanding Series A Preferred Stock, voting as a separate class, we may not adopt any amendment to our certificate of incorporation (including the Certificate of Designation) that would have a material adverse effect on the powers, preferences, duties, or special rights of the Series A Preferred Stock, subject to certain exceptions. In addition, unless we have received the affirmative vote or consent of the holders of at least two-thirds of the outstanding Series A Preferred Stock, voting as a class together with the holders of any parity securities upon which like voting rights have been conferred and are exercisable, we may not: (i) create or issue any senior securities, (ii) create or issue any parity securities (including any additional Series A Preferred Stock) if the cumulative dividends payable on the outstanding Series A Preferred Stock (or parity securities, if applicable) are in arrears; (iii) create or issue any additional Series A Preferred Stock or any parity securities with an aggregate liquidation preference, together with the issued and outstanding Series A Preferred Stock and any parity securities that are then outstanding, of greater than $2.5 billion, and (iv) engage in any Transaction that results in a Covered Disposition (as such terms are defined in the Certificate of Designation).

In addition, holders of the Series A Preferred Stock are entitled to receive, when, as, and if declared by our Board, semi-annual cash dividends on the Series A Preferred Stock, which are cumulative from the Initial Issuance Date and payable in arrears, and unless full cumulative dividends have been or contemporaneously are being paid or declared on the Series A Preferred Stock, we may not (i) declare or pay any dividends on any junior securities, including our common stock, or (ii) redeem or repurchase any parity securities or junior securities, subject to limited exceptions set forth in the Certificate of Designation. The holders of Series A Preferred Stock (along with any parity securities then outstanding with similar rights) are also entitled to elect two additional directors in the event any dividends on Series A Preferred Stock are in arrears for three or more semi-annual dividend periods (whether or not consecutive), and such directors may have competing and different interests to those elected by our common stockholders. The dividend rate for the Series A Preferred Stock from and including the Initial Issuance Date until October 15, 2026 (First Reset Date) will be 8.0% per annum of the $1,000 liquidation preference per share of Series A Preferred Stock. On and after the First Reset Date, the dividend rate on the Series A Preferred Stock for each subsequent five-year period (each, a Reset Period) will be adjusted based upon the applicable Treasury rate, plus a spread of 6.93% per annum; provided that the applicable Treasury rate for each Reset Period will not be lower than 1.07%. In the event that the Company does not exercise its option to redeem all the shares of Series A Preferred Stock within 120 days after the first date on which a Change of Control Trigger Event (as defined in the Certificate of Designation) occurs, the then-applicable dividend rate for the Series A Preferred Stock will be increased by 5.00%.

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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 September 30, 2021.

Total Number of Shares Purchased

Average Price Paid per Share

Total Number of Shares Purchased as Part of a Publicly Announced Program

July 1 - July 31, 2021

—

August 1 - August 31, 2021

—

September 1 - September 30, 2021

—

For the quarter ended September 30, 2021

—

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 the net proceeds from our October 2021 preferred stock offering to repurchase shares of our outstanding common stock. We expect to complete repurchases under the Share Repurchase Program by the end of 2022.

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.

See Note 12 to the Financial Statements for more information concerning the Share Repurchase Program.

Item 3.DEFAULTS UPON SENIOR SECURITIES

None.

Item 4. MINE SAFETY DISCLOSURES

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

Item 5.OTHER INFORMATION

None.

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Item 6. EXHIBITS

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


Exhibits	Previously Filed With File Number*	As Exhibit

(3(i))	Articles of Incorporation

3.1	0001-38086 Form 8-K (filed May 4, 2020)	3.1	—	Restated Certificate of Incorporation of Vistra Energy Corp. (now known as Vistra Corp.)

3.2	0001-38086 Form 8-K (filed June 29, 2020)	3.1	—	Certificate of Amendment of the Restated Certificate of Incorporation of Vistra Energy Corp. (now known as Vistra Corp.), effective July 2, 2020

3.3	0001-38086 Form 8-K (filed October 15, 2021)	3.1	—	Series A Preferred Stock Certificate of Designation, filed with the Secretary of State of Delaware on October 14, 2021

(3(ii))	By-laws

3.3	001-38086 Form 10-K (Year ended December 31, 2020) (filed February 23, 2021)	3.3	—	Restated Bylaws of Vistra Corp., effective February 23, 2021

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

4.1	0001-38086 Form 8-K (filed July 15, 2021)	4.1	—	Tenth Amendment to Receivables Purchase Agreement, dated as of July 9, 2021, 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

4.2	**		—	Eleventh Amendment to Receivables Purchase Agreement, dated as of July 16, 2021, 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

4.3	**		—	Seventh Supplemental Indenture for the 5.500% Senior Notes due 2026, dated July 29, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee

4.4	**		—	Seventh Supplemental Indenture for the 5.625% Senior Notes due 2026, dated July 29, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee

4.5	**		—	Seventh Supplemental Indenture for the 5.000% Senior Notes due 2027, dated July 29, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee

4.6	**		—	Ninth Supplemental Indenture for the 3.55% Senior Secured Notes due 2024, 3.70% Senior Secured Notes due 2027 and 4.30% Senior Secured Notes due 2029, dated as of July 29, 2021, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee

4.7	**		—	First Supplemental Indenture for the 4.375% Senior Notes due 2029, dated July 29, 2021, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee

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

10.1	0001-38086 Form 8-K (filed July 15, 2021)	10.1	—	Amendment No. 1 to Master Framework Agreement, dated as of July 9, 2021, by and among TXU Energy Retail Company LLC, as seller and seller party agent, certain originators name therein, Vistra Operations Company LLC, as guarantor, and MUFG Bank, Ltd., as buyer

10.2	**		—	Amendment No. 2 to Master Framework Agreement, dated as of August 3, 2021, by and among TXU Energy Retail Company LLC, as seller and seller party agent, certain originators name therein, Vistra Operations Company LLC, as guarantor, and MUFG Bank, Ltd., as buyer

10.3	**		—	Amendment No. 1 to Master Repurchase Agreement, dated as of August 3, 2021, between TXU Energy Retail Company LLC and MUFG Bank, Ltd.

10.4	0001-38086 Form 8-K (filed October 15, 2021)	10.1	—	Purchase Agreement, dated October 12, 2021, by and between Vistra Corp. and Goldman Sachs & Co. LLC

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

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

31.2	**		—	Certification of James A. Burke, 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 Curtis A. Morgan, 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 James A. Burke, 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 September 30, 2021 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

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Exhibits

Previously Filed With File Number*

Exhibit

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

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SIGNATURE

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

Vistra Corp.

By:

/s/ CHRISTY DOBRY

Name:

Christy Dobry

Title:

Senior Vice President and Controller

(Principal Accounting Officer)

Date: November 5, 2021