Vistra Corp. - Quarter Report: 2018 September (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2018

— OR —

o 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)

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 x No o

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 x No o

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 Securities Exchange Act of 1934.

Large accelerated filer o Accelerated filer o Non-Accelerated filer x Smaller reporting company o Emerging growth company o

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. o

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

As of October 31, 2018, there were 504,446,340 shares of common stock, par value $0.01, outstanding of Vistra Energy Corp.

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		PAGE
GLOSSARY		ii
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Statements of Consolidated Income (Loss) — Three and Nine Months Ended September 30, 2018 and 2017	1
	Condensed Statements of Consolidated Comprehensive Income (Loss) — Three and Nine Months Ended September 30, 2018 and 2017	1
	Condensed Statements of Consolidated Cash Flows — Nine Months Ended September 30, 2018 and 2017	2
	Condensed Consolidated Balance Sheets — September 30, 2018 and December 31, 2017	3
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	59
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	87
Item 4.	Controls and Procedures	91
PART II.	OTHER INFORMATION	92
Item 1.	Legal Proceedings	92
Item 1A.	Risk Factors	92
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	92
Item 3.	Defaults Upon Senior Securities	92
Item 4.	Mine Safety Disclosures	93
Item 5.	Other Information	93
Item 6.	Exhibits	93
SIGNATURE		99

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. 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 or Homefield Energy 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.



2017 Form 10-K		Vistra Energy's annual report on Form 10-K for the year ended December 31, 2017, filed with the SEC on February 26, 2018, except for Part II, Items 7 and 8, which were amended in Vistra Energy's current report on Form 8-K filed with the SEC on June 15, 2018

ARO		asset retirement and mining reclamation obligation

CAA		Clean Air Act

CAISO		The California Independent System Operator

CCGT		combined cycle gas turbine

CFTC		U.S. Commodity Futures Trading Commission

CME		Chicago Mercantile Exchange

CO₂		carbon dioxide

Dynegy		Dynegy Inc., and/or its subsidiaries, depending on context

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.

FERC		U.S. Federal Energy Regulatory Commission

Fitch		Fitch Ratings Inc. (a credit rating agency)

GAAP		generally accepted accounting principles

GWh		gigawatt-hours

ICE		IntercontinentalExchange

IRS		U.S. Internal Revenue Service

ISO		Independent System Operator

ISO-NE		Independent System Operator New England

kW		kilowatt

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

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

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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.

MMBtu		million British thermal units

Moody's		Moody's Investors Service, Inc. (a credit rating agency)

MW		megawatts

MWh		megawatt-hours

NERC		North American Electricity Reliability Corporation

NRC		U.S. Nuclear Regulatory Commission

NYMEX		the New York Mercantile Exchange, a commodity derivatives exchange

NYISO		New York Independent System Operator

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

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

S&P		Standard & Poor's Ratings (a credit rating agency)

SEC		U.S. Securities and Exchange Commission

SG&A		selling, general and administrative

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 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

TDSP		transmission and distribution service provider

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)

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

iii

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Vistra Energy		Vistra Energy Corp. and/or its subsidiaries, depending on context

Vistra Operations Credit Facilities		Vistra Operations Company LLC's $8.328 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 (LOSS)

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Operating revenues (Note 5)	$	3,243		$	1,833		$	6,581		$	4,487
Fuel, purchased power costs and delivery fees	(1,627		)	(838		)	(3,492		)	(2,250		)
Operating costs	(346		)	(218		)	(926		)	(626		)
Depreciation and amortization	(426		)	(178		)	(967		)	(519		)
Selling, general and administrative expenses	(194		)	(147		)	(711		)	(434		)
Operating income	650			452			485			658
Other income (Note 20)	6			10			25			29
Other deductions (Note 20)	(1		)	—			(4		)	(5		)
Interest expense and related charges (Note 20)	(154		)	(76		)	(291		)	(169		)
Impacts of Tax Receivable Agreement (Note 8)	17			138			(65		)	96
Equity in earnings of unconsolidated investment	7			—			11			—
Income before income taxes	525			524			161			609
Income tax expense (Note 7)	(194		)	(251		)	(31		)	(284		)
Net income	$	331		$	273		$	130		$	325
Less: Net (income) loss attributable to noncontrolling interest	1			—			(2		)	—
Net income attributable to Vistra Energy	$	330		$	273		$	132		$	325
Weighted average shares of common stock outstanding:
Basic	533,142,189			427,591,426			500,781,573			427,587,404
Diluted	540,972,802			428,312,438			508,128,988			428,001,869
Net income per weighted average share of common stock outstanding:
Basic	$	0.62		$	0.64		$	0.26		$	0.76
Diluted	$	0.61		$	0.64		$	0.26		$	0.76

See Notes to the Condensed Consolidated Financial Statements.

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited) (Millions of Dollars)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018			2017
Net income	$	331	$	273	$	130		$	325
Other comprehensive income, net of tax effects:
Effect related to pension and other retirement benefit obligations (net of tax benefit of $— in all periods)	1		—		2			—
Total other comprehensive income	1		—		2			—
Comprehensive income	$	332	$	273	$	132		$	325
Less: Comprehensive (income) loss attributable to noncontrolling interest	1		—		(2		)	—
Comprehensive income attributable to Vistra Energy	$	331	$	273	$	134		$	325

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,
	2018			2017

Cash flows — operating activities:
Net income	$	130		$	325
Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:
Depreciation and amortization	1,070			621
Deferred income tax (benefit) expense, net	29			209
Unrealized net (gain) loss from mark-to-market valuations of commodities	207			(202		)
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps	(123		)	3
Accretion expense	37			43
Impacts of Tax Receivable Agreement (Note 8)	65			(96		)
Stock-based compensation (Note 17)	59			13
Other, net	64			41
Changes in operating assets and liabilities:
Margin deposits, net	(39		)	183
Accrued interest	(59		)	(26		)
Accrued taxes	(102		)	4
Accrued incentive plan	(17		)	(46		)
Other operating assets and liabilities	(458		)	(227		)
Cash provided by operating activities	863			845
Cash flows — financing activities:
Issuances of long-term debt (Note 11)	1,000			—
Repayments/repurchases of debt (Note 11)	(2,902		)	(32		)
Borrowing under accounts receivable securitization program (Note 10)	350			—
Stock repurchase (Note 13)	(414		)	—
Debt tender offer and other financing fees (Note 11)	(216		)	(5		)
Other, net	10			—
Cash used in financing activities	(2,172		)	(37		)
Cash flows — investing activities:
Capital expenditures	(209		)	(86		)
Nuclear fuel purchases	(66		)	(56		)
Cash acquired in the Merger	445			—
Solar development expenditures (Note 3)	(28		)	(129		)
Odessa acquisition (Note 3)	—			(355		)
Proceeds from sales of nuclear decommissioning trust fund securities (Note 20)	211			154
Investments in nuclear decommissioning trust fund securities (Note 20)	(227		)	(169		)
Other, net	7			10
Cash provided by (used in) investing activities	133			(631		)

Net change in cash, cash equivalents and restricted cash	(1,176		)	177
Cash, cash equivalents and restricted cash — beginning balance	2,046			1,588
Cash, cash equivalents and restricted cash — ending balance	$	870		$	1,765

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, 2018		December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	811	$	1,487
Restricted cash (Note 20)	59		59
Trade accounts receivable — net (Note 20)	1,243		582
Income taxes receivable	12		—
Inventories (Note 20)	393		253
Commodity and other derivative contractual assets (Note 15)	458		190
Margin deposits related to commodity contracts	177		30
Prepaid expense and other current assets	123		72
Total current assets	3,276		2,673
Restricted cash (Note 20)	—		500
Investments (Note 20)	1,357		1,240
Investment in unconsolidated subsidiary (Note 20)	135		—
Property, plant and equipment — net (Note 20)	14,756		4,820
Goodwill (Note 6)	1,907		1,907
Identifiable intangible assets — net (Note 6)	2,711		2,530
Commodity and other derivative contractual assets (Note 15)	265		58
Accumulated deferred income taxes	1,053		710
Other noncurrent assets	428		162
Total assets	$	25,888	$	14,600
LIABILITIES AND EQUITY
Current liabilities:
Accounts receivable securitization program (Note 10)	$	350	$	—
Long-term debt due currently (Note 11)	181		44
Trade accounts payable	812		473
Commodity and other derivative contractual liabilities (Note 15)	981		224
Margin deposits related to commodity contracts	4		4
Accrued income taxes	—		58
Accrued taxes other than income	139		136
Accrued interest	123		16
Asset retirement obligations (Note 20)	183		99
Other current liabilities	329		297
Total current liabilities	3,102		1,351
Long-term debt, less amounts due currently (Note 11)	11,060		4,379
Commodity and other derivative contractual liabilities (Note 15)	254		102
Accumulated deferred income taxes	5		—
Tax Receivable Agreement obligation (Note 8)	402		333
Asset retirement obligations (Note 20)	2,139		1,837
Identifiable intangible liabilities — net (Note 6)	175		36
Other noncurrent liabilities and deferred credits (Note 20)	346		220
Total liabilities	17,483		8,258

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

	September 30, 2018			December 31, 2017
Commitments and Contingencies (Note 12)
Total equity (Note 13):
Common stock (par value — $0.01; number of shares authorized — 1,800,000,000) (shares outstanding: September 30, 2018 — 507,391,134; December 31, 2017 — 428,398,802)	5			4
Additional paid-in-capital	9,670			7,765
Retained deficit	(1,261		)	(1,410		)
Accumulated other comprehensive income	(15		)	(17		)
Stockholders' equity	8,399			6,342
Noncontrolling interest in subsidiary	6			—
Total equity	8,405			6,342
Total liabilities and equity	$	25,888		$	14,600

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 electricity market activities including power generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity 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. The Asset Closure segment was established as of January 1, 2018, and we have recast prior period information to reflect this change in reportable segments. See Note 19 for further information concerning reportable business segments.

Merger Transaction

On the Merger Date, Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement entered into in October 2017. 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 2017 Form 10-K, with the exception of the changes in reportable segments as detailed above. 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 2017 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. dollars unless otherwise indicated.

Use of Estimates

Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements, estimates of expected obligations, 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.

Unconsolidated Investments

We use the equity method of accounting for investments in affiliates over which we exercise significant influence. Our share of net income (loss) from these affiliates is recorded to equity in earnings (loss) of unconsolidated investment in the condensed statements of consolidated net income (loss). We use the cost method of accounting where we do not exercise significant influence. See Note 20.

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Noncontrolling Interest

Noncontrolling interest is comprised of the 20% of Electric Energy, Inc. (EEI) that we do not own. EEI is our consolidated subsidiary that owns a coal facility in Joppa, Illinois. This noncontrolling interest is classified as a component of equity separate from stockholders' equity in the condensed consolidated balance sheets.

Treasury Stock

Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock, which is presented in our condensed consolidated balance sheets as a reduction to additional paid-in capital. See Note 13.

Adoption of New Accounting Standards

Revenue from Contracts with Customers — On January 1, 2018, we adopted Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606) and all related amendments (new revenue standard) using the modified retrospective method for all contracts outstanding at the time of adoption. We recognized the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The impact of the adoption of the new revenue standard was immaterial and we expect the adoption to continue to be immaterial to our net income on an ongoing basis. Our retail energy charges and wholesale generation, capacity and contract revenues will continue to be recognized when electricity and other services are delivered to our customers. The impact of adopting the new revenue standard primarily relates to the deferral of acquisition costs associated with retail contracts with customers that were previously expensed as incurred. Under the new revenue standard, these amounts will be capitalized and amortized over the expected life of the customer.

As of January 1, 2018, the cumulative effect of the changes made to our condensed consolidated balance sheet for the adoption of the new revenue standard was as follows:



	December 31, 2017			Adoption of New Revenue Standard			January 1, 2018
Impact on condensed consolidated balance sheet:
Assets
Prepaid expense and other current assets	$	72		$	5		$	77
Accumulated deferred income taxes	$	710		$	(4	)	$	706
Other noncurrent assets	$	162		$	16		$	178
Equity
Retained deficit	$	(1,410	)	$	17		$	(1,393	)

The disclosure of the impact of adoption on our condensed statement of consolidated income (loss) and condensed consolidated balance sheet was as follows:



	Three Months Ended September 30, 2018								Nine Months Ended September 30, 2018
	As Reported			Amount Without Adoption of New Revenue Standard			Effect of Change Higher (Lower)		As Reported			Amount Without Adoption of New Revenue Standard			Effect of Change Higher (Lower)
Impact on condensed statement of consolidated income (loss):
Operating revenues	$	3,243		$	3,242		$	1	$	6,581		$	6,578		$	3
Selling, general and administrative expenses	(194		)	(196		)	2		(711		)	(720		)	9
Net income (loss)	331			328			3		130			121			9

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	September 30, 2018
	As Reported			Balances Without Adoption of New Revenue Standard			Effect of Change Higher (Lower)
Impact on condensed consolidated balance sheet:
Assets
Prepaid expense and other current assets	$	123		$	116		$	7
Accumulated deferred income taxes	1,053			1,057			(4		)
Other noncurrent assets	428			403			25
Equity
Retained deficit	$	(1,261	)	$	(1,287	)	$	26

See Note 5 for the disclosures required by the new revenue standard.

Statement of Cash Flows — In November 2016, the FASB issued ASU 2016-18 Statement of Cash Flows (Topic 230): Restricted Cash. The ASU requires restricted cash to be included in the cash and cash equivalents and a reconciliation between the change in cash and cash equivalents and the amounts presented on the balance sheet (see Note 20). We adopted the standard on January 1, 2018. The ASU modified our presentation of our condensed statements of consolidated cash flows, and retrospective application to comparative periods presented was required. For the nine months ended September 30, 2017, our condensed statement of consolidated cash flows previously reflected a source of cash of $34 million reported as changes in restricted cash that is now reported in net change in cash, cash equivalents and restricted cash. See the condensed statements of consolidated cash flows and Note 20 for disclosures related to the adoption of this accounting standard.

Changes in Accounting Standards

In February 2016, the Financial Accounting Standards Board (FASB) issued ASU 2016-02, Leases. The ASU amends previous GAAP to require the recognition of lease assets and liabilities for operating leases. The ASU will be effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Retrospective application to comparative periods presented will be required in the year of adoption. We have identified the contracts that are within the scope of this ASU and are currently evaluating the impact of this ASU on our financial statements.

In August 2018, the 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 2018-14, Changes to the Disclosure Requirements for Defined Benefit Plans. The ASU will be effective for fiscal years beginning after December 15, 2020 and early adoption is permitted. The ASU removes disclosure requirements for (a) the amounts in accumulated other comprehensive income expected to be recognized as components of net periodic benefit cost over the next fiscal year, (b) related party disclosures about the amount of future annual benefits covered by insurance and annuity contracts and significant transactions between the employer or related parties and the plan and (c) the effects of a one-percentage-point change in assumed health care cost trend rates on the aggregate of the service and interest cost components of net periodic benefit costs and benefit obligation for postretirement health care benefits. The ASU will require new disclosures for (a) the weighted-average interest crediting rates for cash balance plans and other plans with promised interest crediting rates and (b) an explanation of the reasons for significant gains and losses related to changes in the benefit obligation for the period. We are currently evaluating the impact of this ASU on our disclosures.

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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.

2. MERGER TRANSACTION AND BUSINESS COMBINATION ACCOUNTING

Merger Transaction

On the Merger Date, Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement entered into in October 2017. Pursuant to the Merger Agreement, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the surviving corporation. The Merger is 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 will 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.

Business Combination Accounting

We believe the Merger provides a number of significant potential strategic benefits and opportunities to Vistra Energy, including increased scale and market diversification, rebalanced asset portfolio and improved earnings and cash flow. The Merger 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 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 preliminary fair value of the identifiable assets and liabilities, as well as their classification within the fair value hierarchy (see Note 14), is listed below:


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


•	Acquired 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 14 (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 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 preliminary 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 preliminary purchase price was approximately $2.3 billion. The preliminary values included below represent our current best estimates for property plant and equipment, identifiable intangible assets and liabilities, inventories, asset retirement obligations and deferred taxes. The purchase price allocation is preliminary and each of these may change materially based upon the receipt of more detailed information, additional analyses and completed valuations. The purchase price allocation is ongoing and is dependent upon final valuation determinations, which have not been completed. During the three months ended September 30, 2018, we updated the initial purchase price allocation with revised valuation estimates by increasing property, plant and equipment by $44 million, increasing intangible assets by $76 million, decreasing inventory by $37 million, decreasing accumulated deferred tax asset by $19 million, decreasing other noncurrent assets by $106 million, decreasing other noncurrent liabilities by $47 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. We currently expect the final purchase price allocation will be completed no later than the second quarter of 2019.



Dynegy shares outstanding as of April 9, 2018 (in millions)	173
Exchange Ratio	0.652
Vistra Energy shares issued for Dynegy shares outstanding (in millions)	113
Opening price of Vistra Energy common stock on April 9, 2018	$	19.87
Purchase price for common stock	$	2,245
Fair value of outstanding stock compensation awards attributable to pre-combination service	$	26
Fair value of outstanding warrants	$	2
Total purchase price	$	2,273



Preliminary Purchase Price Allocation
Cash and cash equivalents	$	445
Trade accounts receivables, inventories, prepaid expenses and other current assets	826
Property, plant and equipment	10,406
Accumulated deferred income taxes	372
Identifiable intangible assets	463
Other noncurrent assets	426
Total assets acquired	12,938
Trade accounts payable and other current liabilities	645
Commodity and other derivative contractual assets and liabilities, net	422
Asset retirement obligations, including amounts due currently	426
Long-term debt, including amounts due currently	8,920
Other noncurrent liabilities	245
Total liabilities assumed	10,658
Identifiable net assets acquired	2,280
Noncontrolling interest in subsidiary	7
Total purchase price	$	2,273

Acquisition costs incurred in the Merger totaled $25 million for the nine months ended September 30, 2018. For the period from the Merger Date through September 30, 2018, our condensed statements of consolidated income (loss) include revenues and net income (loss) acquired in the Merger totaling $2.684 billion and $193 million, respectively.

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Unaudited Pro Forma Financial Information — The following unaudited pro forma financial information for the nine months ended September 30, 2018 and 2017 assumes that the Merger occurred on January 1, 2017. The unaudited pro forma financial information is provided for information purposes only and is not necessarily indicative of the results of operations that would have occurred had the Merger been completed on January 1, 2017, 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			2017
Revenues	$	8,032		$	8,542
Net income (loss)	$	(64	)	$	316
Net income (loss) attributable to Vistra Energy	$	(61	)	$	318
Net income (loss) attributable to Vistra Energy per weighted average share of common stock outstanding — basic	$	(0.12	)	$	0.56
Net income (loss) attributable to Vistra Energy per weighted average share of common stock outstanding — diluted	$	(0.12	)	$	0.56

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 (benefit), changes in the expected impacts of the tax receivable agreement due to the Merger, and other related adjustments.

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3.	ACQUISITION AND DEVELOPMENT OF GENERATION FACILITIES

Odessa Acquisition

In August 2017, La Frontera Holdings, LLC (La Frontera), an indirect, wholly owned subsidiary of Vistra Energy, purchased a 1,054 MW CCGT natural gas fueled generation plant (and other related assets and liabilities) located in Odessa, Texas (Odessa Facility) from Odessa-Ector Power Partners, L.P., an indirect, wholly owned subsidiary of Koch Ag & Energy Solutions, LLC (Koch) (altogether, the Odessa Acquisition). La Frontera paid an aggregate purchase price of approximately $355 million, plus a five-year earn-out provision, to acquire the Odessa Facility. The purchase price was funded by cash on hand.

The Odessa Acquisition was accounted for as an asset acquisition. Substantially all of the approximately $355 million purchase price was assigned to property, plant and equipment in our consolidated balance sheet. Additionally, the initial fair value associated with an earn-out provision of approximately $16 million was included as consideration in the overall purchase price. The earn-out provision requires cash payments to be made to Koch if spark-spreads related to the pricing point of the Odessa Facility exceed certain thresholds. Subsequent to the acquisition, the earn-out provision has been accounted for as a derivative in our consolidated financial statements, and partial buybacks of the earn-out provision were settled in February and May 2018.

Upton Solar Development

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). As part of this project, we entered a turnkey engineering, procurement and construction agreement to construct the approximately 180 MW facility. During 2017 and 2018, we spent approximately $218 million related to this project primarily for payments under the engineering, procurement and construction agreement. The facility began test operations in March 2018 and commercial operations began in June 2018.

Battery Energy Storage Projects

In October 2018, we were awarded a $1 million grant from the TCEQ for our battery energy storage system at Upton solar facility. The grant is part of the Texas Emissions Reduction Plan. The 10 MW lithium-ion energy storage system will capture excess solar energy produced during the day and release the energy in late afternoon and early evening, when demand is highest. We expect the project to be operational in late 2018.

In June 2018, we announced that, subject to approval by the California Public Utilities Commission (CPUC), we will enter into a 20-year resource adequacy contract with Pacific Gas and Electric Company (PG&E) to develop a 300 MW battery energy storage project at our Moss Landing Power Plant site in California. In late June 2018, PG&E filed its application with the CPUC to approve the contract, and a decision is expected in the fourth quarter of 2018. Pending the receipt of CPUC approval, we anticipate the battery storage project will enter commercial operations by the fourth quarter of 2020.

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4.	RETIREMENT OF GENERATION FACILITIES

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 waste coal facility in McAddo, Pennsylvania. We decided to retire this facility due to its uneconomic operations and financial outlook. Following the receipt of regulatory approvals, the facility is expected to close in late 2018. The decision to retire this facility did not result in a material impact to the financial statements.

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

In January and February 2018, we retired three power plants 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 both the three and nine months ended September 30, 2018. The operational results of these facilities are included in our Asset Closure segment. 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

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5.	REVENUE

The following tables disaggregate our revenue by major source:



	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	—			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 19 for unrealized net gains (losses) by segment.



	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	—			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:
Retail contract 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 19 for unrealized net gains (losses) by segment.

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Retail Energy Charges

Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes delivered or services provided. Sales tax is excluded from revenue. Payment terms vary from 15 to 45 days from invoice date. Revenue is recognized over-time using the output method based on kilowatt hours delivered. Energy charges are delivered as a series of distinct services and are accounted for as a single performance obligation.

Wholesale Generation Revenue from ISOs

Revenue is recognized when volumes are delivered to the ISO. Revenue is recognized over time using the output method based on kilowatt hours delivered and cash is settled within 10 days of invoicing. Vistra Energy operates as a market participant within ERCOT, PJM, NYISO, ISO-NE, MISO and CAISO and expects to continue to remain under contract with each ISO indefinitely. Wholesale generation revenues are delivered as a series of distinct services and are accounted for as a single performance obligation.

Capacity Revenue

Revenues are recognized when the performance obligation is satisfied ratably over time in accordance with the contracts as our power generation facilities stand ready to deliver power to the customer. We provide capacity to customers through participation in capacity auctions held by the ISO or through bilateral sales. Generation facilities are awarded auction volumes through the ISO auction and bilateral sales are based on executed contracts with customers.

Revenue from Other Wholesale Contracts

Other wholesale contracts include other revenue activity with the ISOs, such as ancillary services, auction revenue, neutrality revenue and revenue from nonaffiliated retail electric providers. Revenue is recognized when the service is performed. Revenue is recognized over time using the output method based on kilowatt hours delivered or other applicable measurements, and cash settles as invoiced. Vistra Energy operates as a market participant within ERCOT, PJM, NYISO, ISO-NE, MISO and CAISO and expects to continue to remain under contract with each ISO indefinitely. Other wholesale contracts are delivered as a series of distinct services and are accounted for as a single performance obligation.

Contract and Other Customer Acquisition Costs

We defer costs to acquire retail contracts and amortize these costs over the expected life of the contract. The expected life of a retail contract is calculated using historical attrition rates, which we believe to be an accurate indicator of future attrition rates. The deferred acquisition and contract cost balance as of September 30, 2018 and January 1, 2018 was $34 million and $22 million, respectively. The amortization related to these costs during the three and nine months ended September 30, 2018 totaled $3 million and $7 million, respectively, recorded as selling, general and administrative expenses, and $2 million and $5 million, respectively, recorded as a reduction to operating revenues in the condensed statement of consolidated income (loss).

Practical Expedients

The vast majority of revenues are recognized under the right to invoice practical expedient, which allows us to recognize revenue in the same amount that we invoice our customers. We do not disclose the value of unsatisfied performance obligations for contracts with variable consideration for which we recognize revenue using the right to invoice practical expedient. We use the portfolio approach in evaluating similar customer contracts with similar performance obligations. Sales taxes are not included in revenue.

Performance Obligations

As of September 30, 2018, 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 through bilateral sales. Therefore, an obligation exists as of the date of the results of the respective ISO 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 $311 million, $966 million, $718 million, $720 million and $342 million that will be recognized in the years ending December 31, 2018, 2019, 2020, 2021 and 2022, respectively, and $103 million thereafter. Capacity revenue are recognized as capacity services are provided to the related ISOs.

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Accounts Receivable

The following table presents trade accounts receivable relating to both contracts with customers and other activities:



	September 30, 2018
Trade accounts receivable from contracts with customers — net	$	1,135
Other trade accounts receivable — net	108
Total trade accounts receivable — net	$	1,243


6.	GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

Goodwill

The carrying value of goodwill totaling $1.907 billion at both September 30, 2018 and December 31, 2017 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 and liabilities are comprised of the following:



	September 30, 2018						December 31, 2017
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	1,681	$	799	$	882	$	1,648	$	572	$	1,076
Software and other technology-related assets	239		80		159		183		47		136
Retail and wholesale contracts	445		123		322		154		87		67
Contractual service agreements	72		—		72		—		—		—
Other identifiable intangible assets (a)	40		14		26		33		11		22
Total identifiable intangible assets subject to amortization	$	2,477	$	1,016	1,461		$	2,018	$	717	1,301
Retail trade names (not subject to amortization)					1,246						1,225
Mineral interests (not currently subject to amortization)					4						4
Total identifiable intangible assets					$	2,711					$	2,530
______________
(a) Includes mining development costs and environmental allowances and credits.

Identifiable Intangible Liability									September 30, 2018		December 31, 2017
Contractual service agreements									$93		$0
Purchase and sales contracts									46		36
Environmental allowances									36		—
Total identifiable intangible liabilities									$	175	$	36

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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 (loss)) consisted of:



Identifiable Intangible Assets and Liabilities	Condensed Statements of Consolidated Income (Loss) Line	Three Months Ended September 30,						Nine Months Ended September 30,
Identifiable Intangible Assets and Liabilities	Condensed Statements of Consolidated Income (Loss) Line	2018			2017			2018		2017
Retail customer relationship	Depreciation and amortization	$	77		$	105		$	227	$	315
Software and other technology-related assets	Depreciation and amortization	6			10			36		27
Retail and wholesale contracts/purchase and sales contracts	Operating revenues/fuel, purchased power costs and delivery fees	(5		)	(19		)	28		27
Other identifiable intangible assets	Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization	10			5			14		14
Total amortization expense (a)		$	88		$	101		$	305	$	383

____________


(a)	Amounts recorded in depreciation and amortization totaled $84 million and $116 million for the three months ended September 30, 2018 and 2017, respectively, and $266 million and $347 million for the nine months ended September 30, 2018 and 2017, respectively.

Following is a description of the separately identifiable intangible assets and liabilities recorded in connection with the Merger (see Note 2) that were adjusted based on their estimated fair value as of the Merger Date, based on observable prices or estimates of fair value using valuation models. The purchase price allocation is ongoing and is dependent upon final valuation determinations, which have not been completed.

•

Retail customer relationship – The acquired retail customer relationship intangible asset represents the estimated fair value of our non-contracted Northeast/Midwest retail customer base, including residential and business customers, and is being amortized using an accelerated method based on historical customer attrition rates and reflecting the expected pattern in which economic benefits are realized over their estimated useful life.

•

Retail trade names – Our acquired retail trade name intangible asset represents the fair value of the Homefield and Dynegy Energy Services trade names and was determined to be an indefinite-lived asset not subject to amortization. This intangible asset will be evaluated for impairment at least annually in accordance with accounting guidance related to goodwill and other indefinite-lived intangible assets.

•

Retail and wholesale contracts/purchase and sales contracts – Our acquired retail and wholesale contracts and purchase and sales contracts represent various types of customer and supplier contracts, including municipal supplier contracts, capacity contracts, gas transportation contracts, and other contracts. The contracts were identified as either assets or liabilities based on the respective fair values at the time of the Merger utilizing prevailing market prices for commodities or services compared to fixed prices contained in these agreements. The intangible assets and liabilities are being amortized in relation to the economic terms of the related contracts.

•

Contractual service agreements – Our acquired contractual service agreements represent the estimated fair value of favorable or unfavorable contract obligations with respect to long-term plant maintenance agreements and are being amortized based on the expected usage of the service agreements over the contract terms. For the portion of the services that relate to capital improvements, the amortization of the contractual services agreements is recorded to property, plant and equipment.

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Estimated Amortization of Identifiable Intangible Assets and Liabilities

As of September 30, 2018, 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
2018	$	402
2019	$	331
2020	$	250
2021	$	180
2022	$	111


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,
	2018			2017			2018			2017
Income before income taxes	$	525		$	524		$	161		$	609
Income tax expense	$	(194	)	$	(251	)	$	(31	)	$	(284	)
Effective tax rate	37.0		%	47.9		%	19.3		%	46.6		%

For the three months ended September 30, 2018, the effective tax rate of 37.0% 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 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 expense 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.

For the three months ended September 30, 2017, the effective tax rate of 47.9% related to our income tax expense was higher than the U.S. federal statutory rate of 35% due primarily to nondeductible impacts of the TRA and the Texas margin tax and a reduction in the tax basis of certain of our assets based on the finalization of tax returns related to the pre-Emergence period. For the nine months ended September 30, 2017, the effective tax rate of 46.6% related to our income tax expense was higher than the U.S. federal statutory rate of 35% due primarily to nondeductible impacts of the TRA and the Texas margin tax and a reduction in the tax basis of certain of our assets based on the finalization of tax returns related to the pre-Emergence period.

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 has limited operational history and filed its first federal tax return in October 2017. Vistra Energy is not currently under audit for any period. Uncertain tax positions totaling $41 million at September 30, 2018 arose in connection with the Merger and our assessment of the assumed liabilities is not complete as discussed in Note 2. We had no uncertain tax positions at December 31, 2017.

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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 our predecessor. 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 subject to various transfer restrictions described in the TRA and are entitled to certain registration rights more fully described in the Registration Rights Agreement (see Note 18).

During the three months ended September 30, 2018, we recorded a decrease to the carrying value of the TRA obligation totaling $32 million related to changes in the timing of estimated payments resulting from the Merger. During the nine months ended September 30, 2018, the carrying value of the TRA obligation was increased by approximately $14 million as a result of changes in the timing of estimated payments and new multistate tax impacts resulting from the Merger. During the three months ended September 30, 2017, we recorded a decrease to the carrying value of the TRA obligation totaling $160 million related to changes in the timing of estimated payments resulting from changes in certain tax assumptions including (a) the impacts of Luminant's plan to retire its Monticello generation plant (see Note 4), (b) investment tax credits we expected to receive related to the Upton solar development project, (c) assets acquired in the Odessa Acquisition (see Note 3) and (d) the impacts of other forecasted tax amounts.

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, 2018 and 2017:



	Nine Months Ended September 30,
	2018			2017
TRA obligation at the beginning of the period	$	357		$	596
Accretion expense	51			64
Changes in tax assumptions impacting timing of payments	14			(160		)
TRA obligation at the end of the period	422			500
Less amounts due currently	(20		)	(24		)
Noncurrent TRA obligation at the end of the period	$	402		$	476

As of September 30, 2018, the estimated carrying value of the TRA obligation totaled $422 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% for 2018 and 35% for 2017, (b) estimates of our taxable income in the current and future years and (c) additional states that Vistra Energy now operates in, its relevant tax rate and apportionment factor. 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, 2018, the aggregate amount of undiscounted federal and state payments under the TRA is estimated to be approximately $1.4 billion, with more than half of such amount expected to be attributable to the first 15 tax years following Emergence, and the final payment expected to be made approximately 40 years following Emergence (assuming that 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. During the three and nine months ended September 30, 2018, the Impacts of Tax Receivable Agreement on the condensed statements of consolidated income (loss) totaled income of $17 million and expense of $65 million, respectively, which represents the changes to the carrying value of the TRA obligation discussed above and accretion expense totaling $15 million and $51 million, respectively. During the three and nine months ended September 30, 2017, the Impacts of Tax Receivable Agreement on the condensed statements of consolidated income (loss) totaled income of $138 million and $96 million, respectively, which represents a decrease to the carrying value of the TRA obligation discussed above and accretion expense totaling $22 million and $64 million, respectively.

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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, 2018					Three Months Ended September 30, 2017
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Net income available for common stock — basic (a)	$	330	533,142,189	$	0.62	$	273	427,591,426	$	0.64
Dilutive securities:
Stock-based incentive compensation plan	—		7,830,613	0.01		—		721,012	—
Net income available for common stock — diluted	$	330	540,972,802	$	0.61	$	273	428,312,438	$	0.64

	Nine Months Ended September 30, 2018					Nine Months Ended September 30, 2017
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Net income available for common stock — basic (a)	$	132	500,781,573	$	0.26	$	325	427,587,404	$	0.76
Dilutive securities:
Stock-based incentive compensation plan	—		7,347,415	—		—		414,465	—
Net income available for common stock — diluted	$	132	508,128,988	$	0.26	$	325	428,001,869	$	0.76

____________


(a)	The minimum settlement amount of tangible equity units, or 15,056,260 shares, are considered to be outstanding and are included in the computation of basic net income per share (see Note 13).

Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 7,094,687 and 85,393 shares in the three months ended September 30, 2018 and 2017, respectively, and 5,651,527 and 490,345 shares in the nine months ended September 30, 2018 and 2017, 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 is currently scheduled to terminate in August 2019, unless termination occurs earlier in accordance with the terms of the Receivables Facility. The Receivables Facility provides RecCo with the ability to borrow up to $350 million.

Under the Receivables Facility, TXU Energy may sell or contribute, on an ongoing basis and without recourse, its accounts receivable to its 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 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, 2018, the receivables facility is fully drawn and is supported by $587 million of RecCo gross receivables.


11.	LONG-TERM DEBT

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



	September 30, 2018			December 31, 2017
Vistra Operations Credit Facilities	$	5,828		$	4,311
Vistra Operations 5.500% Senior Notes, due September 1, 2026	1,000			—
Vistra Energy Senior Notes:
7.375% Senior Notes, due November 1, 2022	1,750			—
5.875% Senior Notes, due June 1, 2023	500			—
7.625% Senior Notes, due November 1, 2024	1,224			—
8.034% Senior Notes, due February 2, 2024	25			—
8.000% Senior Notes, due January 15, 2025	81			—
8.125% Senior Notes, due January 30, 2026	166			—
Total Vistra Energy Senior Notes	3,746			—
Other:
7.000% Amortizing Notes, due July 1, 2019	31			—
Forward Capacity Agreements	238			—
Equipment Financing Agreements	136			—
Mandatorily redeemable subsidiary preferred stock (a)	70			70
8.82% Building Financing due semiannually through February 11, 2022 (b)	21			27
Total other long-term debt	496			97
Unamortized debt premiums, discounts and issuance costs	171			15
Total long-term debt including amounts due currently	11,241			4,423
Less amounts due currently	(181		)	(44		)
Total long-term debt less amounts due currently	$	11,060		$	4,379

____________


(a)	Shares of mandatorily redeemable preferred stock in PrefCo issued as part of the Plan of Reorganization. This subsidiary preferred stock is accounted for as a debt instrument under relevant accounting guidance.


(b)	Obligation related to a corporate office space capital 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.

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Vistra Operations Credit Facilities

At September 30, 2018, the Vistra Operations Credit Facilities consisted of up to $8.328 billion in senior secured, first lien revolving credit commitments and outstanding term loans, consisting of revolving credit commitments of up to $2.5 billion, including a $2.3 billion letter of credit sub-facility (Revolving Credit Facility) and term loans of $2.8 billion (Term Loan B-1 Facility), $983 million (Term Loan B-2 Facility) and $2.045 billion (Term Loan B-3 Facility, and together with the Term Loan B-1 Facility and the Term Loan B-2 Facility, the Term Loan B Facility).

These amounts 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 condensed statements of consolidated income (loss), $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, 2018 are presented below.



		September 30, 2018
Vistra Operations Credit Facilities	Maturity Date	Facility Limit		Cash Borrowings		Available Capacity
Revolving Credit Facility (a)	June 14, 2023	$	2,500	$	—	$	1,290
Term Loan B-1 Facility (b)	August 4, 2023	2,800		2,800		—
Term Loan B-2 Facility (b)	December 14, 2023	983		983		—
Term Loan B-3 Facility (b)	December 31, 2025	2,045		2,045		—
Total Vistra Operations Credit Facilities		$	8,328	$	5,828	$	1,290

___________


(a)	Facility to be used for general corporate purposes. Facility includes a $2.3 billion letter of credit sub-facility, of which $1.210 billion of letters of credit were outstanding at September 30, 2018 and which reduce our available capacity.


(b)	Cash borrowings under the Term Loan B Facility reflect required scheduled quarterly payment in annual amount equal to 1% of the original principal amount with the balance paid at maturity. Principal amounts paid cannot be reborrowed.

In February and June 2018, certain pricing terms for the Vistra Operations Credit Facilities were amended. We accounted for these transactions as a modification of debt. At September 30, 2018, 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 Facility bear interest based on applicable LIBOR rates plus a fixed spread of 2.00%. Amounts borrowed under the Term Loan B-2 Facility bear interest based on applicable LIBOR rates plus a fixed spread of 2.25%. Amounts borrowed under the Term Loan B-3 Facility bear interest based on applicable LIBOR rates plus a fixed spread of 2.00%. At September 30, 2018, the weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings were 4.24%, 4.49% and 4.18% under the Term Loan B-1, B-2 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 Revolving Credit Facility.

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

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

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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. As of September 30, 2018, we were in compliance with this financial covenant. Upon the existence of an event of default, the Vistra Operations Credit Facilities provide that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.

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 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 of Vistra Energy (legacy Dynegy) interest rate swaps to Vistra Operations Company LLC (Vistra Operations). In June 2018, $238 million of these interest rate swaps expired. The remaining interest rate swaps expire between March 2019 and February 2024.

The interest rate swaps effectively fix the interest rates between 4.13% and 4.38% on $4.718 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.

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 Notes

In August 2018, Vistra Operations issued $1.0 billion principal amount of 5.500% senior notes due 2026 in an offering to eligible purchasers. The senior 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 $12 million in the three months ended September 30, 2018, which was capitalized as a reduction in the carrying amount of the debt. Net proceeds from the sale of the senior notes 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 cash 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.

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The indenture governing the 5.500% senior notes provides for the full and unconditional guarantee by certain direct and indirect subsidiaries of Vistra Operations of the punctual payment of the principal and interest on the notes. The Indenture contains 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 Notes


•	$26 million of 7.625% senior notes due 2024;


•	$163 million of 8.034% senior notes due 2024;


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


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

In connection with the Tender Offers, Vistra Energy also commenced solicitations of consents from holders of the 7.375% senior notes due 2022, the 7.625% senior notes due 2024, the 8.034% senior notes due 2024, the 8.000% senior notes due 2025 and the 8.125% senior notes due 2026 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 due 2026. Vistra Energy received the requisite consents from the holders of the 8.034% senior notes due 2024, the 8.000% senior notes due 2025 and the 8.125% senior notes due 2026 (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 due 2026 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 notes. In May 2018, $850 million of outstanding 6.75% senior notes due 2019 were redeemed at a redemption price of 101.688% of the aggregate principal amount, plus accrued and unpaid interest 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 (loss). 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.

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 21). The respective indentures of the senior notes (except with respect to the Consent Senior Notes) 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 respective indentures of the senior notes 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 amortizing note (Amortizing Notes) maturing on July 1, 2019. The Amortizing Notes were issued in connection with the issuance of the tangible equity units (TEUs) by Dynegy (see Note 13). Each installment payment per Amortizing Note will be paid in cash and will constitute a partial repayment of principal and a payment of interest, computed at an annual rate of 7.00%. Interest will be calculated on the basis of a 360-day year consisting of twelve 30-day months. Payments will be 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.

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The indenture for the Amortizing Notes limits, among other things, the ability of the Company to consolidate, merge, sell, or dispose all or substantially all of its assets. If a fundamental change occurs, or if the Company elects to settle the prepaid stock purchase contracts early, then the holders of the Amortizing Notes will have the right to require the Company to repurchase the Amortizing Notes at a repurchase price equal to the principal amount of the Amortizing Notes as of the repurchase date (as described in the supplemental indenture) plus accrued and unpaid interest. The indenture also contains customary events of default which would permit the holders of the Amortizing Notes to declare those Amortizing Notes to be immediately due and payable if not cured within applicable grace periods, including the failure to make timely installment payments on the Amortizing Notes or other material indebtedness aggregating $100 million or more, the failure to satisfy covenants, and specified events of bankruptcy and insolvency.

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 2018-2019, 2019-2020 and 2020-2021 in the amounts of $7 million, $121 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 $238 million with an implied interest rate of 4.90%.

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.

Maturities

Long-term debt maturities at September 30, 2018 are as follows:



	September 30, 2018
Remainder of 2018	$	54
2019	182
2020	204
2021	130
2022	1,824
Thereafter	8,676
Unamortized premiums, discounts and debt issuance costs	171
Total long-term debt, including amounts due currently	$	11,241

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12.	COMMITMENTS AND CONTINGENCIES

Guarantees

We have entered into contracts, including the assumed Dynegy senior notes described above, that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. As of September 30, 2018, 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, 2018, we had outstanding letters of credit under the Vistra Operations Credit Facilities totaling $1.210 billion as follows:


•	$1.030 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;


•	$52 million to support executory contracts and insurance agreements;


•	$55 million to support our REP financial requirements with the PUCT, and


•	$73 million for other credit support requirements.

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. Four of the cases are putative class actions and one case, Reorganized FLI (nka J.P. Morgan Trust Co., National Assn.) v. Oneok Inc., et al., is an individual action on behalf of Farmland Industries, Inc. (Farmland), with Farmland seeking full consideration damages (i.e., the full amount it paid for natural gas purchases during the relevant timeframe). The cases are consolidated in a multi-district litigation proceeding pending in the U. S. District Court for Nevada. In March 2017, the court denied the class plaintiffs' motions to certify class actions in each of the states, which decision was taken on an interlocutory appeal to U.S Court of Appeals for the Ninth Circuit (Ninth Circuit Court). In August 2018, the Ninth Circuit Court vacated the district court orders denying class certification and remanded the cases to the district court for further consideration of the class certification issue. In September 2018, the defendants filed a joint motion for entry of an order denying class certification, and the plaintiffs filed a motion for remand of the cases to the transferor courts to decide class certification issues. As for the Farmland matter, in March 2018, the Ninth Circuit Court reversed a summary judgment in favor of the defendants and it shortly will be remanded for further discovery and other pretrial proceedings. 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.

Advatech Dispute — In September 2016, Illinois Power Generating Company (Genco), terminated its Second Amended and Restated Newton Flue Gas Desulfurization System Engineering, Procurement, Construction and Commissioning Services Contract dated as of December 15, 2014 with Advatech, LLC (Advatech). Advatech issued Genco its final invoice in September 2016 totaling $81 million. Genco contested the invoice in October 2016 and believes the proper amount is less than $1 million. In October 2016, Advatech initiated the dispute resolution process under the contract and filed for arbitration in March 2017. Settlement discussions required under the dispute resolution process were unsuccessful. The arbitration hearing occurred in October 2018. We dispute the allegations. 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.

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.

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Greenhouse Gas Emissions

In August 2015, the EPA finalized rules to address greenhouse gas emissions from new, modified and reconstructed and existing 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 (including Luminant) 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 states, industry (including Luminant) and other parties filed applications with the U.S. Supreme Court (Supreme Court) asking that the Supreme Court stay the rule while the D.C. Circuit Court reviews the legality of the rule for existing plants. In February 2016, the Supreme Court stayed the rule pending the conclusion of legal challenges on the rule before the D.C. Circuit Court and until the Supreme Court disposes of any subsequent petition for review. Oral argument on the merits of the legal challenges to the rule was heard in September 2016 before the entire D.C. Circuit Court, but the D.C. Circuit Court has not issued a decision. The D.C. Circuit Court's most-recent 60-day abeyance of the case expired in August 2018.

In October 2017, the EPA issued a proposed rule that would repeal the Clean Power Plan, with the proposed repeal focusing on what the EPA believes to be the unlawful nature of the Clean Power Plan and asking for public comment on the EPA's interpretations of its authority under the Clean Air Act. In December 2017, the EPA published an advance notice of proposed rulemaking (ANPR) soliciting information from the public as the EPA considers proposing a future rule. Vistra Energy submitted comments on the ANPR in February 2018. Vistra Energy submitted comments to the proposed repeal in April 2018. In August 2018, the EPA published a proposed replacement rule called the Affordable Clean Energy rule. Comments on the proposed rule are due in October 2018. While we cannot predict the outcome of these rulemakings and related legal proceedings, or estimate a range of reasonably probable costs, if the rules are ultimately implemented or upheld as they were issued, they 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 generating 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, Luminant and a number of other parties, including 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 filed by Luminant and the other parties pending final review of the petitions for review. In December 2016, the EPA filed a motion seeking a voluntary remand of the rule back to the EPA for further consideration of Luminant's pending request for administrative reconsideration. In March 2017, the Fifth Circuit Court remanded the rule back to the EPA for reconsideration. The stay of the rule (and the emission control requirements) remains in effect, and the EPA is required to file status reports of its reconsideration every 60 days. 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 generating 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 will start on January 1, 2019, and the identified units will receive an annual allowance allocation that is equal to their most recent annual CSAPR SO₂ allocation. Cumulatively, our units covered by the program are allocated 100,279 allowances annually. Under the rule, a unit that is listed that does not operate for two consecutive years starting after 2018 would no longer receive allowances after the fifth year of non-operation. 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 electric generating units are subject to BART for particulate matter. The National Parks Conservation Association, the Sierra Club and the Environmental Defense Fund 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 granted a joint motion filed by the EPA and the environmental groups involved to abate the Fifth Circuit Court proceedings until the EPA has taken action on the reconsideration petition and concludes the reconsideration process. In August 2018, the EPA issued a proposed rule to affirm the prior BART final rule and seeking comments on that proposal, which are 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 February 2013, the EPA proposed a rule requiring certain states to remove SIP exemptions for excess emissions during malfunctions or replace them with an affirmative defense. In May 2015, the EPA finalized its 2013 proposal to extend the EPA's proposed findings of inadequacy to states that have affirmative defense provisions, including Texas. The final rule impacted 36 states, including Texas, Illinois and Ohio, in which we operate. The EPA's final rule would require covered states to remove or replace their EPA-approved exemptions or affirmative defense provisions for excess emissions during startup, shutdown and maintenance events. Several states (including the State of Texas and the State of Ohio) and various industry parties (including Luminant) filed petitions for review of the EPA's final rule, and all of those petitions were consolidated in the D.C. Circuit Court. Before the oral argument was held, in April 2017, the D.C. Circuit Court granted the EPA's motion to continue oral argument and ordered that the case be held in abeyance with the EPA to provide status reports to the D.C. Circuit Court on the EPA's review of the action at 90-day intervals. In October 2018, the EPA partially granted Texas' petition for reconsideration of the Texas SIP call. We cannot predict the timing or outcome of this proceeding, or estimate a range of reasonably possible costs, but implementation of the rule as finalized could have a material impact on our results of operations, liquidity or financial condition.

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 in light of 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 addition, with respect to Monticello and Big Brown, the retirement of those plants should favorably impact our legal challenge to the nonattainment designations in that the nonattainment designation for Freestone County and Titus County are based solely on the Sierra Club modeling, which we dispute, of alleged SO₂ emissions from Monticello and Big Brown. Regardless, considering these retirements, the nonattainment designation for those counties are no longer supported. 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.

Effluent Limitation Guidelines (ELGs)

In November 2015, the EPA revised the ELGs for steam electric generating facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, flue desulfurization, fly ash, bottom ash and flue gas mercury control. 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 issued in 2015 and administratively stayed the ELG rule's compliance date deadlines pending ongoing judicial review of the rule. The legal challenges pertaining to bottom ash transport water, flue gas desulfurization wastewater and gasification wastewater have been suspended while the EPA reconsiders the rules.

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The EPA issued a final rule in September 2017 postponing the earliest compliance dates in the ELG rule for bottom ash transport water and flue-gas desulfurization wastewater by two years, from November 1, 2018 to November 1, 2020.

Given the EPA's decision to reconsider the bottom ash transport water and flue gas desulfurization wastewater provisions of the ELG rule, the rule postponing the ELG rule's earliest compliance dates for those provisions, 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-fired 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 New Source Review 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. After the parties filed their respective briefs in the Fifth Circuit Court, the appeal was argued before the Fifth Circuit Court in March 2018. 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. We believe that we have complied with all requirements of the CAA and intend to continue to vigorously defend against the remaining allegations. An adverse outcome could require substantial capital expenditures that cannot be determined at this time or retirement of the remaining plant at issue, Martin Lake. The retirement of the Big Brown plant should have a favorable impact on this litigation. We cannot predict the outcome of these proceedings, including the financial effects, if any.

Zimmer NOVs — In December 2014, the EPA issued an 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. We are unable to predict the outcome of these matters.

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. We filed a motion seeking interlocutory appeal of the court’s summary judgment ruling. In February 2017, the appellate court denied our motion for interlocutory appeal. The parties completed briefing on motions for summary judgment in October 2018, and the remedy phase trial remains scheduled for March 2019. We dispute the allegations and will defend the case vigorously. We are unable to predict the outcome of these matters.

Ultimate resolution of any 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 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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Coal Combustion Residuals/Groundwater

On July 30, 2018, the EPA published a final rule that amends certain provisions of the Coal Combustion Residuals (CCR) rule that the agency issued in 2015. The 2018 revisions extend closure deadlines to October 31, 2020, related to the aquifer location restriction and groundwater monitoring requirements. The 2018 revisions also (1) establish groundwater protection standards for cobalt, lithium, molybdenum and lead (2) allow authorized state programs to waive groundwater monitoring requirements when there is a demonstration of no potential for contaminant migration, and (3) allow the permitting authority to issue certifications in lieu of a qualified professional engineer. The 2018 revisions became effective in August 2018, and we are continuing to evaluate the impact on our CCR facilities. Also, on August 21, 2018, the D.C. Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR rule. The EPA is expected to undertake further revisions to its CCR regulations in response to the D.C. Circuit Court's ruling. 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 EPA (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 is not subject to the EPA's 2015 CCR rule, 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. By letter dated January 31, 2018, Prairie Rivers Network provided 60-day notice of its intent to sue our subsidiary Dynegy Midwest Generation, LLC under the federal Clean Water Act for alleged unauthorized discharges from the surface impoundments at our Vermilion facility and alleged related violations of the facility's National Pollutant Discharge Elimination System permit. Prairie Rivers Network filed a citizen suit in May 2018, alleging violations of the Clean Water Act for alleged unauthorized discharges. In August 2018, we filed a motion to dismiss the lawsuit. We dispute the allegations 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.

If remediation measures concerning groundwater are necessary at any of our coal-fired 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 on July 30, 2018 and the D.C. Circuit Court's vacatur and remand of certain provisions of the EPA's 2015 CCR rule, we cannot reasonably estimate the costs, or range of costs, of groundwater remediation, if any, that ultimately may be required. CCR surface impoundment and landfill closure costs, as determined by our operations and environmental services teams, are reflected in our AROs.

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., have challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO PRA structure going forward. Complainants have also alleged that Dynegy could have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the 2015-2016 PRA. The Independent Market Monitor for MISO (MISO IMM), which was responsible for monitoring the MISO 2015-2016 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 proposed remedies. We filed our Answer to these complaints and believe that we complied fully with the terms of the MISO tariff in connection with the 2015-2016 PRA, disputed the allegations, and will defend our actions vigorously. In addition, the Illinois Industrial Energy Consumers filed a complaint at FERC against MISO on June 30, 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this complaint.

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On October 1, 2015, FERC issued an order of non-public, formal investigation, stating that shortly after the conclusion of the 2015-2016 PRA, FERC's Office of Enforcement began a non-public informal investigation into whether market manipulation or other potential violations of FERC orders, rules, and regulations occurred before or during the PRA (the Order). The Order noted that the investigation is ongoing, and that the conversion of the informal, non-public investigation to a formal, non-public investigation does not indicate that FERC has determined that any entity has engaged in market manipulation or otherwise violated any FERC order, rule, or regulation. Vistra Energy is participating in the investigation on behalf of Dynegy following the closing of the Merger. We believe that our conduct was proper and will defend our position vigorously, but we cannot predict the outcome of the investigation or the amount, if any, of loss that may result. 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.

On December 31, 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff provisions associated with calculating Initial Reference Levels and Local Clearing Requirements, effective as of the 2016-2017 PRA. The order did not address the arguments of the complainants regarding the 2015-2016 PRA, and stated that those issues remain under consideration and will be addressed in a future order.

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.


13.	EQUITY

Equity Issuances

See Note 2 for information regarding Vistra Energy common stock issued as a result of the Merger.

Share Repurchase Program

In June 2018, we announced that our board of directors had authorized a share repurchase program (Program) under which up to $500 million of our outstanding common stock may be repurchased. The Program was effective as of June 13, 2018. Through September 30, 2018, 18,271,105 shares of our common stock had been repurchased for $424 million (including related fees and expenses) at an average price per share of common stock of $23.18. At September 30, 2018, $76 million was available for additional repurchases under the Program. The Program was completed on October 19, 2018.

In November 2018, we announced that our board of directors had authorized an incremental share repurchase program under which up to $1.25 billion of our outstanding stock may be purchased. We intend to implement the program opportunistically from time to time over the next 12 to 18 months.

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 Securities Exchange Act of 1934, as amended, or by other means in accordance with federal securities laws. The actual timing, number and value of shares repurchased under the Program 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 and Dividend Restrictions

Dividends — Vistra Energy did not declare or pay any dividends during the nine months ended September 30, 2018 and 2017.

In November 2018, Vistra Energy announced that its board of directors 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 of directors 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.

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Dividend Restrictions — There are no restrictions in the Vistra Energy senior notes that preclude the payment of dividends. The agreement governing 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, 2018, Vistra Operations can distribute approximately $9.2 billion to Vistra Energy Corp. (the Parent) under the Credit Facilities Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to the Parent was partially reduced by distributions made by Vistra Operations to the Parent during the year ended December 31, 2017 of approximately $1.1 billion. In the three and nine months ended September 30, 2018, distributions totaling $1.9 billion and $3.928 billion, respectively, were made by Vistra Operations to the Parent. In September 2018, the board of directors approved an additional $400 million distribution by Vistra Operations to the Parent that was paid in October 2018. Additionally, Vistra Operations may make distributions to the Parent in amounts sufficient for the Parent to make any payments required under the TRA or the Tax Matters Agreement or, to the extent arising out of the Parent's ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses. As of September 30, 2018, the maximum amount of restricted net assets of Vistra Operations that may not be distributed to the Parent totaled approximately $7.8 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).

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, 2018, nine million warrants expiring in 2024 with an exercise price of $35.00 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

At the Merger Date, the Company assumed the obligations of Dynegy's 4,600,000 7.00% tangible equity units, each with a stated amount of $100.00 and each comprised of (i) a prepaid stock purchase contract that will deliver to the holder, not later than July 1, 2019, unless earlier redeemed or settled, not more than 4.0421 shares of Vistra Energy common stock and not less than 3.2731 shares of Vistra Energy common stock per contract based upon the applicable fixed settlement rate in the contract and (ii) a senior amortizing note with an outstanding principal amount of $38 million at the Merger Date that pays an equal quarterly cash installment of $1.75 per amortizing note (see Note 11). In the aggregate, the annual quarterly cash installments will be equivalent to a 7.00% cash payment per year with respect to each $100.00 stated amount of tangible equity units. The prepaid stock purchase contracts are classified within equity. The amortizing notes are classified as long-term debt.

Shareholder's Equity

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



	Common Stock (a)		Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest			Total Equity
Balance at June 30, 2018	$	5	$	10,015		$	(1,591	)	$	(16	)	$	7		$	8,420
Net income	—		—			330			—			—			330
Treasury stock	—		(349		)	—			—			—			(349		)
Effects of stock-based incentive compensation plans	—		6			—			—			—			6
Change in unrecognized losses related to pension and OPEB plans	—		—			—			1			—			1
Investment by noncontrolling interest	—		—			—			—			(1		)	(1		)
Other	—		(2		)	—			—			—			(2		)
Balance at September 30, 2018	$	5	$	9,670		$	(1,261	)	$	(15	)	$	6		$	8,405

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



	Common Stock (a)		Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interest		Total Equity
Balance at December 31, 2017	$	4	$	7,765		$	(1,410	)	$	(17	)	$	—	$	6,342
Stock issued in connection with the Merger	1		1,891			—			—			—		1,892
Net income	—		—			132			—			—		132
Adoption of accounting standard (Note 1)	—		—			17			—			—		17
Treasury stock	—		(424		)	—			—			—		(424		)
Effects of stock-based incentive compensation plans	—		69			—			—			—		69
Tangible equity units acquired	—		369			—			—			—		369
Warrants acquired	—		2			—			—			—		2
Change in unrecognized losses related to pension and OPEB plans	—		—			—			2			—		2
Investment by noncontrolling interest	—		—			—			—			6		6
Other	—		(2		)	—			—			—		(2		)
Balance at September 30, 2018	$	5	$	9,670		$	(1,261	)	$	(15	)	$	6	$	8,405

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(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.

The following table presents the changes to shareholder's equity for the three months ended September 30, 2017:



	Common Stock (a)		Additional Paid-in Capital		Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)		Total Shareholders' Equity
Balance at June 30, 2017	$	4	$	7,750	$	(1,102	)	$	6	$	6,658
Net income	—		—		273			—		273
Effects of stock-based incentive compensation plans	—		5		—			—		5
Other	—		—		(1		)	—		(1		)
Balance at September 30, 2017	$	4	$	7,755	$	(830	)	$	6	$	6,935

The following table presents the changes to shareholder's equity for the nine months ended September 30, 2017:



	Common Stock (a)		Additional Paid-in Capital		Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)		Total Shareholders' Equity
Balance at December 31, 2016	$	4	$	7,742	$	(1,155	)	$	6	$	6,597
Net income	—		—		325			—		325
Effects of stock-based incentive compensation plans	—		13		—			—		13
Balance at September 30, 2017	$	4	$	7,755	$	(830	)	$	6	$	6,935

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(a)	Authorized shares totaled 1,800,000,000 at September 30, 2017. Outstanding shares totaled 427,597,368 and 427,580,232 at September 30, 2017 and December 31, 2016, respectively.

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14.	FAIR VALUE MEASUREMENTS

We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. We use a mid-market valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs. Our valuation policies and procedures were developed, maintained and validated by a centralized risk management group that reports to the Vistra 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 15 for additional information regarding credit risk associated with our derivatives). We utilize credit ratings and default rate factors in calculating these fair value measurement adjustments.

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

•

Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. Our Level 1 assets and liabilities include CME or ICE (electronic commodity derivative exchanges) futures and options transacted through clearing brokers for which prices are actively quoted. We report the fair value of CME and ICE transactions without taking into consideration margin deposits, with the exception of certain margin amounts related to changes in fair value on certain CME transactions that, beginning in January 2017, are legally characterized as settlement of derivative contracts rather than collateral.

•

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

•

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

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

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



September 30, 2018
	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	192	$	143	$	148	$	65	$	548
Interest rate swaps	—		175		—		—		175
Nuclear decommissioning trust – equity securities (c)	519		—		—		—		519
Nuclear decommissioning trust – debt securities (c)	—		433		—		—		433
Sub-total	$	711	$	751	$	148	$	65	1,675
Assets measured at net asset value (d):
Nuclear decommissioning trust – equity securities (c)									322
Total assets									$	1,997
Liabilities:
Commodity contracts	$	273	$	501	$	392	$	65	$	1,231
Interest rate swaps	—		4		—		—		4
Total liabilities	$	273	$	505	$	392	$	65	$	1,235



December 31, 2017
	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	47	$	98	$	75	$	2	$	222
Interest rate swaps	—		18		—		8		26
Nuclear decommissioning trust – equity securities (c)	468		—		—		—		468
Nuclear decommissioning trust – debt securities (c)	—		430		—		—		430
Sub-total	$	515	$	546	$	75	$	10	1,146
Assets measured at net asset value (d):
Nuclear decommissioning trust – equity securities (c)									290
Total assets									$	1,436
Liabilities:
Commodity contracts	$	45	$	143	$	128	$	2	$	318
Interest rate swaps	—		—		—		8		8
Total liabilities	$	45	$	143	$	128	$	10	$	326

____________


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


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


(c)	The nuclear decommissioning trust investment is included in the other investments line in our condensed consolidated balance sheets. See Note 20.


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

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Commodity contracts consist primarily of natural gas, electricity, fuel oil, uranium, coal and emissions agreements and include financial instruments entered into for 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 15 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.

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, 2018 and December 31, 2017:



September 30, 2018
	Fair Value
Contract Type (a)	Assets		Liabilities			Total			Valuation Technique	Significant Unobservable Input	Range (b)
Electricity purchases and sales	$	11	$	(173	)	$	(162	)	Valuation Model	Hourly price curve shape (c)	$0 to $90/ MWh
										Illiquid delivery periods for ERCOT hub power prices and heat rates (d)	$20 to $120/ MWh
Electricity and weather options	15		(161		)	(146		)	Option Pricing Model	Gas to power correlation (e)	15% to 95%
										Power volatility (e)	5% to 435%
Financial transmission rights	86		(19		)	67			Market Approach (f)	Illiquid price differences between settlement points (g)	$(10) to $50/ MWh
Other (h)	36		(39		)	(3		)
Total	$	148	$	(392	)	$	(244	)



December 31, 2017
	Fair Value
Contract Type (a)	Assets		Liabilities			Total			Valuation Technique	Significant Unobservable Input	Range (b)
Electricity purchases and sales	$	12	$	(33	)	$	(21	)	Valuation Model	Hourly price curve shape (c)	$0 to $40/ MWh
										Illiquid delivery periods for ERCOT hub power prices and heat rates (d)	$20 to $70/ MWh
Electricity and weather options	10		(91		)	(81		)	Option Pricing Model	Gas to power correlation (e)	30% to 100%
										Power volatility (e)	5% to 180%
Financial transmission rights	45		(4		)	41			Market Approach (f)	Illiquid price differences between settlement points (g)	$0 to $15/ MWh
Other (h)	8		—			8
Total	$	75	$	(128	)	$	(53	)

____________

(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 are referred to as congestion revenue rights contracts 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 power price and heat rate variability.

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(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 historical price differences between settlement points within ERCOT hubs and load zones.


(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, 2018 and 2017. See the table below for discussion of transfers between Level 2 and Level 3 for the three and nine months ended September 30, 2018 and 2017.

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, 2018 and 2017.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Net asset (liability) balance at beginning of period	$	(222	)	$	75		$	(53	)	$	83
Total unrealized valuation gains (losses)	(102		)	132			(333		)	139
Purchases, issuances and settlements (a):
Purchases	41			16			99			51
Issuances	(14		)	(5		)	(22		)	(19		)
Settlements	58			(45		)	104			(87		)
Transfers into Level 3 (b)	1			—			3			4
Transfers out of Level 3 (b)	(6		)	—			(5		)	2
Net liabilities assumed in connection with the Merger (Note 2)	—			—			(37		)	—
Earn-out provision	—			(16		)	—			(16		)
Net change (c)	(22		)	82			(191		)	74
Net asset (liability) balance at end of period	$	(244	)	$	157		$	(244	)	$	157
Unrealized valuation gains (losses) relating to instruments held at end of period	$	(120	)	$	106		$	(273	)	$	110

____________


(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.


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

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15.	COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Strategic Use of Derivatives

We transact in derivative instruments, such as options, swaps, futures and forward contracts, to manage commodity price and interest rate risk. See Note 14 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. We also utilize short-term electricity, natural gas, coal, fuel oil, uranium and emission 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 (loss) 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 (loss) in interest expense and related charges.

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, 2018 and December 31, 2017. 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, 2018
	Derivative Assets					Derivative Liabilities
	Commodity Contracts			Interest Rate Swaps		Commodity Contracts			Interest Rate Swaps			Total
Current assets	$	432		$	25	$	1		$	—		$	458
Noncurrent assets	67			150		48			—			265
Current liabilities	(6		)	—		(973		)	(2		)	(981		)
Noncurrent liabilities	(10		)	—		(242		)	(2		)	(254		)
Net assets (liabilities)	$	483		$	175	$	(1,166	)	$	(4	)	$	(512	)



	December 31, 2017
	Derivative Assets					Derivative Liabilities
	Commodity Contracts		Interest Rate Swaps			Commodity Contracts			Interest Rate Swaps			Total
Current assets	$	190	$	—		$	—		$	—		$	190
Noncurrent assets	30		22			2			4			58
Current liabilities	—		(4		)	(216		)	(4		)	(224		)
Noncurrent liabilities	—		—			(102		)	—			(102		)
Net assets (liabilities)	$	220	$	18		$	(316	)	$	—		$	(78	)

At September 30, 2018 and December 31, 2017, there were no derivative positions accounted for as cash flow or fair value hedges. There were no amounts recognized in OCI for both the three and nine months ended September 30, 2018 and 2017.

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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 (loss) presentation)	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Commodity contracts (Operating revenues)	$	(278	)	$	166		$	(655	)	$	333
Commodity contracts (Fuel, purchased power costs and delivery fees)	21			9			32			3
Interest rate swaps (Interest expense and related charges)	38			(4		)	115			(24		)
Net gain (loss)	$	(219	)	$	171		$	(508	)	$	312

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 certain CME transactions that are legally characterized as settlement of forward exposure rather than collateral. Margin deposits received from counterparties are primarily used for working capital or other general corporate purposes.

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



	September 30, 2018												December 31, 2017
	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	$	483		$	(338	)	$	(1	)	$	144		$	220		$	(113	)	$	(1	)	$	106
Interest rate swaps	175			(4		)	—			171			18			—			—			18
Total derivative assets	658			(342		)	(1		)	315			238			(113		)	(1		)	124
Derivative liabilities:
Commodity contracts	(1,166		)	338			92			(736		)	(316		)	113			1			(202		)
Interest rate swaps	(4		)	4			—			—			—			—			—			—
Total derivative liabilities	(1,170		)	342			92			(736		)	(316		)	113			1			(202		)
Net amounts	$	(512	)	$	—		$	91		$	(421	)	$	(78	)	$	—		$	—		$	(78	)

____________


(a)	Amounts presented exclude trade accounts receivable and payable related to settled financial instruments.


(b)	Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin requirements and, to a lesser extent, initial margin requirements.

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Derivative Volumes

The following table presents the gross notional amounts of derivative volumes at September 30, 2018 and December 31, 2017:



	September 30, 2018		December 31, 2017
Derivative type	Notional Volume				Unit of Measure
Natural gas (a)	5,264		1,259		Million MMBtu
Electricity	246,262		114,129		GWh
Financial Transmission Rights (b)	176,207		110,913		GWh
Coal	47		2		Million U.S. tons
Fuel oil	4		5		Million gallons
Uranium	100		325		Thousand pounds
Emissions	25		—		Million tons
Interest rate swaps – floating/fixed (c)	$	7,718	$	3,000	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.


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

Credit Risk-Related Contingent Features of Derivatives

Our derivative contracts may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of these agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies or include cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants.

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



	September 30, 2018			December 31, 2017
Fair value of derivative contract liabilities (a)	$	(629	)	$	(204	)
Offsetting fair value under netting arrangements (b)	161			103
Cash collateral and letters of credit	222			41
Liquidity exposure	$	(246	)	$	(60	)

____________


(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, 2018, total credit risk exposure to all counterparties related to derivative contracts totaled $858 million (including associated accounts receivable). The net exposure to those counterparties totaled $397 million at September 30, 2018, after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $70 million. At September 30, 2018, the credit risk exposure to the banking and financial sector represented 57% of the total credit risk exposure and 47% of the net exposure.

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

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


16.	PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFIT (OPEB) PLANS

Vistra Energy is the plan sponsor of the Vistra Energy Retirement Plan, which provides benefits to eligible employees of its subsidiaries. Eligible employees under the Vistra Energy Retirement Plan consist entirely of active and retired collective bargaining unit employees. Vistra Energy and our participating subsidiaries offer other postretirement benefits (OPEB) in the form of certain health care and life insurance benefits to eligible retirees and their eligible dependents.

Prior to the Merger, Dynegy provided pension and OPEB benefits to certain of its employees and retirees. At the Merger Date, Vistra Energy assumed these plans and the excess of the benefit obligations over the fair value of plan assets was recognized as a liability (see Note 2). Benefit obligations assumed totaled $539 million and the fair value of plan assets assumed totaled $459 million, and the net unfunded liability was recorded as $15 million to other noncurrent assets, $2 million to other current liabilities and $93 million to other noncurrent liabilities in the condensed consolidated balance sheets.

Components of Net Benefit Cost

For the three and nine months ended September 30, 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,
	2018			2017		2018			2017		2018		2017		2018		2017
Service cost	$	5		$	1	$	10		$	4	$	1	$	—	$	2	$	1
Other costs	(1		)	—		(1		)	—		1		1		3		3
Net periodic benefit cost	$	4		$	1	$	9		$	4	$	2	$	1	$	5	$	4

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17. STOCK-BASED COMPENSATION

At the Merger Date, 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.



Instrument Type	Dynegy Awards Prior to the Merger Date	Vistra Awards Converted at the Merger Date	Fair Value of Awards (a)
Stock Options	4,096,027	2,670,610	$	10
Restricted Stock Units	5,718,148	3,056,689	61
Performance Units	1,538,133	938,721	18
Total			$	89

____________

(a)

$26 million was attributable to pre-combination service and considered part of the purchase price (see Note 2). $33 million was recognized immediately as compensation expense due to accelerated vesting as a result of the Merger. $30 million will be amortized as compensation expense over the remaining service period and will be recorded in additional paid in capital in the condensed consolidated balance sheets.


18.	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.

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 of 1933, as amended, 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, 2018 and 2017.

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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.


19.	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 related services to residential, commercial and industrial customers. Substantially all of these activities are conducted by TXU Energy and Value Based Brands LLC in Texas, Dynegy Energy Services in Massachusetts, Ohio, Illinois and Pennsylvania and Homefield Energy in Illinois. Prior to the Merger, the Retail segment was referred to as the Retail Electricity segment.

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 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. Prior to the Merger, the ERCOT segment was referred to as the Wholesale Generation segment.

As discussed in Note 1, the Asset Closure segment was established effective January 1, 2018. The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines. 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 recast prior period information to reflect this change in reportable segments. 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 January, February and May 2018.

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.

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 to the Financial Statements in our 2017 Form 10-K. 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 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,
	2018			2017			2018			2017
Operating revenues (a)
Retail	$	1,813		$	1,286		$	4,239		$	3,136
ERCOT	1,396			891			2,190			1,994
PJM	620			—			1,104			—
NY/NE	301			—			487			—
MISO	230			—			488			—
Asset Closure	(1		)	312			48			763
Corporate and Other (b)	91			—			123			—
Eliminations	(1,207		)	(656		)	(2,098		)	(1,406		)
Consolidated operating revenues	$	3,243		$	1,833		$	6,581		$	4,487

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Depreciation and amortization
Retail	$	(80	)	$	(108	)	$	(237	)	$	(322	)
ERCOT	(122		)	(59		)	(295		)	(166		)
PJM	(141		)	—			(266		)	—
NY/NE	(55		)	—			(104		)	—
MISO	(3		)	—			(6		)	—
Asset Closure	—			(1		)	—			(1		)
Corporate and Other (b)	(25		)	(10		)	(60		)	(30		)
Eliminations	—			—			1			—
Consolidated depreciation and amortization	$	(426	)	$	(178	)	$	(967	)	$	(519	)
Operating income (loss)
Retail (c)	$	(83	)	$	(3	)	$	371		$	54
ERCOT	643			406			234			555
PJM	61			—			85			—
NY/NE	45			—			36			—
MISO	(2		)	—			30			—
Asset Closure	(4		)	63			(26		)	96
Corporate and Other (b)	(8		)	(15		)	(244		)	(47		)
Eliminations	(2		)	1			(1		)	—
Consolidated operating income	$	650		$	452		$	485		$	658
Net income (loss)
Retail (c)	$	(86	)	$	7		$	397		$	77
ERCOT	643			405			236			552
PJM	62			—			86			—
NY/NE	47			—			41			—
MISO	(3		)	—			29			—
Asset Closure	(4		)	64			(24		)	101
Corporate and Other (b)	(328		)	(203		)	(635		)	(405		)
Consolidated net income	$	331		$	273		$	130		$	325

____________


(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,
	2018			2017			2018			2017
Retail	$	(24	)	$	2		$	(11	)	$	11
ERCOT	192			226			(207		)	375
PJM	(28		)	—			(38		)	—
NY/NE	(7		)	—			(32		)	—
MISO	(34		)	—			(4		)	—
Corporate and Other (b)	3			—			4			—
Eliminations (1)	(130		)	(89		)	49			(171		)
Consolidated unrealized net gains (losses) from mark-to-market valuations of commodity positions included in operating revenues	$	(28	)	$	139		$	(239	)	$	215

____________

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(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 net income.


(c)	Retail operating loss and net loss is driven by unrealized losses from mark-to-market valuations of commodity positions included in fuel, purchased power costs and delivery fees.



	September 30, 2018			December 31, 2017
Total assets
Retail	$	7,365		$	6,156
ERCOT	9,101			6,834
PJM	6,796			—
NY/NE	2,705			—
MISO	945			—
Asset Closure	237			235
Corporate and Other and Eliminations	(1,261		)	1,375
Consolidated total assets	$	25,888		$	14,600

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20.	SUPPLEMENTARY FINANCIAL INFORMATION

Interest Expense and Related Charges



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Interest paid/accrued	$	164		$	52		$	380		$	157
Unrealized mark-to-market net (gains) losses on interest rate swaps	(38		)	(3		)	(123		)	3
Losses on extinguishment of debt and amortization of debt issuance costs, discounts and premiums	27			2			31			2
Reversal of debt extinguishment gain	—			21			—			—
Capitalized interest	(3		)	(1		)	(10		)	(5		)
Other	4			5			13			12
Total interest expense and related charges	$	154		$	76		$	291		$	169

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 11, was 4.18% at September 30, 2018.

Other Income and Deductions



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Other income:
Office space sublease rental income (a)	$	2	$	3	$	6	$	9
Mineral rights royalty income (b)	—		1		—		3
Sale of land (b)	—		1		1		4
Interest income	3		4		14		10
All other	1		1		4		3
Total other income	$	6	$	10	$	25	$	29
Other deductions:
Other	1		—		$	4	$	5
Total other deductions	$	1	$	—	$	4	$	5

____________


(a)	Reported in Corporate and Other non-segment.


(b)	Reported in ERCOT segment.

Restricted Cash



	September 30, 2018				December 31, 2017
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to the Vistra Operations Credit Facilities (Note 11)	$	—	$	—	$	—	$	500
Amounts related to restructuring escrow accounts	59		—		59		—
Total restricted cash	$	59	$	—	$	59	$	500

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Trade Accounts Receivable



	September 30, 2018			December 31, 2017
Wholesale and retail trade accounts receivable	$	1,268		$	596
Allowance for uncollectible accounts	(25		)	(14		)
Trade accounts receivable — net	$	1,243		$	582

Gross trade accounts receivable at September 30, 2018 and December 31, 2017 included unbilled retail revenues of $356 million and $251 million, respectively.

Allowance for Uncollectible Accounts Receivable



	Nine Months Ended September 30,
	2018			2017
Allowance for uncollectible accounts receivable at beginning of period	$	14		$	10
Increase for bad debt expense	41			35
Decrease for account write-offs	(30		)	(24		)
Allowance for uncollectible accounts receivable at end of period	$	25		$	21

Inventories by Major Category



	September 30, 2018		December 31, 2017
Materials and supplies	$	279	$	149
Fuel stock	108		83
Natural gas in storage	6		21
Total inventories	$	393	$	253

Investments



	September 30, 2018		December 31, 2017
Nuclear plant decommissioning trust	$	1,274	$	1,188
Assets related to employee benefit plans (Note 16)	34		—
Land	49		49
Miscellaneous other	—		3
Total investments	$	1,357	$	1,240

Investments 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, 2018, our estimated investment in NELP totaled $133 million subject to any adjustments to our purchase price allocation. Our risk of loss related to our equity method investment is limited to our investment balance (see Note 2).

For the three and nine months ended September 30, 2018, equity earnings related to our investment in NELP totaled $7 million and $11 million, respectively, recorded in equity in earnings of unconsolidated investment in our condensed statements of consolidated net income (loss). For the three and nine months ended September 30, 2018, we received distributions totaling $7 million and $13 million, 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 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. In the event that funds recovered from Oncor's customers that are 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, 2018
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	437	$	5	$	(9	)	$	433
Equity securities (c)	277		564		—			841
Total	$	714	$	569	$	(9	)	$	1,274



	December 31, 2017
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	418	$	14	$	(2	)	$	430
Equity securities (c)	265		495		(2		)	758
Total	$	683	$	509	$	(4	)	$	1,188

____________


(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 3.73% and 3.55% at September 30, 2018 and December 31, 2017, respectively, and an average maturity of nine years at both September 30, 2018 and December 31, 2017.


(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 Inc. EAFE Index for non-U.S. equity investments.

Debt securities held at September 30, 2018 mature as follows: $146 million in one to five years, $96 million in five to 10 years and $191 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,
	2018			2017			2018			2017
Realized gains	$	(1	)	$	1		$	—		$	3
Realized losses	$	1		$	(1	)	$	(2	)	$	(3	)
Proceeds from sales of securities	$	118		$	56		$	211		$	154
Investments in securities	$	(124	)	$	(62	)	$	(227	)	$	(169	)

Property, Plant and Equipment

At September 30, 2018 and December 31, 2017, property, plant and equipment of $14.756 billion and $4.820 billion, respectively, is stated net of accumulated depreciation and amortization of $1.148 billion and $393 million, respectively.

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Asset Retirement and Mining Reclamation Obligations (ARO)

These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining and removal of lignite/coal fueled plant ash treatment facilities. 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, 2018, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.265 billion, which is less 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 $9 million in other noncurrent liabilities and deferred credits.

The following table summarizes 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, 2018:



	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, 2018		December 31, 2017
Uncertain tax positions, including accrued interest	$	12	$	—
Other, including retirement and other employee benefits	334		220
Total other noncurrent liabilities and deferred credits	$	346	$	220

Fair Value of Debt



		September 30, 2018				December 31, 2017
Debt:	Fair Value Hierarchy	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt under the Vistra Operations Credit Facilities (Note 11)	Level 2	$	5,823	$	5,836	$	4,323	$	4,334
Vistra Operations Senior Notes (Note 11)	Level 2	1,000		1,010		—		—
Vistra Energy Senior Notes (Note 11)	Level 2	3,954		3,945		—		—
7.000% Amortizing Notes (Note 11)	Level 2	31		32		—		—
Forward Capacity Agreements (Note 11)	Level 3	221		221		—		—
Equipment Financing Agreements (Note 11)	Level 3	119		119		—		—
Mandatorily redeemable subsidiary preferred stock (Note 11)	Level 2	70		70		70		70
Building Financing (Note 11)	Level 2	23		21		30		27

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We determine fair value in accordance with accounting standards as discussed in Note 14. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services, such as Bloomberg.

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, 2018 and December 31, 2017:



	September 30, 2018		December 31, 2017
Cash and cash equivalents	$	811	$	1,487
Restricted cash included in current assets	59		59
Restricted cash included in noncurrent assets	—		500
Total cash, cash equivalents and restricted cash	$	870	$	2,046

The following table summarizes our supplemental cash flow information for the nine months ended September 30, 2018 and 2017:



	Nine Months Ended September 30,
	2018			2017
Cash payments related to:
Interest paid	$	662		$	197
Capitalized interest	(10		)	(5		)
Interest paid (net of capitalized interest)	$	652		$	192
Income taxes	$	66		$	51
Noncash investing and financing activities:
Construction expenditures (a)	$	58		$	16
Vistra Energy common stock issued in the Merger (Notes 2 and 13)	$	2,245		$	—

____________


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

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21.	SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Our senior 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.

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 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

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Condensed Statements of Consolidating Income (Loss) for the Three Months Ended September 30, 2017

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Operating revenues	$	—		$	1,833		$	—	$	—		$	1,833
Fuel, purchased power costs and delivery fees	—			(838		)	—		—			(838		)
Operating costs	—			(218		)	—		—			(218		)
Depreciation and amortization	—			(178		)	—		—			(178		)
Selling, general and administrative expenses	(7		)	(140		)	—		—			(147		)
Operating income (loss)	(7		)	459			—		—			452
Other income	2			8			—		—			10
Other deductions	—			—			—		—			—
Interest expense and related charges	—			(76		)	—		—			(76		)
Impacts of Tax Receivable Agreement	138			—			—		—			138
Income before income taxes	133			391			—		—			524
Income tax expense	(62		)	(189		)	—		—			(251		)
Equity in loss of subsidiaries, net of tax	202			—			—		(202		)	—
Net income (loss)	$	273		$	202		$	—	$	(202	)	$	273

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 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 income attributable to noncontrolling interest	—			—			(2		)	—			(2		)
Net income (loss) attributable to Vistra Energy	$	132		$	453		$	(44	)	$	(409	)	$	132

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Condensed Statements of Consolidating Income (Loss) for the Nine Months Ended September 30, 2017

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Operating revenues	$	—		$	4,487		$	—	$	—		$	4,487
Fuel, purchased power costs and delivery fees	—			(2,250		)	—		—			(2,250		)
Operating costs	—			(626		)	—		—			(626		)
Depreciation and amortization	—			(519		)	—		—			(519		)
Selling, general and administrative expenses	(20		)	(414		)	—		—			(434		)
Operating income (loss)	(20		)	678			—		—			658
Other income	2			27			—		—			29
Other deductions	—			(5		)	—		—			(5		)
Interest expense and related charges	—			(169		)	—		—			(169		)
Impacts of Tax Receivable Agreement	96			—			—		—			96
Income before income taxes	78			531			—		—			609
Income tax expense	(36		)	(248		)	—		—			(284		)
Equity in earnings of subsidiaries, net of tax	283			—			—		(283		)	—
Net income (loss)	$	325		$	283		$	—	$	(283	)	$	325

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 Three Months Ended September 30, 2017

(Millions of Dollars)



	Parent (Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Net income (loss)	$	273	$	202	$	—	$	(202	)	$	273
Other comprehensive income (loss), net of tax effects:
Effect related to pension and other retirement benefit obligations	—		—		—		—			—
Total other comprehensive income	—		—		—		—			—
Comprehensive income (loss)	$	273	$	202	$	—	$	(202	)	$	273

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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 income attributable to noncontrolling interest	—		—		(2		)	—			(2		)
Comprehensive income (loss) attributable to Vistra Energy	$	132	$	455	$	(44	)	$	(409	)	$	134

Condensed Statements of Consolidating Comprehensive Income (Loss) for the Nine Months Ended September 30, 2017

(Millions of Dollars)



	Parent (Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Net income (loss)	$	325	$	283	$	—	$	(283	)	$	325
Other comprehensive income (loss), net of tax effects:
Effect related to pension and other retirement benefit obligations	—		—		—		—			—
Total other comprehensive income	—		—		—		—			—
Comprehensive income (loss)	$	325	$	283	$	—	$	(283	)	$	325

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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		)
Borrowings under accounts receivable securitization program	—			—			350						350
Cash dividend paid	—			(3,928		)	—			3,928			—
Stock repurchase	(414		)	—			—			—			(414		)
Debt tender offer and other 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		)
Cash acquired in the Merger	—			445			—			—			445
Solar development expenditures	—			(28		)	—			—			(28		)
Proceeds from sales of nuclear decommissioning trust fund securities	—			211			—			—			211
Investments in nuclear decommissioning trust fund securities	—			(227		)	—			—			(227		)
Dividend received from subsidiaries	3,928									(3,928		)	—
Other, net	—			10			(3		)	—			7
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 Statements of Consolidating Cash Flows for the Nine Months Ended September 30, 2017

(Millions of Dollars)



	Parent (Issuer)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Cash flows — operating activities:
Cash provided by (used in) operating activities	$	(39	)	$	884		$	—	$	—		$	845
Cash flows — financing activities:
Repayments/repurchases of debt	—			(32		)	—		—			(32		)
Cash dividend paid	—			(537		)	—		537			—
Debt financing fees	—			(5		)	—		—			(5		)
Cash provided by (used in) financing activities	—			(574		)	—		537			(37		)
Cash flows — investing activities:
Capital expenditures	—			(86		)	—		—			(86		)
Nuclear fuel purchases	—			(56		)	—		—			(56		)
Solar development expenditures	—			(129		)	—		—			(129		)
Odessa acquisition	—			(355		)	—		—			(355		)
Proceeds from sales of nuclear decommissioning trust fund securities	—			154			—		—			154
Investments in nuclear decommissioning trust fund securities	—			(169		)	—		—			(169		)
Dividend received from subsidiaries	537			—			—		(537		)	—
Other, net	—			10			—		—			10
Cash provided by (used in) investing activities	537			(631		)	—		(537		)	(631		)
Net change in cash, cash equivalents and restricted cash	498			(321		)	—		—			177
Cash, cash equivalents and restricted cash — beginning balance	26			1,562			—		—			1,588
Cash, cash equivalents and restricted cash — ending balance	$	524		$	1,241		$	—	$	—		$	1,765

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Condensed Consolidating Balance Sheet as of September 30, 2018 (Millions of Dollars)

	Parent (Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	66	$	732	$	13	$	—		$	811
Restricted cash	59		—		—		—			59
Advances to affiliates	11		—		—		(11		)	—
Trade accounts receivable — net	9		875		359		—			1,243
Accounts receivable — affiliates	15		—		211		(226		)	—
Notes due from affiliates	—		101		—		(101		)	—
Income taxes receivable	12		—		—		—			12
Inventories	—		378		15		—			393
Commodity and other derivative contractual assets	—		458		—		—			458
Margin deposits related to commodity contracts	—		177		—		—			177
Prepaid expense and other current assets	2		117		4		—			123
Total current assets	174		2,838		602		(338		)	3,276
Investments	—		1,323		34		—			1,357
Investment in unconsolidated subsidiary	—		135		—		—			135
Investment in affiliated companies	11,631		362		—		(11,993		)	—
Property, plant and equipment — net	18		14,058		680		—			14,756
Goodwill	—		1,907		—		—			1,907
Identifiable intangible assets — net	—		2,711		—		—			2,711
Commodity and other derivative contractual assets	—		265		—		—			265
Accumulated deferred income taxes	955		239		—		(141		)	1,053
Other noncurrent assets	240		185		2		1			428
Total assets	$	13,018	$	24,023	$	1,318	$	(12,471	)	$	25,888
LIABILITIES AND EQUITY
Current liabilities:
Accounts receivable securitization program	$	—	$	—	$	350	$	—		$	350
Advances from affiliates	—		2		8		(10		)	—
Long-term debt due currently	31		145		5		—			181
Trade accounts payable	3		587		222		—			812
Accounts payable — affiliates	—		215		8		(223		)	—
Notes due to affiliates	—		—		101		(101		)	—
Commodity and other derivative contractual liabilities	—		981		—		—			981
Margin deposits related to commodity contracts	—		4		—		—			4
Accrued taxes other than income	—		138		1		—			139
Accrued interest	107		16		3		(3		)	123
Asset retirement obligations	—		183		—		—			183
Other current liabilities	96		231		2		—			329
Total current liabilities	237		2,502		700		(337		)	3,102

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Condensed Consolidating Balance Sheet as of September 30, 2018 (Millions of Dollars)

	Parent (Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
Long-term debt, less amounts due currently	3,954		7,073		33		—			11,060
Commodity and other derivative contractual liabilities	—		254		—		—			254
Accumulated deferred income taxes	—		—		146		(141		)	5
Tax Receivable Agreement obligation	402		—		—		—			402
Asset retirement obligations	—		2,126		13		—			2,139
Identifiable intangible liabilities — net	—		132		43		—			175
Other noncurrent liabilities and deferred credits	26		305		15		—			346
Total liabilities	4,619		12,392		950		(478		)	17,483
Total stockholders' equity	8,399		11,631		362		(11,993		)	8,399
Noncontrolling interest in subsidiary	—		—		6		—			6
Total liabilities and equity	$	13,018	$	24,023	$	1,318	$	(12,471	)	$	25,888

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Condensed Consolidating Balance Sheet as of December 31, 2017

(Millions of Dollars)



	Parent (Issuer)		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	1,124	$	363	$	—	$	—		$	1,487
Restricted cash	59		—		—		—			59
Trade accounts receivable — net	4		578		—		—			582
Inventories	—		253		—		—			253
Commodity and other derivative contractual assets	—		190		—		—			190
Margin deposits related to commodity contracts	—		30		—		—			30
Prepaid expense and other current assets	—		72		—		—			72
Total current assets	1,187		1,486		—		—			2,673
Restricted cash	—		500		—		—			500
Investments	—		1,240		—		—			1,240
Investment in affiliated companies	5,632		—		—		(5,632		)	—
Property, plant and equipment — net	—		4,820		—		—			4,820
Goodwill	—		1,907		—		—			1,907
Identifiable intangible assets — net	—		2,530		—		—			2,530
Commodity and other derivative contractual assets	—		58		—		—			58
Accumulated deferred income taxes	5		705		—		—			710
Other noncurrent assets	6		156		—		—			162
Total assets	$	6,830	$	13,402	$	—	$	(5,632	)	$	14,600
LIABILITIES AND EQUITY
Current liabilities:
Long-term debt due currently	$	—	$	44	$	—	$	—		$	44
Trade accounts payable	11		462		—		—			473
Commodity and other derivative contractual liabilities	—		224		—		—			224
Margin deposits related to commodity contracts	—		4		—		—			4
Accrued taxes	58		—		—		—			58
Accrued taxes other than income	—		136		—		—			136
Accrued interest	—		16		—		—			16
Asset retirement obligations	—		99		—		—			99
Other current liabilities	86		211		—		—			297
Total current liabilities	155		1,196		—		—			1,351
Long-term debt, less amounts due currently	—		4,379		—		—			4,379
Commodity and other derivative contractual liabilities	—		102		—		—			102
Tax Receivable Agreement obligation	333		—		—		—			333
Asset retirement obligations	—		1,837		—		—			1,837
Identifiable intangible liabilities — net	—		36		—		—			36
Other noncurrent liabilities and deferred credits	—		220		—		—			220
Total liabilities	488		7,770		—		—			8,258
Total equity	6,342		5,632		—		(5,632		)	6,342
Total liabilities and equity	$	6,830	$	13,402	$	—	$	(5,632	)	$	14,600

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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, 2018 and 2017 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

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 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. The Asset Closure segment was established as of January 1, 2018, and we have recast information from prior periods to reflect this change in reportable segments. See Note 19 to the Financial Statements for further information concerning reportable business segments.

Significant Activities and Events and Items Influencing Future Performance

Merger Transaction — On the Merger Date, Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement entered into in October 2017. Pursuant to the Merger Agreement, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the surviving corporation.

Based on the opening price of Vistra Energy common stock on the Merger Date, the purchase price was approximately $2.3 billion. The purchase price allocation is ongoing and is dependent upon final valuation determinations, which have not been completed. The preliminary values for property plant and equipment, identifiable intangible assets and liabilities, inventories, asset retirement obligations and deferred taxes represent our current best estimates of the fair value at the Merger Date. The purchase price allocation is preliminary and each of these may change materially based upon the receipt of more detailed information, additional analyses and completed valuations. We currently expect the final purchase price allocation will be completed no later than the second quarter of 2019.

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

Dividend Program — In November 2018, Vistra Energy announced that its board of directors 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 of directors 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.

Share Repurchase Program — In June 2018, we announced that our board of directors had authorized a share repurchase program (Program) under which up to $500 million of our outstanding common stock may be repurchased. The Program was effective as of June 13, 2018, and the program was completed on October 19, 2018.

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Through September 30, 2018, 18,271,105 shares of our common stock had been repurchased for $424 million (including related fees and expenses) at an average price per share of common stock of $23.18, and at September 30, 2018, $76 million was available for additional repurchases under the Program. On a cumulative basis through October 19, 2018, 21,421,925 shares of our common stock had been repurchased for $500 million (including related fees and expenses) at an average price per share of common stock of $23.36.

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 Securities Exchange Act of 1934, as amended, or by other means in accordance with federal securities laws. The actual timing, number and value of shares repurchased under the Program 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.

Battery Energy Storage Projects — In October 2018, we were awarded a $1 million grant from the TCEQ for our battery energy storage system at Upton solar facility. The grant is part of the Texas Emissions Reduction Plan. The 10 MW lithium-ion energy storage system will capture excess solar energy produced during the day and release the energy in late afternoon and early evening, when demand is highest. We expect the project to be operational in late 2018.

Upton Solar Development — In May 2017, we acquired the rights to develop, construct and operate a utility scale solar photovoltaic power generation facility in Upton County, Texas. As part of this project, we entered a turnkey engineering, procurement and construction agreement to construct the approximately 180 MW facility. The facility began test operations in March 2018 and commercial operations began in June 2018.

CCGT Plant Acquisition — In July 2017, La Frontera Holdings, LLC (La Frontera), an indirect wholly owned subsidiary of Vistra Energy, entered into an asset purchase agreement with Odessa-Ector Power Partners, L.P., an indirect wholly owned subsidiary of Koch Ag & Energy Solutions, LLC (the Odessa Acquisition), to acquire a 1,054 MW CCGT natural gas fueled generation plant (and other related assets and liabilities) located in Odessa, Texas (the Odessa Facility). On August 1, 2017, the Odessa Acquisition closed and La Frontera acquired the Odessa Facility. La Frontera paid an aggregate purchase price of approximately $355 million, plus a five-year earn-out provision, to acquire the Odessa Facility. The purchase price was funded by cash on hand. Subsequent to the acquisition, the earn-out provision has been accounted for as a derivative in our consolidated financial statements, and partial buybacks of the earn-out provision were settled in February and May 2018.

Retirement of Generation Plants — In January and February 2018, we retired three power plants with a total installed nameplate generation capacity of 4,167 MW. Luminant decided to retire these units because they were projected to be uneconomic based on 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.

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.

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Debt Activity — We have a target to reduce leverage to approximately 2.5x net debt/EBITDA. The following transactions reflect our intention to simplify our capital structure and reduce interest expense. We will continue to pursue opportunities to refinance our long-term debt and reduce interest expense.

Accounts Receivable Securitization Program — In August 2018, TXU Energy Receivables Company LLC (RecCo), a wholly-owned subsidiary of TXU Energy, and Vistra Energy entered into a $350 million accounts receivable financing facility (Receivables Facility), currently scheduled to terminate in August 2019, with issuers of asset-backed commercial paper and commercial banks. Vistra Energy expects to have the opportunity to renew and/or extend the Receivables Facility upon its expiration subject to such terms and conditions as may be agreed upon by the parties thereto. The Receivables Facility provides Vistra Energy with the ability to borrow up to $350 million. See Note 10 to the Financial Statements for details of the accounts receivable securitization program.

Issuance of Vistra Operations 5.500% Senior Notes Due 2026 — In August 2018, Vistra Operations issued and sold $1.0 billion aggregate principal amount of the 5.500% senior notes due 2026 in an offering to eligible purchasers under Rule 144A and Regulation S under the Securities Act of 1933, as amended. The senior notes were sold pursuant to a purchase agreement by and among Vistra Operations, certain direct and indirect subsidiaries of Vistra Operations and Citigroup Global Markets Inc., as representative of the several initial purchasers. Net proceeds from the sale of the senior notes totaling approximately $990 million, together with cash on hand and cash received from the funding of the accounts receivable securitization program described above, were used to pay the purchase price and accrued interest (together with fees and expenses) required in connection with the tender offers described below.

Tender Offers and Consent Solicitations — In August 2018, Vistra Energy used the net proceeds from the issuance of the Vistra Operations 5.500% senior notes due 2026, proceeds from the accounts receivable securitization program and cash on hand to fund cash tender offers to purchase for cash $1.542 billion of senior notes assumed in the Merger. In connections with the tender offers, Vistra Energy also commenced solicitations of consents from holders of the 7.375% senior notes due 2022, the 7.625% senior notes due 2024, the 8.034% senior notes due 2024, the 8.000% senior notes due 2025 and the 8.125% senior notes due 2026 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 due 2026. Vistra Energy received the requisite consents from the holders of the 8.034% senior notes due 2024, the 8.000% senior notes due 2025 and the 8.125% senior notes due 2026 and amended 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. In addition, Vistra Energy received the requisite consents from the holders of the 8.125% senior notes due 2026 and amended the registration rights agreement with respect to the 8.125% senior notes due 2026 to remove, among other things, the requirement that Vistra Energy commence an exchange offer to issue registered securities in exchange for the notes.

Amendment to Vistra Operations Credit Facilities — In June 2018, the Credit Facilities Agreement was amended. Among other things, the amendment included the following updated terms:

•

Aggregate commitments under the Revolving Credit Facility were increased from $860 million to $2.5 billion. The letter of credit sub-facility was also increased from $715 million to $2.3 billion. The maturity date of the Revolving Credit Facility was extended from August 4, 2021 to June 14, 2023. Pricing terms for the Revolving Credit Facility were reduced from LIBOR plus an applicable margin of 2.25% to LIBOR plus an applicable margin of 1.75%. Pricing terms for letters of credit issued under the Revolving Credit Facility were reduced from 2.25% to 1.75%.


•	Pricing terms for the Term Loan B-1 Facility were reduced from LIBOR plus an applicable margin of 2.50% to LIBOR plus an applicable margin of 2.00%.


•	Borrowings under the new Term Loan B-3 Facility of $2.050 billion principal amount were used to repay borrowings under the credit agreement that Vistra Energy assumed from Dynegy in connection with the Merger. Amounts borrowed under the Term Loan B-3 Facility bear interest based on applicable LIBOR rates plus a fixed spread of 2.00%, and the maturity date of the facility is December 31, 2025.


•	Borrowings under the Term Loan C Facility of $500 million were repaid using $500 million of cash from collateral accounts used to backstop letters of credit.

See Note 11 to the Financial Statements for details of the Vistra Operations Credit Facilities.

Redemption of Debt — In May 2018, $850 million of outstanding 6.75% Senior Notes due 2019 were redeemed at a redemption price of 101.688% of the aggregate principal amount, plus accrued and unpaid interest to but not including the date of redemption (see Note 11).

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Natural Gas Price and Market Heat Rate Exposure — Taking together forward wholesale, retail electricity sales and other retail customer considerations and all other hedging positions in ERCOT at September 30, 2018, we had effectively hedged an estimated 98% and 93% of the natural gas price exposure related to our overall business for 2018 and 2019, respectively. These percentages assume conversion of generation positions based on market heat rates and an estimate of natural gas generally being on the margin 70% to 90% of the time in the ERCOT market. Additionally, taking into consideration our overall heat rate exposure and related hedging positions in ERCOT at September 30, 2018, we had effectively hedged 92% and 78% of the heat rate exposure to our overall business for 2018 and 2019, respectively. We make the distinction between natural gas price exposure and heat rate exposure for the ERCOT market because of the high percentage of time natural gas is on the margin and the availability of traded products in ERCOT to hedge heat rate directly. Generation volumes hedged in PJM, NYISO, ISO-NE, MISO and CAISO at September 30, 2018 were as follows:



	2018		2019
PJM	83	%	75	%
NYISO/ISO-NE	70	%	77	%
MISO/CAISO	82	%	58	%

The following sensitivity tables provide approximate estimates of the potential impact of movements in natural gas prices and market heat rates on realized pretax earnings (in millions) taking into account the hedge positions noted in the paragraph above for the periods presented. The estimates related to price sensitivity are based on our expected generation and retail positions, related hedges and forward prices as of September 30, 2018.



	Balance 2018 (a)	2019
ERCOT:
$0.50/MMBtu increase in natural gas price (b)	$ ~—	$ ~45
$0.50/MMBtu decrease in natural gas price (b)	$ ~—	$ ~(25)
1.0/MMBtu/MWh increase in market heat rate (c)	$ ~10	$ ~75
1.0/MMBtu/MWh decrease in market heat rate (c)	$ ~(5)	$ ~(60)
PJM:
$0.50/MMBtu increase in natural gas price (d)	$ ~9	$ ~33
$0.50/MMBtu decrease in natural gas price (d)	$ ~(3)	$ ~(14)
1.0/MMBtu/MWh increase in market heat rate (e)	$ ~9	$ ~39
1.0/MMBtu/MWh decrease in market heat rate (e)	$ ~(4)	$ ~(27)
NYISO/ISO-NE:
$0.50/MMBtu increase in natural gas price (d)	$ ~6	$ ~27
$0.50/MMBtu decrease in natural gas price (d)	$ ~(3)	$ ~(11)
1.0/MMBtu/MWh increase in market heat rate (f)	$ ~8	$ ~26
1.0/MMBtu/MWh decrease in market heat rate (f)	$ ~(3)	$ ~(10)
MISO/CAISO:
$0.50/MMBtu increase in natural gas price (d)	$ ~9	$ ~92
$0.50/MMBtu decrease in natural gas price (d)	$ ~(3)	$ ~(56)
1.0/MMBtu/MWh increase in market heat rate (g)	$ ~7	$ ~46
1.0/MMBtu/MWh decrease in market heat rate (g)	$ ~(4)	$ ~(35)

___________


(a)	Balance of 2018 is from October 1, 2018 through December 31, 2018.


(b)	Based on Houston Ship Channel natural gas prices at September 30, 2018.


(c)	Based on ERCOT North Hub around-the-clock heat rates at September 30, 2018.


(d)	Based on NYMEX natural gas prices at September 30, 2018.


(e)	Based on AEP Dayton Hub, Northern Illinois Hub and PJM West Hub around-the-clock heat rates at September 30, 2018.


(f)	Based on Massachusetts Hub and NYISO Zone C around-the-clock heat rates at September 30, 2018.


(g)	Based on Indiana Hub and NP15 around-the-clock heat rates at September 30, 2018.

Environmental Matters — See Note 12 to Financial Statements for a discussion of greenhouse gas emissions, the Cross-State Air Pollution Rule, 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, 2018 Compared to Three and Nine Months Ended September 30, 2017



	Three Months Ended September 30,						Favorable (Unfavorable) $ Change			Nine Months Ended September 30,						Favorable (Unfavorable) $ Change
	2018			2017			Favorable (Unfavorable) $ Change			2018			2017			Favorable (Unfavorable) $ Change
Operating revenues	$	3,243		$	1,833		$	1,410		$	6,581		$	4,487		$	2,094
Fuel, purchased power costs and delivery fees	(1,627		)	(838		)	(789		)	(3,492		)	(2,250		)	(1,242		)
Operating costs	(346		)	(218		)	(128		)	(926		)	(626		)	(300		)
Depreciation and amortization	(426		)	(178		)	(248		)	(967		)	(519		)	(448		)
Selling, general and administrative expenses	(194		)	(147		)	(47		)	(711		)	(434		)	(277		)
Operating income	650			452			198			485			658			(173		)
Other income	6			10			(4		)	25			29			(4		)
Other deductions	(1		)	—			(1		)	(4		)	(5		)	1
Interest expense and related charges	(154		)	(76		)	(78		)	(291		)	(169		)	(122		)
Impacts of Tax Receivable Agreement	17			138			(121		)	(65		)	96			(161		)
Equity in earnings of unconsolidated investment	7			—			7			11			—			11
Income before income taxes	525			524			1			161			609			(448		)
Income tax expense	(194		)	(251		)	57			(31		)	(284		)	253
Net income	$	331		$	273		$	58		$	130		$	325		$	(195	)



	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

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	Three Months Ended September 30, 2017
	Retail			ERCOT			Asset Closure			Eliminations / Corporate and Other			Vistra Energy Consolidated
Operating revenues	$	1,286		$	891		$	312		$	(656	)	$	1,833
Fuel, purchased power costs and delivery fees	(1,064		)	(257		)	(173		)	656			(838		)
Operating costs	(4		)	(142		)	(71		)	(1		)	(218		)
Depreciation and amortization	(108		)	(59		)	(1		)	(10		)	(178		)
Selling, general and administrative expenses	(113		)	(27		)	(4		)	(3		)	(147		)
Operating income (loss)	(3		)	406			63			(14		)	452
Other income	10			8			1			(9		)	10
Other deductions	—			—			—			—			—
Interest expense and related charges	—			(9		)	—			(67		)	(76		)
Impacts of Tax Receivable Agreement	—			—			—			138			138
Income before income taxes	7			405			64			48			524
Income tax expense	—			—			—			(251		)	(251		)
Net income (loss)	$	7		$	405		$	64		$	(203	)	$	273

The third quarter is important to full-year results due to the impact of seasonality on our Luminant subsidiaries, particularly in ERCOT. For the three months ended September 30, 2018, net income reflects operating results from operations acquired in the Merger and strong operating performance in our operating segments. Consolidated results increased $58 million to net income of $331 million in the three months ended September 30, 2018 compared to the three months ended September 30, 2017. The change in results was driven by additional operations acquired in the Merger and the impact of the Comanche Peak outage in 2017, partially offset by unrealized mark-to-market gains on commodity risk management activity in 2017 and Q1 2018 plant retirements.

Interest expense and related charges increased $78 million to $154 million in the three months ended September 30, 2018 compared to the three months ended September 30, 2017 and reflected a $112 million increase in interest expense incurred reflecting long-term debt assumed in the Merger, partially offset by a $35 million increase in unrealized mark-to-market gains on interest rate swaps. See Note 20 to the Financial Statements.

For the three months ended September 30, 2018, the Impacts of the Tax Receivable Agreement totaled income of $17 million and reflected a gain due to changes in the estimated amount and timing of TRA payments totaling $32 million, offset by accretion expense totaling $15 million. For the three months ended September 30, 2017, the Impacts of the Tax Receivable Agreement totaled income of $138 million and reflected a gain due to changes in the estimated timing of TRA payments totaling $160 million, partially offset by accretion expense totaling $22 million. 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, 2018, income tax expense totaled $194 million and the effective tax rate was 37.0%. For the three months ended September 30, 2017, income tax expense totaled $251 million and the effective tax rate was 47.9%. See Note 7 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

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	Nine Months Ended September 30, 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 expense	—			—			—			—			—			—			(31		)	(31		)
Net income (loss)	$	397		$	236		$	86		$	41		$	29		$	(24	)	$	(635	)	$	130



	Nine Months Ended September 30, 2017
	Retail			ERCOT			Asset Closure			Eliminations / Corporate and Other			Vistra Energy Consolidated
Operating revenues	$	3,136		$	1,994		$	763		$	(1,406	)	$	4,487
Fuel, purchased power costs and delivery fees	(2,432		)	(752		)	(473		)	1,407			(2,250		)
Operating costs	(11		)	(436		)	(180		)	1			(626		)
Depreciation and amortization	(322		)	(166		)	(1		)	(30		)	(519		)
Selling, general and administrative expenses	(317		)	(85		)	(13		)	(19		)	(434		)
Operating income (loss)	54			555			96			(47		)	658
Other income	23			15			5			(14		)	29
Other deductions	—			(4		)	—			(1		)	(5		)
Interest expense and related charges	—			(14		)	—			(155		)	(169		)
Impacts of Tax Receivable Agreement	—			—			—			96			96
Income (loss) before income taxes	77			552			101			(121		)	609
Income tax expense	—			—			—			(284		)	(284		)
Net income (loss)	$	77		$	552		$	101		$	(405	)	$	325

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For the nine months ended September 30, 2018, net income reflects operating results subsequent to the Merger Date and strong operating performance in our operating segments despite unrealized mark-to-market losses on commodity risk management activity in 2018 reflecting higher forward power prices principally driven by higher market heat rates. Consolidated results decreased $195 million to net income of $130 million in the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017. The change in results was driven by unrealized mark-to-market losses on commodity risk management activity in 2018 as compared to unrealized mark-to-market gains on commodity risk management activity in 2017, one-time Merger-related expenses including severance and transaction fees and Q1 2018 plant retirements, partially offset by additional operations acquired in the Merger and the impact of the Comanche Peak outage in 2017.

Interest expense and related charges increased $122 million to $291 million in the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017 and reflected a $223 million increase in interest expense incurred reflecting long-term debt assumed in the Merger and a $29 million increase in amortization of debt issuance costs, discounts and premiums, partially offset by a $126 million increase in unrealized mark-to-market gains on interest rate swaps. See Note 20 to the Financial Statements.

For the nine months ended September 30, 2018, the Impacts of the Tax Receivable Agreement totaled expense of $65 million and reflected a loss due to changes in the estimated amount and timing of TRA payments totaling $14 million and accretion expense totaling $51 million. For the nine months ended September 30, 2017, the Impacts of the Tax Receivable Agreement totaled income of $96 million and reflected a gain due to changes in the estimated timing of TRA payments totaling $160 million, partially offset by accretion expense totaling $64 million. 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, 2018, income tax expense totaled $31 million and the effective tax rate was 19.3%. For the nine months ended September 30, 2017, income tax expense totaled $284 million and the effective tax rate was 46.6%. 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 entire power generation fleet 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 our 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, 2018 Compared to Three and Nine Months Ended September 30, 2017



	Three Months Ended September 30,						Favorable (Unfavorable) $ Change			Nine Months Ended September 30,						Favorable (Unfavorable) $ Change
	2018			2017			Favorable (Unfavorable) $ Change			2018			2017			Favorable (Unfavorable) $ Change
Net income	$	331		$	273		$	58		$	130		$	325		$	(195	)
Income tax expense	194			251			(57		)	31			284			(253		)
Interest expense and related charges	154			76			78			291			169			122
Depreciation and amortization (a)	446			196			250			1,027			584			443
EBITDA before Adjustments	1,125			796			329			1,479			1,362			117
Unrealized net (gain) loss resulting from hedging transactions	8			(148		)	156			207			(202		)	409
Generation plant retirement expenses	—			24			(24		)	—			24
Fresh start/purchase accounting impacts	(8		)	(15		)	7			26			35			(9		)
Impacts of Tax Receivable Agreement	(17		)	(138		)	121			65			(96		)	161
Reorganization items and restructuring expenses	—			2			(2		)	62			15			47
Non-cash compensation expenses	14			—			14			—			—			—
Transition and merger expenses	19			—			19			205			—			205
Other, net	—			1			(1		)	(4		)	5			(9		)
Adjusted EBITDA	$	1,141		$	522		$	619		$	2,040		$	1,143		$	897

____________


(a)	Includes nuclear fuel amortization in the ERCOT segment of $20 million and $19 million for the three months ended September 30, 2018 and 2017, respectively and $60 million and $66 million for the nine months ended September 30, 2018 and 2017, respectively.

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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	3			(2		)	3			1		1			—			148			154
Depreciation and amortization (a)	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/purchase 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 nuclear fuel amortization of $20 million in ERCOT segment.



	Three Months Ended September 30, 2017
	Retail			ERCOT			Asset Closure		Eliminations / Corporate and Other			Vistra Energy Consolidated
Net income (loss)	$	7		$	405		$	64	$	(203	)	$	273
Income tax expense	—			—			—		251			251
Interest expense and related charges	—			9			—		67			76
Depreciation and amortization (a)	108			77			1		10			196
EBITDA before Adjustments	115			491			65		125			796
Unrealized net (gain) loss resulting from hedging transactions	87			(235		)	—		—			(148		)
Generation plant retirement expenses	—			—			24					24
Fresh start accounting impacts	(19		)	—			4		—			(15		)
Impacts of Tax Receivable Agreement	—			—			—		(138		)	(138		)
Reorganization items and restructuring expenses	—			—			—		2			2
Other, net	(7		)	—			—		8			1
Adjusted EBITDA	$	176		$	256		$	93	$	(3	)	$	522

____________


(a)	Includes nuclear fuel amortization of $19 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	3			13			5			1		1		—			268			291
Depreciation and amortization (a)	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/purchase 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 nuclear fuel amortization of $60 million in ERCOT segment.



	Nine Months Ended September 30, 2017
	Retail			ERCOT			Asset Closure		Eliminations / Corporate and Other			Vistra Energy Consolidated
Net income (loss)	$	77		$	552		$	101	$	(405	)	$	325
Income tax expense	—			—			—		284			284
Interest expense and related charges	—			14			—		155			169
Depreciation and amortization (a)	322			232			1		29			584
EBITDA before Adjustments	399			798			102		63			1,362
Unrealized net (gain) loss resulting from hedging transactions	160			(362		)	—		—			(202		)
Generation plant retirement expenses	—			—			24		—			24
Fresh start accounting impacts	24			(1		)	12		—			35
Impacts of Tax Receivable Agreement	—			—			—		(96		)	(96		)
Reorganization items and restructuring expenses	2			1			—		12			15
Other, net	(13		)	6			—		12			5
Adjusted EBITDA	$	572		$	442		$	138	$	(9	)	$	1,143

____________


(a)	Includes nuclear fuel amortization of $66 million in ERCOT segment.

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Adjusted EBITDA increased by $619 million to $1.141 billion in three months ended September 30, 2018 compared to the three months ended September 30, 2017, primarily due to the following:



PJM, MISO and NY/NE segments acquired in the Merger	$	390
Increase in ERCOT segment driven by operations acquired in the Merger, higher realized prices and the impact of the Comanche Peak outage in 2017	341
Decrease in Retail segment driven by higher power costs in ERCOT	(35		)
Decrease in Asset Closure segment driven by retirement of facilities in first quarter of 2018	(105		)
Corporate and Other	28
Total	$	619

Adjusted EBITDA increased by $897 million to $2.040 billion in the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, primarily due to the following:



PJM, MISO and NY/NE segments acquired in the Merger	$	636
Increase in ERCOT segment driven by operations acquired in the Merger, higher realized prices and the impact of the Comanche Peak outage in 2017	367
Increase in Retail segment driven by Midwest/Northeast margins	23
Decrease in Asset Closure segment driven by retirement of facilities in first quarter of 2018, partially offset by the change in estimates for certain AROs	(167		)
Corporate and Other	38
Total	$	897

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Retail Segment — Three and Nine Months Ended September 30, 2018 and 2017 Compared to Three and Nine Months Ended September 30, 2018 and 2017



	Three Months Ended September 30,						Favorable (Unfavorable) Change			Nine Months Ended September 30,						Favorable (Unfavorable) Change
	2018			2017						2018			2017
Operating revenues:
Revenues in ERCOT	$	1,362		$	1,245		$	117		$	3,423		$	3,085		$	338
Revenues in Northeast/Midwest	442			—			442			778			—			778
Amortization expense	15			20			(5		)	(12		)	(24		)	12
Other revenues	(6		)	21			(27		)	50			75			(25		)
Total operating revenues	1,813			1,286			527			4,239			3,136			1,103
Fuel, purchased power costs and delivery fees:
Purchases from affiliates	(1,108		)	(566		)	(542		)	(2,169		)	(1,235		)	(934		)
Unrealized net gains (losses) on hedging activities with affiliates	(130		)	(89		)	(41		)	49			(171		)	220
Delivery fees	(452		)	(408		)	(44		)	(1,167		)	(1,023		)	(144		)
Other costs	1			(1		)	2			(3		)	(3		)	—
Total fuel, purchased power costs and delivery fees	(1,689		)	(1,064		)	(625		)	(3,290		)	(2,432		)	(858		)
Operating costs	(16		)	(4		)	(12		)	(29		)	(11		)	(18		)
Depreciation and amortization	(80		)	(108		)	28			(237		)	(322		)	85
Selling, general and administrative expenses	(111		)	(113		)	2			(312		)	(317		)	5
Operating income (loss)	(83		)	(3		)	(80		)	371			54			317
Other income	—			10			(10		)	29			23			6
Interest expense and related charges	(3		)	—			(3		)	(3		)	—			(3		)
Net income (loss)	$	(86	)	$	7		$	(93	)	$	397		$	77		$	320
Interest expense and related charges	3			—			3			3			—			3
Depreciation and amortization	80			108			(28		)	237			322			(85		)
EBITDA	(3		)	115			(118		)	637			399			238
Unrealized net (gains) losses on hedging activities	154			87			67			(38		)	160			(198		)
Fresh start/purchase accounting impacts	(15		)	(19		)	4			12			24			(12		)
Reorganization items and restructuring expenses	—			—			—			—			2			(2		)
Other, net	5			(7		)	12			(16		)	(13		)	(3		)
Adjusted EBITDA	$	141		$	176		$	(35	)	$	595		$	572		$	23
Sales volumes (GWh):
Retail electricity sales volumes:
Sales volumes in ERCOT	13,263			12,205			1,058			33,316			30,066			3,250
Sales volumes in Northeast/Midwest	8,042			—			8,042			14,361			—			14,361
Total retail electricity sales volumes	21,305			12,205			9,100			47,677			30,066			17,611
Weather (North Texas average) - percent of normal (a):
Cooling degree days	98.8		%	93.3		%				106.6		%	96.3		%
Heating degree days	—		%	—		%				100.9		%	60.2		%

____________


(a)	Weather data is obtained from Weatherbank, Inc. For the three and nine months ended September 30, 2018, normal is defined as the average over the 10-year period from 2007 to 2016. For the three and nine months ended September 30, 2017, normal is defined as the average over the 10-year period from 2006 to 2015.

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Net income (loss) decreased by $93 million to a net loss of $86 million in the three months ended September 30, 2018 compared to the three months ended September 30, 2017, primarily due to the following:



Unfavorable impact of unrealized net losses on hedging activities	$	(67	)
Unfavorable margins in ERCOT primarily due to higher power costs	(57		)
Lower intercompany interest income	(10		)
Lower depreciation and amortization expenses driven by the retail customer relationship	28
Favorable margins in Midwest/Northeast	17
Higher interest expense and other	(4		)
Total	$	(93	)

Net income increased by $320 million to $397 million in the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, primarily due to the following:



Favorable impact of unrealized net gains on hedging activities	$	198
Lower depreciation and amortization expenses driven by the retail customer relationship	85
Favorable margins in Midwest/Northeast	15
Favorable weather in ERCOT	54
Unfavorable margins in ERCOT primarily due to higher power costs	(56		)
Lower impact from fresh start and purchase accounting related to retail contracts	12
Lower selling, general and administrative and other	12
Total	$	320

Adjusted EBITDA decreased by $35 million to $141 million in the three months ended September 30, 2018 compared to the three months ended September 30, 2017, primarily due to the following:



Unfavorable margins in ERCOT primarily due to higher power costs	$	(57	)
Favorable margins in Midwest/Northeast	17
Lower selling, general and administrative and other	5
Total	$	(35	)

Adjusted EBITDA increased by $23 million to $595 million in the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, primarily due to the following:



Favorable margins in Midwest/Northeast	$	15
Favorable weather in ERCOT	54
Unfavorable margins in ERCOT primarily due to higher power costs	(56		)
Lower selling, general and administrative and other	10
Total	$	23

ERCOT Segment — Three and Nine Months Ended September 30, 2018 Compared to Three and Nine Months Ended September 30, 2017



	Three Months Ended September 30,						Favorable (Unfavorable) Change			Nine Months Ended September 30,						Favorable (Unfavorable) Change
	2018			2017			Favorable (Unfavorable) Change			2018			2017			Favorable (Unfavorable) Change
Operating revenues:
Wholesale electricity sales	$	494		$	89		$	405		$	939		$	361		$	578
Sales to affiliates	709			566			143			1,459			1,235			224
Rolloff of unrealized net gains (losses) representing positions settled in the current period	180			(26		)	206			348			(115		)	463
Unrealized net gains (losses) from changes in fair value	(158		)	163			(321		)	(518		)	319			(837		)

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	Three Months Ended September 30,						Favorable (Unfavorable) Change			Nine Months Ended September 30,						Favorable (Unfavorable) Change
	2018			2017			Favorable (Unfavorable) Change			2018			2017			Favorable (Unfavorable) Change
Unrealized net gains (losses) on hedging activities with affiliates	170			89			81			(37		)	171			(208		)
Other revenues	1			10			(9		)	(1		)	23			(24		)
Operating revenues	$	1,396		$	891		$	505		2,190			1,994			196
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs	(421		)	(251		)	(170		)	(976		)	(677		)	(299		)
Unrealized (gains) losses from hedging activities	3			9			(6		)	—			(13		)	13
Ancillary and other costs	(40		)	(15		)	(25		)	(109		)	(62		)	(47		)
Fuel, purchased power costs and delivery fees	(458		)	(257		)	(201		)	(1,085		)	(752		)	(333		)
Operating costs	(155		)	(142		)	(13		)	(503		)	(436		)	(67		)
Depreciation and amortization	(122		)	(59		)	(63		)	(295		)	(166		)	(129		)
Selling, general and administrative expenses	(18		)	(27		)	9			(73		)	(85		)	12
Operating income	643			406			237			234			555			(321		)
Other income	—			8			(8		)	20			15			5
Other deductions	(2		)	—			(2		)	(5		)	(4		)	(1		)
Interest expense and related charges	2			(9		)	11			(13		)	(14		)	1
Net income	$	643		$	405		$	238		$	236		$	552		$	(316	)
Interest expense and related charges	(2		)	9			(11		)	13			14			(1		)
Depreciation and amortization (including nuclear fuel amortization)	142			77			65			355			232			123
EBITDA	783			491			292			604			798			(194		)
Unrealized net (gains) losses on hedging activities	(195		)	(235		)	40			207			(362		)	569
Fresh start/purchase accounting impacts	—			—			—			(4		)	(1		)	(3		)
Reorganization items and restructuring expenses	—			—			—			—			1			(1		)
Transition and merger expenses	3			—			3			7			—			7
Other, net	6			—			6			(5		)	6			(11		)
Adjusted EBITDA	$	597		$	256		$	341		$	809		$	442		$	367
Production volumes (GWh):
Nuclear facilities	5,197			3,936			1,261			15,744			12,646			3,098
Lignite and coal facilities	8,854			7,344			1,510			21,257			19,508			1,749
Natural gas facilities	11,992			6,026			5,966			26,413			13,496			12,917
Solar facilities	132			—			132			266			—			266
Capacity factors:
Nuclear facilities	102.3		%	77.5		%				104.5		%	83.9		%
Lignite and coal facilities	89.1		%	86.4		%				75.7		%	77.3		%
CCGT facilities	67.9		%	87.6		%				59.6		%	67.2		%
Market pricing:
Average ERCOT North power price ($/MWh)	$	34.67		$	26.26		$	8.41		$	29.31		$	23.85		$	5.46

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Net income increased by $238 million to $643 million in the three months ended September 30, 2018 compared to the three months ended September 30, 2017, primarily due to the following:



Favorable margins driven by higher realized power prices and increased production	$	200
Operating results driven by operations acquired in the Merger	49
Impact related to Comanche Peak outage in 2017	47
Additional operations from Odessa acquired in 2017	33
Lower selling, general and administrative expenses	9
Increased depreciation and amortization driven by facilities acquired in the Merger	(65		)
Unfavorable impact of decrease in unrealized net gains on hedging activities	(40		)
Favorable other	5
Total	$	238

Net income decreased by $316 million to $236 million in the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, primarily due to the following:



Unfavorable impact of unrealized net losses on hedging activities	$	(569	)
Increased depreciation and amortization driven by facilities acquired in the Merger	(123		)
Partial buybacks of the Odessa earn-out provision in 2018	(40		)
Favorable margins driven by higher realized power prices and increased production	205
Operating results driven by operations acquired in the Merger	61
Impact related to Comanche Peak outage in 2017	74
Additional operations from Odessa acquired in 2017	60
Lower selling, general and administrative expenses	12
Insurance reimbursement for Comanche Peak in second quarter of 2018	5
Unfavorable other	(1		)
Total	$	(316	)

Adjusted EBITDA increased by $341 million to $597 million in the three months ended September 30, 2018 compared to the three months ended September 30, 2017, primarily due to the following:



Favorable margins driven by higher realized power prices and increased production	$	200
Operating results driven by operations acquired in the Merger	49
Additional operations from Odessa acquired in 2017	33
Lower selling, general and administrative expenses	9
Impact related to Comanche Peak outage in 2017	47
Favorable other	3
Total	$	341

Adjusted EBITDA increased by $367 million to $809 million in the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, primarily due to the following:



Favorable margins driven by higher realized power prices and increased production	$	205
Operating results driven by operations acquired in the Merger	61
Impact related to Comanche Peak outage in 2017	74
Additional operations from Odessa acquired in 2017	60
Lower selling, general and administrative expenses	12
Insurance reimbursement for Comanche Peak in second quarter of 2018	5
Partial buybacks of the Odessa earn-out provision in 2018	(40		)
Unfavorable other	(10		)
Total	$	367

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PJM Segment — Three and Nine Months Ended September 30, 2018



	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
Operating revenues:
Energy	$	255		$	462
Capacity	164			283
Unrealized net losses on hedging activities	(17		)	(11		)
Sales to affiliates	229			397
Unrealized net losses on hedging activities with affiliates	(11		)	(27		)
Operating revenues	620			1,104
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs	(326		)	(569		)
Fuel for generation facilities and purchased power costs from affiliates	(2		)	(8		)
Unrealized gains from hedging activities	7			18
Other costs	—			(1		)
Fuel, purchased power costs and delivery fees	(321		)	(560		)
Operating costs	(83		)	(165		)
Depreciation and amortization	(141		)	(266		)
Selling, general and administrative expenses	(14		)	(28		)
Operating income	61			85
Other income	1			1
Interest expense and related charges	(3		)	(5		)
Equity in earnings of unconsolidated investment	3			5
Net income	$	62		$	86
Interest expense and related charges	3			5
Depreciation and amortization	141			266
EBITDA	206			357
Unrealized net losses on hedging activities	21			20
Purchase accounting adjustments	(1		)	(2		)
Transition and merger expenses	5			7
Other, net	9			12
Adjusted EBITDA	$	240		$	394
Production volumes (GWh)	15,435			26,686
Capacity factors:
CCGT facilities	68.3		%	66.7		%
Coal facilities	69.5		%	59.6		%
Weather - percent of normal (a):
Cooling degree days	122.6		%	116.9		%
Heating degree days	68.1		%	98.4		%
Average Market On-Peak Power Prices ($/MWh) (b):
PJM West	$	39.98		$	42.59
AD Hub	$	40.25		$	40.57
Average natural gas price - TetcoM3 ($/MMBtu) (c)	$	2.50		$	3.73

____________

(a) Reflects cooling degree days or heating degree days for the PJM Region based on Weather Services International (WSI) data. For the nine months ended September 30, 2018, represents April 9, 2018 through September 30, 2018 only.

(b) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized. For the nine months ended September 30, 2018, represents April 9, 2018 through September 30, 2018 only.

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(c) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us. For the nine months ended September 30, 2018, represents April 9, 2018 through September 30, 2018 only.

Net income totaled $62 million in the three months ended September 30, 2018, primarily reflecting the following:



Generation revenue net of fuel on 15,435 GWh of production	$	156
Capacity revenue	164
Depreciation and amortization	(141		)
Operating costs	(83		)
Unrealized net losses on hedging activities	(21		)
Selling, general and administrative expenses	(14		)
Other	1
Total	$	62

Net income totaled $86 million in the nine months ended September 30, 2018, primarily reflecting the following:



Generation revenue net of fuel on 26,686 GWh of production	$	281
Capacity revenue	283
Depreciation and amortization	(266		)
Operating costs	(165		)
Selling, general and administrative expenses	(28		)
Unrealized net losses on hedging activities	(20		)
Other	1
Total	$	86

Adjusted EBITDA totaled $240 million in the three months ended September 30, 2018, primarily reflecting the following:



Generation revenue net of fuel on 15,435 GWh of production	$	160
Capacity revenue, net of capacity expense	164
Operating costs	(81		)
Selling, general and administrative expenses	(8		)
Equity income from unconsolidated investment and other	5
Total	$	240

Adjusted EBITDA totaled $394 million in the nine months ended September 30, 2018, primarily reflecting the following:



Generation revenue net of fuel on 26,686 GWh of production	$	284
Capacity revenue, net of capacity expense	283
Operating costs	(162		)
Selling, general and administrative expenses	(19		)
Equity income from unconsolidated investment and other	8
Total	$	394

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NY/NE Segment — Three and Nine Months Ended September 30, 2018



	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
Operating revenues:
Energy	$	216		$	331
Capacity	79			162
Unrealized net losses on hedging activities	(6		)	(27		)
Sales to affiliates	16			31
Unrealized net losses on hedging activities with affiliates	(1		)	(5		)
Other revenues	(3		)	(5		)
Operating revenues	301			487
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs	(149		)	(258		)
Fuel for generation facilities and purchased power costs from affiliates	2			—
Unrealized gains from hedging activities	7			10
Other costs	(27		)	(28		)
Fuel, purchased power costs and delivery fees	(167		)	(276		)
Operating costs	(23		)	(48		)
Depreciation and amortization	(55		)	(104		)
Selling, general and administrative expenses	(11		)	(23		)
Operating income	45			36
Interest expense and related charges	(1		)	(1		)
Equity in earnings of unconsolidated investment	3			6
Net income	$	47		$	41
Interest expense and related charges	1			1
Depreciation and amortization	55			104
EBITDA	103			146
Unrealized net losses on hedging activities	—			22
Purchase accounting adjustments	5			9
Transition and merger expenses	1			1
Other, net	2			7
Adjusted EBITDA	$	111		$	185
Production volumes (GWh)	6,030			9,795
Capacity Factor for CCGT Facilities	55.2		%	48.0		%
Weather - percent of normal (a):
Cooling degree days	119.9		%	116.2		%
Heating degree days	72.1		%	99.0		%
Average Market On-Peak Power Prices ($/MWh) (b):
New York - Zone C	$	39.18		$	37.01
Mass Hub	$	43.80		$	48.87
Average natural gas price - Algonquin Citygates ($/MMBtu) (c)	$	2.98		$	4.78

____________

(a) Reflects cooling degree days or heating degree days for the ISO-NE Region based on WSI data. For the nine months ended September 30, 2018, represents April 9, 2018 through September 30, 2018 only.

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Net income totaled $47 million in the three months ended September 30, 2018, primarily reflecting the following:



Capacity revenue	$	79
Generation revenue net of fuel on 6,030 GWh of production	55
Depreciation and amortization	(55		)
Operating costs	(23		)
Selling, general and administrative expenses	(11		)
Other	2
Total	47

Net income totaled $41 million in the nine months ended September 30, 2018, primarily reflecting the following:



Capacity revenue	$	162
Generation revenue net of fuel on 9,795 GWh of production	71
Depreciation and amortization	(104		)
Operating costs	(48		)
Unrealized net losses on hedging activities	(22		)
Selling, general and administrative expenses	(23		)
Other	5
Total	41

Adjusted EBITDA totaled $111 million in the three months ended September 30, 2018, primarily reflecting the following:



Capacity revenue	$	79
Generation revenue net of fuel on 6,030 GWh of production	58
Operating costs	(22		)
Selling, general and administrative expenses and other	(4		)
Total	$	111

Adjusted EBITDA totaled $185 million in the nine months ended September 30, 2018, primarily reflecting the following:



Capacity revenue	$	162
Generation revenue net of fuel on 9,795 GWh of production	80
Operating costs	(47		)
Selling, general and administrative expenses and other	(10		)
Total	$	185

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MISO Segment — Three and Nine Months Ended September 30, 2018



	Three Months Ended September 30, 2018			Nine Months Ended September 30, 2018
Operating revenues:
Energy	$	130		$	211
Capacity	15			44
Unrealized net losses on hedging activities	(6		)	(24		)
Sales to affiliates	124			240
Unrealized net gains (losses) on hedging activities with affiliates	(28		)	20
Other revenues	(5		)	(3		)
Operating revenues	230			488
Fuel, purchased power costs and delivery fees:
Fuel for generation facilities and purchased power costs	(179		)	(313		)
Fuel for generation facilities and purchased power costs from affiliates	30			30
Unrealized gains from hedging activities	2			4
Other costs	(3		)	(4		)
Fuel, purchased power costs and delivery fees	(150		)	(283		)
Operating costs	(61		)	(136		)
Depreciation and amortization	(3		)	(6		)
Selling, general and administrative expenses	(18		)	(33		)
Operating income	(2		)	30
Interest expense and related charges	(1		)	(1		)
Net income (loss)	$	(3	)	$	29
Interest expense and related charges	1			1
Depreciation and amortization	3			6
EBITDA	1			36
Unrealized net losses on hedging activities	32			—
Purchase accounting adjustments	3			11
Transition and merger expenses	1			5
Other, net	2			5
Adjusted EBITDA	$	39		$	57
Production volumes (GWh)	8,293			14,633
Capacity Factor for Coal Facilities	58.3		%	59.4		%
Weather - percent of normal (a):
Cooling degree days	120.9		%	133.4		%
Heating degree days	83.5		%	92.9		%

____________

(a) Reflects cooling degree days or heating degree days for the MISO Region based on WSI data. For the nine months ended September 30, 2018, represents April 9, 2018 through September 30, 2018 only.

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Net loss totaled $3 million in the three months ended September 30, 2018, primarily reflecting the following:



Generation revenue net of fuel on 8,293 GWh of production	$	97
Capacity revenue	15
Operating costs	(61		)
Unrealized net losses on hedging activities	(32		)
Selling, general and administrative expenses	(18		)
Depreciation and amortization	(3		)
Other	(1		)
Total	(3		)

Net income totaled $29 million in the nine months ended September 30, 2018, primarily reflecting the following:



Generation revenue net of fuel on 14,633 GWh of production	$	161
Capacity revenue	44
Operating costs	(136		)
Selling, general and administrative expenses	(33		)
Depreciation and amortization	(6		)
Other	(1		)
Total	29

Adjusted EBITDA totaled $39 million in the three months ended September 30, 2018, primarily reflecting the following:



Generation revenue net of fuel on 8,293 GWh of production	$	100
Capacity revenue	15
Operating costs	(60		)
Selling, general and administrative expenses and other	(16		)
Total	$	39

Adjusted EBITDA totaled $57 million in the nine months ended September 30, 2018, primarily reflecting the following:



Generation revenue net of fuel on 14,633 GWh of production	$	172
Capacity revenue	44
Operating costs	(135		)
Selling, general and administrative expenses and other	(24		)
Total	$	57

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Asset Closure Segment — Three and Nine Months Ended September 30, 2018 Compared to Three and Nine Months Ended September 30, 2017



	Three Months Ended September 30,						Favorable (Unfavorable) Change			Nine Months Ended September 30,						Favorable (Unfavorable) Change
	2018			2017			Favorable (Unfavorable) Change			2018			2017			Favorable (Unfavorable) Change
Operating revenues	$	(1	)	$	312		$	(313	)	$	48		$	763		$	(715	)
Fuel, purchased power costs and delivery fees	—			(173		)	173			(37		)	(473		)	436
Operating costs	(3		)	(71		)	68			(33		)	(180		)	147
Depreciation and amortization	—			(1		)	1			—			(1		)	1
Selling, general and administrative expenses	—			(4		)	4			(4		)	(13		)	9
Operating income (loss)	(4		)	63			(67		)	(26		)	96			(122		)
Other income	—			1			(1		)	2			5			(3		)
Net income (loss)	$	(4	)	$	64		$	(68	)	$	(24	)	$	101		$	(125	)
Depreciation and amortization	—			1			(1		)	—			1			(1		)
EBITDA	(4		)	65			(69		)	(24		)	102			(126		)
Generation plant retirement expenses	—			24			(24		)	—			24			(24		)
Fresh start accounting impacts	—			4			(4		)	—			12			(12		)
Transition and merger expenses	—			—			—			2			—			2
Other	(8		)	—			(8		)	(7		)	—			(7		)
Adjusted EBITDA	$	(12	)	$	93		$	(105	)	$	(29	)	$	138		$	(167	)
Production volumes (GWh)	—			7,437			(7,437		)	1,513			19,005			(17,492		)

Results for the Asset Closure segment reflect the retirement of the Stuart and Killen plants in May 2018 (acquired in the Merger) and the retirement of the Monticello, Sandow and Big Brown plants in January and February 2018 (see Note 4 to the Financial Statements) and corresponding 100% and 92% decreases in volume in the three and nine months ended September 30, 2018, respectively. Operating costs for the nine months ended September 30, 2018 included ongoing costs associated with closing these plants as well as a favorable adjustment to the estimated asset retirement obligation of $21 million.

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

The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2018 and 2017. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $207 million in unrealized net losses for the nine months ended September 30, 2018 and $202 million in unrealized net gains for the nine months ended September 30, 2017 arising from mark-to-market accounting for positions in the commodity contract portfolio.



	Nine Months Ended September 30,
	2018			2017
Commodity contract net asset (liability) at beginning of period	$	(96	)	$	64
Settlements/termination of positions (a)	416			(134		)
Changes in fair value of positions in the portfolio (b)	(623		)	336
Acquired commodity contracts in Merger (c)	(452		)	—
Other activity (d)	72			(45		)
Commodity contract net asset (liability) at end of period	$	(683	)	$	221

____________

(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, 2018 and 2017 includes reversal of $10 million and $38 million, respectively, of previously recorded unrealized gains related to Vistra Energy beginning balances. The nine months ended September 30, 2018 also includes reversal of $315 million 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 at the Merger Date (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 on the CME.

Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair values at September 30, 2018, 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, 2018
Source of fair value	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	(74	)	$	(6	)	$	(1	)	$	—		$	(81	)
Prices provided by other external sources	(385		)	29			—			(2		)	(358		)
Prices based on models	(81		)	(148		)	(11		)	(4		)	(244		)
Total	$	(540	)	$	(125	)	$	(12	)	$	(6	)	$	(683	)

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FINANCIAL CONDITION

Cash Flows

Nine Months Ended September 30, 2018 Compared to Nine Months ended September 30, 2017 — Cash provided by operating activities totaled $863 million and $845 million in the nine months ended September 30, 2018 and 2017, respectively. The favorable change of $18 million was primarily driven by increased cash from operations reflecting operations acquired in the Merger, partially offset by increased interest paid of $460 million due to the assumption of long-term debt obligations in the Merger and an increase in cash used for margin deposits of $222 million related to derivative contracts.

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 (loss) by $103 million and $102 million for the nine months ended September 30, 2018 and 2017, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the statements of consolidated income (loss) consistent with industry practice, and amortization of intangible net assets and liabilities that are reported in various other statements of condensed consolidated income (loss) line items including operating revenues and fuel and purchased power costs and delivery fees.

Cash used in financing activities totaled $2.172 billion and $37 million in the nine months ended September 30, 2018 and 2017, respectively. The increase in cash used in financing activities was driven by:


•	cash tender offers to purchase $1.542 billion of senior notes assumed in the Merger;


•	the amendment to the Vistra Operations Credit Facilities, including the repayment of $500 million in borrowings under the Term C Facility;


•	the redemption of $850 million principal amount of outstanding 6.75% Senior Notes in May 2018, and


•	$414 million of cash paid for share repurchases in the second and third quarters of 2018,

partially offset by:


•	the issuance of $1.0 billion principal amount of Vistra Operations 5.500% senior notes due 2026, and


•	proceeds of $350 million from the accounts receivable securitization program.

Cash provided by investing activities totaled $133 million in the nine months ended September 30, 2018, compared to cash used in investing activities of $631 million in the nine months ended September 30, 2017, respectively. Cash provided by investing activities in 2018 reflected $445 million of cash acquired in the Merger (see Note 2 to the Financial Statements). Capital expenditures (including nuclear fuel purchases) totaled $275 million and $142 million in the nine months ended September 30, 2018 and 2017, respectively. Cash used in investing activities in the nine months ended September 30, 2017 also included $355 million related to the Odessa Acquisition (see Note 3 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, 2018:



	September 30, 2018		December 31, 2017		Change
Cash and cash equivalents (a)	$	811	$	1,487	$	(676	)
Vistra Operations Credit Facilities — Revolving Credit Facility	1,290		834		456
Vistra Operations Credit Facilities — Term Loan C Facility (b)	—		7		(7		)
Total available liquidity	$	2,101	$	2,328	$	(227	)

___________


(a)	Cash and cash equivalents excludes $500 million of restricted cash held for letter of credit support at December 31, 2017 (see Note 20 to the Financial Statements).

(b)

The Term Loan C Facility was used for issuing letters of credit for general corporate purposes. Borrowings totaling $500 million under this facility were held in collateral accounts at December 31, 2017, and were reported as restricted cash in our condensed consolidated balance sheets. In June 2018, the Vistra Operations Credit Facilities were amended, and the Term Loan C Facility was repaid using $500 million of cash from the collateral accounts used to backstop letters of credit.

The decrease in available liquidity to $2.101 billion in the nine months ended September 30, 2018 was primarily driven by cash tender offers to purchase $1.542 billion of senior notes assumed in the Merger, the redemption of $850 million principal amount of outstanding 6.75% senior notes, the amendment to the Vistra Operations Credit Facilities, including the repayment of $500 million in borrowings under the Term C Facility, and $414 million in cash paid for share repurchases, partially offset by the issuance of $1.0 billion principal amount of Vistra Operations 5.500% senior notes, $445 million of cash acquired in the Merger, increased available capacity under the Revolving Credit Facility, proceeds of $350 million from the accounts receivable securitization program and increased cash from operations.

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.

Capital Expenditures

Estimated capital expenditures and nuclear fuel purchases for 2018 are expected to total approximately $445 million and include:


•	$264 million for investments in generation and mining facilities:


•	$109 million for nuclear fuel purchases, and


•	$72 million for information technology and other corporate investments.

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.

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At September 30, 2018, we received or posted cash and letters of credit for commodity hedging and trading activities as follows:


•	$177 million in cash has been posted with counterparties as compared to $30 million posted at December 31, 2017;


•	$4 million in cash has been received from counterparties as compared to $4 million received at December 31, 2017;


•	$1.030 billion in letters of credit have been posted with counterparties as compared to $390 million posted at December 31, 2017, and


•	$8 million in letters of credit have been received from counterparties as compared to $3 million received at December 31, 2017.

Income Tax Payments

In the next twelve months, we do not expect to make federal income tax payments due to Vistra Energy's forecasted taxable loss position in 2018, and we expect to receive a refund of $21 million related to Vistra Energy's 2017 federal tax return. We expect to make state income tax payments of approximately $21 million and TRA payments of approximately $20 million in the next twelve months. There were $66 million and $51 million of income tax payments for the nine months ended September 30, 2018 and 2017, respectively.

Financial Covenants

The Credit Facilities Agreement includes a covenant, solely with respect to the Revolving Credit Facility and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $300 million) exceed 30% of the revolving commitments), that requires the consolidated first lien net leverage ratio not exceed 4.25 to 1.00. As of September 30, 2018, we were in compliance with this financial covenant.

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, 2018, Vistra Energy has posted letters of credit in the amount of $55 million with the PUCT, which is subject to adjustments.

The ISOs we operate in have rules in place to assure adequate creditworthiness of parties that participate in the markets operated by those ISOs. Under these rules, Vistra Energy has posted collateral support, in the form of letters of credit and cash, totaling $192 million at September 30, 2018 (which is subject to daily adjustments based on settlement activity with the ISO).

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 $5.8 billion at September 30, 2018) under such facilities.

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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 in excess of $300 million that results in the acceleration of such debt, would give each 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 Vistra Operations' senior notes indenture, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any subsidiary guarantor for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more, may result in a cross default under the senior notes.

Each of Vistra Energy's indentures for each series of senior notes (except with respect to the Consent Senior Notes) and the TEUs, respectively, contain a cross default provision. A default by Vistra Energy, as issuer of each series of senior notes and the TEUs, respectively, in respect of certain specified indebtedness in an aggregate amount in excess of $100 million may result in a cross default under the respective indentures of the senior notes and TEUs. Such a default would allow the trustee or noteholders holding at least 25% in principal amount of the respective series of senior notes or TEUs that are outstanding (each such series treated as a separate class) to accelerate the maturity of such portion of the principal amount of all securities of such series of senior notes or TEUs, respectively.

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 Program 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.

Guarantees

See Note 12 to the Financial Statements for discussion of guarantees.

OFF–BALANCE SHEET ARRANGEMENTS

We do not have any off-balance sheet arrangements.

COMMITMENTS AND CONTINGENCIES

See Note 12 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.

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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 a several factors, including the size, duration and composition of our energy and financial portfolio, as well as the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swaps to hedge debt costs, as well as exchange-traded, over-the-counter contracts and other contractual arrangements to hedge commodity prices.

Risk Oversight

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

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

Commodity Price Risk

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

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

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

Parametric processes are used to calculate VaR and are considered by management to be the most effective way to estimate changes in a portfolio's value based on assumed market conditions for liquid markets. The use of this method requires a number of key assumptions, such as use of (i) an assumed confidence level; (ii) an assumed holding period (i.e., the time necessary for management action, such as to liquidate positions); and (iii) historical estimates of volatility and correlation data. The table below details certain VaR measures 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 2019.



	Three Months Ended September 30, 2018		Year Ended December 31, 2017
Month-end average VaR:	$	161	$	92
Month-end high VaR:	$	208	$	140
Month-end low VaR:	$	65	$	62

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The increase in the month-end high VaR risk measure in 2018 reflected operations acquired in the Merger.

Interest Rate Risk

At September 30, 2018, 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 $11 million, taking into account the interest rate swaps discussed in Note 11 to Financial Statements.

Credit Risk

Credit risk relates to the risk of loss associated with nonperformance by counterparties. We minimize credit risk by evaluating potential counterparties, monitoring ongoing counterparty risk and assessing overall portfolio risk. This includes review of counterparty financial condition, current and potential credit exposures, credit rating and other quantitative and qualitative credit criteria. We also employ certain risk mitigation practices, including utilization of standardized master agreements that provide for netting and setoff rights, as well as credit enhancements such as margin deposits and customer deposits, letters of credit, parental guarantees and surety bonds. See Note 15 to the Financial Statements for further discussion of this exposure.

Credit Exposure — Our gross credit exposure (excluding collateral impacts) associated with retail and wholesale trade accounts receivable and net derivative assets arising from commodity contracts and hedging and trading activities totaled $1.281 billion at September 30, 2018.

At September 30, 2018, Retail segment credit exposure totaled $1.051 billion, including $1.044 billion of trade accounts receivable and $7 million related to derivative assets. Cash deposits and letters of credit held as collateral for these receivables totaled $40 million, resulting in a net exposure of $1.011 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, 2018, aggregate ERCOT, PJM, NY/NE and MISO segments credit exposure totaled $230 million including $111 million related to derivative assets and $119 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 $224 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, 2018. 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	$	176	$	—	$	176
Below investment grade or no rating	54		6		48
Totals	$	230	$	6	$	224

Significant (10% or greater) concentration of credit exposure exists with two counterparties, which represented an aggregate $108 million, or 48%, 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.

At September 30, 2018, interest rate swap exposure in the Corporate and Other non-segment totaled $171 million. There are no collateral offsets. The counterparty credit rating is investment grade.

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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 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 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 regulatory authorities;


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

•

prevailing governmental policies and regulatory actions, including those of the legislatures and other government actions of states in which we operate, the U.S. Congress, the FERC, the NERC, the Texas Reliability Entity, Inc., the public utility commissions of states 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 tax laws and policies;


◦	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 cyber security 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;


•	changes in the ability of vendors to provide or deliver commodities as needed;

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•	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, our changes to, 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 CP 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 integrate the businesses of Vistra Energy and Dynegy and our ability to successfully capture any projected synergies relating to the Merger, 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 in effect at the end of the current period included in this quarterly report on Form 10-Q. On the Merger Date, Dynegy merged with and into Vistra Energy. The evaluation considered that Vistra Energy is currently in the process of integrating certain processes, technology and operations of the combined company 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 Merger, there have been no changes in our internal control over financial reporting that have materially affected, or is 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 12 to the Financial Statements regarding legal proceedings.


Item 1A.	RISK FACTORS

There have been no material changes to the risk factors discussed in Part II, Item 1A. Risk Factors in our June 30, 2018 quarterly report on Form 10-Q. 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 Securities Exchange Act of 1934, as amended, during the quarter ended September 30, 2018.



	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) (a)
July 1 - July 31, 2018	3,240,864	$	23.16	3,240,864	$	350
August 1 - August 31, 2018	6,308,888	$	22.76	6,308,888	$	206
September 1 - September 30, 2018	5,569,280	$	23.32	5,569,280	$	76
For the quarter ended September 30, 2018	15,119,032	$	23.05	15,119,032	$	76

____________


(a)	On a cumulative basis through October 19, 2018, 21,421,925 shares of our common stock had been repurchased for $500 million (including related fees and expenses) at an average price per share of common stock of $23.36.

In June 2018, we announced that our board of directors had authorized a share repurchase program (the Program) under which up to $500 million of our outstanding common stock could be repurchased. The Program was effective as of June 13, 2018, and the program was completed on October 19, 2018.

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 Securities Exchange Act of 1934, as amended, or by other means in accordance with federal securities laws. The actual timing, number and value of shares repurchased under the Program 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 operates, or 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(a) to this quarterly report on Form 10-Q.


Item 5.	OTHER INFORMATION

None.


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(a)	001-33443 Form 8-K (filed on October 30, 2014)	4.8	—	2022 Notes Indenture, dated October 27, 2014, among Dynegy Finance II, Inc. and the Trustee

4(b)	001-33443 Form 8-K (filed on April7, 2015)	4.11	—	First Supplemental Indenture to the 2022 Notes Indenture, dated April 1, 2015, between Dynegy and the Trustee

4(c)	001-33443 Form 8-K (filed on April 7, 2015)	4.12	—	Second Supplemental Indenture to the 2022 Notes Indenture, dated April 1, 2015, among Dynegy, the Subsidiary Guarantors and the Trustee

4(d)	001-33443 Form 8-K (filed on April 8, 2015)	4.17	—	Third Supplemental Indenture to the 2022 Notes Indenture, dated April 2, 2015, among Dynegy, the Subsidiary Guarantors and the Trustee

4(e)	001-33443 Form10-Q(Quarter ended June 30, 2015) (filed on August 7, 2015)	4.2	—	Fourth Supplemental Indenture to the 2022 Notes Indenture, dated May 11, 2015, among Dynegy, the Subsidiary Guarantors and the Trustee

4(f)	001-33443 Form 10-Q (Quarter ended September 30, 2015) (filed on November 5, 2015)	4.2	—	Fifth Supplemental Indenture to the 2022 Notes Indenture, dated September 21, 2015, among Dynegy, the Subsidiary Guarantors and the Trustee

4(g)	001-33443 Form 10-K (Year ended December 31, 2016) (filed on February 24, 2017)	4.24	—	Sixth Supplemental Indenture to the 2022 Notes Indenture, dated February 2, 2017, among Dynegy, the Subsidiary Guarantors and the Trustee

4(h)	001-33443 Form 10-K (Year ended December 31, 2016) (filed on February 24, 2017)	4.25	—	Seventh Supplemental Indenture to the 2022 Notes Indenture, dated February 7, 2017, among Dynegy, the Subsidiary Guarantors and the Trustee

4(i)	001-38086 Form 8-K (filed on April 9, 2018)	4.19	—	Eighth Supplemental Indenture to the 2022 Notes Indenture, dated April 9, 2018, among the Company, the Subsidiary Guarantors and the Trustee

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Exhibits	Previously Filed With File Number*	As Exhibit
4(j)	001-38086 Form 8-K (filed on June 15, 2018)	4.1	—	Ninth Supplemental Indenture to the 2022 Notes Indenture, dated June 14, 2018, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee

4(k)	001-33443 Form 8-K (filed on October 30, 2014)	4.8	—	Form of 7.375% Senior Note due 2022

4(l)	001-33443 Form 8-K (filed on May 21, 2013)	4.1	—	2023 Notes Indenture, dated May 20, 2013, among Dynegy, the Subsidiary Guarantors and the Trustee

4(m)	001-33443 Form 10-K (Year ended December 31, 2013) (filed on February 27, 2014)	4.3	—	First Supplemental Indenture to the 2023 Notes Indenture, dated as of December 5, 2014, among Dynegy, the Subsidiary Guarantors and the Trustee

4(n)	001-33443 Form 8-K (filed on April 7, 2015)	4.20	—	Second Supplemental Indenture to the 2023 Notes Indenture, dated April 1, 2015, among Dynegy, the Subsidiary Guarantors and the Trustee

4(o)	001-33443 Form 8-K (filed on April 8, 2015)	4.28	—	Third Supplemental Indenture to the 2023 Notes Indenture, dated April 2, 2015, among Dynegy, the Subsidiary Guarantors and the Trustee

4(p)	001-33443 Form10-Q (Quarter ended June 30, 2015) (filed on August 7, 2015)	4.4	—	Fourth Supplemental Indenture to the 2023 Notes Indenture, dated May 11, 2015, among Dynegy, the Subsidiary Guarantors

4(q)	001-33443 Form 10-Q (Quarter ended September 30, 2015) (filed on November 5, 2015)	4.4	—	Fifth Supplemental Indenture to the 2023 Notes Indenture, dated September 21, 2015, among Dynegy, the Subsidiary Guarantors and the Trustee

4(r)	001-33443 Form10-K (Year ended December 31, 2016) (filed on February 24, 2017)	4.7	—	Sixth Supplemental Indenture to the 2023 Notes Indenture, dated February 2, 2017, among Dynegy, the Subsidiary Guarantors and the Trustee

4(s)	001-33443 Form10-K (Year ended December 31, 2016) (filed on February 24, 2017)	4.8	—	Seventh Supplemental Indenture to the 2023 Notes Indenture, dated February 7, 2017, among Dynegy, the Subsidiary Guarantors and the Trustee

4(t)	001-38086 Form 8-K (filed on April 9, 2018)	4.29	—	Eighth Supplemental Indenture to the 2023 Notes Indenture, dated April 9, 2018, among the Company, the Subsidiary Guarantors and the Trustee

4(u)	001-38086 Form 8-K (filed on June 15, 2018)	4.2	—	Ninth Supplemental Indenture to the 2023 Notes Indenture, dated June 14, 2018, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee

4(v)	001-33443 Form 8-K (filed on May 21, 2013)	4.1	—	Form of 5.875% Senior Note due 2023

4(w)	001-33443 Form 8-K (filed on October 30, 2014)	4.9	—	2024 7.625% Notes Indenture, dated October 27, 2014, among Dynegy Finance II, Inc. and the Trustee

4(x)	001-33443 Form 8-K (filed on April 7, 2015)	4.14	—	First Supplemental Indenture to the 2024 7.625% Notes Indenture, dated April 1, 2015, between Dynegy and the Trustee

4(y)	001-33443 Form 8-K (filed on April 7, 2015)	4.15	—	Second Supplemental Indenture to the 2024 7.625% Notes Indenture, dated April 1, 2015, among Dynegy, the Subsidiary Guarantors and the Trustee

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Exhibits	Previously Filed With File Number*	As Exhibit
4(z)	001-33443 Form 8-K (filed on April 8, 2015)	4.21	—	Third Supplemental Indenture to the 2024 7.625% Notes Indenture, dated April 2, 2015, among Dynegy, the Subsidiary Guarantors and the Trustee

4(aa)	001-33443 Form10-Q (Quarter ended June 30, 2015) (filed on August 7, 2015)	4.3	—	Fourth Supplemental Indenture to the 2024 7.625% Notes Indenture, dated May 11, 2015, among Dynegy, the Subsidiary Guarantors and the Trustee

4(bb)	001-33443 Form 10-Q (Quarter ended September 30, 2015) (filed on November 5, 2015)	4.3	—	Fifth Supplemental Indenture to the 2024 7.625% Notes Indenture, dated September 21, 2015, among Dynegy, the Subsidiary Guarantors and the Trustee

4(cc)	001-33443 Form10-K (Year ended December 31, 2016) (filed on February 24, 2017)	4.32	—	Sixth Supplemental Indenture to the 2024 7.625% Notes Indenture, dated February 2, 2017, among Dynegy, the Subsidiary Guarantors and the Trustee

4(dd)	001-33443 Form10-K (Year ended December 31, 2016) (filed on February 24, 2017)	4.33	—	Seventh Supplemental Indenture to the 2024 7.625% Notes Indenture, dated February 7, 2017, among Dynegy, the Subsidiary Guarantors and the Trustee

4(ee)	001-38086 Form 8-K (filed on April 9, 2018)	4.39	—	Eighth Supplemental Indenture to the 2024 7.625% Notes Indenture, dated April 9, 2018, among the Company, the Subsidiary Guarantors and the Trustee

4(ff)	001-38086 Form 8-K (filed on June 15, 2018)	4.3	—	Ninth Supplemental Indenture to the 2024 7.625% Notes Indenture, dated June 14, 2018, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee

4(gg)	001-33443 Form of 8-K (filed on October 30, 2014)	4.9	—	Form of 7.625% Senior Note due 2024

4(hh)	001-33443 Form 8-K (filed on February 7, 2017)	4.2	—	2024 8.034% Notes Indenture, dated February 2, 2017, by and among Dynegy, the guarantors party thereto and the Trustee

4(ii)	001-33443 Form10-K (Year ended December 31, 2016) (filed on February 24, 2017)	4.41	—	First Supplemental Indenture to the 2024 8.034% Notes Indenture, dated February 7, 2017, between Dynegy, the Subsidiary Guarantors and the Trustee

4(jj)	001-38086 Form 8-K (filed on April 9, 2018)	4.43	—	Second Supplemental Indenture to the 2024 8.034% Notes Indenture, dated April 9, 2018, among the Company, the Subsidiary Guarantors and the Trustee

4(kk)	001-38086 Form 8-K (filed on June 15, 2018)	4.4	—	Third Supplemental Indenture to the 2024 8.034% Notes Indenture, dated June 14, 2018, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee

4(ll)	001-38086 Form 8-K (filed on August 23, 2018)	4.5	—	Fourth Supplemental Indenture to the 2024 8.034% Notes Indenture, dated August 22, 2018, by and among the Company and Wilmington Trust, National Association, as Trustee

4(mm)	001-33443 Form of 8-K (filed on February 7, 2017)	4.2	—	Form of 8.034% Senior Note due 2024

4(nn)	001-33443 Form 8-K (filed on October 11, 2016)	4.1	—	2025 Notes Indenture, dated October 11, 2016, between Dynegy and the Trustee

4(oo)	001-33443 Form10-K (Year ended December 31, 2016) (filed on February 24, 2017)	4.35	—	First Supplemental Indenture to the 2025 Notes Indenture, dated February 2, 2017, between Dynegy, the Subsidiary Guarantors and the Trustee

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Exhibits	Previously Filed With File Number*	As Exhibit
4(pp)	001-33443 Form10-K (Year ended December 31, 2016) (filed on February 24, 2017)	4.36	—	Second Supplemental Indenture to the 2025 Notes Indenture, dated February 7, 2017, between Dynegy, the Subsidiary Guarantors and the Trustee

4(qq)	001-38086 Form 8-K (filed on April 9, 2018)	4.48	—	Third Supplemental Indenture to the 2025 Notes Indenture, dated April 9, 2018, among the Company, the Subsidiary Guarantors and the Trustee

4(rr)	001-38086 Form 8-K (filed on June 15, 2018)	4.5	—	Fourth Supplemental Indenture to the 2025 Notes Indenture, dated June 14, 2018, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee

4(ss)	001-38086 Form 8-K (filed on August 23, 2018)	4.6	—	Fifth Supplemental Indenture to the 2025 Notes Indenture, dated August 22, 2018, by and among the Company and Wilmington Trust, National Association, as Trustee

4(tt)	001-33443 Form 8-K (filed on October 11, 2016)	4.1	—	Form of 8.000% Senior Note due 2025

4(uu)	001-33443 Form 8-K (filed on August 21, 2017)	4.1	—	2026 Notes Indenture, dated August 21, 2017, among Dynegy, the Subsidiary Guarantors and the Trustee

4(vv)	001-33443 Form 8-K (filed on August 21, 2017)	4.2	—	Registration Rights Agreement, dated August 21, 2017, among Dynegy, the Subsidiary Guarantors and the Trustee

4(ww)	001-38086 Form 8-K (filed on April 9, 2018)	4.52	—	First Supplemental Indenture to the 2026 Notes Indenture, dated April 9, 2018, among the Company, the Subsidiary Guarantors and the Trustee

4(xx)	001-38086 Form 8-K (filed on June 15, 2018)	4.6	—	Second Supplemental Indenture to the 2026 Notes Indenture, dated June 14, 2018, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee

4(yy)	001-38086 Form 8-K (filed on August 23, 2018)	4.4	—	Third Supplemental Indenture to the 2026 Notes Indenture, dated August 22, 2018, by and among the Company and Wilmington Trust, National Association, as Trustee

4(zz)	001-33443 Form 8-K (filed on August 21, 2017)	4.1	—	Form of 8.125% Senior Note due 2026

4(aaa)	001-38086 Form 8-K (filed on August 23, 2018)	4.1	—	Indenture for 5.500% Senior Note due 2026, dated as of August 22, 2018, among Vistra Operations Company LLC, as issuer, the Subsidiary Guarantors (as defined therein), and Wilmington Trust, National Association, as Trustee

4(bbb)	001-38086 Form 8-K (filed on August 23, 2018)	4.2	—	Form of Rule 144A Global Security for 5.500% Senior Note due 2026 (included in Exhibit 4.1)

4(ccc)	001-38086 Form 8-K (filed on August 23, 2018)	4.3	—	Form of Regulation S Global Security for 5.500% Senior Note due 2026 (included in Exhibit 4.1)

4(ddd)	001-38086 Form 8-K (filed on August 23, 2018)	4.7	—	Purchase and Sale Agreement dated as of August 21, 2018, between TXU Energy Retail Company LLC as originator, and TXU Energy Receivables Company LLC, as purchaser

4(eee)	001-38086 Form 8-K (filed on August 23, 2018)	4.8	—	Receivable Purchase Agreement dated as of August 21, 2018, among TXU Energy Receivables Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as performance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator

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Exhibits	Previously Filed With File Number*	As Exhibit

4(fff)	001-33443 Form 8-K (filed on June 21, 2016)	4.3	—	Purchase Contract Agreement, dated June 21, 2016, between Dynegy and the Trustee

4(ggg)	001-38086 Registration Statement on Form 8-A (filed on April 9, 2018)	4.5	—	First Supplement to the Purchase Contract Agreement, dated April 9, 2018, between the Company, the Purchase Contract Agent and the Trustee

4(hhh)	001-33443 Form 8-K (filed on June 21, 2016)	4.3	—	Form of Unit

4(iii)	001-33443 Form 8-K (filed on June 21, 2016)	4.3	—	Form of Purchase Contract

4(jjj)	001-33443 Form 8-K (filed on June 21, 2016)	4.1	—	Amortizing Notes Indenture, dated June 21, 2016, between Dynegy and the Trustee

4(kkk)	001-33443 Form 8-K (filed on June 21, 2016)	4.2	—	First Supplemental Indenture to the Amortizing Notes Indenture, dated June 21, 2016, between Dynegy and the Trustee

4(lll)	001-38086 Registration Statement on Form 8-A (filed on April 9, 2018)	4.3	—	Second Supplemental Indenture to the Amortizing Notes Indenture, dated April 9, 2018, between the Company and the Trustee

4(mmm)	001-33443 Form 8-K (filed on June 21, 2016)	4.2	—	Form of Amortizing Note

4(nnn)	001-33443 Form of 8-K (filed on February 7, 2017)	4.1	—	Warrant Agreement, dated February 2, 2017, by and among Dynegy, Computershare Inc. and Computershare Trust Company, N.A., as warrant agent

4(ooo)	001-38086 Registration Statement on Form 8-A (filed on April 9, 2018)	4.2	—	Supplemental Warrant Agreement, dated as of April 9, 2018 among the Company and the Warrant Agent

4(ppp)	001-33443 Form of 8-K (filed on February 7, 2017)	4.1	—	Form of Warrant

4(qqq)	333-215288 Amendment No. 3 to Form S-1 (filed May 1, 2017)	4.1	—	Registration Rights Agreement, dated October 3, 2016

(10)	Material Contracts

10(a)	001-38086 Form 8-K (filed on August 23, 2018)	10.1	—	Amendment No. 1 to Registration Rights Agreement dated as of August 22, 2018, by and among the Company and the Guarantors (as defined therein)

10(b)	001-38086 Form 8-K (filed on August 7, 2018)	10.1	—	Purchase Agreement, dated August 7, 2018, by and among Vistra Operations Company LLC and Citigroup Global Markets Inc., on behalf of itself and the several Initial Purchasers named in Schedule I to the Purchase Agreement

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

31(a)	**		—	Certification of Curtis A. Morgan, principal executive 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
31(b)	**		—	Certification of J. William Holden, principal financial officer of Vistra Energy Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

(32)	Section 1350 Certifications

32(a)	**		—	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(b)	**		—	Certification of J. William Holden, 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(a)	**		—	Mine Safety Disclosures

	XBRL Data Files

101.INS	**		—	XBRL Instance Document

101.SCH	**		—	XBRL Taxonomy Extension Schema Document

101.CAL	**		—	XBRL Taxonomy Extension Calculation Document

101.DEF	**		—	XBRL Taxonomy Extension Definition Document

101.LAB	**		—	XBRL Taxonomy Extension Labels Document

101.PRE	**		—	XBRL Taxonomy Extension Presentation Document

____________________


*	Incorporated herein by reference


**	Filed 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 hereunto duly authorized.



			Vistra Energy Corp.

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

Date: November 2, 2018