UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, ~~2020~~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~~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 ~~July 31, 2020,~~August 3, 2021, there were ~~488,780,072~~482,518,768 shares of common stock, par value $0.01, outstanding of Vistra Corp.

Table of Contents

TABLE OF CONTENTS


		PAGE
GLOSSARY		ii
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Statements of Operations — Three and Six Months Ended June 30 , ~~2020~~2021 and ~~2019~~2020	1
	Condensed Consolidated Statements of Comprehensive Income (Loss) — Three and Six Months Ended June 30 , ~~2020~~2021 and ~~2019~~2020	1
	Condensed Consolidated Statements of Cash Flows — ~~Six~~Three and Six Months Ended June 3 0 30 , ~~2020~~2021 and ~~2019~~2020	2
	Condensed Consolidated Balance Sheets — June 30 , ~~2020~~2021 and December 31, ~~2019~~2020	3
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	4745
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	7069
Item 4.	Controls and Procedures	7574
PART II.	OTHER INFORMATION	7675
Item 1.	Legal Proceedings	7675
Item 1A.	Risk Factors	7675
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	7775
Item 3.	Defaults Upon Senior Securities	7775
Item 4.	Mine Safety Disclosures	7775
Item 5.	Other Information	7776
Item 6.	Exhibits	7776
SIGNATURE		8078

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

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

Table of Contents

GLOSSARY

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


~~2019~~2020 Form 10-K						Vistra's annual report on Form 10-K for the year ended December 31, ~~2019,~~2020, filed with the SEC on February ~~28, 2020~~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
~~CAA~~						~~Clean Air Act~~
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, respectively)~~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 ~~Agreement~~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
~~Merger Date~~						~~April 9, 2018, the date Vistra and Dynegy completed the transactions contemplated by the Merger Agreement~~
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.~~facility
NERC						North American Electric Reliability Corporation
NJEA						North Jersey Energy Associates, aA Limited Partnership
NO_X						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 ~~ISO-NE~~ and MISO that is engaged in the retail sale of electricity to residential and business customers
PUCT						Public Utility Commission of Texas
REP						retail electric provider
RCT						Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas, and has jurisdiction over oil and natural gas exploration and production, permitting and inspecting intrastate pipelines, and overseeing natural gas utility rates and compliance
RTO						regional transmission organization
S&P						Standard & Poor's Ratings (a credit rating agency)
SEC						U.S. Securities and Exchange Commission
Securities Act						Securities Act of 1933, as amended
SO₂						~~sulfur dioxide~~

iii

Table of Contents


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 87 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 ~~ISO-NE~~ 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 ~~4Change~~Energy, Express Energy and ~~Express~~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 1110 to the Financial Statements) and borrower under the Vistra Operations Credit Facilities
Vistra Operations Credit Facilities						Vistra Operations Company LLC's ~~$5.311 billion~~ senior secured financing facilities (see Note 1110 to the Financial Statements).

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1.FINANCIAL STATEMENTS

VISTRA CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

Three Months Ended June 30, Six Months Ended June 30,
2020 2019 2020 2019
Operating revenues (Note 5) $ 2,509 $ 2,832 $ 5,367 $ 5,755
Fuel, purchased power costs and delivery fees (1,029) (1,139) (2,362) (2,600)
Operating costs (412) (370) (792) (755)
Depreciation and amortization (455) (384) (875) (790)
Selling, general and administrative expenses (236) (210) (488) (392)
Impairment of long-lived assets (Note 18) — — (84) —
Operating income 377 729 766 1,218
Other income (Note 18) 5 13 12 39
Other deductions (Note 18) (4) (2) (35) (5)
Interest expense and related charges (Note 18) (141) (274) (440) (495)
Impacts of Tax Receivable Agreement (Note 8) (6) 33 (14) 36
Equity in earnings of unconsolidated investment 1 3 4 10
Income before income taxes 232 502 293 803
Income tax expense (Note 7) (68) (148) (84) (225)
Net income $ 164 $ 354 $ 209 $ 578
Net loss attributable to noncontrolling interest 2 2 13 3
Net income attributable to Vistra $ 166 $ 356 $ 222 $ 581
Weighted average shares of common stock outstanding:
Basic 488,680,442 499,778,235 488,312,503 499,213,522
Diluted 490,468,735 507,500,383 490,709,932 507,248,920
Net income per weighted average share of common stock outstanding:
Basic $ 0.34 $ 0.71 $ 0.45 $ 1.16
Diluted $ 0.34 $ 0.70 $ 0.45 $ 1.15


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Operating revenues (Note 4)	$	2,565	$	2,509	$	5,772	$	5,367
Fuel, purchased power costs and delivery fees	(1,320)		(1,029)		(6,065)		(2,362)
Operating costs	(429)		(412)		(801)		(792)
Depreciation and amortization	(464)		(455)		(887)		(875)
Selling, general and administrative expenses	(252)		(236)		(502)		(488)

Impairment of long-lived assets (Note 17)	(38)		0		(38)		(84)
Operating income (loss)	62		377		(2,521)		766
Other income (Note 17)	36		5		92		12
Other deductions (Note 17)	(2)		(4)		(7)		(35)
Interest expense and related charges (Note 17)	(135)		(141)		(164)		(440)
Impacts of Tax Receivable Agreement (Note 7)	(41)		(6)		(4)		(14)
Equity in earnings of unconsolidated investment	0		1		0		4
Income (loss) before income taxes	(80)		232		(2,604)		293
Income tax (expense) benefit (Note 6)	115		(68)		600		(84)
Net income (loss)	$	35	$	164	$	(2,004)	$	209
Net (income) loss attributable to noncontrolling interest	1		2		(2)		13
Net income (loss) attributable to Vistra	$	36	$	166	$	(2,006)	$	222
Weighted average shares of common stock outstanding:
Basic	486,022,633		488,680,442		485,364,606		488,312,503
Diluted	487,366,226		490,468,735		485,364,606		490,709,932
Net income (loss) per weighted average share of common stock outstanding:
Basic	$	0.07	$	0.34	$	(4.13)	$	0.45
Diluted	$	0.07	$	0.34	$	(4.13)	$	0.45

See Notes to the Condensed Consolidated Financial Statements.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited) (Millions of Dollars)

Three Months Ended June 30, Six Months Ended June 30,
2020 2019 2020 2019
Net income $ 164 $ 354 $ 209 $ 578
Other comprehensive income, net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax benefit of $—, $—, $7 and $—) 1 — (22) 1
Total other comprehensive income (loss) 1 — (22) 1
Comprehensive income $ 165 $ 354 $ 187 $ 579
Comprehensive loss attributable to noncontrolling interest 2 2 13 3
Comprehensive income attributable to Vistra $ 167 $ 356 $ 200 $ 582


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Net income (loss)	$	35	$	164	$	(2,004)	$	209
Other comprehensive income (loss), net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax (expense) benefit of $(1), $0, $(1) and $7)	1		1		3		(22)

Total other comprehensive income (loss)	1		1		3		(22)
Comprehensive income (loss)	$	36	$	165	$	(2,001)	$	187
Comprehensive (income) loss attributable to noncontrolling interest	1		2		(2)		13
Comprehensive income (loss) attributable to Vistra	$	37	$	167	$	(2,003)	$	200

See Notes to the Condensed Consolidated Financial Statements.

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VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars)
	Six Months Ended June 30,
	2021		2020
Cash flows — operating activities:
Net income (loss)	$	(2,004)	$	209
Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:
Depreciation and amortization	969		1,022
Deferred income tax expense (benefit), net	(626)		73

Impairment of long-lived assets (Note 17)	38		84
Loss on disposal of investment in NELP (Note 17)	0		29

Unrealized net (gain) loss from mark-to-market valuations of commodities	182		(123)
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps	(79)		192
Asset retirement obligation accretion expense	19		23
Impacts of Tax Receivable Agreement (Note 7)	4		14
Stock-based compensation	25		30
Other, net	56		55
Changes in operating assets and liabilities:
Margin deposits, net	(240)		58
Accrued interest	8		(6)
Accrued taxes	(75)		(59)
Accrued employee incentive	(107)		(70)
Other operating assets and liabilities	773		(222)
Cash provided by (used in) operating activities	(1,057)		1,309
Cash flows — investing activities:
Capital expenditures, including nuclear fuel purchases and LTSA prepayments	(546)		(588)

Proceeds from sales of nuclear decommissioning trust fund securities (Note 17)	267		224
Investments in nuclear decommissioning trust fund securities (Note 17)	(277)		(234)
Proceeds from sales of environmental allowances	64		88
Purchases of environmental allowances	(173)		(173)
Insurance proceeds	63		15

Other, net	27		15
Cash used in investing activities	(575)		(653)
Cash flows — financing activities:
Issuances of long-term debt (Note 10)	1,250		0
Borrowings under Term Loan A (Note 10)	1,250		0
Repayment under Term Loan A (Note 10)	(1,250)		0
Proceeds from forward capacity agreement (Note 10)	500		0
Repayments/repurchases of debt (Note 10)	(101)		(756)
Net borrowings under accounts receivable financing (Note 9)	361		0
Borrowings under Revolving Credit Facility (Note 10)	1,300		925
Repayments under Revolving Credit Facility (Note 10)	(1,300)		(725)
Share repurchases (Note 12)	(175)		0
Dividends paid to stockholders (Note 12)	(147)		(132)
Debt tender offer and other financing fees (Note 10)	(13)		(10)
Other, net	(4)		0
Cash provided by (used in) financing activities	1,671		(698)

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VISTRA CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited) (Millions of Dollars)
Six Months Ended June 30,
2020 2019
Cash flows — operating activities:
Net income $ 209 $ 578
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization 1,022 886
Deferred income tax expense, net 73 217
Impairment of long-lived assets (Note 18) 84 —
Loss on disposal of investment in NELP (Note 18) 29 —
Unrealized net gain from mark-to-market valuations of commodities (123) (703)
Unrealized net loss from mark-to-market valuations of interest rate swaps 192 199
Asset retirement obligation accretion expense 23 27
Impacts of Tax Receivable Agreement (Note 8) 14 (36)
Stock-based compensation 30 24
Other, net 55 73
Changes in operating assets and liabilities:
Margin deposits, net 58 112
Accrued interest (6) 6
Accrued taxes (59) (67)
Accrued employee incentive (70) (72)
Other operating assets and liabilities (222) (362)
Cash provided by operating activities 1,309 882
Cash flows — investing activities:
Capital expenditures, including nuclear fuel purchases and LTSA prepayments (588) (303)
Proceeds from sales of nuclear decommissioning trust fund securities (Note 18) 224 292
Investments in nuclear decommissioning trust fund securities (Note 18) (234) (302)
Proceeds from sales of environmental allowances 88 31
Purchases of environmental allowances (173) (138)
Other, net 30 21
Cash used in investing activities (653) (399)
Cash flows — financing activities:
Issuances of long-term debt (Note 11) — 4,600
Repayments/repurchases of debt (Note 11) (756) (4,137)
Net borrowings under accounts receivable securitization program (Note 10) — 91
Borrowings under Revolving Credit Facility (Note 11) 925 —
Repayments under Revolving Credit Facility (Note 11) (725) —
Stock repurchase (Note 13) — (457)
Dividends paid to stockholders (Note 13) (132) (120)
Debt tender offer and other financing fees (Note 11) (10) (146)
Other, net — (1)
Cash used in financing activities (698) (170)
Net change in cash, cash equivalents and restricted cash (42) 313
Cash, cash equivalents and restricted cash — beginning balance 475 693
Cash, cash equivalents and restricted cash — ending balance $ 433 $ 1,006


VISTRA CORP. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Millions of Dollars)
	Six Months Ended June 30,
	2021		2020
Net change in cash, cash equivalents and restricted cash	39		(42)
Cash, cash equivalents and restricted cash — beginning balance	444		475
Cash, cash equivalents and restricted cash — ending balance	$	483	$	433

See Notes to the Condensed Consolidated Financial Statements.

~~Table of Contents~~


VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars)	VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars)									VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars)
		June 30, 2020		December 31, 2019			June 30, 2021		December 31, 2020
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	382	$	300	Cash and cash equivalents	$	444	$	406
Restricted cash (Note 18)		27		147
Trade accounts receivable — net (Note 18)		1,272		1,365
Restricted cash (Note 17)						Restricted cash (Note 17)	23		19
Trade accounts receivable — net (Note 17)						Trade accounts receivable — net (Note 17)	1,352		1,279

Inventories (Note 18)		541		469
Commodity and other derivative contractual assets (Note 15)		1,350		1,333
Inventories (Note 17)						Inventories (Note 17)	486		515
Commodity and other derivative contractual assets (Note 14)						Commodity and other derivative contractual assets (Note 14)	1,687		748
Margin deposits related to commodity contracts	Margin deposits related to commodity contracts	161		202		Margin deposits related to commodity contracts	507		257
Prepaid expense and other current assets	Prepaid expense and other current assets	304		298		Prepaid expense and other current assets	250		205
Total current assets	Total current assets	4,037		4,114		Total current assets	4,749		3,429
Restricted cash (Note 18)		24		28
Investments (Note 18)		1,552		1,537
Investment in unconsolidated subsidiary (Note 18)		—		124
Property, plant and equipment — net (Note 18)		13,881		13,914
Restricted cash (Note 17)						Restricted cash (Note 17)	16		19
Investments (Note 17)						Investments (Note 17)	1,912		1,759

Property, plant and equipment — net (Note 17)						Property, plant and equipment — net (Note 17)	13,327		13,499
Operating lease right-of-use assets	Operating lease right-of-use assets	44		44		Operating lease right-of-use assets	42		45

Goodwill (Note 6)		2,568		2,553
Identifiable intangible assets — net (Note 6)		2,532		2,748
Commodity and other derivative contractual assets (Note 15)		277		136
Goodwill (Note 5)						Goodwill (Note 5)	2,583		2,583
Identifiable intangible assets — net (Note 5)						Identifiable intangible assets — net (Note 5)	2,290		2,446
Commodity and other derivative contractual assets (Note 14)						Commodity and other derivative contractual assets (Note 14)	332		258
Accumulated deferred income taxes	Accumulated deferred income taxes	994		1,066		Accumulated deferred income taxes	1,464		838
Other noncurrent assets	Other noncurrent assets	398		352		Other noncurrent assets	300		332
Total assets	Total assets	$	26,307	$	26,616	Total assets	$	27,015	$	25,208
LIABILITIES AND EQUITY	LIABILITIES AND EQUITY					LIABILITIES AND EQUITY
Current liabilities:	Current liabilities:					Current liabilities:
Short-term borrowings (Note 11)		$	550	$	350
Accounts receivable securitization program (Note 10)		450		450
Long-term debt due currently (Note 11)		337		277

Accounts receivable financing (Note 9)						Accounts receivable financing (Note 9)	661		300
Long-term debt due currently (Note 10)						Long-term debt due currently (Note 10)	511		95
Trade accounts payable	Trade accounts payable	879		947		Trade accounts payable	1,078		880
Commodity and other derivative contractual liabilities (Note 15)		1,546		1,529
Commodity and other derivative contractual liabilities (Note 14)						Commodity and other derivative contractual liabilities (Note 14)	2,044		789
Margin deposits related to commodity contracts	Margin deposits related to commodity contracts	15		8		Margin deposits related to commodity contracts	43		33
Accrued income taxes	Accrued income taxes	10		1		Accrued income taxes	8		16
Accrued taxes other than income	Accrued taxes other than income	133		200		Accrued taxes other than income	143		210
Accrued interest	Accrued interest	144		151		Accrued interest	138		131
Asset retirement obligations (Note 18)		138		141
Asset retirement obligations (Note 17)						Asset retirement obligations (Note 17)	103		103
Operating lease liabilities	Operating lease liabilities	11		14		Operating lease liabilities	7		8

Other current liabilities	Other current liabilities	418		506		Other current liabilities	487		471
Total current liabilities	Total current liabilities	4,631		4,574		Total current liabilities	5,223		3,036
Long-term debt, less amounts due currently (Note 11)		9,261		10,102
Operating lease liabilities		37		41

Commodity and other derivative contractual liabilities (Note 15)		599		396
Accumulated deferred income taxes		2		2
Tax Receivable Agreement obligation (Note 8)		468		455
Asset retirement obligations (Note 18)		2,314		2,097

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VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars)	VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars)									VISTRA CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars)
		June 30, 2020		December 31, 2019			June 30, 2021		December 31, 2020
Other noncurrent liabilities and deferred credits (Note 18)		951		989
Long-term debt, less amounts due currently (Note 10)						Long-term debt, less amounts due currently (Note 10)	10,484		9,235
Operating lease liabilities						Operating lease liabilities	38		40

Commodity and other derivative contractual liabilities (Note 14)						Commodity and other derivative contractual liabilities (Note 14)	537		624
Accumulated deferred income taxes						Accumulated deferred income taxes	1		1
Tax Receivable Agreement obligation (Note 7)						Tax Receivable Agreement obligation (Note 7)	451		447
Asset retirement obligations (Note 17)						Asset retirement obligations (Note 17)	2,346		2,333

Other noncurrent liabilities and deferred credits (Note 17)						Other noncurrent liabilities and deferred credits (Note 17)	1,867		1,131
Total liabilities	Total liabilities	18,263		18,656		Total liabilities	20,947		16,847
Commitments and Contingencies (Note 12)
Total equity (Note 13):
Common stock (par value — $0.01; number of shares authorized — 1,800,000,000) (shares outstanding: June 30, 2020 — 488,772,572; December 31, 2019 — 487,698,111)		5		5
Treasury stock, at cost (shares: June 30, 2020 — 41,043,224; December 31, 2019 — 41,043,224)		(973)		(973)
Commitments and Contingencies (Note 11)						Commitments and Contingencies (Note 11)	0		0
Total equity (Note 12):						Total equity (Note 12):
Common stock (par value — $0.01; number of shares authorized — 1,800,000,000) (shares outstanding: June 30, 2021 — 482,468,556; December 31, 2020 — 489,305,888)						Common stock (par value — $0.01; number of shares authorized — 1,800,000,000) (shares outstanding: June 30, 2021 — 482,468,556; December 31, 2020 — 489,305,888)	5		5
Treasury stock, at cost (shares: June 30, 2021 — 49,701,377; December 31, 2020 — 41,043,224)						Treasury stock, at cost (shares: June 30, 2021 — 49,701,377; December 31, 2020 — 41,043,224)	(1,148)		(973)
Additional paid-in-capital	Additional paid-in-capital	9,754		9,721		Additional paid-in-capital	9,816		9,786
Retained deficit	Retained deficit	(678)		(764)		Retained deficit	(2,552)		(399)
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(52)		(30)		Accumulated other comprehensive loss	(45)		(48)
Stockholders' equity	Stockholders' equity	8,056		7,959		Stockholders' equity	6,076		8,371
Noncontrolling interest in subsidiary	Noncontrolling interest in subsidiary	(12)		1		Noncontrolling interest in subsidiary	(8)		(10)
Total equity	Total equity	8,044		7,960		Total equity	6,068		8,361
Total liabilities and equity	Total liabilities and equity	$	26,307	$	26,616	Total liabilities and equity	$	27,015	$	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. Effective July 2, 2020, we changed our name from Vistra Energy Corp. to Vistra Corp. (Vistra) to distinguish from companies that are involved in exploring for, producing, refining, or transporting fossil fuels (many of which use "energy" in their names) and to better reflect our integrated business model, which combines a retail electricity and natural gas business focused on serving its customers with new and innovative products and services and an electric power generation business powering the communities we serve with safe, reliable power.

Vistra has 6 reportable segments: (i) Retail, (ii) ~~ERCOT,~~Texas, (iii) ~~PJM,~~East, (iv) ~~NY/NE (comprising NYISO and ISO-NE),~~West, (v) ~~MISO~~Sunset and (vi) Asset Closure. See Note 1716 for further information concerning reportable business segments.

~~Ambit Transaction~~Winter Storm Uri

~~On November 1, 2019, an indirect, wholly owned subsidiary~~In February 2021, a severe winter storm with extremely cold temperatures affected much of ~~Vistra completed~~ the ~~acquisition~~U.S., including Texas. Winter Storm Uri had a material adverse impact on our results of ~~Ambit (Ambit Transaction). Because~~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 ~~Ambit Transaction closed on November 1, 2019, Vistra's condensed consolidated financial statements~~completion of customer billing activities, receipt of final settlement data from ERCOT, the outcome of potential litigation and legislative actions arising from the ~~notes related thereto do not include~~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 ~~condition~~impacts of market-wide load shed ratably across all retail market participants), that is currently being considered or ~~the operating results of Ambit and its subsidiaries prior~~may be considered by any such parties. Additionally, we have disputes over certain gas invoices that are not anticipated to ~~November 1, 2019. See Note 2 for~~have a ~~summary of the Ambit Transaction.~~

~~Crius Transaction~~

On July 15, 2019, an indirect, wholly owned subsidiary of Vistra completed the acquisition of the equity interests of two wholly owned subsidiaries of Crius that indirectly owned the operating business of Crius (Crius Transaction). Because the Crius Transaction closed on July 15, 2019, Vistra's condensed consolidated financial statements and the notes related thereto do not include the financial condition or the operating results of Crius and its subsidiaries prior to July 15, 2019. See Note 2 for a summary of the Crius Transaction.material impact.

COVID-19 Pandemic

In March 2020, the World Health Organization categorized the novel coronavirus (COVID-19) as a pandemic, and the ~~President of the United States (the President)~~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 six months ended June 30, ~~2020.~~2021.

In response to the global pandemic related to COVID-19, the ~~President~~CARES Act was signed into law ~~the CARES Act on~~in March ~~27,~~ 2020. See Note 76 for a summary of certain anticipated tax-related impacts of the CARES Act to the Company.

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Basis of Presentation

The condensed consolidated financial statements have been prepared in accordance with U.S. GAAP and on the same basis as the audited financial statements included in our ~~2019~~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 ~~2019~~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.

Use of Estimates

Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements, estimates of expected obligations, judgments related to the potential timing of events and other estimates. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information.

~~Adoption of Accounting Standards~~Recent Developments

~~In December 2019, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2019-12,~~ ~~Simplifying the Accounting for Income Taxes (Topic 740)~~.Finalization of Plant's Planned Retirement Date ~~The ASU enhances and simplifies various aspects of~~— In July 2021, we announced we would retire the ~~income tax accounting guidance including the elimination of certain exceptions related~~Zimmer coal generation facility by May 31, 2022 due to the ~~approach~~inability to secure capacity revenues for ~~intraperiod tax allocation,~~ the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-upplant in the ~~tax basis~~latest PJM capacity auction held in May 2021. We had previously announced that Zimmer would retire no later than the end of ~~goodwill. We adopted all provisions of this ASU in the first quarter of 2020, and it did not have a material impact on our financial statements.~~2027.

Accounts Receivable Financing — In July 2021, certain subsidiaries of the Company entered into amendments to the Receivables Facility and Repurchase Facility, respectively, extending the terms of such facilities to July 2022 and August 2021, respectively. In August ~~2018,~~2021, the ~~FASB issued ASU 2018-13,~~ ~~Changes~~Repurchase Facility was further amended to ~~the Disclosure Requirements for Fair Value Measurement.~~ The ASU removes disclosure requirements for (a) the reasons for transfers between Level 1 and Level 2, (b) the policy for timing of transfers between levels and (c) the valuation processes for Level 3. The ASU requires new disclosures around (a) the changes in unrealized gains and losses for the period included in other comprehensive income for recurring Level 3 fair value measurements held at the end of the reporting period and (b) the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. We adopted this ASU in the first quarter of 2020, and the updated disclosures are included in Note 14.

~~In August 2018, the FASB issued ASU 2018-15,~~ ~~Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract.~~ The ASU requires a customer in a cloud hosting arrangement that is a service contract to determine which implementation costs to capitalize and which costs to expense based on the project stage of the implementation. The ASU also requires the customer to expense the capitalized implementation costs overextend the term of ~~the hosting arrangement. The customer is required~~such facility to apply the existing impairment and abandonment guidance on the capitalized implementation costs. We adopted this ASU in the first quarter of 2020, and it did not have a material impact on our financial statements.July 2022 (see Note 9).

~~In June 2016, the FASB issued ASU 2016-13,~~ ~~Financial Instruments—Credit Losses~~. The ASU requires organizations to measure all expected credit losses for financial instruments held at the reporting date based on historical experience, current conditions and reasonable and supportable forecasts. We adopted this ASU in the first quarter of 2020, and it did not have a material impact on our financial statements.

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~~Changes in Accounting Standards~~

~~In March 2020, the FASB issued ASU 2020-04,~~ ~~Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting~~. The ASU provides optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that reference LIBOR or another rate that is expected to be discontinued. The amendments in the ASU are effective for all entities as of March 12, 2020 through December 31, 2022. The adoption of this guidance did not have a material impact on our financial statements.

In March 2020, the SEC amended Rule 3-10 of Regulation S-X regarding financial disclosure requirements for registered debt offerings involving subsidiaries as either issuers or guarantors and affiliates whose securities are pledged as collateral. This new guidance narrows the circumstances that require separate financial statements of subsidiary issuers and guarantors and streamlines the alternative disclosures required in lieu of those statements. This rule is effective January 4, 2021 with earlier adoption permitted. We elected to adopt this rule in the first quarter of 2020. Accordingly, summarized financial information has been presented only for the issuer and guarantors of the Company's registered debt securities, and the location of the required disclosures has been moved outside the Notes to the Consolidated Financial Statements and is provided in Part I, Item 2 ~~Management's Discussion and Analysis of Financial Condition and Results of Operations~~ ~~under~~ ~~Financial Condition - Guarantor Summary Financial Information~~.

2. ~~ACQUISITIONS, MERGER TRANSACTION AND BUSINESS COMBINATION ACCOUNTING~~

~~Ambit Transaction~~

On November 1, 2019 (Ambit Acquisition Date), Volt Asset Company, Inc., an indirect, wholly owned subsidiary of Vistra, completed the Ambit Transaction. Ambit is an energy retailer selling both electricity and natural gas products to residential and small business customers in 17 states. Vistra funded the purchase price of $555 million (including cash acquired and net working capital) using cash on hand. All of Ambit's outstanding debt was repaid from the purchase price at closing and not assumed by Vistra.

~~Crius Transaction~~

On July 15, 2019 (Crius Acquisition Date), Vienna Acquisition B.C. Ltd., an indirect, wholly owned subsidiary of Vistra, completed the acquisition of the equity interests of two wholly owned subsidiaries of Crius that indirectly own the operating business of Crius. Crius is an energy retailer selling both electricity and natural gas products to residential and small business customers in 19 states. Vistra funded the purchase price of $400 million (including $382 million for outstanding trust units) using cash on hand. In addition, Vistra assumed $140 million of outstanding debt and acquired $26 million of cash at the closing of the Crius Transaction.

~~Ambit and Crius Business Combination Accounting~~

We believe the Ambit Transaction has (i) augmented Vistra's existing retail marketing capabilities with additional direct selling capability and a proprietary technology platform, (ii) reduced risk and aided expansion into higher margin channels by improving Vistra's match of its generation to load profile due to a high degree of overlap of Vistra's generation fleet with Ambit's approximately 11 TWh of annual load, primarily in ERCOT and PJM and (iii) enhanced the integrated value proposition through collateral and transaction efficiencies, particularly via Ambit's retail electric portfolio.

We believe the Crius Transaction has (i) reduced risk and aided expansion into higher margin channels by improving Vistra's match of its generation to load profile due to a high degree of overlap of Vistra's generation fleet with Crius' approximately 10 TWh of annual electricity load, (ii) established a platform for growth by leveraging Vistra's existing retail marketing capabilities and Crius' experienced team and (iii) enhanced the integrated value proposition through collateral and transaction efficiencies, particularly via Crius' retail electric portfolio.

~~Table of Contents~~

~~Each of the Ambit Transaction and Crius Transaction, respectively, is being accounted for in accordance with ASC 805,~~ ~~Business Combinations~~ (ASC 805), with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the Ambit Acquisition Date and Crius Acquisition Date, respectively. The combined results of operations are reported in our condensed consolidated financial statements beginning as of the respective Ambit Acquisition Date and Crius Acquisition Date. A summary of the techniques used to estimate the fair value of the identifiable assets and liabilities, as well as their classification within the fair value hierarchy (see Note 14), is listed below:

•~~Working capital was valued using available market information (Level 2).~~

•~~Acquired derivatives were valued using the methods described in Note 14 (Level 2 or Level 3).~~

•~~Acquired retail customer relationship was valued based on discounted cash flow analysis of acquired customers and estimated attrition rates (Level 3).~~

•~~Crius' long-term debt was valued using a market approach (Level 2).~~

The following table summarizes the allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Ambit Transaction and Crius Transaction, respectively, as of the Ambit Acquisition Date and Crius Acquisition Date, respectively. The Ambit Transaction purchase price was $555 million (including cash acquired and net working capital), and the Crius Transaction purchase price was $400 million. The Ambit Transaction purchase price allocation is ongoing and is dependent upon final valuation determinations, which have not been completed. The Ambit Transaction preliminary values included below represent our current best estimates for identifiable intangible assets, goodwill and net working capital. The Ambit Transaction purchase price allocation is preliminary and each of the values included below may change materially based upon the receipt of more detailed information, additional analyses and completed valuations. The final purchase price allocation was completed in the second quarter of 2020 for the Crius Transaction and will be completed no later than the third quarter of 2020 for the Ambit Transaction.

Ambit Transaction Preliminary Purchase Price Allocation and Crius Transaction Final Purchase Price Allocation
Ambit Transaction Crius Transaction
Updated Preliminary Purchase Price Allocation Measurement Period Adjustments recorded through
June 30, 2020 Final
Purchase Price Allocation Measurement Period Adjustments recorded through
June 30, 2020
Cash and cash equivalents $ 49 $ — $ 26 $ —
Net working capital 35 6 (9) (42)
Accumulated deferred income taxes — — — (36)
Identifiable intangible assets 230 (33) 317 23
Goodwill 243 29 243 38
Commodity and other derivative contractual assets 23 — 18 —
Other noncurrent assets 13 — 17 (3)
Total assets acquired 593 2 612 (20)
Identifiable intangible liabilities — — 2 (34)
Long-term debt, including amounts due currently — — 140 —
Commodity and other derivative contractual liabilities 28 — 40 —
Accumulated deferred income taxes — — 14 14
Other noncurrent liabilities and deferred credits 10 2 16 —
Total liabilities assumed 38 2 212 (20)
Identifiable net assets acquired $ 555 $ — $ 400 $ —

~~Dynegy Merger Transaction~~

On the Merger Date, Vistra and Dynegy completed the transactions contemplated by the Merger Agreement. Pursuant to the Merger Agreement, Dynegy merged with and into Vistra, with Vistra continuing as the surviving corporation. The Merger was intended to qualify as a tax-free reorganization under the IRC, so that none of Vistra, Dynegy or any of the Dynegy stockholders would recognize any gain or loss in the transaction, except that Dynegy stockholders could recognize a gain or loss with respect to cash received in lieu of fractional shares of Vistra's common stock. Vistra is the acquirer for both federal tax and accounting purposes.

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On the Merger Date, each issued and outstanding share of Dynegy common stock, par value $0.01 per share, other than shares owned by Vistra or its subsidiaries, held in treasury by Dynegy or held by a subsidiary of Dynegy, was automatically converted into 0.652 shares of common stock, par value $0.01 per share, of Vistra (the Exchange Ratio), except that cash was paid in lieu of fractional shares, which resulted in Vistra issuing 94,409,573 shares of Vistra common stock to the former Dynegy stockholders, as well as converting stock options, equity-based awards, tangible equity units and warrants. The total number of Vistra shares outstanding at the close of the Merger was 522,932,453 shares. Dynegy stock options and equity-based awards outstanding immediately prior to the Merger Date were generally automatically converted upon completion of the Merger into stock options and equity-based awards, respectively, with respect to Vistra's common stock, after giving effect to the Exchange Ratio.

3. DEVELOPMENT OF GENERATION FACILITIES

~~Battery~~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 Fall 2021 to Fall 2023. At June 30, 2021, we had accumulated approximately $133 million in construction-work-in-process for these Texas segment solar generation and battery ESS projects.

West Segment Energy Storage Projects

Oakland — In June 2019, East Bay Community Energy (EBCE) signed a ten-year contract to receive resource adequacy capacity from the planned development of a 20 MW battery ESS at our Oakland Power Plant site in California. In April 2020, the project received necessary approvals from EBCE and from Pacific Gas and Electric Company (PG&E)~~, and the~~. 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~~Local Area Reliability Service (LARS) agreement to ensure grid reliability as part of the Oakland Clean Energy Initiative was signed, ~~and sent to the~~but required California Public Utilities Commission (CPUC) ~~for~~ approval. ~~The~~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 ~~is expected~~while seeking another contractual arrangement that will allow the investment to ~~enter commercial operations by January 2022.~~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. ~~At June 30, 2020, we had accumulated approximately $315 million in construction work-in-process for Moss Landing Phase I.~~ 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. ~~We anticipate the~~ Moss Landing Phase I ~~will commence~~commenced commercial operations in the fourth quarter of 2020. PG&E filed for Chapter 11 bankruptcy protection in January 2019. In November 2019, the bankruptcy court approved PG&E's motion requesting approval of the assumption of the resource adequacy contract subject to the CPUC approving the terms of an amendment to the resource adequacy contract, and the CPUC approved the terms of the amendment in January 2020. PG&E emerged from bankruptcy protection in July 2020.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 ~~a decision is expected to be received by~~ the ~~end of~~CPUC approved the ~~third quarter of~~resource adequacy contract in August 2020. ~~Assuming the receipt of CPUC approval,~~At June 30, 2021, we ~~anticipate~~had accumulated approximately $130 million in construction work-in-process for Moss Landing Phase II. Moss Landing Phase II ~~will commence~~commenced commercial operations in ~~the third quarter of~~July 2021.

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4.3. RETIREMENT OF GENERATION FACILITIES

~~MISO~~In September and December 2020, we announced our intention to retire all of our remaining coal generation facilities in Illinois and Ohio, 1 — coal generation facility in Texas and 1natural 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 ~~Bartonville,~~ 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 (see~~2022.

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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 ~~12).~~ 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 ~~August 2019,~~December 2020, we announced the ~~planned~~ retirement of ~~4 power plants~~our 83 MW Wharton natural gas facility in ~~Illinois with a total installed nameplate generation capacity of 2,068 MW. We retired these units~~Texas due to ~~changes in~~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 Illinois multi-pollutant standard rule (MPS rule) that require us to retire approximately 2,000 MW of generation capacity (see Note 12). In light of the provisions of the Federal Power Act and the FERC regulations thereunder, the affected subsidiaries of Vistra identified the retired units by analyzing the economics of each of our Illinois plants and designating the least economic units for retirement. Expected plant retirement expenses of $47 million, driven by severance costs, were accrued in the three months ended September 30, 2019 and were included primarily in operating costs of our Asset Closure segment. In August 2019, we remeasured our pension and OPEB plans resulting in an increase to the benefit obligation liability of $21 million, pretax other comprehensive loss of $18 million and curtailment expense of $3 million recognized as other deductions in our condensed consolidated statements of operations. The following table details the units in Illinois totaling 2,653 MW that have been or will be retired.facility. Operational results for ~~retired plants~~the Wharton facility are included in the Asset Closure ~~segment, which is engaged~~segment. The previously announced retirement of our 244 MW Trinidad natural gas facility in ~~the decommissioning and reclamation of retired plants and mines.~~

Name Location Fuel Type Net Generation Capacity (MW) Number of Units Dates Units Retired or
Expected Retirement Date
Coffeen Coffeen, IL Coal 915 2 November 1, 2019
Duck Creek Canton, IL Coal 425 1 December 15, 2019
Havana Havana, IL Coal 434 1 November 1, 2019
Hennepin Hennepin, IL Coal 294 2 November 1, 2019
Edwards Bartonville, IL Coal 585 2 By the end of 2022
Total 2,653 8
Texas was rescinded in April 2021.

5.4. REVENUE

~~The following tables disaggregate our revenue by major source:~~


		Three Months Ended June 30, 2020																															Three Months Ended June 30, 2021
		Retail		ERCOT		PJM		NY/NE		MISO		Asset Closure		CAISO/Eliminations		Consolidated			Retail		Texas		East		West		Sunset		Asset Closure		Eliminations		Consolidated
Revenue from contracts with customers:	Revenue from contracts with customers:																	Revenue from contracts with customers:
Retail energy charge in ERCOT	Retail energy charge in ERCOT	$	1,411	$	—	$	—	$	—	$	—	$	—	$	—	$	1,411	Retail energy charge in ERCOT	$	1,417	$	0	$	0	$	0	$	0	$	0	$	0	$	1,417
Retail energy charge in Northeast/Midwest	Retail energy charge in Northeast/Midwest	540		—		—		—		—		—		—		540		Retail energy charge in Northeast/Midwest	504		0		0		0		0		0		0		504

Wholesale generation revenue from ISO/RTO	Wholesale generation revenue from ISO/RTO	—		76		71		16		3		—		13		179		Wholesale generation revenue from ISO/RTO	0		128		96		31		185		0		0		440
Capacity revenue from ISO/RTO(a)	Capacity revenue from ISO/RTO(a)	—		—		15		10		4		—		—		29		Capacity revenue from ISO/RTO(a)	0		0		2		0		43		0		0		45
Revenue from other wholesale contracts	Revenue from other wholesale contracts	—		63		137		26		54		—		21		301		Revenue from other wholesale contracts	0		56		130		24		44		0		0		254
Total revenue from contracts with customers	Total revenue from contracts with customers	1,951		139		223		52		61		—		34		2,460		Total revenue from contracts with customers	1,921		184		228		55		272		0		0		2,660
Other revenues:	Other revenues:																	Other revenues:
Intangible amortization	Intangible amortization	(5)		—		—		—		(7)		—		—		(12)		Intangible amortization	(2)		0		73		0		(2)		0		0		69
Hedging and other revenues ~~(a)~~(b)	Hedging and other revenues ~~(a)~~(b)	10		62		(6)		(10)		(6)		—		11		61		Hedging and other revenues ~~(a)~~(b)	0		(8)		131		(7)		(280)		0		0		(164)
Affiliate sales(c)	Affiliate sales(c)	—		664		195		89		73		—		(1,021)		—		Affiliate sales(c)	0		(644)		73		0		(38)		0		609		0
Total other revenues	Total other revenues	5		726		189		79		60		—		(1,010)		49		Total other revenues	(2)		(652)		277		(7)		(320)		0		609		(95)
Total revenues	Total revenues	$	1,956	$	865	$	412	$	131	$	121	$	—	$	(976)	$	2,509	Total revenues	$	1,919	$	(468)	$	505	$	48	$	(48)	$	0	$	609	$	2,565

____________

(a)Represents net capacity sold (purchased) in each ISO/RTO.

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

(c)Texas segment includes $952 million of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.

Table of Contents


	Three Months Ended June 30, 2020
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations		Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	1,411	$	0	$	0	$	0	$	0	$	0	$	0	$	1,411
Retail energy charge in Northeast/Midwest	540		0		0		0		0		0		0		540


Wholesale generation revenue from ISO/RTO	0		61		38		13		66		1		0		179
Capacity revenue from ISO/RTO (a)	0		0		(12)		0		41		0		0		29
Revenue from other wholesale contracts	0		63		163		21		54		0		0		301
Total revenue from contracts with customers	1,951		124		189		34		161		1		0		2,460
Other revenues:
Intangible amortization	(5)		0		0		0		(7)		0		0		(12)
Hedging and other revenues (b)	10		53		(8)		11		(6)		1		0		61
Affiliate sales	0		664		284		0		73		0		(1,021)		0
Total other revenues	5		717		276		11		60		1		(1,021)		49
Total revenues	$	1,956	$	841	$	465	$	45	$	221	$	2	$	(1,021)	$	2,509

____________

(a)Represents net capacity sold (purchased) in each ISO/RTO. The East segment includes net purchases of capacity in the PJM market and the Sunset segment includes net sales of capacity in the PJM market.

(b)Includes $69 million of unrealized net losses from mark-to-market valuations of commodity positions. See Note ~~17 for unrealized net gains (losses) by segment.~~

~~Table of Contents~~

Three Months Ended June 30, 2019
Retail ERCOT PJM NY/NE MISO Asset
Closure CAISO/Eliminations Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT $ 1,091 $ — $ — $ — $ — $ — $ — $ 1,091
Retail energy charge in Northeast/Midwest 315 — — — — — — 315
Wholesale generation revenue from ISO/RTO — 188 130 81 33 43 22 497
Capacity revenue from ISO/RTO — — 53 72 8 3 — 136
Revenue from other wholesale contracts — 52 87 6 40 1 4 190
Total revenue from contracts with customers 1,406 240 270 159 81 47 26 2,229
Other revenues:
Intangible amortization (10) — — (1) (4) — 1 (14)
Hedging and other revenues (a) 25 404 81 61 15 11 20 617
Affiliate sales — 1,027 335 35 96 — (1,493) —
Total other revenues 15 1,431 416 95 107 11 (1,472) 603
Total revenues $ 1,421 $ 1,671 $ 686 $ 254 $ 188 $ 58 $ (1,446) $ 2,832

~~____________~~

~~(a)Includes $538 million of unrealized net gains from mark-to-market valuations of commodity positions. See Note 17~~16 for unrealized net gains (losses) by segment.


		Six Months Ended June 30, 2020																															Six Months Ended June 30, 2021
		Retail		ERCOT		PJM		NY/NE		MISO		Asset Closure		CAISO/Eliminations		Consolidated			Retail		Texas		East		West		Sunset		Asset Closure		Eliminations		Consolidated
Revenue from contracts with customers:	Revenue from contracts with customers:																	Revenue from contracts with customers:
Retail energy charge in ERCOT	Retail energy charge in ERCOT	$	2,665	$	—	$	—	$	—	$	—	$	—	$	—	$	2,665	Retail energy charge in ERCOT	$	2,565	$	0	$	0	$	0	$	0	$	0	$	0	$	2,565
Retail energy charge in Northeast/Midwest	Retail energy charge in Northeast/Midwest	1,180		—		—		—		—		—		—		1,180		Retail energy charge in Northeast/Midwest	1,091		0		0		0		0		0		0		1,091
Wholesale generation revenue from ISO/RTO	Wholesale generation revenue from ISO/RTO	—		174		148		58		17		—		46		443		Wholesale generation revenue from ISO/RTO	0		3,374		252		69		908		0		0		4,603
Capacity revenue from ISO/RTO(a)	Capacity revenue from ISO/RTO(a)	—		—		30		35		9		—		—		74		Capacity revenue from ISO/RTO(a)	0		0		(2)		0		82		0		0		80
Revenue from other wholesale contracts	Revenue from other wholesale contracts	—		113		288		38		103		—		25		567		Revenue from other wholesale contracts	0		2,084		293		46		102		0		0		2,525
Total revenue from contracts with customers	Total revenue from contracts with customers	3,845		287		466		131		129		—		71		4,929		Total revenue from contracts with customers	3,656		5,458		543		115		1,092		0		0		10,864
Other revenues:	Other revenues:																	Other revenues:
Intangible amortization	Intangible amortization	(8)		—		—		—		(11)		—		—		(19)		Intangible amortization	(3)		0		74		0		(8)		0		0		63
Hedging and other revenues ~~(a)~~(b)	Hedging and other revenues ~~(a)~~(b)	27		313		32		29		2		—		54		457		Hedging and other revenues ~~(a)~~(b)	16		(4,450)		195		(36)		(880)		0		0		(5,155)
Affiliate sales(c)	Affiliate sales(c)	—		1,131		562		257		143		—		(2,093)		—		Affiliate sales(c)	0		(393)		418		2		26		0		(53)		0
Total other revenues	Total other revenues	19		1,444		594		286		134		—		(2,039)		438		Total other revenues	13		(4,843)		687		(34)		(862)		0		(53)		(5,092)
Total revenues	Total revenues	$	3,864	$	1,731	$	1,060	$	417	$	263	$	—	$	(1,968)	$	5,367	Total revenues	$	3,669	$	615	$	1,230	$	81	$	230	$	0	$	(53)	$	5,772

____________

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

Table of Contents

(c)Texas segment includes $1.625 billion of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment.


	Six Months Ended June 30, 2020
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations		Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	2,665	$	0	$	0	$	0	$	0	$	0	$	0	$	2,665
Retail energy charge in Northeast/Midwest	1,180		0		0		0		0		0		0		1,180
Wholesale generation revenue from ISO/RTO	0		156		98		46		142		1		0		443
Capacity revenue from ISO/RTO (a)	0		0		(9)		0		83		0		0		74
Revenue from other wholesale contracts	0		113		326		25		103		0		0		567
Total revenue from contracts with customers	3,845		269		415		71		328		1		0		4,929
Other revenues:
Intangible amortization	(8)		0		0		0		(11)		0		0		(19)
Hedging and other revenues (b)	27		301		(43)		54		117		1		0		457
Affiliate sales	0		1,132		817		2		144		0		(2,095)		0
Total other revenues	19		1,433		774		56		250		1		(2,095)		438
Total revenues	$	3,864	$	1,702	$	1,189	$	127	$	578	$	2	$	(2,095)	$	5,367

____________

(b)Includes $131 million of unrealized net gains from mark-to-market valuations of commodity positions. See Note ~~17 for unrealized net gains (losses) by segment.~~

~~Table of Contents~~

Six Months Ended June 30, 2019
Retail ERCOT PJM NY/NE MISO Asset
Closure CAISO/Eliminations Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT $ 2,116 $ — $ — $ — $ — $ — $ — $ 2,116
Retail energy charge in Northeast/Midwest 663 — — — — — — 663
Wholesale generation revenue from ISO/RTO — 435 351 276 104 110 95 1,371
Capacity revenue from ISO/RTO — — 120 152 18 6 — 296
Revenue from other wholesale contracts — 97 159 12 55 2 6 331
Total revenue from contracts with customers 2,779 532 630 440 177 118 101 4,777
Other revenues:
Intangible amortization (19) — — (3) (9) — 2 (29)
Hedging and other revenues (a) 46 562 171 113 29 25 61 1,007
Affiliate sales — 1,531 590 49 160 — (2,330) —
Total other revenues 27 2,093 761 159 180 25 (2,267) 978
Total revenues $ 2,806 $ 2,625 $ 1,391 $ 599 $ 357 $ 143 $ (2,166) $ 5,755

~~____________~~

~~(a)Includes $697 million of unrealized net gains from mark-to-market valuations of commodity positions. See Note 17~~16 for unrealized net gains (losses) by segment.

Performance Obligations

As of June 30, ~~2020,~~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 or~~ ISO/RTO or contracts with customers. Therefore, an obligation exists as of the date of the results of the respective ~~ISO or~~ ISO/RTO capacity auction or the contract execution date. These obligations total ~~$390~~$464 million, ~~$826~~$661 million, ~~$479~~$245 million, ~~$121~~$147 million and ~~$38~~$98 million that will be recognized, in the balance of the year ended December 31, ~~2020~~2021 and the years ending December 31, ~~2021,~~ 2022, 2023, 2024 and ~~2024,~~2025, respectively, and ~~$18~~$484 million thereafter. Capacity revenues are recognized as capacity is made available to the related ~~ISOs or~~ ISOs/RTOs or counterparties.

Accounts Receivable

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


		June 30, 2020		December 31, 2019			June 30, 2021		December 31, 2020
Trade accounts receivable from contracts with customers — net	Trade accounts receivable from contracts with customers — net	$	1,197	$	1,246	Trade accounts receivable from contracts with customers — net	$	1,266	$	1,169
Other trade accounts receivable — net	Other trade accounts receivable — net	75		119		Other trade accounts receivable — net	86		110
Total trade accounts receivable — net	Total trade accounts receivable — net	$	1,272	$	1,365	Total trade accounts receivable — net	$	1,352	$	1,279

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6.5. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

Goodwill

~~The following table provides information regarding our goodwill balance. There have been no impairments of goodwill.~~


~~Balance at December 31, 2019~~	$	~~2,553~~
~~Measurement period adjustments recorded in connection with the Ambit Transaction~~	29
~~Measurement period adjustments recorded in connection with the Crius Transaction~~	~~(14)~~
~~Balance at June 30, 2020~~	$	~~2,568~~

At both June 30, 2021 and December 31, 2020, the carrying value of goodwill ~~balance of $2.568~~totaled $2.583 billion, ~~consisted of the following:~~

•~~$1.907~~including $2.461 billion ~~arose in connection with our application of fresh start reporting at Emergence and was~~ allocated ~~entirely~~ to our Retail reporting unit and $122 million allocated to our Texas Generation reporting unit. ~~Of the goodwill recorded at Emergence, $1.686~~Goodwill of $1.944 billion is deductible for tax purposes over 15 years on a ~~straight-line~~straight line basis.

•$175 million arose in connection with the Merger, of which $122 million was allocated to our ERCOT Generation reporting unit and $53 million was allocated to our Retail reporting unit. None of the goodwill related to the Merger is deductible for tax purposes.

•$243 million of goodwill arose in connection with the Crius Transaction and was allocated entirely to our Retail reporting unit. None of the goodwill related to the Crius Transaction is deductible for tax purposes.

•$243 million of preliminary goodwill arose in connection with the Ambit Transaction and is allocated entirely to our Retail reporting unit pending completion of the purchase price allocation. The goodwill related to the Ambit Transaction is deductible for tax purposes over 15 years on a straight-line basis.

Identifiable Intangible Assets and Liabilities

Identifiable intangible assets are comprised of the following:


		June 30, 2020										December 31, 2019											June 30, 2021				December 31, 2020
Identifiable Intangible Asset	Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net		Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	Retail customer relationship	$	2,087	$	1,302	$	785	$	2,078	$	1,151	$	927	Retail customer relationship	$	2,082	$	1,532	$	550	$	2,082	$	1,434	$	648
Software and other technology-related assets	Software and other technology-related assets	364		151		213		341		125		216		Software and other technology-related assets	434		215		219		414		186		228
Retail and wholesale contracts	Retail and wholesale contracts	272		195		77		315		182		133		Retail and wholesale contracts	248		197		51		272		204		68
Contractual service agreements (a)	Contractual service agreements (a)	55		2		53		59		5		54		Contractual service agreements (a)	32		0		32		51		1		50
Other identifiable intangible assets (b)	Other identifiable intangible assets (b)	45		17		28		40		15		25		Other identifiable intangible assets (b)	83		20		63		96		19		77
Total identifiable intangible assets subject to amortization	Total identifiable intangible assets subject to amortization	$	2,823	$	1,667	1,156		$	2,833	$	1,478	1,355		Total identifiable intangible assets subject to amortization	$	2,879	$	1,964	915		$	2,915	$	1,844	1,071
Retail trade names (not subject to amortization)	Retail trade names (not subject to amortization)					1,374						1,391		Retail trade names (not subject to amortization)					1,374						1,374
Mineral interests (not currently subject to amortization)	Mineral interests (not currently subject to amortization)					2						2		Mineral interests (not currently subject to amortization)					1						1
Total identifiable intangible assets	Total identifiable intangible assets					$	2,532					$	2,748	Total identifiable intangible assets					$	2,290					$	2,446

____________

(a)At June 30, ~~2020,~~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).

~~Table of Contents~~

Identifiable intangible liabilities are comprised of the following:


Identifiable Intangible Liability	Identifiable Intangible Liability	June 30, 2020		December 31, 2019		Identifiable Intangible Liability	June 30, 2021		December 31, 2020
Contractual service agreements	Contractual service agreements	$	127	$	110	Contractual service agreements	$	125	$	129
Purchase and sale of power and capacity	Purchase and sale of power and capacity	92		100		Purchase and sale of power and capacity	11		87
Fuel and transportation purchase contracts	Fuel and transportation purchase contracts	75		76		Fuel and transportation purchase contracts	16		73
Total identifiable intangible liabilities	Total identifiable intangible liabilities	$	294	$	286	Total identifiable intangible liabilities	$	152	$	289

Table of Contents

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


Identifiable Intangible Assets and Liabilities	Identifiable Intangible Assets and Liabilities	Condensed Consolidated Statements of Operations	Three Months Ended June 30,						Six Months Ended June 30,										Identifiable Intangible Assets and Liabilities			Condensed Consolidated Statements of Operations	Three Months Ended June 30,				Six Months Ended June 30,
					2020		2019		2020			2019			Identifiable Intangible Assets and Liabilities			Condensed Consolidated Statements of Operations		2021			2020		2021		2020
Retail customer relationship	Retail customer relationship	Depreciation and amortization	$	77	$	55	$	151	$	111	Retail customer relationship			Depreciation and amortization		$	50			$	77		$	98	$	151
Software and other technology-related assets	Software and other technology-related assets	Depreciation and amortization	21		15		38		29		Software and other technology-related assets			Depreciation and amortization		20				21			38		38
Retail and wholesale contracts/purchase and sale/fuel and transportation contracts	Retail and wholesale contracts/purchase and sale/fuel and transportation contracts	Operating revenues/fuel, purchased power costs and delivery fees	13		12		15		24		Retail and wholesale contracts/purchase and sale/fuel and transportation contracts			Operating revenues/fuel, purchased power costs and delivery fees		(69)				13			(61)		15
Other identifiable intangible assets	Other identifiable intangible assets	Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization	44		15		96		39		Other identifiable intangible assets			Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization		48				44			105		96
Total intangible asset expense (a)	Total intangible asset expense (a)				$	155	$	97	$	300		$	203		Total intangible asset expense (a)					$	49		$	155	$	180	$	300

____________

(a)Amounts recorded in depreciation and amortization totaled ~~$99~~$70 million and ~~$72~~$99 million for the three months ended June 30, ~~2020~~2021 and ~~2019,~~2020, respectively and ~~$190~~$138 million and ~~$141~~$190 million for the six months ended June 30, ~~2020~~2021 and ~~2019, respectively.~~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 ~~credit~~certificate obligations are accrued as retail electricity delivery occurs.

Estimated Amortization of Identifiable Intangible Assets and Liabilities

As of June 30, ~~2020,~~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	Year	Estimated Amortization Expense		Year	Estimated Amortization Expense
2020		$	369
2021	2021	$	257	2021	$	210
2022	2022	$	161	2022	$	190
2023	2023	$	116	2023	$	136
2024	2024	$	78	2024	$	87
2025				2025	$	62

7.6. INCOME TAXES

Income Tax Expense

The calculation of our effective tax rate is as follows:

Three Months Ended June 30, Six Months Ended June 30,
2020 2019 2020 2019
Income before income taxes $ 232 $ 502 $ 293 $ 803
Income tax expense $ (68) $ (148) $ (84) $ (225)
Effective tax rate 29.3 % 29.5 % 28.7 % 28.0 %


	Three Months Ended June 30,						Six Months Ended June 30,
	2021			2020			2021			2020
Income (loss) before income taxes	$	(80)		$	232		$	(2,604)		$	293
Income tax (expense) benefit	$	115		$	(68)		$	600		$	(84)
Effective tax rate	143.8		%	29.3		%	23.0		%	28.7		%

For the three months ended June 30, 2021, the effective tax rate of 143.8% was higher than the U.S. federal statutory rate of 21% due primarily to nondeductible impacts of the TRA and state income taxes, including the impact of a decrease in our state valuation allowances primarily due to newly enacted state tax legislation. For the six months ended June 30, 2021, the effective tax rate of 23.0% was higher than the U.S. federal statutory rate of 21% due primarily to nondeductible impacts of the TRA and state income taxes.

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For the three months ended June 30, 2020, the effective tax rate of 29.3% was higher that the U.S. federal statutory rate of 21% due primarily to nondeductible impacts of the TRA and state income taxes. For the six months ended June 30, 2020, the effective tax rate of 28.7% was higher than the U.S. federal statutory rate of 21% due primarily to nondeductible impacts of the TRA and state income taxes.

For the three months ended June 30, 2019, the effective tax rate of 29.5% 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 a partial valuation allowance on the state of Illinois net operating loss. For the six months ended June 30, 2019, the effective tax rate of 28.0% was higher than the U.S. federal statutory rate of 21% due primarily to nondeductible impacts of the TRA and state income taxes, including the impact of a partial valuation allowance on the state of Illinois net operating loss.

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 ~~President~~CARES Act was signed into law ~~the CARES Act on~~in March ~~27,~~ 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. ~~While Vistra is still evaluating~~Additionally, the ~~impact of certain tax-related benefits available under the CARES Act, we anticipate the acceleration of AMT refunds and the expansion of the~~final Section 163(j) ~~limitation from 30%~~regulations were issued in July 2020 and provided a critical correction to ~~50%~~the proposed regulations with respect to the computation of adjusted taxable ~~income to have material impacts to Vistra. Specifically, we expect~~income. Vistra expects to receive ~~approximately $64 million in 2020 relating to the acceleration of AMT refunds and~~ an approximate ~~$550~~$298 million increase in interest expense deduction ~~over~~in the ~~2019 and 2020~~2021 tax ~~years~~year under the final Section 163(j). regulations. We do not anticipate a material impact to the effective tax rate from ~~these impacts.~~this impact. Vistra ~~will continue~~also utilized the CARES Act payroll deferral mechanism to ~~monitor legislative developments related~~defer the payment of approximately $20 million from 2020 to ~~COVID-19.~~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 ~~state~~foreign jurisdictions and are, ~~expected to be~~at times, subject to examinations by the IRS and other taxing authorities. In February 2021, Vistra ~~is not currently under audit by~~was notified that the IRS had opened a federal income tax audit for ~~any period, although review of Dynegy's final pre-acquisition~~tax years 2018 and 2019 and an employment tax audit for tax year ~~2018 continues to progress through the IRS's Compliance Assurance Process audit program.~~2018. Crius is currently under audit by the IRS for the tax years 2015 ~~2016~~ and ~~2017.~~2016. Uncertain tax positions totaled ~~$125~~$40 million and ~~$126~~$39 million at June 30, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively. The final regulations under Section 163(j) were released in July 2020. While we are still evaluating the impact, we expect to adjust deferred tax assets and deferred tax liabilities in the third quarter of 2020 and do not expect the final regulation to materially impact our effective tax rate.

8.7. 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~~2 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 ~~16)~~15).

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The following table summarizes the changes to the TRA obligation, reported as other current liabilities and Tax Receivable Agreement obligation in our condensed consolidated balance sheets, for the six months ended June 30, ~~2020~~2021 and ~~2019:~~2020:


		Six Months Ended June 30,							Six Months Ended June 30,
		2020		2019			2021		2020
TRA obligation at the beginning of the period	TRA obligation at the beginning of the period	$	455	$	420	TRA obligation at the beginning of the period	$	450	$	455
Accretion expense	Accretion expense	34		31		Accretion expense	32		34
Changes in tax assumptions impacting timing of payments (a)	Changes in tax assumptions impacting timing of payments (a)	(20)		(67)		Changes in tax assumptions impacting timing of payments (a)	(28)		(20)
Impacts of Tax Receivable Agreement	Impacts of Tax Receivable Agreement	14		(36)		Impacts of Tax Receivable Agreement	4		14

TRA obligation at the end of the period	TRA obligation at the end of the period	469		384		TRA obligation at the end of the period	454		469
Less amounts due currently	Less amounts due currently	(1)		—		Less amounts due currently	(3)		(1)
TRA obligation at the end of the period (noncurrent)		$	468	$	384
Noncurrent TRA obligation at the end of the period						Noncurrent TRA obligation at the end of the period	$	451	$	468

____________

(a)During the three months ended June 30, 2021, we recorded an increase to the carrying value of the TRA obligation totaling $26 million as a result of adjustments to forecasted taxable income. During the six months ended June 30, 2021, we recorded a decrease to the carrying value of the TRA obligation totaling $28 million as a result of adjustments to

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forecasted taxable income including the financial impacts of Winter Storm Uri. During the three and six months ended June 30, 2020, we recorded decreases of $11 million and $20 million, respectively, to the carrying value of the TRA obligation ~~totaling $11 million and $20 million, respectively,~~ 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. During the three and six months ended June 30, 2019, we recorded decreases to the carrying value of the TRA obligation totaling $48 million and $67 million, respectively, as a result of adjustments to forecasted taxable income and higher net operating losses acquired in the Merger.

As of June 30, ~~2020,~~2021, the estimated carrying value of the TRA obligation totaled ~~$469~~$454 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 June 30, ~~2020,~~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.

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9.8. 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 June 30, Six Months Ended June 30,
2020 2019 2020 2019
Net income attributable to common stock — basic $ 166 $ 356 $ 222 $ 581
Weighted average shares of common stock outstanding — basic (a) 488,680,442 499,778,235 488,312,503 499,213,522
Net income per weighted average share of common stock outstanding — basic $ 0.34 $ 0.71 $ 0.45 $ 1.16
Dilutive securities: Stock-based incentive compensation plan 1,788,293 7,722,148 2,397,429 8,035,398
Weighted average shares of common stock outstanding — diluted 490,468,735 507,500,383 490,709,932 507,248,920
Net income per weighted average share of common stock outstanding — diluted $ 0.34 $ 0.70 $ 0.45 $ 1.15

~~____________~~

~~(a)~~For the three and six months ended June 30, 2019, the minimum settlement amount of tangible equity units, or 15,207,600 shares, are considered to be outstanding and are included in the computation of basic net income per share.


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Net income (loss) attributable to common stock — basic	$	36	$	166	$	(2,006)	$	222
Weighted average shares of common stock outstanding — basic	486,022,633		488,680,442		485,364,606		488,312,503
Net income (loss) per weighted average share of common stock outstanding — basic	$	0.07	$	0.34	$	(4.13)	$	0.45
Dilutive securities: Stock-based incentive compensation plan	1,343,593		1,788,293		0		2,397,429
Weighted average shares of common stock outstanding — diluted	487,366,226		490,468,735		485,364,606		490,709,932
Net income (loss) per weighted average share of common stock outstanding — diluted	$	0.07	$	0.34	$	(4.13)	$	0.45

Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 14,433,851 and 13,978,168 ~~and 2,910,226 for~~in the three months ended June 30, ~~2020~~2021 and ~~2019,~~2020, respectively, and ~~12,123,691~~15,734,553 and ~~7,577,246~~12,123,691 shares for the six months ended June 30, ~~2020~~2021 and ~~2019,~~2020, respectively.

~~10.~~9. ACCOUNTS RECEIVABLE ~~SECURITIZATION PROGRAM~~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 ~~2020,~~2021, extending the term of the Receivables Facility ~~from July 2020~~ to July ~~2021,~~2022, with the ability to borrow ~~$550~~$600 million beginning with the settlement date in July ~~2020~~2021 until the settlement date in August ~~2020, $625~~2021, $725 million from the settlement date in August ~~2020~~2021 until the settlement date in November ~~2020, $550~~2021 and $600 million from the settlement date in November ~~2020 until the settlement date in December 2020~~2021 and ~~$450 million~~ thereafter for the remaining term of the Receivables Facility.

~~Under~~

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In connection with the Receivables Facility, TXU Energy, ~~and~~ Dynegy Energy Services, ~~are obligated to~~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, ~~on an ongoing basis~~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 ~~without recourse, their accounts receivable~~related rights (Receivables), to ~~TXU Energy's special purpose subsidiary,~~ RecCo, a consolidated, wholly owned, bankruptcy-remote, direct subsidiary of TXU Energy. RecCo, in turn, is subject to certain conditions, and may ~~from time to time, sell an undivided interest in all~~draw under the ~~receivables acquired from TXU Energy and Dynegy Energy Services~~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 ~~its assets and credit are not available~~Vistra Operations has agreed to ~~satisfy~~guarantee the ~~debts and~~ obligations ~~of any person, including affiliates of RecCo.~~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 ~~trade receivables~~Receivables on behalf of RecCo and the Purchasers, as applicable.

As of June 30, ~~2020,~~2021, outstanding borrowings under the ~~receivables facility~~Receivables Facility totaled ~~$450~~$536 million and were supported by ~~$639~~$831 million of RecCo gross receivables. As of December 31, ~~2019,~~2020, outstanding borrowings under the ~~receivables facility~~Receivables Facility totaled ~~$450~~$300 million and were supported by ~~$629~~$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.

As of June 30, 2021, outstanding borrowings under the Repurchase Facility totaled $125 million. There were 0 outstanding borrowings at December 31, 2020.

1715

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~~11.~~10. LONG-TERM DEBT

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


		June 30, 2020		December 31, 2019			June 30, 2021		December 31, 2020
Vistra Operations Credit Facilities	Vistra Operations Credit Facilities	$	2,586	$	2,700	Vistra Operations Credit Facilities	$	2,557	$	2,572
Vistra Operations Senior Secured Notes:	Vistra Operations Senior Secured Notes:					Vistra Operations Senior Secured Notes:
3.550% Senior Secured Notes, due July 15, 2024	3.550% Senior Secured Notes, due July 15, 2024	1,500		1,500		3.550% Senior Secured Notes, due July 15, 2024	1,500		1,500
3.700% Senior Secured Notes, due January 30, 2027	3.700% Senior Secured Notes, due January 30, 2027	800		800		3.700% Senior Secured Notes, due January 30, 2027	800		800
4.300% Senior Secured Notes, due July 15, 2029	4.300% Senior Secured Notes, due July 15, 2029	800		800		4.300% Senior Secured Notes, due July 15, 2029	800		800
Total Vistra Operations Senior Secured Notes	Total Vistra Operations Senior Secured Notes	3,100		3,100		Total Vistra Operations Senior Secured Notes	3,100		3,100
Vistra Operations Senior Unsecured Notes:	Vistra Operations Senior Unsecured Notes:					Vistra Operations Senior Unsecured Notes:
5.500% Senior Unsecured Notes, due September 1, 2026	5.500% Senior Unsecured Notes, due September 1, 2026	1,000		1,000		5.500% Senior Unsecured Notes, due September 1, 2026	1,000		1,000
5.625% Senior Unsecured Notes, due February 15, 2027	5.625% Senior Unsecured Notes, due February 15, 2027	1,300		1,300		5.625% Senior Unsecured Notes, due February 15, 2027	1,300		1,300
5.000% Senior Unsecured Notes, due July 31, 2027	5.000% Senior Unsecured Notes, due July 31, 2027	1,300		1,300		5.000% Senior Unsecured Notes, due July 31, 2027	1,300		1,300
4.375% Senior Secured Notes, due May 15, 2029						4.375% Senior Secured Notes, due May 15, 2029	1,250		0
Total Vistra Operations Senior Unsecured Notes	Total Vistra Operations Senior Unsecured Notes	3,600		3,600		Total Vistra Operations Senior Unsecured Notes	4,850		3,600
Vistra Senior Unsecured Notes:
5.875% Senior Unsecured Notes, due June 1, 2023		—		500
8.000% Senior Unsecured Notes, due January 15, 2025		—		81
8.125% Senior Unsecured Notes, due January 30, 2026 (a)		166		166
Total Vistra Senior Unsecured Notes		166		747

Other:	Other:					Other:
Forward Capacity Agreements	Forward Capacity Agreements	101		161		Forward Capacity Agreements	473		45
Equipment Financing Agreements	Equipment Financing Agreements	91		99		Equipment Financing Agreements	92		68
8.82% Building Financing due semiannually through February 11, 2022 (b)		13		15
8.82% Building Financing due semiannually through February 11, 2022 (a)						8.82% Building Financing due semiannually through February 11, 2022 (a)	6		10
Other	Other	4		12		Other	3		3
Total other long-term debt	Total other long-term debt	209		287		Total other long-term debt	574		126
Unamortized debt premiums, discounts and issuance costs (c)		(63)		(55)
Unamortized debt premiums, discounts and issuance costs (b)						Unamortized debt premiums, discounts and issuance costs (b)	(86)		(68)
Total long-term debt including amounts due currently	Total long-term debt including amounts due currently	9,598		10,379		Total long-term debt including amounts due currently	10,995		9,330
Less amounts due currently	Less amounts due currently	(337)		(277)		Less amounts due currently	(511)		(95)
Total long-term debt less amounts due currently	Total long-term debt less amounts due currently	$	9,261	$	10,102	Total long-term debt less amounts due currently	$	10,484	$	9,235

____________

(a)~~Vistra redeemed all of its outstanding 8.125% senior unsecured notes due 2026 in July 2020.~~

~~(b)~~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 ~~other noncurrent~~current assets in our condensed consolidated balance sheets.

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

Vistra Operations Credit Facilities

At June 30, ~~2020,~~2021, the Vistra Operations Credit Facilities consisted of up to ~~$5.311~~$5.282 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 ~~$2.586~~$2.557 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 six months ended June 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 and cancelled them.~~$93.875. We recorded an extinguishment gain of $6 million on the transaction in the six months ended June 30, 2020.

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During the six months ended June 30, ~~2020,~~2021, we borrowed ~~$925 million~~$1.3 billion and repaid ~~$725 million~~$1.3 billion under the Revolving Credit Facility, with proceeds from the borrowings used for general corporate purposes.

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In June 2019, Vistra Operations used the net proceeds from the June 2019 Senior Secured Notes Offerings (described below) to repay $889 million under the Term Loan B-1 Facility, the entire amount outstanding of $977 million under Term Loan B-2 Facility (and together with the Term Loan B-1 Facility and the Term Loan B-3 Facility, the Term Loan B Facility) and $134 million under the Term Loan B-3 Facility. We recorded an extinguishment loss of $4 million on the transactions in the three months ended June 30, 2019.

In March 2019 and May 2019 the Vistra Operations Credit Facilities were amended whereby we obtained $225 million of incremental Revolving Credit Facility commitments. The letter of credit sub-facility was also increased by $50 million. Fees and expenses related to the amendments to the Vistra Operations Credit Facilities totaled $2 million for the six months ended June 30, 2019, which were capitalized as a noncurrent asset.

The Vistra Operations Credit Facilities and related available capacity at June 30, ~~2020~~2021 are presented below.


			June 30, 2020												June 30, 2021
Vistra Operations Credit Facilities	Vistra Operations Credit Facilities	Maturity Date	Facility Limit		Cash Borrowings		Available Capacity		Vistra Operations Credit Facilities	Maturity Date	Facility Limit		Cash Borrowings		Letters of Credit Outstanding		Available Capacity
Revolving Credit Facility (a)	Revolving Credit Facility (a)	June 14, 2023	$	2,725	$	550	$	1,287	Revolving Credit Facility (a)	June 14, 2023	$	2,725	$	0	$	832	$	1,893
Term Loan B-3 Facility		December 31, 2025	2,586		2,586		—

Term Loan B-3 Facility (b)									Term Loan B-3 Facility (b)	December 31, 2025	2,557		2,557		0		0
Total Vistra Operations Credit Facilities	Total Vistra Operations Credit Facilities		$	5,311	$	3,136	$	1,287	Total Vistra Operations Credit Facilities		$	5,282	$	2,557	$	832	$	1,893

___________

(a)Revolving Credit Facility ~~to be~~ used for general corporate purposes. The Facility includes a $2.35 billion letter of credit ~~sub-facility, of which $888 million of letters~~sub-facility. Letters of credit ~~were~~ outstanding ~~at June 30, 2020 and which~~ 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 June 30, ~~2020,~~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 ~~$550 million~~0 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 June 30, ~~2020,~~2021, the weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings was ~~1.93% including both the Revolving Credit Facility and the Term Loan B-3 Facility.~~1.85%. 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.

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The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties, material breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against Vistra Operations. Solely with respect to the Revolving Credit Facility, and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $300 million) exceed 30% of the revolving commitments), the agreement includes a covenant that requires the consolidated first lien net leverage ratio, which is based on the ratio of net ~~first-lien~~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. ~~As of~~Although the period ended June 30, ~~2020,~~2021 was not a compliance period, we ~~were~~would have been in compliance with this financial ~~covenant.~~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 June 30, ~~2020,~~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 ~~$2.120~~$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 ~~$2.3~~$2.30 billion of debt through July 2026.

~~Alternate~~Secured Letter of Credit Facilities

~~Two alternate~~In 2020, Vistra entered into uncommitted standby letter of credit facilities ~~(each, an Alternative LOC Facility, and collectively, the Alternate~~(Secured LOC Facilities) that are each secured by a first lien on substantially all of Vistra Operations' (and its subsidiaries') assets (which ranks pari passu with ~~an aggregate~~the Vistra Operations Credit Facilities). The facility ~~limit of $500 million became effective in the year ended December 31, 2019.~~is to be used for general corporate purposes. At June 30, ~~2020, $500~~2021, $323 million of letters of credit were outstanding under the ~~Alternate~~Secured LOC Facilities. ~~Of the total facility limit,~~

Alternate Letter of Credit Facility

At June 30, 2021, $250 million ~~matures in December 2020 and~~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 ~~the six months ended June 30,~~ 2019, Vistra Operations issued and sold ~~$2.0~~$3.1 billion aggregate principal amount of senior secured notes ~~(June 2019 Senior Secured Notes)~~ in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities ~~Act (June 2019 Senior Secured Notes Offerings) consisting of the following:~~

Senior Secured Notes Maturity Year Interest Terms
(Due Semiannually in Arrears) June 2019
Senior Secured Notes Offerings (a)
3.550% Senior Secured Notes 2024 January 15 and July 15 $ 1,200
4.300% Senior Secured Notes 2029 January 15 and July 15 800
Total senior secured notes $ 2,000
Net proceeds $ 1,976
Debt issuance and other fees (b) $ 20

~~___________~~

~~(a)~~The June 2019 Senior Secured Notes were sold pursuant to a purchase agreement by and among Vistra Operations, certain direct and indirect subsidiaries of Vistra Operations and Citigroup Global Markets Inc., as representative of the several initial purchasers. Net proceeds, together with cash on hand, were used to prepay certain amounts outstanding and accrued interest (together with fees and expenses) under the Vistra Operations Credit Facility's Term Loan B Facility.

~~(b)Capitalized as a reduction in the carrying amount of the debt.~~

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Act. The indenture (as may be amended or supplemented from time to time, the Vistra Operations Senior Secured Indenture) governing the ~~June 2019 Senior Secured Notes and~~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 ~~the six months ended June 30, 2019,~~May 2021, Vistra Operations issued and sold ~~$2.6~~$1.250 billion aggregate principal amount of 4.375% senior unsecured notes due 2029 in ~~offerings (the February 2019 Senior Unsecured Notes Offering and the June 2019 Senior Unsecured Notes Offering)~~an offering to eligible purchasers under Rule 144A and Regulation S under the Securities ~~Act consisting of the following:~~

Senior Unsecured Notes Maturity Year Interest Terms
(Due Semiannually in Arrears) February 2019 Senior Unsecured Notes Offering (a) June 2019
Senior Unsecured Notes Offering (b)
5.625% Senior Unsecured Notes 2027 February 15 and August 15 1,300 —
5.000% Senior Unsecured Notes 2027 January 31 and July 31 — 1,300
Total $ 1,300 $ 1,300
Net Proceeds $ 1,287 $ 1,287
Debt issuance and other fees (c) $ 16 $ 13

~~___________~~

~~(a)~~Act. The ~~5.625%~~4.375% senior unsecured notes due ~~2027 (the February 2019 Senior Unsecured Notes)~~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 ~~pay~~repay all amounts outstanding under the ~~purchase price~~Term Loan A Facility and ~~accrued interest (together with~~to pay fees and ~~expenses) required in connection with (i)~~expenses of $15 million related to the ~~February 2019 Tender Offer (defined below)~~offering.

Since 2018, Vistra Operations has issued and ~~(ii) the redemption of approximately $35 million~~sold $4.85 billion aggregate principal amount of ~~our 7.375%~~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 ~~2022 (7.375% senior notes) and approximately $25 million aggregate principal amount of our outstanding 8.034%~~2026, the 5.625% senior unsecured notes due ~~2024 (8.034% senior notes).~~

~~(b)The~~2027, the 5.000% senior unsecured notes due 2027 ~~(the June 2019 Senior Unsecured Notes) were sold pursuant to a purchase agreement by~~ and ~~among Vistra Operations,~~ the Guarantor Subsidiaries and Goldman Sachs & Co. LLC, as representative of the several initial purchasers. Net proceeds, together with cash on hand, were used to pay the purchase price and accrued interest (together with fees and expenses) required in connection with (i) the June 2019 Tender Offer (defined below) and (ii) the redemption of approximately $306 million of our outstanding 7.375% senior notes and approximately $87 million of our 7.625%4.375% senior unsecured notes due ~~2024 (7.625% senior notes) in July 2019. We recorded an extinguishment gain of $2 million on the redemptions in the six months ended June 30, 2019.~~

~~(c)Capitalized as a reduction in the carrying amount of the debt.~~

~~The indentures governing the June 2019 Senior Unsecured Notes, the February 2019 Senior Unsecured Notes and the 5.500% senior unsecured notes due 2026~~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.

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Debt Repurchase Program

In November 2018, our board of directors (the Board) authorized a bond repurchase program under which up to $200 million principal amount of outstanding Vistra Senior Unsecured Notes could be repurchased. In July 2019, the Board authorized up to $1.0 billion to repay or repurchase any outstanding debt of the Company (or its subsidiaries), with that authority superseding the remaining availability under the $200 million bond repurchase program. Through April 2020, $684 million amount of debt had been repurchased under the $1.0 billion July 2019 authorization, including the repurchase of $100 million principal amount of Term Loan B-3 Facility borrowings discussed above and the redemption of $81 million aggregate principal amount outstanding of 8.000% senior unsecured notes due 2025 (8.000% senior notes) discussed below. In April 2020, the ~~Board~~Company's board of directors (Board) authorized up to $1.0 billion to repay or repurchase additional outstanding ~~debt, with this new authority superseding and replacing the $316 million of availability under the previously authorized $1.0 billion debt repurchase program.~~debt. Through ~~July 31, 2020,~~February 2021, approximately $666 million had been repurchased under the ~~$1.0~~authorization. In March 2021, the Board authorized up to $1.8 billion ~~April 2020~~to repay or repurchase additional outstanding debt, which authorization ~~consisting of~~superseded any amounts that remained outstanding under any previous authorizations. Through June 30, 2021, 0 debt had been repurchased under the redemption of the Vistra 5.875% senior unsecured notes due 2023 (5.875% senior notes) and the redemption of the Vistra 8.125% senior unsecured notes due 2026 (8.125% senior notes), each as described below.March 2021 authorization.

Vistra Senior Unsecured Notes

~~July~~June 2020 Redemption — In July 2020, Vistra redeemed the entire $166 million aggregate principal amount of 8.125% senior notes, at a redemption price equal to 104.063% of the aggregate principal amount thereof, plus accrued and unpaid interest to, but excluding, the date of redemption (July 2020 Redemption). Following the July 2020 Redemption, Vistra had no outstanding senior notes at the Parent level.

~~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 (the June 2020 Redemption).~~redemption. We recorded an extinguishment gain of $3 million on the transaction in the six months ended June 30, 2020.

January 2020 Redemption — In January 2020, Vistra redeemed the entire $81 millionaggregate 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 (January 2020 Redemption, and together with the June 2020 Redemption and the July 2020 Redemption, the Redemptions).~~redemption. We recorded an extinguishment gain of $2 million on the transaction in the six months ended June 30, 2020.

~~June 2019 Tender Offer~~ — In June 2019, Vistra used the net proceeds from the June 2019 Senior Unsecured Notes Offering to fund a cash tender offer (June 2019 Tender Offer) to purchase for cash $845 million aggregate principal amount of certain notes assumed in the Merger, including $173 million of 7.375% senior notes and $672 million of 7.625% senior notes. We recorded an extinguishment gain of $7 million on the transactions in the six months ended June 30, 2019. In July 2019, Vistra accepted and settled an additional approximately $1 million aggregate principal amount of outstanding 7.625% senior notes that were tendered after the early tender date of the June 2019 Tender Offer.

~~February 2019 Tender Offer and Consent Solicitation~~ — In February 2019, Vistra used the net proceeds from the February 2019 Senior Unsecured Notes Offering to fund a cash tender offer (February 2019 Tender Offer, and together with the June 2019 Tender Offer, the Tender Offers) to purchase for cash $1.193 billion aggregate principal amount of 7.375% senior notes assumed in the Merger. We recorded an extinguishment gain of $7 million on the transactions in the six months ended June 30, 2019.

In connection with the February 2019 Tender Offer, Vistra also commenced a solicitation of consents from holders of the 7.375% senior notes. Vistra received the requisite consents from the holders of the 7.375% senior notes and amended the indenture governing these senior notes to, among other things, eliminate substantially all of the restrictive covenants and certain events of default.

As of June 30, 2020, as a result of the Tender Offers and Redemptions of the Vistra senior unsecured notes, only the 8.125% senior notes remained outstanding. The 8.125% senior notes were redeemed in July 2020.

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Other Long-Term Debt

Forward Capacity Agreements — In March 2021, the Company sold a portion of the PJM capacity that cleared for Planning Years 2021-2022 to a financial institution (2021-2022 Forward Capacity Agreement). The buyer in this transaction 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 ~~(Forward~~(Legacy Forward Capacity Agreements, and, together with the 2021-2022 Forward Capacity Agreement, the Forward Capacity Agreements). ~~The buyer in this transaction will receive~~In May 2021, the final capacity ~~payments~~payment from PJM during the Planning Years2020-2021 inwas paid, and the ~~amount~~terms of ~~$101 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 long-term debt with an implied interest rate of 2.29%.Legacy Forward Capacity were fulfilled.

~~Equipment Financing Agreements~~ ~~— On the Merger Date, the Company assumed Dynegy's Equipment Financing Agreements. Under certain~~Table of our contractual service agreements in which we receive maintenance and capital improvements for our gas-fueled generation fleet, we have obtained parts and equipment intended to increase the output, efficiency and availability of our generation units. We financed these parts and equipment under agreements with maturities ranging from 2020 to 2026.Contents

~~Letter of Credit Obligations Assumed in Ambit Transaction~~ — At June 30, 2020, approximately $3 million of letters of credit were outstanding under legacy Ambit agreements, all of which are collateralized with cash and recorded as restricted cash in the condensed consolidated balance sheets.

Maturities

Long-term debt maturities at June 30, ~~2020~~2021 are as follows:


		June 30, 2020			June 30, 2021
Remainder of 2020		$	263
2021		96
Remainder of 2021				Remainder of 2021	$	291
2022	2022	44		2022	257
2023	2023	40		2023	40
2024	2024	1,540		2024	1,540
2025				2025	2,470
Thereafter	Thereafter	7,678		Thereafter	6,483
Unamortized premiums, discounts and debt issuance costs	Unamortized premiums, discounts and debt issuance costs	(63)		Unamortized premiums, discounts and debt issuance costs	(86)
Total long-term debt, including amounts due currently	Total long-term debt, including amounts due currently	$	9,598	Total long-term debt, including amounts due currently	$	10,995

~~12.~~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. ~~As of June 30, 2020, there~~Material guarantees are ~~no material outstanding claims related to our guarantee obligations, and we do not anticipate we will be required to make any material payments under these guarantees in the near term.~~discussed below.

Letters of Credit

At June 30, ~~2020,~~2021, we had outstanding letters of credit totaling ~~$1.391~~$1.405 billion as follows:

•$~~1.117~~1.067 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 or~~ ISOs/RTOs;

•$~~108~~172 million to support battery and solar development projects;

•$4534 million to support executory contracts and insurance agreements;

•$5974 million to support our REP financial requirements with the PUCT, and

•$6258 million for other credit support requirements.

Surety Bonds

At June 30, ~~2020,~~2021, we had outstanding surety bonds totaling ~~$71~~$513 million to support performance under various contracts and legal obligations in the normal course of business.

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Litigation and Regulatory Proceedings

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

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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 2 consolidated putative class actions (Wisconsin) and 1 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. ~~Settlement discussions required under the dispute resolution process have been unsuccessful.~~ 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 ~~an arbitration hearing is currently scheduled for March 2021.~~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 ~~MPS~~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. 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.

~~ME2C Patent Dispute~~Koch Disputes — In ~~July 2019, Midwest Energy Emissions Corporation and MES Inc. (collectively, the plaintiffs)~~March 2021, we filed a ~~patent infringement complaint~~lawsuit in ~~federal~~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 ~~numerous parties,~~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 ~~Vistra and some of its subsidiaries (collectively,~~ERCOT, the ~~Vistra defendants), and its amended complaint in July 2020. The amended complaint alleges that~~ERCOT Independent Market Monitor, the ~~Vistra defendants infringed five patents owned by~~Texas Attorney General, the ~~plaintiffs by using specific processes for mercury control at certain coal-fueled plants. The amended complaint seeks injunctive relief and unspecified damages. In July 2020, the plaintiffs~~FERC and the ~~Vistra defendants entered into an agreement resolving all~~NRC initiated investigations or issued requests for information of various parties related to the ~~claims alleged against~~significant load shed event that occurred during the ~~Vistra defendants in the complaint. The court signed its stipulation and order of dismissal in July 2020, dismissing the Vistra defendants~~event as well as operational challenges for generators arising from the ~~lawsuit.~~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 ~~greenhouse gas (GHG)~~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 ~~new~~issuance of the rule that ~~replaces~~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.

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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 ~~develops~~developed emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generating units. ~~States must~~The ACE rule set a deadline of July 2022 for states to submit their plans for regulating GHG emissions from existing ~~facilities by July 2022.~~facilities. States where we operate coal plants ~~(Texas,~~(i.e., Texas, Illinois and Ohio) ~~have begun the development of~~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.~~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. 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 ~~September~~October 2017, the EPA ~~signed~~issued a final rule addressing BART for Texas electricity generation units, with the rule serving as a partial approval of ~~Texas's~~Texas' 2009 ~~SIP~~State Implementation Plan (SIP) and a partial ~~FIP.~~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 NO_X, 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 ~~Court~~(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 ~~June~~August 2020, the EPA ~~signed~~issued a final rule affirming the prior BART final rule but also ~~includes~~included additional revisions that were proposed in November 2019. ~~As finalized,~~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, but we ~~expect~~have challenged that ~~we will be able~~decision. We are in compliance with the rule. The BART rule is subject to ~~comply with~~ 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.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.~~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. On April 12, 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

Illinois Multi-Pollutant Standards (MPS)

In August 2019, changes proposed by the Illinois Pollution Control Board to the MPS rule, which places ~~NOx,~~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 NO_X 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 NO_X 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 ~~in order to comply~~thereby fully complying with the MPS rule's requirement to retire at least 2,000 MW of our generation in MISO. ~~See Note 4 for information regarding the retirement of these four plants.~~

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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, if finalized, would redesignate 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 expect the TCEQ to develop a SIP for Texas and submit to the EPA for approval.

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Effluent Limitation Guidelines (ELGs)

In November 2015, the EPA revised the ELGs for steam electricity generation facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, such as flue gas desulfurization (FGD), fly ash, bottom ash and flue gas mercury control wastewaters. Various parties filed petitions for review of the ELG rule, and the petitions were consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions requesting reconsideration of the ELG rule and administratively stayed the rule's compliance date deadlines. In 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.

~~Given~~ The EPA published the ~~EPA's decision to reconsider~~final rule in October 2020. The final rule extends the compliance date for both FGD and bottom ash ~~wastewater provisions~~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. Notification to the state agency on the retirement exemption is due by October 2021. In November 2020, environmental groups petitioned for review of the new ELG ~~rule, the rule postponing the ELG rule's earliest compliance dates for those provisions, the uncertainty stemming from the vacatur~~revisions, and Vistra subsidiaries filed a motion to intervene in support of the ~~effluent limitations for legacy wastewater and leachate, and~~EPA in December 2020. The final rule is subject to the ~~intertwined relationship of the ELG rule with the Coal Combustion Residuals rule~~Environment Executive Order discussed below, which is also being reconsidered by the EPA, as well as pending legal challenges concerning both rules, substantial uncertainty exists regarding our projected capital expenditures for ELG compliance, including the timing of such expenditures.above.

~~CAA Matters~~

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~~Zimmer NOVs~~ — In December 2014, the EPA issued a notice of violation (NOV) alleging violation of opacity standards at the Zimmer facility. The EPA previously had issued NOVs to Zimmer in 2008 and 2010 alleging violations of the CAA, the Ohio State Implementation Plan and the station's air permits including standards applicable to opacity, sulfur dioxide, sulfuric acid mist and heat input. In January 2020, the U.S. Department of Justice filed a complaint and proposed consent decree agreed to by Dynegy Zimmer, LLC in the U.S. District Court for the Southern District of Ohio that would resolve claims alleged in the 2008, 2010 and 2014 NOVs. The District Court approved that consent decree in May 2020. The consent decree does not have a material impact on our results of operations, liquidity or financial condition.

Coal Combustion ~~Residuals (CCR)/~~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 ~~extend~~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. The EPA is expected to undertake further revisions to its CCR regulations in response to the D.C. Circuit Court's ruling. In October 2018, the rule that extends certain closure deadlines to 2020 was challenged in the D.C. Circuit Court. In March 2019, the D.C. Circuit Court granted the EPA's request for remand without vacatur. 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 ~~July~~August 2020, the EPA ~~finalized~~issued a rule finalizing the December 2019 proposal, ~~with~~establishing a ~~final~~ deadline of April 11, 2021 to cease receipt of waste and initiate closure ofat unlined CCR impoundments. The final rule allows a generation plant to seek the EPA's approval to ~~retire~~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) ~~as a means of compliance. We may decide~~. Prior to ~~avail ourselves~~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 ~~compliance mechanism~~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 ~~some~~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 ~~our facilities.~~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.

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.

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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 2 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. ~~Plaintiffs have appealed the judgment to~~In June 2021, the U.S. Court of Appeals for the Seventh Circuit ~~and briefing on~~affirmed the district court's dismissal of the lawsuit, but stated that ~~appeal is now underway.~~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. ~~This~~In July 2021, we answered that complaint, and this matter is in the very early stages.

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 ~~has since been~~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).

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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 and we expect the rulemaking process should be completed by early 2021.~~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 ~~have been scheduled for~~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 ~~will provide testimony during~~expect to file our opening brief in September 2021. Other parties have also filed appeals of certain provisions of the ~~hearing process.~~final 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. ~~Until the revisions to the EPA's CCR rule and the~~The Illinois coal ash ~~rulemaking are~~rule was finalized in April 2021 and wedoes not require removal. However, the rule will require us to undertake further site specific evaluations ~~required by each program we~~which are underway. We will not know the full range of decommissioning costs, ofincluding groundwater remediation, if any, that ultimately may be required under ~~those rules.~~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, 3 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 1 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.

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.

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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. ~~The~~Oral argument was heard by the D.C. Circuit Court in May 2021 and the appeal remains pending.

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Other Matters

We are involved in various legal and administrative proceedings and other disputes in the normal course of business, including disputes over certain gas invoices, 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.

~~13.~~12. EQUITY

Share Repurchase ~~Program~~Programs

In ~~June 2018,~~September 2020, we announced that the Board ~~had~~ authorized a share repurchase program under which up to $500 million of our outstanding common stock may be purchased, and this authorized amount was fully utilized in 2018. In November 2018, we announced that the Board had authorized an incremental share repurchase program under which up to $1.250 billion of our outstanding stock may be purchased, resulting in an aggregate $1.750 billionnew share repurchase program (Share Repurchase Program)~~. No repurchases were made~~ under which up to $1.5 billion of our outstanding shares of common stock may be repurchased. The Share Repurchase Program became effective on January 1, 2021.

Under the Share Repurchase Program, ~~in the three and six months ended June 30, 2020. In the three months ended June 30, 2019, 8,558,712~~ shares ~~of our common stock were repurchased under the Share Repurchase Program for approximately $212 million (including related fees and expenses) at an average price of $24.72 per share of common stock.~~In the six months ended June 30, 2019, 18,100,329 shares of our common stock were repurchased under the Share Repurchase Program for approximately $448 million (including related fees and expenses) at an average price of $24.75 per share of common stock. On a cumulative basis, 59,817,182 shares of our common stock have been repurchased under the Share Repurchase Program for approximately $1.418 billion (including related fees and expenses) at an average price of $23.72 per share of common stock. As of June 30, 2020, approximately $332 million was available for additional repurchases 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~~agreements.

NaN shares were repurchased in the three months ended June 30, 2021. In the six months ended June 30, 2021, 8,658,153 shares of our common stock were repurchased under the 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 June 30, 2021, approximately $1.325 billion was available for additional repurchases under the ~~Tax Matters Agreement.~~Share Repurchase Program.

Dividends

In November 2018, Vistra announced the Board adopted a dividend program which we initiated in the first quarter of 2019. Each dividend under the program ~~will be~~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 ~~2019, May 2019,~~2020, April 2020, July ~~2019 and October 2019, the Board declared quarterly dividends of $0.125 per share that were paid in March 2019, June 2019, September 2019 and December 2019, respectively.~~

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

In ~~July 2020,~~February 2021 and April 2021, the Board declared a quarterly dividend of ~~$0.135~~$0.15 per share that was paid in March 2021 and June 2021, respectively. In July 2021, the Board declared a quarterly dividend of $0.15 per share that will be paid in September ~~2020.~~2021.

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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 June 30, ~~2020,~~2021, Vistra Operations can distribute approximately ~~$6.1~~$6.4 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 $100 million and $740 million during the three months ended June 30, 2021 and 2020, respectively, and $330 million and $850 million during the ~~three and~~ six months ended June 30, ~~2020, respectively,~~2021 and ~~approximately $3.9 billion, $4.7 billion and $1.1 billion during the years ended December 31, 2019, 2018 and 2017,~~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 June 30, ~~2020,~~2021, all of the ~~maximum amount of~~ restricted net assets of Vistra Operations ~~that~~ may ~~not~~ be distributed to ~~Parent totaled approximately $1.5 billion.~~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.

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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 June 30, ~~2020, approximately~~2021, 9000000 warrants expiring in 2024 were outstanding. The warrants ~~are immaterial and reflected as~~were included in equity ~~in our condensed consolidated balance sheets.~~based on their fair value at the Merger Date.

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Equity

The following table presents the changes to equity for the three months ended June 30, ~~2020:~~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 March 31, 2021	$	5	$	(1,148)	$	9,805	$	(2,516)	$	(46)	$	6,100	$	(7)	$	6,093
Stock repurchases	—		0		—		—		—		—		—		—

Dividends declared on common stock	—		—		—		(73)		—		(73)		—		(73)
Effects of stock-based incentive compensation plans	—		—		10		—		—		10		—		10
Net income (loss)	—		—		—		36		—		36		(1)		35

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

Other	—		—		1		1		—		2		—		2
Balance at June 30, 2021	$	5	$	(1,148)	$	9,816	$	(2,552)	$	(45)	$	6,076	$	(8)	$	6,068

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 March 31, 2020 $ 5 $ (973) $ 9,737 $ (780) $ (53) $ 7,936 $ (10) $ 7,926
Dividends declared on common stock — — — (66) — (66) — (66)
Effects of stock-based incentive compensation plans — — 16 — — 16 — 16
Net income (loss) — — — 166 — 166 (2) 164
Change in accumulated other comprehensive income (loss) — — — — 1 1 — 1
Other — — 1 2 — 3 — 3
Balance at June 30, 2020 $ 5 $ (973) $ 9,754 $ (678) $ (52) $ 8,056 $ (12) $ 8,044
The following table presents the changes to equity for the six months ended June 30, 2021:


	Common Stock (a)		Treasury Stock		Additional Paid-in Capital		Retained Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss)		Total Stockholders' Equity		Noncontrolling Interest in Subsidiary		Total Equity
Balance at December 31, 2020	$	5	$	(973)	$	9,786	$	(399)	$	(48)	$	8,371	$	(10)	$	8,361
Stock repurchases	—		(175)		—		—		—		(175)		—		(175)

Dividends declared on common stock	—		—		—		(147)		—		(147)		—		(147)
Effects of stock-based incentive compensation plans	—		—		27		—		—		27		—		27
Net income (loss)	—		—		—		(2,006)		—		(2,006)		2		(2,004)

Change in accumulated other comprehensive income (loss)	—		—		—		—		3		3		—		3

Other	—		—		3		0		—		3		—		3
Balance at June 30, 2021	$	5	$	(1,148)	$	9,816	$	(2,552)	$	(45)	$	6,076	$	(8)	$	6,068

________________

(a)Authorized shares totaled 1,800,000,000 at June 30, 2021. Outstanding common shares totaled 482,468,556 and 489,305,888 at June 30, 2021 and December 31, 2020, respectively. Treasury shares totaled 49,701,377 and 41,043,224 at June 30, 2021 and December 31, 2020, respectively.

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The following table presents the changes to equity for the three months ended June 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 March 31, 2020	$	5	$	(973)	$	9,737	$	(780)	$	(53)	$	7,936	$	(10)	$	7,926


Dividends declared on common stock	—		—		—		(66)		—		(66)		—		(66)
Effects of stock-based incentive compensation plans	—		—		16		—		—		16		—		16
Net income	—		—		—		166		—		166		(2)		164

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

Other	—		—		1		2		—		3		0		3
Balance at June 30, 2020	$	5	$	(973)	$	9,754	$	(678)	$	(52)	$	8,056	$	(12)	$	8,044

The following table presents the changes to equity for the six months ended June 30, 2020:


		Common Stock (a)		Treasury Stock		Additional Paid-in Capital		Retained Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss)		Total Stockholders' Equity		Noncontrolling Interest		Total Equity			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	Balance at December 31, 2019	$	5	$	(973)	$	9,721	$	(764)	$	(30)	$	7,959	$	1	$	7,960	Balance at December 31, 2019	$	5	$	(973)	$	9,721	$	(764)	$	(30)	$	7,959	$	1	$	7,960

Dividends declared on common stock	Dividends declared on common stock	—		—		—		(132)		—		(132)		—		(132)		Dividends declared on common stock	—		—		—		(132)		—		(132)		—		(132)
Effects of stock-based incentive compensation plans	Effects of stock-based incentive compensation plans	—		—		30		—		—		30		—		30		Effects of stock-based incentive compensation plans	—		—		30		—		—		30		—		30
Net income (loss)	Net income (loss)	—		—		—		222		—		222		(13)		209		Net income (loss)	—		—		—		222		—		222		(13)		209
Adoption of accounting standard	Adoption of accounting standard	—		—		—		(4)		—		(4)		—		(4)		Adoption of accounting standard	—		—		—		(4)		—		(4)		—		(4)
Change in accumulated other comprehensive income (loss)	Change in accumulated other comprehensive income (loss)	—		—		—		—		(22)		(22)		—		(22)		Change in accumulated other comprehensive income (loss)	—		—		—		—		(22)		(22)		—		(22)

Other	Other	—		—		3		—		—		3		—		3		Other	—		—		3		0		—		3		—		3
Balance at June 30, 2020	Balance at June 30, 2020	$	5	$	(973)	$	9,754	$	(678)	$	(52)	$	8,056	$	(12)	$	8,044	Balance at June 30, 2020	$	5	$	(973)	$	9,754	$	(678)	$	(52)	$	8,056	$	(12)	$	8,044

________________

(a)Authorized shares totaled 1,800,000,000 at June 30, 2020. Outstanding common shares totaled 488,772,572 and 487,698,111 at June 30, 2020 and December 31, 2019, respectively. Treasury shares totaled 41,043,224 at both June 30, 2020 and December 31, 2019.

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~~The following table presents the changes to equity for the three months ended June 30, 2019:~~

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 March 31, 2019 $ 5 $ (1,014) $ 10,119 $ (1,285) $ (21) $ 7,804 $ 2 $ 7,806
Stock repurchase — (212) — — — (212) — (212)
Dividends declared on common stock — — — (59) — (59) — (59)
Effects of stock-based incentive compensation plans — — 16 — — 16 — 16
Net income (loss) — — — 356 — 356 (2) 354
Other — — — (1) — (1) — (1)
Balance at June 30, 2019 $ 5 $ (1,226) $ 10,135 $ (989) $ (21) $ 7,904 $ — $ 7,904

~~The following table presents the changes to equity for the six months ended June 30, 2019:~~

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
December 31, 2018
$ 5 $ (778) $ 10,107 $ (1,449) $ (22) $ 7,863 $ 4 $ 7,867
Stock repurchase — (448) — — — (448) — (448)
Dividends declared on common stock — — — (120) — (120) — (120)
Effects of stock-based incentive compensation plans — — 28 — — 28 — 28
Net income — — — 581 — 581 (3) 578
Adoption of accounting standard — — — (2) — (2) — (2)
Change in accumulated other comprehensive income (loss) — — — — 1 1 — 1
Other — — — 1 — 1 (1) —
Balance at June 30, 2019 $ 5 $ (1,226) $ 10,135 $ (989) $ (21) $ 7,904 $ — $ 7,904

~~________________~~

~~(a)~~Authorized shares totaled 1,800,000,000 at June 30, 2019. Outstanding common shares totaled 476,166,856 and 493,215,309 at June 30, 2019 and December 31, 2018, respectively. Treasury shares totaled 51,323,829 and 32,815,783 at June 30, 2019 and December 31, 2018, respectively.

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~~14.~~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 1514 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 ~~beginning in January 2017,~~ are legally characterized as settlement of derivative contracts rather than collateral.

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

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

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

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


		June 30, 2020																		December 31, 2019																			June 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			Level 1		Level 2		Level 3 (a)		Reclass (b)		Total		Level 1		Level 2		Level 3 (a)		Reclass (b)		Total
Assets:	Assets:																					Assets:
Commodity contracts	Commodity contracts	$	1,033	$	158	$	314	$	36	$	1,541	$	1,047	$	172	$	239	$	11	$	1,469	Commodity contracts	$	1,133	$	449	$	335	$	59	$	1,976	$	452	$	201	$	205	$	76	$	934
Interest rate swaps	Interest rate swaps	—		86		—		—		86		—		—		—		—		—		Interest rate swaps	—		43		—		—		43		—		72		—		—		72
Nuclear decommissioning trust – equity securities (c)	Nuclear decommissioning trust – equity securities (c)	523		—		—				523		564		—		—				564		Nuclear decommissioning trust – equity securities (c)	686		—		—				686		623		—		—				623
Nuclear decommissioning trust – debt securities (c)	Nuclear decommissioning trust – debt securities (c)	—		588		—				588		—		521		—				521		Nuclear decommissioning trust – debt securities (c)	—		639		—				639		—		618		—				618
Sub-total	Sub-total	$	1,556	$	832	$	314	$	36	2,738		$	1,611	$	693	$	239	$	11	2,554		Sub-total	$	1,819	$	1,131	$	335	$	59	3,344		$	1,075	$	891	$	205	$	76	2,247
Assets measured at net asset value (d):	Assets measured at net asset value (d):																					Assets measured at net asset value (d):
Nuclear decommissioning trust – equity securities (c)	Nuclear decommissioning trust – equity securities (c)									355										366		Nuclear decommissioning trust – equity securities (c)									499										433
Total assets	Total assets									$	3,093									$	2,920	Total assets									$	3,843									$	2,680
Liabilities:	Liabilities:																					Liabilities:
Commodity contracts	Commodity contracts	$	970	$	484	$	200	$	36	$	1,690	$	985	$	439	$	313	$	11	$	1,748	Commodity contracts	$	1,412	$	525	$	289	$	59	$	2,285	$	578	$	172	$	183	$	76	$	1,009
Interest rate swaps	Interest rate swaps	—		455		—		—		455		—		177		—		—		177		Interest rate swaps	—		296		—		—		296		—		404		—		—		404
Total liabilities	Total liabilities	$	970	$	939	$	200	$	36	$	2,145	$	985	$	616	$	313	$	11	$	1,925	Total liabilities	$	1,412	$	821	$	289	$	59	$	2,581	$	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 ~~18.~~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 1514 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 June 30, ~~2020~~2021 and December 31, ~~2019:~~2020:


June 30, 2020
June 30, 2021																				June 30, 2021
		Fair Value																																Fair Value
Contract Type (a)	Contract Type (a)	Assets		Liabilities		Total		Valuation Technique		Significant Unobservable Input		Range (b)											Average (b)		Contract Type (a)				Assets					Liabilities					Total				Valuation Technique					Significant Unobservable Input						Range (b)												Average (b)
Electricity purchases and sales	Electricity purchases and sales	$	149	$	(32)	$	117	Valuation Model		Hourly price curve shape (c)		$	—	to		td05			$53	Electricity purchases and sales				$	233				$	(109)				$	124				Income Approach				Hourly price curve shape (c)					$	0		to			$70						$34
																MWh												Electricity purchases and sales														Income Approach						Hourly price curve shape (c)						MWh
										Illiquid delivery periods for ERCOT hub power prices and heat rates (d)		$	20	to		td20			$73																									Illiquid delivery periods for hub power prices and heat rates (d)							$	15		td40			$76
														MWh																																			Illiquid delivery periods for hub power prices and heat rates (d)						MWh
Options	Options	74		(121)		(47)			Option Pricing Model		Gas to power correlation (e)			25	%	to		100%		63%			Options				10						(155)					(145)									Option Pricing Model								Gas to power correlation (e)						10		%	100%			55%
												Power and gas volatility (e)				5	%	to	675%		341%			Options																	Option Pricing Model					Power and gas volatility (e)						5		%	to			500%						252%
Financial transmission rights	Financial transmission rights	76		(13)		63		Market Approach (f)		Illiquid price differences between settlement points (g)		$	(5)	to		$50			td2	Financial transmission rights						73			(16)					57						Market Approach (f)								$	(30)		to			$50						$9
																MWh												Financial transmission rights																	Market Approach (f)					Illiquid price differences between settlement points (g)						MWh

Natural gas																						Natural gas				8						0					8							Income Approach									Gas basis (h)						$	0		to			td0			$3
																																										MMBtu

Other (h)		15		(34)		(19)
Other (i)																				Other (i)						11					(9)					2
Total	Total	$	314	$	(200)	$	114													Total				$	335				$	(289)				$	46


December 31, 2019
December 31, 2020																				December 31, 2020
		Fair Value																																Fair Value
Contract Type (a)	Contract Type (a)	Assets		Liabilities		Total		Valuation Technique		Significant Unobservable Input		Range (b)											Average (b)		Contract Type (a)				Assets					Liabilities				Total				Valuation Technique						Significant Unobservable Input					Range (b)											Average (b)
Electricity purchases and sales	Electricity purchases and sales	$	64	$	(53)	$	11	Valuation Model		Hourly price curve shape (c)		$	—	to		td15			$58	Electricity purchases and sales				$	61				$	(90)				$	(29)			Income Approach				Hourly price curve shape (c)						$	0		to		$85						$43
																MWh												Electricity purchases and sales													Income Approach							Hourly price curve shape (c)					MWh
										Illiquid delivery periods for ERCOT hub power prices and heat rates (d)		$	20	to		td20			$70																								Illiquid delivery periods for ERCOT hub power prices and heat rates (d)								$	25	td25			$75
														MWh																																			Illiquid delivery periods for ERCOT hub power prices and heat rates (d)					MWh
Options	Options	38		(188)		(150)			Option Pricing Model		Gas to power correlation (e)			10	%	to		100%		55%			Options				38						(56)				(18)									Option Pricing Model								Gas to power correlation (e)						30		%	100%		64%
												Power and gas volatility (e)				5	%	to	440%		223%			Options																Option Pricing Model					Power and gas volatility (e)							5	%	to			665%						336%
Financial transmission rights	Financial transmission rights	120		(26)		94		Market Approach (f)		Illiquid price differences between settlement points (g)		$	(10)	to		$40			td5	Financial transmission rights						92			(16)					76					Market Approach (f)									$	(5)		to		$50						td2
																MWh												Financial transmission rights																Market Approach (f)						Illiquid price differences between settlement points (g)					MWh
Natural gas																						Natural gas				7						(14)				(7)					Income Approach						Gas basis (h)								$	(1)		$0			$0
																																											MMBtu

Other (h)		17		(46)		(29)
Other (i)																				Other (i)						7					(7)					0
Total	Total	$	239	$	(313)	$	(74)													Total				$	205				$	(183)				$	22

____________

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

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

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

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

(e)Primarily based on the historical forward correlation and volatility within ~~ERCOT.~~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 Northeast gas basis prices.

(i)Other includes contracts for ~~natural gas,~~ coal and emissions.

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See the table below for discussion of transfers between Level 2 and Level 3 for the three and six months ended June 30, ~~2020~~2021 and ~~2019.~~2020.

~~Table of Contents~~

The following table presents the changes in fair value of the Level 3 assets and liabilities for the three and six months ended June 30, ~~2020~~2021 and ~~2019.~~2020.


		Three Months Ended June 30,						Six Months Ended June 30,							Three Months Ended June 30,				Six Months Ended June 30,
		2020		2019		2020		2019			2021		2020		2021		2020
Net asset (liability) balance at beginning of period	Net asset (liability) balance at beginning of period	$	28	$	(113)	$	(74)	$	(135)	Net asset (liability) balance at beginning of period	$	204	$	28	$	22	$	(74)
Total unrealized valuation gains		104		87		98		125
Total unrealized valuation gains (losses)										Total unrealized valuation gains (losses)	(16)		104		174		98
Purchases, issuances and settlements (a):	Purchases, issuances and settlements (a):									Purchases, issuances and settlements (a):
Purchases	Purchases	34		61		89		79		Purchases	23		34		40		89
Issuances	Issuances	(3)		(10)		(6)		(17)		Issuances	(4)		(3)		(10)		(6)
Settlements	Settlements	(34)		(20)		(47)		(42)		Settlements	(146)		(34)		(166)		(47)
Transfers into Level 3 (b)	Transfers into Level 3 (b)	(2)		3		(1)		5		Transfers into Level 3 (b)	0		(2)		2		(1)
Transfers out of Level 3 (b)	Transfers out of Level 3 (b)	(13)		(4)		55		(11)		Transfers out of Level 3 (b)	(15)		(13)		(16)		55

Net change (c)	Net change (c)	86		117		188		139		Net change (c)	(158)		86		24		188
Net asset balance at end of period	Net asset balance at end of period	$	114	$	4	$	114	$	4	Net asset balance at end of period	$	46	$	114	$	46	$	114
Unrealized valuation gains relating to instruments held at end of period		$	123	$	92	$	137	$	110
Unrealized valuation gains (losses) relating to instruments held at end of period										Unrealized valuation gains (losses) relating to instruments held at end of period	$	3	$	123	$	49	$	137

____________

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

(b)Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. For the three months ended June 30, 2021 and 2020, transfers out of Level 3 primarily consist of gas and power derivatives where forward pricing inputs have become observable. For the six months ended June 30, 2020, transfers out of Level 3 primarily consist of gas, power and coal derivatives where forward pricing inputs have become observable.

(c)Activity excludes change in fair value in the month positions settle. Substantially all changes in values of commodity contracts (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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~~15.~~

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 1413 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.

~~Table of Contents~~

Financial Statement Effects of Derivatives

Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of derivative contractual assets and liabilities as reported in our condensed consolidated balance sheets at June 30, ~~2020~~2021 and December 31, ~~2019.~~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.


		June 30, 2020																			June 30, 2021
		Derivative Assets						Derivative Liabilities									Derivative Assets				Derivative Liabilities
		Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total			Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total
Current assets	Current assets	$	1,313	$	19	$	18	$	—	$	1,350	Current assets	$	1,631	$	19	$	37	$	0	$	1,687
Noncurrent assets	Noncurrent assets	208		67		2		—		277		Noncurrent assets	308		24		0		0		332
Current liabilities	Current liabilities	(3)		—		(1,473)		(70)		(1,546)		Current liabilities	(7)		0		(1,966)		(71)		(2,044)
Noncurrent liabilities	Noncurrent liabilities	(13)		—		(201)		(385)		(599)		Noncurrent liabilities	(15)		0		(297)		(225)		(537)
Net assets (liabilities)	Net assets (liabilities)	$	1,505	$	86	$	(1,654)	$	(455)	$	(518)	Net assets (liabilities)	$	1,917	$	43	$	(2,226)	$	(296)	$	(562)


		December 31, 2019																			December 31, 2020
		Derivative Assets						Derivative Liabilities									Derivative Assets				Derivative Liabilities
		Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total			Commodity Contracts		Interest Rate Swaps		Commodity Contracts		Interest Rate Swaps		Total
Current assets	Current assets	$	1,323	$	—	$	10	$	—	$	1,333	Current assets	$	665	$	19	$	64	$	0	$	748
Noncurrent assets	Noncurrent assets	136		—		—		—		136		Noncurrent assets	197		53		8		0		258
Current liabilities	Current liabilities	(1)		—		(1,510)		(18)		(1,529)		Current liabilities	(1)		0		(717)		(71)		(789)
Noncurrent liabilities	Noncurrent liabilities	—		—		(237)		(159)		(396)		Noncurrent liabilities	(3)		0		(288)		(333)		(624)
Net assets (liabilities)	Net assets (liabilities)	$	1,458	$	—	$	(1,737)	$	(177)	$	(456)	Net assets (liabilities)	$	858	$	72	$	(933)	$	(404)	$	(407)

At June 30, ~~2020~~2021 and December 31, ~~2019,~~2020, there were no derivative positions accounted for as cash flow or fair value hedges.

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


Derivative (condensed consolidated statements of operations presentation)	Derivative (condensed consolidated statements of operations presentation)	Three Months Ended June 30,									Six Months Ended June 30,									Derivative (condensed consolidated statements of operations presentation)	Three Months Ended June 30,						Six Months Ended June 30,
				2020			2019			2020			2019		Derivative (condensed consolidated statements of operations presentation)	2021			2020				2021			2020
Commodity contracts (Operating revenues)	Commodity contracts (Operating revenues)	$	6		$	549		$	263		$	776	Commodity contracts (Operating revenues)	$			$	6			$	(98)		$	263
Commodity contracts (Fuel, purchased power costs and delivery fees)	Commodity contracts (Fuel, purchased power costs and delivery fees)	48			(24)			(58)			3		Commodity contracts (Fuel, purchased power costs and delivery fees)	74			48				115			(58)
Interest rate swaps (Interest expense and related charges)	Interest rate swaps (Interest expense and related charges)	(29)			(108)			(207)			(183)		Interest rate swaps (Interest expense and related charges)	(22)			(29)				53			(207)
Net gain (loss)	Net gain (loss)	$	25		$	417		$	(2)		$	596	Net gain (loss)	$	(131)		$	25			$	70		$	(2)

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.

~~Table of Contents~~

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


		June 30, 2020														December 31, 2019															June 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 and Liabilities		Offsetting Instruments (a)		Cash Collateral (Received) Pledged (b)		Net Amounts		Derivative Assets and Liabilities		Offsetting Instruments (a)		Cash Collateral (Received) Pledged (b)		Net Amounts
Derivative assets:	Derivative assets:																	Derivative assets:
Commodity contracts	Commodity contracts	$	1,505	$	(1,171)	$	(8)	$	326	$	1,458	$	(1,113)	$	—	$	345	Commodity contracts	$	1,917	$	(1,620)	$	(34)	$	263	$	858	$	(667)	$	(11)	$	180
Interest rate swaps	Interest rate swaps	86		(86)		—		—		—		—		—		—		Interest rate swaps	43		(43)		0		0		72		(72)		0		0
Total derivative assets	Total derivative assets	1,591		(1,257)		(8)		326		1,458		(1,113)		—		345		Total derivative assets	1,960		(1,663)		(34)		263		930		(739)		(11)		180
Derivative liabilities:	Derivative liabilities:																	Derivative liabilities:
Commodity contracts	Commodity contracts	(1,654)		1,171		30		(453)		(1,737)		1,113		40		(584)		Commodity contracts	(2,226)		1,620		311		(295)		(933)		667		138		(128)
Interest rate swaps	Interest rate swaps	(455)		86		—		(369)		(177)		—		—		(177)		Interest rate swaps	(296)		43		0		(253)		(404)		72		0		(332)
Total derivative liabilities	Total derivative liabilities	(2,109)		1,257		30		(822)		(1,914)		1,113		40		(761)		Total derivative liabilities	(2,522)		1,663		311		(548)		(1,337)		739		138		(460)
Net amounts	Net amounts	$	(518)	$	—	$	22	$	(496)	$	(456)	$	—	$	40	$	(416)	Net amounts	$	(562)	$	0	$	277	$	(285)	$	(407)	$	0	$	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 June 30, ~~2020~~2021 and December 31, ~~2019:~~2020:


		June 30, 2020		December 31, 2019					June 30, 2021		December 31, 2020
Derivative type	Derivative type	Notional Volume						Unit of Measure		Derivative type	Notional Volume			Unit of Measure
Natural gas (a)	Natural gas (a)	5,395		6,160		Million MMBtu	Natural gas (a)		5,189		5,264		Million MMBtu
Electricity	Electricity	436,983		428,367		GWh	Electricity		415,307		438,863		GWh
Financial transmission rights (b)	Financial transmission rights (b)	212,461		199,648		GWh	Financial transmission rights (b)		229,313		217,350		GWh
Coal	Coal	17		22		Million U.S. tons	Coal		13		20		Million U.S. tons
Fuel oil	Fuel oil	165		33		Million gallons	Fuel oil		105		176		Million gallons

Emissions	Emissions	37		20		Million tons	Emissions		16		8		Million tons
Renewable energy certificates	Renewable energy certificates	12		11		Million certificates	Renewable energy certificates		26		18		Million certificates

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

____________

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

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

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

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.

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


		June 30, 2020		December 31, 2019			June 30, 2021		December 31, 2020
Fair value of derivative contract liabilities (a)	Fair value of derivative contract liabilities (a)	$	(930)	$	(692)	Fair value of derivative contract liabilities (a)	$	(938)	$	(679)
Offsetting fair value under netting arrangements (b)	Offsetting fair value under netting arrangements (b)	303		167		Offsetting fair value under netting arrangements (b)	529		262
Cash collateral and letters of credit	Cash collateral and letters of credit	91		67		Cash collateral and letters of credit	71		35
Liquidity exposure	Liquidity exposure	$	(536)	$	(458)	Liquidity exposure	$	(338)	$	(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 June 30, ~~2020,~~2021, total credit risk exposure to all counterparties related to derivative contracts totaled ~~$1.712~~$2.112 billion (including associated accounts receivable). The net exposure to those counterparties totaled ~~$378~~$311 million at June 30, ~~2020,~~2021, after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling ~~$80~~$81 million. At June 30, ~~2020,~~2021, the credit risk exposure to the banking and financial sector represented ~~79%~~78% of the total credit risk exposure and ~~47%~~32% 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.

~~16.~~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:

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•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. ~~Legal fee expenses paid or accrued by Vistra on behalf of the selling stockholders totaled less than $1 million during both the three and six months ended June 30, 2020 and 2019.~~

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 87 for discussion of the TRA.

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~~17.~~16.SEGMENT INFORMATION

The operations of Vistra are aligned into 6 reportable business segments: (i) Retail, (ii) ~~ERCOT,~~Texas, (iii) ~~PJM,~~East, (iv) ~~NY/NE,~~West, (v) ~~MISO~~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 ~~chief operating decision maker (CODM)~~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. ~~Operational results for 4 facilities retired in late 2019 were recast from the MISO segment to the Asset Closure segment (see Note 4).~~

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 ~~ERCOT, PJM, NY/NE (comprising NYISO~~Texas and ~~ISO-NE) and MISO~~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 1 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 ~~all largely within their respective ISO/RTO market.~~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 4)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 ~~2019.~~2020.

Corporate and Other represents the remaining non-segment operations consisting primarily of ~~(i)~~ general corporate expenses, interest, taxes and other expenses related to our support functions that provide shared services to our operating ~~segments and (ii) CAISO operations.~~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 ~~chief operating decision maker~~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.

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Three months ended	Three months ended	Retail		ERCOT		PJM		NY/NE		MISO		Asset Closure		Corporate and Other (b)		Eliminations		Consolidated		Three months ended	Retail		Texas		East		West		Sunset		Asset Closure		Corporate and Other (b)		Eliminations		Consolidated
Operating revenues (a):	Operating revenues (a):																			Operating revenues (a):
June 30, 2021																				June 30, 2021	$	1,919	$	(468)	$	505	$	48	$	(48)	$	0	$	0	$	609	$	2,565
June 30, 2020	June 30, 2020	$	1,956	$	865	$	412	$	131	$	121	$	—	$	46	$	(1,022)	$	2,509	June 30, 2020	1,956		841		465		45		221		2		0		(1,021)		2,509
June 30, 2019		1,421		1,671		686		254		188		58		47		(1,493)		2,832
Depreciation and amortization:	Depreciation and amortization:																					Depreciation and amortization:
June 30, 2021																				June 30, 2021	$	(54)	$	(159)	$	(193)	$	(10)	$	(30)	$	0	$	(18)	$	0	$	(464)
June 30, 2020	June 30, 2020	$	(82)	$	(130)	$	(165)	$	(48)	$	(9)	$	—	$	(21)	$	—	$	(455)	June 30, 2020	(82)		(120)		(192)		(5)		(39)		(1)		(16)		0		(455)
June 30, 2019		(59)		(128)		(134)		(39)		(3)		—		(21)		—		(384)
Operating income (loss):	Operating income (loss):																			Operating income (loss):
June 30, 2021																				June 30, 2021	$	1,811	$	(1,167)	$	(95)	$	(18)	$	(427)	$	(16)	$	(26)	$	0	$	62
June 30, 2020	June 30, 2020	$	232	$	296	$	(66)	$	(18)	$	(32)	$	(14)	$	(21)	$	—	$	377	June 30, 2020	232		305		(49)		14		(76)		(14)		(35)		0		377
June 30, 2019		(581)		1,047		185		78		46		(27)		(19)		—		729
Net income (loss):	Net income (loss):																			Net income (loss):
June 30, 2021																				June 30, 2021	$	1,810	$	(1,138)	$	(100)	$	(13)	$	(424)	$	(14)	$	(86)	$	0	$	35
June 30, 2020	June 30, 2020	$	229	$	299	$	(66)	$	(18)	$	(32)	$	(14)	$	(234)	$	—	$	164	June 30, 2020	229		306		(49)		16		(76)		(12)		(250)		0		164
June 30, 2019		(585)		1,056		183		79		46		(26)		(399)		—		354

Six months ended		Retail		ERCOT		PJM		NY/NE		MISO		Asset Closure		Corporate and Other (b)		Eliminations		Consolidated
Six Months ended																				Six Months ended	Retail		Texas		East		West		Sunset		Asset Closure		Corporate and Other (b)		Eliminations		Consolidated
Operating revenues (a):	Operating revenues (a):																			Operating revenues (a):
June 30, 2021																				June 30, 2021	$	3,669	$	615	$	1,230	$	81	$	230	$	0	$	0	$	(53)	$	5,772
June 30, 2020	June 30, 2020	$	3,864	$	1,731	$	1,060	$	417	$	263	$	—	$	127	$	(2,095)	$	5,367	June 30, 2020	3,864		1,702		1,189		127		578		2		0		(2,095)		5,367
June 30, 2019		2,806		2,625		1,391		599		357		143		164		(2,330)		5,755
Depreciation and amortization:	Depreciation and amortization:																																					Depreciation and amortization:
June 30, 2021																				June 30, 2021	$	(107)	$	(283)	$	(389)	$	(15)	$	(59)	$	0	$	(34)	$	0	$	(887)
June 30, 2020	June 30, 2020	$	(162)	$	(253)	$	(303)	$	(97)	$	(20)	$	—	$	(40)	$	—	$	(875)	June 30, 2020	(162)		(233)		(360)		(9)		(79)		(1)		(31)		0		(875)
June 30, 2019		(118)		(259)		(265)		(104)		(7)		—		(37)		—		(790)
Operating income (loss):	Operating income (loss):																			Operating income (loss):
June 30, 2021																				June 30, 2021	$	1,905	$	(3,723)	$	(92)	$	(52)	$	(472)	$	(32)	$	(55)	$	0	$	(2,521)
June 30, 2020	June 30, 2020	$	329	$	552	$	68	$	10	$	(114)	$	(30)	$	(49)	$	—	$	766	June 30, 2020	329		574		34		17		(92)		(30)		(66)		0		766
June 30, 2019		(563)		1,335		348		94		67		(51)		(12)		—		1,218
Net income (loss):	Net income (loss):																			Net income (loss):
June 30, 2021																				June 30, 2021	$	1,898	$	(3,656)	$	(99)	$	(44)	$	(467)	$	(13)	$	377	$	0	$	(2,004)
June 30, 2020	June 30, 2020	$	323	$	557	$	53	$	(3)	$	(111)	$	(31)	$	(579)	$	—	$	209	June 30, 2020	323		577		6		20		(89)		(29)		(599)		0		209
June 30, 2019		(571)		1,356		346		100		67		(50)		(670)		—		578
Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures:	Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures:																																					Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures:
June 30, 2021																				June 30, 2021	$	0	$	142	$	26	$	2	$	15	$	0	$	21	$	0	$	206
June 30, 2020	June 30, 2020	$	1	$	141	$	53	$	14	$	7	$	—	$	43	$	—	$	259	June 30, 2020	1		122		67		0		28		0		41		0		259
June 30, 2019		1		161		20		5		15		—		27		—		229

___________

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

Three months ended Retail ERCOT PJM NY/NE MISO Asset Closure Corporate and Other (b) Eliminations (1) Consolidated
June 30, 2020 $ (5) $ 180 $ (76) $ (55) $ (31) $ — $ (8) $ (74) $ (69)
June 30, 2019 6 1,050 184 31 67 — 3 (803) $ 538
Six months ended Retail ERCOT PJM NY/NE MISO Asset Closure Corporate and Other (b) Eliminations (1) Consolidated
June 30, 2020 $ (5) $ 383 $ 4 $ (24) $ (33) $ — $ (1) $ (193) $ 131
June 30, 2019 5 1,287 276 32 46 — 19 (968) $ 697
(b)


Three months ended	Retail		Texas		East		West		Sunset		Asset Closure		Corporate and Other		Eliminations (1)		Consolidated
June 30, 2021	$	(18)	$	(1,116)	$	(148)	$	(35)	$	(362)	$	0	$	0	$	1,336	$	(343)
June 30, 2020	(5)		180		(68)		(8)		(94)		0		0		(74)		$	(69)
Six Months ended	Retail		Texas		East		West		Sunset		Asset Closure		Corporate and Other		Eliminations (1)		Consolidated
June 30, 2021	$	(22)	$	(1,657)	$	(183)	$	(88)	$	(461)	$	0	$	0	$	2,126	$	(285)
June 30, 2020	(5)		383		(13)		(1)		(40)		0		0		(193)		$	131

____________

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

(b)~~Other includes CAISO operations.~~ Income tax expense is not reflected in net income of the segments but is reflected entirely in Corporate and Other net income.

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~~18.~~17.SUPPLEMENTARY FINANCIAL INFORMATION

~~Pension and OPEB Plans~~ — ~~Components of Net Benefit Cost~~

~~For the three and six months ended June 30, 2020 and 2019, net periodic benefit costs consisted of the following:~~

Pension Benefits OPEB Benefits
Three Months Ended June 30, Six Months Ended
June 30, Three Months Ended June 30, Six Months Ended
June 30,
2020 2019 2020 2019 2020 2019 2020 2019
Service cost $ 2 $ 2 $ 4 $ 4 $ — $ — $ — $ —
Other costs — — 1 — 2 2 4 4
Net periodic benefit cost $ 2 $ 2 $ 5 $ 4 $ 2 $ 2 $ 4 $ 4

Impairment of Long-Lived Assets

In ~~March~~the second quarter of 2021, we recognized an impairment loss of $38 million related to our Zimmer generation Facility in Ohio, and in the first quarter of 2020, we recognized an impairment loss of $52 million related to our Joppa/EEI coal generation facility in ~~Illinois~~Illinois. Both impairment losses were as a result of a significant decrease in the estimated useful life of the ~~facility,~~facilities, reflecting a decrease in the economic forecast of the facility and ~~changes~~the inability to secure capacity revenues for the ~~operating assumption based on lower forecasted wholesale electricity prices. We~~plant in the latest PJM capacity auction held in May 2021 for Zimmer. In the first quarter of 2020, 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 ~~MISO~~Sunset segment and include ~~a $45 million write-down~~write-downs of property, plant and equipment ~~a $32~~of $33 million ~~write-down~~and $45 million, write-downs of intangible assets of 0 and a$32 million and write-downs of inventory of $5 million and $7 million ~~write-down~~in the second quarter of ~~inventory.~~2021 and the first quarter of 2020, respectively.

Material impairments may occur in the future at coal generation facilities if forward wholesale electricity prices continue to decline or if additional environmental regulations increase the cost of producing electricity at our generation facilities. Specifically, a resolution to the CCR and/or ELG matters could result in increased operating costs and impact the economic viability of our MISO and PJM coal generation facilities (see Note 12).

Interest Expense and Related Charges


		Three Months Ended June 30,						Six Months Ended June 30,							Three Months Ended June 30,				Six Months Ended June 30,
		2020		2019		2020		2019			2021		2020		2021		2020
Interest paid/accrued	Interest paid/accrued	$	121	$	154	$	249	$	305	Interest paid/accrued	$	118	$	121	$	230	$	249
Unrealized mark-to-market net losses on interest rate swaps		18		119		192		199
Unrealized mark-to-market net (gains) losses on interest rate swaps										Unrealized mark-to-market net (gains) losses on interest rate swaps	9		18		(79)		192
Amortization of debt issuance costs, discounts and premiums	Amortization of debt issuance costs, discounts and premiums	4		—		8		(2)		Amortization of debt issuance costs, discounts and premiums	9		4		14		8
Debt extinguishment gain		(3)		(3)		(11)		(10)
Debt extinguishment (gain) loss										Debt extinguishment (gain) loss	1		(3)		1		(11)
Capitalized interest	Capitalized interest	(5)		(3)		(9)		(7)		Capitalized interest	(10)		(5)		(18)		(9)
Other	Other	6		7		11		10		Other	8		6		16		11
Total interest expense and related charges	Total interest expense and related charges	$	141	$	274	$	440	$	495	Total interest expense and related charges	$	135	$	141	$	164	$	440

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note ~~11,~~10, was ~~3.53%~~3.89% and ~~4.03%~~3.53% at June 30, ~~2020~~2021 and ~~2019.~~2020.

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Other Income and Deductions


		Three Months Ended June 30,						Six Months Ended June 30,							Three Months Ended June 30,				Six Months Ended June 30,
		2020		2019		2020		2019			2021		2020		2021		2020
Other income:	Other income:									Other income:

Insurance settlement (a)	Insurance settlement (a)	$	2	$	8	$	5	$	19	Insurance settlement (a)	$	27	$	2	$	65	$	5
Funds released from escrow to settle pre-petition claims of our predecessor		—		—		—		9

Gain on settlement of rail transportation disputes (b)										Gain on settlement of rail transportation disputes (b)	0		0		15		0

Interest income	Interest income	1		3		1		7		Interest income	0		1		0		1
All other	All other	2		2		6		4		All other	9		2		12		6
Total other income	Total other income	$	5	$	13	$	12	$	39	Total other income	$	36	$	5	$	92	$	12
Other deductions:	Other deductions:									Other deductions:

Loss on disposal of investment in NELP ~~(b)~~(c)	Loss on disposal of investment in NELP ~~(b)~~(c)	$	1	$	—	$	29	$	—	Loss on disposal of investment in NELP ~~(b)~~(c)	$	0	$	1	$	0	$	29

All other	All other	3		2		6		5		All other	2		3		7		6
Total other deductions	Total other deductions	$	4	$	2	$	35	$	5	Total other deductions	$	2	$	4	$	7	$	35

____________

(a)~~The amount for~~For both the three months ended June 30, 2021 and 2020, reported in the ~~ERCOT~~Texas segment. For the six months ended June 30, 2021, $63 million reported in the Texas segment and $2 million reported in the Corporate and other non-segment. For the six months ended June 30, 2020, $3 million reported in the Corporate and Other non-segment and $2 million reported in the ~~ERCOT segment. The amounts for the three and six months ended June 30, 2019 reported in the ERCOT~~Texas segment.

(b)~~For the six months ended June 30, 2020, loss of $15 million reported~~Reported in the ~~NY/NE segment and $14 million~~Asset Closure segment.

(c)Reported in the ~~PJM~~East segment.

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Restricted Cash

June 30, 2020 December 31, 2019
Current Assets Noncurrent Assets Current Assets Noncurrent Assets
Amounts related to remediation escrow accounts $ 20 $ 24 $ 15 $ 28
Amounts related to restructuring escrow accounts 4 — 43 —
Amounts related to Ambit customer deposits — — 19 —
Amounts related to Ambit commodity trading agreement — — 62 —
Amounts related to Ambit letters of credit (Note 11) 3 — 8 —
Total restricted cash $ 27 $ 24 $ 147 $ 28


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

Amounts related to remediation escrow accounts	$	23	$	16	$	19	$	19






Total restricted cash	$	23	$	16	$	19	$	19

Trade Accounts Receivable


		June 30, 2020		December 31, 2019			June 30, 2021		December 31, 2020
Wholesale and retail trade accounts receivable	Wholesale and retail trade accounts receivable	$	1,310	$	1,401	Wholesale and retail trade accounts receivable	$	1,403	$	1,324
Allowance for uncollectible accounts	Allowance for uncollectible accounts	(38)		(36)		Allowance for uncollectible accounts	(51)		(45)
Trade accounts receivable — net	Trade accounts receivable — net	$	1,272	$	1,365	Trade accounts receivable — net	$	1,352	$	1,279

Gross trade accounts receivable at June 30, ~~2020~~2021 and December 31, ~~2019~~2020 included unbilled retail revenues of ~~$483~~$485 million and ~~$494~~$468 million, respectively.

Allowance for Uncollectible Accounts Receivable

Six Months Ended June 30,
2020 2019
Allowance for uncollectible accounts receivable at beginning of period (a) $ 42 $ 19
Increase for bad debt expense 45 29
Decrease for account write-offs (49) (31)
Allowance for uncollectible accounts receivable at end of period $ 38 $ 17

~~____________~~

~~(a)Includes a $6 million increase recorded due to the adoption of ASU 2016-13,~~ ~~Financial Instruments—Credit Losses~~ ~~(see Note 1).~~


	Six Months Ended June 30,
	2021		2020
Allowance for uncollectible accounts receivable at beginning of period	$	45	$	42
Increase for bad debt expense	55		45
Decrease for account write-offs	(49)		(49)

Allowance for uncollectible accounts receivable at end of period	$	51	$	38

~~Table of Contents~~

Inventories by Major Category


		June 30, 2020		December 31, 2019			June 30, 2021		December 31, 2020
Materials and supplies	Materials and supplies	$	274	$	278	Materials and supplies	$	257	$	260
Fuel stock	Fuel stock	250		172		Fuel stock	202		236
Natural gas in storage	Natural gas in storage	17		19		Natural gas in storage	27		19
Total inventories	Total inventories	$	541	$	469	Total inventories	$	486	$	515

Investments

June 30,
2020 December 31,
2019
Nuclear plant decommissioning trust $ 1,466 $ 1,451
Assets related to employee benefit plans 37 37
Land 49 49
Total investments $ 1,552 $ 1,537

~~Investment in Unconsolidated Subsidiary~~

On the Merger Date, we assumed Dynegy's 50% interest in Northeast Energy, LP (NELP), a joint venture with NextEra Energy, Inc., which indirectly owns the Bellingham NEA facility and the Sayreville facility. At December 31, 2019, our investment in NELP totaled $123 million.

In December 2019, Dynegy Northeast Generation GP, Inc. and Dynegy Northeast Associates LP, Inc., indirect subsidiaries of Vistra, entered into a transaction agreement with NELP and certain indirect subsidiaries of NextEra Energy, Inc. wherein the indirect subsidiaries of Vistra redeemed their ownership interest in NELP in exchange for 100% ownership interest in NJEA, the company which owns the Sayreville facility. The NELP Transaction was approved by FERC in February 2020, and the NELP Transaction closed on March 2, 2020. As a result of the NELP Transaction, Vistra indirectly owns 100% of the Sayreville facility and no longer has any ownership interest in the Bellingham NEA facility. A loss of $29 million was recognized in connection with the NELP Transaction, reflecting the difference between our derecognized investment in NELP and the value of our acquired 100% interest in North Jersey Energy Associates, which was measured in accordance with ASC 805. The loss is reported in our condensed consolidated statements of operations in other deductions.


	June 30, 2021		December 31, 2020
Nuclear plant decommissioning trust	$	1,824	$	1,674
Assets related to employee benefit plans	42		41
Land	44		44
Miscellaneous other	2		0
Total investments	$	1,912	$	1,759

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Equity earnings related to our investment in NELP totaled $3 million for the three months ended June 30, 2019 and $3 million and $9 million for the six months ended June 30, 2020 and 2019, respectively, recorded in equity in earnings (loss) of unconsolidated investment in our condensed consolidated statements of operations. We received distributions totaling $9 million for the three months ended June 30, 2019 and $3 million and $14 million for the six months ended June 30, 2020 and 2019, respectively.

Nuclear Decommissioning Trust

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


		June 30, 2020		December 31, 2019			June 30, 2021		December 31, 2020
Debt securities (a)	Debt securities (a)	$	588	$	521	Debt securities (a)	$	639	$	618
Equity securities (b)	Equity securities (b)	878		930		Equity securities (b)	1,185		1,056
Total	Total	$	1,466	$	1,451	Total	$	1,824	$	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 of ~~3.16%~~2.62% and ~~3.42%~~2.91% at June 30, ~~2020~~2021 and December 31, ~~2019,~~2020, respectively, and an average maturity of ~~ten~~nine years and ~~nine~~ten years at June 30, ~~2020~~2021 and December 31, ~~2019,~~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 June 30, ~~2020~~2021 mature as follows: ~~$194~~$232 million in one to five years, ~~$165~~$201 million in five to 10 years and ~~$229~~$206 million after 10 years.

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


		Three Months Ended June 30,						Six Months Ended June 30,							Three Months Ended June 30,				Six Months Ended June 30,
		2020		2019		2020		2019			2021		2020		2021		2020
Proceeds from sales of securities	Proceeds from sales of securities	$	149	$	214	$	224	$	292	Proceeds from sales of securities	$	134	$	149	$	267	$	224
Investments in securities	Investments in securities	$	(154)	$	(219)	$	(234)	$	(302)	Investments in securities	$	(139)	$	(154)	$	(277)	$	(234)

Property, Plant and Equipment


		June 30, 2020		December 31, 2019			June 30, 2021		December 31, 2020
Power generation and structures	Power generation and structures	$	15,479	$	15,205	Power generation and structures	$	15,894	$	15,222
Land	Land	623		622		Land	615		617
Office and other equipment	Office and other equipment	171		164		Office and other equipment	176		173
Total	Total	16,273		15,991		Total	16,685		16,012
Less accumulated depreciation	Less accumulated depreciation	(3,160)		(2,553)		Less accumulated depreciation	(4,204)		(3,614)
Net of accumulated depreciation	Net of accumulated depreciation	13,113		13,438		Net of accumulated depreciation	12,481		12,398
Finance lease right-of-use assets		56		59
Nuclear fuel (net of accumulated amortization of $159 million and $216 million)		211		197
Finance lease right-of-use assets (net of accumulated depreciation)						Finance lease right-of-use assets (net of accumulated depreciation)	177		182
Nuclear fuel (net of accumulated amortization of $131 million and $91 million)						Nuclear fuel (net of accumulated amortization of $131 million and $91 million)	200		207
Construction work in progress	Construction work in progress	501		220		Construction work in progress	469		712
Property, plant and equipment — net	Property, plant and equipment — net	$	13,881	$	13,914	Property, plant and equipment — net	$	13,327	$	13,499

Depreciation expenses totaled $394 million and $356 million for the three months ended June 30, 2021 and 2020, respectively, and $749 million and $685 million for six months ended June 30, 2021 and 2020, respectively.

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Depreciation expenses totaled $356 million and $312 million for the three months ended June 30, 2020 and 2019, respectively, and $685 million and $647 million for six months ended June 30, 2020 and 2019, respectively.

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. However, because the period of remediation is indeterminable, no removal liabilities have been recognized.

At June 30, ~~2020,~~2021, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled ~~$1.561~~$1.610 billion, which is ~~higher~~lower than the fair value of the assets contained in the nuclear decommissioning trust. Since the costs to ultimately decommission that plant are recoverable through the regulatory rate making process as part of Oncor's delivery fees, a corresponding regulatory ~~asset~~liability has been recorded to our condensed consolidated balance sheet of ~~$95~~$214 million in other noncurrent ~~assets.~~liabilities and deferred credits.

The following table summarizes the changes to these obligations, reported as AROs (current and noncurrent liabilities) in our condensed consolidated balance sheets, for the six months ended June 30, ~~2020~~2021 and ~~2019.~~2020.

Six Months Ended June 30, 2020 Six Months Ended June 30, 2019
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 $ 1,320 $ 410 $ 508 $ 2,238 $ 1,276 $ 442 $ 655 $ 2,373
Additions:
Accretion 22 10 13 45 22 11 16 49
Adjustment for change in estimates (a) 219 (4) (2) 213 — (3) (3) (6)
Adjustment for obligations assumed through acquisitions — — — — — — (3) (3)
Reductions:
Payments — (28) (16) (44) — (32) (16) (48)
Liability at end of period 1,561 388 503 2,452 1,298 418 649 2,365
Less amounts due currently — (92) (46) (138) — (132) (100) (232)
Noncurrent liability at end of period $ 1,561 $ 296 $ 457 $ 2,314 1,298 286 549 2,133

~~____________~~

~~(a)~~The adjustment for nuclear plant decommissioning resulted from a new cost estimate completed in the second quarter of 2020. Under applicable accounting standards, the liability is remeasured when significant changes in the amount or timing of cash flows occur, and the PUCT requires a new cost estimate at least every five years. The increase in the liability was driven by changes in assumptions including increased costs for labor, equipment and services and a delay in timing of when the U.S. Department of Energy is estimated to begin accepting spent fuel offsite.


	Six Months Ended June 30, 2021								Six Months Ended June 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	25		8		11		44		22		10		13		45
Adjustment for change in estimates	0		1		4		5		219		(4)		(2)		213


Reductions:
Payments	0		(28)		(8)		(36)		0		(28)		(16)		(44)


Liability at end of period	1,610		340		499		2,449		1,561		388		503		2,452
Less amounts due currently	0		(87)		(16)		(103)		0		(92)		(46)		(138)
Noncurrent liability at end of period	$	1,610	$	253	$	483	$	2,346	1,561		296		457		2,314

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Other Noncurrent Liabilities and Deferred Credits

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


		June 30, 2020		December 31, 2019			June 30, 2021		December 31, 2020
Retirement and other employee benefits ~~(a)~~	Retirement and other employee benefits ~~(a)~~	$	324	$	295	Retirement and other employee benefits ~~(a)~~	$	311	$	312
Identifiable intangible liabilities (Note 6)		294		286
Winter Storm Uri impact (a)						Winter Storm Uri impact (a)	700		0
Identifiable intangible liabilities (Note 5)						Identifiable intangible liabilities (Note 5)	152		289
Regulatory liability	Regulatory liability	—		131		Regulatory liability	214		89
Finance lease liabilities	Finance lease liabilities	79		78		Finance lease liabilities	226		206
Uncertain tax positions, including accrued interest	Uncertain tax positions, including accrued interest	10		10		Uncertain tax positions, including accrued interest	14		12
Liability for third-party remediation	Liability for third-party remediation	37		41		Liability for third-party remediation	27		31
Environmental allowances		53		52

Accrued severance costs						Accrued severance costs	53		54
Other accrued expenses	Other accrued expenses	154		96		Other accrued expenses	170		138
Total other noncurrent liabilities and deferred credits	Total other noncurrent liabilities and deferred credits	$	951	$	989	Total other noncurrent liabilities and deferred credits	$	1,867	$	1,131

____________

(a)~~We have applied settlement accounting in 2020 due~~Includes the allocation of ERCOT default uplift charges, accrual of Koch earn-out disputed amounts (see Note 11) and future bill credits related to ~~distributions exceeding the current period service~~large commercial and interest costs. For the three and six months ended June 30, 2020, the remeasurement of our pension plan in connection with settlement accounting resulted in an increase in the benefit obligation liability of $1 million and $33 million, respectively, pretax other comprehensive loss of 0 and $30 million, respectively, and settlement expense of $1 million and $3 million, respectively, recognized as other deductions in our condensed consolidated statements of operations.industrial customers that curtailed during Winter Storm Uri.

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Fair Value of Debt


			June 30, 2020						December 31, 2019								June 30, 2021				December 31, 2020
Long-term debt (see Note 11):		Fair Value Hierarchy	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt (see Note 10):											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	Long-term debt under the Vistra Operations Credit Facilities	Level 2	$	2,594	$	2,489	$	2,715	$	2,717	Long-term debt under the Vistra Operations Credit Facilities	Level 2	$	2,564	$	2,538	$	2,579	$	2,565
Vistra Operations Senior Notes	Vistra Operations Senior Notes	Level 2	6,629		6,890		6,620		6,926		Vistra Operations Senior Notes	Level 2	7,874		8,275		6,634		7,204
Vistra Senior Notes		Level 2	179		173		774		772

Forward Capacity Agreements	Forward Capacity Agreements	Level 3	99		99		155		155		Forward Capacity Agreements	Level 3	464		464		45		45
Equipment Financing Agreements	Equipment Financing Agreements	Level 3	80		80		87		87		Equipment Financing Agreements	Level 3	84		84		59		59
Building Financing	Building Financing	Level 2	13		13		16		16		Building Financing	Level 2	6		6		10		10
Other debt	Other debt	Level 3	4		4		12		12		Other debt	Level 3	3		3		3		3

We determine fair value in accordance with accounting standards as discussed in Note ~~14.~~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 June 30, ~~2020~~2021 and December 31, ~~2019:~~2020:


		June 30, 2020		December 31, 2019			June 30, 2021		December 31, 2020
Cash and cash equivalents	Cash and cash equivalents	$	382	$	300	Cash and cash equivalents	$	444	$	406
Restricted cash included in current assets	Restricted cash included in current assets	27		147		Restricted cash included in current assets	23		19
Restricted cash included in noncurrent assets	Restricted cash included in noncurrent assets	24		28		Restricted cash included in noncurrent assets	16		19
Total cash, cash equivalents and restricted cash	Total cash, cash equivalents and restricted cash	$	433	$	475	Total cash, cash equivalents and restricted cash	$	483	$	444

~~Table of Contents~~

The following table summarizes our supplemental cash flow information for the six months ended June 30, ~~2020~~2021 and ~~2019:~~2020:


		Six Months Ended June 30,							Six Months Ended June 30,
		2020		2019			2021		2020
Cash payments related to:	Cash payments related to:					Cash payments related to:
Interest paid	Interest paid	$	262	$	307	Interest paid	$	230	$	262
Capitalized interest	Capitalized interest	(9)		(7)		Capitalized interest	(18)		(9)
Interest paid (net of capitalized interest)	Interest paid (net of capitalized interest)	$	253	$	300	Interest paid (net of capitalized interest)	$	212	$	253
Income taxes paid (refunds received) (a)	Income taxes paid (refunds received) (a)	$	(32)	$	9	Income taxes paid (refunds received) (a)	$	35	$	(32)

Noncash investing and financing activities:	Noncash investing and financing activities:					Noncash investing and financing activities:
Construction expenditures (b)		$	51	$	41

Disposition of investment in NELP	Disposition of investment in NELP	$	123	$	—	Disposition of investment in NELP	$	0	$	123
Acquisition of investment in North Jersey Energy Associates		$	90	$	—
Acquisition of investment in NJEA						Acquisition of investment in NJEA	$	0	$	90

____________

(a)For the six months ended June 30, ~~2020~~2021 and ~~2019,~~2020, we paid state income taxes of $5$37 million and ~~$30~~$8 million, respectively, ~~and~~ received federal tax refunds of 0 and $37 million, respectively, and ~~$21~~received state tax refunds of $2 million and $3 million, respectively.

~~(b)Represents end-of-period accruals for ongoing construction projects.~~

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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 ~~2019~~2020 Form 10-K ~~Part II, Item 1A "Risk Factors" in the Company's quarterly report on Form 10-Q for the period ended March 31, 2020~~ 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 six months ended June 30, ~~2020.~~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 six months ended June 30, ~~2020~~2021 and ~~2019~~2020 should be read in conjunction with our condensed consolidated financial statements and the notes to those statements. Results are impacted by the effects of the Ambit Transaction and the Crius Transaction (see Note 2 to the Financial Statements). Operational results for four facilities retired in late 2019 were recast from the MISO segment to the Asset Closure segment (see Note 4 to the Financial Statements).

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

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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 ~~2019~~2020 Form 10-K.

Business

Operating Segments

Vistra has six reportable segments: (i) Retail, (ii) ~~ERCOT,~~Texas, (iii) ~~PJM,~~East, (iv) ~~NY/NE (comprising NYISO and ISO-NE),~~West, (v) ~~MISO~~Sunset and (vi) Asset Closure. See Note 1716 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 six months ended June 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 the completion of customer billing activities and receipt of the final settlement data from ERCOT, which is expected to be released 180 days after the transaction day. These factors could, but are not expected to, materially change the reported amount of the storm impact. Additionally, we have disputes over certain gas invoices that are not anticipated to have a material impact.

The final amount of the storm impact is also subject to legislative actions that may be taken, such as legislation passed in the Texas Legislature's 87th Session. Securitization bills HB 4492, SB 1580 and HB 1520 may impact the total amount of default balances owed to the market, as well as balances related to exposure to Ancillary Services and the Reliability Deployment Price Adder. 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.

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.

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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 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. 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) 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 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.

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”~~"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.

The fundamentals of the Company remain strong. ~~Vistra believes it has sufficient available liquidity to continue business operations during this volatile period.~~ As described under Available Liquidity, the Company has total available liquidity of ~~$1.669~~$2.337 billion as of June 30, ~~2020,~~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 ~~expenditure reductions, reductions to~~or reducing capital expenditures, planned voluntary debt repayments ~~and cost reductions.~~or operating costs. As a result of the Company's ongoing initiatives, the Company believes it is well positioned to be able to respond to changes in customer demand, regulation or other factors impacting the Company's business related to the COVID-19 pandemic.

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The COVID-19 pandemic presents 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 first or second quarter 2020 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 II, 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 response to the economic and employment impacts of the COVID-19 outbreak, various states have instituted moratoriums or other conditions on disconnections for retail electricity customers. For example, in March and April 2020, the PUCT issued multiple orders requiring REPs in the ERCOT market to suspend late fees for residential customers through May 15, 2020, and to offer deferred payment plans to customers upon request. The PUCT also enacted the COVID-19 Electricity Relief Program whereby REPs must forego disconnecting customers certified as experiencing COVID-19-related hardship, and if such customer would otherwise be subject to disconnection and meets other qualifications, such REP ~~must~~would request suppression of the delivery charges from the transmission and distribution utility and request a proxy energy charge reimbursement from the COVID-19 Electricity Relief Program of $0.04/~~kWh, which is currently set to expire on~~kWh. The PUCT ceased accepting new enrollments under the COVID-19 Electricity Relief Program after August 31, 2020, ~~unless otherwise extended by~~and the ~~PUCT. Residential customers who cannot pay their electric bill(s) due to unemployment from the effects of the COVID-19 disaster must contact the Low-Income List Administrator (LILA)~~disconnection protections and provide an attestation of unemployment and other identifying information, followed by documentation of unemployment. The extent and duration of these orders or other regulatory and legislative actions, rules, policies or requirements cannot be estimated at this time.financial assistance expired after September 30, 2020.

See Note 76 to the Financial Statements for a summary of certain ~~anticipated~~ tax-related impacts of the CARES Act to the Company.

~~Ambit Transaction~~

~~On November 1, 2019 (Ambit Acquisition Date), Volt Asset Company, Inc., an indirect, wholly owned subsidiary of Vistra, completed the acquisition of Ambit (Ambit Transaction). See Note 2~~The COVID-19 pandemic has presented potential new risks to the ~~Financial Statements~~Company's business. Although there have been logistical and other challenges to date, there has been no material adverse impact on the Company's six months ended June 30, 2021 results of operations. The situation surrounding COVID-19 remains fluid and the potential for a ~~summary~~material impact on the Company's results of operations, financial condition and liquidity increases the ~~Ambit Transaction~~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, ~~combination accounting.~~

~~Crius Transaction~~

~~On July 15, 2019, Vienna Acquisition B.C. Ltd., an indirect, wholly owned subsidiary~~financial condition, and results of Vistra, completed the acquisition of the equity interests of two wholly owned subsidiaries of Crius that indirectly own the operating business of Crius (Crius Transaction). See Note 2 to the Financial Statements for a summary of the Crius Transaction and business combination accounting.

operations

~~Acquisition, Development and Disposition of Generation Facilities~~

~~See Note 3 to the Financial Statements for a summary of~~ in our ~~battery energy storage projects. See Note 4 to the Financial Statements for a summary of our generation plant retirements in 2019.~~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 1312 to the Financial Statements for more information about our dividend program.

Share Repurchase Program

In ~~June 2018,~~September 2020, we announced that the Board had authorized a new share repurchase program (Share Repurchase Program) under which up to ~~$500 million~~$1.5 billion of our outstanding common stock may be ~~purchased, and in November 2018, we announced that~~repurchased. The Share Repurchase Program replaced the ~~Board had authorized an incremental~~ share repurchase program ~~under which up~~previously authorized by the Board and became effective on January 1, 2021. The Company continues to ~~$1.250 billion~~evaluate opportunities to reallocate capital for repurchases in the remainder of ~~our outstanding stock may be purchased, resulting in an aggregate $1.750 billion share repurchase program (Share Repurchase Program).~~2021. See Note 1312 to the Financial Statements for more information concerning the Share Repurchase Program, including shares repurchased and remaining amounts available ~~under the Share Repurchase Program.~~for repurchase.

~~Table of Contents~~

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. ~~In 2019 and 2020, we completed several transactions, including~~While the ~~redemption and repayment of all previously outstanding senior notes issued by Parent, that we believe,~~financial impacts resulting from Winter Storm Uri caused an increase in our consolidated net leverage, the ~~aggregate, advanced all of these goals.~~Company remains committed to a strong balance sheet. See Note 1110 to the Financial Statements for details of our long-term debt activity and Note 109 to the Financial Statements for details of ~~the~~our accounts receivable ~~securitization program.~~financing.

Power Price, Natural Gas Price and Market Heat Rate Exposure

Estimated hedging levels for generation volumes in ~~ERCOT, PJM, NYISO, ISO-NE, MISO~~our Texas, East, West and ~~CAISO~~Sunset segments at June 30, ~~2020~~2021 were as follows:

2020 2021
Nuclear/Renewable/Coal Generation:
ERCOT 100 % 83 %
PJM 100 % 97 %
MISO 100 % 80 %
Gas Generation:
ERCOT 100 % 53 %
PJM 99 % 51 %
NYISO/ISO-NE 95 % 83 %
CAISO 100 % 80 %


	2021		2022
Nuclear/Renewable/Coal Generation:
Texas	95	%	75	%
Sunset	95	%	82	%
Gas Generation:
Texas	83	%	18	%
East	99	%	70	%
West	99	%	53	%

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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 ~~pretax~~pre-tax earnings (in millions) taking into account the hedge positions noted above for the periods presented. The residual gas position is calculated based on two steps: first, calculating the difference between actual heat rates of our natural gas generation units and the assumed 7.2 heat rate used to calculate the sensitivity to spark spreads; and second, calculating the residual natural gas exposure that is not already included in the gas generation spark spread sensitivity shown in the table below. The estimates related to price sensitivity are based on our expected generation, related hedges and forward prices as of June 30, ~~2020.~~2021.

Balance 2020 (a) 2021
ERCOT:
Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price $ 1 $ 22
Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price $ — $ (18)
Gas Generation: $1.00/MWh increase in spark spread $ 1 $ 20
Gas Generation: $1.00/MWh decrease in spark spread $ — $ (17)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ 3 $ (27)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price $ (3) $ 15
PJM:
Coal Generation: $2.50/MWh increase in power price $ 2 $ 3
Coal Generation: $2.50/MWh decrease in power price $ — $ —
Gas Generation: $1.00/MWh increase in spark spread $ 1 $ 16
Gas Generation: $1.00/MWh decrease in spark spread $ — $ (14)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ — $ (1)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price $ — $ 1
NYISO/ISO-NE:
Gas Generation: $1.00/MWh increase in spark spread $ 1 $ 3
Gas Generation: $1.00/MWh decrease in spark spread $ — $ (1)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ 1 $ —
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price $ (1) $ —

~~Table of Contents~~

Balance 2020 (a) 2021
MISO/CAISO:
Coal Generation: $2.50/MWh increase in power price $ 2 $ 10
Coal Generation: $2.50/MWh decrease in power price $ — $ (6)
Gas Generation: $1.00/MWh increase in spark spread $ — $ 1
Gas Generation: $1.00/MWh decrease in spark spread $ — $ (1)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ — $ 2
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price $ — $ (2)

~~___________~~


	Balance 2021		2022
Texas:
Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price	$	4	$	30
Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price	$	(3)	$	(28)
Gas Generation: $1.00/MWh increase in spark spread	$	4	$	34
Gas Generation: $1.00/MWh decrease in spark spread	$	(3)	$	(32)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	2	$	(32)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	(4)	$	25
East:
Gas Generation: $1.00/MWh increase in spark spread	$	1	$	15
Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	(12)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	(3)	$	(7)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	3	$	7
West:
Gas Generation: $1.00/MWh increase in spark spread	$	—	$	2
Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	(2)


Sunset:
Coal Generation: $2.50/MWh increase in power price	$	3	$	17
Coal Generation: $2.50/MWh decrease in power price	$	(2)	$	(13)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	—	$	(1)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	—	$	1

~~(a)~~

PJM Auction Results

~~Balance~~

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 ~~2020 is from July 1, 2020 through December 31, 2020.~~purchases, for planning year 2022-2023, are as follows:


	East Segment		Sunset Segment		Total
CP auction capacity sold, net (MW)	5,700		1,519		7,219
Bilateral capacity sold, net (MW)	325		—		325
Total segment capacity sold, net (MW)	6,025		1,519		7,544
Average price per MW-day	$	69.45	$	70.52	$	69.66

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RESULTS OF OPERATIONS

Consolidated Financial Results — Three and Six Months Ended June 30, ~~2020~~2021 Compared to Three and Six Months Ended June 30, ~~2019~~2020


		Three Months Ended June 30,						Favorable (Unfavorable) $ Change			Six Months Ended June 30,									Favorable (Unfavorable) $ Change	Three Months Ended June 30,						Favorable (Unfavorable) $ Change				Six Months Ended June 30,				Favorable (Unfavorable) $ Change
		2020		2019						2020			2019					Favorable (Unfavorable) $ Change	2021		2020		Favorable (Unfavorable) $ Change								2020			Favorable (Unfavorable) $ Change
Operating revenues	Operating revenues	$	2,509	$	2,832	$	(323)	$	5,367		$	5,755		$	(388)	Operating revenues	$		$	2,509	$	56			$	5,367			$	405
Fuel, purchased power costs and delivery fees	Fuel, purchased power costs and delivery fees	(1,029)		(1,139)		110		(2,362)			(2,600)			238		Fuel, purchased power costs and delivery fees	(1,320)		(1,029)		(291)				(6,065)				(2,362)				(3,703)
Operating costs	Operating costs	(412)		(370)		(42)		(792)			(755)			(37)		Operating costs	(429)		(412)		(17)		(801)				(792)				(9)
Depreciation and amortization	Depreciation and amortization	(455)		(384)		(71)		(875)			(790)			(85)		Depreciation and amortization	(464)		(455)		(9)		(887)				(875)				(12)
Selling, general and administrative expenses	Selling, general and administrative expenses	(236)		(210)		(26)		(488)			(392)			(96)		Selling, general and administrative expenses	(252)		(236)		(16)		(502)				(488)				(14)

Impairment of long-lived assets	Impairment of long-lived assets	—		—		—		(84)			—			(84)		Impairment of long-lived assets	(38)		—		(38)		(38)				(84)				46
Operating income		377		729		(352)		766			1,218			(452)
Operating income (loss)																Operating income (loss)	62		377		(315)		(2,521)				766				(3,287)
Other income	Other income	5		13		(8)		12			39			(27)		Other income	36		5		31		92				12				80
Other deductions	Other deductions	(4)		(2)		(2)		(35)			(5)			(30)		Other deductions	(2)		(4)		2		(7)				(35)				28
Interest expense and related charges	Interest expense and related charges	(141)		(274)		133		(440)			(495)			55		Interest expense and related charges	(135)		(141)		6		(164)				(440)				276
Impacts of Tax Receivable Agreement	Impacts of Tax Receivable Agreement	(6)		33		(39)		(14)			36			(50)		Impacts of Tax Receivable Agreement	(41)		(6)		(35)		(4)				(14)				10
Equity in earnings of unconsolidated investment	Equity in earnings of unconsolidated investment	1		3		(2)		4			10			(6)		Equity in earnings of unconsolidated investment	—		1		(1)		—				4				(4)
Income before income taxes		232		502		(270)		293			803			(510)
Income tax expense		(68)		(148)		80		(84)			(225)			141
Net income		$	164	$	354	$	(190)	$	209		$	578		$	(369)
Income (loss) before income taxes																Income (loss) before income taxes	(80)		232		(312)		(2,604)				293				(2,897)
Income tax (expense) benefit																Income tax (expense) benefit	115		(68)		183		600				(84)				684
Net income (loss)																Net income (loss)	$	35	$	164	$	(129)	$	(2,004)			$	209			$	(2,213)


		Three Months Ended June 30, 2020																															Three Months Ended June 30, 2021
		Retail		ERCOT		PJM		NY/NE		MISO		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated			Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	Operating revenues	$	1,956	$	865	$	412	$	131	$	121	$	—	$	(976)	$	2,509	Operating revenues	$	1,919	$	(468)	$	505	$	48	$	(48)	$	—	$	609	$	2,565
Fuel, purchased power costs and delivery fees	Fuel, purchased power costs and delivery fees	(1,468)		(223)		(204)		(58)		(85)		—		1,009		(1,029)		Fuel, purchased power costs and delivery fees	150		(333)		(319)		(38)		(171)		—		(609)		(1,320)
Operating costs	Operating costs	(28)		(196)		(94)		(31)		(45)		(9)		(9)		(412)		Operating costs	(29)		(184)		(69)		(10)		(126)		(11)		—		(429)
Depreciation and amortization	Depreciation and amortization	(82)		(130)		(165)		(48)		(9)		—		(21)		(455)		Depreciation and amortization	(54)		(159)		(193)		(10)		(30)		—		(18)		(464)
Selling, general and administrative expenses	Selling, general and administrative expenses	(146)		(20)		(15)		(12)		(14)		(5)		(24)		(236)		Selling, general and administrative expenses	(175)		(23)		(19)		(8)		(14)		(5)		(8)		(252)

Impairment of long-lived assets																		Impairment of long-lived assets	—		—		—		—		(38)		—		—		(38)
Operating income (loss)	Operating income (loss)	232		296		(66)		(18)		(32)		(14)		(21)		377		Operating income (loss)	1,811		(1,167)		(95)		(18)		(427)		(16)		(26)		62
Other income	Other income	—		3		1		—		1		—		—		5		Other income	1		27		—		—		3		2		3		36
Other deductions	Other deductions	—		(2)		(1)		—		—		—		(1)		(4)		Other deductions	—		(2)		—		—		—		—		—		(2)
Interest expense and related charges	Interest expense and related charges	(3)		2		(1)		—		(1)		—		(138)		(141)		Interest expense and related charges	(2)		4		(5)		5		—		—		(137)		(135)
Impacts of Tax Receivable Agreement	Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(6)		(6)		Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(41)		(41)
Equity in earnings of unconsolidated investment		—		—		1		—		—		—		—		1

Income (loss) before income taxes	Income (loss) before income taxes	229		299		(66)		(18)		(32)		(14)		(166)		232		Income (loss) before income taxes	1,810		(1,138)		(100)		(13)		(424)		(14)		(201)		(80)
Income tax expense		—		—		—		—		—		—		(68)		(68)
Income tax benefit																		Income tax benefit	—		—		—		—		—		—		115		115
Net income (loss)	Net income (loss)	$	229	$	299	$	(66)	$	(18)	$	(32)	$	(14)	$	(234)	$	164	Net income (loss)	$	1,810	$	(1,138)	$	(100)	$	(13)	$	(424)	$	(14)	$	(86)	$	35

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Three Months Ended June 30, 2019
Retail ERCOT PJM NY/NE MISO Asset
Closure Eliminations / Corporate and Other Vistra
Consolidated
Operating revenues $ 1,421 $ 1,671 $ 686 $ 254 $ 188 $ 58 $ (1,446) $ 2,832
Fuel, purchased power costs and delivery fees (1,828) (299) (265) (100) (78) (42) 1,473 (1,139)
Operating costs (11) (174) (86) (25) (34) (32) (8) (370)
Depreciation and amortization (59) (128) (134) (39) (3) — (21) (384)
Selling, general and administrative expenses (104) (23) (16) (12) (27) (11) (17) (210)
Operating income (loss) (581) 1,047 185 78 46 (27) (19) 729
Other income — 8 — — 2 1 2 13
Other deductions — (2) — — — — — (2)
Interest expense and related charges (4) 3 (3) (1) (2) — (267) (274)
Impacts of Tax Receivable Agreement — — — — — — 33 33
Equity in earnings of unconsolidated investment — — 1 2 — — — 3
Income (loss) before income taxes (585) 1,056 183 79 46 (26) (251) 502
Income tax expense — — — — — — (148) (148)
Net income (loss) $ (585) $ 1,056 $ 183 $ 79 $ 46 $ (26) $ (399) $ 354

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 significant economic disruption. 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 expectations and significant cash from operations despite general uncertainty in the overall economy.


	Three Months Ended June 30, 2020
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	1,956	$	841	$	465	$	45	$	221	$	2	$	(1,021)	$	2,509
Fuel, purchased power costs and delivery fees	(1,468)		(207)		(214)		(13)		(149)		—		1,022		(1,029)
Operating costs	(28)		(190)		(85)		(8)		(90)		(10)		(1)		(412)
Depreciation and amortization	(82)		(120)		(192)		(5)		(39)		(1)		(16)		(455)
Selling, general and administrative expenses	(146)		(19)		(23)		(5)		(19)		(5)		(19)		(236)

Impairment of long-lived assets	—		—		—		—		—		—		—		—
Operating income (loss)	232		305		(49)		14		(76)		(14)		(35)		377
Other income	—		1		1		—		1		2		—		5
Other deductions	—		(2)		(1)		—		—		—		(1)		(4)
Interest expense and related charges	(3)		2		(1)		2		(1)		—		(140)		(141)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(6)		(6)
Equity in earnings of unconsolidated investment	—		—		1		—		—		—		—		1
Income (loss) before income taxes	229		306		(49)		16		(76)		(12)		(182)		232
Income tax expense	—		—		—		—		—		—		(68)		(68)
Net income (loss)	$	229	$	306	$	(49)	$	16	$	(76)	$	(12)	$	(250)	$	164

Consolidated results decreased ~~$190~~$315 million to ~~net~~operating income of ~~$164~~$62 million in the three months ended June 30, ~~2020~~2021 compared to the three months ended June 30, ~~2019.~~2020. The change in results is driven by a ~~$519~~$276 million ~~decrease~~pre-tax increase in unrealized ~~net (gains)~~ losses on commodity hedging transactions.

For the three months ended June 30, ~~2020~~2021 and ~~2019, operating costs increased $42 million to $412 million primarily driven by increased LTSA costs and incremental expense related to our COVID-19 response.~~

~~For the three months ended June 30,~~ 2020, ~~and 2019, selling, general and administrative expense increased by $26 million, primarily due to the increased expense resulting from the acquisition of Crius in July 2019 and Ambit in November 2019.~~

Interest expense and related charges decreased $133 million to $141 million in the three months ended June 30, 2020 compared to the three months ended June 30, 2019 driven by a $101 million decrease in unrealized mark-to-market losses on interest rate swaps and a $33 million decrease in interest paid/accrued reflecting the reduction in higher interest Vistra senior unsecured notes through the Redemptions and Tender Offers in 2019 and 2020. See Note 18 to the Financial Statements.

~~For the three months ended June 30, 2020 and 2019,~~ the Impacts of the Tax Receivable Agreement totaled expense of $6$41 million and ~~income of $33~~$6 million, respectively. See Note 87 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement Obligation.

For the three months ended June 30, 2021, income tax benefit totaled $115 million and the effective tax rate was 143.8%. For the three months ended June 30, 2020, income tax expense totaled $68 million and the effective tax rate was 29.3%. ~~For~~See Note 6 to the ~~three~~Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

Table of Contents


	Six Months Ended June 30, 2021
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	3,669	$	615	$	1,230	$	81	$	230	$	—	$	(53)	$	5,772
Fuel, purchased power costs and delivery fees	(1,250)		(3,651)		(773)		(86)		(358)		—		53		(6,065)
Operating costs	(60)		(364)		(123)		(17)		(219)		(18)		—		(801)
Depreciation and amortization	(107)		(283)		(389)		(15)		(59)		—		(34)		(887)
Selling, general and administrative expenses	(347)		(40)		(37)		(15)		(28)		(14)		(21)		(502)

Impairment of long-lived assets	—		—		—		—		(38)		—		—		(38)
Operating income (loss)	1,905		(3,723)		(92)		(52)		(472)		(32)		(55)		(2,521)
Other income	1		64		—		—		4		19		4		92
Other deductions	(4)		(4)		—		—		1		—		—		(7)
Interest expense and related charges	(4)		7		(7)		8		—		—		(168)		(164)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(4)		(4)

Income (loss) before income taxes	1,898		(3,656)		(99)		(44)		(467)		(13)		(223)		(2,604)
Income tax benefit	—		—		—		—		—		—		600		600
Net income (loss)	$	1,898	$	(3,656)	$	(99)	$	(44)	$	(467)	$	(13)	$	377	$	(2,004)

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	Six Months Ended June 30, 2020
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Operating revenues	$	3,864	$	1,702	$	1,189	$	127	$	578	$	2	$	(2,095)	$	5,367
Fuel, purchased power costs and delivery fees	(3,014)		(476)		(600)		(78)		(289)		—		2,095		(2,362)
Operating costs	(58)		(381)		(139)		(14)		(181)		(19)		—		(792)
Depreciation and amortization	(162)		(233)		(360)		(9)		(79)		(1)		(31)		(875)
Selling, general and administrative expenses	(301)		(38)		(56)		(9)		(37)		(12)		(35)		(488)

Impairment of long-lived assets	—		—		—		—		(84)		—		—		(84)
Operating income (loss)	329		574		34		17		(92)		(30)		(66)		766
Other income	—		2		1		—		4		3		2		12
Other deductions	—		(3)		(29)		—		—		(2)		(1)		(35)
Interest expense and related charges	(6)		4		(4)		3		(1)		—		(436)		(440)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(14)		(14)
Equity in earnings of unconsolidated investment	—		—		4		—		—		—		—		4
Income (loss) before income taxes	323		577		6		20		(89)		(29)		(515)		293
Income tax expense	—		—		—		—		—		—		(84)		(84)
Net income (loss)	$	323	$	577	$	6	$	20	$	(89)	$	(29)	$	(599)	$	209

Consolidated results decreased $3.287 billion to a net operating loss of $2.521 billion in the six months ended June 30, ~~2019,~~2021 compared to the six months ended June 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 $182 million in pre-tax unrealized losses on commodity hedging transactions in 2021 compared to $123 million in pre-tax unrealized gains on commodity heading transactions in 2020.

Interest expense and related charges decreased $276 million to $164 million in the six months ended June 30, 2021 compared to the six months ended June 30, 2020 driven by $79 million in unrealized mark-to-market gains on interest rate swaps in 2021 compared to $192 million in unrealized mark-to-market losses on interest rate swaps in 2020. See Note 17 to the Financial Statements.

For the six months ended June 30, 2021 and 2020, the Impacts of the Tax Receivable Agreement totaled expense of $4 million and $14 million, respectively. See Note 7 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement Obligation.

For the six months ended June 30, 2021, income tax ~~expense~~benefit totaled ~~$148~~$600 million and the effective tax rate was ~~29.5%~~23.0%. For the six months ended June 30, 2020, income tax expense totaled $84 million and the effective tax rate was 28.7%. See Note 76 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

Table of Contents

Six Months Ended June 30, 2020
Retail ERCOT PJM NY/NE MISO Asset
Closure Eliminations / Corporate and Other Vistra
Consolidated
Operating revenues $ 3,864 $ 1,731 $ 1,060 $ 417 $ 263 $ — $ (1,968) $ 5,367
Fuel, purchased power costs and delivery fees (3,014) (494) (481) (231) (159) — 2,017 (2,362)
Operating costs (58) (393) (167) (54) (88) (18) (14) (792)
Depreciation and amortization (162) (253) (303) (97) (20) — (40) (875)
Selling, general and administrative expenses (301) (39) (41) (25) (26) (12) (44) (488)
Impairment of long-lived assets — — — — (84) — — (84)
Operating income (loss) 329 552 68 10 (114) (30) (49) 766
Other income — 4 — 1 4 1 2 12
Other deductions — (3) (14) (15) — (2) (1) (35)
Interest expense and related charges (6) 4 (3) (1) (1) — (433) (440)
Impacts of Tax Receivable Agreement — — — — — — (14) (14)
Equity in earnings of unconsolidated investment — — 2 2 — — — 4
Income (loss) before income taxes 323 557 53 (3) (111) (31) (495) 293
Income tax expense — — — — — — (84) (84)
Net income (loss) $ 323 $ 557 $ 53 $ (3) $ (111) $ (31) $ (579) $ 209

Six Months Ended June 30, 2019
Retail ERCOT PJM NY/NE MISO Asset
Closure Eliminations / Corporate and Other Vistra
Consolidated
Operating revenues $ 2,806 $ 2,625 $ 1,391 $ 599 $ 357 $ 143 $ (2,166) $ 5,755
Fuel, purchased power costs and delivery fees (3,024) (633) (581) (329) (171) (101) 2,239 (2,600)
Operating costs (22) (359) (169) (50) (68) (71) (16) (755)
Depreciation and amortization (118) (259) (265) (104) (7) — (37) (790)
Selling, general and administrative expenses (205) (39) (28) (22) (44) (22) (32) (392)
Operating income (loss) (563) 1,335 348 94 67 (51) (12) 1,218
Other income — 20 — — 3 1 15 39
Other deductions — (4) — — — — (1) (5)
Interest expense and related charges (8) 5 (5) (1) (3) — (483) (495)
Impacts of Tax Receivable Agreement — — — — — — 36 36
Equity in earnings of unconsolidated investment — — 3 7 — — — 10
Income (loss) before income taxes (571) 1,356 346 100 67 (50) (445) 803
Income tax benefit — — — — — — (225) (225)
Net income (loss) $ (571) $ 1,356 $ 346 $ 100 $ 67 $ (50) $ (670) $ 578

~~Table of Contents~~

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 significant economic disruption. 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 expectations and significant cash from operations of $1.309 billion for the six months ended June 30, 2020 despite general uncertainty in the overall economy.

Consolidated results decreased $369 million to net income of $209 million in the six months ended June 30, 2020 compared to the six months ended June 30, 2019. The change in results is driven by a $580 million decrease in unrealized gains on hedging transactions, an $84 million impairment of assets related to our Joppa/EEI coal plant and a $29 million loss on disposal of our equity method investment in Northeast Energy, LP (NELP). See Note 18 to the Financial Statements.

For the six months ended June 30, 2020 and 2019, operating costs increased $37 million to $792 million primarily driven by increased LTSA costs and incremental expense related to our COVID-19 response.

For the six months ended June 30, 2020 and 2019, selling, general and administrative expense increased by $96 million, primarily due to the increased expense resulting from the acquisition of Crius in July 2019 and Ambit in November 2019 and a nonrecurring charge of approximately $10 million related to gross receipts taxes.

Interest expense and related charges decreased $55 million to $440 million in the six months ended June 30, 2020 compared to the six months ended June 30, 2019 driven by a $56 million decrease in interest paid/accrued reflecting the reduction in higher interest Vistra senior unsecured notes through the Redemptions and Tender Offers in 2019 and 2020 and a $7 million decrease in unrealized mark-to-market losses on interest rate swaps. See Note 18 to the Financial Statements.

For the six months ended June 30, 2020 and 2019, the Impacts of the Tax Receivable Agreement totaled expense of $14 million and income of $36 million, respectively. See Note 8 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement Obligation.

For the six months ended June 30, 2020, income tax expense totaled $84 million and the effective tax rate was 28.7%. For the six months ended June 30, 2019, income tax expense totaled $225 million and the effective tax rate was 28.0%. See Note 7 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

Discussion of Adjusted EBITDA

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

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

Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers, and evaluate overall financial performance, we believe they provide useful information for investors.

~~Table of Contents~~

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).

Table of Contents

Adjusted EBITDA — Three and Six Months Ended June 30, ~~2020~~2021 Compared to Three and Six Months Ended June 30, ~~2019~~2020


		Three Months Ended June 30,						Favorable (Unfavorable) $ Change			Six Months Ended June 30,										Favorable (Unfavorable) $ Change			Three Months Ended June 30,						Favorable (Unfavorable) $ Change		Six Months Ended June 30,				Favorable (Unfavorable) $ Change
		2020		2019						2020			2019					Favorable (Unfavorable) $ Change		2021				2020				Favorable (Unfavorable) $ Change				2020		Favorable (Unfavorable) $ Change
Net income		$	164	$	354	$	(190)	$	209		$	578		$	(369)
Income tax expense		68		148		(80)		84			225			(141)
Net income (loss)																Net income (loss)	$		35			$	164			$	(129)			$	(2,004)	$	209	$	(2,213)
Income tax expense (benefit)																Income tax expense (benefit)	(115)			68				(183)				(600)		84		(684)
Interest expense and related charges (a)	Interest expense and related charges (a)	141		274		(133)		440			495			(55)		Interest expense and related charges (a)	135			141				(6)				164		440		(276)
Depreciation and amortization (b)	Depreciation and amortization (b)	472		399		73		912			824			88		Depreciation and amortization (b)	484			472				12				927		912		15
EBITDA before Adjustments	EBITDA before Adjustments	845		1,175		(330)		1,645			2,122			(477)		EBITDA before Adjustments	539			845				(306)				(1,513)		1,645		(3,158)
Unrealized net (gain) loss resulting from hedging transactions	Unrealized net (gain) loss resulting from hedging transactions	2		(517)		519		(123)			(703)			580		Unrealized net (gain) loss resulting from hedging transactions	278			2				276				182		(123)		305

Generation plant retirement expenses																Generation plant retirement expenses	15			—				15				15		—		15
Fresh start/purchase accounting impacts	Fresh start/purchase accounting impacts	30		20		10		34			33			1		Fresh start/purchase accounting impacts	(79)			30				(109)				(79)		34		(113)
Impacts of Tax Receivable Agreement	Impacts of Tax Receivable Agreement	6		(33)		39		14			(36)			50		Impacts of Tax Receivable Agreement	41			6				35				4		14		(10)

Non-cash compensation expenses	Non-cash compensation expenses	17		11		6		30			24			6		Non-cash compensation expenses	12			17				(5)				29		30		(1)
Transition and merger expenses	Transition and merger expenses	—		27		(27)		19			44			(25)		Transition and merger expenses	1			—				1				(13)		19		(32)
Impairment of long-lived assets	Impairment of long-lived assets	—		—		—		84			—			84		Impairment of long-lived assets	38			—				38				38		84		(46)
Loss on disposal of investment in NELP	Loss on disposal of investment in NELP	1		—		1		29			—			29		Loss on disposal of investment in NELP	—			1				(1)				—		29		(29)
COVID-19-related expenses (c)	COVID-19-related expenses (c)	12		—		12		14			—			14		COVID-19-related expenses (c)	1			12				(11)				4		14		(10)
Winter Storm Uri impact (d)																Winter Storm Uri impact (d)	(35)			—				(35)				900		—		900
Other, net	Other, net	3		9		(6)		3			10			(7)		Other, net	—			3				(3)				3		3		—
Adjusted EBITDA	Adjusted EBITDA	$	916	$	692	$	224	$	1,749		$	1,494		$	255	Adjusted EBITDA	$	811		$	916			$	(105)			$	(430)	$	1,749	$	(2,179)

____________

(a)Includes unrealized mark-to-market net losses on interest rate swaps of ~~$18~~$9 million and ~~$119~~$18 million for the three months ended June 30, ~~2020~~2021 and ~~2019,~~2020, respectively, and ~~$192~~unrealized mark-to-market net gains on interest rate swaps of $79 million and ~~$199~~unrealized mark-to-market net losses on interest rate swaps of $192 million for the six months ended June 30, ~~2020~~2021 and ~~2019,~~2020, respectively.

(b)Includes nuclear fuel amortization in the ~~ERCOT~~Texas segment of ~~$17~~$20 million and ~~$15~~$17 million for the three months ended June 30, ~~2020~~2021 and ~~2019,~~2020, respectively, and ~~$37~~$40 million and ~~$34~~$37 million for the six months ended June 30, ~~2020~~2021 and ~~2019,~~2020, respectively.

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

(d)For the six months ended June 30, 2021, includes the following amounts, which we believe are not reflective of our operating performance: $196 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; $418 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 $80 million), 2022 (approximately $165 million), 2023 (approximately $95 million) and 2024 (approximately $20 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


	Three Months Ended June 30, 2021
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	$	1,810	$	(1,138)	$	(100)	$	(13)	$	(424)	$	(14)	$	(86)	$	35
Income tax benefit	—		—		—		—		—		—		(115)		(115)
Interest expense and related charges (a)	2		(4)		5		(5)		—		—		137		135
Depreciation and amortization (b)	54		179		193		10		30		—		18		484
EBITDA before Adjustments	1,866		(963)		98		(8)		(394)		(14)		(46)		539
Unrealized net (gain) loss resulting from hedging transactions	(1,318)		1,093		133		27		343		—		—		278
Generation plant retirement expenses	—		—		—		—		14		—		1		15
Fresh start/purchase accounting impacts	2		(1)		(73)		—		(7)		—		—		(79)
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		41		41

Non-cash compensation expenses	—		—		—		—		—		—		12		12
Transition and merger expenses	3		—		—		—		—		—		(2)		1
Impairment of long lived assets	—		—		—		—		38		—		—		38
Loss on disposal of investment in NELP	—		��		—		—		—		—		—		—
COVID-19-related expenses (c)	—		1		—		—		—		—		—		1
Winter Storm Uri impacts (d)	(47)		12		—		—		—		—		—		(35)
Other, net	4		2		2		2		2		—		(12)		—
Adjusted EBITDA	$	510	$	144	$	160	$	21	$	(4)	$	(14)	$	(6)	$	811

____________

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

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

(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, partially offset by additional ERCOT default uplift charges and ongoing Winter Storm Uri related legal fees and other costs.


	Three Months Ended June 30, 2020
	Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	$	229	$	306	$	(49)	$	16	$	(76)	$	(12)	$	(250)	$	164
Income tax expense	—		—								—		68		68
Interest expense and related charges (a)	3		(2)		1		(2)		1		—		140		141
Depreciation and amortization (b)	82		137		192		5		39		1		16		472
EBITDA before Adjustments	314		441		144		19		(36)		(11)		(26)		845
Unrealized net (gain) loss resulting from hedging transactions	81		(190)		40		(3)		74		—		—		2

Fresh start/purchase accounting impacts	5		(2)		17		—		10		—		—		30
Impacts of Tax Receivable Agreement	—		—		—		—		—		—		6		6

Non-cash compensation expenses	—		—		—		—		—		—		17		17
Transition and merger expenses	1		(1)		—		—		—		(3)		3		—
Loss on disposal of investment in NELP	—		—		1		—		—		—		—		1
COVID-19-related expenses (c)	—		9		1		—		2		—		—		12
Other, net	—		3		3		—		2		1		(6)		3
Adjusted EBITDA	$	401	$	260	$	206	$	16	$	52	$	(13)	$	(6)	$	916

Table of Contents

Three Months Ended June 30, 2020
Retail ERCOT PJM NY/NE MISO Asset
Closure Eliminations / Corporate and Other Vistra
Consolidated
Net income (loss) $ 229 $ 299 $ (66) $ (18) $ (32) $ (14) $ (234) $ 164
Income tax expense — — — — — — 68 68
Interest expense and related charges (a) 3 (2) 1 — 1 — 138 141
Depreciation and amortization (b) 82 147 165 48 9 — 21 472
EBITDA before Adjustments 314 444 100 30 (22) (14) (7) 845
Unrealized net (gain) loss resulting from hedging transactions 81 (190) 67 33 14 — (3) 2
Fresh start/purchase accounting impacts 5 (2) 12 7 8 — — 30
Impacts of Tax Receivable Agreement — — — — — — 6 6
Non-cash compensation expenses — — — — — — 17 17
Transition and merger expenses 1 (4) — — — — 3 —
Loss on disposal of investment in NELP — — 1 — — — — 1
COVID-19-related expenses (c) — 9 2 — 1 — — 12
Other, net — 3 1 2 2 1 (6) 3
Adjusted EBITDA $ 401 $ 260 $ 183 $ 72 $ 3 $ (13) $ 10 $ 916

____________

(a)Includes $18 million of unrealized mark-to-market net losses on interest rate swaps.

(b)Includes nuclear fuel amortization of $17 million in ~~ERCOT~~Texas segment.

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


		Three Months Ended June 30, 2019																															Six Months Ended June 30, 2021
		Retail		ERCOT		PJM		NY/NE		MISO		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated			Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	Net income (loss)	$	(585)	$	1,056	$	183	$	79	$	46	$	(26)	$	(399)	$	354	Net income (loss)	$	1,898	$	(3,656)	$	(99)	$	(44)	$	(467)	$	(13)	$	377	$	(2,004)
Income tax expense		—		—								—		148		148
Income tax benefit																		Income tax benefit	—		—		—		—		—		—		(600)		(600)
Interest expense and related charges (a)	Interest expense and related charges (a)	4		(3)		3		1		2		—		267		274		Interest expense and related charges (a)	4		(7)		7		(8)		—		—		168		164
Depreciation and amortization (b)	Depreciation and amortization (b)	59		143		134		39		3		—		21		399		Depreciation and amortization (b)	107		323		389		15		59		—		34		927
EBITDA before Adjustments	EBITDA before Adjustments	(522)		1,196		320		119		51		(26)		37		1,175		EBITDA before Adjustments	2,009		(3,340)		297		(37)		(408)		(13)		(21)		(1,513)
Unrealized net (gain) loss resulting from hedging transactions	Unrealized net (gain) loss resulting from hedging transactions	797		(1,047)		(163)		(32)		(65)		—		(7)		(517)		Unrealized net (gain) loss resulting from hedging transactions	(2,101)		1,615		153		80		435		—		—		182

Generation plant retirement expenses																		Generation plant retirement expenses	—		—		—		—		15		—		—		15
Fresh start/purchase accounting impacts	Fresh start/purchase accounting impacts	15		(1)		2		1		3		1		(1)		20		Fresh start/purchase accounting impacts	3		(2)		(74)		—		(6)		—		—		(79)
Impacts of Tax Receivable Agreement	Impacts of Tax Receivable Agreement	—		—		—		—		—		—		(33)		(33)		Impacts of Tax Receivable Agreement	—		—		—		—		—		—		4		4

Non-cash compensation expenses	Non-cash compensation expenses	—		—		—		—		—		—		11		11		Non-cash compensation expenses	—		—		—		—		—		—		29		29
Transition and merger expenses	Transition and merger expenses	—		5		1		1		17		—		3		27		Transition and merger expenses	3		—		—		—		—		(15)		(1)		(13)
Impairment of long-lived assets																		Impairment of long-lived assets	—		—		—		—		38		—		—		38

COVID-19-related expenses (c)																		COVID-19-related expenses (c)	—		2		1		—		1		—		—		4
Winter Storm Uri impacts (d)																		Winter Storm Uri impacts (d)	384		514		—		—		1		—		1		900
Other, net	Other, net	3		3		7		2		5		—		(11)		9		Other, net	12		3		3		2		3		—		(20)		3
Adjusted EBITDA	Adjusted EBITDA	$	293	$	156	$	167	$	91	$	11	$	(25)	$	(1)	$	692	Adjusted EBITDA	$	310	$	(1,208)	$	380	$	45	$	79	$	(28)	$	(8)	$	(430)

____________

(a)Includes ~~$119~~$79 million of unrealized mark-to-market net ~~losses~~gains on interest rate swaps.

(b)Includes nuclear fuel amortization of ~~$15~~$40 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: $196 million for allocation of ERCOT ~~segment.~~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; $418 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 $80 million), 2022 (approximately $165 million), 2023 (approximately $95 million) and 2024 (approximately $20 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


		Six Months Ended June 30, 2020																															Six Months Ended June 30, 2020
		Retail		ERCOT		PJM		NY/NE		MISO		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated			Retail		Texas		East		West		Sunset		Asset Closure		Eliminations / Corporate and Other		Vistra Consolidated
Net income (loss)	Net income (loss)	$	323	$	557	$	53	$	(3)	$	(111)	$	(31)	$	(579)	$	209	Net income (loss)	$	323	$	577	$	6	$	20	$	(89)	$	(29)	$	(599)	$	209
Income tax expense	Income tax expense	—		—		—		—		—		—		84		84		Income tax expense	—		—		—		—		—		—		84		84
Interest expense and related charges (a)	Interest expense and related charges (a)	6		(4)		3		1		1		—		433		440		Interest expense and related charges (a)	6		(4)		4		(3)		1		—		436		440
Depreciation and amortization (b)	Depreciation and amortization (b)	162		290		303		97		20		—		40		912		Depreciation and amortization (b)	162		271		360		9		79		—		31		912
EBITDA before Adjustments	EBITDA before Adjustments	491		843		359		95		(90)		(31)		(22)		1,645		EBITDA before Adjustments	491		844		370		26		(9)		(29)		(48)		1,645
Unrealized net (gain) loss resulting from hedging transactions	Unrealized net (gain) loss resulting from hedging transactions	202		(371)		1		12		24		—		9		(123)		Unrealized net (gain) loss resulting from hedging transactions	202		(371)		2		9		35		—		—		(123)

Fresh start/purchase accounting impacts	Fresh start/purchase accounting impacts	8		(5)		14		7		10		—		—		34		Fresh start/purchase accounting impacts	8		(5)		17		—		14		—		—		34
Impacts of Tax Receivable Agreement	Impacts of Tax Receivable Agreement	—		—		—		—		—		—		14		14		Impacts of Tax Receivable Agreement	—		—		—		—		—		—		14		14

Non-cash compensation expenses	Non-cash compensation expenses	—		—		—		—		—		—		30		30		Non-cash compensation expenses	—		—		—		—		—		—		30		30
Transition and merger expenses	Transition and merger expenses	6		(2)		7		—		—		—		8		19		Transition and merger expenses	6		1		7		—		—		(3)		8		19
Impairment of long-lived assets	Impairment of long-lived assets	—		—		—		—		84		—		—		84		Impairment of long-lived assets	—		—		—		—		84		—		—		84
Loss on disposal of investment in NELP	Loss on disposal of investment in NELP	—		—		14		15		—		—		—		29		Loss on disposal of investment in NELP	—		—		29		—		—		—		—		29
COVID-19-related expenses (c)	COVID-19-related expenses (c)	—		9		2		1		1		—		1		14		COVID-19-related expenses (c)	—		9		2		—		2		—		1		14

Other, net	Other, net	5		3		4		2		2		1		(14)		3		Other, net	5		3		6		—		2		1		(14)		3
Adjusted EBITDA	Adjusted EBITDA	$	712	$	477	$	401	$	132	$	31	$	(30)	$	26	$	1,749	Adjusted EBITDA	$	712	$	481	$	433	$	35	$	128	$	(31)	$	(9)	$	1,749

____________

(a)Includes $192 million of unrealized mark-to-market net losses on interest rate swaps.

(b)Includes nuclear fuel amortization of $37 million in ~~ERCOT~~Texas segment.

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

Six Months Ended June 30, 2019
Retail ERCOT PJM NY/NE MISO Asset
Closure Eliminations / Corporate and Other Vistra
Consolidated
Net income (loss) $ (571) $ 1,356 $ 346 $ 100 $ 67 $ (50) $ (670) $ 578
Income tax expense — — — — — — 225 225
Interest expense and related charges (a) 8 (5) 5 1 3 — 483 495
Depreciation and amortization (b) 118 293 265 104 7 — 37 824
EBITDA before Adjustments (445) 1,644 616 205 77 (50) 75 2,122
Unrealized net (gain) loss resulting from hedging transactions 961 (1,298) (255) (38) (50) — (23) (703)
Fresh start/purchase accounting impacts 29 — (5) 3 6 2 (2) 33
Impacts of Tax Receivable Agreement — — — — — — (36) (36)
Non-cash compensation expenses — — — — — — 24 24
Transition and merger expenses — 6 3 2 24 — 9 44
Other, net 5 8 9 5 10 1 (28) 10
Adjusted EBITDA $ 550 $ 360 $ 368 $ 177 $ 67 $ (47) $ 19 $ 1,494

~~____________~~

~~(a)Includes $199 million of unrealized mark-to-market net losses on interest rate swaps.~~

~~(b)Includes nuclear fuel amortization of $34 million in ERCOT segment.~~

~~Table of Contents~~

Retail Segment — Three and Six Months Ended June 30, ~~2020~~2021 Compared to Three and Six Months Ended June 30, ~~2019~~2020


	Three Months Ended June 30,				Favorable (Unfavorable) Change		Six Months Ended June 30,				Favorable (Unfavorable) Change
	2021		2020				2021		2020
Operating revenues:
Revenues in ERCOT	$	1,434	$	1,426	$	8	$	2,604	$	2,697	$	(93)
Revenues in Northeast/Midwest	504		540		(36)		1,091		1,180		(89)
Amortization expense	(2)		(5)		3		(3)		(8)		5
Other revenues	(17)		(5)		(12)		(23)		(5)		(18)
Total operating revenues	1,919		1,956		(37)		3,669		3,864		(195)
Fuel, purchased power costs and delivery fees:
Purchases from affiliates	(726)		(948)		222		(2,177)		(1,902)		(275)
Unrealized net gains (losses) on hedging activities with affiliates	1,336		(76)		1,412		2,126		(195)		2,321
Unrealized net losses on hedging activities	—		—		—		(3)		(2)		(1)
Delivery fees	(436)		(448)		12		(877)		(877)		—
Other costs (a)	(24)		4		(28)		(319)		(38)		(281)
Total fuel, purchased power costs and delivery fees	150		(1,468)		1,618		(1,250)		(3,014)		1,764









Net income	$	1,810	$	229	$	1,581	$	1,898	$	323	$	1,575












Adjusted EBITDA	$	510	$	401	$	109	$	310	$	712	$	(402)

Table of Contents

Three Months Ended June 30, Favorable (Unfavorable)
Change Six Months Ended June 30, Favorable (Unfavorable)
Change
2020 2019 2020 2019
Operating revenues:
Revenues in ERCOT $ 1,426 $ 1,110 $ 316 $ 2,697 $ 2,157 $ 540
Revenues in Northeast/Midwest 540 315 225 1,180 663 517
Amortization expense (5) (10) 5 (8) (19) 11
Other revenues (5) 6 (11) (5) 5 (10)
Total operating revenues 1,956 1,421 535 3,864 2,806 1,058
Fuel, purchased power costs and delivery fees:
Purchases from affiliates (948) (689) (259) (1,902) (1,360) (542)
Unrealized net gains (losses) on hedging activities with affiliates (76) (803) 727 (195) (968) 773
Unrealized net gains (losses) on hedging activities — — — (2) 2 (4)
Delivery fees (448) (346) (102) (877) (694) (183)
Other costs (a) 4 10 (6) (38) (4) (34)
Total fuel, purchased power costs and delivery fees (1,468) (1,828) 360 (3,014) (3,024) 10
Net income (loss) $ 229 $ (585) $ 814 $ 323 $ (571) $ 894
Adjusted EBITDA $ 401 $ 293 $ 108 $ 712 $ 550 $ 162
Retail sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT 13,184 10,693 2,491 24,974 20,476 4,498
Sales volumes in Northeast/Midwest 8,320 6,012 2,308 17,537 12,563 4,974
Total retail electricity sales volumes 21,504 16,705 4,799 42,511 33,039 9,472
Weather (North Texas average) - percent of normal (b):
Cooling degree days 93.0 % 81.0 % 95.0 % 79.0 %
Heating degree days 153.0 % 107.0 % 88.0 % 111.0 %


Retail sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT	13,636		13,184		452	26,483		24,974		1,509
Sales volumes in Northeast/Midwest	8,474		8,320		154	17,524		17,537		(13)
Total retail electricity sales volumes	22,110		21,504		606	44,007		42,511		1,496
Weather (North Texas average) - percent of normal (b):
Cooling degree days	80.6	%	92.9	%		79.3	%	95.1	%
Heating degree days	127.1	%	83.7	%		117.1	%	88.0	%

____________

(a)For the ~~three and~~ six months ended June 30, ~~2020,~~2021, includes ~~third-party fuel~~$162 million of future bill credits to large commercial and ~~power purchases of ($5) million and $37 million, respectively.~~industrial customers.

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

Net income increased by $1.581 billion to $1.810 billion and Adjusted EBITDA increased by $109 million to $510 million in the three months ended June 30, 2021 compared to the three months ended June 30, 2020. Net income increased by $1.575 billion to $1.898 billion and Adjusted EBITDA decreased by $402 million to $310 million in the six months ended June 30, ~~2019, normal is defined as~~2021 compared to the ~~average over the 10-year period from~~six months ended June ~~2009 to June 2018.~~30, 2020.


	Three Months Ended June 30, 2021 Compared to 2020		Six Months Ended June 30, 2021 Compared to 2020
Monetization of certain commercial positions	$	115	$	115
Winter Storm Uri, including bill credits	(37)		(564)
Higher margins	45		77
Other driven by higher SG&A and bad debt expense	(14)		(30)
Change in Adjusted EBITDA	$	109	$	(402)
Favorable impact of higher unrealized net gains on hedging activities	1,399		2,303
Future bill credits and other costs related to Winter Storm Uri	47		(384)
Decrease in depreciation and amortization expenses	28		55
Change in transition and merger and other expenses	(2)		3
Change in net income	$	1,581	$	1,575

Table of Contents

Net income increased by $814 million to $229 million and Adjusted EBITDA increased by $108 million to $401 million in the three months ended June 30, 2020 compared to the three months ended June 30, 2019. Net income increased by $894 million to $323 million and Adjusted EBITDA increased by $162 million to $712 million in the six months ended June 30, 2020 compared to the six months ended June 30, 2019.

Three Months Ended June 30, 2020
Compared to 2019 Six Months Ended
June 30, 2020
Compared to 2019
Higher margin primarily driven by the addition of Crius acquired in July 2019 and Ambit acquired in November 2019 151 $ 252
Other driven by higher SG&A expense and bad debt expense primarily due to the addition of Crius and Ambit (43) (90)
Change in Adjusted EBITDA $ 108 $ 162
Change in depreciation and amortization expenses driven by Crius/Ambit intangibles (14) (35)
Favorable impact of lower unrealized net losses on hedging activities 716 759
Lower transition and merger and other expenses 13 17
Change in net income (loss) $ 823 $ 903

Generation — Three Months Ended June 30, ~~2020~~2021 Compared to Three Months Ended June 30, ~~2019~~2020


	Three Months Ended June 30,
	Texas						East						West						Sunset
	2021			2020			2021			2020			2021			2020			2021			2020
Operating revenues:
Electricity sales	$	340		$	182		$	241		$	174		$	82		$	53		$	191		$	182
Capacity revenue from ISO/RTO	—			—			2			(12)			—			—			43			41
Sales to affiliates	308			479			337			369			—			—			82			99
Rolloff of unrealized net gains (losses) representing positions settled in the current period	(129)			(22)			(23)			22			(6)			(15)			(2)			(56)
Unrealized net gains (losses) on hedging activities	(35)			17			138			(5)			(29)			7			(239)			(12)
Unrealized net gains (losses) on hedging activities with affiliates	(952)			185			(263)			(85)			—			—			(121)			(26)
Other revenues	—			—			73			2			1			—			(2)			(7)
Operating revenues	(468)			841			505			465			48			45			(48)			221
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs	(310)			(187)			(326)			(228)			(44)			(24)			(188)			(169)
Fuel for generation facilities and purchased power costs from affiliates	(1)			2			—			(1)			—			—			—			1
Unrealized gains from hedging activities	23			10			15			26			8			11			19			20
Unrealized net gains on hedging activities with affiliates	—			—			—			2			—			—			—			—
Ancillary and other costs	(45)			(32)			(8)			(13)			(2)			—			(2)			(1)
Fuel, purchased power costs and delivery fees	(333)			(207)			(319)			(214)			(38)			(13)			(171)			(149)










Net income (loss)	$	(1,138)		$	306		$	(100)		$	(49)		$	(13)		$	16		$	(424)		$	(76)













Adjusted EBITDA	$	144		$	260		$	160		$	206		$	21		$	16		$	(4)		$	52
Production volumes (GWh):
Natural gas facilities	6,698			7,525			12,143			12,286			1,101			882
Lignite and coal facilities	5,580			6,012															8,595			5,406
Nuclear facilities	4,879			4,551
Solar/Battery facilities	126			129									3
Capacity factors:
CCGT facilities	37.9		%	42.2		%	49.9		%	50.5		%	49.4		%	39.6		%
Lignite and coal facilities	66.4		%	71.5		%													54.1		%	34.1		%
Nuclear facilities	97.1		%	90.6		%
Weather - percent of normal (a):
Cooling degree days	88.5		%	96.2		%	127.0		%	103.0		%	101.7		%	179.2		%	119.0		%	106.0		%
Heating degree days	148.6		%	158.2		%	94.1		%	133.4		%	96.9		%	69.2		%	95.4		%	117.1		%

___________

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

Three Months Ended June 30,
ERCOT PJM NY/NE MISO
2020 2019 2020 2019 2020 2019 2020 2019
Operating revenues:
Electricity sales $ 205 $ 228 $ 211 $ 240 $ 67 $ 124 $ 57 $ 86
Capacity revenue from ISO/RTO — — 15 53 10 72 4 8
Sales to affiliates 479 392 261 209 108 29 99 31
Rolloff of unrealized net gains (losses) representing positions settled in the current period (22) 22 (4) (6) (20) (13) (10) (4)
Unrealized net gains (losses) on hedging activities 17 393 (6) 64 (16) 38 5 35
Unrealized net gains (losses) on hedging activities with affiliates 185 635 (66) 126 (19) 6 (26) 36
Other revenues 1 1 1 — 1 (2) (8) (4)
Operating revenues 865 1,671 412 686 131 254 121 188
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs (203) (268) (206) (244) (73) (99) (102) (74)
Fuel for generation facilities and purchased power costs from affiliates 2 — (2) — 1 — 1 —
Unrealized (gains) losses from hedging activities 10 (3) 9 (21) 20 1 17 (2)
Unrealized net (gains) losses on hedging activities with affiliates — — — — 2 — — —
Ancillary and other costs (32) (28) (5) — (8) (2) (1) (2)
Fuel, purchased power costs and delivery fees (223) (299) (204) (265) (58) (100) (85) (78)
Net income (loss) $ 299 $ 1,056 $ (66) $ 183 $ (18) $ 79 $ (32) $ 46
Adjusted EBITDA $ 260 $ 156 $ 183 $ 167 $ 72 $ 91 $ 3 $ 11

Table of Contents

Three Months Ended June 30,
ERCOT PJM NY/NE MISO
2020 2019 2020 2019 2020 2019 2020 2019
Production volumes (GWh):
Natural gas facilities 7,525 8,939 9,291 7,936 2,995 3,687
Lignite and coal facilities 6,716 5,800 2,377 2,705 2,325 3,297
Nuclear facilities 4,551 4,060
Solar/Battery facilities 129 131
Capacity factors:
CCGT facilities 42.2 % 49.1 % 67.9 % 59.9 % 29.0 % 35.7 %
Lignite and coal facilities 68.3 % 59.0 % 31.3 % 35.6 % 33.4 % 47.4 %
Nuclear facilities 90.6 % 80.8 %
Weather - percent of normal (a):
Cooling degree days 96.0 % 92.0 % 99.0 % 89.0 % 105.0 % 80.0 % 106.0 % 86.0 %
Heating degree days 158.0 % 136.0 % 144.0 % 83.0 % 130.0 % 100.0 % 117.0 % 93.0 %
Market pricing:
Average ERCOT North power price ($/MWh) $ 16.45 $ 25.09
Average NYMEX Henry Hub natural gas price ($/MMBTU) $ 1.65 $ 2.51
Average Market On-Peak Power Prices ($MWh) (b):
PJM West Hub $ 20.80 $ 28.60
AEP Dayton Hub $ 21.30 $ 28.90
NYISO Zone C $ 16.29 $ 21.80
Massachusetts Hub $ 20.32 $ 27.21
Indiana Hub $ 24.15 $ 29.69
Northern Illinois Hub $ 19.26 $ 26.73
Average natural gas price (c):
TetcoM3 ($/MMBtu) $ 1.43 $ 2.21
Algonquin Citygates ($/MMBtu) $ 1.51 $ 2.33


	Three Months Ended June 30,					Three Months Ended June 30,
	2021		2020			2021		2020
Market pricing					Average Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)	$	35.92	$	16.45	PJM West Hub	$	33.71	$	20.80
					AEP Dayton Hub	$	35.35	$	21.30
Average NYMEX Henry Hub natural gas price ($/MMBtu)	$	2.88	$	1.65	NYISO Zone C	$	22.43	$	16.29
					Massachusetts Hub	$	33.85	$	20.32
Average natural gas price (a):					Indiana Hub	$	35.32	$	24.15
TetcoM3 ($/MMBtu)	$	2.32	$	1.43	Northern Illinois Hub	$	32.07	$	19.26
Algonquin Citygates ($/MMBtu)	$	2.49	$	1.51

___________

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

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

The following table presents changes in net income (loss) and Adjusted EBITDA for the three months ended June 30, 2021 compared to the three months ended June 30, 2020.


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

Favorable/(unfavorable) change in revenue net of fuel	$	(93)	$	(46)	$	8	$	(43)
Winter Storm Uri impact	(47)		—		—		—
Unfavorable change in other operating costs	(1)		(1)		(2)		(22)
Favorable/(unfavorable) change in selling. general and administrative expenses	3		3		(2)		5
Other (a)	22		(2)		1		4
Change in Adjusted EBITDA	$	(116)	$	(46)	$	5	$	(56)
Favorable/(unfavorable) change in depreciation and amortization	(42)		(1)		(5)		9
Change in unrealized net losses on hedging activities	(1,283)		(93)		(30)		(269)
Impairment of long-lived assets	—		—		—		(38)
Generation plant retirement expenses	—		—		—		(14)
Fresh start/purchase accounting impacts	(1)		90		—		17
Transition and merger expenses	(1)		—		—		—
Winter Storm Uri impact (ERCOT default uplift and legal disputes)	(12)		—		—		—
Other (including interest and COVID-19 related expenses)	11		(1)		1		3
Change in Net income (loss)	$	(1,444)	$	(51)	$	(29)	$	(348)

___________

(a) For the three months ended June 30, 2021, includes $27 million of insurance proceeds.

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

The change in West segment results was driven by larger unrealized hedging losses in current year versus 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, impairment and generation plant retirement expenses related to the Zimmer generation facility and larger unrealized hedging losses in current year versus prior year.

Table of Contents

Generation — Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020


	Six Months Ended June 30,
	Texas						East						West						Sunset
	2021			2020			2021			2020			2021			2020			2021			2020
Operating revenues:
Electricity sales	$	1,040		$	441		$	575		$	358		$	167		$	126		$	436		$	375
Capacity revenue from ISO/RTO	—			—			(2)			(9)			—			—			82			83
Sales to affiliates	1,232			878			765			851			2			2			181			171
Rolloff of unrealized net gains (losses) representing positions settled in the current period	(154)			(64)			32			97			(11)			(25)			(54)			(132)
Unrealized net gains (losses) on hedging activities	122			193			132			(76)			(77)			24			(253)			119
Unrealized net gains (losses) on hedging activities with affiliates	(1,625)			254			(347)			(34)			—			—			(154)			(27)
Other revenues	—			—			75			2			—			—			(8)			(11)
Operating revenues	615			1,702			1,230			1,189			81			127			230			578
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs	(1,982)			(401)			(785)			(587)			(92)			(70)			(380)			(293)
Fuel for generation facilities and purchased power costs from affiliates	(1)			4			—			(4)			—			—			(1)			2
Unrealized gains (losses) from hedging activities	42			(12)			30			9			8			(8)			26			5
Unrealized gains from hedging activities with affiliates	—			—			—			2			—			—			—			—
Ancillary and other costs	(1,710)			(67)			(18)			(20)			(2)			—			(3)			(3)
Fuel, purchased power costs and delivery fees	(3,651)			(476)			(773)			(600)			(86)			(78)			(358)			(289)










Net income (loss)	$	(3,656)		$	577		$	(99)		$	6		$	(44)		$	20		$	(467)		$	(89)













Adjusted EBITDA	$	(1,208)		$	481		$	380		$	433		$	45		$	35		$	79		$	128
Production volumes (GWh):
Natural gas facilities	13,545			16,389			26,021			25,434			2,363			2,408
Lignite and coal facilities	11,472			11,491															17,128			11,184
Nuclear facilities	10,089			9,775
Solar/Battery facilities	222			208									3
Capacity factors:
CCGT facilities	38.2		%	46.6		%	54.7		%	53.3		%	53.3		%	54.3		%
Lignite and coal facilities	68.6		%	68.7		%													54.2		%	35.4		%
Nuclear facilities	101.0		%	97.8		%
Weather - percent of normal (a):
Cooling degree days	85.8		%	101.5		%	126.0		%	102.0		%	99.0		%	173.6		%	119.0		%	106.0		%
Heating degree days	122.9		%	80.9		%	96.0		%	92.0		%	108.2		%	91.4		%	94.8		%	88.6		%

____________

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

~~(b)~~

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


	Six Months Ended June 30,					Six Months Ended June 30,
	2021		2020			2021		2020
Market pricing					Average Market On-Peak Power Prices ($MWh) (b):
Average ERCOT North power price ($/MWh)	$	262.00	$	17.92	PJM West Hub	$	34.20	$	21.65
					AEP Dayton Hub	$	35.04	$	21.84
Average NYMEX Henry Hub natural gas price ($/MMBtu)	$	3.13	$	1.76	NYISO Zone C	$	25.88	$	17.31
					Massachusetts Hub	$	44.07	$	22.45
Average natural gas price (a):					Indiana Hub	$	40.16	$	24.40
TetcoM3 ($/MMBtu)	$	2.79	$	1.60	Northern Illinois Hub	$	32.52	$	20.25
Algonquin Citygates ($/MMBtu)	$	3.97	$	1.87

___________

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

~~Table of Contents~~

~~The following table presents changes in net income (loss) and Adjusted EBITDA for the three months ended June 30, 2020 compared to the three months ended June 30, 2019.~~

Three Months Ended June 30, 2020 Compared to 2019
ERCOT PJM NY/NE MISO
Favorable/(unfavorable) change in revenue net of fuel $ 128 $ 12 $ (16) $ 9
Favorable/(unfavorable) change in other operating costs (14) 5 1 (11)
Unfavorable change in selling. general and administrative expenses (3) — (1) (7)
Other (7) (1) (3) 1
Change in Adjusted EBITDA $ 104 $ 16 $ (19) $ (8)
Favorable/(unfavorable) change in depreciation and amortization 4 (31) (9) (6)
Change in unrealized net (gains)/losses on hedging activities (857) (230) (65) (79)
Fresh start/purchase accounting impacts (7) (10) (6) (5)
Transition and merger expenses 9 1 1 17
Other (including interest) (10) 5 1 3
Change in Net income (loss) $ (757) $ (249) $ (97) $ (78)

The change in ERCOT segment results was driven by improved realized margin through hedging activities and plant optimization efforts, partially offset by higher operating costs, lower insurance reimbursement and lower unrealized gains.

The change in PJM segment results was driven by lower unrealized hedging gains, lower capacity revenue and increased depreciation expense, partially offset by improved realized margin through hedging activities and plant optimization efforts.

The change in NY/NE segment results was driven by lower capacity revenue and higher unrealized losses, partially offset by improved realized margin through hedging activities and plant optimization efforts.

~~The change in MISO segment results was driven by lower unrealized hedging gains and higher operating costs.~~

~~Generation~~ — ~~Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019~~

Six Months Ended June 30,
ERCOT PJM NY/NE MISO
2020 2019 2020 2019 2020 2019 2020 2019
Operating revenues:
Electricity sales $ 470 $ 587 $ 439 $ 564 $ 140 $ 375 $ 127 $ 228
Capacity revenue from ISO/RTO — — 30 120 35 152 9 18
Sales to affiliates 878 750 586 431 265 43 171 74
Rolloff of unrealized net gains (losses) representing positions settled in the current period (64) (9) 12 (15) (21) (34) (26) (20)
Unrealized net gains on hedging activities 193 515 17 132 6 60 20 44
Unrealized net gains (losses) on hedging activities with affiliates 254 781 (25) 159 (9) 6 (27) 22
Other revenues — 1 1 — 1 (3) (11) (9)
Operating revenues 1,731 2,625 1,060 1,391 417 599 263 357
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs (419) (587) (462) (560) (233) (331) (167) (171)
Fuel for generation facilities and purchased power costs from affiliates 4 — (4) — — — 2 —
Unrealized (gains) losses from hedging activities (12) 11 (5) (21) 10 6 9 4

~~Table of Contents~~

Six Months Ended June 30,
ERCOT PJM NY/NE MISO
2020 2019 2020 2019 2020 2019 2020 2019
Unrealized (gains) losses from hedging activities with affiliates — — — — 2 — — —
Ancillary and other costs (67) (57) (10) — (10) (4) (3) (4)
Fuel, purchased power costs and delivery fees (494) (633) (481) (581) (231) (329) (159) (171)
Net income (loss) $ 557 $ 1,356 $ 53 $ 346 $ (3) $ 100 $ (111) $ 67
Adjusted EBITDA $ 477 $ 360 $ 401 $ 368 $ 132 $ 177 $ 31 $ 67
Production volumes (GWh):
Natural gas facilities 16,389 17,330 18,721 17,457 6,713 8,640
Lignite and coal facilities 12,279 12,780 5,203 7,644 5,193 7,977
Nuclear facilities 9,775 8,678
Solar/Battery facilities 208 217
Capacity factors:
CCGT facilities 46.6 % 49.0 % 70.1 % 67.1 % 32.7 % 42.1 %
Lignite and coal facilities 62.8 % 65.4 % 34.4 % 50.6 % 37.5 % 57.6 %
Nuclear facilities 97.8 % 86.9 %
Weather - percent of normal (a):
Cooling degree days 102.0 % 89.0 % 99.0 % 89.0 % 105.0 % 80.0 % 106.0 % 86.0 %
Heating degree days 81.0 % 110.0 % 91.0 % 98.0 % 92.0 % 101.0 % 89.0 % 99.0 %
Market pricing:
Average ERCOT North power price ($/MWh) $ 17.92 $ 24.75
Average NYMEX Henry Hub natural gas price ($/MMBTU) $ 1.76 $ 2.70
Average Market On-Peak Power Prices ($MWh) (b):
PJM West Hub $ 21.65 $ 31.25
AEP Dayton Hub $ 21.84 $ 30.77
NYISO Zone C $ 17.31 $ 27.80
Massachusetts Hub $ 22.45 $ 37.42
Indiana Hub $ 24.40 $ 31.81
Northern Illinois Hub $ 20.25 $ 28.31
Average natural gas price (c):
TetcoM3 ($/MMBtu) $ 1.60 $ 2.77
Algonquin Citygates ($/MMBtu) $ 1.87 $ 3.70

~~____________~~

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

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

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

~~Table of Contents~~

The following table presents changes in net income (loss) and Adjusted EBITDA for the six months ended June 30, ~~2020~~2021 compared to the six months ended June 30, ~~2019.~~2020.


		Six Months Ended June 30, 2020 Compared to 2019															Six Months Ended June 30, 2021 Compared to 2020
		ERCOT		PJM		NY/NE		MISO			Texas		East		West		Sunset

Favorable/(unfavorable) change in revenue net of fuel	Favorable/(unfavorable) change in revenue net of fuel	$	167	$	30	$	(39)	$	(8)	Favorable/(unfavorable) change in revenue net of fuel	$	(217)	$	(103)	$	17	$	(52)
Winter Storm Uri impact										Winter Storm Uri impact	(1,548)		50		—		17
Favorable/(unfavorable) change in other operating costs	Favorable/(unfavorable) change in other operating costs	(24)		14		3		(19)		Favorable/(unfavorable) change in other operating costs	15		(2)		(3)		(23)
Unfavorable change in selling. general and administrative expenses		(6)		(3)		(3)		(12)
Other		(20)		(8)		(6)		3
Change in selling, general and administrative expenses										Change in selling, general and administrative expenses	1		8		(4)		11
Other (a)										Other (a)	60		(6)		—		(2)
Change in Adjusted EBITDA	Change in Adjusted EBITDA	$	117	$	33	$	(45)	$	(36)	Change in Adjusted EBITDA	$	(1,689)	$	(53)	$	10	$	(49)
Favorable/(unfavorable) change in depreciation and amortization	Favorable/(unfavorable) change in depreciation and amortization	11		(38)		7		(13)		Favorable/(unfavorable) change in depreciation and amortization	(52)		(29)		(6)		20
Change in unrealized net (gains)/losses on hedging activities		(927)		(256)		(50)		(74)
Change in unrealized net losses on hedging activities										Change in unrealized net losses on hedging activities	(1,986)		(151)		(71)		(400)
Impairment of long-lived assets										Impairment of long-lived assets	—		—		—		46
Generation plant retirement expenses										Generation plant retirement expenses	—		—		—		(15)
Fresh start/purchase accounting impacts	Fresh start/purchase accounting impacts	(3)		(19)		(4)		(4)		Fresh start/purchase accounting impacts	(3)		91		—		20
Transition and merger expenses	Transition and merger expenses	8		(4)		2		24		Transition and merger expenses	1		7		—		—
Impairment of long-lived assets		—		—		—		(84)
Loss on disposal of investment in NELP	Loss on disposal of investment in NELP	—		(14)		(15)		—		Loss on disposal of investment in NELP	—		29		—		—
Other (including interest)		(5)		5		2		9
Winter Storm Uri impact (ERCOT default uplift and legal disputes)										Winter Storm Uri impact (ERCOT default uplift and legal disputes)	(514)		—		—		(1)
Other (including interest and COVID-19 related expenses)										Other (including interest and COVID-19 related expenses)	10		1		3		1
Change in Net income (loss)	Change in Net income (loss)	$	(799)	$	(293)	$	(103)	$	(178)	Change in Net income (loss)	$	(4,233)	$	(105)	$	(64)	$	(378)

___________

(a) For the six months ended June 30, 2021, includes $63 million of insurance proceeds.

The change in Texas segment results was 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 ~~unrealized hedging gains and lower insurance reimbursement, partially offset by higher realized prices through hedging activities and plant optimization efforts.~~

~~The change in PJM segment results was driven by lower unrealized hedging gains, lower capacity~~ revenue ~~and~~net of fuel, loss on disposal of equity method investment in NELP for 100% ownership of ~~North Jersey Energy Associates~~NJEA (see Note 1817 to the Financial Statements), in 2020, partially offset by ~~higher realized prices through~~larger unrealized hedging ~~activities and plant optimization efforts.~~losses in current year versus prior year.

The change in ~~NY/NE~~West segment results was driven by ~~lower capacity~~larger unrealized hedging losses in current year versus prior year, partially offset by a favorable change in revenue ~~and loss on disposal~~net of ~~equity method investment in NELP for 100% ownership of North Jersey Energy Associates (see Note 18 to the Financial Statements).~~fuel.

Table of Contents

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

Asset Closure Segment — Three and Six Months Ended June 30, ~~2020~~2021 Compared to Three and Six Months Ended June 30, ~~2019~~2020


	Three Months Ended June 30,				Favorable (Unfavorable) Change		Six Months Ended June 30,				Favorable (Unfavorable) Change
	2021		2020				2021		2020
Operating revenues	$	—	$	2	$	(2)	$	—	$	2	$	(2)

Operating costs	(11)		(10)		(1)		$	(18)	$	(19)	$	1
Depreciation and amortization	—		(1)		1		—		(1)		1
Selling, general and administrative expenses	(5)		(5)		—		(14)		(12)		(2)


Operating loss	(16)		(14)		(2)		(32)		(30)		(2)
Other income	2		2		—		19		3		16
Other deductions	—		—		—		—		(2)		2


Loss before income taxes	(14)		(12)		(2)		(13)		(29)		16

Net loss	$	(14)	$	(12)	$	(2)	$	(13)	$	(29)	$	16






Adjusted EBITDA	$	(14)	$	(13)	$	(1)	$	(28)	$	(31)	$	3
Production volumes (GWh)	—		—		—		—		—		—

Three Months Ended June 30, Favorable (Unfavorable)
Change Six Months Ended June 30, Favorable (Unfavorable)
Change
2020 2019 2020 2019
Operating revenues $ — $ 58 $ (58) $ — $ 143 $ (143)
Fuel, purchased power costs and delivery fees — (42) 42 — (101) 101
Operating costs (9) (32) 23 (18) (71) 53
Selling, general and administrative expenses (5) (11) 6 (12) (22) 10
Operating loss (14) (27) 13 (30) (51) 21
Other income — 1 (1) 1 1 —
Other deductions — — — (2) — (2)
Loss before income taxes (14) (26) 12 (31) (50) 19
Net loss $ (14) $ (26) $ 12 $ (31) $ (50) $ 19
Adjusted EBITDA $ (13) $ (25) $ 12 $ (30) $ (47) $ 17
Production volumes (GWh) — 1,816 (1,816) — 4,292 (4,292)

~~Table of Contents~~

~~Results for the Asset Closure segment primarily reflect the retirement of the Coffeen, Duck Creek, Havana and Hennepin plants in November and December 2019 (see Note 4 to the Financial Statements).~~ Operating costs for the three and six months ended June 30, 2021 and 2020 included ongoing costs associated with the decommissioning and reclamation of retired plants and mines. The six months ended June 30, 2021 includes a gain on the settlement of rail transportation disputes (see Note 17 to the Financial Statements).

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

The table below summarizes the changes in commodity contract assets and liabilities for the six months ended June 30, ~~2020~~2021 and ~~2019.~~2020. The net change in these assets and liabilities, excluding "other activity" as described below, reflects ~~$123~~$182 million in unrealized net losses and ~~$703~~$123 million in unrealized net gains for the six months ended June 30, ~~2020~~2021 and ~~2019,~~2020, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.


		Six Months Ended June 30,							Six Months Ended June 30,
		2020		2019			2021		2020
Commodity contract net liability at beginning of period	Commodity contract net liability at beginning of period	$	(279)	$	(850)	Commodity contract net liability at beginning of period	$	(75)	$	(279)
Settlements/termination of positions (a)	Settlements/termination of positions (a)	(82)		(76)		Settlements/termination of positions (a)	(199)		(82)
Changes in fair value of positions in the portfolio (b)	Changes in fair value of positions in the portfolio (b)	205		779		Changes in fair value of positions in the portfolio (b)	17		205

Other activity (c)	Other activity (c)	7		(73)		Other activity (c)	(52)		7
Commodity contract net liability at end of period	Commodity contract net liability at end of period	$	(149)	$	(220)	Commodity contract net liability at end of period	$	(309)	$	(149)

____________

(a)Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). The six months ended June 30, ~~2020~~2021 and ~~2019~~2020 include reversals of $1 million of previously recorded unrealized losses and $7 million of previously recorded unrealized gains related to Vistra beginning balances, respectively. The six months ended June 30, 2020 and 2019 also include reversals of $21$4 million and ~~$13~~$21 million, respectively, of previously recorded unrealized losses related to commodity contracts acquired in the Merger, Crius ~~Transaction~~acquisition and Ambit ~~Transaction.~~acquisition. The six months ended June 30, 2020 includes reversal of less than $1 million of previously recorded losses related to Vistra Corp 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.

Table of Contents

Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair values at June 30, ~~2020,~~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 June 30, 2020																			Maturity dates of unrealized commodity contract net liability at June 30, 2021
		Less than 1 year		1-3 years		4-5 years		Excess of 5 years		Total			Less than 1 year		1-3 years		4-5 years		Excess of 5 years		Total
Prices actively quoted	Prices actively quoted	$	108	$	(43)	$	(2)	$	—	$	63	Prices actively quoted	$	(210)	$	(69)	$	—	$	—	$	(279)
Prices provided by other external sources	Prices provided by other external sources	(247)		(78)		1		(2)		(326)		Prices provided by other external sources	(57)		(21)		2		—		(76)
Prices based on models	Prices based on models	39		39		21		15		114		Prices based on models	31		49		(15)		(19)		46
Total	Total	$	(100)	$	(82)	$	20	$	13	$	(149)	Total	$	(236)	$	(41)	$	(13)	$	(19)	$	(309)

Table of Contents

FINANCIAL CONDITION

Operating Cash Flows

~~Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019~~ — Cash ~~provided by~~used in operating activities totaled ~~$1.309~~$1.057 billion ~~and $882 million~~ for the six months ended June 30, ~~2020 and 2019, respectively.~~2021 compared to cash provided by operating activities of $1.309 billion for the six months ended June 30, 2020. The ~~favorable~~unfavorable change of ~~$427 million~~$2.366 billion was primarily driven by ~~increased~~lower cash from operations due to Winter Storm Uri impacts and ~~a decrease in~~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 ~~$147~~$82 million and ~~$96~~$147 million for the six months ended June 30, ~~2020~~2021 and ~~2019,~~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 ~~$653~~$575 million and ~~$399~~$653 million for the six months ended June 30, ~~2020~~2021 and ~~2019,~~2020, respectively. Capital expenditures totaled ~~$588~~$546 million and ~~$303~~$588 million for the six months ended June 30, 2021 and 2020, respectively, and ~~2019, respectively.~~ consisted of the following:


	Six Months Ended June 30,
	2021		2020
Capital expenditures, including LTSA prepayments	$	273	$	297
Nuclear fuel purchases	$	15	$	36
Growth and development expenditures	$	258	$	255
Capital expenditures	$	546	$	588

Cash used in investing activities ~~for the six months ended June 30, 2020 and 2019~~ also reflected net purchases of environmental allowances of $109 million and $85 million ~~and $107 million, respectively. For~~for the six months ended June 30, 2021 and 2020, respectively. In the six months ended June 30, 2021and 2020, we also received insurance proceeds of $63 million and ~~2019, capital expenditures consisted of:~~

Six Months Ended June 30,
2020 2019
Capital expenditures, including LTSA prepayments $ 297 $ 247
Nuclear fuel purchases $ 36 $ 20
Growth and development expenditures $ 255 $ 36
Capital expenditures $ 588 $ 303
$15 million, respectively.

Financing Cash Flows

Cash ~~used in~~provided by financing activities totaled $1.671 billion in the six months ended June 30, 2021 compared to cash used of $698 ~~million and $170~~ million for the six months ended June 30, ~~2020 and 2019, respectively.~~2020. The change was primarily driven by:

•the issuance of ~~$4.6~~$1.250 billion principal amount of Vistra Operations senior ~~secured and~~ unsecured notes in ~~2019;~~May 2021;

•redemption of $581 million principal amount of outstanding of Vistra unsecured senior notes in 2020;

•$500 million ~~principal amount~~in cash received from the sale of ~~outstanding~~a portion of ~~5.875% senior notes redeemed~~the PJM capacity that cleared for Planning Years 2021-2022 in ~~June 2020;~~March 2021;

•~~$100~~net borrowings of $361 million under the accounts receivable financing facilities in 2021;

•repayment of $100 million of term loans under the Vistra Operations Credit Facility ~~repaid~~ in March ~~2020, and~~

•~~$81 million principal amount of outstanding of 8.000% senior notes redeemed in January 2020,~~2020;

partially offset by:

•~~cash tender offers to purchase approximately $2.0 billion~~net borrowings of ~~senior unsecured notes assumed in the Merger in 2019;~~

•~~repayment of approximately $2.0 billion of term loans~~$200 million under the ~~Vistra Operations~~Revolving Credit ~~Facilities~~Facility in ~~2019;~~2020; and

•$~~457~~175 million in cash paid for share repurchases in ~~2019;~~

•~~$200 million increase in net short-term borrowings under the Revolving Credit Facility in 2020, and~~

•~~$136 million decrease in debt tender offer and other financing fees in 2020 compared to 2019.~~2021.

Debt Activity

See Note 119 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.

Table of Contents

Available Liquidity

The following table summarizes changes in available liquidity for the six months ended June 30, ~~2020:~~2021:


		June 30, 2020		December 31, 2019		Change			June 30, 2021		December 31, 2020		Change
Cash and cash equivalents	Cash and cash equivalents	$	382	$	300	$	82	Cash and cash equivalents	$	444	$	406	$	38
Vistra Operations Credit Facilities — Revolving Credit Facility	Vistra Operations Credit Facilities — Revolving Credit Facility	1,287		1,426		(139)		Vistra Operations Credit Facilities — Revolving Credit Facility	1,893		1,988		(95)

Vistra Operations — Alternate Letter of Credit Facility								Vistra Operations — Alternate Letter of Credit Facility	—		5		(5)
Total available liquidity(a)	Total available liquidity(a)	$	1,669	$	1,726	$	(57)	Total available liquidity(a)	$	2,337	$	2,399	$	(62)

____________

(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 ~~$57~~$62 million decrease in available liquidity for the six months ended June 30, ~~2020~~2021 was primarily driven by ~~$588~~cash used in operations, $546 million of capital expenditures (including LTSA prepayments, nuclear fuel and development and growth expenditures), ~~$500~~$175 million ~~principal amount of outstanding 5.875% senior notes redeemed~~ in June 2020, $100 million of term loans under the Vistra Operations Credit Facility repaid in March 2020, $81 million principal amount of outstanding of 8.000% senior notes redeemed in January 2020 and $132cash paid for share repurchases, $147 million in dividends paid to ~~shareholders,~~stockholders and a $95 million increase in letters of credit outstanding under the Revolving Credit Facility, partially offset by cash received from ~~operations.~~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 $361 million in net cash borrowings under the accounts receivable financing facilities.

Based upon our current internal financial forecasts, we believe that we will have sufficient liquidity to fund our anticipated cash requirements ~~including those related to our capital allocation initiatives,~~ 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 1110 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.

At June 30, ~~2020,~~2021, we received or posted cash and letters of credit for commodity hedging and trading activities as follows:

•$~~161~~507 million in cash has been posted with counterparties as compared to ~~$202~~$257 million posted at December 31, ~~2019;~~2020;

•$1543 million in cash has been received from counterparties as compared to $8$33 million received at December 31, ~~2019;~~2020;

•$~~1.117~~1.067 billion in letters of credit have been posted with counterparties as compared to ~~$1.150 billion~~$878 million posted at December 31, ~~2019,~~2020; and

•$1727 million in letters of credit have been received from counterparties as compared to ~~$17~~$18 million received at December 31, ~~2019.~~2020.

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

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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 ~~$55~~$27 million in state income tax payments, offset by ~~$13~~$9 million in state tax refunds, and $1$3 million in TRA payments ~~in the next 12 months. In addition, we expect to receive approximately $129 million in AMT refundable credits~~ in the next 12 months.

For the six months ended June 30, ~~2020, we received a refund of $37 million related to alternative minimum tax credits claimed on Dynegy tax returns. For the six months ended June 30, 2020,~~2021, there were no federal income tax payments, $5$37 million in state income tax payments, $2 million in state income tax refunds and no TRA payments.

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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. ~~As of~~Although the period ended June 30, ~~2020,~~2021 was not a compliance period, we ~~were~~would have been in compliance with this financial ~~covenant.~~covenant if it was required to be tested at such date.

See Note 1110 to the Financial Statements for discussion of other covenants related to the Vistra Operations Credit Facilities.

Collateral Support Obligations

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

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, at June 30, ~~2020,~~2021, Vistra has posted letters of credit in the amount of ~~$59~~$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 ~~$383~~$329 million in the form of letters of credit, $10 million in the form of a surety bond and $2$1 million of cash at June 30, ~~2020~~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 ~~was~~were a failure under financing arrangements to meet payment terms or to observe covenants that could result in an acceleration of payments due. Such provisions are referred to as "cross default" or "cross acceleration" provisions.

A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of $300 million may result in a cross default under the Vistra Operations Credit Facilities. Such a default would allow the lenders to accelerate the maturity of outstanding balances ~~(approximately $3.1~~under such facilities, which totaled approximately $2.557 billion at June 30, ~~2020) including $550 million of cash borrowings under the Revolving Credit Facility) under such facilities.~~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.

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Under ~~(i)~~ 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 or (ii) as of June 30, 2020, with respect to the 8.125% Senior Unsecured Indenture, a default under any document evidencing indebtedness for borrowed money by Vistra 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 $100 million or more, may ~~have resulted~~result in a cross default under the Vistra Operations Senior Unsecured Notes, the Senior Secured Notes, ~~the 8.125% senior 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.

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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~~cross-default provision. The ~~cross default~~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 ~~Operations,~~and originators under the ~~performance guarantor,~~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 ~~originator and servicer,~~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 ~~Summary Financial Information~~

AsSubsidiary for failure to pay principal when due at final maturity or that results in the acceleration of ~~June 30, 2020, our 8.125% senior notes were guaranteed by substantially all~~such indebtedness in an aggregate amount of ~~our wholly owned subsidiaries. The following tables summarize the combined financial information of (i) Vistra Corp. (Parent), which is the ultimate parent company and issuer~~$300 million or more, may result in a termination of the senior notes with effect as of the Merger Date, on a stand-alone, unconsolidated basis and (ii) the guarantor subsidiaries of Vistra (Guarantor Subsidiaries). The Guarantor Subsidiaries consist of the wholly owned subsidiaries, which jointly, severally, fully and unconditionally, guarantee the payment obligations under the senior notes. See Note 11 to the Financial Statements for discussion of the senior notes and Note 13 to the Financial Statements for discussion of dividend restrictions of Vistra Operations (a guarantor subsidiary of Vistra) and Parent.

This financial information should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto of Vistra. Transactions between the Parent and the Guarantor Subsidiaries have been eliminated. The inclusion of Vistra's subsidiaries as Guarantor Subsidiaries in the summary financial information is determined as of the most recent balance sheet date presented.

The Parent files a consolidated U.S. federal income tax return. All consolidated income tax expense or benefits and deferred tax assets and liabilities are included in the Guarantor summary financial information presented below.


	~~Six Months Ended June 30, 2020~~
~~Revenues~~	$	~~5,130~~
~~Operating income~~	$	~~829~~
~~Net income~~	$	~~274~~
~~Net income attributable to Vistra~~	$	~~274~~

June 30, 2020 June 30, 2020
Current assets $ 3,303 Current liabilities $ 3,741
Noncurrent assets 21,798 Noncurrent liabilities 13,432
Total assets $ 25,101 Total liabilities $ 17,173
Noncontrolling interest $ (12)
Secured LOC Facilities.

Guarantees

See Note 1211 to the Financial Statements for discussion of guarantees.

~~OFF–BALANCE SHEET ARRANGEMENTS~~

~~As of June 30, 2020, we have no off-balance sheet arrangements which are expected to have any material impact on our financial condition, results of operations or liquidity.~~

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COMMITMENTS AND CONTINGENCIES

See Note 1211 to the Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

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

Item 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the risk that in the normal course of business we may experience a loss in value ~~due to~~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.

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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 ~~framework established and overseen by the Company's board of directors (Board) and the sustainability and risk committee of the Board, as applicable.~~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.~~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.


		Six Months Ended June 30, 2020		Year Ended December 31, 2019			Six Months Ended June 30, 2021		Year Ended December 31, 2020
Month-end average VaR	Month-end average VaR	$	281	$	263	Month-end average VaR	$	523	$	234
Month-end high VaR	Month-end high VaR	$	361	$	520	Month-end high VaR	$	684	$	361
Month-end low VaR	Month-end low VaR	$	205	$	103	Month-end low VaR	$	359	$	164

The increase in the month-end high VaR risk ~~measures~~measure in ~~2020 were~~2021 is primarily ~~comparable to the prior year. Month-end high VaR was lower in 2020 due to lower~~driven by a larger net open position, higher forward prices and ~~a decrease~~an increase in volatility ~~in ERCOT as~~ compared to the prior year.

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Interest Rate Risk

At June 30, ~~2020,~~2021, the potential reduction of annual ~~pretax~~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 ~~$13~~$9 million taking into account the interest rate swaps discussed in Note 1110 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 1514 to the Financial Statements for further discussion of this exposure.

~~Bankruptcies~~ — We are party to (i) certain gas transportation agreements with PG&E and (ii) a long-term resource adequacy contract with PG&E in connection with the Moss Landing battery storage project, which was originally approved by the California Public Utilities Commission (CPUC) in November 2018. PG&E filed for Chapter 11 bankruptcy protection in January 2019. In November 2019, the bankruptcy court approved PG&E's motion requesting approval of the assumption of the resource adequacy contract subject to the CPUC approving the terms of an amendment to the resource adequacy contract, and the CPUC approved the terms of the amendment in January 2020. PG&E emerged from bankruptcy protection in July 2020.

As of June 30, 2020, we had no outstanding accounts receivable from PG&E and accordingly, we have not recorded a reserve related to the pre-petition receivables. While our assumptions and conclusions may change, we could have future impairment losses or be required to seek alternative, higher-cost fuel transportation methods if any of the terms of the gas transportation agreements are not honored by PG&E or the gas transportation agreements are rejected through the bankruptcy process.

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 ~~$1.394~~$1.405 billion at June 30, ~~2020.~~2021.

At June 30, ~~2020,~~2021, Retail segment credit exposure totaled ~~$1.020 billion, including $1.009~~$1.047 billion of trade accounts ~~receivable and $11 million related to derivative assets.~~receivable. Cash deposits and letters of credit held as collateral for these receivables totaled ~~$78~~$69 million, resulting in a net exposure of ~~$942~~$978 million. 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 June 30, ~~2020,~~2021, aggregate ~~ERCOT, PJM, NY/NE~~Texas, East and ~~MISO~~Sunset segments credit exposure totaled ~~$374~~$358 million including ~~$316~~$265 million related to derivative assets and ~~$58~~$93 million of trade accounts receivable, after taking into account master netting agreement provisions but excluding collateral impacts.

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Including collateral posted to us by counterparties, our net ~~ERCOT, PJM, NY/NE~~Texas, East and ~~MISO~~Sunset segments exposure was ~~$365~~$318 million, substantially all of which is with investment grade customers as seen in the following table that presents the distribution of credit exposure at June 30, ~~2020.~~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			Exposure Before Credit Collateral		Credit Collateral		Net Exposure
Investment grade	Investment grade	$	348	$	7	$	341	Investment grade	$	289	$	31	$	258
Below investment grade or no rating	Below investment grade or no rating	26		2		24		Below investment grade or no rating	69		9		60
Totals	Totals	$	374	$	9	$	365	Totals	$	358	$	40	$	318

Significant (i.e., 10% or greater) concentration of credit exposure exists with ~~three~~two counterparties, which represented an aggregate ~~$218~~$114 million, or ~~60%~~36%, of the total net exposure. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the counterparties' credit ratings, each of which is rated as investment grade, the counterparties' market role and deemed creditworthiness and the importance of our business relationship with the counterparties. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts such as margin deposits are owed to the counterparties or delays in receipts of expected settlements owed to us.

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

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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 ~~have a negative~~negatively impact our financial ~~effect;~~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 ~~COVID-19)~~Winter Storm Uri), ~~weather conditions (including~~ drought and limitations on access to ~~water),~~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 ~~operational impacts related thereto;~~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;~~

•~~our ability to profitably serve our~~ 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;

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•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 ~~strategy,~~initiatives, including the completion and integration of mergers, acquisitions and/or joint venture activity, ~~and~~the identification and completion of sales and divestitures ~~activity;~~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.

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

INDUSTRY AND MARKET INFORMATION

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

Item 4.CONTROLS AND PROCEDURES

An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15a-15(e) of the Exchange Act) in effect at June 30, 2020. On the Ambit Acquisition Date, we completed the Ambit Transaction. Vistra is currently in the process of integrating certain processes, technology and operations of Ambit, and will continue to evaluate the impact of any related changes to the internal control over financial reporting.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, ~~other than the changes resulting from the Ambit Transaction,~~ 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. Furthermore, with respect to the fiscal quarter covered by this quarterly report on Form 10-Q, we have not experienced any material impact to our internal controls over financial reporting due to the COVID-19 pandemic. We are continually monitoring and assessing the design and operating effectiveness of our internal controls in light of the COVID-19 situation and the fact that the majority of our employees that do not work in our power generation facilities are working remotely.

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PART II. OTHER INFORMATION

Item 1.LEGAL PROCEEDINGS

Reference is made to the discussion in Note 1211 to the Financial Statements regarding legal proceedings.

Item 1A.RISK FACTORS

There have been no material changes to ~~our~~the risk factors ~~disclosed~~discussed in Part I, Item 1A Risk Factors in our ~~2019~~2020 Form ~~10-K, except as set forth below.~~

~~The outbreak of COVID-19, or the future outbreak of any other highly infectious or contagious diseases,~~10-K. We could ~~have a material and adverse effect on our business, financial condition, and results of operations.~~

~~The outbreak of the COVID-19 pandemic has adversely impacted economic activity and conditions worldwide, and we~~also be affected by additional factors that are ~~responding to the outbreak by taking steps to mitigate the potential risks~~not presently known to us ~~posed by its spread.We continue~~or that we currently consider to ~~examine the impacts of the pandemic on~~be immaterial to our workforce, liquidity, reliability, cybersecurity, customers, suppliers, along with other macroeconomic conditions and cannot currently predict whether COVID-19 will have a material impact on our results of operations, financial condition, and cash flows.operations.

Because we are deemed a critical infrastructure provider that provides a critical service to our customers, we must keep our employees who operate our businesses safe and minimize unnecessary risk of exposure.~~We have updated and implemented our company-wide pandemic plan to address specific aspects of the COVID-19 pandemic.This plan guides 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 will take additional precautions that we determine are necessary in order to mitigate the impacts.~~In particular, we have taken extra precautions for our employees who work in the field and for employees who continue to work in our facilities including requiring, for both employees and contractors, social distancing where possible and requiring the use of appropriate personal protective equipment in certain circumstances.We have implemented work-from-home policies and other safety measures where appropriate, including, but not limited to, temperature testing at all of our locations for employees, contractors, and other essential visitors and closing our facilities to non-essential visitors.While our systems and operations remain vulnerable to cyber-attacks and other disruptions due in part to the fact that a portion of our workforce continues to work remotely, we have implemented physical and cyber-security measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers.~~We will continue to review and modify our plans as conditions change.~~

Measures to control the spread of COVID-19, including restrictions on travel, public gatherings, and certain business operations, have affected the demand for the products and services of many businesses in the areas in which we operate and disrupted supply chains around the world.~~The full scope and extent of the impacts of COVID-19 on our operations are unknown at this time.~~However, COVID-19 or another pandemic could have material and adverse effects on our results of operations, financial condition and cash flows due to, among other factors, a protracted slowdown of broad sectors of the economy, changes in demand or supply for commodities, significant changes in legislation or regulatory policy to address the pandemic (including moratoriums or conditions or disconnections and limits or restrictions or late fees), reduced demand for electricity (particularly from commercial and industrial customers), increased late or uncollectible customer payments, and the inability of the Company's contractors, suppliers, and other business partners to fulfill their contractual obligations.

Despite our efforts to manage these impacts to the Company, their ultimate impact also depends on factors beyond our knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects.To the extent COVID-19 adversely affects our business and financial results, it may also have the effect of hastening, heightening, or increasing the negative impacts of, many of the other risks described in this ~~Risk Factors~~ ~~section and in our 2019 Form 10-K.~~

~~Table of Contents~~

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

The following table provides information about our repurchase of equity securities that are registered by us pursuant to Section 12 of the Exchange Act, as amended, during the quarter ended June 30, ~~2020.~~2021.

Total Number of Shares Purchased

Average Price Paid per Share

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

Maximum Dollar Amount of Shares that may yet be Purchased under the Program (in millions)

April 1 - April 30, ~~2020~~2021

—

~~332~~1,325

May 1 - May 31, ~~2020~~2021

—

~~332~~1,325

June 1 - June 30, ~~2020~~2021

—

~~332~~1,325

For the quarter ended June 30, ~~2020~~2021

—

~~332~~1,325

In ~~June 2018,~~September 2020, we announced that the Board had authorized a new share repurchase program (Share Repurchase Program) under which up to ~~$500 million~~$1.5 billion of our outstanding common stock may be purchased, and in November 2018, we announced that the Board had authorized an incremental share repurchase program under which up to $1.250 billion of our outstanding stock may be purchased, resulting in an aggregate $1.750 billion share repurchase program (Share Repurchase Program).repurchased. The Share Repurchase Program ~~has no set expiration date and will continue until complete or terminated~~replaced the share repurchase program previously authorized by the ~~Board. At June 30, 2020, $332 million was available~~Board and became effective on January 1, 2021. The Company continues to evaluate opportunities to reallocate capital for ~~additional~~ repurchases ~~under~~in the remainder of 2021.

Under the Share Repurchase ~~Program. See Note 13 to the Financial Statements for more information concerning the Share Repurchase Program.~~

~~Any~~Program, any purchases of shares of the Company's stock ~~will~~may be repurchased from time to time in open market transactions at prevailing market prices, in privately negotiated transactions, pursuant to plans complying with the Exchange Act or by other means in accordance with federal securities laws. The actual timing, number and value of shares repurchased under the Share Repurchase Program or otherwise will be determined at our discretion and will depend on a number of factors, including our capital allocation priorities, the market price of our stock, general market and economic conditions, applicable legal requirements and compliance with the terms of our debt ~~agreements and~~agreements.

See Note 12 to the ~~Tax Matters Agreement.~~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.

Table of Contents

Item 5.OTHER INFORMATION

~~None~~On August 3, 2021, certain subsidiaries of the Company, namely TXU Energy, as seller (Seller) and seller party agent, Vistra Operations, as guarantor, the originators named therein (collectively with Seller, the Originators), and MUFG Bank, Ltd., as buyer (Buyer), entered into (i) an amendment (the Framework Amendment) to the Master Framework Agreement, dated as of October 9, 2020 (as amended, supplemented or otherwise modified from time to time, the MFA), among Seller, the Originators, and Buyer and (ii) an amendment (the Repurchase Amendment) to the Master Repurchase Agreement, dated as of October 9, 2020 (as amended, supplemented or otherwise modified from time to time, the MRA), between Seller and Buyer. The Framework Amendment amends certain provisions of the MFA, including (i) decreasing the facility size from $150 million to $125 million and (ii) extending the term of the MFA until July 11, 2022. The Repurchase Amendment amends certain provisions of the MRA relating to the applicable benchmark replacement rate which will apply upon the occurrence of an early opt-in election or a benchmark transition event.

The above descriptions of the Framework Amendment and Repurchase Amendment, respectively, do not purport to be complete and are qualified in its entirety by reference to the full text of the Framework Amendment and Repurchase Amendment, respectively, each of which will be filed with the Company's Quarterly Report on Form 10-Q for the quarter ending September 30, 2021.

~~Table of Contents~~

Item 6. EXHIBITS

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


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

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

3.1	3.1	001-38086 Form 8-K (filed May 4, 2020)	3.1	—	Restated Certificate of Incorporation of Vistra Energy Corp.	3.1	0001-38086 Form 8-K (filed May 4, 2020)	3.1	—		Restated Certificate of Incorporation of Vistra Energy Corp. (now known as Vistra Corp.)

3.2	3.2	001-38086 Form 8-K (filed June 29, 2020)	3.1	—	Certificate of Amendment to Restated Certificate of Incorporation of Vistra Corp., effective July 2, 2020	3.2	0001-38086 Form 8-K (filed June 29, 2020)	3.1	—		Certificate of Amendment of the Restated Certificate of Incorporation of Vistra Energy Corp. (now known as Vistra Corp.), effective July 2, 2020

(3(ii))	(3(ii))	Bylaws				(3(ii))	By-laws

3.2		001-38086 Form 8-K (filed June 29, 2020)	3.2	—	Restated Bylaws of Vistra Corp., effective July 2, 2020
3.3						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)	(4)	Instruments Defining the Rights of Security Holders, Including Indentures								(4)	Instruments Defining the Rights of Security Holders, Including Indentures

4.1	4.1	001-38086 Form 8-K (filed July 16, 2020)	4.1	—	Fifth Amendment to Receivables Purchase Agreement, dated as of July 13, 2020, 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	4.1	0001-38086 Form 8-K (filed May 11, 2021)	4.1	—		Indenture for 4.375% Senior Notes due 2029, dated as of May 10, 2021, between Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors, and Wilmington Trust, National Association, as Trustee

4.2						4.2	0001-38086 Form 8-K (filed May 11, 2021)	4.2	—		Form of Rule 144A Global Security for 4.375% Senior Note due 2029 (included in Exhibit 4.1)

4.3						4.3	0001-38086 Form 8-K (filed May 11, 2021)	4.3	—		Form of Regulation S Global Security for 4.375% Senior Note due 2029 (included in Exhibit 4.1)

4.4						4.4	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

(10)						(10)	Material Contracts

(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 David A. Campbell, 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 David A. Campbell, 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

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~~Exhibits~~

Previously Filed With File Number*

~~Exhibit~~

~~XBRL Data Files~~

~~101.INS~~

—

The following financial information from Vistra Corp.'s Quarterly Report on Form 10-Q for the period ended June 30, 2020 formatted in Inline XBRL (Extensible Business Reporting Language) includes: (i) the Condensed Consolidated Statements of Operations, (ii) the Condensed Consolidated Statements of Comprehensive Income, (iii) the Condensed Consolidated Statements of Cash Flows, (iv) the Condensed Consolidated Balance Sheets and (v) the Notes to the Condensed Consolidated Financial Statements

~~101.SCH~~

—

~~XBRL Taxonomy Extension Schema Document~~

~~101.CAL~~

—

~~XBRL Taxonomy Extension Calculation Linkbase Document~~

~~101.DEF~~

—

~~XBRL Taxonomy Extension Definition Linkbase Document~~

~~101.LAB~~

—

~~XBRL Taxonomy Extension Label Linkbase Document~~

~~101.PRE~~

—

~~XBRL Taxonomy Extension Presentation Linkbase Document~~

~~104~~

—

~~The Cover Page Interactive Data File does not appear in Exhibit 104 because its XBRL tags are embedded within the Inline XBRL document~~

Exhibits

Previously Filed With File Number*

Exhibit

10.1

0001-38086
Form 8-K
(filed May 11, 2021)

10.1

—

Purchase Agreement, dated as of May 5, 2021, by and among Vistra Operations Company LLC and J.P. Morgan Securities LLC, on behalf of itself and the several Initial Purchasers named in Schedule I to the Purchase Agreement

10.2

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

(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 June 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

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

**** Indicates a management contract or compensatory plan or arrangement.

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SIGNATURE

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

Vistra Corp.

By:

/s/ CHRISTY DOBRY

Name:

Christy Dobry

Title:

Senior Vice President and Controller

(Principal Accounting Officer)

Date: August 5, ~~2020~~2021

8078


Ambit Transaction Preliminary Purchase Price Allocation and Crius Transaction Final Purchase Price Allocation
	Ambit Transaction						Crius Transaction
	Updated Preliminary Purchase Price Allocation		Measurement Period Adjustments recorded through June 30, 2020		Final Purchase Price Allocation		Measurement Period Adjustments recorded through June 30, 2020
Cash and cash equivalents	$	49	$	—	$	26	$	—
Net working capital	35		6		(9)		(42)
Accumulated deferred income taxes	—		—		—		(36)
Identifiable intangible assets	230		(33)		317		23
Goodwill	243		29		243		38
Commodity and other derivative contractual assets	23		—		18		—
Other noncurrent assets	13		—		17		(3)
Total assets acquired	593		2		612		(20)
Identifiable intangible liabilities	—		—		2		(34)
Long-term debt, including amounts due currently	—		—		140		—
Commodity and other derivative contractual liabilities	28		—		40		—
Accumulated deferred income taxes	—		—		14		14
Other noncurrent liabilities and deferred credits	10		2		16		—
Total liabilities assumed	38		2		212		(20)
Identifiable net assets acquired	$	555	$	—	$	400	$	—


	Six Months Ended June 30, 2019
	Retail		ERCOT		PJM		NY/NE		MISO		Asset Closure		CAISO/Eliminations		Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	2,116	$	—	$	—	$	—	$	—	$	—	$	—	$	2,116
Retail energy charge in Northeast/Midwest	663		—		—		—		—		—		—		663
Wholesale generation revenue from ISO/RTO	—		435		351		276		104		110		95		1,371
Capacity revenue from ISO/RTO	—		—		120		152		18		6		—		296
Revenue from other wholesale contracts	—		97		159		12		55		2		6		331
Total revenue from contracts with customers	2,779		532		630		440		177		118		101		4,777
Other revenues:
Intangible amortization	(19)		—		—		(3)		(9)		—		2		(29)
Hedging and other revenues (a)	46		562		171		113		29		25		61		1,007
Affiliate sales	—		1,531		590		49		160		—		(2,330)		—
Total other revenues	27		2,093		761		159		180		25		(2,267)		978
Total revenues	$	2,806	$	2,625	$	1,391	$	599	$	357	$	143	$	(2,166)	$	5,755


Senior Secured Notes	Maturity Year	Interest Terms (Due Semiannually in Arrears)	June 2019 Senior Secured Notes Offerings (a)
3.550% Senior Secured Notes	2024	January 15 and July 15	$	1,200

4.300% Senior Secured Notes	2029	January 15 and July 15	800
Total senior secured notes			$	2,000
Net proceeds			$	1,976
Debt issuance and other fees (b)			$	20


Senior Unsecured Notes	Maturity Year	Interest Terms (Due Semiannually in Arrears)	February 2019 Senior Unsecured Notes Offering (a)		June 2019 Senior Unsecured Notes Offering (b)

5.625% Senior Unsecured Notes	2027	February 15 and August 15	1,300		—
5.000% Senior Unsecured Notes	2027	January 31 and July 31	—		1,300
Total			$	1,300	$	1,300
Net Proceeds			$	1,287	$	1,287
Debt issuance and other fees (c)			$	16	$	13


	Pension Benefits														OPEB Benefits
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019		2020		2019		2020		2019
Service cost	$	2	$	2	$	4	$	4	$	—	$	—	$	—	$	—
Other costs	—		—		1		—		2		2		4		4
Net periodic benefit cost	$	2	$	2	$	5	$	4	$	2	$	2	$	4	$	4


	Balance 2020 (a)		2021
ERCOT:
Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price	$	1	$	22
Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price	$	—	$	(18)
Gas Generation: $1.00/MWh increase in spark spread	$	1	$	20
Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	(17)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	3	$	(27)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	(3)	$	15
PJM:
Coal Generation: $2.50/MWh increase in power price	$	2	$	3
Coal Generation: $2.50/MWh decrease in power price	$	—	$	—
Gas Generation: $1.00/MWh increase in spark spread	$	1	$	16
Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	(14)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	—	$	(1)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	—	$	1
NYISO/ISO-NE:
Gas Generation: $1.00/MWh increase in spark spread	$	1	$	3
Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	(1)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	1	$	—
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	(1)	$	—


	Balance 2020 (a)		2021
MISO/CAISO:
Coal Generation: $2.50/MWh increase in power price	$	2	$	10
Coal Generation: $2.50/MWh decrease in power price	$	—	$	(6)
Gas Generation: $1.00/MWh increase in spark spread	$	—	$	1
Gas Generation: $1.00/MWh decrease in spark spread	$	—	$	(1)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	—	$	2
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	—	$	(2)


	Three Months Ended June 30, 2020 Compared to 2019		Six Months Ended June 30, 2020 Compared to 2019

Higher margin primarily driven by the addition of Crius acquired in July 2019 and Ambit acquired in November 2019	151		$	252

Other driven by higher SG&A expense and bad debt expense primarily due to the addition of Crius and Ambit	(43)		(90)
Change in Adjusted EBITDA	$	108	$	162
Change in depreciation and amortization expenses driven by Crius/Ambit intangibles	(14)		(35)
Favorable impact of lower unrealized net losses on hedging activities	716		759
Lower transition and merger and other expenses	13		17
Change in net income (loss)	$	823	$	903