Vistra Corp. - Quarter Report: 2019 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2019

— OR —



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

Commission File Number 001-38086

Vistra Energy 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 ☐

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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☒ Accelerated filer ☐ Non-Accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark if the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

As of October 31, 2019, there were 487,394,276 shares of common stock, par value $0.01, outstanding of Vistra Energy Corp.

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TABLE OF CONTENTS



		PAGE
GLOSSARY		ii
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Statements of Consolidated Income — Three and Nine Months Ended September 30, 2019 and 2018	1
	Condensed Statements of Consolidated Comprehensive Income — Three and Nine Months Ended September 30, 2019 and 2018	1
	Condensed Statements of Consolidated Cash Flows — Nine Months Ended September 30, 2019 and 2018	2
	Condensed Consolidated Balance Sheets — September 30, 2019 and December 31, 2018	3
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	66
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	88
Item 4.	Controls and Procedures	93
PART II.	OTHER INFORMATION	94
Item 1.	Legal Proceedings	94
Item 1A.	Risk Factors	94
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	94
Item 3.	Defaults Upon Senior Securities	94
Item 4.	Mine Safety Disclosures	95
Item 5.	Other Information	95
Item 6.	Exhibits	96
SIGNATURE		98

Vistra Energy Corp.'s (Vistra Energy) annual reports, quarterly reports, current reports and any amendments to those reports are made available to the public, free of charge, on the Vistra Energy website at http://www.vistraenergy.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 Energy 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 Energy's website. The information on Vistra Energy'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 Energy and its subsidiaries occasionally make references to Vistra Energy (or "we," "our," "us" or "the Company"), Luminant, TXU Energy, Value Based Brands LLC, Dynegy Energy Services, Homefield Energy, TriEagle Energy, U.S. Gas & Electric or Public Power, 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, their respective parent company's financial statements for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or vice versa.

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GLOSSARY

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



Ambit		Ambit Holdings, LLC, and/or its subsidiaries, depending on context
ARO		asset retirement and mining reclamation obligation
CAA		Clean Air Act
CAISO		The California Independent System Operator
CCGT		combined cycle gas turbine
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 (d/b/a Dynegy and Brighten Energy), indirect, wholly owned subsidiaries of Vistra Energy, 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 Energy, 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
GWh		gigawatt-hours
Homefield Energy		Illinois Power Marketing Company (d/b/a Homefield Energy), an indirect, wholly owned subsidiary of Vistra Energy, a REP in certain areas of MISO that is engaged in the retail sale of electricity to municipal customers
ICE		IntercontinentalExchange
IRS		U.S. Internal Revenue Service
ISO		Independent System Operator
ISO-NE		Independent System Operator New England
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 Energy engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management
market heat rate		Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier (generally natural gas plants), by the market price of natural gas.
Merger		the merger of Dynegy with and into Vistra Energy, with Vistra Energy as the surviving corporation
Merger Agreement		the Agreement and Plan of Merger, dated as of October 29, 2017, by and between Vistra Energy and Dynegy, as it may be amended or modified from time to time
Merger Date		April 9, 2018, the date Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement
MISO		Midcontinent Independent System Operator, Inc.

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MMBtu		million British thermal units
Moody's		Moody's Investors Service, Inc. (a credit rating agency)
MW		megawatts
MWh		megawatt-hours
NO_X		nitrogen oxide
NRC		U.S. Nuclear Regulatory Commission
NYMEX		the New York Mercantile Exchange, a commodity derivatives exchange
NYISO		New York Independent System Operator
OPEB		postretirement employee benefits other than pensions
Parent		Vistra Energy 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 Spin-Off, 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, an indirect, wholly owned subsidiary of Vistra Energy, a REP in certain areas of PJM, 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
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
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 Receivable Agreement, containing certain rights (TRA Rights) to receive payments from Vistra Energy related to certain tax benefits, including those it realized as a result of certain transactions entered into at Emergence (see Note 8 to the Financial Statements)
TriEagle Energy		TriEagle Energy, LP, an indirect, wholly owned subsidiary of Vistra Energy, 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, an indirect, wholly owned subsidiary of Vistra Energy 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., an indirect, wholly owned subsidiary of Vistra Energy, a REP in certain areas of PJM, NYISO, ISO-NE and MISO that is engaged in the retail sale of electricity to residential and business customers

iii

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Value Based Brands		Value Based Brands LLC (d/b/a 4Change Energy and Express Energy), an indirect, wholly owned subsidiary of Vistra Energy that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers
Vistra Energy		Vistra Energy Corp. and/or its subsidiaries, depending on context
Vistra Intermediate		Vistra Intermediate Company LLC, a direct, wholly owned subsidiary of Vistra Energy
Vistra Operations		Vistra Operations Company LLC, an indirect, wholly owned subsidiary of Vistra Energy that is the issuer of certain series of notes (see Note 11 to the Financial Statements) and borrower under the Vistra Operations Credit Facilities
Vistra Operations Credit Facilities		Vistra Operations Company LLC's $6.523 billion senior secured financing facilities (see Note 11 to the Financial Statements).

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PART I. FINANCIAL INFORMATION


Item 1.	FINANCIAL STATEMENTS

VISTRA ENERGY CORP.

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Operating revenues (Note 5)	$	3,194		$	3,243		$	8,949		$	6,581
Fuel, purchased power costs and delivery fees	(1,687		)	(1,627		)	(4,287		)	(3,492		)
Operating costs	(397		)	(346		)	(1,153		)	(926		)
Depreciation and amortization	(424		)	(426		)	(1,213		)	(967		)
Selling, general and administrative expenses	(246		)	(194		)	(637		)	(711		)
Operating income	440			650			1,659			485
Other income (Note 19)	6			6			45			25
Other deductions (Note 19)	(4		)	(1		)	(9		)	(4		)
Interest expense and related charges (Note 19)	(224		)	(154		)	(720		)	(291		)
Impacts of Tax Receivable Agreement (Note 8)	(62		)	17			(26		)	(65		)
Equity in earnings of unconsolidated investment	3			7			13			11
Income before income taxes	159			525			962			161
Income tax expense (Note 7)	(45		)	(194		)	(270		)	(31		)
Net income	$	114		$	331		$	692		$	130
Net (income) loss attributable to noncontrolling interest	(1		)	(1		)	2			2
Net income attributable to Vistra Energy	$	113		$	330		$	694		$	132
Weighted average shares of common stock outstanding:
Basic	490,562,179			533,142,189			486,215,356			500,781,573
Diluted	493,670,295			540,972,802			490,226,743			508,128,988
Net income per weighted average share of common stock outstanding:
Basic	$	0.23		$	0.62		$	1.43		$	0.26
Diluted	$	0.23		$	0.61		$	1.42		$	0.26

See Notes to the Condensed Consolidated Financial Statements.

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(Unaudited) (Millions of Dollars)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Net income	$	114		$	331		$	692		$	130
Other comprehensive income, net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax benefit of $4, $—, $4 and $—)	(13		)	1			(12		)	2
Total other comprehensive income (loss)	(13		)	1			(12		)	2
Comprehensive income	$	101		$	332		$	680		$	132
Comprehensive (income) loss attributable to noncontrolling interest	(1		)	(1		)	2			2
Comprehensive income attributable to Vistra Energy	$	100		$	331		$	682		$	134

See Notes to the Condensed Consolidated Financial Statements.

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VISTRA ENERGY CORP. CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited) (Millions of Dollars)

	Nine Months Ended September 30,
	2019			2018

Cash flows — operating activities:
Net income	$	692		$	130
Adjustments to reconcile net income to cash provided by (used in) operating activities:
Depreciation and amortization	1,394			1,070
Deferred income tax expense, net	254			29
Unrealized net (gain) loss from mark-to-market valuations of commodities	(625		)	207
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps	275			(123		)
Asset retirement obligation accretion expense	40			37
Impacts of Tax Receivable Agreement (Note 8)	26			65
Stock-based compensation	35			59
Other, net	12			64
Changes in operating assets and liabilities:
Margin deposits, net	129			(39		)
Accrued interest	15			(59		)
Accrued taxes	(31		)	(102		)
Accrued employee incentive	(53		)	(17		)
Other operating assets and liabilities	(340		)	(458		)
Cash provided by operating activities	1,823			863
Cash flows — financing activities:
Issuances of long-term debt (Note 11)	4,600			1,000
Repayments/repurchases of debt (Note 11)	(4,668		)	(2,902		)
Net borrowings under accounts receivable securitization program (Note 10)	261			350
Stock repurchase (Note 14)	(632		)	(414		)
Dividends paid to stockholders (Note 14)	(181		)	—
Debt tender offer and other financing fees (Note 11)	(170		)	(216		)
Other, net	6			10
Cash used in financing activities	(784		)	(2,172		)
Cash flows — investing activities:
Capital expenditures, including LTSA prepayments	(348		)	(209		)
Nuclear fuel purchases	(33		)	(66		)
Development and growth expenditures	(93		)	(28		)
Crius acquisition (net of cash acquired)	(374		)	—
Cash acquired in the Merger	—			445
Proceeds from sales of nuclear decommissioning trust fund securities (Note 19)	354			211
Investments in nuclear decommissioning trust fund securities (Note 19)	(370		)	(227		)
Proceeds from sale of environmental allowances	32			—
Purchases of environmental allowances	(169		)	(4		)
Other, net	22			11
Cash (used in) provided by investing activities	(979		)	133

Net change in cash, cash equivalents and restricted cash	60			(1,176		)
Cash, cash equivalents and restricted cash — beginning balance	693			2,046
Cash, cash equivalents and restricted cash — ending balance	$	753		$	870

See Notes to the Condensed Consolidated Financial Statements.

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VISTRA ENERGY CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars)

	September 30, 2019		December 31, 2018
ASSETS
Current assets:
Cash and cash equivalents	$	707	$	636
Restricted cash (Note 19)	46		57
Trade accounts receivable — net (Note 19)	1,419		1,087
Inventories (Note 19)	430		412
Commodity and other derivative contractual assets (Note 16)	999		730
Margin deposits related to commodity contracts	236		361
Prepaid expense and other current assets	291		152
Total current assets	4,128		3,435
Investments (Note 19)	1,451		1,250
Investment in unconsolidated subsidiary (Note 19)	123		131
Property, plant and equipment — net (Note 19)	14,075		14,612
Operating lease right-of-use assets (Note 12)	50		—
Goodwill (Note 6)	2,287		2,068
Identifiable intangible assets — net (Note 6)	2,595		2,493
Commodity and other derivative contractual assets (Note 16)	181		109
Accumulated deferred income taxes	1,155		1,336
Other noncurrent assets	398		590
Total assets	$	26,443	$	26,024
LIABILITIES AND EQUITY
Current liabilities:
Accounts receivable securitization program (Note 10)	$	600	$	339
Long-term debt due currently (Note 11)	220		191
Trade accounts payable	916		945
Commodity and other derivative contractual liabilities (Note 16)	1,364		1,376
Margin deposits related to commodity contracts	8		4
Accrued income taxes	18		10
Accrued taxes other than income	152		182
Accrued interest	88		77
Asset retirement obligations (Note 19)	167		156
Operating lease liabilities (Note 12)	12		—
Other current liabilities	370		345
Total current liabilities	3,915		3,625
Long-term debt, less amounts due currently (Note 11)	10,728		10,874
Operating lease liabilities (Note 12)	53		—
Commodity and other derivative contractual liabilities (Note 16)	426		270
Accumulated deferred income taxes	10		10
Tax Receivable Agreement obligation (Note 8)	443		420
Asset retirement obligations (Note 19)	2,157		2,217
Identifiable intangible liabilities — net (Note 6)	381		401
Other noncurrent liabilities and deferred credits (Note 19)	538		340
Total liabilities	18,651		18,157

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VISTRA ENERGY CORP. CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Millions of Dollars)

	September 30, 2019			December 31, 2018
Commitments and Contingencies (Note 13)
Total equity (Note 14):
Common stock (par value — $0.01; number of shares authorized — 1,800,000,000) (shares outstanding: September 30, 2019 — 487,783,432; December 31, 2018 — 493,215,309)	5			5
Treasury stock, at cost (shares: September 30, 2019 — 40,151,888; December 31, 2018 — 32,815,783)	(951		)	(778		)
Additional paid-in-capital	9,708			10,107
Retained deficit	(936		)	(1,449		)
Accumulated other comprehensive income (loss)	(34		)	(22		)
Stockholders' equity	7,792			7,863
Noncontrolling interest in subsidiary	—			4
Total equity	7,792			7,867
Total liabilities and equity	$	26,443		$	26,024

See Notes to the Condensed Consolidated Financial Statements.

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VISTRA ENERGY 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 Energy and/or its subsidiaries, as apparent in the context. See Glossary for defined terms.

Vistra Energy is a holding company operating an integrated retail and generation business in markets throughout the U.S. Through our subsidiaries, we are engaged in competitive energy market activities including power generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity and natural gas to end users.

Vistra Energy has six reportable segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv) NY/NE (comprising NYISO and ISO-NE), (v) MISO and (vi) Asset Closure. See Note 18 for further information concerning reportable business segments.

Ambit Transaction

On November 1, 2019, an indirect, wholly owned subsidiary of Vistra Energy completed the acquisition of Ambit (Ambit Transaction). Because the Ambit Transaction closed on November 1, 2019, Vistra Energy's condensed consolidated financial statements and the notes related thereto do not include the financial condition or the operating results of Ambit and its subsidiaries. See Note 2 for a summary of the Ambit Transaction.

Crius Transaction

On July 15, 2019, an indirect, wholly owned subsidiary of Vistra Energy completed the acquisition of the equity interests of two wholly owned subsidiaries of Crius that indirectly own the operating business of Crius (Crius Transaction). Because the Crius Transaction closed on July 15, 2019, Vistra Energy'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.

Dynegy Merger Transaction

On the Merger Date, Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement. Pursuant to the Merger Agreement, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the surviving corporation. Because the Merger closed on April 9, 2018, Vistra Energy's condensed consolidated financial statements and the notes related thereto do not include the financial condition or the operating results of Dynegy prior to April 9, 2018. See Note 2 for a summary of the Merger transaction and business combination accounting.

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 annual report on Form 10-K for the year ended December 31, 2018. Adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. 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 annual report on Form 10-K for the year ended December 31, 2018. 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.

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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, judgment 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.

Leases

At the inception of a contract we determine if it is or contains a lease, which involves the contract conveying the right to control the use of explicitly or implicitly identified property, plant, or equipment for a period of time in exchange for consideration.

Right-of-use (ROU) assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized at the commencement date of the underlying lease based on the present value of lease payments over the lease term. We use our secured incremental borrowing rate based on the information available at the lease commencement date to determine the present value of lease payments. Operating leases are included in operating lease ROU assets, operating lease liabilities (current) and operating lease liabilities (noncurrent) on our condensed consolidated balance sheet. Finance leases are included in property, plant and equipment, other current liabilities and other noncurrent liabilities and deferred credits on our condensed consolidated balance sheet. Lease term includes options to extend or terminate the lease when it is reasonably certain that we will exercise the option. We have elected the practical expedient which permits us to not reassess under the new standard our prior conclusion about lease classification and initial direct costs. We have also elected the practical expedient to not separate lease and non-lease components for a majority of the lease asset classes. We have also elected the hindsight practical expedient to determine the lease term.

Leases with an initial lease term of 12 months or less are not recorded on the balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term.

We also present lessor sublease income on a net basis against the related lessee lease expense.

Adoption of New Accounting Standards

Leases — On January 1, 2019, we adopted Accounting Standards Update (ASU) 2016-02, Leases (Topic 842) and all related amendments (new lease standard) using the modified retrospective method with the cumulative-effect adjustment to the opening balance of retained earnings for all contracts outstanding at the time of adoption. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. We expect the impact of the adoption of the new lease standard to be immaterial to our net income on an ongoing basis. The impact of adopting the new lease standard primarily relates to recognition of lease liabilities and ROU assets for all leases classified as operating leases. Under the new lease standard, each ROU asset will be amortized over the lease term and liability settled at the end of the lease term.

We recognized the effect of initially applying the new lease standard by recording ROU assets of $85 million and lease liabilities of $123 million in our condensed consolidated balance sheet.

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As of January 1, 2019, the cumulative effect of the changes made to our condensed consolidated balance sheet for the adoption of the new lease standard was as follows:



	December 31, 2018			Adoption of New Lease Standard			January 1, 2019
Impact on condensed consolidated balance sheet:
Assets
Property, plant and equipment — net	$	14,612		$	15		$	14,627
Operating lease right-of-use assets	—			70			70
Prepaid expense and other current assets	152			(2		)	150
Accumulated deferred income taxes	1,336			1			1,337
Liabilities
Other current liabilities	345			(1		)	344
Operating lease liabilities	—			109			109
Identifiable intangible liabilities	401			(36		)	365
Other noncurrent liabilities and deferred credits	340			14			354
Equity
Retained deficit	(1,449		)	(2		)	(1,451		)

See Note 12 for the disclosures required by the new lease standard.

Changes in Accounting Standards

In August 2018, the Financial Accounting Standards Board (FASB) issued ASU 2018-13, Changes to the Disclosure Requirements for Fair Value Measurement. The ASU will be effective for fiscal years beginning after December 15, 2019 and early adoption is permitted. 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 will require 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 are currently evaluating the impact of this ASU on our disclosures.

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 will be effective for fiscal years beginning after December 15, 2019 and early adoption is permitted. 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 over the term of the hosting arrangement. The customer is required to apply the existing impairment and abandonment guidance on the capitalized implementation costs. We are currently evaluating the impact of this ASU on our financial statements.

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. The ASU will be effective for fiscal years beginning after December 31, 2019. We do not expect the ASU to have a material impact on our financial statements.

2. ACQUISITONS, 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 Energy, completed the acquisition of Ambit (Ambit Transaction). Ambit is an energy retailer selling both electricity and natural gas products to residential and small business customers in 17 states.

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The Ambit Transaction is expected to (i) augment Vistra Energy's existing retail marketing capabilities with additional direct selling capability and a proprietary technology platform, (ii) reduce risk and aid expansion into higher margin channels by improving Vistra Energy's match of its generation to load profile due to a high degree of overlap with Vistra Energy's generation fleet with Ambit's approximately 11 TWh of annual load, primarily in ERCOT and PJM and (iii) enhance the integrated value proposition through collateral and transaction efficiencies.

The Ambit Transaction will be 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. Due to the limited time between the Acquisition Date and this filing, our purchase price allocation for the assets acquired and the liabilities assumed in the Ambit Acquisition has not been completed. The results of operations of Ambit will be reported in our consolidated financial statements beginning as of the Ambit Acquisition Date. Vistra Energy funded the purchase price of $475 million plus Ambit's outstanding net working capital using cash on hand. All of Ambit's outstanding debt was repaid at closing and not assumed by Vistra Energy. Our initial accounting for the purchase price allocation for the assets acquired and the liabilities assumed in the Ambit Transaction and the supplemental pro forma financial results is currently underway and will be presented no later than the fourth quarter of 2019.

Crius Transaction

On July 15, 2019 (Crius Acquisition Date), Vienna Acquisition B.C. Ltd., an indirect, wholly owned subsidiary of Vistra Energy, 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 Energy funded the purchase price of $400 million (including $382 million for outstanding trust units) using cash on hand.

Crius Business Combination Accounting

We believe the Crius Transaction has (i) reduced risk and aided expansion into higher margin channels by improving Vistra Energy's match of its generation to load profile due to a high degree of overlap with Vistra Energy's generation fleet with Crius' approximately 10 TWh of annual electricity load, (ii) established a platform for growth by leveraging Vistra Energy'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.

The Crius Transaction 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 Crius Acquisition Date. The combined results of operations are reported in our consolidated financial statements beginning as of the 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 15), is listed below:


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


•	Acquired derivatives were valued using the methods described in Note 15 (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).


•	Long-term debt was valued using a market approach (Level 2).

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The following table summarizes the preliminary allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Crius Transaction as of the Crius Acquisition Date. The purchase price was $400 million. The purchase price allocation is ongoing and is dependent upon final valuation determinations, which have not been completed. The preliminary values included below represent our current best estimates for accumulated deferred income taxes, identifiable intangible assets, net working capital and long-term debt. The 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 will be completed no later than the second quarter of 2020.



Crius Transaction Preliminary Purchase Price Allocation
Cash and cash equivalents	$	26
Net working capital	33
Accumulated deferred income taxes	36
Identifiable intangible assets	294
Goodwill	205
Other noncurrent assets and liabilities, net	4
Total assets acquired	598
Identifiable intangible liabilities	36
Long-term debt, including amounts due currently	140
Commodity and other derivative contractual assets and liabilities, net	22
Total liabilities assumed	198
Identifiable net assets acquired	$	400

Acquisition costs incurred in the Crius Transaction totaled $2 million and $4 million in the three and nine months ended September 30, 2019, respectively. For the Crius Acquisition Date through September 30, 2019, our condensed statements of consolidated income include revenues and net loss acquired in the Crius Transaction totaling $239 million and $16 million, respectively. The net loss acquired in the Crius Transaction includes intangible amortization and transition related expenses.

Crius Transaction Unaudited Pro Forma Financial Information — The following unaudited consolidated pro forma financial information for the nine months ended September 30, 2019 assumes that the Crius Transaction occurred on January 1, 2019. The unaudited consolidated pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the Crius Transaction been completed on January 1, 2019, nor is the unaudited consolidated pro forma financial information indicative of future results of operations, which may differ materially from the consolidated pro forma financial information presented here.



	Nine Months Ended September 30, 2019
Revenues	$	9,513
Net income (a)	$	629
Net income attributable to Vistra Energy	$	631
Net income attributable to Vistra Energy per weighted average share of common stock outstanding — basic	$	1.30
Net income attributable to Vistra Energy per weighted average share of common stock outstanding — diluted	$	1.29

__________


(a)	Decrease in pro forma net income compared to consolidated net income is driven by unrealized losses on hedging activities of Crius and increased amortization.

The consolidated unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired and the related impacts on tax expense.

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Dynegy Merger Transaction

On the Merger Date, Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement. Pursuant to the Merger Agreement, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the surviving corporation. The Merger was intended to qualify as a tax-free reorganization under the Internal Revenue Code, as amended, so that none of Vistra Energy, 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 Energy's common stock. Vistra Energy is the acquirer for both federal tax and accounting purposes.

At the closing of the Merger, each issued and outstanding share of Dynegy common stock, par value $0.01 per share, other than shares owned by Vistra Energy 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 Energy (the Exchange Ratio), except that cash was paid in lieu of fractional shares, which resulted in Vistra Energy issuing 94,409,573 shares of Vistra Energy 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 Energy 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 Energy's common stock, after giving effect to the Exchange Ratio.

Dynegy Business Combination Accounting

We believe the Merger has provided and continues to provide significant strategic benefits and opportunities to Vistra Energy, including increased scale and market diversification, rebalanced asset portfolio and improved earnings and cash flow. The Merger was 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 Merger Date. The combined results of operations are reported in our consolidated financial statements beginning as of the Merger 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 15), is listed below:


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


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


•	Acquired derivatives were valued using the methods described in Note 15 (Level 1, Level 2 or Level 3).


•	Contracts with terms that were not at current market prices were also valued using a discounted cash flow analysis (Level 3). The cash flows generated by the contracts were compared with their cash flows based on current market prices with the resulting difference discounted to present value and recorded as either an intangible asset or liability.


•	Long-term debt was valued using a market approach (Level 2).


•	AROs were recorded in accordance with ASC 410, Asset Retirement and Environmental Obligations (Level 3).

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The following table summarizes the consideration paid and the final allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Merger as of the Merger Date. Based on the opening price of Vistra Energy common stock on the Merger Date, the purchase price was approximately $2.3 billion. During the three months ended March 31, 2019, the purchase price allocation was completed. During the period from April 9, 2018 through March 31, 2019, we updated the initial purchase price allocation with final valuations by increasing property, plant and equipment by $173 million, decreasing intangible assets by $36 million, increasing goodwill by $175 million, decreasing accounts receivable, inventory, prepaid expenses and other current assets by $10 million, increasing accumulated deferred tax asset by $127 million, decreasing other noncurrent assets by $113 million, increasing trade accounts payable and other current liabilities by $89 million, increasing other noncurrent liabilities by $177 million, increasing asset retirement obligations, including amounts due currently, by $56 million, as well as other minor adjustments. The valuation revisions were a result of updated inputs used in determining the fair value of the acquired assets and liabilities.



Dynegy shares outstanding as of April 9, 2018 (in millions)	144.8
Exchange Ratio	0.652
Vistra Energy shares issued for Dynegy shares outstanding (in millions)	94.4
Opening price of Vistra Energy common stock on April 9, 2018	$	19.87
Purchase price for common stock	$	1,876
Fair value of equity component of tangible equity units	$	369
Fair value of outstanding stock compensation awards attributable to pre-combination service	$	26
Fair value of outstanding warrants	$	2
Total purchase price	$	2,273



Dynegy Merger Final Purchase Price Allocation
Cash and cash equivalents	$	445
Trade accounts receivables, inventories, prepaid expenses and other current assets	853
Property, plant and equipment	10,535
Accumulated deferred income taxes	518
Identifiable intangible assets	351
Goodwill	175
Other noncurrent assets	419
Total assets acquired	13,296
Trade accounts payable and other current liabilities	733
Commodity and other derivative contractual assets and liabilities, net	422
Asset retirement obligations, including amounts due currently	475
Long-term debt, including amounts due currently	8,919
Other noncurrent liabilities	469
Total liabilities assumed	11,018
Identifiable net assets acquired	2,278
Noncontrolling interest in subsidiary	5
Total purchase price	$	2,273

Acquisition costs incurred in the Merger totaled less than $1 million and $25 million for the nine months ended September 30, 2019 and 2018, respectively.

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Dynegy Merger Unaudited Pro Forma Financial Information — The following unaudited pro forma financial information for the nine months ended September 30, 2018 assumes that the Merger occurred on January 1, 2018. The unaudited pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the Merger been completed on January 1, 2018, nor is the unaudited pro forma financial information indicative of future results of operations, which may differ materially from the pro forma financial information presented here.



	Nine Months Ended September 30, 2018
Revenues	$	8,032
Net loss	$	(64	)
Net loss attributable to Vistra Energy	$	(61	)
Net loss attributable to Vistra Energy per weighted average share of common stock outstanding — basic	$	(0.12	)
Net loss attributable to Vistra Energy per weighted average share of common stock outstanding — diluted	$	(0.12	)

The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired, interest expense on debt assumed in the Merger, effects of the Merger on tax expense, changes in the expected impacts of the tax receivable agreement due to the Merger, and other related adjustments.


3.	ACQUISITION AND DEVELOPMENT OF GENERATION FACILITIES

Battery Energy Storage Projects

Upton 2 — We have completed the construction of our first battery energy storage system (ESS). In October 2018, we were awarded a $1 million grant from the TCEQ for our battery ESS at our Upton 2 solar facility. The grant is part of the Texas Emissions Reduction Plan. The 10 MW lithium-ion ESS captures excess solar energy produced during the day and releases the energy in late afternoon and early evening, when demand is highest. The Upton 2 battery ESS became operational in December 2018.

Oakland — In June 2019, East Bay Community Energy 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. The contract is pending a concurrent utility Market Capability Agreement contract for review and signature. The utility Market Capability Agreement will then be sent to the California Public Utilities Commission (CPUC) for approval.

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 Pacific Gas and Electric Company (PG&E) to develop a 300 MW battery ESS at our Moss Landing Power Plant site in California. PG&E filed its application with the CPUC in June 2018 and the CPUC approved the resource adequacy contract in November 2018. At September 30, 2019, we had accumulated approximately $50 million in construction work-in-process for this ESS. 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 battery ESS will commence commercial operations in the fourth quarter of 2020. PG&E filed for Chapter 11 bankruptcy protection in January 2019. On October 15, 2019, PG&E filed a motion in its bankruptcy proceeding requesting approval of the assumption of the resource adequacy contract. If the terms of the resource adequacy contract are not honored by PG&E or the resource adequacy contract is rejected through the bankruptcy process, we could have future impairment losses.

Solar Development Project

Upton 2 — In May 2017, we acquired the rights to develop, construct and operate a utility scale solar photovoltaic power generation facility in Upton County, Texas (Upton 2). As part of this project, we entered into a turnkey engineering, procurement and construction agreement to construct the approximately 180 MW facility. We spent approximately $231 million related to this project primarily for progress payments under the engineering, procurement and construction agreement and the acquisition of the development rights. The facility began test operations in March 2018 and commercial operations began in June 2018.

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4.	RETIREMENT OF GENERATION FACILITIES

In September 2019, we announced the settlement of a lawsuit alleging violations of opacity and particulate matter limits at our Edwards facility in Bartonville, Illinois. As part of the settlement, which requires review by the Department of Justice and approval by the U.S. District Court for the Central District of Illinois, we will retire the Edwards facility by the end of 2022 (see Note 13). In August 2019, we announced the planned retirement of four power plants in Illinois with a total installed nameplate generation capacity of 2,068 MW. We are retiring these units due to changes in the Illinois multi-pollutant standard rule that require us to retire approximately 2,000 MW of generation capacity (see Note 13). In light of the provisions of the Federal Power Act and the FERC regulations thereunder, the affected subsidiaries of Vistra Energy identified the retiring units by analyzing each MISO plant's economics and designating the least economic units for retirement. Expected plant retirement expenses of $47 million were accrued in the three months ended September 30, 2019 and are included primarily in operating costs of our MISO 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 statements of consolidated income. The following table details the units that have been or will be retired in Illinois totaling 2,653 MW. Operational results for these plants are included in the MISO segment for the three and nine months ended September 30, 2019 and 2018, but will be recast and included in the Asset Closure segment when they cease operations in the fourth quarter of 2019.



Name	Location (all in the state of Illinois)	Fuel Type	Net Generation Capacity (MW)	Number of Units	Dates Units To Be Taken Offline
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

In August 2018, we filed a notice of suspension of operation with PJM and other mandatory regulatory notifications related to the retirement of our 51 MW Northeastern Power Company waste coal facility in McAdoo, Pennsylvania (Northeastern Facility). We decided to retire the Northeastern Facility due to its uneconomic operations and financial outlook. Following the receipt of regulatory approvals, the Northeastern Facility was retired in October 2018. The decision to retire the Northeastern Facility did not result in a material impact to the financial statements, and the operational results of the Northeastern Facility are included in our Asset Closure segment.

Two of our non-operated, jointly held power plants acquired in the Merger, for which our proportional generation capacity was 883 MW, were retired in May 2018. These units were retired as previously scheduled. No gain or loss was recorded in conjunction with the retirement of these units, and the operational results of these facilities are included in our Asset Closure segment. The following table details the units retired.



Name	Location	Fuel Type	Net Generation Capacity (MW)	Ownership Interest	Date Units Taken Offline
Killen	Manchester, Ohio	Coal	204	33%	May 31, 2018
Stuart	Aberdeen, Ohio	Coal	679	39%	May 24, 2018
Total			883

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In January and February 2018, we retired three power plants in Texas with a total installed nameplate generation capacity of 4,167 MW. We decided to retire these units because they were projected to be uneconomic based on then-current market conditions and would have faced significant environmental costs associated with operating such units. In the case of the Sandow units, the decision also reflected the execution of a contract termination agreement pursuant to which the Company and Alcoa agreed to an early settlement of a long-standing power and mining agreement. Expected retirement expenses were accrued in the third and fourth quarter of 2017 and, as a result, no retirement expenses were recorded related to these facilities in the three and nine months ended September 30, 2018. The operational results of these facilities are included in our Asset Closure segment, which is engaged in the decommissioning and reclamation of retired plants and mines. The following table details the units retired.



Name	Location (all in the state of Texas)	Fuel Type	Installed Nameplate Generation Capacity (MW)	Number of Units	Date Units Taken Offline
Monticello	Titus County	Lignite/Coal	1,880	3	January 4, 2018
Sandow	Milam County	Lignite	1,137	2	January 11, 2018
Big Brown	Freestone County	Lignite/Coal	1,150	2	February 12, 2018
Total			4,167	7


5.	REVENUE

The following tables disaggregate our revenue by major source:



	Three Months Ended September 30, 2019
	Retail		ERCOT			PJM			NY/NE		MISO			CAISO/Eliminations			Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	1,600	$	—		$	—		$	—	$	—		$	—		$	1,600
Retail energy charge in Northeast/Midwest	576		—			—			—		—			—			576
Wholesale generation revenue from ISO/RTO	—		990			137			79		116			46			1,368
Capacity revenue	—		—			24			23		5			—			52
Revenue from other wholesale contracts	—		110			187			84		48			1			430
Total revenue from contracts with customers	2,176		1,100			348			186		169			47			4,026
Other revenues:
Intangible amortization	12		—			—			—		(4		)	—			8
Hedging and other revenues (a)	19		(813		)	(83		)	6		(17		)	48			(840		)
Affiliate sales	—		444			178			22		49			(693		)	—
Total other revenues	31		(369		)	95			28		28			(645		)	(832		)
Total revenues	$	2,207	$	731		$	443		$	214	$	197		$	(598	)	$	3,194

____________


(a)	Includes $86 million of unrealized net losses from mark-to-market valuations of commodity positions. See Note 18 for unrealized net gains (losses) by segment.

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	Three Months Ended September 30, 2018
	Retail			ERCOT		PJM			NY/NE			MISO			Asset Closure			CAISO/Eliminations			Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	1,362		$	—	$	—		$	—		$	—		$	—		$	—		$	1,362
Retail energy charge in Northeast/Midwest	442			—		—			—			—			—			—			442
Wholesale generation revenue from ISO/RTO	—			393		502			244			255			1			81			1,476
Capacity revenue	—			—		164			79			15			(4		)	9			263
Revenue from other wholesale contracts	—			72		11			9			5			(2		)	3			98
Total revenue from contracts with customers	1,804			465		677			332			275			(5		)	93			3,641
Other revenues:
Intangible amortization	15			—		—			(4		)	(5		)	—			—			6
Hedging and other revenues (a)	(6		)	52		(275		)	(42		)	(136		)	5			(2		)	(404		)
Affiliate sales	—			879		218			15			96			(1		)	(1,207		)	—
Total other revenues	9			931		(57		)	(31		)	(45		)	4			(1,209		)	(398		)
Total revenues	$	1,813		$	1,396	$	620		$	301		$	230		$	(1	)	$	(1,116	)	$	3,243

____________


(a)	Includes $28 million of unrealized net losses from mark-to-market valuations of commodity positions. See Note 18 for unrealized net gains (losses) by segment.



	Nine Months Ended September 30, 2019
	Retail			ERCOT			PJM		NY/NE			MISO			CAISO/Eliminations			Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	3,716		$	—		$	—	$	—		$	—		$	—		$	3,716
Retail energy charge in Northeast/Midwest	1,239			—			—		—			—			—			1,239
Wholesale generation revenue from ISO/RTO	—			1,426			487		355			330			141			2,739
Capacity revenue	—			—			144		176			30			—			350
Revenue from other wholesale contracts	—			207			347		96			106			7			763
Total revenue from contracts with customers	4,955			1,633			978		627			466			148			8,807
Other revenues:
Intangible amortization	(7		)	—			—		(3		)	(13		)	3			(20		)
Hedging and other revenues (a)	66			(253		)	88		117			36			108			162
Affiliate sales	—			1,976			767		72			208			(3,023		)	—
Total other revenues	59			1,723			855		186			231			(2,912		)	142
Total revenues	$	5,014		$	3,356		$	1,833	$	813		$	697		$	(2,764	)	$	8,949

____________


(a)	Includes $611 million of unrealized net gains from mark-to-market valuations of commodity positions. See Note 18 for unrealized net gains (losses) by segment.

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	Nine Months Ended September 30, 2018
	Retail			ERCOT			PJM			NY/NE			MISO			Asset Closure			CAISO/Eliminations			Consolidated
Revenue from contracts with customers:
Retail energy charge in ERCOT	$	3,423		$	—		$	—		$	—		$	—		$	—		$	—		$	3,423
Retail energy charge in Northeast/Midwest	778			—			—			—			—			—			—			778
Wholesale generation revenue from ISO/RTO	—			775			869			362			436			52			95			2,589
Capacity revenue	—			—			283			162			44			6			20			515
Revenue from other wholesale contracts	—			175			18			14			16			(1		)	4			226
Total revenue from contracts with customers	4,201			950			1,170			538			496			57			119			7,531
Other revenues:
Intangible amortization	(12		)	(1		)	—			(6		)	(12		)	—			—			(31		)
Hedging and other revenues (a)	50			(181		)	(436		)	(71		)	(256		)	(29		)	4			(919		)
Affiliate sales	—			1,422			370			26			260			20			(2,098		)	—
Total other revenues	38			1,240			(66		)	(51		)	(8		)	(9		)	(2,094		)	(950		)
Total revenues	$	4,239		$	2,190		$	1,104		$	487		$	488		$	48		$	(1,975	)	$	6,581

____________


(a)	Includes $239 million of unrealized net losses from mark-to-market valuations of commodity positions. See Note 18 for unrealized net gains (losses) by segment.

Performance Obligations

As of September 30, 2019, 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 RTO or through bilateral sales. Therefore, an obligation exists as of the date of the results of the respective ISO or RTO capacity auction or the contract execution date for bilateral customers. The transaction price is also set by the results of the capacity auction and/or executed contract. These obligations total $217 million, $776 million, $725 million, $426 million and $96 million that will be recognized in the balance of the year ended December 31, 2019 and the years ending December 31, 2020, 2021, 2022 and 2023, respectively, and $65 million thereafter. Capacity revenues are recognized as capacity is made available to the related ISOs or RTOs or bilateral counterparties.

Accounts Receivable

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



	September 30, 2019		December 31, 2018
Trade accounts receivable from contracts with customers — net (a)	$	1,275	$	951
Other trade accounts receivable — net	144		136
Total trade accounts receivable — net	$	1,419	$	1,087

____________


(a)	At September 30, 2019, includes $136 million of trade accounts receivable related to operations acquired in the Crius Transaction.

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6.	GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

Goodwill

The carrying value of goodwill totaled $2.287 billion and $2.068 billion at September 30, 2019 and December 31, 2018, respectively. Of the total goodwill at September 30, 2019, (a) $205 million arose in connection with the Crius Acquisition, and is unassigned to a reporting unit pending completion of the purchase price allocation and (b) $175 million arose in connection with the Merger, of which $122 million is recorded in our ERCOT Generation reporting unit and $53 million is recorded in our ERCOT Retail reporting unit (see Note 2). The remaining $1.907 billion arose in connection with our application of fresh start reporting at Emergence and was allocated entirely to our ERCOT Retail reporting unit. Of the goodwill recorded at Emergence, $1.686 billion is deductible for tax purposes over 15 years on a straight-line basis.

Identifiable Intangible Assets and Liabilities

Identifiable intangible assets are comprised of the following:



	September 30, 2019						December 31, 2018
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	1,922	$	1,069	$	853	$	1,680	$	876	$	804
Software and other technology-related assets	304		109		195		270		105		165
Retail and wholesale contracts	315		167		148		316		138		178
Contractual service agreements (a)	60		2		58		70		—		70
Other identifiable intangible assets (b)	138		96		42		42		15		27
Total identifiable intangible assets subject to amortization	$	2,739	$	1,443	1,296		$	2,378	$	1,134	1,244
Retail trade names (not subject to amortization)					1,297						1,245
Mineral interests (not currently subject to amortization)					2						4
Total identifiable intangible assets					$	2,595					$	2,493

__________


(a)	At September 30, 2019, 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 and credits.

Identifiable intangible liabilities are comprised of the following:



Identifiable Intangible Liability	September 30, 2019		December 31, 2018
Contractual service agreements	$	107	$	136
Purchase and sale contracts	179		195
Environmental allowances	95		70
Total identifiable intangible liabilities	$	381	$	401

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



Identifiable Intangible Assets and Liabilities	Condensed Statements of Consolidated Income Line	Three Months Ended September 30,						Nine Months Ended September 30,
Identifiable Intangible Assets and Liabilities	Condensed Statements of Consolidated Income Line	2019			2018			2019		2018
Retail customer relationship	Depreciation and amortization	$	82		$	77		$	193	$	227
Software and other technology-related assets	Depreciation and amortization	16			6			45		36
Retail and wholesale contracts/purchase and sale contracts	Operating revenues/fuel, purchased power costs and delivery fees	(9		)	(5		)	14		28
Other identifiable intangible assets	Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization	76			10			116		14
Total amortization expense (a)		$	165		$	88		$	368	$	305

____________


(a)	Amounts recorded in depreciation and amortization totaled $99 million and $84 million for the three months ended September 30, 2019 and 2018, respectively, and $240 million and $266 million for the nine months ended September 30, 2019 and 2018, respectively. Excludes contractual services agreements.

Estimated Amortization of Identifiable Intangible Assets and Liabilities

As of September 30, 2019, the estimated aggregate amortization expense of identifiable intangible assets and liabilities for each of the next five fiscal years is as shown below.



Year	Estimated Amortization Expense
2019	$	308
2020	$	211
2021	$	164
2022	$	101
2023	$	76


7.	INCOME TAXES

Income Tax Expense

The calculation of our effective tax rate is as follows:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Income before income taxes	$	159		$	525		$	962		$	161
Income tax expense	$	(45	)	$	(194	)	$	(270	)	$	(31	)
Effective tax rate	28.3		%	37.0		%	28.1		%	19.3		%

For the three months ended September 30, 2019, the effective tax rate of 28.3% related to our income tax expense 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 nine months ended September 30, 2019, the effective tax rate of 28.1% was higher than the U.S. federal statutory rate of 21% due primarily to state income taxes, including the impact of a valuation allowance on a portion of the State of Illinois net operating loss.

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For the three months ended September 30, 2018, the effective tax rate of 37.0% 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, partially offset by the return to provision adjustment for permanent book-tax differences. For the nine months ended September 30, 2018, the effective tax rate of 19.3% related to our income tax benefit was lower than the U.S. federal statutory rate of 21% due primarily to Vistra Energy's expanded state tax footprint requiring a remeasurement of historical Vistra Energy deferred tax balances and the return to provision adjustment for permanent book-tax differences, partially offset by an increase in state tax expense including a partial valuation allowance on the State of Illinois net operating loss.

Liability for Uncertain Tax Positions

Vistra Energy and its subsidiaries file income tax returns in U.S. federal and state jurisdictions and are expected to be subject to examinations by the IRS and other taxing authorities. Vistra Energy is not currently under audit by the IRS for any period, although review of Dynegy tax year 2018 continues to progress through the IRS's Compliance Assurance Process audit program. Crius is currently under audit by the IRS for the tax years 2015, 2016 and 2017. Uncertain tax positions totaling $38 million at September 30, 2019 reflect (i) the reversal of a $4 million reserve resulting from Vistra Energy's payment of a California State income tax assessment acquired in the Merger and (ii) the addition of a $2 million reserve associated with the acquired Crius tax position. Uncertain tax positions totaling $39 million at December 31, 2018 arose in connection with the Merger.


8.	TAX RECEIVABLE AGREEMENT OBLIGATION

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

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

During the three and nine months ended September 30, 2019, we recorded an increase of $48 million and a decrease of $19 million, respectively, to the carrying value of the TRA obligation as a result of adjustments to the timing of forecasted taxable income and state apportionment due to the expansion of Vistra Energy's state income tax profile, including Dynegy and Crius acquisitions.

During the three and nine months ended September 30, 2018, we recorded a decrease of $32 million and an increase of $14 million, respectively, to the carrying value of the TRA obligation related to changes in the timing of estimated payments resulting from the Merger, including new multistate tax impacts.

The following table summarizes the changes to the TRA obligation, reported as other current liabilities and Tax Receivable Agreement obligation in our condensed consolidated balance sheets, for the nine months ended September 30, 2019 and 2018:



	Nine Months Ended September 30,
	2019			2018
TRA obligation at the beginning of the period	$	420		$	357
Accretion expense	45			51
Changes in tax assumptions impacting timing of payments	(19		)	14
Impacts of Tax Receivable Agreement	26			65
TRA obligation at the end of the period	446			422
Less amounts due currently	(3		)	(20		)
Noncurrent TRA obligation at the end of the period	$	443		$	402

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As of September 30, 2019, the estimated carrying value of the TRA obligation totaled $446 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 Energy now operates in, including the relevant tax rate and apportionment factor for each state. Our taxable income takes into consideration the current federal tax code, various relevant state tax laws and reflects our current estimates of future results of the business. These assumptions are subject to change, and those changes could have a material impact on the carrying value of the TRA obligation. As of September 30, 2019, the aggregate amount of undiscounted federal and state payments under the TRA is estimated to be approximately $1.3 billion, with more than half of such amount expected to be attributable to the first 15 tax years following Emergence, and the final payment expected to be made approximately 40 years following Emergence (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.


9.	EARNINGS PER SHARE

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Net income attributable to common stock — basic	$	113	$	330	$	694	$	132
Weighted average shares of common stock outstanding — basic	490,562,179		533,142,189		486,215,356		500,781,573
Net income per weighted average share of common stock outstanding — basic	$	0.23	$	0.62	$	1.43	$	0.26
Dilutive securities: Stock-based incentive compensation plan	3,108,116		7,830,613		4,011,387		7,347,415
Weighted average shares of common stock outstanding — diluted	493,670,295		540,972,802		490,226,743		508,128,988
Net income per weighted average share of common stock outstanding — diluted	$	0.23	$	0.61	$	1.42	$	0.26

Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 7,145,662 and 7,094,687 shares for the three months ended September 30, 2019 and 2018, respectively, and 7,104,523 and 5,651,527 shares for the nine months ended September 30, 2019 and 2018, respectively.

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10.	ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM

TXU Energy Receivables Company LLC (RecCo), an indirect subsidiary of Vistra Energy, 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 2019, extending its scheduled termination from August 2019 to July 2020, with the ability to borrow up to $600 million until the settlement date in November 2019, after which the amount available for RecCo to borrow will revert to $450 million.

Under the Receivables Facility, TXU Energy and Dynegy Energy Services are obligated to sell or contribute, on an ongoing basis and without recourse, their accounts receivable 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 the receivables acquired from TXU Energy and Dynegy Energy Services to the Purchasers, and its assets and credit are not available to satisfy the debts and obligations of any person, including affiliates of RecCo. 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 statements of consolidated cash flows. Receivables transferred to the Purchasers remain on Vistra Energy's balance sheet and Vistra Energy 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 on behalf of RecCo and the Purchasers, as applicable.

As of September 30, 2019, outstanding borrowings under the receivables facility totaled $600 million and were supported by $835 million of RecCo gross receivables. As of December 31, 2018, outstanding borrowings under the receivables facility totaled $339 million.

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11.	LONG-TERM DEBT

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



	September 30, 2019			December 31, 2018
Vistra Operations Credit Facilities	$	3,798		$	5,813
Vistra Operations Senior Secured Notes:
3.550% Senior Secured Notes, due July 15, 2024	1,200			—
4.300% Senior Secured Notes, due July 15, 2029	800			—
Total Vistra Operations Senior Secured Notes	2,000			—
Vistra Operations Senior Unsecured Notes:
5.500% Senior Notes, due September 1, 2026	1,000			1,000
5.625% Senior Notes, due February 15, 2027	1,300			—
5.000% Senior Notes, due July 31, 2027	1,300			—
Total Vistra Operations Senior Unsecured Notes	3,600			1,000
Vistra Energy Senior Unsecured Notes:
7.375% Senior Notes, due November 1, 2022	—			1,707
5.875% Senior Notes, due June 1, 2023	500			500
7.625% Senior Notes, due November 1, 2024 (a)	387			1,147
8.034% Senior Notes, due February 2, 2024	—			25
8.000% Senior Notes, due January 15, 2025	81			81
8.125% Senior Notes, due January 30, 2026	166			166
Total Vistra Energy Senior Unsecured Notes	1,134			3,626
Other:
7.000% Amortizing Notes, due July 1, 2019	—			24
Forward Capacity Agreements	191			236
Equipment Financing Agreements	114			120
Mandatorily redeemable subsidiary preferred stock (b)	70			70
8.82% Building Financing due semiannually through February 11, 2022 (c)	15			21
9.5% Promissory Notes, due July 2025	44			—
2% Term Loan due February 2027	8			—
Total other long-term debt	442			471
Unamortized debt premiums, discounts and issuance costs (d)	(26		)	155
Total long-term debt including amounts due currently	10,948			11,065
Less amounts due currently	(220		)	(191		)
Total long-term debt less amounts due currently	$	10,728		$	10,874

____________


(a)	On November 1, 2019, Vistra Energy redeemed all outstanding 7.625% Senior Notes due 2024 at a redemption price equal to 103.8% of the aggregate principal amount thereof, plus accrued and unpaid interest to, but excluding the date of redemption.


(b)	Shares of mandatorily redeemable preferred stock in PrefCo. This subsidiary preferred stock is accounted for as a debt instrument under relevant accounting guidance. On October 3, 2019, PrefCo redeemed all of the issued and outstanding preferred stock at a price per share equal to the preferred liquidation amount, plus accrued and unpaid dividends to and including the date of redemption.


(c)	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 assets in our condensed consolidated balance sheets.


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

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Vistra Operations Credit Facilities

At September 30, 2019, the Vistra Operations Credit Facilities consisted of up to $6.523 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 $1.897 billion (Term Loan B-1 Facility) and $1.901 billion (Term Loan B-3 Facility).

In June 2019, Vistra Operations used the net proceeds from the Senior Secured Notes Offering 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.

These amounts reflect amendments to the Vistra Operations Credit Facilities in March 2019 and May 2019 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 in the nine months ended September 30, 2019, which were capitalized as a noncurrent asset.

These amounts also reflect an amendment to the Vistra Operations Credit Facilities in June 2018 whereby we incurred $2.050 billion of borrowings under the new Term Loan B-3 Facility and obtained $1.640 billion of incremental Revolving Credit Facility commitments. The letter of credit sub-facility was also increased by $1.585 billion. The maturity date of the Revolving Credit Facility was extended from August 4, 2021 to June 14, 2023. As discussed below, the proceeds from the Term Loan B-3 Facility were used to repay borrowings under the credit agreement that Vistra Energy assumed from Dynegy in connection with the Merger. Additionally, letter of credit term loans totaling $500 million (Term Loan C Facility) were repaid using $500 million of cash from collateral accounts used to backstop letters of credit. Fees and expenses related to the amendment to the Vistra Operations Credit Facilities totaled $42 million in the nine months ended September 30, 2018, of which $23 million was recorded as interest expense and other charges on the statements of consolidated income, $9 million was capitalized as a reduction in the carrying amount of the debt and $10 million was capitalized as a noncurrent asset.

The Vistra Operations Credit Facilities and related available capacity at September 30, 2019 are presented below.



		September 30, 2019
Vistra Operations Credit Facilities	Maturity Date	Facility Limit		Cash Borrowings		Available Capacity
Revolving Credit Facility (a)	June 14, 2023	$	2,725	$	—	$	1,844
Term Loan B-1 Facility	August 4, 2023	1,897		1,897		—
Term Loan B-3 Facility	December 31, 2025	1,901		1,901		—
Total Vistra Operations Credit Facilities		$	6,523	$	3,798	$	1,844

___________


(a)	Facility to be used for general corporate purposes. Facility includes a $2.35 billion letter of credit sub-facility, of which $881 million of letters of credit were outstanding at September 30, 2019 and which reduce our available capacity.

In February 2018 and June 2018, certain pricing terms for the Vistra Operations Credit Facilities were amended. We accounted for these transactions as modifications of debt. At September 30, 2019, cash borrowings under the Revolving Credit Facility would bear interest based on applicable LIBOR rates, plus a fixed spread of 1.75%, and there were no outstanding borrowings. Letters of credit issued under the Revolving Credit Facility bear interest of 1.75%. Amounts borrowed under the Term Loan B-1 and B-3 Facilities bear interest based on applicable LIBOR rates plus fixed spreads of 2.00% and 2.00%, respectively. At September 30, 2019, the weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings was 4.04% and 4.04% under the Term Loan B-1 and B-3 Facilities, respectively. 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.

In October 2019, Vistra Operations borrowed $550 million under its Revolving Credit Facility. The proceeds of the borrowing were used for general corporate purposes, including the funding of a $425 million dividend to Vistra Energy to pay the principal, premium and interest due in connection with the redemption by Vistra Energy of the entire $387 million aggregate principal amount outstanding of 7.625% senior notes.

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Obligations under the Vistra Operations Credit Facilities are secured by a lien covering substantially all of Vistra Operations' (and its subsidiaries') consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra Operations Credit Facilities, provided that the amount of loans outstanding under the Vistra Operations Credit Facilities that may be secured by a lien covering certain principal properties of the Company is expressly limited by the terms of the Vistra Operations Credit Facilities.

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

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

The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties, material breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against Vistra Operations. Solely with respect to the Revolving Credit Facility, and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $300 million) exceed 30% of the revolving commitments), the agreement includes a covenant that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first-lien debt compared to an EBITDA calculation defined under the terms of the facilities, not to exceed 4.25 to 1.00. Although the period ended September 30, 2019 was not a compliance period, we would have been in compliance with this financial covenant if it was required to be tested at such date. 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.

Interest Rate Swaps — Effective January 2017, we entered into $3.0 billion notional amount of interest rate swaps to hedge a portion of our exposure to our variable rate debt. The interest rate swaps expire in July 2023. In May 2018 and June 2018, we entered into $3.0 billion notional amount of interest rate swaps that become effective in July 2023 and expire in July 2026.

In June 2018, we completed the novation of $1.959 billion notional amount of Vistra Energy (legacy Dynegy) interest rate swaps to Vistra Operations. In June 2019, we terminated $841 million notional amount of these interest rate swaps. At September 30, 2019, $720 million notional amount of these interest rate swaps remained in effect with an expiration date of February 2024.

The interest rate swaps that are currently effective and expire in July 2023 and February 2024 effectively fix the interest rates between 3.92% and 4.16% on $3.720 billion of our variable rate debt. The interest rate swaps that become effective in July 2023 and expire in July 2026 effectively fix the interest rates between 4.97% and 5.04% on $3.0 billion of our variable rate debt during the period. The interest rate swaps are secured by a first-lien secured interest on a pari-passu basis with the Vistra Operations Credit Facilities.

Alternate Letter of Credit Facilities

Two alternate letter of credit facilities (each, an Alternative LOC Facility, and collectively, the Alternate LOC Facilities) with an aggregate facility limit of $500 million became effective in the nine months ended September 30, 2019. At September 30, 2019, $489 million of letters of credit were outstanding under the Alternate LOC Facilities. Of the total facility limit, $250 million matures in December 2020 and $250 million matures in December 2021.

Debt Assumed in Crius Transaction

On the Crius Acquisition Date, Vistra Energy assumed $140 million in long-term debt obligations in connection with the Crius Transaction consisting of the following:

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•	$44 million of 9.50% promissory notes due July 2025 (2025 promissory notes);


•	$8 million of 2.00% Connecticut Department of Economic and Community Development (CT DECD) term loans due February 2027, and


•	$88 million of borrowings and $9 million of issued letters of credit under the legacy Crius credit facility.

In July 2019, borrowings of $88 million under the legacy Crius credit facility were repaid using cash on hand. At September 30, 2019, $3 million of letters of credit were outstanding under the legacy Crius credit facility. In November 2019, (i) borrowings of approximately $38 million under the 2025 promissory notes were repaid using cash on hand and (ii) borrowings of approximately $2 million were offset by legacy indemnification obligations of the holders of the 2025 promissory notes.

Vistra Energy (legacy Dynegy) Credit Agreement

On the Merger Date, Vistra Energy assumed the obligations under Dynegy's $3.563 billion credit agreement consisting of a $2.018 billion senior secured term loan facility due 2024 and a $1.545 billion senior secured revolving credit facility. As of the Merger Date, there were no cash borrowings and $656 million of letters of credit outstanding under the senior secured revolving credit facility. On April 23, 2018, $70 million of the senior secured revolving credit facility matured. In June 2018, the $2.018 billion senior secured term loan facility due 2024 was repaid using proceeds from the Term Loan B-3 Facility. In addition, all letters of credit outstanding under the senior secured revolving credit facility were replaced with letters of credit under the amended Vistra Operations Credit Facilities discussed above, and the revolving credit facility assumed from Dynegy in connection with the Merger was paid off in full and terminated.

Vistra Operations Senior Secured Notes

In June 2019, Vistra Operations issued and sold $2.0 billion aggregate principal amount of senior secured notes (Senior Secured Notes), consisting of $1.2 billion aggregate principal amount of 3.55% senior secured notes due 2024 (3.55% senior secured notes) at a price to the public of 99.807% of their face value and $800 million aggregate principal amount of 4.30% senior secured notes due 2029 (4.30% senior secured notes) at a price to the public of 99.784% of their face value in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act (Senior Secured Notes Offering). The 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. Fees and expenses related to the offering totaled $20 million in the three months ended June 30, 2019, which were capitalized as a reduction in the carrying amount of the debt. Net proceeds from the Senior Secured Notes Offering totaling $1.976 billion, 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 Facilities' Term Loan B Facility. Interest on the Senior Secured Notes is payable in cash semiannually in arrears on January 15 and July 15 beginning January 15, 2020.

The Senior Secured Notes are and will be fully and unconditionally guaranteed 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.

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Vistra Operations Senior Unsecured Notes

In June 2019, Vistra Operations issued and sold $1.3 billion aggregate principal amount of 5.00% senior unsecured notes due 2027 (5.00% senior notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act (the June 2019 Notes Offering). The 5.00% senior 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. Fees and expenses related to the offering totaled $13 million in the three months ended June 30, 2019, which were capitalized as a reduction in the carrying amount of the debt. Net proceeds from the June 2019 Notes Offering totaling approximately $1.287 billion, 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 described below and (ii) the redemption of approximately $306 million of our outstanding 7.375% senior unsecured notes due 2022 (7.375% senior notes) and approximately $87 million of our 7.625% senior unsecured notes due 2024 (7.625% senior notes) in July 2019. The 5.00% senior notes mature in July 2027, with interest payable in cash semiannually in arrears on January 31and July 31 beginning January 31, 2020. We recorded an extinguishment gain of $2 million on the redemptions in the three months ended September 30, 2019.

In February 2019, Vistra Operations issued and sold $1.3 billion aggregate principal amount of 5.625% senior unsecured notes due 2027 (5.625% senior notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act (the February 2019 Notes Offering). The 5.625% senior notes 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. Fees and expenses related to the offering totaled $16 million in the three months ended March 31, 2019, which were capitalized as a reduction in the carrying amount of the debt. Net proceeds from the February 2019 Notes Offering totaling approximately $1.287 billion, 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 February 2019 Tender Offer described below, (ii) the redemption of approximately $35 million aggregate principal amount of our 7.375% senior notes and (iii) the redemption of approximately $25 million aggregate principal amount of our outstanding 8.034% senior unsecured notes due 2024 (8.034% senior notes). The 5.625% senior notes mature in February 2027, with interest payable in cash semiannually in arrears on February 15 and August 15 beginning August 15, 2019.

In August 2018, Vistra Operations issued $1.0 billion principal amount of 5.500% senior unsecured notes due 2026 (5.500% senior notes, and together with the 5.00% senior notes and the 5.625% senior notes, the Vistra Operations Senior Unsecured Notes) in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act (the 2018 Notes Offering). The 5.500% senior notes were sold pursuant to a purchase agreement by and among Vistra Operations, the Guarantor Subsidiaries and Citigroup Global Markets Inc., as representative of the several initial purchasers. Fees and expenses related to the offering totaled $12 million in the three months ended September 30, 2018, which were capitalized as a reduction in the carrying amount of the debt. Net proceeds from the 2018 Notes Offering totaling approximately $990 million, together with cash on hand and cash received from the funding of the Receivables Facility (see Note 10), were used to pay the purchase price and accrued interest (together with fees and expenses) required in connection with the 2018 Tender Offers described below. The 5.500% senior notes mature in September 2026, with interest payable in cash semiannually in arrears on March 1 and September 1 beginning March 1, 2019.

The indentures governing the 5.00% senior notes, the 5.625% senior notes and the 5.500% senior notes (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 the Issuer and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets.

Vistra Energy Senior Unsecured Notes

Bond 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 Energy Senior Unsecured Notes could be repurchased. Through September 30, 2019, $119 million principal amount of Vistra Energy Senior Unsecured Notes had been repurchased. No repurchases were made in the three and nine months ended September 30, 2019. 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 its authority superseding the previously authorized bond repurchase program.

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November 2019 Redemption — In November 2019, Vistra Energy redeemed the entire $387 million aggregate principal amount outstanding of 7.625% senior notes at a redemption price equal to 103.8% of the aggregate principal amount thereof, plus accrued and unpaid interest to, but excluding, the date of redemption.

June 2019 Tender Offer — In June 2019, Vistra Energy used the net proceeds from the June 2019 Notes Offering to fund a cash tender offer (the 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 three months ended June 30, 2019. In July 2019, Vistra Energy 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 2019 Tender Offer.

February 2019 Tender Offer and Consent Solicitation — In February 2019, Vistra Energy used the net proceeds from the February 2019 Notes Offering to fund a cash tender offer (the February 2019 Tender Offer) 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 three months ended March 31, 2019.

In connection with the February 2019 Tender Offer, Vistra Energy also commenced solicitation of consents from holders of the 7.375% senior notes. Vistra Energy 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.

August 2018 Tender Offers and Consent Solicitations — In August 2018, Vistra Energy used the net proceeds from the 2018 Notes Offering, proceeds from the Receivables Facility (see Note 10) and cash on hand to fund cash tender offers (the 2018 Tender Offers) to purchase for cash $1.542 billion aggregate principal amount of Vistra Energy Senior Unsecured Notes assumed in the Merger. We recorded an extinguishment loss of $27 million on the transactions in the three months ended September 30, 2018. Notes purchased consisted of the following:


•	$26 million of 7.625% senior notes;


•	$163 million of 8.034% senior notes;


•	$669 million of 8.000% senior unsecured notes due 2025 (8.000% senior notes), and


•	$684 million of 8.125% senior unsecured notes due 2026 (8.125% senior notes).

In connection with the 2018 Tender Offers, Vistra Energy also commenced solicitations of consents from holders of the 7.375% senior notes, the 7.625% senior notes, the 8.034% senior notes, the 8.000% senior notes and the 8.125% senior notes to amend certain provisions of the applicable indentures governing each series of senior notes and the registration rights agreement with respect to the 8.125% senior notes. Vistra Energy received the requisite consents from the holders of the 8.034% senior notes, the 8.000% senior notes and the 8.125% senior notes (collectively, the Consent Senior Notes) and amended (a) the indentures governing each series of the applicable senior notes to, among other things, eliminate substantially all of the restrictive covenants and certain events of default and (b) the registration rights agreement with respect to the 8.125% senior notes to remove, among other things, the requirement that Vistra Energy commence an exchange offer to issue registered securities in exchange for the existing, nonregistered notes.

Assumption of Senior Notes in Merger — On the Merger Date, Vistra Energy assumed $6.138 billion principal amount of Dynegy's senior unsecured notes. In May 2018, $850 million of outstanding 6.75% senior unsecured notes due 2019 were redeemed at a redemption price of 101.7% of the aggregate principal amount, plus accrued and unpaid interest up to but not including the date of redemption. Fees and expenses related to the redemption totaled $14 million in the three months ended June 30, 2018 and were recorded as interest expense and other charges on the condensed statements of consolidated income. In June 2018, each of the Company's subsidiaries that guaranteed the Vistra Operations Credit Facilities (and did not already guarantee the senior notes) provided a guarantee on the senior notes that remained outstanding.

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The senior notes that remain outstanding after the closing of the Tender Offers are unsecured and unsubordinated obligations of Vistra Energy and are guaranteed by substantially all of its current and future wholly owned domestic subsidiaries that from time to time are a borrower or guarantor under the agreement governing the Vistra Operations Credit Facilities (Credit Facilities Agreement) (see Note 20). Except with respect to the Consent Senior Notes, the respective indentures of the senior notes of Vistra Energy (collectively, as each may be amended or supplemented from time to time, the Vistra Energy Senior Unsecured Indentures) limit, among other things, the ability of the Company or any of the guarantors to create liens upon any principal property to secure debt for borrowed money in excess of, among other limitations, 30% of total assets. The Vistra Energy Senior Unsecured Indentures also contain customary events of default which would permit the holders of the applicable series of senior notes to declare such notes to be immediately due and payable if not cured within applicable grace periods, including the failure to make timely principal or interest payments on such notes or (except with respect to the Consent Senior Notes) other indebtedness aggregating $100 million or more, and, except with respect to the Consent Senior Notes, the failure to satisfy covenants, and specified events of bankruptcy and insolvency.

Amortizing Notes

On the Merger Date, Vistra Energy assumed the obligations of Dynegy's senior unsecured amortizing note (Amortizing Notes) that matured on July 1, 2019. The Amortizing Notes were issued in connection with the issuance of the tangible equity units (TEUs) by Dynegy (see Note 14). Each installment payment per Amortizing Note was paid in cash and constituted a partial repayment of principal and a payment of interest, computed at an annual rate of 7.00%. Interest was calculated on the basis of a 360-day year consisting of twelve 30-day months. Payments were applied first to the interest due and payable and then to the reduction of the unpaid principal amount, allocated as set forth in the indenture (Amortizing Notes Indenture). On the maturity date, the Company paid all amounts due under the Amortizing Notes Indenture and the Amortizing Notes Indenture ceased to be of further force and effect.

Forward Capacity Agreements

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 Capacity Agreements). The buyer in this transaction will receive capacity payments from PJM during the Planning Years 2019-2020 and 2020-2021 in the amounts of $81 million and $110 million, respectively. 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 of $191 million with an implied interest rate of 3.20%.

Equipment Financing Agreements

On the Merger Date, the Company assumed Dynegy's Equipment Financing Agreements. Under certain 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 have financed these parts and equipment under agreements with maturities ranging from 2019 to 2026. The portion of future payments attributable to principal will be classified as cash outflows from financing activities, and the portion of future payments attributable to interest will be classified as cash outflows from operating activities in our condensed statements of consolidated cash flows.

Redeemable Preferred Stock of PrefCo

In October 2019, PrefCo voluntarily redeemed the entire $70 million aggregate principal amount outstanding of its authorized preferred stock at a price per share equal to the preferred liquidation amount, plus accrued and unpaid dividends to and including the date of redemption.

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Maturities

Long-term debt maturities at September 30, 2019 are as follows:



	September 30, 2019
Remainder of 2019	$	122
2020	144
2021	70
2022	16
2023	2,408
Thereafter	8,214
Unamortized premiums, discounts and debt issuance costs	(26		)
Total long-term debt, including amounts due currently	$	10,948


12.	LEASES

Vistra has both finance and operating leases for real estate, rail cars and equipment. Our leases have remaining lease terms for 1 to 38 years. Our leases include options to renew up to 14 years. Certain leases also contain options to terminate the lease.

Lease Cost

The following table presents costs related to lease activities:



	Three Months Ended September 30, 2019			Nine Months Ended September 30, 2019
Operating lease cost	$	3		$	10
Finance lease:
Finance lease right-of-use asset amortization	1			3
Interest on lease liabilities	1			2
Total finance lease cost	2			5
Variable lease cost (a)	5			17
Short-term lease cost	4			17
Sublease income (b)	(2		)	(6		)
Net lease cost	$	12		$	43

____________


(a)	Represents coal stockpile management services, common area maintenance services and rail car payments based on the number of rail cars used.


(b)	Represents sublease income related to real estate leases.

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Balance Sheet Information

The following table presents lease related balance sheet information:



	September 30, 2019
Lease assets
Operating lease right-of-use assets	$	50
Finance lease right-of-use assets (net of accumulated depreciation)	70
Total lease right-of-use assets	120
Current lease liabilities
Operating lease liabilities	12
Finance lease liabilities	7
Total current lease liabilities	19
Noncurrent lease liabilities
Operating lease liabilities	53
Finance lease liabilities	88
Total noncurrent lease liabilities	141
Total lease liabilities	$	160

Cash Flow and Other Information

The following table presents lease related cash flow and other information:



	Nine Months Ended September 30, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	10
Operating cash flow from finance leases	3
Finance cash flow from finance leases	2
Non-cash disclosure upon commencement of new lease
Right-of-use assets obtained in exchange for new operating lease liabilities	91
Right-of-use assets obtained in exchange for new finance lease liabilities	24
Non-cash disclosure upon modification of existing lease
Modification of operating lease right-of-use assets	(36		)
Modification of finance lease right-of-use assets	51

Weighted Average Remaining Lease Term

The following table presents weighted average remaining lease term information:



	September 30, 2019
Weighted average remaining lease term
Operating lease	14 years
Finance lease	16 years
Weighted average discount rate
Operating lease	5.67%
Finance lease	5.83%

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Maturity of Lease Liabilities

The following table presents maturity of lease liabilities:



	Operating lease			Finance lease			Total lease
Remainder of 2019	$	3		$	3		$	6
2020	14			13			27
2021	9			12			21
2022	8			12			20
2023	7			12			19
Thereafter	52			85			137
Total lease payments	93			137			230
Less: Interest	(28		)	(42		)	(70		)
Present value of lease liabilities	$	65		$	95		$	160

As of September 30, 2019, we have no material operating or finance leases that have not yet commenced.


13.	COMMITMENTS AND CONTINGENCIES

Guarantees

We have entered into contracts, including the assumed Dynegy senior unsecured notes described above, that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. As of September 30, 2019, there 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.

Letters of Credit

At September 30, 2019, we had outstanding letters of credit totaling $1.370 billion as follows:


•	$1.224 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 RTOs;


•	$47 million to support executory contracts and insurance agreements;


•	$38 million to support our REP financial requirements with the PUCT, and


•	$61 million for other credit support requirements.

Surety Bonds

At September 30, 2019, we had outstanding surety bonds totaling $55 million to support performance under various contracts and legal obligations in the normal course of business.

Litigation

Gas Index Pricing Litigation — We, through our subsidiaries, and other energy 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 cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices in three states (Kansas, Missouri and Wisconsin) during the relevant time period and seek damages under the respective state antitrust statutes. The cases had been consolidated (along with other similar cases) in a multi-district litigation (MDL) proceeding in the U.S. District Court for Nevada, but in January 2019 the MDL judge issued an order remanding the consolidated cases back to their respective courts of origin. Along with other defendants, we had previously reached a settlement in the Kansas and Missouri class action cases, which the judge approved. The settlement amounts were immaterial. We remain as defendants in two consolidated putative class actions (Wisconsin) and one individual action (Kansas). While we cannot predict the outcome of these legal proceedings, or estimate a range of costs, they could have a material impact on our results of operations, liquidity or financial condition.

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Advatech Dispute — In October 2018, Illinois Power Generating Company (Genco) defended an arbitration filed by Advatech LLC (Advatech) alleging $81 million in termination charges under the Second Amended and Restated Newton Flue Gas Desulfurization System Engineering, Procurement, Construction and Commissioning Services Contract dated as of December 15, 2014. An arbitration panel issued a final award in June 2019, including pre-award and post-award interest and fees totaling approximately $46 million, of which $42 million was recorded as a liability as part of our purchase price allocation of the Merger, $2 million was recorded as interest expense in our condensed statements of consolidated income and $2 million was recorded as selling, general and administrative expense in our condensed statements of consolidated income. Post-award interest of approximately $1 million was recorded as interest expense in our condensed statements of consolidated income in the three months ended September 30, 2019. In June 2019, Genco moved to vacate the award in the U.S. District Court for the Southern District of Illinois, and Advatech moved to confirm the award in the U.S. District Court for the Northern District of Illinois, which is currently stayed pending a decision by the Southern District of Illinois on the issue of venue.

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 and Norfolk Southern Railway Company filed a demand for arbitration. We dispute the railroads' allegations and will defend our position vigorously. While we cannot predict the outcome of this legal proceeding, or estimate a range of costs, it could have a material impact on our results of operations, liquidity or financial condition.

Greenhouse Gas Emissions

In August 2015, the EPA finalized rules to address greenhouse gas emissions (GHG) 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) and subsequently, in January 2016, a coalition of state, industry and other parties filed applications with the U.S. Supreme Court (Supreme Court) asking that the Supreme Court stay the rule pending review by the D.C. Circuit Court. In February 2016, the Supreme Court stayed the rule. In July 2019, petitioners filed a joint motion to dismiss in light of the EPA's new rule, the Affordable Clean Energy rule, that replaces the Clean Power Plan discussed below. In September 2019, the D.C. Circuit Court granted petitioners' motion to dismiss and dismissed all of the petitions as moot.

In July 2019, the EPA finalized a rule to repeal the Clean Power Plan, with new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the Affordable Clean Energy (ACE) rule. The ACE rule develops emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generating units. States must submit their plans for regulating GHG emissions from existing facilities by July 2022. 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. Additionally, in December 2018, the EPA issued proposed revisions to the emission standards for new, modified and reconstructed units. Vistra Energy submitted comments on that proposed rulemaking. While we cannot predict the outcome of these rulemakings and related legal proceedings, or estimate a range of reasonably probable costs, the rules, if implemented, could have a material impact on our results of operations, liquidity or financial condition.

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

In January 2016, the EPA issued a final rule approving in part and disapproving in part Texas's 2009 State Implementation Plan (SIP) as it relates to the reasonable progress component of the Regional Haze program and issuing a Federal Implementation Plan (FIP). The EPA's emission limits in the FIP assume additional control equipment for specific lignite/coal-fueled generation units across Texas, including new flue gas desulfurization systems (scrubbers) at seven electricity generation units (including Big Brown Units 1 and 2, Monticello Units 1 and 2 and Coleto Creek) and upgrades to existing scrubbers at seven generation units (including Martin Lake Units 1, 2 and 3, Monticello Unit 3 and Sandow Unit 4).

In March 2016, various parties (including Luminant and the State of Texas) filed petitions for review in the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court) challenging the FIP's Texas requirements. In July 2016, the Fifth Circuit Court granted motions to stay the rule pending final review of the petitions for review. In March 2017, the Fifth Circuit Court granted a motion by the EPA to remand the rule back to the EPA for reconsideration. The stay of the rule (and the emission control requirements) remains in effect. The retirements of our Monticello, Big Brown and Sandow 4 plants should have a favorable impact on this rulemaking and litigation. While we cannot predict the outcome of the rulemaking and legal proceedings, or estimate a range of reasonably possible costs, the result could have a material impact on our results of operations, liquidity or financial condition.

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In September 2017, the EPA signed a final rule addressing BART for Texas electricity generation units, with the rule serving as a partial approval of Texas's 2009 SIP and a partial FIP. For SO₂, the rule creates 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. We believe the retirements of our Monticello, Big Brown and Sandow 4 plants will enhance our ability to comply with this BART rule for SO₂. For NO_X, the rule adopts the CSAPR's ozone program as BART and for particulate matter, the rule approves 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 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 until the EPA concludes the reconsideration process. In August 2018, the EPA issued a proposed rule affirming the prior BART final rule and seeking comments on that proposal, which were due in October 2018. While we cannot predict the outcome of the rulemaking and legal proceedings, we believe the rule, if ultimately implemented or upheld as issued, will not have a material impact on our results of operations, liquidity or financial condition.

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. We cannot predict the timing or outcome of this proceeding, or estimate a range of reasonably possible costs, but implementation of the 2015 rule as finalized could have a material impact on our results of operations, liquidity or financial condition.

Illinois Multi-Pollutant Standards (MPS)

In August 2019, changes proposed by the Illinois Pollution Control Board to the Illinois multi-pollutant standard rule (MPS rule), which places NOx, SO₂ and mercury emissions limits on our coal plants located in MISO went into effect. Under the revised MPS rule, our allowable SO₂ and NOx emissions from the MISO fleet are 48% and 42% lower. respectively, than prior to the rule changes. The revised MPS rule requires the continuous operation of existing selective catalytic reduction (SCR) control systems during the ozone season, requires SCR-controlled units to meet an ozone season NO_X emission rate limit, and set an additional, site-specific annual SO₂ limit for our Joppa Power Station. Additionally, the company will be retiring its Havana, Hennepin, Coffeen and Duck Creek plants by the end of 2019 in order to comply with the MPS rule's requirement to retire at least 2,000 MW of the company's generation in MISO. The required regulatory approvals for these retirements have been received from MISO and PJM and these plants will be permanently retired by the end of 2019. See Note 4 for information regarding the retirement of the four plants.

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. While we cannot predict the outcome of this matter, or estimate a range of reasonably possible costs, the result could have a material impact on our results of operations, liquidity or financial condition.

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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 final rule and administratively stayed the rule's compliance date deadlines. In August 2017, the EPA announced that its reconsideration of the 2015 ELG final 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 2015 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. The EPA has not yet proposed or finalized a rule reconsidering the FGD and bottom ash wastewater provisions of the 2015 ELG rule.

Given the EPA's decision to reconsider the FGD and bottom ash wastewater provisions of the ELG rule, the rule postponing the ELG rule's earliest compliance dates for those provisions, the uncertainty stemming from the vacatur of the effluent limitations for legacy wastewater and leachate, and the intertwined relationship of the ELG rule with the Coal Combustion Residuals rule 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. While we cannot predict the outcome of this matter, or estimate a range of costs, it could have a material impact on our results of operations, liquidity or financial condition.

New Source Review and CAA Matters

New Source Review — Since 1999, the EPA has engaged in a nationwide enforcement initiative to determine whether coal-fueled power plants failed to comply with the requirements of the New Source Review (NSR) and New Source Performance Standard provisions under the CAA when the plants implemented changes. The EPA's NSR initiative focuses on whether projects performed at power plants triggered various permitting requirements, including the need to install pollution control equipment.

In August 2013, the U.S. Department of Justice (DOJ), acting as the attorneys for the EPA, filed a civil enforcement lawsuit against Luminant in federal district court in Dallas, alleging violations of the CAA, including its NSR standards, at our Big Brown and Martin Lake generation facilities. The lawsuit requests (i) the maximum civil penalties available under the CAA to the government of up to $32,500 to $37,500 per day for each alleged violation, depending on the date of the alleged violation, and (ii) injunctive relief, including an order to apply for pre-construction permits which may require the installation of best available control technology at the affected units. In August 2015, the district court granted Luminant's motion to dismiss seven of the nine claims asserted by the EPA in the lawsuit.

In January 2017, the EPA dismissed its two remaining claims with prejudice and the district court entered final judgment in Luminant's favor. In March 2017, the EPA and the Sierra Club appealed the final judgment to the Fifth Circuit Court. In October 2018, the Fifth Circuit Court affirmed in part, reversed in part, and remanded to the district court. The Fifth Circuit Court's decision held that the district court properly dismissed all of the civil penalties as time-barred. The Fifth Circuit Court further held that the grounds cited by the district court did not support dismissal of the injunctive relief claims at this early stage of the case and remanded the case back to the district court for further consideration. In November 2018, we filed a petition for rehearing en banc on two issues and the EPA has filed a response to that petition. In July 2019, the full Fifth Circuit Court granted our en banc petition and oral argument was scheduled to be held in September 2019. Following the Fifth Circuit Court's grant of oral argument, in August 2019, the EPA and the Sierra Club moved to dismiss their appeals of the district court's judgment, which the Fifth Circuit granted, ending this litigation.

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. The NOVs remain unresolved.

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Edwards CAA Citizen Suit — In April 2013, environmental groups filed a CAA citizen suit in the U.S. District Court for the Central District of Illinois alleging violations of opacity and particulate matter limits at our MISO segment's Edwards facility. In August 2016, the district court granted the plaintiffs' motion for summary judgment on certain liability issues. In March 2019, the court denied the parties' motions for summary judgment on remedy issues. In September 2019, the parties to the lawsuit announced a proposed settlement which, if approved by the court, would require the retirement of the Edwards plant by the end of 2022 and funding for certain projects that benefit Peoria-area communities. On October 15, 2019, following EPA and DOJ review, the parties filed a joint motion seeking the court's approval of a Consent Decree memorializing this settlement. If approved by the court, the proposed consent decree would resolve this lawsuit. See Note 4 for information regarding the retirement of the Edwards plant.

Ultimate resolution of these CAA matters could have a material adverse impact on our future financial condition, results of operations, and cash flows. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties, or could result in an order or a decision to retire these plants. While we cannot predict the outcome of the unresolved legal proceedings, or estimate a range of costs, they could have a material impact on our results of operations, liquidity or financial condition.

Coal Combustion Residuals/Groundwater

In July 2018, the EPA published a final rule, which became effective in August 2018, that amends certain provisions of the Coal Combustion Residuals (CCR) rule that the agency issued in 2015. Among other changes, the 2018 revisions extend closure deadlines to October 31, 2020, related to the aquifer location restriction and groundwater monitoring requirements. Also, on August 21, 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. The EPA is expected to issue proposed rules on these and other aspects of the CCR rule in the near term. While we cannot predict the impacts of these rule revisions (including whether and if so how the states in which we operate will utilize the authority delegated to the states through the revisions), or estimate a range of reasonably possible costs related to these revisions, the changes that result from these revisions could have a material impact on our results of operations, liquidity or financial condition.

MISO Segment — 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. In 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east, and west fly ash CCR surface impoundments. We are working towards implementation of those closure plans.

At our retired Vermilion facility, which was not subject to the EPA's 2015 CCR rule until the aforementioned D.C. Circuit court decision in August 2018, we submitted proposed corrective action plans involving closure of two CCR surface impoundments (i.e., the old east and the north impoundments) to the IEPA in 2012, with revised plans submitted 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 filed a citizen suit against our subsidiary Dynegy Midwest Generation, LLC (DMG), alleging violations of the Clean Water Act for alleged unauthorized discharges. In August 2018, we filed a motion to dismiss the lawsuit. In November 2018, the district court granted our motion to dismiss and judgment was entered in our favor. Plaintiffs have appealed the judgment to the U.S Court of Appeals for the Seventh Circuit. That appeal is now stayed. 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 matter is in very early stages and we dispute the allegations in the complaint. We dispute the allegations in both of these matters and will vigorously defend our position.

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 and that notice has since been referred to the Illinois Attorney General.

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. We dispute the allegations and will vigorously defend our position.

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In July 2019, coal ash disposal and storage legislation in Illinois was enacted. The legislation addresses state requirements for the proper closure of coal ash ponds in the state of Illinois. The law tasks the IEPA and the IPCB to set up a series of guidelines, rules and permit requirements for closure of ash ponds. We expect the rulemaking process should take about 18 months to complete. Under the new law, 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 law does not mandate closure by removal at any site. With respect to near-term costs, the law requires that operators pay a one-time fee of $50,000 for each closed site and $75,000 for each open site. This one-time fee is paid six months after the effective date of the law. The law also requires annual permit fees. While we cannot predict the outcome of these proceedings, or estimate a range of costs, they could have a material impact on our results of operations, liquidity or financial condition.

For all of the above matters, if remediation measures concerning groundwater are necessary 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. At this time, in part because of the revisions to the CCR rule that the EPA published in July 2018 and the D.C. Circuit Court's vacatur and remand of certain provisions of the EPA's 2015 CCR rule and the Illinois coal ash rulemaking, we cannot reasonably estimate the costs, or range of costs, of groundwater remediation, if any, that ultimately may be required. The currently anticipated CCR surface impoundment and landfill closure costs, as contained in our AROs, reflect the costs of well-accepted closure methods that our operations and environmental services teams believe are appropriate and protective of the environment for each location.

MISO 2015-2016 Planning Resource Auction

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

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

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

In July 2019, FERC issued an order denying the remaining issues raised by the complaints and noted that the investigation into Dynegy was closed. FERC found that Dynegy's conduct did not constitute market manipulation and the results of the PRA were just and reasonable because the PRA was conducted in accordance with MISO's tariff. With the issuance of the order, this matter has been resolved in Dynegy's favor. The order remains subject to rehearing at FERC and appeal.

Other Matters

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

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14.	EQUITY

Share Repurchase Program

In November 2018, we announced that the Board had authorized an incremental share repurchase program (Program) under which up to $1.250 billion of our outstanding stock may be purchased. In the three months ended September 30, 2019, 7,407,199 shares of our common stock were repurchased for approximately $171 million (including related fees and expenses) at an average price of $23.07 per share of common stock. In the nine months ended September 30, 2019, 25,507,528 shares of our common stock were repurchased for approximately $619 million (including related fees and expenses) at an average price of $24.27 per share of common stock. On a cumulative basis, 37,580,619 shares of our common stock have been repurchased under the Program for approximately $897 million (including related fees and expenses) at an average price of $23.86 per share of common stock. At September 30, 2019, approximately $353 million was available for additional repurchases under the 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 Program or otherwise will be determined at our discretion and will depend on a number of factors, including the market price of our stock, general market and economic conditions, applicable legal requirements and compliance with the terms of our debt agreements and the Tax Matters Agreement.

Dividends

In November 2018, Vistra Energy announced the Board had adopted a dividend program pursuant to which Vistra Energy would initiate an annual dividend of approximately $0.50 per share expected to begin in the first quarter of 2019. Each dividend under the program will be subject to the 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 Energy's results of operations, financial condition and liquidity and Delaware law.

In February 2019, May 2019 and July 2019, the Board declared quarterly dividends of $0.125 per share that were paid in March 2019, June 2019 and September 2019, respectively.

In October 2019, the Board declared a quarterly dividend of $0.125 per share that will be paid in December 2019. Vistra Energy did not declare or pay any dividends during the three months or nine months ended September 30, 2018.

Dividend Restrictions

The Credit Facilities Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of September 30, 2019, Vistra Operations can distribute approximately $6.3 billion to Parent under the Credit Facilities Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Parent of approximately $270 million and $3.465 billion during the three and nine months ended September 30, 2019, respectively, and approximately $4.7 billion and $1.1 billion during the years ended December 31, 2018 and 2017, respectively. Additionally, Vistra Operations may make distributions to Parent in amounts sufficient for Parent to make any payments required under the TRA or the Tax Matters Agreement or, to the extent arising out of Parent's ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses. As of September 30, 2019, the maximum amount of restricted net assets of Vistra Operations that may not be distributed to Parent totaled approximately $2.0 billion.

Under applicable Delaware General Corporate Law, we are prohibited from paying any distribution to the extent that such distribution exceeds the value of our "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).

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Warrants

At the Merger Date, the Company entered into an agreement whereby holders of each outstanding warrant previously issued by Dynegy will be entitled to receive, upon exercise, the equity securities to which the holder would have been entitled to receive of Dynegy common stock converted into shares of Vistra Energy common stock at the Exchange Ratio. As of September 30, 2019, nine million warrants expiring in 2024 with an exercise price of $35.00 (subject to adjustment from time to time) were outstanding, each of which can be redeemed for 0.652 share of Vistra Energy common stock. The warrants are recorded as equity in our condensed consolidated balance sheet.

Tangible Equity Units (TEUs)

At the Merger Date, the Company assumed the obligations of Dynegy's 4,600,000 7.00% TEUs, each with a stated amount of $100.00 and each comprised of (i) a prepaid stock purchase contract that delivered to the holder, on July 1, 2019, 4.0813 shares of Vistra Energy common stock per contract with cash paid in lieu of any fractional shares at a rate of $22.5954 per share and (ii) a senior amortizing note with an outstanding principal amount of $38 million at the Merger Date that paid an equal quarterly cash installment of $1.75 per amortizing note (see Note 11). In the aggregate, the annual quarterly cash installments were equivalent to a 7.00% cash payment per year with respect to each $100.00 stated amount of TEUs. The amortizing notes were accounted for as debt while the stock purchase contract was included in equity based on the fair value of the contract at the Merger Date (see Note 11). The entire class of TEUs were suspended from trading on the New York Stock Exchange on July 1, 2019 and removed from listing and registration on July 12, 2019. On July 1, 2019, approximately 18.8 million treasury shares of Vistra Energy common stock were issued in connection with the settlement of all outstanding TEUs.

Equity

The following table presents the changes to equity for the three months ended September 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 June 30, 2019	$	5	$	(1,226	)	$	10,135		$	(989	)	$	(21	)	$	7,904		$	—		$	7,904
Stock repurchase	—		(171		)	—			—			—			(171		)	—			(171		)
Shares issued for tangible equity unit contracts	—		446			(446		)	—			—			—			—			—
Dividends declared on common stock	—		—			—			(61		)	—			(61		)	—			(61		)
Effects of stock-based incentive compensation plans	—		—			17			—			—			17			—			17
Net income	—		—			—			113			—			113			1			114
Change in accumulated other comprehensive income (loss) (a)	—		—			—			—			(13		)	(13		)	—			(13		)
Other	—		—			2			1			—			3			(1		)	2
Balance at September 30, 2019	$	5	$	(951	)	$	9,708		$	(936	)	$	(34	)	$	7,792		$	—		$	7,792

________________


(a)	Reflects remeasurement of our pension and OPEB plans resulting from the MISO segment plant closures (see Note 4).

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The following table presents the changes to equity for the nine months ended September 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	—		(619		)	—			—			—			(619		)	—			(619		)
Shares issued for tangible equity unit contracts	—		446			(446		)	—			—			—			—			—
Dividends declared on common stock	—		—			—			(181		)	—			(181		)	—			(181		)
Effects of stock-based incentive compensation plans	—		—			45			—			—			45			—			45
Net income	—		—			—			694			—			694			(2		)	692
Adoption of accounting standard	—		—			—			(2		)	—			(2		)	—			(2		)
Change in accumulated other comprehensive income (loss) (b)	—		—			—			—			(12		)	(12		)	—			(12		)
Other	—		—			2			2			—			4			(2		)	2
Balance at September 30, 2019	$	5	$	(951	)	$	9,708		$	(936	)	$	(34	)	$	7,792		$	—		$	7,792

________________


(a)	Authorized shares totaled 1,800,000,000 at September 30, 2019. Outstanding shares totaled 487,783,432 and 493,215,309 at September 30, 2019 and December 31, 2018, respectively.


(b)	Reflects remeasurement of our pension and OPEB plans resulting from the MISO segment plant closures (see Note 4).

The following table presents the changes to equity for the three months ended September 30, 2018:



	Common Stock		Treasury Stock			Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Stockholders' Equity			Noncontrolling Interest			Total Equity
Balance at June 30, 2018	$	5	$	(75	)	$	10,090		$	(1,591	)	$	(16	)	$	8,413		$	7		$	8,420
Stock repurchase	—		(349		)	—			—			—			(349		)	—			(349		)
Effects of stock-based incentive compensation plans	—		—			6			—			—			6			—			6
Net income	—		—			—			330			—			330			—			330
Change in accumulated other comprehensive income (loss)	—		—			—			—			1			1			—			1
Investment by noncontrolling interest	—		—			—			—			—			—			(1		)	(1		)
Other	—		—			(2		)	—			—			(2		)	—			(2		)
Balance at September 30, 2018	$	5	$	(424	)	$	10,094		$	(1,261	)	$	(15	)	$	8,399		$	6		$	8,405

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The following table presents the changes to equity for the nine months ended September 30, 2018:



	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, 2017	$	4	$	—		$	7,765		$	(1,410	)	$	(17	)	$	6,342		$	—	$	6,342
Stock and stock compensation awards issued in connection with the Merger	1		—			1,891			—			—			1,892			—		1,892
Stock repurchase	—		(424		)	—			—			—			(424		)	—		(424		)
Effects of stock-based incentive compensation plans	—		—			69			—			—			69			—		69
Tangible equity units acquired	—		—			369			—			—			369			—		369
Warrants acquired	—		—			2			—			—			2			—		2
Net loss	—		—			—			132			—			132			—		132
Adoption of accounting standard	—		—			—			17			—			17			—		17
Change in accumulated other comprehensive income (loss)	—		—			—			—			2			2			—		2
Investment by noncontrolling interest	—		—			—			—			—			—			6		6
Other	—		—			(2		)	—			—			(2		)	—		(2		)
Balance at September 30, 2018	$	5	$	(424	)	$	10,094		$	(1,261	)	$	(15	)	$	8,399		$	6	$	8,405

________________


(a)	Authorized shares totaled 1,800,000,000 at September 30, 2018. Outstanding shares totaled 507,391,134 and 428,398,802 at September 30, 2018 and December 31, 2017, respectively.


15.	FAIR VALUE MEASUREMENTS

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

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

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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.

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



September 30, 2019
	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	729	$	165	$	176	$	110	$	1,180
Nuclear decommissioning trust – equity securities (c)	516		—		—		—		516
Nuclear decommissioning trust – debt securities (c)	—		518		—		—		518
Sub-total	$	1,245	$	683	$	176	$	110	2,214
Assets measured at net asset value (d):
Nuclear decommissioning trust – equity securities (c)									336
Total assets									$	2,550
Liabilities:
Commodity contracts	$	776	$	444	$	228	$	110	$	1,558
Interest rate swaps	—		232		—		—		232
Total liabilities	$	776	$	676	$	228	$	110	$	1,790

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December 31, 2018
	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	456	$	152	$	153	$	1	$	762
Interest rate swaps	—		77		—		—		77
Nuclear decommissioning trust – equity securities (c)	449		—		—		—		449
Nuclear decommissioning trust – debt securities (c)	—		443		—		—		443
Sub-total	$	905	$	672	$	153	$	1	1,731
Assets measured at net asset value (d):
Nuclear decommissioning trust – equity securities (c)									278
Total assets									$	2,009
Liabilities:
Commodity contracts	$	557	$	766	$	288	$	1	$	1,612
Interest rate swaps	—		34		—		—		34
Total liabilities	$	557	$	800	$	288	$	1	$	1,646

____________


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


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


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


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

Commodity contracts consist primarily of natural gas, electricity, coal and emissions agreements and include financial instruments entered into for economic hedging purposes as well as physical contracts that have not been designated as 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 16 for further discussion regarding derivative instruments.

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

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The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations at September 30, 2019 and December 31, 2018:



September 30, 2019
	Fair Value
Contract Type (a)	Assets		Liabilities			Total			Valuation Technique	Significant Unobservable Input	Range (b)
Electricity purchases and sales	$	55	$	(52	)	$	3		Valuation Model	Hourly price curve shape (c)	$	—		to	$110
Electricity purchases and sales									Valuation Model	Hourly price curve shape (c)	MWh
										Illiquid delivery periods for hub power prices and heat rates (d)	$	20		to	$120
											MWh
Electricity and weather options	2		(128		)	(126		)	Option Pricing Model	Gas to power correlation (e)	10		%	to	100%
Electricity and weather options									Option Pricing Model	Power volatility (e)	5		%	to	440%
Financial transmission rights	102		(17		)	85			Market Approach (f)	Illiquid price differences between settlement points (g)	$	(5	)	to	$10
Financial transmission rights									Market Approach (f)	Illiquid price differences between settlement points (g)	MWh
Other (h)	17		(31		)	(14		)
Total	$	176	$	(228	)	$	(52	)



December 31, 2018
	Fair Value
Contract Type (a)	Assets		Liabilities			Total			Valuation Technique	Significant Unobservable Input	Range (b)
Electricity purchases and sales	$	22	$	(48	)	$	(26	)	Valuation Model	Hourly price curve shape (c)	$	—		to	$110
Electricity purchases and sales									Valuation Model	Hourly price curve shape (c)	MWh
										Illiquid delivery periods for ERCOT hub power prices and heat rates (d)	$	20		to	$120
											MWh
Electricity and weather options	31		(192		)	(161		)	Option Pricing Model	Gas to power correlation (e)	15		%	to	95%
Electricity and weather options									Option Pricing Model	Power volatility (e)	5		%	to	435%
Financial transmission rights	85		(20		)	65			Market Approach (f)	Illiquid price differences between settlement points (g)	$	(10	)	to	$50
Financial transmission rights									Market Approach (f)	Illiquid price differences between settlement points (g)	MWh
Other (h)	15		(28		)	(13		)
Total	$	153	$	(288	)	$	(135	)

____________

(a)

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


(b)	The range of the inputs may be influenced by factors such as time of day, delivery period, season and location.


(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)	Based on historical forward correlation and volatility within ERCOT.


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


(g)	Primarily based on the auction price that reflects the difference in power prices at two locations.


(h)	Other includes contracts for natural gas, coal options and emissions.

There were no transfers between Level 1 and Level 2 of the fair value hierarchy for the three and nine months ended September 30, 2019 and 2018. See the table below for discussion of transfers between Level 2 and Level 3 for the three and nine months ended September 30, 2019 and 2018.

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The following table presents the changes in fair value of the Level 3 assets and liabilities for the three and nine months ended September 30, 2019 and 2018.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Net asset (liability) balance at beginning of period	$	4		$	(222	)	$	(135	)	$	(53	)
Total unrealized valuation gains (losses)	(112		)	(102		)	13			(333		)
Purchases, issuances and settlements (a):
Purchases	28			41			107			99
Issuances	(4		)	(14		)	(21		)	(22		)
Settlements	8			58			(34		)	104
Transfers into Level 3 (b)	1			1			7			3
Transfers out of Level 3 (b)	23			(6		)	11			(5		)
Net liabilities assumed in connection with the Merger	—			—			—			(37		)
Net change (c)	(56		)	(22		)	83			(191		)
Net liability balance at end of period	$	(52	)	$	(244	)	$	(52	)	$	(244	)
Unrealized valuation losses relating to instruments held at end of period	$	(79	)	$	(120	)	$	(56	)	$	(273	)

____________


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


(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 nine months ended September 30, 2019, transfers out of Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become observable.


(c)	Activity excludes change in fair value in the month positions settle. Substantially all changes in values of commodity contracts (excluding the net liabilities assumed in connection with the Merger) are reported as operating revenues in our condensed statements of consolidated income.


16.	COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Strategic Use of Derivatives

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

Commodity Hedging and Trading Activity — We utilize natural gas and electricity derivatives to reduce exposure to changes in electricity prices primarily to hedge future revenues from electricity sales from our generation assets and, in limited circumstances, 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, 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 statements of consolidated income 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 statements of consolidated income in interest expense and related charges.

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Financial Statement Effects of Derivatives

Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of derivative contractual assets and liabilities as reported in our condensed consolidated balance sheets at September 30, 2019 and December 31, 2018. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract.



	September 30, 2019
	Derivative Assets					Derivative Liabilities
	Commodity Contracts			Interest Rate Swaps		Commodity Contracts			Interest Rate Swaps			Total
Current assets	$	988		$	—	$	11		$	—		$	999
Noncurrent assets	102			—		79			—			181
Current liabilities	—			—		(1,350		)	(14		)	(1,364		)
Noncurrent liabilities	(20		)	—		(188		)	(218		)	(426		)
Net assets (liabilities)	$	1,070		$	—	$	(1,448	)	$	(232	)	$	(610	)



	December 31, 2018
	Derivative Assets				Derivative Liabilities
	Commodity Contracts		Interest Rate Swaps		Commodity Contracts			Interest Rate Swaps			Total
Current assets	$	707	$	22	$	1		$	—		$	730
Noncurrent assets	54		55		—			—			109
Current liabilities	—		—		(1,374		)	(2		)	(1,376		)
Noncurrent liabilities	—		—		(238		)	(32		)	(270		)
Net assets (liabilities)	$	761	$	77	$	(1,611	)	$	(34	)	$	(807	)

At September 30, 2019 and December 31, 2018, there were no derivative positions accounted for as cash flow or fair value hedges.

The following table presents the pretax 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 statements of consolidated income presentation)	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Commodity contracts (Operating revenues)	$	(482	)	$	(278	)	$	295		$	(655	)
Commodity contracts (Fuel, purchased power costs and delivery fees)	6			21			9			32
Interest rate swaps (Interest expense and related charges)	(74		)	38			(257		)	115
Net gain (loss)	$	(550	)	$	(219	)	$	47		$	(508	)

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.

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



	September 30, 2019											December 31, 2018
	Derivative Assets and Liabilities			Offsetting Instruments (a)			Cash Collateral (Received) Pledged (b)		Net Amounts			Derivative Assets and Liabilities			Offsetting Instruments (a)			Cash Collateral (Received) Pledged (b)			Net Amounts
Derivative assets:
Commodity contracts	$	1,070		$	(877	)	$	—	$	193		$	761		$	(593	)	$	(1	)	$	167
Interest rate swaps	—			—			—		—			77			(26		)	—			51
Total derivative assets	1,070			(877		)	—		193			838			(619		)	(1		)	218
Derivative liabilities:
Commodity contracts	(1,448		)	877			62		(509		)	(1,611		)	593			109			(909		)
Interest rate swaps	(232		)	—			—		(232		)	(34		)	26			—			(8		)
Total derivative liabilities	(1,680		)	877			62		(741		)	(1,645		)	619			109			(917		)
Net amounts	$	(610	)	$	—		$	62	$	(548	)	$	(807	)	$	—		$	108		$	(699	)

____________


(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.

Derivative Volumes

The following table presents the gross notional amounts of derivative volumes at September 30, 2019 and December 31, 2018:



	September 30, 2019		December 31, 2018
Derivative type	Notional Volume				Unit of Measure
Natural gas (a)	6,328		7,011		Million MMBtu
Electricity	403,218		317,572		GWh
Financial Transmission Rights (b)	207,831		172,611		GWh
Coal	23		45		Million U.S. tons
Fuel oil	48		60		Million gallons
Uranium	29		50		Thousand pounds
Emissions	39		10		Million tons
Renewable energy certificates	7		—		Million certificates
Interest rate swaps – floating/fixed (c)	$	6,720	$	7,717	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 ISOs or RTOs.


(c)	Includes notional amounts of interest rate swaps with maturity dates through July 2026. See Note 11 for termination of interest rate swaps.

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:



	September 30, 2019			December 31, 2018
Fair value of derivative contract liabilities (a)	$	(659	)	$	(856	)
Offsetting fair value under netting arrangements (b)	157			218
Cash collateral and letters of credit	60			190
Liquidity exposure	$	(442	)	$	(448	)

____________


(a)	Excludes fair value of contracts that contain contingent features that do not provide specific amounts to be posted if features are triggered, including provisions that generally provide the right to request additional collateral (material adverse change, performance assurance and other clauses).


(b)	Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master netting arrangements.

Concentrations of Credit Risk Related to Derivatives

We have concentrations of credit risk with the counterparties to our derivative contracts. At September 30, 2019, total credit risk exposure to all counterparties related to derivative contracts totaled $1.256 billion (including associated accounts receivable). The net exposure to those counterparties totaled $269 million at September 30, 2019, after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $96 million. At September 30, 2019, the credit risk exposure to the banking and financial sector represented 69% of the total credit risk exposure and 19% of the net exposure.

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

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


17.	RELATED PARTY TRANSACTIONS

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

Registration Rights Agreement

Pursuant to the Plan of Reorganization, on the Effective Date, we entered into a Registration Rights Agreement (the Registration Rights Agreement) with certain selling stockholders providing for registration of the resale of the Vistra Energy common stock held by such selling stockholders.

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


•	if we propose to file certain types of registration statements under the Securities Act with respect to an offering of equity securities, we will be required to use our reasonable best efforts to offer the other parties to the Registration Rights Agreement the opportunity to register all or part of their shares on the terms and conditions set forth in the Registration Rights Agreement; and

•

the selling stockholders received the right, subject to certain conditions and exceptions, to request that we file registration statements or amend or supplement registration statements, with the SEC for an underwritten offering of all or part of their respective shares of Vistra Energy 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 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 Energy on behalf of the selling stockholders totaled less than $1 million during both the three and nine months ended September 30, 2019 and 2018.

Tax Receivable Agreement

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


18.	SEGMENT INFORMATION

The operations of Vistra Energy are aligned into six reportable business segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv) NY/NE, (v) MISO and (vi) Asset Closure. Our chief operating decision maker reviews the results of these segments separately and allocates resources to the respective segments as part of our strategic operations.

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 and Value Based Brands in Texas, Dynegy Energy Services in Massachusetts, Ohio, Illinois and Pennsylvania, Homefield Energy in Illinois, TriEagle Energy in Texas, Pennsylvania and New Jersey, U.S. Gas & Electric in Connecticut, Illinois, Kentucky, Maryland, Massachusetts, Michigan, New Jersey, New York, Ohio, Pennsylvania and Washington D.C. and Public Power in Connecticut, Illinois, Maryland, Massachusetts, New York, Ohio, Pennsylvania, Rhode Island and Washington D.C.

The ERCOT, PJM, NY/NE (comprising NYISO and ISO-NE) and MISO segments are engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel production and fuel logistics management, all largely within their respective RTO/ISO market. The PJM, NY/NE and MISO segments were established on the Merger Date to reflect markets served by businesses acquired in the Merger.

The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines (see Note 4). Separately reporting the Asset Closure segment provides management with better information related to the performance and earnings power of Vistra Energy'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 commodity risk management activities to the Asset Closure segment for the generation plants that were retired in 2018 and 2019.

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.

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Except as noted in Note 1, 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 uses more than one measure to assess segment performance, including segment net income (loss), which is the measure most comparable to consolidated net income (loss) prepared based on U.S. GAAP. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at market prices. Certain shared services costs are allocated to the segments.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Operating revenues (a)
Retail	$	2,207		$	1,813		$	5,014		$	4,239
ERCOT	731			1,396			3,356			2,190
PJM	443			620			1,833			1,104
NY/NE	214			301			813			487
MISO	197			230			697			488
Asset Closure	—			(1		)	—			48
Corporate and Other (b)	95			91			259			123
Eliminations	(693		)	(1,207		)	(3,023		)	(2,098		)
Consolidated operating revenues	$	3,194		$	3,243		$	8,949		$	6,581
Depreciation and amortization
Retail	$	(86	)	$	(80	)	$	(204	)	$	(237	)
ERCOT	(126		)	(122		)	(385		)	(295		)
PJM	(135		)	(141		)	(399		)	(266		)
NY/NE	(51		)	(55		)	(155		)	(104		)
MISO	(5		)	(3		)	(11		)	(6		)
Asset Closure	—			—			—			—
Corporate and Other (b)	(21		)	(25		)	(59		)	(60		)
Eliminations	—			—			—			1
Consolidated depreciation and amortization	$	(424	)	$	(426	)	$	(1,213	)	$	(967	)
Operating income (loss)
Retail (c)	$	581		$	(83	)	$	19		$	371
ERCOT	(11		)	643			1,324			234
PJM	(61		)	61			287			85
NY/NE	20			45			115			36
MISO	(85		)	(2		)	(40		)	30
Asset Closure	(9		)	(4		)	(39		)	(26		)
Corporate and Other (b)	5			(8		)	(7		)	(244		)
Eliminations	—			(2		)	—			(1		)
Consolidated operating income	$	440		$	650		$	1,659		$	485
Net income (loss)
Retail (c)	$	573		$	(86	)	$	3		$	397
ERCOT	(10		)	643			1,346			236
PJM	(62		)	62			283			86
NY/NE	21			47			122			41
MISO	(88		)	(3		)	(42		)	29
Asset Closure	(8		)	(4		)	(37		)	(24		)
Corporate and Other (b)	(312		)	(328		)	(983		)	(635		)
Consolidated net income	$	114		$	331		$	692		$	130

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____________


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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Retail	$	3		$	(24	)	$	8		$	(11	)
ERCOT	(681		)	192			606			(207		)
PJM	(128		)	(28		)	147			(38		)
NY/NE	(12		)	(7		)	20			(32		)
MISO	(48		)	(34		)	(2		)	(4		)
Corporate and Other (b)	22			3			42			4
Eliminations (1)	758			(130		)	(210		)	49
Consolidated unrealized net gains (losses) from mark-to-market valuations of commodity positions included in operating revenues	$	(86	)	$	(28	)	$	611		$	(239	)

____________


(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.

(c)

For the three months ended September 30, 2019, Retail operating income and net income is driven by unrealized gains from mark-to-market valuations of commodity positions included in fuel, purchased power costs and delivery fees. For the nine months ended September 30, 2018, Retail operating income and net income is driven by unrealized gains from mark-to-market valuations of commodity positions included in fuel, purchased power costs and delivery fees.



	September 30, 2019			December 31, 2018
Total assets
Retail	$	9,372		$	7,699
ERCOT	10,090			9,347
PJM	5,362			7,188
NY/NE	2,841			2,722
MISO	401			836
Asset Closure	253			254
Corporate and Other and Eliminations	(1,876		)	(2,022		)
Consolidated total assets	$	26,443		$	26,024


19.	SUPPLEMENTARY FINANCIAL INFORMATION

Pension and OPEB Plans — Components of Net Benefit Cost

For the three and nine months ended September 30, 2019 and 2018, net periodic benefit costs consisted of the following:



	Pension Benefits										OPEB Benefits
	Three Months Ended September 30,					Nine Months Ended September 30,					Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018			2019		2018			2019		2018		2019		2018
Service cost	$	1	$	5		$	5	$	10		$	1	$	1	$	1	$	2
Other costs	1		(1		)	1		(1		)	3		1		7		3
Net periodic benefit cost	$	2	$	4		$	6	$	9		$	4	$	2	$	8	$	5

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Interest Expense and Related Charges



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Interest paid/accrued	$	140		$	164		$	445		$	380
Unrealized mark-to-market net (gains) losses on interest rate swaps	76			(38		)	275			(123		)
Amortization of debt issuance costs, discounts and premiums	4			—			2			4
Debt extinguishment (gain) loss	(2		)	27			(12		)	27
Capitalized interest	(2		)	(3		)	(9		)	(10		)
Other	8			4			19			13
Total interest expense and related charges	$	224		$	154		$	720		$	291

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 11, was 4.02% at September 30, 2019.

Other Income and Deductions



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Other income:
Office space sublease rental income (a)	$	—	$	2	$	—	$	6
Insurance settlement (b)	—		—		19		—
Funds released from escrow to settle pre-petition claims of our predecessor	—		—		9		—
Sale of land (b)	—		—		—		1
Interest income	2		3		9		14
All other	4		1		8		4
Total other income	$	6	$	6	$	45	$	25
Other deductions:
Curtailment expense (Note 4) (c)	$	3	$	—	$	3	$	—
All other	1		1		6		4
Total other deductions	$	4	$	1	$	9	$	4

____________


(a)	Reported in Corporate and Other non-segment. Beginning January 1, 2019, our sublease rental income related to real estate leases is reported in selling, general and administrative expenses in the condensed statements of consolidated income.


(b)	Reported in ERCOT segment.


(c)	Reported in MISO segment.

Restricted Cash



	September 30, 2019		December 31, 2018
	Current Assets
Amounts related to restructuring escrow accounts	$	43	$	57
Other	3		—
Total restricted cash	$	46	$	57

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Trade Accounts Receivable



	September 30, 2019			December 31, 2018
Wholesale and retail trade accounts receivable	$	1,451		$	1,106
Allowance for uncollectible accounts	(32		)	(19		)
Trade accounts receivable — net (a)	$	1,419		$	1,087

____________


(a)	At September 30, 2019, includes $136 million of trade accounts receivable related to operations acquired in the Crius Transaction.

Gross trade accounts receivable at September 30, 2019 and December 31, 2018 included unbilled retail revenues of $467 million and $350 million, respectively.

Allowance for Uncollectible Accounts Receivable



	Nine Months Ended September 30,
	2019			2018
Allowance for uncollectible accounts receivable at beginning of period	$	19		$	14
Increase for bad debt expense	56			41
Decrease for account write-offs	(43		)	(30		)
Allowance for uncollectible accounts receivable at end of period	$	32		$	25

Inventories by Major Category



	September 30, 2019		December 31, 2018
Materials and supplies	$	280	$	286
Fuel stock	136		115
Natural gas in storage	14		11
Total inventories	$	430	$	412

Investments



	September 30, 2019		December 31, 2018
Nuclear plant decommissioning trust	$	1,370	$	1,170
Assets related to employee benefit plans	32		31
Land	49		49
Total investments	$	1,451	$	1,250

Investment in Unconsolidated Subsidiaries

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 September 30, 2019, our investment in NELP totaled $123 million. Our risk of loss related to our equity method investment is limited to our investment balance.

Equity earnings related to our investment in NELP totaled $2 million and $7 million for the three months ended September 30, 2019 and 2018, respectively, and $11 million and $11 million for the nine months ended September 30, 2019 and 2018, respectively, recorded in equity in earnings (loss) of unconsolidated investment in our condensed statements of consolidated net income (loss). We received distributions totaling $5 million and $7 million for the three months ended September 30, 2019 and 2018, respectively, and $19 million and $13 million for the nine months ended September 30, 2019 and 2018, respectively.

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Nuclear Decommissioning Trust

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



	September 30, 2019
	Cost (a)		Unrealized gain		Unrealized loss		Fair market value
Debt securities (b)	$	489	$	29	$	—	$	518
Equity securities (c)	275		577		—		852
Total	$	764	$	606	$	—	$	1,370



	December 31, 2018
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	444	$	7	$	(8	)	$	443
Equity securities (c)	280		448		(1		)	727
Total	$	724	$	455	$	(9	)	$	1,170

____________


(a)	Includes realized gains and losses on securities sold.

(b)

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 3.43% and 3.69% at September 30, 2019 and December 31, 2018, respectively, and an average maturity of nine years and eight years at September 30, 2019 and December 31, 2018, respectively.


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

Debt securities held at September 30, 2019 mature as follows: $174 million in one to five years, $142 million in five to 10 years and $202 million after 10 years.

The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from such sales.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Realized gains	$	1		$	(1	)	$	11		$	—
Realized losses	$	(1	)	$	1		$	(4	)	$	(2	)
Proceeds from sales of securities	$	62		$	118		$	354		$	211
Investments in securities	$	(68	)	$	(124	)	$	(370	)	$	(227	)

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Property, Plant and Equipment



	September 30, 2019			December 31, 2018
Power generation and structures	$	15,070		$	14,604
Land	637			642
Office and other equipment	160			182
Total	15,867			15,428
Less accumulated depreciation	(2,241		)	(1,284		)
Net of accumulated depreciation	13,626			14,144
Finance lease right-of-use assets	70			—
Nuclear fuel (net of accumulated amortization of $196 million and $189 million)	180			191
Construction work in progress	199			277
Property, plant and equipment — net	$	14,075		$	14,612

Depreciation expenses totaled $325 million and $342 million for the three months ended September 30, 2019 and 2018, respectively, and $973 million and $701 million for nine months ended September 30, 2019 and 2018, respectively.

Asset Retirement and Mining Reclamation Obligations (ARO)

These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of coal/lignite fueled plant ash treatment facilities 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.

At September 30, 2019, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.309 billion, which is lower than the fair value of the assets contained in the nuclear decommissioning trust. Since the costs to ultimately decommission that plant are recoverable through the regulatory rate making process as part of Oncor's delivery fees, a corresponding regulatory liability has been recorded to our condensed consolidated balance sheet of $61 million in other noncurrent liabilities and deferred credits.

The following tables summarize the changes to these obligations, reported as asset retirement obligations (current and noncurrent liabilities) in our condensed consolidated balance sheets, for the nine months ended September 30, 2019 and 2018.



	Nuclear Plant Decommissioning		Mining Land Reclamation			Coal Ash and Other			Total
Liability at December 31, 2018	$	1,276	$	442		$	655		$	2,373
Additions:
Accretion	33		17			23			73
Adjustment for change in estimates	—		12			(17		)	(5		)
Adjustment for obligations assumed through acquisitions	—		—			(3		)	(3		)
Reductions:
Payments	—		(54		)	(26		)	(80		)
Liability transfer (a)	—		—			(34		)	(34		)
Liability at September 30, 2019	1,309		417			598			2,324
Less amounts due currently	—		(105		)	(62		)	(167		)
Noncurrent liability at September 30, 2019	$	1,309	$	312		$	536		$	2,157

____________


(a)	Represents ARO transferred to a third-party for remediation. Any remaining unpaid third-party obligation has been reclassified to other current and noncurrent liabilities in our condensed consolidated balance sheets.

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	Nuclear Plant Decommissioning		Mining Land Reclamation			Coal Ash and Other			Total
Liability at December 31, 2017	$	1,233	$	438		$	265		$	1,936
Additions:
Accretion	32		16			20			68
Adjustment for change in estimates	—		7			(47		)	(40		)
Obligations assumed in the Merger	—		2			424			426
Reductions:
Payments	—		(57		)	(11		)	(68		)
Liability at September 30, 2018	$	1,265	$	406		$	651		$	2,322
Less amounts due currently	—		(124		)	(59		)	(183		)
Noncurrent liability at September 30, 2018	$	1,265	$	282		$	592		$	2,139

Other Noncurrent Liabilities and Deferred Credits

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



	September 30, 2019		December 31, 2018
Retirement and other employee benefits	$	296	$	270
Finance lease liabilities	88		—
Uncertain tax positions, including accrued interest	6		4
Other	148		66
Total other noncurrent liabilities and deferred credits	$	538	$	340

Fair Value of Debt



		September 30, 2019				December 31, 2018
Long-term debt (see Note 11):	Fair Value Hierarchy	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt under the Vistra Operations Credit Facilities	Level 2	$	3,808	$	3,812	$	5,820	$	5,599
Vistra Operations Senior Notes	Level 2	5,530		5,779		987		963
Vistra Energy Senior Notes	Level 2	1,188		1,176		3,819		3,765
7.000% Amortizing Notes	Level 2	—		—		23		24
Forward Capacity Agreements	Level 3	184		184		221		221
Equipment Financing Agreements	Level 3	99		99		102		102
Mandatorily redeemable subsidiary preferred stock	Level 2	70		70		70		70
Building Financing	Level 2	17		16		23		21
9.5% Promissory Notes	Level 3	44		44		—		—
2% Term Loan	Level 3	8		8		—		—

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

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Supplemental Cash Flow Information

The following table reconciles cash, cash equivalents and restricted cash reported in our condensed statements of consolidated cash flows to the amounts reported in our condensed balance sheets at September 30, 2019 and December 31, 2018:



	September 30, 2019		December 31, 2018
Cash and cash equivalents	$	707	$	636
Restricted cash included in current assets	46		57
Total cash, cash equivalents and restricted cash	$	753	$	693

The following table summarizes our supplemental cash flow information for the nine months ended September 30, 2019 and 2018:



	Nine Months Ended September 30,
	2019			2018
Cash payments related to:
Interest paid	$	444		$	662
Capitalized interest	(9		)	(10		)
Interest paid (net of capitalized interest)	$	435		$	652
Income taxes (a)	$	19		$	66
Noncash investing and financing activities:
Construction expenditures (b)	$	43		$	58
Shares issued for tangible equity unit contracts (Note 14)	$	446		$	—
Vistra Energy common stock issued in the Merger (Notes 2 and 14)	$	—		$	2,245

____________


(a)	Income tax payments are net of tax refunds of $21 million in the nine months ended September 30, 2019.


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

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20.	SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Our senior unsecured notes are guaranteed by substantially all of our wholly owned subsidiaries. The following condensed consolidating financial statements present the financial information of (i) Vistra Energy Corp. (Parent), which is the ultimate parent company and issuer of the senior notes with effect as of the Merger Date, on a stand-alone, unconsolidated basis, (ii) the guarantor subsidiaries of Vistra Energy (Guarantor Subsidiaries), (iii) the non-guarantor subsidiaries of Vistra Energy (Non-Guarantor Subsidiaries) and (iv) the eliminations necessary to arrive at the information for Vistra Energy on a consolidated basis. 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 for discussion of the senior notes.

These statements should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto of Vistra Energy. The supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements. The inclusion of Vistra Energy's subsidiaries as either Guarantor Subsidiaries or Non-Guarantor Subsidiaries in the condensed consolidating 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 have been allocated to the respective subsidiary columns in accordance with the accounting rules that apply to separate financial statements of subsidiaries.

Vistra Energy Corp. (Parent) received $3.465 billion in dividends from its consolidated subsidiaries in the nine months ended September 30, 2019.

Condensed Statements of Consolidating Income (Loss) for the Three Months Ended September 30, 2019

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues	$	—		$	3,026		$	310		$	(142	)	$	3,194
Fuel, purchased power costs and delivery fees	—			(1,510		)	(212		)	35			(1,687		)
Operating costs	—			(378		)	(19		)	—			(397		)
Depreciation and amortization	(2		)	(376		)	(46		)	—			(424		)
Selling, general and administrative expenses	(16		)	(270		)	(50		)	90			(246		)
Operating income (loss)	(18		)	492			(17		)	(17		)	440
Other income	(2		)	6			—			2			6
Other deductions	—			(4		)	—			—			(4		)
Interest expense and related charges	(12		)	(200		)	(11		)	(1		)	(224		)
Impacts of Tax Receivable Agreement	(62		)	—			—			—			(62		)
Equity in earnings of unconsolidated investment	—			3			—			—			3
Income (loss) before income taxes	(94		)	297			(28		)	(16		)	159
Income tax benefit (expense)	22			(82		)	(1		)	16			(45		)
Equity in earnings (loss) of subsidiaries, net of tax	185			(30		)	—			(155		)	—
Net income (loss)	113			185			(29		)	(155		)	114
Net loss attributable to noncontrolling interest	—			—			(1		)	—			(1		)
Net income (loss) attributable to Vistra Energy	$	113		$	185		$	(30	)	$	(155	)	$	113

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Condensed Statements of Consolidating Income (Loss) for the Three Months Ended September 30, 2018

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues	$	—		$	3,208		$	59		$	(24	)	$	3,243
Fuel, purchased power costs and delivery fees	—			(1,590		)	(37		)	—			(1,627		)
Operating costs	—			(334		)	(12		)	—			(346		)
Depreciation and amortization	—			(402		)	(24		)	—			(426		)
Selling, general and administrative expenses	(23		)	(165		)	(30		)	24			(194		)
Operating income (loss)	(23		)	717			(44		)	—			650
Other income	1			7			—			(2		)	6
Other deductions	—			(1		)	—			—			(1		)
Interest expense and related charges	(110		)	(43		)	(3		)	2			(154		)
Impacts of Tax Receivable Agreement	17			—			—			—			17
Equity in earnings of unconsolidated investment	—			7			—			—			7
Income (loss) before income taxes	(115		)	687			(47		)	—			525
Income tax benefit (expense)	42			(251		)	15			—			(194		)
Equity in earnings (loss) of subsidiaries, net of tax	403			(33		)	—			(370		)	—
Net income (loss)	330			403			(32		)	(370		)	331
Net loss attributable to noncontrolling interest	—			—			(1		)	—			(1		)
Net income (loss) attributable to Vistra Energy	$	330		$	403		$	(33	)	$	(370	)	$	330

Condensed Statements of Consolidating Income (Loss) for the Nine Months Ended September 30, 2019

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues	$	—		$	8,787		$	420		$	(258	)	$	8,949
Fuel, purchased power costs and delivery fees	—			(4,122		)	(260		)	95			(4,287		)
Operating costs	—			(1,105		)	(48		)	—			(1,153		)
Depreciation and amortization	(4		)	(1,121		)	(88		)	—			(1,213		)
Selling, general and administrative expenses	(47		)	(665		)	(88		)	163			(637		)
Operating income (loss)	(51		)	1,774			(64		)	—			1,659
Other income	13			37			1			(6		)	45
Other deductions	—			(9		)	—			—			(9		)
Interest expense and related charges	(84		)	(619		)	(23		)	6			(720		)
Impacts of Tax Receivable Agreement	(26		)	—			—			—			(26		)
Equity in earnings of unconsolidated investment	—			13			—			—			13
Income (loss) before income taxes	(148		)	1,196			(86		)	—			962
Income tax benefit (expense)	42			(336		)	24			—			(270		)
Equity in earnings (loss) of subsidiaries, net of tax	800			(60		)	—			(740		)	—
Net income (loss)	694			800			(62		)	(740		)	692
Net loss attributable to noncontrolling interest	—			—			2			—			2
Net income (loss) attributable to Vistra Energy	$	694		$	800		$	(60	)	$	(740	)	$	694

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Condensed Statements of Consolidating Income (Loss) for the Nine Months Ended September 30, 2018

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues	$	—		$	6,480		$	126		$	(25	)	$	6,581
Fuel, purchased power costs and delivery fees	—			(3,405		)	(89		)	2			(3,492		)
Operating costs	—			(898		)	(28		)	—			(926		)
Depreciation and amortization	—			(926		)	(41		)	—			(967		)
Selling, general and administrative expenses	(250		)	(452		)	(32		)	23			(711		)
Operating income (loss)	(250		)	799			(64		)	—			485
Other income	8			19			—			(2		)	25
Other deductions	—			(5		)	1			—			(4		)
Interest expense and related charges	(197		)	(92		)	(4		)	2			(291		)
Impacts of Tax Receivable Agreement	(65		)	—			—			—			(65		)
Equity in earnings of unconsolidated investment	—			11			—			—			11
Income (loss) before income taxes	(504		)	732			(67		)	—			161
Income tax benefit (expense)	183			(235		)	21			—			(31		)
Equity in earnings (loss) of subsidiaries, net of tax	453			(44		)	—			(409		)	—
Net income (loss)	132			453			(46		)	(409		)	130
Net loss attributable to noncontrolling interest	—			—			2			—			2
Net income (loss) attributable to Vistra Energy	$	132		$	453		$	(44	)	$	(409	)	$	132

Condensed Statements of Consolidating Comprehensive Income (Loss) for the Three Months Ended September 30, 2019

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	113		$	185	$	(29	)	$	(155	)	$	114
Other comprehensive income (loss), net of tax effects:
Effect related to pension and other retirement benefit obligations	(13		)	—		—			—			(13		)
Total other comprehensive income	(13		)	—		—			—			(13		)
Comprehensive income (loss)	100			185		(29		)	(155		)	101
Comprehensive loss attributable to noncontrolling interest	—			—		(1		)	—			(1		)
Comprehensive income (loss) attributable to Vistra Energy	$	100		$	185	$	(30	)	$	(155	)	$	100

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Condensed Statements of Consolidating Comprehensive Income (Loss) for the Three Months Ended September 30, 2018

(Millions of Dollars)



	Parent (Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	330	$	403	$	(32	)	$	(370	)	$	331
Other comprehensive income (loss), net of tax effects:
Effect related to pension and other retirement benefit obligations	—		1		—			—			1
Total other comprehensive income	—		1		—			—			1
Comprehensive income (loss)	$	330	$	404	$	(32	)	$	(370	)	$	332
Comprehensive loss attributable to noncontrolling interest	—		—		(1		)	—			(1		)
Comprehensive income (loss) attributable to Vistra Energy	$	330	$	404	$	(33	)	$	(370	)	$	331

Condensed Statements of Consolidating Comprehensive Income (Loss) for the Nine Months Ended September 30, 2019

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	694		$	800	$	(62	)	$	(740	)	$	692
Other comprehensive income (loss), net of tax effects:
Effect related to pension and other retirement benefit obligations	(12		)	—		—			—			(12		)
Total other comprehensive income	(12		)	—		—			—			(12		)
Comprehensive income (loss)	682			800		(62		)	(740		)	680
Comprehensive loss attributable to noncontrolling interest	—			—		2			—			2
Comprehensive income (loss) attributable to Vistra Energy	$	682		$	800	$	(60	)	$	(740	)	$	682

Condensed Statements of Consolidating Comprehensive Income (Loss) for the Nine Months Ended September 30, 2018

(Millions of Dollars)



	Parent (Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	132	$	453	$	(46	)	$	(409	)	$	130
Other comprehensive income (loss), net of tax effects:
Effect related to pension and other retirement benefit obligations	—		2		—			—			2
Total other comprehensive income	—		2		—			—			2
Comprehensive income (loss)	$	132	$	455	$	(46	)	$	(409	)	$	132
Comprehensive loss attributable to noncontrolling interest	—		—		2			—			2
Comprehensive income (loss) attributable to Vistra Energy	$	132	$	455	$	(44	)	$	(409	)	$	134

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Condensed Statements of Consolidating Cash Flows for the Nine Months Ended September 30, 2019

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows — operating activities:
Cash provided by (used in) operating activities	$	(130	)	$	2,084		$	(131	)	$	—		$	1,823
Cash flows — financing activities:
Issuances of long-term debt	—			4,600			—			—			4,600
Repayments/repurchases of debt	(2,516		)	(2,064		)	(88		)	—			(4,668		)
Net borrowings under accounts receivable securitization program	—			—			261						261
Cash dividends paid	(181		)	(3,465		)	—			3,465			(181		)
Stock repurchase	(632		)	—			—			—			(632		)
Debt tender offer and other financing fees	(108		)	(62		)	—			—			(170		)
Other, net	—			6			—			—			6
Cash provided by (used in) financing activities	(3,437		)	(985		)	173			3,465			(784		)
Cash flows — investing activities:
Capital expenditures, including LTSA prepayments	(23		)	(318		)	(7		)	—			(348		)
Nuclear fuel purchases	—			(33		)	—			—			(33		)
Development and growth expenditures	—			(93		)	—			—			(93		)
Crius acquisition	—			(374		)	—			—			(374		)
Proceeds from sales of nuclear decommissioning trust fund securities	—			354			—			—			354
Investments in nuclear decommissioning trust fund securities	—			(370		)	—			—			(370		)
Proceeds from sale of environmental allowances	—			32			—			—			32
Purchases of environmental allowances	—			(162		)	(7		)	—			(169		)
Dividend received from subsidiaries	3,465			—						(3,465		)	—
Other, net	—			22			—			—			22
Cash provided by (used in) investing activities	3,442			(942		)	(14		)	(3,465		)	(979		)
Net change in cash, cash equivalents and restricted cash	(125		)	157			28			—			60
Cash, cash equivalents and restricted cash — beginning balance	228			453			12			—			693
Cash, cash equivalents and restricted cash — ending balance	$	103		$	610		$	40		$	—		$	753

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Condensed Statements of Consolidating Cash Flows for the Nine Months Ended September 30, 2018

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows — operating activities:
Cash provided by (used in) operating activities	$	521		$	670		$	(328	)	$	—		$	863
Cash flows — financing activities:
Issuances of long-term debt	—			1,000			—			—			1,000
Repayments/repurchases of debt	(4,918		)	2,016			—			—			(2,902		)
Net borrowings under accounts receivable securitization program (Note 10)	—			—			350			—			350
Stock repurchase	(414		)	—			—			—			(414		)
Cash dividend paid	—			(3,928		)	—			3,928			—
Debt financing fees	(173		)	(43		)	—			—			(216		)
Other, net	10			—			—			—			10
Cash provided by (used in) financing activities	(5,495		)	(955		)	350			3,928			(2,172		)
Cash flows — investing activities:
Capital expenditures	(12		)	(191		)	(6		)	—			(209		)
Nuclear fuel purchases	—			(66		)	—			—			(66		)
Development and growth expenditures	—			(28		)	—			—			(28		)
Cash acquired in the Merger	—			445			—			—			445
Proceeds from sales of nuclear decommissioning trust fund securities	—			211			—			—			211
Investments in nuclear decommissioning trust fund securities	—			(227		)	—			—			(227		)
Proceeds from sale of environmental allowances	—			—			—			—			—
Purchases of environmental allowances	—			(4		)	—			—			(4		)
Dividend received from subsidiaries	3,928			—			—			(3,928		)	—
Other, net	—			14			(3		)	—			11
Cash provided by (used in) investing activities	3,916			154			(9		)	(3,928		)	133
Net change in cash, cash equivalents and restricted cash	(1,058		)	(131		)	13			—			(1,176		)
Cash, cash equivalents and restricted cash — beginning balance	1,183			863			—			—			2,046
Cash, cash equivalents and restricted cash — ending balance	$	125		$	732		$	13		$	—		$	870

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Condensed Consolidating Balance Sheet as of September 30, 2019 (Millions of Dollars)

	Parent (Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	61	$	606	$	40	$	—		$	707
Restricted cash	42		4		—		—			46
Advances to affiliates	—		42		—		(42		)	—
Trade accounts receivable — net	9		646		953		(189		)	1,419
Accounts receivable — affiliates	—		101		—		(101		)	—
Notes due from affiliates	—		112		—		(112		)	—
Income taxes receivable	—		—		—		—			—
Inventories	—		404		26		—			430
Commodity and other derivative contractual assets	—		988		11		—			999
Margin deposits related to commodity contracts	—		236		—		—			236
Prepaid expense and other current assets	130		142		19		—			291
Total current assets	242		3,281		1,049		(444		)	4,128
Investments	—		1,420		31		—			1,451
Investment in unconsolidated subsidiary	—		123		—		—			123
Investment in affiliated companies	8,344		556		—		(8,900		)	—
Property, plant and equipment — net	7		13,528		540		—			14,075
Operating lease right-of-use assets	—		50		—		—			50
Goodwill	—		2,082		205		—			2,287
Identifiable intangible assets — net	40		2,285		270		—			2,595
Commodity and other derivative contractual assets	—		180		1		—			181
Accumulated deferred income taxes	807		430		—		(82		)	1,155
Other noncurrent assets	132		245		18		3			398
Total assets	$	9,572	$	24,180	$	2,114	$	(9,423	)	$	26,443
LIABILITIES AND EQUITY
Current liabilities:
Accounts receivable securitization program	$	—	$	—	$	600	$	—		$	600
Advances from affiliates	—		—		42		(42		)	—
Long-term debt due currently	—		215		5		—			220
Trade accounts payable	1		811		280		(176		)	916
Accounts payable — affiliates	35		—		66		(101		)	—
Notes due to affiliates	—		—		112		(112		)	—
Commodity and other derivative contractual liabilities	—		1,348		16		—			1,364
Margin deposits related to commodity contracts	—		8		—		—			8
Accrued taxes	16		—		2		—			18
Accrued taxes other than income	—		148		4		—			152
Accrued interest	25		65		9		(11		)	88
Asset retirement obligations	—		167		—		—			167
Operating lease liabilities	—		11		1		—			12
Other current liabilities	50		299		21		—			370
Total current liabilities	127		3,072		1,158		(442		)	3,915

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Condensed Consolidating Balance Sheet as of September 30, 2019 (Millions of Dollars)

	Parent (Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Long-term debt, less amounts due currently	1,188		9,458		82		—			10,728
Operating lease liabilities	—		52		1		—			53
Commodity and other derivative contractual liabilities	—		416		10		—			426
Accumulated deferred income taxes	—		—		91		(81		)	10
Tax Receivable Agreement obligation	443		—		—		—			443
Asset retirement obligations	—		2,143		14		—			2,157
Identifiable intangible liabilities — net	—		215		166		—			381
Other noncurrent liabilities and deferred credits	22		480		36		—			538
Total liabilities	1,780		15,836		1,558		(523		)	18,651
Total stockholders' equity	7,792		8,344		556		(8,900		)	7,792
Noncontrolling interest in subsidiary	—		—		—		—			—
Total liabilities and equity	$	9,572	$	24,180	$	2,114	$	(9,423	)	$	26,443

Condensed Consolidating Balance Sheet as of December 31, 2018 (Millions of Dollars)

	Parent (Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	171	$	453	$	12	$	—		$	636
Restricted cash	57		—		—		—			57
Advances to affiliates	11		11		—		(22		)	—
Trade accounts receivable — net	4		729		464		(110		)	1,087
Accounts receivable - affiliates	—		245		—		(245		)	—
Notes due from affiliates	—		101		—		(101		)	—
Income taxes receivable	—		1		—		(1		)	—
Inventories	—		391		21		—			412
Commodity and other derivative contractual assets	—		730		—		—			730
Margin deposits related to commodity contracts	—		361		—		—			361
Prepaid expense and other current assets	2		134		16		—			152
Total current assets	245		3,156		513		(479		)	3,435
Investments	—		1,218		32		—			1,250
Investments in unconsolidated subsidiary	—		131		—		—			131
Investment in affiliated companies	11,186		263		—		(11,449		)	—
Property, plant and equipment — net	15		14,017		580		—			14,612
Goodwill	—		2,068		—		—			2,068
Identifiable intangible assets — net	10		2,480		3		—			2,493
Commodity and other derivative contractual assets	—		109		—		—			109
Accumulated deferred income taxes	809		599		—		(72		)	1,336
Other noncurrent assets	255		330		5		—			590
Total assets	$	12,520	$	24,371	$	1,133	$	(12,000	)	$	26,024

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Condensed Consolidating Balance Sheet as of December 31, 2018 (Millions of Dollars)

	Parent (Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
LIABILITIES AND EQUITY
Current liabilities:
Accounts receivable securitization program	$	—	$	—	$	339	$	—		$	339
Advances from affiliates	—		—		22		(22		)	—
Long-term debt due currently	23		163		5		—			191
Trade accounts payable	2		928		121		(106		)	945
Accounts payable - affiliates	236		—		9		(245		)	—
Notes due to affiliates	—		—		101		(101		)	—
Commodity and other derivative contractual liabilities	—		1,376		—		—			1,376
Margin deposits related to commodity contracts	—		4		—		—			4
Accrued income taxes	11		—		—		(1		)	10
Accrued taxes other than income	—		181		1		—			182
Accrued interest	48		29		4		(4		)	77
Asset retirement obligations	—		156		—		—			156
Other current liabilities	74		267		4		—			345
Total current liabilities	394		3,104		606		(479		)	3,625
Long-term debt, less amounts due currently	3,819		7,027		28		—			10,874
Commodity and other derivative contractual liabilities	—		270		—		—			270
Accumulated deferred income taxes	—		—		82		(72		)	10
Tax Receivable Agreement obligation	420		—		—		—			420
Asset retirement obligations	—		2,203		14		—			2,217
Identifiable intangible liabilities — net	—		278		123		—			401
Other noncurrent liabilities and deferred credits	20		303		17		—			340
Total liabilities	4,653		13,185		870		(551		)	18,157
Total stockholders' equity	7,867		11,186		259		(11,449		)	7,863
Noncontrolling interest in subsidiary	—		—		4		—			4
Total liabilities and equity	$	12,520	$	24,371	$	1,133	$	(12,000	)	$	26,024

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

The following discussion and analysis of our financial condition and results of operations for the three and nine months ended September 30, 2019 and 2018 should be read in conjunction with our condensed consolidated financial statements and the notes to those statements.

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

Business

Vistra Energy is a holding company operating an integrated power business 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.

Operating Segments

Vistra Energy has six reportable segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv) NY/NE (comprising NYISO and ISO-NE), (v) MISO and (vi) Asset Closure. The PJM, NY/NE and MISO segments were established on the Merger Date to reflect markets served by businesses acquired in the Merger. See Note 18 to the Financial Statements for further information concerning reportable business segments.

Significant Activities and Events and Items Influencing Future Performance

Ambit Transaction

On November 1, 2019 (Ambit Acquisition Date), Volt Asset Company, Inc., an indirect, wholly owned subsidiary of Vistra Energy, completed the acquisition of Ambit (Ambit Transaction). Vistra Energy funded the purchase price of $475 million plus Ambit's outstanding net working capital using cash on hand. See Note 2 to the Financial Statements for further information concerning the Ambit Transaction.

Crius Transaction

On July 15, 2019, Vienna Acquisition B.C. Ltd., an indirect, wholly owned subsidiary of Vistra Energy, completed the acquisition of the equity interests of two wholly owned subsidiaries of Crius that indirectly own the operating business of Crius (Crius Transaction). Vistra Energy funded the purchase price of approximately $400 million (including $382 million for outstanding trust units) using cash on hand. See Note 2 to the Financial Statements for a summary of the Crius Transaction and business combination accounting.

Dynegy Merger Transaction

See Note 2 to the Financial Statements for a summary of the Merger transaction and business combination accounting.

Acquisition, Development and Disposition of Generation Facilities

See Note 3 to the Financial Statements for a summary of our solar generation and battery energy storage projects. See Note 4 to the Financial Statements for a summary of our generation plant retirements in 2018 and 2019.

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Dividend Program

In November 2018, Vistra Energy announced that the Board had adopted a dividend program pursuant to which Vistra Energy would initiate an annual dividend of approximately $0.50 per share, beginning in the first quarter of 2019. In February 2019, May 2019 and July 2019, the Board declared quarterly dividends of $0.125 per share that were paid in March 2019, June 2019 and September 2019, respectively.

Share Repurchase Program

In June 2018, we announced that the Board had authorized a share repurchase program under which up to $500 million of our outstanding common stock may be repurchased. In November 2018, we announced that the Board had authorized an incremental share repurchase program under which up to $1.25 billion of our outstanding stock may be purchased. Shares of the Company's common stock may be repurchased in open market transactions at prevailing market prices, in privately negotiated transactions or by other means in accordance 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 the market price of our stock, general market and economic conditions, applicable legal requirements and compliance with the terms of our debt agreements and the Tax Matters Agreement. See Note 14 to the Financial Statements for more information concerning the share repurchase program, including shares repurchased and remaining amounts available under the program.

Debt Activity

We have stated our objective is to reduce our consolidated net leverage from current levels to approximately 2.5x net debt/EBITDA. 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 the second quarter of 2019, we completed several transactions that we believe, in the aggregate, advanced all of these goals. While the premiums, fees and expenses that we paid in connection with these transactions resulted in an increase in our total debt as of September 30, 2019 relative to March 31, 2019, we expect the ongoing free cash flow savings will offset this increase over the next few years. See Note 11 to the Financial Statements for details of our long-term debt activity and Note 10 to the Financial Statements for details of the accounts receivable securitization program.

Power Price and Natural Gas Price Exposure

Estimated hedging levels for generation volumes in ERCOT, PJM, NYISO, ISO-NE, MISO and CAISO at September 30, 2019 were as follows:



	2019		2020
Coal/Nuclear/Renewable Generation:
ERCOT	100	%	100	%
PJM	100	%	92	%
MISO	95	%	98	%
Gas Generation:
ERCOT	94	%	59	%
PJM	95	%	65	%
NYISO/ISO-NE	100	%	78	%
CAISO	98	%	83	%

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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 MWh/MMBtu) on realized pretax earnings (in millions) taking into account the hedge positions noted above for the periods presented. The residual gas position is calculated based on two steps: first, calculating the difference between actual heat rates of our natural gas generation units and the assumed 7.2 heat rate used to calculate the sensitivity to spark spreads; and second, calculating the residual natural gas exposure that is not already included in the gas generation spark spread sensitivity shown in the table below. The estimates related to price sensitivity are based on our expected generation, related hedges and forward prices as of September 30, 2019.



	Balance 2019 (a)			2020
ERCOT:
Coal/Nuclear/Renewable Generation: $2.50/MWh increase in power price	$	1		$	3
Coal/Nuclear/Renewable Generation: $2.50/MWh decrease in power price	$	—		$	—
Gas Generation: $1.00/MWh increase in spark spread	$	1		$	17
Gas Generation: $1.00/MWh decrease in spark spread	$	—		$	(14	)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	1		$	(3	)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	(1	)	$	3
PJM:
Coal Generation: $2.50/MWh increase in power price	$	1		$	5
Coal Generation: $2.50/MWh decrease in power price	$	—		$	(2	)
Gas Generation: $1.00/MWh increase in spark spread	$	1		$	13
Gas Generation: $1.00/MWh decrease in spark spread	$	—		$	(12	)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	(1	)	$	(2	)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	1		$	2
NYISO/ISO-NE:
Gas Generation: $1.00/MWh increase in spark spread	$	—		$	4
Gas Generation: $1.00/MWh decrease in spark spread	$	—		$	(3	)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	—		$	(1	)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	—		$	1
MISO/CAISO:
Coal Generation: $2.50/MWh increase in power price	$	2		$	2
Coal Generation: $2.50/MWh decrease in power price	$	—		$	—
Gas Generation: $1.00/MWh increase in spark spread	$	—		$	1
Gas Generation: $1.00/MWh decrease in spark spread	$	—		$	(1	)
Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price	$	—		$	(1	)
Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price	$	—		$	1

___________


(a)	Balance of 2019 is from October 1, 2019 through December 31, 2019.

Environmental Matters — See Note 13 to Financial Statements for a discussion of greenhouse gas emissions, regional haze, state implementation plan and other recent EPA actions as well as related litigation.

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RESULTS OF OPERATIONS

Consolidated Financial Results — Three and Nine Months Ended September 30, 2019 Compared to Three and Nine Months Ended September 30, 2018



	Three Months Ended September 30,						Favorable (Unfavorable) $ Change			Nine Months Ended September 30,						Favorable (Unfavorable) $ Change
	2019			2018			Favorable (Unfavorable) $ Change			2019			2018			Favorable (Unfavorable) $ Change
Operating revenues	$	3,194		$	3,243		$	(49	)	$	8,949		$	6,581		$	2,368
Fuel, purchased power costs and delivery fees	(1,687		)	(1,627		)	(60		)	(4,287		)	(3,492		)	(795		)
Operating costs	(397		)	(346		)	(51		)	(1,153		)	(926		)	(227		)
Depreciation and amortization	(424		)	(426		)	2			(1,213		)	(967		)	(246		)
Selling, general and administrative expenses	(246		)	(194		)	(52		)	(637		)	(711		)	74
Operating income	440			650			(210		)	1,659			485			1,174
Other income	6			6			—			45			25			20
Other deductions	(4		)	(1		)	(3		)	(9		)	(4		)	(5		)
Interest expense and related charges	(224		)	(154		)	(70		)	(720		)	(291		)	(429		)
Impacts of Tax Receivable Agreement	(62		)	17			(79		)	(26		)	(65		)	39
Equity in earnings of unconsolidated investment	3			7			(4		)	13			11			2
Income before income taxes	159			525			(366		)	962			161			801
Income tax expense	(45		)	(194		)	149			(270		)	(31		)	(239		)
Net income	$	114		$	331		$	(217	)	$	692		$	130		$	562



	Three Months Ended September 30, 2019
	Retail			ERCOT			PJM			NY/NE			MISO			Asset Closure			Eliminations / Corporate and Other			Vistra Energy Consolidated
Operating revenues	$	2,207		$	731		$	443		$	214		$	197		$	—		$	(598	)	$	3,194
Fuel, purchased power costs and delivery fees	(1,358		)	(429		)	(281		)	(108		)	(164		)	—			653			(1,687		)
Operating costs	(22		)	(166		)	(74		)	(24		)	(101		)	(4		)	(6		)	(397		)
Depreciation and amortization	(86		)	(126		)	(135		)	(51		)	(5		)	—			(21		)	(424		)
Selling, general and administrative expenses	(160		)	(21		)	(14		)	(11		)	(12		)	(5		)	(23		)	(246		)
Operating income (loss)	581			(11		)	(61		)	20			(85		)	(9		)	5			440
Other income	—			1			—			—			1			1			3			6
Other deductions	—			(2		)	—			—			(2		)	—			—			(4		)
Interest expense and related charges	(8		)	2			(2		)	(1		)	(2		)	—			(213		)	(224		)
Impacts of Tax Receivable Agreement	—			—			—			—			—			—			(62		)	(62		)
Equity in earnings of unconsolidated investment	—			—			1			2			—			—			—			3
Income (loss) before income taxes	573			(10		)	(62		)	21			(88		)	(8		)	(267		)	159
Income tax expense	—			—			—			—			—			—			(45		)	(45		)
Net income (loss)	$	573		$	(10	)	$	(62	)	$	21		$	(88	)	$	(8	)	$	(312	)	$	114

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	Three Months Ended September 30, 2018
	Retail			ERCOT			PJM			NY/NE			MISO			Asset Closure			Eliminations / Corporate and Other			Vistra Energy Consolidated
Operating revenues	$	1,813		$	1,396		$	620		$	301		$	230		$	(1	)	$	(1,116	)	$	3,243
Fuel, purchased power costs and delivery fees	(1,689		)	(458		)	(321		)	(167		)	(150		)	—			1,158			(1,627		)
Operating costs	(16		)	(155		)	(83		)	(23		)	(61		)	(3		)	(5		)	(346		)
Depreciation and amortization	(80		)	(122		)	(141		)	(55		)	(3		)	—			(25		)	(426		)
Selling, general and administrative expenses	(111		)	(18		)	(14		)	(11		)	(18		)	—			(22		)	(194		)
Operating income (loss)	(83		)	643			61			45			(2		)	(4		)	(10		)	650
Other income	—			—			1			—			—			—			5			6
Other deductions	—			(2		)	—			—			—			—			1			(1		)
Interest expense and related charges	(3		)	2			(3		)	(1		)	(1		)	—			(148		)	(154		)
Impacts of Tax Receivable Agreement	—			—			—			—			—			—			17			17
Equity in earnings of unconsolidated investment	—			—			3			3			—			—			1			7
Income (loss) before income taxes	(86		)	643			62			47			(3		)	(4		)	(134		)	525
Income tax expense	—			—			—			—			—			—			(194		)	(194		)
Net income (loss)	$	(86	)	$	643		$	62		$	47		$	(3	)	$	(4	)	$	(328	)	$	331

In the third quarter of 2019, we continued with our balanced capital allocation program, refinancing approximately $400 million of debt, which lowered interest rates and extended maturities, and returning approximately $171 million to stockholders through share repurchases. We produced results during the quarter in line with expectations, reflecting the stability of our integrated model with the generation fleet operating safely and reliably over the volatile ERCOT summer while our Retail segment delivered stable pricing and growth in ERCOT residential customer counts. Consolidated results decreased $217 million to net income of $114 million in the three months ended September 30, 2019 compared to the three months ended September 30, 2018. The change in results reflects higher power costs in our Retail segment, lower revenue net of fuel in our PJM, NY/NE and MISO segments, an increase in unrealized losses on hedging transactions and interest rate swaps, and one-time costs associated with the MISO segment plant closures and the Crius Transaction; partially offset by higher revenue net of fuel in our ERCOT segment and a decrease in income tax expense.

Interest expense and related charges increased $70 million to $224 million in the three months ended September 30, 2019 compared to the three months ended September 30, 2018 and reflected a $114 million increase in unrealized mark-to-market losses on interest rate swaps, partially offset by a $24 million decrease in interest paid/accrued reflecting repayments and repurchases of long-term debt. Debt extinguishment gains totaled $2 million in 2019 compared to debt extinguishment losses of $27 million in 2018. See Note 19 to the Financial Statements.

For the three months ended September 30, 2019 and 2018, the Impacts of the Tax Receivable Agreement totaled expense of $62 million and income of $17 million, respectively. See Note 8 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement Obligation.

For the three months ended September 30, 2019, income tax expense totaled $45 million and the effective tax rate was 28.3%. For the three months ended September 30, 2018, income tax expense totaled $194 million and the effective tax rate was 37.0%. See Note 7 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

Consolidated cash flow from operations produced $941 million in the three months ended September 30, 2019 compared to $892 million produced in the three months ended September 30, 2018.

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	Nine Months Ended September 30, 2019
	Retail			ERCOT			PJM			NY/NE			MISO			Asset Closure			Eliminations / Corporate and Other			Vistra Energy Consolidated
Operating revenues	$	5,014		$	3,356		$	1,833		$	813		$	697		$	—		$	(2,764	)	$	8,949
Fuel, purchased power costs and delivery fees	(4,383		)	(1,062		)	(862		)	(436		)	(436		)	—			2,892			(4,287		)
Operating costs	(44		)	(525		)	(244		)	(74		)	(219		)	(25		)	(22		)	(1,153		)
Depreciation and amortization	(204		)	(385		)	(399		)	(155		)	(11		)	—			(59		)	(1,213		)
Selling, general and administrative expenses	(364		)	(60		)	(41		)	(33		)	(71		)	(14		)	(54		)	(637		)
Operating income (loss)	19			1,324			287			115			(40		)	(39		)	(7		)	1,659
Other income	—			21			—			—			5			2			17			45
Other deductions	—			(6		)	—			—			(2		)	—			(1		)	(9		)
Interest expense and related charges	(16		)	7			(8		)	(2		)	(5		)	—			(696		)	(720		)
Impacts of Tax Receivable Agreement	—			—			—			—			—			—			(26		)	(26		)
Equity in earnings of unconsolidated investment	—			—			4			9			—			—			—			13
Income (loss) before income taxes	3			1,346			283			122			(42		)	(37		)	(713		)	962
Income tax expense	—			—			—			—			—			—			(270		)	(270		)
Net income (loss)	$	3		$	1,346		$	283		$	122		$	(42	)	$	(37	)	$	(983	)	$	692



	Nine Months Ended September 30, 2018
	Retail			ERCOT			PJM			NY/NE			MISO			Asset Closure			Eliminations / Corporate and Other			Vistra Energy Consolidated
Operating revenues	$	4,239		$	2,190		$	1,104		$	487		$	488		$	48		$	(1,975	)	$	6,581
Fuel, purchased power costs and delivery fees	(3,290		)	(1,085		)	(560		)	(276		)	(283		)	(37		)	2,039			(3,492		)
Operating costs	(29		)	(503		)	(165		)	(48		)	(136		)	(33		)	(12		)	(926		)
Depreciation and amortization	(237		)	(295		)	(266		)	(104		)	(6		)	—			(59		)	(967		)
Selling, general and administrative expenses	(312		)	(73		)	(28		)	(23		)	(33		)	(4		)	(238		)	(711		)
Operating income (loss)	371			234			85			36			30			(26		)	(245		)	485
Other income	29			20			1			—			—			2			(27		)	25
Other deductions	—			(5		)	—			—			—			—			1			(4		)
Interest expense and related charges	(3		)	(13		)	(5		)	(1		)	(1		)	—			(268		)	(291		)
Impacts of Tax Receivable Agreement	—			—			—			—			—			—			(65		)	(65		)
Equity in earnings of unconsolidated investment	—			—			5			6			—			—						11
Income (loss) before income taxes	397			236			86			41			29			(24		)	(604		)	161
Income tax benefit	—			—			—			—			—			—			(31		)	(31		)
Net income (loss)	$	397		$	236		$	86		$	41		$	29		$	(24	)	$	(635	)	$	130

Table of Contents

In the nine months ended September 30, 2019, we refinanced approximately $4.5 billion of debt and returned approximately $619 million to stockholders through share repurchases. Our operating segments delivered strong operating performance with a disciplined focus on cost management, while generating and selling electricity in a safe and reliable manner. Consolidated results increased $562 million to net income of $692 million in the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018. The change in results reflects an increase in unrealized gains on hedging transactions and a full year of operations acquired in the Merger, partially offset by an increase in interest and income tax expenses.

Interest expense and related charges increased $429 million to $720 million in the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018 and driven by a $398 million increase in unrealized mark-to-market losses on interest rate swaps and a $65 million increase in interest paid/accrued reflecting long-term debt assumed in the Merger. Debt extinguishment gains totaled $12 million in 2019 compared to debt extinguishment losses of $27 million in 2018. See Note 19 to the Financial Statements.

For the nine months ended September 30, 2019 and 2018, the Impacts of the Tax Receivable Agreement totaled expense of $26 million and $65 million, respectively. See Note 8 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement Obligation.

For the nine months ended September 30, 2019, income tax expense totaled $270 million and the effective tax rate was 28.1%. For the nine months ended September 30, 2018, income tax expense totaled $31 million and the effective tax rate was 19.3%. 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 Energy 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 related to our portfolio, (iii) the impact of impairment charges, (iv) certain amounts associated with fresh-start reporting, acquisitions, dispositions, transition costs or restructurings, (v) non-cash compensation expense, (vi) impacts from the Tax Receivable Agreement and (vii) other material nonrecurring or unusual items.

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

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

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Adjusted EBITDA — Three and Nine Months Ended September 30, 2019 Compared to Three and Nine Months Ended September 30, 2018



	Three Months Ended September 30,						Favorable (Unfavorable) $ Change			Nine Months Ended September 30,						Favorable (Unfavorable) $ Change
	2019			2018			Favorable (Unfavorable) $ Change			2019			2018			Favorable (Unfavorable) $ Change
Net income	$	114		$	331		$	(217	)	$	692		$	130		$	562
Income tax expense	45			194			(149		)	270			31			239
Interest expense and related charges (a)	224			154			70			720			291			429
Depreciation and amortization (b)	444			446			(2		)	1,266			1,027			239
EBITDA before Adjustments	827			1,125			(298		)	2,948			1,479			1,469
Unrealized net (gain) loss resulting from hedging transactions	79			8			71			(625		)	207			(832		)
Generation plant retirement expenses	49			—			49			49			—			49
Fresh start/purchase accounting impacts	(8		)	(8		)	—			26			26			—
Impacts of Tax Receivable Agreement	62			(17		)	79			26			65			(39		)
Reorganization items and restructuring expenses	—			—			—			—			62			(62		)
Non-cash compensation expenses	12			14			(2		)	36			—			36
Transition and merger expenses	38			19			19			82			205			(123		)
Other, net	1			—			1			12			(4		)	16
Adjusted EBITDA	$	1,060		$	1,141		$	(81	)	$	2,554		$	2,040		$	514

____________


(a)	Includes unrealized mark-to-market net gains/losses on interest rate swaps of $76 million net losses and $38 million net gains for the three months ended September 30, 2019 and 2018, respectively, and $275 million net losses and $123 million net gains for the nine months ended September 30, 2019 and 2018, respectively.


(b)	Includes nuclear fuel amortization in the ERCOT segment of $20 million and $20 million for the three months ended September 30, 2019 and 2018, respectively, and $53 million and $60 million for the nine months ended September 30, 2019 and 2018, respectively.

Table of Contents



	Three Months Ended September 30, 2019
	Retail			ERCOT			PJM			NY/NE		MISO			Asset Closure			Eliminations / Corporate and Other			Vistra Energy Consolidated
Net income (loss)	$	573		$	(10	)	$	(62	)	$	21	$	(88	)	$	(8	)	$	(312	)	$	114
Income tax expense	—			—			—			—		—			—			45			45
Interest expense and related charges (a)	8			(2		)	2			1		2			—			213			224
Depreciation and amortization (b)	86			146			135			51		5			—			21			444
EBITDA before Adjustments	667			134			75			73		(81		)	(8		)	(33		)	827
Unrealized net (gain) loss resulting from hedging transactions	(769		)	682			139			5		43			—			(21		)	79
Generation plant retirement expenses	—			—			—			—		47			2			—			49
Fresh start/purchase accounting impacts	(12		)	—			3			—		2			—			(1		)	(8		)
Impacts of Tax Receivable Agreement	—			—			—			—		—			—			62			62
Non-cash compensation expenses	—			—			—			—		—			—			12			12
Transition and merger expenses	24			5			1			1		1			1			5			38
Other, net	3			2			4			2		(1		)	1			(10		)	1
Adjusted EBITDA	$	(87	)	$	823		$	222		$	81	$	11		$	(4	)	$	14		$	1,060

___________


(a)	Includes $76 million of unrealized mark-to-market net losses on interest rate swaps.


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

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	Three Months Ended September 30, 2018
	Retail			ERCOT			PJM			NY/NE		MISO			Asset Closure			Eliminations / Corporate and Other			Vistra Energy Consolidated
Net income (loss)	$	(86	)	$	643		$	62		$	47	$	(3	)	$	(4	)	$	(328	)	$	331
Income tax expense	—			—											—			194			194
Interest expense and related charges (a)	3			(2		)	3			1		1			—			148			154
Depreciation and amortization (b)	80			142			141			55		3			—			25			446
EBITDA before Adjustments	(3		)	783			206			103		1			(4		)	39			1,125
Unrealized net (gain) loss resulting from hedging transactions	154			(195		)	21			—		32			—			(4		)	8
Fresh start accounting impacts	(15		)	—			(1		)	5		3			—			—			(8		)
Impacts of Tax Receivable Agreement	—			—			—			—		—			—			(17		)	(17		)
Non-cash compensation expenses	—			—			—			—		—			—			14			14
Transition and merger expenses	—			3			5			1		1			—			9			19
Other, net	5			6			9			2		2			(8		)	(16		)	—
Adjusted EBITDA	$	141		$	597		$	240		$	111	$	39		$	(12	)	$	25		$	1,141

____________


(a)	Includes $38 million of unrealized mark-to-market net gains on interest rate swaps.


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



	Nine Months Ended September 30, 2019
	Retail		ERCOT			PJM			NY/NE			MISO			Asset Closure			Eliminations / Corporate and Other			Vistra Energy Consolidated
Net income (loss)	$	3	$	1,346		$	283		$	122		$	(42	)	$	(37	)	$	(983	)	$	692
Income tax expense	—		—			—			—			—			—			270			270
Interest expense and related charges (a)	16		(7		)	8			2			5			—			696			720
Depreciation and amortization (b)	204		438			399			155			11			—			59			1,266
EBITDA before Adjustments	223		1,777			690			279			(26		)	(37		)	42			2,948
Unrealized net (gain) loss resulting from hedging transactions	192		(616		)	(115		)	(33		)	(8		)	—			(45		)	(625		)
Generation plant retirement expenses	—		—			—			—			47			2			—			49
Fresh start/purchase accounting impacts	17		—			(2		)	3			11			—			(3		)	26
Impacts of Tax Receivable Agreement	—		—			—			—			—			—			26			26
Non-cash compensation expenses	—		—			—			—			—			—			36			36
Transition and merger expenses	24		11			4			2			25			—			16			82
Other, net	7		11			13			7			10			3			(39		)	12
Adjusted EBITDA	$	463	$	1,183		$	590		$	258		$	59		$	(32	)	$	33		$	2,554

____________


(a)	Includes $275 million of unrealized mark-to-market net losses on interest rate swaps.


(b)	Includes nuclear fuel amortization of $53 million in ERCOT segment.

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	Nine Months Ended September 30, 2018
	Retail			ERCOT			PJM			NY/NE		MISO		Asset Closure			Eliminations / Corporate and Other			Vistra Energy Consolidated
Net income (loss)	$	397		$	236		$	86		$	41	$	29	$	(24	)	$	(635	)	$	130
Income tax expense	—			—			—			—		—		—			31			31
Interest expense and related charges (a)	3			13			5			1		1		—			268			291
Depreciation and amortization (b)	237			355			266			104		6		—			59			1,027
EBITDA before Adjustments	637			604			357			146		36		(24		)	(277		)	1,479
Unrealized net (gain) loss resulting from hedging transactions	(38		)	207			20			22		—		—			(4		)	207
Fresh start accounting impacts	12			(4		)	(2		)	9		11		—			—			26
Impacts of Tax Receivable Agreement	—			—			—			—		—		—			65			65
Reorganization items and restructuring expenses	—			—			—			—		—		—			62			62
Transition and merger expenses	—			7			7			1		5		2			183			205
Other, net	(16		)	(5		)	12			7		5		(7		)	—			(4		)
Adjusted EBITDA	$	595		$	809		$	394		$	185	$	57	$	(29	)	$	29		$	2,040

____________


(a)	Includes $123 million of unrealized mark-to-market net gains on interest rate swaps.


(b)	Includes nuclear fuel amortization of $60 million in ERCOT segment.

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Retail Segment — Three and Nine Months Ended September 30, 2019 Compared to Three and Nine Months Ended September 30, 2018



	Three Months Ended September 30,						Favorable (Unfavorable) Change			Nine Months Ended September 30,						Favorable (Unfavorable) Change
	2019			2018			Favorable (Unfavorable) Change			2019			2018			Favorable (Unfavorable) Change
Operating revenues:
Revenues in ERCOT	$	1,600		$	1,362		$	238		$	3,716		$	3,423		$	293
Revenues in Northeast/Midwest	576			442			134			1,239			778			461
Amortization expense	12			15			(3		)	(7		)	(12		)	5
Other revenues	19			(6		)	25			66			50			16
Total operating revenues	2,207			1,813			394			5,014			4,239			775
Fuel, purchased power costs and delivery fees:
Purchases from affiliates	(1,451		)	(1,108		)	(343		)	(2,813		)	(2,169		)	(644		)
Unrealized net gains (losses) on hedging activities with affiliates	757			(130		)	887			(209		)	49			(258		)
Delivery fees	(497		)	(452		)	(45		)	(1,192		)	(1,167		)	(25		)
Other costs (b)	(167		)	1			(168		)	(169		)	(3		)	(166		)
Total fuel, purchased power costs and delivery fees	(1,358		)	(1,689		)	331			(4,383		)	(3,290		)	(1,093		)
Net income (loss)	$	573		$	(86	)	$	659		$	3		$	397		$	(394	)
Adjusted EBITDA	$	(87	)	$	141		$	(228	)	$	463		$	595		$	(132	)
Retail sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT	15,251			13,263			1,988			35,727			33,316			2,411
Sales volumes in Northeast/Midwest	9,193			8,042			1,151			21,756			14,361			7,395
Total retail electricity sales volumes	24,444			21,305			3,139			57,483			47,677			9,806
Weather (North Texas average) - percent of normal (a):
Cooling degree days	106.0		%	99.0		%				96.0		%	106.0		%
Heating degree days	—		%	—		%				111.0		%	106.0		%

____________


(a)	Weather data is obtained from Weatherbank, Inc. For the three and nine months ended September 30, 2019, normal is defined as the average over the 10-year period from September 2009 to September 2018. For the three and nine months ended September 30, 2018, normal is defined as the average over the 10-year period from September 2008 to September 2017.


(b)	For the three and nine months ended September 30, 2019, includes $176 million of third-party power purchases, primarily related to the recent Cruis Transaction.

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Net income (loss) increased by $659 million to $573 million and Adjusted EBITDA decreased by $228 million to $(87) million in the three months ended September 30, 2019 compared to the three months ended September 30, 2018. Net income of $397 million decreased by $394 million to a net income of $3 million and Adjusted EBITDA decreased by $132 million to $463 million in the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018.



	Three Months Ended September 30, 2019 Compared to 2018			Nine Months Ended September 30, 2019 Compared to 2018
Unfavorable margins in ERCOT driven by increased power costs and timing of multi-year retail contracts due to backwardation of power curves	$	(243	)	$	(118	)
Impact of Crius acquired in July 2019	18			18
Favorable/(unfavorable) weather in ERCOT	7			(20		)
Other	(10		)	(12		)
Change in Adjusted EBITDA	$	(228	)	$	(132	)
Change in depreciation and amortization expenses (a)	(6		)	33
Favorable (unfavorable) impact of unrealized net losses on hedging activities	923			(230		)
Higher transition and merger and other expenses	(30		)	(65		)
Change in net income (loss)	$	659		$	(394	)

____________


(a)	Nine months ended September 30, 2019 compared to 2018 driven by reduced amortization of the retail customer relationship.

Generation — Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018



	Three Months Ended September 30,
	ERCOT						PJM						NY/NE						MISO
	2019			2018			2019			2018			2019			2018			2019			2018
Operating revenues:
Electricity sales	$	321		$	494		$	300		$	255		$	175		$	216		$	158		$	130
Capacity	—			—			24			164			23			79			5			15
Sales to affiliates	1,090			709			247			229			28			16			86			124
Rolloff of unrealized net gains (losses) representing positions settled in the current period	380			180			18			29			14			27			(8		)	4
Unrealized net gains (losses) on hedging activities	(415		)	(158		)	(77		)	(46		)	(20		)	(33		)	(3		)	(10		)
Unrealized net gains (losses) on hedging activities with affiliates	(646		)	170			(69		)	(11		)	(6		)	(1		)	(37		)	(28		)
Other revenues	1			1			—			—			—			(3		)	(4		)	(5		)
Operating revenues	731			1,396			443			620			214			301			197			230
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs	(341		)	(421		)	(268		)	(326		)	(112		)	(149		)	(168		)	(179		)
Fuel for generation facilities and purchased power costs from affiliates							(1		)	(2		)	(1		)	2			1			30
Unrealized (gains) losses from hedging activities	(1		)	3			(11		)	7			7			7			5			2
Ancillary and other costs	(87		)	(40		)	(1		)	—			(2		)	(27		)	(2		)	(3		)
Fuel, purchased power costs and delivery fees	(429		)	(458		)	(281		)	(321		)	(108		)	(167		)	(164		)	(150		)
Net income (loss)	$	(10	)	$	643		$	(62	)	$	62		$	21		$	47		$	(88	)	$	(3	)
Adjusted EBITDA	$	823		$	597		$	222		$	240		$	81		$	111		$	11		$	39

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	Three Months Ended September 30,
	ERCOT						PJM						NY/NE						MISO
	2019			2018			2019			2018			2019			2018			2019			2018
Production volumes (GWh):
Natural gas facilities	12,924			11,992			10,532			10,097			4,953			6,030
Lignite and coal facilities	7,833			8,854			3,891			5,338									7,052			8,293
Nuclear facilities	5,274			5,197
Solar/Battery facilities	137			132
Capacity factors:
CCGT facilities	69.5		%	67.9		%	76.3		%	68.3		%	47.4		%	55.2		%
Lignite and coal facilities	78.8		%	89.1		%	50.6		%	69.5		%							60.8		%	58.3		%
Nuclear facilities	103.8		%	102.3		%
Weather - percent of normal (a):
Cooling degree days	108		%	99		%	116		%	118.0		%	105.0		%	120.0		%	119.0		%	121.0		%
Heating degree days	—		%	—		%	—		%	65.0		%	60.0		%	74.0		%	—		%	90.0		%
Market pricing:
Average ERCOT North power price ($/MWh)	$	71.13		$	34.67
Average Market On-Peak Power Prices ($MWh) (b):
PJM West Hub							$	31.17		$	39.98
AEP Dayton Hub							$	32.28		$	40.25
NYISO Zone C													$	25.85		$	39.18
Massachusetts Hub													$	29.69		$	43.80
Indiana Hub																			$	32.00		$	38.85
Northern Illinois Hub																			$	29.79		$	37.01
Average natural gas price - (c)
TetcoM3 ($/MMBtu)							$	1.87		$	2.50
Algonquin Citygates ($/MMBtu)													$	2.09		$	2.98

____________

(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.

Table of Contents

The following table presents changes in net income and Adjusted EBITDA for the three months ended September 30, 2019 compared to the three months ended September 30, 2018.



	Three Months Ended September 30, 2019 Compared to 2018
	ERCOT			PJM			NY/NE			MISO
Favorable/(unfavorable) change in revenue net of fuel	$	241		$	(20	)	$	(26	)	$	(38	)
Favorable/(unfavorable) change in other operating costs	(13		)	7			(2		)	4
Favorable/(unfavorable) change in selling, general and administrative expenses	(2		)	(2		)	—			6
Other	—			(3		)	(2		)	—
Change in Adjusted EBITDA	$	226		$	(18	)	$	(30	)	$	(28	)
Favorable/(unfavorable) change in depreciation and amortization	(4		)	6			4			(2		)
Unrealized net losses on hedging activities	(877		)	(118		)	(5		)	(11		)
Fresh start/purchase accounting impacts	—			4			5			1
Transition and merger expenses	2			4			—			—
Generation plant retirement expenses	—			—			—			(47		)
Other	—			(2		)	—			2
Change in Net income	$	(653	)	$	(124	)	$	(26	)	$	(85	)

The change in ERCOT segment results was driven by a $241 million increase in revenue net of fuel reflecting higher realized power prices.

The change in PJM segment results was driven by a $20 million decrease in revenue net of fuel reflecting lower power prices and a 1,012 GWh (7%) decrease in production volumes.

The change in NY/NE segment results was driven by a $26 million decrease in revenue net of fuel reflecting lower power prices and a 1,077 GWh (22%) decrease in production volumes.

The change in MISO segment results was driven by a $38 million decrease in revenue net of fuel reflecting lower power prices and a 1,242 GWh (18%) decrease in production volumes.

Generation — Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018



	Nine Months Ended September 30,
	ERCOT					PJM					NY/NE						MISO
	2019		2018			2019		2018			2019			2018			2019			2018
Operating revenues:
Electricity Sales	$	908	$	939		$	864	$	462		$	549		$	331		$	459		$	211
Capacity	—		—			144		283			175			162			30			44
Sales to affiliates	1,840		1,459			678		397			72			31			223			240
Rolloff of unrealized net gains (losses) representing positions settled in the current period	370		348			3		44			(20		)	23			(28		)	1
Unrealized net gains (losses) on hedging activities	100		(518		)	55		(55		)	40			(50		)	41			(25		)
Unrealized net gains (losses) on hedging activities with affiliates	136		(37		)	89		(27		)	—			(5		)	(15		)	20
Other revenues	2		(1		)	—		—			(3		)	(5		)	(13		)	(3		)
Operating revenues	3,356		2,190			1,833		1,104			813			487			697			488

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	Nine Months Ended September 30,
	ERCOT						PJM						NY/NE						MISO
	2019			2018			2019			2018			2019			2018			2019			2018
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs	(928		)	(976		)	(828		)	(569		)	(443		)	(258		)	(440		)	(313		)
Fuel for generation facilities and purchased power costs from affiliates	—			—			(1		)	(8		)	(1		)	—			1			30
Unrealized (gains) losses from hedging activities	10			—			(32		)	18			13			10			10			4
Ancillary and other costs	(144		)	(109		)	(1		)	(1		)	(5		)	(28		)	(7		)	(4		)
Fuel, purchased power costs and delivery fees	(1,062		)	(1,085		)	(862		)	(560		)	(436		)	(276		)	(436		)	(283		)
Net income (loss)	$	1,346		$	236		$	283		$	86		$	122		$	41		$	(42	)	$	29
Adjusted EBITDA	$	1,183		$	809		$	590		$	394		$	258		$	185		$	59		$	57
Production volumes (GWh):
Natural gas facilities	30,255			26,413			27,989			17,969			13,593			9,795
Lignite and coal facilities	20,613			21,257			11,535			8,717									19,321			14,633
Nuclear facilities	13,951			15,744
Solar/Battery facilities	354			266
Capacity factors:
CCGT facilities	55.9		%	59.6		%	70.2		%	66.7		%	43.9		%	48.0		%
Lignite and coal facilities	69.9		%	75.7		%	50.6		%	59.6		%							56.1		%	59.4		%
Nuclear facilities	92.6		%	104.5		%
Weather - percent of normal (a):
Cooling degree days	100.0		%	102.0		%	109.0		%	118.0		%	100.0		%	116.0		%	110.0		%	133.0		%
Heating degree days	110.0		%	104.0		%	97.0		%	100.0		%	100.0		%	100.0		%	98.0		%	96.0		%
Market pricing:
Average ERCOT North power price ($/MWh)	$	40.38		$	29.31
Average Market On-Peak Power Prices ($MWh) (b):
PJM West Hub							$	31.22		$	42.59
AEP Dayton Hub							$	31.27		$	40.57
NYISO Zone C													$	27.15		$	37.01
Massachusetts Hub													$	34.83		$	48.87
Indiana Hub																			$	31.87		$	38.13
Northern Illinois Hub																			$	28.81		$	33.98
Average natural gas price - (c)
TetcoM3 ($/MMBtu)							$	2.47		$	3.73
Algonquin Citygates ($/MMBtu)													$	3.16		$	4.78

____________


(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.

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The following table presents changes in net income and Adjusted EBITDA for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018.



	Nine Months Ended September 30, 2019 Compared to 2018
	ERCOT			PJM			NY/NE			MISO
Favorable impact related to operations acquired in the Merger (a)	$	—		$	201		$	86		$	47
Favorable/(unfavorable) change in revenue net of fuel	365			1			(7		)	(73		)
Favorable/(unfavorable) change in other operating costs	(22		)	1			(3		)	25
Favorable/(unfavorable) change in selling. general and administrative expenses	13			(4		)	—			2
Other	18			(3		)	(3		)	1
Change in Adjusted EBITDA	$	374		$	196		$	73		$	2
Unfavorable change in depreciation and amortization	(83		)	(133		)	(51		)	(5		)
Unrealized net gains on hedging activities	823			135			55			8
Fresh start/purchase accounting impacts	4			—			6			—
Transition and merger expenses	(4		)	3			(1		)	(20		)
Generation plant retirement expenses	—			—			—			(47		)
Other	(4		)	(4		)	(1		)	(9		)
Change in Net income	$	1,110		$	197		$	81		$	(71	)

____________


(a)	Impact related to PJM, NY/NE and MISO operations acquired in the Merger are the combined results for the first quarter of 2019, for which there is no comparable period for 2018 due to the Merger date of April 9, 2018.

The change in ERCOT segment results was driven by a $365 million increase in generation revenue net of fuel reflecting an increase in production volumes and higher realized power prices.

The change in PJM segment results was driven by $201 million related to operations in the first quarter of 2019 acquired in the Merger.

The change in NY/NE segment results was driven by $86 million related to operations in the first quarter of 2019 acquired in the Merger.

The change in MISO segment results was driven by a $76 million decrease in revenue net of fuel reflecting lower realized price and lower capacity revenue, partially offset by $47 million related to operations in the first quarter of 2019 acquired in the Merger.

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Asset Closure Segment —Three and Nine Months Ended September 30, 2019 Compared to Three and Nine Months Ended September 30, 2018



	Three Months Ended September 30,						Favorable (Unfavorable) Change			Nine Months Ended September 30,						Favorable (Unfavorable) Change
	2019			2018			Favorable (Unfavorable) Change			2019			2018			Favorable (Unfavorable) Change
Operating revenues	$	—		$	(1	)	$	1		$	—		$	48		$	(48	)
Fuel, purchased power costs and delivery fees	—			—			—			—			(37		)	37
Operating costs	(4		)	(3		)	(1		)	(25		)	(33		)	8
Selling, general and administrative expenses	(5		)	—			(5		)	(14		)	(4		)	(10		)
Operating loss	(9		)	(4		)	(5		)	(39		)	(26		)	(13		)
Other income	1			—			1			2			2			—
Net loss	$	(8	)	$	(4	)	$	(4	)	$	(37	)	$	(24	)	$	(13	)
Adjusted EBITDA	$	(4	)	$	(12	)	$	8		$	(32	)	$	(29	)	$	(3	)
Production volumes (GWh)	—			—			—			—			1,513			(1,513		)

Results for the Asset Closure segment reflect the retirement of the Stuart and Killen plants in May 2018 (acquired in the Merger), retirement of the Northeastern waste coal plant in October 2018 and the retirement of the Monticello, Sandow and Big Brown plants in January and February 2018 (see Note 4 to the Financial Statements). Operating costs for the nine months ended September 30, 2019 included ongoing costs associated with closing these plants.

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

The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2019 and 2018. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $625 million in unrealized net gains for the nine months ended September 30, 2019 and $207 million in unrealized net losses for the nine months ended September 30, 2018, arising from mark-to-market accounting for positions in the commodity contract portfolio.



	Nine Months Ended September 30,
	2019			2018
Commodity contract net asset (liability) at beginning of period	$	(850	)	$	(96	)
Settlements/termination of positions (a)	321			416
Changes in fair value of positions in the portfolio (b)	304			(623		)
Acquired commodity contracts (c)	(22		)	(452		)
Other activity (d)	(131		)	72
Commodity contract net asset (liability) at end of period	$	(378	)	$	(683	)

____________

(a)

Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). The nine months ended September 30, 2019 and 2018 include reversals of $1 million of unrealized losses and $10 million of previously recorded unrealized gains related to Vistra Energy beginning balances. The nine months ended September 30, 2019 and 2018 also include reversals of $116 million and $315 million, respectively, of previously recorded unrealized losses related to commodity contracts acquired in the Merger. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.


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


(c)	Includes fair value of commodity contracts acquired on the Crius Acquisition Date in 2019 and on the Merger Date in 2018 (see Note 2 to the Financial Statements).


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

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Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair values at September 30, 2019, scheduled by the source of fair value and contractual settlement dates of the underlying positions.



	Maturity dates of unrealized commodity contract net liability at September 30, 2019
Source of fair value	Less than 1 year			1-3 years		4-5 years			Excess of 5 years			Total
Prices actively quoted	$	(35	)	$	1	$	(13	)	$	—		$	(47	)
Prices provided by other external sources	(304		)	26		(1		)	—			(279		)
Prices based on models	—			7		13			(72		)	(52		)
Total	$	(339	)	$	34	$	(1	)	$	(72	)	$	(378	)

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FINANCIAL CONDITION

Operating Cash Flows

Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018 — Cash provided by operating activities totaled $1.823 billion and $863 million in the nine months ended September 30, 2019 and 2018, respectively. The favorable change of $960 million was primarily driven by increased cash from operations reflecting operations acquired in the Merger and a decrease in cash margin deposits posted with third-parties.

Depreciation and amortization expense reported as a reconciling adjustment in the statements of condensed consolidated cash flows exceeds the amount reported in the statements of condensed consolidated income by $181 million and $103 million for the nine months ended September 30, 2019 and 2018, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the statements of consolidated income consistent with industry practice, and amortization of intangible net assets and liabilities that are reported in various other statements of condensed consolidated income line items including operating revenues and fuel and purchased power costs and delivery fees.

Financing Cash Flows

Cash used in financing activities totaled $784 million and $2.172 billion in the nine months ended September 30, 2019 and 2018, respectively. The decrease in cash used in financing activities was driven by:


•	the issuance of $4.6 billion principal amount of Vistra Operations senior secured and unsecured notes in 2019 compared to the issuance of $1.0 billion principal amount of Vistra Operations senior unsecured notes in 2018;


•	redemption in 2018 of $850 million principal amount of senior unsecured notes assumed in the Merger;


•	the amendment to the Vistra Operations Credit Facilities in 2018, including the repayment of $500 million of term loans;


•	$89 million net decrease in incremental borrowings under the accounts receivable securitization program;


•	$46 million decrease in debt tender offer and other financing fees in 2019 compared to 2018,

partially offset by:


•	cash tender offers and early redemptions to purchase senior unsecured notes assumed in the Merger of $2.5 billion in 2019 compared to $1.5 billion in 2018;


•	repayment of approximately $2.0 billion of term loans under the Vistra Operations Credit Facilities in 2019;


•	$218 million increase in cash paid for share repurchases in 2019 compared to 2018, and


•	$181 million of cash dividend paid to stockholders.

Investing Cash Flows

Cash used in investing activities totaled $979 million in the nine months ended September 30, 2019 compared to cash provided by investing activities of $133 million in the nine months ended September 30, 2018. Capital expenditures (including LTSA prepayments, nuclear fuel purchases and development and growth expenditures) totaled $474 million and $303 million in the nine months ended September 30, 2019 and 2018, respectively. Cash used in investing activities in the nine months ended September 30, 2019 also reflected $374 million of net cash paid in the Crius Transaction and net purchases of environmental allowances of $137 million. Cash provided by investing activities in the nine months ended September 30, 2018 also reflected $445 million of cash acquired in the Merger (see Note 2 to the Financial Statements).

Debt Activity

See Note 11 to the Financial Statements for details of the Vistra Operations Credit Facilities and other long-term debt.

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Available Liquidity

The following table summarizes changes in available liquidity for the nine months ended September 30, 2019:



	September 30, 2019		December 31, 2018		Change
Cash and cash equivalents	$	707	$	636	$	71
Vistra Operations Credit Facilities — Revolving Credit Facility	1,844		1,135		709
Vistra Operations — Alternative Letter of Credit Facility	11		—		11
Total available liquidity	$	2,562	$	1,771	$	791

The $791 million increase in available liquidity in the nine months ended September 30, 2019 was primarily driven by cash from operations, $500 million of new Alternate LOC Facilities and $225 million of additional available capacity under the Revolving Credit Facility, partially offset by $632 million in cash paid for share repurchases, $474 million of capital expenditures (including LTSA prepayments, nuclear fuel and development and growth expenditures), $374 million of net cash paid in the Crius Transaction, $181 million in dividends paid to shareholders and $170 million in debt tender offer and other financing fees.

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 11 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 September 30, 2019, we received or posted cash and letters of credit for commodity hedging and trading activities as follows:


•	$236 million in cash has been posted with counterparties as compared to $361 million posted at December 31, 2018;


•	$8 million in cash has been received from counterparties as compared to $4 million received at December 31, 2018;


•	$1.224 billion in letters of credit have been posted with counterparties as compared to $1.185 billion posted at December 31, 2018, and


•	$13 million in letters of credit have been received from counterparties as compared to $12 million received at December 31, 2018.

Income Tax Payments

In the next 12 months, we do not expect to make federal income tax payments due to Vistra Energy's forecasted taxable loss position in 2019. In February 2019, we received a refund of $21 million related to Vistra Energy's 2017 federal tax return. We expect to make state income tax payments of approximately $25 million and $2 million in TRA payments in the next 12 months. There were no federal income tax payments and $40 million in state income tax payments for the nine months ended September 30, 2019. There were $66 million in state income tax payments in the nine months ended September 30, 2018.

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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. Although the period ended September 30, 2019 was not a compliance period, we would have been in compliance with this financial covenant if it was required to be tested at such date.

See Note 11 to the Financial Statements for discussion of other covenants related to the Vistra Operations Credit Facilities.

Collateral Support Obligations

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

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, at September 30, 2019, Vistra Energy has posted letters of credit in the amount of $38 million with the PUCT, which is subject to adjustments.

The RTOs/ISOs we operate in have rules in place to assure adequate creditworthiness of parties that participate in the markets operated by those RTOs/ISOs. Under these rules, Vistra Energy has posted collateral support totaling $414 million in the form of letters of credit, $10 million in the form of a surety bond and $1 million of cash at September 30, 2019 (which is subject to daily adjustments based on settlement activity with the RTOs/ISOs).

Material Cross Default/Acceleration Provisions

Certain of our contractual arrangements contain provisions that could result in an event of default if there was 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 $3.8 billion at September 30, 2019) under such facilities.

Each of Vistra Operations' (or its subsidiaries') commodity hedging agreements and interest rate swap agreements that are secured with a lien on its assets on a pari passu basis with the Vistra Operations Credit Facilities lenders contains a cross default provision. An event of a default by Vistra Operations or any of its subsidiaries relating to indebtedness equal to or above a threshold defined in the applicable agreement that results in the acceleration of such debt, would give such counterparty under these hedging agreements the right to terminate its hedge or interest rate swap agreement with Vistra Operations (or its applicable subsidiary) and require all outstanding obligations under such agreement to be settled.

Under (i) the Vistra Operations' Senior Unsecured Indentures and the 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) with respect to the Vistra Energy Senior Unsecured Indentures (except with respect to the Consent Senior Notes), a default under any document evidencing indebtedness for borrowed money by Vistra Energy 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 result in a cross default under the Vistra Operations Senior Unsecured Notes, the Senior Secured Notes, the Vistra Energy Senior Unsecured Notes (except with respect to the Consent 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 provision. The cross default provision applies, among other instances, if Vistra Operations, the performance guarantor, 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, the originator and servicer, in a principal amount of at least $50 million, 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.

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.

Guarantees

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

OFF–BALANCE SHEET ARRANGEMENTS

As of September 30, 2019, we have no off-balance sheet arrangements, other than certain investments in energy and energy-related entities that are accounted for under the equity method of accounting which are not expected to have any material impact on our financial condition, results of operations or liquidity.

COMMITMENTS AND CONTINGENCIES

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

CHANGES IN ACCOUNTING STANDARDS

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


Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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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 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.

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.

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

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

VaR for Underlying Generation Assets and Energy-Related Contracts — This measurement estimates the potential loss in value, due to changes in market conditions, of all underlying generation assets and contracts, based on a 95% confidence level and an assumed holding period of 60 days for a forward period through December 2020 for the nine months ended September 30, 2019 and December 2019 for the year ended December 31, 2018.



	Nine Months Ended September 30, 2019		Year Ended December 31, 2018
Month-end average VaR:	$	311	$	182
Month-end high VaR:	$	520	$	267
Month-end low VaR:	$	159	$	65

The increase in the month-end high VaR risk measure in 2019 is primarily driven by an increase in volatility in ERCOT during the year.

Interest Rate Risk

At September 30, 2019, the potential reduction of annual pretax earnings over the next twelve months due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $7 million, taking into account the interest rate swaps discussed in Note 11 to Financial Statements.

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Credit Risk

Credit risk relates to the risk of loss associated with nonperformance by counterparties. We minimize credit risk by evaluating potential counterparties, monitoring ongoing counterparty risk and assessing overall portfolio risk. This includes review of counterparty financial condition, current and potential credit exposures, credit rating and other quantitative and qualitative credit criteria. We also employ certain risk mitigation practices, including utilization of standardized master agreements that provide for netting and setoff rights, as well as credit enhancements such as margin deposits and customer deposits, letters of credit, parental guarantees and surety bonds. See Note 16 to the Financial Statements for further discussion of this exposure.

Bankruptcies - We are party to (i) certain gas transportation agreements with PG&E and (ii) a long-term renewable power purchase agreement with PG&E in connection with the Moss Landing battery storage project, which was approved by the California Public Utilities Commission in November 2018. PG&E filed for Chapter 11 bankruptcy protection in January 2019.

As of September 30, 2019, 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, specifically with respect to the gas transportation agreements, be required to seek alternative, higher-cost fuel transportation methods, if any of the terms of the contracts are not honored by PG&E or the contracts 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 $1.328 billion at September 30, 2019.

At September 30, 2019, Retail segment credit exposure totaled $1.071 billion, including $1.056 billion of trade accounts receivable and $15 million related to derivative assets. Cash deposits and letters of credit held as collateral for these receivables totaled $34 million, resulting in a net exposure of $1.037 billion. We believe the risk of material loss (after consideration of bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition of large business customers.

At September 30, 2019, aggregate ERCOT, PJM, NY/NE and MISO segments credit exposure totaled $257 million including $151 million related to derivative assets and $106 million of trade accounts receivable, after taking into account master netting agreement provisions but excluding collateral impacts.

Including collateral posted to us by counterparties, our net ERCOT, PJM, NY/NE and MISO segments exposure was $249 million, substantially all of which is with investment grade customers as seen in the following table that presents the distribution of credit exposure at September 30, 2019. Credit collateral includes cash and letters of credit but excludes other credit enhancements such as guarantees or liens on assets.



	Exposure Before Credit Collateral		Credit Collateral		Net Exposure
Investment grade	$	206	$	—	$	206
Below investment grade or no rating	51		8		43
Totals	$	257	$	8	$	249

Significant (10% or greater) concentration of credit exposure exists with one counterparty, which represented an aggregate $96 million, or 39%, 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 North American Electric Reliability Corporation, the Texas Reliability Entity, Inc., 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 U.S. Mine Safety and Health Administration and the U.S. Commodity Futures Trading Commission, 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 National Ambient Air Quality Standards, the Cross-State Air Pollution Rule, the Mercury and Air Toxics Standard, regional haze program implementation and greenhouse gas 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 financial effect;


•	legal and administrative proceedings and settlements;


•	general industry trends;


•	economic conditions, including the impact of an economic downturn;


•	weather conditions, including drought and limitations on access to water, and other natural phenomena, and acts of sabotage, wars or terrorist or cybersecurity threats or activities;


•	our ability to collect trade receivables from counterparties;


•	our ability to attract and retain profitable customers;


•	our ability to profitably serve our customers;


•	restrictions on competitive retail pricing;


•	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;

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•	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;


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


•	our ability to implement our growth strategy, including the completion and integration of mergers, acquisitions and/or joint venture activity and identification and completion of sales and divestitures activity;


•	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;


•	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 Energy, including Dynegy, Crius and Ambit, and our ability to successfully capture the full amount of projected operational and financial synergies relating to such transactions; and


•	actions by credit rating agencies.

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

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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 the end of the current period included in this quarterly report on Form 10-Q. On the Crius Acquisition Date, Vistra Energy completed the Crius Transaction. Vistra Energy is currently in the process of integrating certain processes, technology and operations of Crius, and will continue to evaluate the impact of any related changes to the internal control over financial reporting. 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 Crius 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.

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PART II. OTHER INFORMATION


Item 1.	LEGAL PROCEEDINGS

Reference is made to the discussion in Note 13 to the Financial Statements regarding legal proceedings.


Item 1A.	RISK FACTORS

There have been no material changes to the risk factors discussed in Part I, Item 1A. Risk Factors in our annual report on Form 10-K for the year ended December 31, 2018. Our business operations could also be affected by additional factors that are not presently known to us or that we currently consider to be immaterial to our operations.


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 during the quarter ended September 30, 2019.



	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of a Publicly Announced Program	Maximum Dollar Amount of Shares that may yet be Purchased under the Program (in millions)
July 1 - July 31, 2019	3,395,901	$	22.16	3,395,901	$	449
August 1 - August 31, 2019	2,889,120	$	22.95	2,889,120	$	383
September 1 - September 30, 2019	1,122,178	$	26.16	1,122,178	$	353
For the quarter ended September 30, 2019	7,407,199	$	23.07	7,407,199	$	353

In June 2018, we announced that the Board had authorized a share repurchase program under which up to $500 million of our outstanding 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.

Shares of the Company's stock will be repurchased from time to time in open market transactions at prevailing market prices, in privately negotiated transactions, pursuant to plans complying with Rule 10b5-1 and 10b-18 under the Exchange Act of 1934 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 the market price of our stock, general market and economic conditions, applicable legal requirements and compliance with the terms of our debt agreements.


Item 3.	DEFAULTS UPON SENIOR SECURITIES

None.

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Item 4.	MINE SAFETY DISCLOSURES

Vistra Energy 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 Energy 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 U.S. Mine Safety and Health Administration (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 Energy's mines, on a regular basis, and if it believes a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Such citations and orders can be contested and appealed, which often results in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. Disclosure of MSHA citations, orders and proposed assessments are provided in Exhibit 95.1 to this quarterly report on Form 10-Q.


Item 5.	OTHER INFORMATION

None

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Item 6.	EXHIBITS


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



Exhibits	Previously Filed With File Number*	As Exhibit

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

4.1	**		—	Tenth Supplemental Indenture to the 2023 Notes Indenture, dated August 30, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee

4.2	**		—	Tenth Supplemental Indenture to the 2024 7.625% Notes Indenture, dated August 30, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee

4.3	**		—	Sixth Supplemental Indenture to the 2025 Notes Indenture, dated August 30, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee

4.4	**		—	Fourth Supplemental Indenture to the 2026 Notes Indenture, dated August 30, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee

4.5	**		—	First Supplemental Indenture for the 5.500% Senior Notes due 2026, dated August 30, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee

4.6	**		—	First Supplemental Indenture for the 5.625% Senior Notes due 2027, dated August 30, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee

4.7	**		—	First Supplemental Indenture for the 5.000% Senior Notes due 2027, dated August 30, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee

4.8	**		—	Second Supplemental Indenture for 3.55% Senior Secured Notes due 2024 and 4.30% Senior Secured Notes due 2029, dated as of August 30, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee

4.9	001-38086 Form 8-K (filed July 19, 2019)	4.1	—	Third Amendment to Purchase and Sale Agreement, dated as of July 15, 2019, among TXU Energy Retail Company LLC, Dynegy Energy Services, LLC, and Dynegy Energy Services (East), LLC, each as an originator, and TXU Energy Receivables Company LLC, as purchaser

4.10	001-38086 Form 8-K (filed July 19, 2019)	4.2	—	Third Amendment to Receivables Purchase Agreement, dated as of July 15, 2019, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator

(10)	Material Contracts

10.1	001-38086 Form 8-K (filed September 19, 2019)	10.1	—	Termination of Stockholders' Agreement, dated September 18, 2019, by and among the Company and the Brookfield Stockholder

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

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

31.2	**		—	Certification of David A. Campbell, principal financial officer of Vistra Energy Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

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Exhibits	Previously Filed With File Number*	As Exhibit
(32)	Section 1350 Certifications

32.1	***		—	Certification of Curtis A. Morgan, principal executive officer of Vistra Energy 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 Energy 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 Energy Corp.'s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019 formatted in Inline XBRL (Extensible Business Reporting Language) includes: (i) the Condensed Statements of Consolidated Income, (ii) the Condensed Statements of Consolidated Comprehensive Income, (iii) the Condensed Statements of Consolidated 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

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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 Energy Corp.

	By:		/s/ CHRISTY DOBRY
	Name:		Christy Dobry
	Title:		Vice President and Controller
			(Principal Accounting Officer)

Date: November 5, 2019