Vistra Corp. - FORM 10-Q

Attached files

file	filename
EX-95.A - MINE SAFETY DISCLOSURES - Vistra Corp.	vistra-2018331xexhibit95a.htm
EX-32.B - CERTIFICATION OF J. WILLIAM HOLDEN - Vistra Corp.	vistra-2018331xexhibit32b.htm
EX-32.A - CERTIFICATION OF CURTIS A. MORGAN - Vistra Corp.	vistra-2018331xexhibit32a.htm
EX-31.B - CERTIFICATION OF J. WILLIAM HOLDEN - Vistra Corp.	vistra-2018331xexhibit31b.htm
EX-31.A - CERTIFICATION OF CURTIS A. MORGAN - Vistra Corp.	vistra-2018331xexhibit31a.htm

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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 MARCH 31, 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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 (Do not check if a smaller reporting company)

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 May 1, 2018, there were 522,955,994 shares of common stock, par value $0.01, outstanding of Vistra Energy Corp.

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TABLE OF CONTENTS



		PAGE
GLOSSARY		ii
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Statements of Consolidated Income (Loss) — Three Months Ended March 31, 2018 and 2017	1
	Condensed Statements of Consolidated Comprehensive Income (Loss) — Three Months Ended March 31, 2018 and 2017	1
	Condensed Statements of Consolidated Cash Flows — Three Months Ended March 31, 2018 and 2017	2
	Condensed Consolidated Balance Sheets — March 31, 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	36
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46
Item 4.	Controls and Procedures	50
PART II.	OTHER INFORMATION	51
Item 1.	Legal Proceedings	51
Item 1A.	Risk Factors	51
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51
Item 3.	Defaults Upon Senior Securities	51
Item 4.	Mine Safety Disclosures	51
Item 5.	Other Information	51
Item 6.	Exhibits	52
SIGNATURE		58

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"), TXU Energy or Luminant 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

CCGT		combined cycle gas turbine

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., the independent system operator and the regional coordinator of various electricity systems within Texas

FERC		U.S. Federal Energy Regulatory Commission

GAAP		generally accepted accounting principles

GWh		gigawatt-hours

ICE		IntercontinentalExchange

IRS		U.S. Internal Revenue Service

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, all largely in Texas

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 in ERCOT (generally natural gas plants), by the market price of natural gas.

Merger		the merger of Dynegy with and into Vistra Energy, with Vistra Energy as the surviving corporation

Merger Agreement		the Agreement and Plan of Merger, dated as of October 29, 2017, by and between Vistra Energy and Dynegy, as it may be amended or modified from time to time

Merger Date		April 9, 2018, the date Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement

MMBtu		million British thermal units

MW		megawatts

MWh		megawatt-hours

NRC		U.S. Nuclear Regulatory Commission

NYMEX		the New York Mercantile Exchange, a commodity derivatives exchange

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Oncor		Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., that is engaged in regulated electricity transmission and distribution activities

Oncor Holdings		Oncor Electric Delivery Holdings Company LLC, a direct, wholly owned subsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries, depending on context

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

TCEH		Texas Competitive Electric Holdings Company LLC, a direct, wholly owned subsidiary of Energy Future Competitive Holdings Company LLC, and, prior to the Effective Date, the parent company of our predecessor, depending on context, that were engaged in electricity generation and wholesale and retail energy market activities, and whose major subsidiaries included Luminant and TXU Energy.

TCEQ		Texas Commission on Environmental Quality

TDSP		transmission and distribution service provider

TRA		Tax Receivables 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

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

Vistra Operations Credit Facilities		Vistra Operations Company LLC's $5.162 billion senior secured financing facilities (see Note 10 to the Financial Statements).

iii

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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 March 31,
	2018			2017
Operating revenues (Note 5)	$	765		$	1,357
Fuel, purchased power costs and delivery fees	(650		)	(683		)
Operating costs	(194		)	(214		)
Depreciation and amortization	(153		)	(170		)
Selling, general and administrative expenses	(162		)	(135		)
Operating income (loss)	(394		)	155
Other income (Note 17)	10			9
Other deductions (Note 17)	(2		)	—
Interest expense and related charges (Note 17)	9			(24		)
Impacts of Tax Receivable Agreement (Note 8)	(18		)	(21		)
Income (loss) before income taxes	(395		)	119
Income tax benefit (expense) (Note 7)	89			(41		)
Net income (loss)	$	(306	)	$	78
Weighted average shares of common stock outstanding:
Basic	428,450,384			427,583,339
Diluted	428,450,384			427,800,350
Net income (loss) per weighted average share of common stock outstanding:
Basic	$	(0.71	)	$	0.18
Diluted	$	(0.71	)	$	0.18

See Notes to the Condensed Consolidated Financial Statements.

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

(Unaudited) (Millions of Dollars)



	Three Months Ended March 31,
	2018			2017
Net income (loss)	$	(306	)	$	78
Other comprehensive income (loss), net of tax effects:
Effects related to pension and other retirement benefit obligations (net of tax benefit of $— in all periods)	1			—
Total other comprehensive income	1			—
Comprehensive income (loss)	$	(305	)	$	78

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)

	Three Months Ended March 31,
	2018			2017

Cash flows — operating activities:
Net income (loss)	$	(306	)	$	78
Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:
Depreciation and amortization	180			226
Deferred income tax (benefit) expense, net	(83		)	42
Unrealized net (gain) loss from mark-to-market valuations of derivatives	356			(129		)
Accretion expense	19			14
Impacts of Tax Receivable Agreement (Note 8)	18			21
Stock-based compensation	6			4
Other, net	7			(13		)
Changes in operating assets and liabilities:
Margin deposits, net	(64		)	113
Accrued interest	(11		)	(31		)
Accrued taxes	(69		)	(73		)
Accrued incentive plan	(50		)	(73		)
Other operating assets and liabilities	(25		)	(38		)
Cash (used in) provided by operating activities	(22		)	141
Cash flows — financing activities:
Repayments/repurchases of debt (Note 10)	(10		)	(13		)
Other, net	1			(5		)
Cash used in financing activities	(9		)	(18		)
Cash flows — investing activities:
Capital expenditures	(39		)	(31		)
Nuclear fuel purchases	(11		)	(12		)
Solar development expenditures (Note 3)	(21		)	—
Proceeds from sales of nuclear decommissioning trust fund securities (Note 17)	46			79
Investments in nuclear decommissioning trust fund securities (Note 17)	(51		)	(84		)
Other, net	(1		)	(3		)
Cash used in investing activities	(77		)	(51		)

Net change in cash, cash equivalents and restricted cash	(108		)	72
Cash, cash equivalents and restricted cash — beginning balance	2,046			1,588
Cash, cash equivalents and restricted cash — ending balance	$	1,938		$	1,660

See Notes to the Condensed Consolidated Financial Statements.

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

	March 31, 2018		December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	1,379	$	1,487
Restricted cash (Note 17)	59		59
Trade accounts receivable — net (Note 17)	463		582
Inventories (Note 17)	226		253
Commodity and other derivative contractual assets (Note 14)	404		190
Margin deposits related to commodity contracts	93		30
Prepaid expense and other current assets	75		72
Total current assets	2,699		2,673
Restricted cash (Note 17)	500		500
Investments (Note 17)	1,232		1,240
Property, plant and equipment — net (Note 17)	4,850		4,820
Goodwill (Note 6)	1,907		1,907
Identifiable intangible assets — net (Note 6)	2,437		2,530
Commodity and other derivative contractual assets (Note 14)	169		58
Accumulated deferred income taxes	793		710
Other noncurrent assets	189		162
Total assets	$	14,776	$	14,600
LIABILITIES AND EQUITY
Current liabilities:
Long-term debt due currently (Note 10)	$	44	$	44
Trade accounts payable	421		473
Commodity and other derivative contractual liabilities (Note 14)	595		224
Margin deposits related to commodity contracts	3		4
Accrued taxes	58		58
Accrued taxes other than income	59		136
Accrued interest	3		16
Asset retirement obligations (Note 17)	126		99
Other current liabilities	248		297
Total current liabilities	1,557		1,351
Long-term debt, less amounts due currently (Note 10)	4,366		4,379
Commodity and other derivative contractual liabilities (Note 14)	386		102
Tax Receivable Agreement obligation (Note 8)	351		333
Asset retirement obligations (Note 17)	1,817		1,837
Other noncurrent liabilities and deferred credits (Note 17)	239		256
Total liabilities	8,716		8,258

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

	March 31, 2018			December 31, 2017
Commitments and Contingencies (Note 11)
Total equity (Note 12):
Common stock (par value — $0.01; number of shares authorized — 1,800,000,000) (shares outstanding: March 31, 2018 — 428,506,325; December 31, 2017 — 428,398,802)	4			4
Additional paid-in-capital	7,772			7,765
Retained deficit	(1,700		)	(1,410		)
Accumulated other comprehensive income	(16		)	(17		)
Total equity	6,060			6,342
Total liabilities and equity	$	14,776		$	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 power business in Texas. Through our Luminant and TXU Energy 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 three reportable segments: (i) our Wholesale Generation segment, consisting largely of Luminant; (ii) our Retail Electricity segment, consisting largely of TXU Energy, and (iii) our Asset Closure segment, consisting of financial results associated with retired plants and mines. 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 16 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 occurred after March 31, 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 in any of the periods presented herein or otherwise take into account the closing of the Merger or the effects of the Merger or any transactions related thereto. See Note 2 for a summary of the Merger and related transactions.

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 change in reporting 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.

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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. We expect the impact of the adoption of the new revenue standard to be immaterial to our net income on an ongoing basis and our retail electricity and wholesale generation 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	)

In accordance with the new revenue standard requirements, 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 March 31, 2018
	As Reported			Amount Without Adoption of New Revenue Standard			Effect of Change Higher (Lower)
Impact on condensed statement of consolidated income (loss):
Operating revenues	$	765		$	764		$	1
Selling, general and administrative expenses	$	(162	)	$	(165	)	$	3
Net income (loss)	(306		)	(309		)	3



	March 31, 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	$	75		$	69		$	6
Accumulated deferred income taxes	$	793		$	797		$	(4	)
Other noncurrent assets	$	189		$	169		$	20
Equity
Retained deficit	$	(1,700	)	$	(1,720	)	$	20

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

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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 17). 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 three months ended March 31, 2017, our condensed statement of consolidated cash flows previously reflected a source of cash of $1 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 17 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 (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 are currently evaluating the impact of this ASU on our financial statements.

2. MERGER TRANSACTION

Merger Summary

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. 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 Effective Time 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.

Following is a list of events that took place in connection with the completion of the Merger.

Warrants — 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 the Merger Date, 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.

Credit Agreement — The Company 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.

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Senior Notes — The Company and certain of the Company's wholly-owned subsidiaries that guarantee obligations under the Dynegy credit agreement assumed the following obligations of Dynegy:


•	$850 million of outstanding 6.75% Senior Notes due 2019, which were redeemed on May 1, 2018 at a redemption price of 101.688%, plus accrued and unpaid interest to but not including the date of redemption;


•	$1.750 billion of 7.375% Senior Notes due 2022;


•	$500 million of 5.875% Senior Notes due 2023;


•	$1.250 billion of 7.625% Senior Notes due 2024;


•	$188 million of 8.034% Senior Notes due 2024;


•	$750 million of 8.000% Senior Notes due 2025, and


•	$850 million of 8.125% Senior Notes due 2026.

Tangible Equity Units — 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 $45 million that pays an equal quarterly cash installment of $1.7500 per amortizing note. 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.

Business Combination

The Merger is anticipated to provide 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. Due to the limited time between the Merger Date and this filing, our purchase price allocation for the assets acquired and the liabilities assumed in the Merger has not been completed. The results of operations of Dynegy will be reported in our consolidated financial statements beginning 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. Our initial accounting of the purchase price allocation for the assets acquired and the liabilities assumed in the Merger and the supplemental pro forma financial results is currently underway and will be presented no later than the second quarter of 2018.


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 a partial buyback of the earn-out provision was settled in February 2018.

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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. For the three months ended March 31, 2018, we have spent approximately $21 million related to this project primarily for progress payments under the engineering, procurement and construction agreement. The facility began test operations in March 2018 and is expected to begin commercial operations in May 2018.


4.	RETIREMENT OF GENERATION FACILITIES

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. The following table details the units retired.



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


5.	REVENUE

The following table disaggregates our revenue by major source:



	Three Months Ended March 31, 2018
	Retail Electricity			Wholesale Generation			Asset Closure			Eliminations		Consolidated
Revenue from contracts with customers:
Revenue from Oncor service area	$	662		$	—		$	—		$	—	$	662
Revenue from other TDSP service areas	287			—			—			—		287
Wholesale generation revenue from ERCOT	—			174			36			—		210
Revenue from non-affiliated REPs	—			19			—			—		19
Revenue from other wholesale contracts	—			34			—			—		34
Total revenue from contracts with customers	949			227			36			—		1,212
Other revenues:
Retail contract amortization	(12		)	—			—			—		(12		)
Hedging and other revenues	35			(462		)	(8		)	—		(435		)
Affiliate sales	—			(298		)	—			298		—
Total other revenues	23			(760		)	(8		)	298		(447		)
Total revenues	$	972		$	(533	)	$	28		$	298	$	765

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. Residential invoices are due within 20 days from invoice date and business customer 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.

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Wholesale Generation Revenue from ERCOT

Revenue is recognized when volumes are delivered to ERCOT. Cash settlement occurs within 10 business days after delivery. Revenue is recognized over-time using the output method based on kilowatt hours delivered. Luminant operates as a market participant within ERCOT and expects to continue to remain in a contract agreement with ERCOT indefinitely. Wholesale generation revenues are delivered as a series of distinct services and are accounted for as a single performance obligation.

Revenue from Nonaffiliated Retail Electric Providers

Revenue is recognized when volumes are delivered to the non-affiliated retail electric provider. Cash settlement occurs within 20 days following the month of delivery. Revenue is recognized over-time using the output method based on kilowatt hours delivered. Revenue from non-affiliated retail electric providers are delivered as a series of distinct services and are accounted for as a single performance obligation.

Revenue from Other Wholesale Contracts

Other wholesale contracts include other revenue activity with ERCOT, such as ancillary services, auction revenue and ERCOT neutrality revenue. Revenue is recognized when the service is performed. Cash settlement occurs within 10 business days after invoicing. Revenue is recognized over-time using the output method based on kilowatt hours delivered or other applicable measurements. Luminant operates as a market participant within ERCOT and expects to continue to remain in a contract agreement with ERCOT 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 residential and business 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 March 31, 2018 and January 1, 2018 was $27 million and $22 million, respectively. The amortization expense related to these costs during the three months ended March 31, 2018 totaled $3 million and was recorded as selling, general and administrative expenses and $1 million was recorded to operating costs 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 for which we recognize revenue using the right to invoice practical expedient. We use the portfolio approach to categorize similar customer contracts into single performance obligations. Sales taxes are not included in revenue.

Accounts Receivable

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



	March 31, 2018
Trade accounts receivable from contracts with customers — net	$	415
Other trade accounts receivable — net	48
Total trade accounts receivable — net	$	463


6.	GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS

Goodwill

The carrying value of goodwill totaled $1.907 billion at both March 31, 2018 and December 31, 2017. The goodwill arose in connection with our application of fresh start reporting at Emergence and was allocated entirely to the Retail Electricity reporting unit (see Note 1). Of the goodwill recorded at Emergence, $1.686 billion is deductible for tax purposes over 15 years on a straight-line basis.

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Identifiable Intangible Assets

Identifiable intangible assets are comprised of the following:



	March 31, 2018						December 31, 2017
Identifiable Intangible Asset	Gross Carrying Amount		Accumulated Amortization		Net		Gross Carrying Amount		Accumulated Amortization		Net
Retail customer relationship	$	1,648	$	645	$	1,003	$	1,648	$	572	$	1,076
Software and other technology-related assets	186		57		129		183		47		136
Retail and wholesale contracts	154		99		55		154		87		67
Other identifiable intangible assets (a)	33		11		22		33		11		22
Total identifiable intangible assets subject to amortization	$	2,021	$	812	1,209		$	2,018	$	717	1,301
Retail trade names (not subject to amortization)					1,225						1,225
Mineral interests (not currently subject to amortization)					3						4
Total identifiable intangible assets					$	2,437					$	2,530

____________


(a)	Includes mining development costs and environmental allowances and credits.

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



Identifiable Intangible Asset	Condensed Statements of Consolidated Income (Loss) Line	Three Months Ended March 31,
Identifiable Intangible Asset	Condensed Statements of Consolidated Income (Loss) Line	2018		2017
Retail customer relationship	Depreciation and amortization	$	73	$	105
Software and other technology-related assets	Depreciation and amortization	10		8
Retail and wholesale contracts	Operating revenues/fuel, purchased power costs and delivery fees	12		28
Other identifiable intangible assets	Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization	2		4
Total amortization expense (a)		$	97	$	145

____________


(a)	Amounts recorded in depreciation and amortization totaled $85 million and $115 million for the three months ended March 31, 2018 and 2017, respectively.

Estimated Amortization of Identifiable Intangible Assets

As of March 31, 2018, the estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as shown below.



Year	Estimated Amortization Expense
2018	$	368
2019	$	268
2020	$	192
2021	$	142
2022	$	89

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7.	INCOME TAXES

The calculation of our effective tax rate is as follows:



	Three Months Ended March 31,
	2018			2017
Income (loss) before income taxes	$	(395	)	$	119
Income tax benefit (expense)	$	89		$	(41	)
Effective tax rate	22.5		%	34.5		%

For the three months ended March 31, 2018, the effective tax rate of 22.5% related to our income tax expense was higher than the U.S. Federal statutory rate of 21% due primarily to nondeductible TRA accretion and the Texas margin tax, net of federal benefit, offset by the difference in the forecasted effective tax rate and the statutory tax rate applied to mark-to-market unrealized losses.

For the three months ended March 31, 2017, the effective tax rate of 34.5% related to our income tax expense was lower than the U.S. Federal statutory rate of 35% due primarily to the difference in the forecasted effective tax rate and the statutory tax rate applied to mark-to-market unrealized gains, offset by deductible TRA accretion and the Texas margin tax, net of federal benefit.

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, and we had no uncertain tax positions at both March 31, 2018 and December 31, 2017.


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 15).

The following table summarizes the changes to the TRA obligation, reported as other current liabilities and Tax Receivable Agreement obligation in our condensed consolidated balance sheets, for the three months ended March 31, 2018 and 2017:



	Three Months Ended March 31,
	2018			2017
TRA obligation at the beginning of the period	$	357		$	596
Accretion expense	18			21
TRA obligation at the end of the period	375			617
Less amounts due currently	(24		)	(16		)
Noncurrent TRA obligation at the end of the period	$	351		$	601

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As of March 31, 2018, the estimated carrying value of the TRA obligation totaled $375 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% and (b) estimates of our taxable income in the current and future years. Our taxable income takes into consideration the current federal tax code 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. The aggregate amount of undiscounted payments under the TRA is estimated to be approximately $1.2 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 months ended March 31, 2018 and 2017, the Impacts of Tax Receivable Agreement on the condensed statements of consolidated income (loss) totaled $18 million and $21 million, respectively, which represents accretion expense for the period.


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 March 31, 2018							Three Months Ended March 31, 2017
	Net Loss			Shares	Per Share Amount			Net Income		Shares	Per Share Amount
Net income (loss) available for common stock — basic	$	(306	)	428,450,384	$	(0.71	)	$	78	427,583,339	$	0.18
Dilutive securities:
Stock-based incentive compensation plan	—			—	—			—		217,011	—
Net income (loss) available for common stock — diluted	$	(306	)	428,450,384	$	(0.71	)	$	78	427,800,350	$	0.18

For the three months ended March 31, 2018 and 2017, stock-based incentive compensation plan awards totaling 2,863,872 and 602,403 shares, respectively, were excluded from the calculation of diluted earnings per share because the effect would have been antidilutive.

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10.	LONG-TERM DEBT

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



	March 31, 2018			December 31, 2017
Vistra Operations Credit Facilities (a)	$	4,313		$	4,323
Mandatorily redeemable subsidiary preferred stock (b)	70			70
8.82% Building Financing due semiannually through February 11, 2022 (c)	27			30
Total long-term debt including amounts due currently	4,410			4,423
Less amounts due currently	(44		)	(44		)
Total long-term debt less amounts due currently	$	4,366		$	4,379

____________

(a)

At March 31, 2018, borrowings under the Vistra Operations Credit Facilities in our condensed consolidated balance sheet include debt premiums of $19 million, debt discounts of $2 million and debt issuance costs of $6 million. At December 31, 2017, borrowings under the Vistra Operations Credit Facilities in our condensed consolidated balance sheet include debt premiums of $21 million, debt discounts of $2 million and debt issuance costs of $7 million.


(b)	Shares of mandatorily redeemable preferred stock in PrefCo issued as part of the Spin-Off (see Note 1). This subsidiary preferred stock is accounted for as a debt instrument under relevant accounting guidance.


(c)	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.

Vistra Operations Credit Facilities — At March 31, 2018, the Vistra Operations Credit Facilities consisted of up to $5.162 billion in senior secured, first lien revolving credit commitments and outstanding term loans, consisting of revolving credit commitments of up to $860 million, including a $715 million letter of credit sub-facility (Revolving Credit Facility), initial term loans totaling $2.814 billion (Initial Term Loan B Facility), incremental term loans totaling $988 million (Incremental Term Loan B Facility, and together with the Initial Term Loan B Facility, the Term Loan B Facility) and letter of credit term loans totaling $500 million (Term Loan C Facility).

The Vistra Operations Credit Facilities and related available capacity at March 31, 2018 are presented below.



		March 31, 2018
Vistra Operations Credit Facilities	Maturity Date	Facility Limit		Cash Borrowings		Available Capacity
Revolving Credit Facility (a)	August 4, 2021	$	860	$	—	$	584
Initial Term Loan B Facility (b)	August 4, 2023	2,814		2,814		—
Incremental Term Loan B Facility (b)	December 14, 2023	988		988		—
Term Loan C Facility (c)	August 4, 2023	500		500		18
Total Vistra Operations Credit Facilities		$	5,162	$	4,302	$	602

___________


(a)	Facility to be used for general corporate purposes. Facility includes a $715 million letter of credit sub-facility, of which $276 million of letters of credit were outstanding at March 31, 2018.


(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.


(c)	Facility used for issuing letters of credit for general corporate purposes. Borrowings under this facility were funded to collateral accounts that are reported as restricted cash in our condensed consolidated balance sheets. At March 31, 2018, the restricted cash supported $482 million in letters of credit outstanding (see Note 17), leaving $18 million in available letter of credit capacity.

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In February 2018, certain pricing terms for the Vistra Operations Credit Facility were amended. We accounted for this transaction as a modification of debt. At March 31, 2018, cash borrowings under the Revolving Credit Facility would bear interest based on applicable LIBOR rates, plus a fixed spread of 2.25%, and there were no outstanding borrowings. Letters of credit issued under the Revolving Credit Facility bear interest of 2.25%. Amounts borrowed under the Initial Term Loan B Facility and the Term Loan C Facility bear interest based on applicable LIBOR rates, subject to a 0.75% floor, plus a fixed spread of 2.50%. Amounts borrowed under the Incremental Term Loan B Facility bear interest based on applicable LIBOR rates plus a fixed spread of 2.25%. At March 31, 2018, the weighted average interest rate before taking into consideration interest rate swaps on outstanding borrowings was 4.38%, 4.07% and 4.38% under the Initial Term Loan B Facility, the Incremental Term Loan B Facility and the Term Loan C Facility, respectively. The Vistra Operations Credit Facilities also provide for certain additional fees payable to the agents and lenders, as well as availability fees payable with respect to any unused portions of the available Vistra Operations Credit Facilities.

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.

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

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

The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties, material breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against Vistra Operations. Solely with respect to the Revolving Credit Facility, and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $100 million) exceed 30% of the revolving commitments), the agreement includes a covenant that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first lien debt compared to an EBITDA calculation defined under the terms of the facilities, not to exceed 4.25 to 1.00. Although the period ended March 31, 2018 was not a compliance period, we would have been in compliance with this financial covenant if it was required to be tested at such date. Upon the existence of an event of default, the Vistra Operations Credit Facilities provide that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.

Interest Rate Swaps — Effective January 2017, we entered into $3.0 billion notional amount of interest rate swaps to hedge a portion of our exposure to our variable rate debt. The interest rate swaps expire in July 2023 and effectively fix the interest rates between 4.38% and 4.50% on $3.0 billion of our variable rate debt. The interest rate swaps are secured by a first lien secured interest on a pari-passu basis with the Vistra Operations Credit Facilities.

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11.	COMMITMENTS AND CONTINGENCIES

Guarantees

We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. As of March 31, 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 March 31, 2018, we had outstanding letters of credit under the Vistra Operations Credit Facilities totaling $758 million as follows:


•	$634 million 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 ERCOT;


•	$36 million to support executory contracts and insurance agreements;


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


•	$33 million for other credit support requirements.

Litigation

Litigation Related to EPA Reviews — 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 Clean Air Act (CAA), including its New Source Review standards, at our Big Brown and Martin Lake generation facilities. 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 U.S. Court of Appeals for the Fifth Circuit (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. We believe that we have complied with all requirements of the CAA and intend to vigorously defend against the remaining allegations. 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 requiring the installation of best available control technology at the affected units. 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, and could possibly require the payment of substantial penalties. The recent 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.

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.

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Following a March 2017 Executive Order entitled Promoting Energy Independence and Economic Growth issued by President Trump covering a number of matters, including the Clean Power Plan (Order), in April 2017, in accordance with the Order, the EPA published its intent to review the Clean Power Plan. 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. 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.

Cross-State Air Pollution Rule (CSAPR)

In July 2011, the EPA issued the CSAPR, compliance with which would have required significant additional reductions of sulfur dioxide (SO₂) and nitrogen oxide (NO_X) emissions from our fossil fueled generation units. After certain EPA revisions to the rule, the CSAPR became effective January 1, 2015. With respect to Texas's SO₂ and annual NO_X emission budgets, in November 2016, the EPA proposed to withdraw the CSAPR Federal Implementation Plan (FIP) addressing SO₂ and annual NO_X for Texas and in September 2017, the EPA finalized its proposal to remove Texas from these annual CSAPR programs. The Sierra Club and the National Parks Conservation Association filed a petition for review in the D.C. Circuit Court challenging that final rule and Luminant intervened on behalf of the EPA. On April 10, 2018, the D.C. Circuit Court granted the EPA's and petitioners' motion to hold the case in abeyance pending the EPA's consideration of a pending petition for administrative reconsideration. As a result of the EPA's action, Texas electric generating units are no longer subject to the CSAPR annual SO₂ and NO_X limits, but remain subject to the CSAPR's ozone season NO_X requirements. While we cannot predict the outcome of future proceedings related to the CSAPR, based upon our current operating plans, including the recent retirements of our Monticello, Big Brown and Sandow 4 plants (see Note 3), we do not believe that the CSAPR in its current form will cause any material operational, financial or compliance issues to our business or require us to incur any material compliance costs.

Regional Haze — Reasonable Progress and Long-Term Strategies

The Regional Haze Program of the CAA establishes "as a national goal the prevention of any future, and the remedying of any existing, impairment of visibility in mandatory class I federal areas which impairment results from man-made pollution." In February 2009, the TCEQ submitted a State Implementation Plan (SIP) concerning regional haze (Regional Haze SIP) to the EPA. In December 2011, the EPA proposed a limited disapproval of the Regional Haze SIP due to its reliance on the Clean Air Interstate Rule (CAIR) instead of the EPA's replacement CSAPR program. The EPA finalized the limited disapproval of Texas's Regional Haze SIP in June 2012 and, on March 20, 2018, the D.C. Circuit Court issued a decision upholding the EPA's actions and denying all of Luminant's petitions for review.

In January 2016, the EPA issued a final rule approving in part and disapproving in part Texas' SIP addressing the reasonable progress component of the Regional Haze program and issuing a 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 and upgrades to existing scrubbers at seven generation units. Specifically, for Luminant, the EPA's FIP is based on new scrubbers at Big Brown Units 1 and 2 and Monticello Units 1 and 2 and scrubber upgrades at Martin Lake Units 1, 2 and 3, Monticello Unit 3 and Sandow Unit 4. Under the terms of the rule, subject to the legal proceedings described in the following paragraph, the scrubber upgrades would be required by February 2019, and the new scrubbers would be required by February 2021.

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In March 2016, Luminant and a number of other parties, including the State of Texas, filed petitions for review in the Fifth Circuit Court challenging the FIP's Texas requirements. Luminant and other parties also filed motions to stay the FIP while the court reviews the legality of the EPA's action. In July 2016, the Fifth Circuit Court denied the EPA's motion to dismiss Luminant's challenge to the FIP and granted the motions to stay filed by Luminant and the other parties pending final review of the petitions for review. The case was abated until the end of November 2016 in order to allow the parties to pursue settlement discussions. Settlement discussions were unsuccessful, and 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 in light of the Court's prior determination that we and the other petitioners demonstrated a substantial likelihood that the EPA exceeded its statutory authority and acted arbitrarily and capriciously, but the Court denied all of the other pending motions. 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 recent 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 may have a material impact on our results of operations, liquidity or financial condition.

Regional Haze — Best Available Retrofit Technology (BART)

In September 2017, the EPA signed the final BART FIP for Texas, 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, 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. Luminant's units covered by the program are allocated 91,222 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 recent 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. 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. 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 operation, liquidity or financial condition.

Affirmative Defenses During Malfunctions

In February 2013, the EPA proposed a rule requiring certain states to replace SIP exemptions for excess emissions during malfunctions with an affirmative defense. Texas was not included in that original proposal since it already had an EPA-approved affirmative defense provision in its SIP that was found to be lawful by the Fifth Circuit Court in 2013. 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 EPA's revised proposal would require Texas to remove or replace its EPA-approved affirmative defense provisions for excess emissions during startup, shutdown and maintenance events. In June 2015, the State of Texas and various industry parties (including Luminant) filed petitions for review in the Fifth Circuit Court challenging certain aspects of the EPA's final rule as they apply to the Texas SIP. In August 2015, the Fifth Circuit Court transferred the petitions that Luminant and other parties filed to the D.C. Circuit Court, and in October 2015 the petitions were consolidated with the pending petitions challenging the EPA's action in the D.C. Circuit Court. Before the originally scheduled oral argument was held, in April 2017, the 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 court on the EPA's review of the action at 90-day intervals. 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 may have a material impact on our results of operations, liquidity or financial condition.

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SO2 Designations for Texas

In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Big Brown, Monticello and Martin Lake generation plants. The final designations require Texas to develop nonattainment plans for these areas. In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court. Subsequently, in October 2017, the Fifth Circuit Court granted the EPA's motion to hold the case in abeyance 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 may have a material impact on our results of operations, liquidity or financial condition.

Litigation Related to the Merger

In January 2018, a purported Dynegy stockholder filed a putative class action lawsuit in the U.S. District Court for the Southern Division of Texas, Houston Division, alleging that Dynegy, each member of the Dynegy board of directors and Vistra Energy violated federal securities laws by filing a Form S-4 Registration Statement in connection with the Merger that omitted purportedly material information. The lawsuit sought to enjoin the Merger and to have Dynegy and Vistra Energy issue an amended Form S-4 or, alternatively, damages if the Merger closed without an amended Form S-4 having been filed. Two other related lawsuits were also filed but neither of those named Vistra Energy. In February 2018, Vistra Energy and Dynegy filed supplemental disclosures to the Registration Statement and the plaintiffs agreed to forego any further effort to enjoin the Merger, dismiss the individual claims with prejudice, and dismissed without prejudice claims of the putative class following the stockholder vote on March 2, 2018.

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.


12.	EQUITY

Vistra Energy did not declare or pay any dividends during the three months ended March 31, 2018 and 2017. The agreement governing the Vistra Operations Credit Facilities (the Credit Facilities Agreement) generally restricts the ability of Vistra Operations Company LLC (Vistra Operations) to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of March 31, 2018, Vistra Operations can distribute approximately $975 million 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. There were no distributions made by Vistra Operations to the Parent during the three months ended March 31, 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 March 31, 2018, the maximum amount of restricted net assets of Vistra Operations that may not be distributed to the Parent totaled approximately $3.6 billion.

Under applicable Delaware General Corporate Law, we are prohibited from paying any distribution to the extent that such distribution exceeds the value of our "surplus," which is defined as the excess of our net assets above our capital (the aggregate par value of all outstanding shares of our stock).

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The following table presents the changes to shareholder's equity for the three months ended March 31, 2018:



	Common Stock (a)		Additional Paid-in Capital		Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Shareholders' Equity
Balance at December 31, 2017	$	4	$	7,765	$	(1,410	)	$	(17	)	$	6,342
Net loss	—		—		(306		)	—			(306		)
Adoption of accounting standard (Note 1)	—		—		17			—			17
Effects of stock-based incentive compensation plans	—		7		—			—			7
Change in unrecognized losses related to pension and OPEB plans	—		—		—			1			1
Other	—		—		(1		)	—			(1		)
Balance at March 31, 2018	$	4	$	7,772	$	(1,700	)	$	(16	)	$	6,060

________________


(a)	Authorized shares totaled 1,800,000,000 at March 31, 2018. Outstanding shares totaled 428,506,325 and 428,398,802 at March 31, 2018 and December 31, 2017, respectively.

The following table presents the changes to shareholder's equity for the three months ended March 31, 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	—		—		78			—		78
Effects of stock-based incentive compensation plans	—		4		—			—		4
Other	—		—		1			—		1
Balance at March 31, 2017	$	4	$	7,746	$	(1,076	)	$	6	$	6,680

________________


(a)	Authorized shares totaled 1,800,000,000 at March 31, 2017. Outstanding shares totaled 427,587,401 and 427,580,232 at March 31, 2017 and December 31, 2016, respectively.


13.	FAIR VALUE MEASUREMENTS

We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. We use a mid-market valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs. Our valuation policies and procedures were developed, maintained and validated by a centralized risk management group that reports to the Vistra 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 14 for additional information regarding credit risk associated with our derivatives). We utilize credit ratings and default rate factors in calculating these fair value measurement adjustments.

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

•

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

•

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

•

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

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

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



March 31, 2018
	Level 1		Level 2		Level 3 (a)		Reclassification (b)		Total
Assets:
Commodity contracts	$	40	$	286	$	163	$	7	$	496
Interest rate swaps	—		77		—		—		77
Nuclear decommissioning trust – equity securities (c)	465		—		—		—		465
Nuclear decommissioning trust – debt securities (c)	—		427		—		—		427
Sub-total	$	505	$	790	$	163	$	7	1,465
Assets measured at net asset value (d):
Nuclear decommissioning trust – equity securities (c)									288
Total assets									$	1,753
Liabilities:
Commodity contracts	$	82	$	505	$	387	$	7	$	981
Total liabilities	$	82	$	505	$	387	$	7	$	981

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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 17.


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

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

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

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The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations at March 31, 2018 and December 31, 2017:



March 31, 2018
	Fair Value
Contract Type (a)	Assets		Liabilities			Total			Valuation Technique	Significant Unobservable Input	Range (b)
Electricity purchases and sales	$	41	$	(149	)	$	(108	)	Valuation Model	Hourly price curve shape (c)	$0 to $60/ MWh
										Illiquid delivery periods for ERCOT hub power prices and heat rates (d)	$20 to $90/ MWh
Electricity and weather options	41		(232		)	(191		)	Option Pricing Model	Gas to power correlation (e)	40% to 100%
										Power volatility (e)	5% to 195%
Electricity congestion revenue rights	66		(6		)	60			Market Approach (f)	Illiquid price differences between settlement points (g)	$0 to $15/ MWh
Other (h)	15		—			15
Total	$	163	$	(387	)	$	(224	)



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%
Electricity congestion revenue 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 regions. Electricity congestion revenue rights contracts consist of forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points within ERCOT. 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)	Based on the historical range of forward average hourly ERCOT North Hub prices.


(d)	Based on historical forward ERCOT power price and heat rate variability.


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


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


(g)	Based on the historical price differences between settlement points within ERCOT hubs and load zones.


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

There were no transfers between Level 1 and Level 2 of the fair value hierarchy for the three months ended March 31, 2018 and 2017. See the table below for discussion of transfers between Level 2 and Level 3 for the three months ended March 31, 2018 and 2017.

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The following table presents the changes in fair value of the Level 3 assets and liabilities for the three months ended March 31, 2018 and 2017.



	Three Months Ended March 31,
	2018			2017
Net asset (liability) balance at beginning of period	$	(53	)	$	83
Total unrealized valuation gains (losses)	(213		)	40
Purchases, issuances and settlements (a):
Purchases	29			10
Issuances	(4		)	(12		)
Settlements	17			(19		)
Transfers into Level 3 (b)	—			3
Transfers out of Level 3 (b)	—			2
Net change (c)	(171		)	24
Net asset (liability) balance at end of period	$	(224	)	$	107
Unrealized valuation gains (losses) relating to instruments held at end of period	$	(206	)	$	36

____________


(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 are reported as operating revenues in our condensed statements of consolidated income (loss).

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14.	COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES

Strategic Use of Derivatives

We transact in derivative instruments, such as options, swaps, futures and forward contracts, to manage commodity price and interest rate risk. See Note 13 for a discussion of the fair value of derivatives.

Commodity Hedging and Trading Activity — We utilize natural gas and electricity derivatives to reduce exposure to changes in electricity prices primarily to hedge future revenues from electricity sales from our generation assets. We also utilize short-term electricity, natural gas, coal, fuel oil and uranium 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 March 31, 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.



	March 31, 2018
	Derivative Assets					Derivative Liabilities
	Commodity Contracts			Interest Rate Swaps		Commodity Contracts			Interest Rate Swaps		Total
Current assets	$	397		$	3	$	4		$	—	$	404
Noncurrent assets	95			74		—			—		169
Current liabilities	(2		)	—		(593		)	—		(595		)
Noncurrent liabilities	(1		)	—		(385		)	—		(386		)
Net assets (liabilities)	$	489		$	77	$	(974	)	$	—	$	(408	)



	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 March 31, 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 months ended March 31, 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 March 31,
	2018			2017
Commodity contracts (Operating revenues)	$	(446	)	$	175
Commodity contracts (Fuel, purchased power costs and delivery fees)	(1		)	(5		)
Interest rate swaps (Interest expense and related charges)	56			3
Net gain (loss)	$	(391	)	$	173

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:



	March 31, 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	$	489		$	(277	)	$	(1	)	$	211		$	220		$	(113	)	$	(1	)	$	106
Interest rate swaps	77			—			—			77			18			—			—			18
Total derivative assets	566			(277		)	(1		)	288			238			(113		)	(1		)	124
Derivative liabilities:
Commodity contracts	(974		)	277			85			(612		)	(316		)	113			1			(202		)
Interest rate swaps	—			—			—			—			—			—			—			—
Total derivative liabilities	(974		)	277			85			(612		)	(316		)	113			1			(202		)
Net amounts	$	(408	)	$	—		$	84		$	(324	)	$	(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 March 31, 2018 and December 31, 2017:



	March 31, 2018		December 31, 2017
Derivative type	Notional Volume				Unit of Measure
Natural gas (a)	1,423		1,259		Million MMBtu
Electricity	102,316		114,129		GWh
Congestion Revenue Rights (b)	142,560		110,913		GWh
Coal	2		2		Million U.S. tons
Fuel oil	22		5		Million gallons
Uranium	125		325		Thousand pounds
Interest rate swaps – floating/fixed (c)	$	3,000	$	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 ERCOT.


(c)	Includes notional amounts of interest rate swaps with maturity dates through July 2023.

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:



	March 31, 2018			December 31, 2017
Fair value of derivative contract liabilities (a)	$	(758	)	$	(204	)
Offsetting fair value under netting arrangements (b)	215			103
Cash collateral and letters of credit	336			41
Liquidity exposure	$	(207	)	$	(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 March 31, 2018, total credit risk exposure to all counterparties related to derivative contracts totaled $634 million (including associated accounts receivable). The net exposure to those counterparties totaled $293 million at March 31, 2018 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $77 million. At March 31, 2018, the credit risk exposure to the banking and financial sector represented 29% of the total credit risk exposure and 29% of the net exposure.

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

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


15.	RELATED PARTY TRANSACTIONS

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

Registration Rights Agreement

Pursuant to the Plan of Reorganization, on the Effective Date, we entered into a Registration Rights Agreement (the Registration Rights Agreement) with certain selling stockholders providing for registration of the resale of the Vistra 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. Among other things, under the terms of the Registration Rights Agreement:


•	we will be required to use reasonable best efforts to convert the Form S-1 registration statement into a registration statement on Form S-3 as soon as reasonably practicable after we become eligible to do so and to have such Form S-3 declared effective as promptly as practicable (but in no event more than 30 days after it is filed with the SEC);

•

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 months ended March 31, 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.


16.	SEGMENT INFORMATION

The operations of Vistra Energy are aligned into three reportable business segments: Wholesale Generation, Retail Electricity and Asset Closure. Our chief operating decision maker reviews the results of these three segments separately and allocates resources to the respective segments as part of our strategic operations. The Wholesale Generation and Retail Electricity businesses offer different products or services and involve different risks.

The Wholesale Generation segment is engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel production and fuel logistics management, all largely in the ERCOT market. These activities are substantially all conducted by Luminant.

The Retail Electricity segment is engaged in retail sales of electricity and related services to residential, commercial and industrial customers, all largely in the ERCOT market. These activities are substantially all conducted by TXU Energy.

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 information from prior periods to reflect this change in reportable segments. We have not allocated any unrealized gains or losses to the Asset Closure segment for the generation plants that were retired in January and February 2018.

Corporate and Other represents the remaining non-segment operations consisting primarily of general corporate expenses, interest, taxes and other expenses related to our support functions that provide shared services to our Wholesale Generation, Retail Electricity and Asset Closure segments.

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 current market prices. Certain shared services costs are allocated to the segments.

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	Three Months Ended March 31,
	2018			2017
Operating revenues (a)
Wholesale Generation	$	(533	)	$	785
Retail Electricity	972			865
Asset Closure	28			186
Corporate and Other	—			(1		)
Eliminations	298			(478		)
Consolidated operating revenues	$	765		$	1,357
Depreciation and amortization
Wholesale Generation	$	(64	)	$	(53	)
Retail Electricity	(76		)	$	(106	)
Corporate and Other	(12		)	$	(11	)
Eliminations	$	(1	)	$	—
Consolidated depreciation and amortization	$	(153	)	$	(170	)
Operating income (loss)
Wholesale Generation	$	(1,087	)	$	300
Retail Electricity	757			$	(118	)
Asset Closure	(23		)	$	(15	)
Corporate and Other	(40		)	$	(12	)
Eliminations	$	(1	)	$	—
Consolidated operating income (loss)	$	(394	)	$	155
Net income (loss)
Wholesale Generation	$	(1,086	)	$	303
Retail Electricity	771			(113		)
Asset Closure	(22		)	(13		)
Corporate and Other	31			(99		)
Consolidated net income (loss)	$	(306	)	$	78

____________

(a)

For the three months ended March 31, 2018 and 2017, includes third-party unrealized net gains (losses) from mark-to-market valuations of commodity positions of $(426) million and $126 million, respectively, recorded to the Wholesale Generation segment and $12 million and $8 million, respectively, recorded to the Retail Electricity segment. In addition, for the three months ended March 31, 2018 and 2017, unrealized net gains (losses) with affiliate of $(643) million and $170 million, respectively, were recorded to operating revenues for the Wholesale Generation segment and corresponding unrealized net gains (losses) with affiliate of $643 million and $(170) million, respectively, were recorded to fuel, purchased power costs and delivery fees for the Retail Electricity segment, with no impact to consolidated results.



	March 31, 2018		December 31, 2017
Total assets
Wholesale Generation	$	7,048	$	6,834
Retail Electricity	6,890		6,156
Asset Closure	235		235
Corporate and Other and Eliminations	603		1,375
Consolidated total assets	$	14,776	$	14,600

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17.	SUPPLEMENTARY FINANCIAL INFORMATION

Interest Expense and Related Charges



	Three Months Ended March 31,
	2018			2017
Interest paid/accrued	$	50		$	54
Unrealized mark-to-market net gains on interest rate swaps	(59		)	(9		)
Debt extinguishment gain	—			(21		)
Capitalized interest	(3		)	(3		)
Other	3			3
Total interest expense and related charges	$	(9	)	$	24

The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 10, was 4.43% at March 31, 2018.

Other Income and Deductions



	Three Months Ended March 31,
	2018		2017
Other income:
Office space sublease rental income (a)	$	2	$	3
Mineral rights royalty income (b)	—		1
Sale of land (b)	1		2
Interest income	6		1
All other	1		2
Total other income	$	10	$	9
Other deductions:
All other	$	2	$	—
Total other deductions	$	2	$	—

____________


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


(b)	Reported in Wholesale Generation segment.

Restricted Cash



	March 31, 2018				December 31, 2017
	Current Assets		Noncurrent Assets		Current Assets		Noncurrent Assets
Amounts related to the Vistra Operations Credit Facilities (Note 10)	$	—	$	500	$	—	$	500
Amounts related to restructuring escrow accounts	59		—		59		—
Total restricted cash	$	59	$	500	$	59	$	500

Trade Accounts Receivable



	March 31, 2018			December 31, 2017
Wholesale and retail trade accounts receivable	$	477		$	596
Allowance for uncollectible accounts	(14		)	(14		)
Trade accounts receivable — net	$	463		$	582

Gross trade accounts receivable at March 31, 2018 and December 31, 2017 included unbilled retail revenues of $187 million and $251 million, respectively.

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Allowance for Uncollectible Accounts Receivable



	Three Months Ended March 31,
	2018			2017
Allowance for uncollectible accounts receivable at beginning of period	$	14		$	10
Increase for bad debt expense	11			7
Decrease for account write-offs	(11		)	(9		)
Allowance for uncollectible accounts receivable at end of period	$	14		$	8

Inventories by Major Category



	March 31, 2018		December 31, 2017
Materials and supplies	$	149	$	149
Fuel stock	62		83
Natural gas in storage	15		21
Total inventories	$	226	$	253

Other Investments



	March 31, 2018		December 31, 2017
Nuclear plant decommissioning trust	$	1,180	$	1,188
Land	49		49
Miscellaneous other	3		3
Total other investments	$	1,232	$	1,240

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's 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 receivable/payable (currently a receivable reported in noncurrent assets) that will ultimately be settled through changes in Oncor's delivery fees rates. A summary of investments in the fund follows:



	March 31, 2018
	Cost (a)		Unrealized gain		Unrealized loss			Fair market value
Debt securities (b)	$	425	$	8	$	(6	)	$	427
Equity securities (c)	268		487		(2		)	753
Total	$	693	$	495	$	(8	)	$	1,180



	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 Investors Services, Inc. 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 3.45% and 3.55% at March 31, 2018 and December 31, 2017, respectively, and an average maturity of nine years at both March 31, 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.

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Debt securities held at March 31, 2018 mature as follows: $133 million in one to five years, $91 million in five to 10 years and $203 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 March 31,
	2018			2017
Realized gains	$	—		$	1
Realized losses	$	(2	)	$	(2	)
Proceeds from sales of securities	$	46		$	79
Investments in securities	$	(51	)	$	(84	)

Property, Plant and Equipment

At March 31, 2018 and December 31, 2017, property, plant and equipment of $4.850 billion and $4.820 billion, respectively, is stated net of accumulated depreciation and amortization of $480 million 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, removal of lignite/coal fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through the regulatory process as part of delivery fees charged by Oncor.

At March 31, 2018, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.244 billion, which exceeds the fair value of the assets contained in the nuclear decommissioning trust. Since the costs to ultimately decommission that plant are recoverable through the regulatory rate making process as part of Oncor's delivery fees, a corresponding regulatory asset has been recorded to our condensed consolidated balance sheet of $64 million in other noncurrent assets.

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 three months ended March 31, 2018:



	Nuclear Plant Decommissioning		Mining Land Reclamation			Other			Total
Liability at December 31, 2017	$	1,233	$	438		$	265		$	1,936
Additions:
Accretion	11		5			3			19
Adjustment for change in estimates	—		4			—			4
Reductions:
Payments	—		(16		)	—			(16		)
Liability at March 31, 2018	1,244		431			268			1,943
Less amounts due currently	—		(117		)	(9		)	(126		)
Noncurrent liability at March 31, 2018	$	1,244	$	314		$	259		$	1,817

Other Noncurrent Liabilities and Deferred Credits

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



	March 31, 2018		December 31, 2017
Unfavorable purchase and sales contracts	$	32	$	36
Other, including retirement and other employee benefits	207		220
Total other noncurrent liabilities and deferred credits	$	239	$	256

Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $4 million and $3 million for the three months ended March 31, 2018 and 2017, respectively. See Note 6 for intangible assets related to favorable purchase and sales contracts.

The estimated amortization of unfavorable purchase and sales contracts for each of the next five fiscal years is as follows:



Year	Amount
2018	$	11
2019	$	9
2020	$	9
2021	$	1
2022	$	3

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Fair Value of Debt



	March 31, 2018				December 31, 2017
Debt:	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt under the Vistra Operations Credit Facilities (Note 10)	$	4,313	$	4,328	$	4,323	$	4,334
Other long-term debt, excluding capital lease obligations (Note 10)	27		24		30		27
Mandatorily redeemable subsidiary preferred stock (Note 10)	70		70		70		70

We determine fair value in accordance with accounting standards as discussed in Note 13, and at March 31, 2018, our debt fair value represents Level 2 valuations. 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 March 31, 2018 and December 31, 2017:



	March 31, 2018		December 31, 2017
Cash and cash equivalents	$	1,379	$	1,487
Restricted cash included in current assets	59		59
Restricted cash included in noncurrent assets	500		500
Total cash, cash equivalents and restricted cash	$	1,938	$	2,046

The following table summarizes our supplemental cash flow information for the three months ended March 31, 2018 and 2017:



	Three Months Ended March 31,
	2018			2017
Cash payments related to:
Interest paid	$	65		$	89
Capitalized interest	(3		)	(3		)
Interest paid (net of capitalized interest)	$	62		$	86
Noncash investing and financing activities:
Construction expenditures (a)	$	26		$	1

____________


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

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

The following discussion and analysis of our financial condition and results of operations for the three months ended March 31, 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

Vistra Energy is a holding company operating an integrated power business in Texas. Through our Luminant and TXU Energy subsidiaries, we are principally engaged in competitive electricity market activities including power generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity and related services to end users.

Operating Segments

Vistra Energy has three reportable segments: (i) our Wholesale Generation segment, consisting largely of Luminant; (ii) our Retail Electricity segment, consisting largely of TXU Energy, and (iii) our Asset Closure segment, consisting of financial results of retired plants and mines. See Note 16 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.

Because the Merger occurred after March 31, 2018, Vistra Energy's condensed consolidated financial statements and the notes related thereto and the discussion of the Company's financial condition, results of operations, liquidity, capital and other requirements, tax payments and other financial and business-related information included herein do not include or take into account the closing of the Merger and the effects of the Merger or any transactions related thereto. See Note 2 to the Financial Statements for a list of events that took place in connection with the completion of the Merger.

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.

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 a partial buyback of the earn-out provision was settled in February 2018.

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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 is expected to begin commercial operations in May 2018.

Repricing of Vistra Operations Credit Facilities — In February, August and December 2017 and February 2018, certain pricing terms for the Vistra Operations Credit Facility were amended. Any amounts borrowed under the Revolving Credit Facility will bear interest based on applicable LIBOR rates plus 2.25%. Amounts borrowed under the Initial Term Loan B Facility and the Term Loan C Facility will bear interest based on applicable LIBOR rates, subject to a 0.75% floor, plus 2.50%. The Incremental Term Loan B Facility will bear interest based on applicable LIBOR rates plus 2.25%. In connection with a repricing amendment in December 2017, the Revolving Credit Facility letter of credit sub-facility was increased from $600 million to $715 million and the Term Loan C Facility was reduced from $650 million to $500 million. See Note 10 to the Financial Statements for details of the Vistra Operations Credit Facilities.

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, at March 31, 2018 we had effectively hedged an estimated 91% and 24% of the natural gas price exposure related to our overall business for 2018 and 2019, respectively. Additionally, taking into consideration our overall heat rate exposure and related hedging positions at March 31, 2018, we had effectively hedged 81% and 44% of the heat rate exposure to our overall business for 2018 and 2019, respectively.

The following sensitivity table provides 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 March 31, 2018.



	Balance 2018 (a)	2019
$0.50/MMBtu increase in natural gas price (b)(c)	$ ~75	$ ~175
$0.50/MMBtu decrease in natural gas price (b)(c)	$ ~(65)	$ ~(165)
1.0/MMBtu/MWh increase in market heat rate (d)	$ ~50	$ ~100
1.0/MMBtu/MWh decrease in market heat rate (d)	$ ~(50)	$ ~(95)

___________


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


(b)	Assumes 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.


(c)	Based on Houston Ship Channel natural gas prices at March 31, 2018.


(d)	Based on ERCOT North Hub around-the-clock heat rates at March 31, 2018.

Environmental Matters — See Note 11 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 Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017



	Three Months Ended March 31,						Favorable (Unfavorable) $ Change
	2018			2017			Favorable (Unfavorable) $ Change
Operating revenues	$	765		$	1,357		$	(592	)
Fuel, purchased power costs and delivery fees	(650		)	(683		)	33
Operating costs	(194		)	(214		)	20
Depreciation and amortization	(153		)	(170		)	17
Selling, general and administrative expenses	(162		)	(135		)	(27		)
Operating income (loss)	(394		)	155			(549		)
Other income	10			9			1
Other deductions	(2		)	—			(2		)
Interest expense and related charges	9			(24		)	33
Impacts of Tax Receivable Agreement	(18		)	(21		)	3
Income (loss) before income taxes	(395		)	119			(514		)
Income tax (expense) benefit	89			(41		)	130
Net income (loss)	$	(306	)	$	78		$	(384	)



	Three Months Ended March 31, 2018
	Wholesale Generation			Retail Electricity			Asset Closure			Eliminations / Corporate and Other			Vistra Energy Consolidated
Operating revenues	$	(533	)	$	972		$	28		$	298		$	765
Fuel, purchased power costs and delivery fees	(290		)	(36		)	(27		)	(297		)	(650		)
Operating costs	(165		)	(4		)	(24		)	(1		)	(194		)
Depreciation and amortization	(64		)	(76		)	—			(13		)	(153		)
Selling, general and administrative expenses	(35		)	(99		)	—			(28		)	(162		)
Operating income (loss)	(1,087		)	757			(23		)	(41		)	(394		)
Other income	11			14			1			(16		)	10
Other deductions	(2		)	—			—			—			(2		)
Interest expense and related charges	(8		)	—			—			17			9
Impacts of Tax Receivable Agreement	—			—			—			(18		)	(18		)
Income (loss) before income taxes	(1,086		)	771			(22		)	(58		)	(395		)
Income tax benefit	—			—			—			89			89
Net income (loss)	$	(1,086	)	$	771		$	(22	)	$	31		$	(306	)

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	Three Months Ended March 31, 2017
	Wholesale Generation			Retail Electricity			Asset Closure			Eliminations / Corporate and Other			Vistra Energy Consolidated
Operating revenues	$	785		$	865		$	186		$	(479	)	$	1,357
Fuel, purchased power costs and delivery fees	(250		)	(772		)	(139		)	478			(683		)
Operating costs	(154		)	(3		)	(57		)	—			(214		)
Depreciation and amortization	(53		)	(106		)	—			(11		)	(170		)
Selling, general and administrative expenses	(28		)	(102		)	(5		)	—			(135		)
Operating income (loss)	$	300		$	(118	)	$	(15	)	$	(12	)	$	155
Other income	4			5			2			(2		)	9
Other deductions	—			—			—			—			—
Interest expense and related charges	(1		)	—			—			(23		)	(24		)
Impacts of Tax Receivable Agreement	—			—			—			(21		)	(21		)
Income (loss) before income taxes	303			(113		)	(13		)	(58		)	119
Income tax expense	—			—			—			(41		)	(41		)
Net income (loss)	$	303		$	(113	)	$	(13	)	$	(99	)	$	78

For the three months ended March 31, 2018, consolidated results reflected strong operating performance in our Wholesale Generation and Retail Electricity segments despite unrealized mark-to-market losses on commodity risk management activity reflecting higher forward power prices principally driven by higher market heat rates. Consolidated results decreased $384 million to a net loss of $306 million in the three months ended March 31, 2018 compared to the three months ended March 31, 2017. Results were driven by:

•

Wholesale Generation segment results reflected strong operating performance from our generation fleet, including increased generation from CCGT driven by the Odessa Acquisition. Results for the segment decreased $1.389 billion to net loss of $1.086 billion primarily driven by unrealized losses from hedging activities in 2018 reflecting an increase in forward power prices principally driven by higher market heat rates. Please see the discussion of Wholesale Generation below for further details.

•

Retail Electricity segment results reflected increased sales volumes primarily driven by colder weather. Net income increased $884 million to $771 million primarily driven by unrealized net gains on hedging activities with affiliates in 2018 reflecting increases in forward prices principally driven by higher market heat rates and higher sales volumes. Please see the discussion of Retail Electricity below for further details.


•	Asset Closure segment net loss decreased $9 million to $22 million. Please see the discussion of Asset Closure below for further details.

Interest expense and related charges decreased $33 million to a credit of $9 million in the three months ended March 31, 2018 compared to the three months ended March 31, 2017 and reflected a $50 million increase in unrealized mark-to-market gains on interest rate swaps and a $4 million decrease in interest expense incurred, partially offset by a $21 million debt extinguishment gain recorded in 2017. See Note 17 to the Financial Statements.

The Impacts of the Tax Receivable Agreement reflected $18 million and $21 million in accretion expense for the three months ended March 31, 2018 and 2017, respectively. See Note 8 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement Obligation.

For the three months ended March 31, 2018, income tax benefit totaled $89 million and the effective tax rate was 22.5%. For the three months ended March 31, 2017, income tax expense totaled $41 million and the effective tax rate was 34.5%. See Note 7 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

Net Income (Loss)

We evaluate our segment performance using net income (loss) as an earnings metric. We believe net income (loss) is useful in evaluating our core business activities and is one of the metrics used by our chief operating decision maker and leadership to evaluate segment results.

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Wholesale Generation Segment — Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017



	Three Months Ended March 31,						Favorable (Unfavorable) Change
	2018			2017
Wholesale electricity sales	$	191		$	178		$	13
Sales to affiliates	345			308			37
Rolloff of unrealized net gains (losses) representing positions settled in the current period	35			(41		)	76
Unrealized net gains (losses) from changes in fair value	(461		)	167			(628		)
Unrealized net gains (losses) on hedging activities with affiliates	(643		)	170			(813		)
Other revenues	—			3			(3		)
Operating revenues	(533		)	785			(1,318		)
Fuel for generation facilities and purchased power costs	(255		)	(213		)	(42		)
Unrealized losses from hedging activities	(1		)	(13		)	12
Ancillary and other costs	(34		)	(24		)	(10		)
Fuel, purchased power costs and delivery fees	(290		)	(250		)	(40		)
Operating costs	(165		)	(154		)	(11		)
Depreciation and amortization	(64		)	(53		)	(11		)
Selling, general and administrative expenses	(35		)	(28		)	(7		)
Operating income (loss)	(1,087		)	300			(1,387		)
Other income	11			4			7
Other deductions	(2		)	—			(2		)
Interest expense and related charges	(8		)	(1		)	(7		)
Net income (loss)	$	(1,086	)	$	303		$	(1,389	)
Sales volumes (GWh):
Wholesale electricity sales volumes (a)	7,409			6,819			590
Production volumes (GWh):
Nuclear facilities	5,268			5,253			15
Lignite and coal facilities	5,436			5,713			(277		)
Natural gas facilities	6,391			3,518			2,873
Capacity factors:
Nuclear facilities	103.8		%	105.8		%
Lignite and coal facilities	64.0		%	67.2		%
CCGT facilities	95.6		%	54.2		%
Market pricing:
Average ERCOT North power price ($/MWh)	$	25.40		$	21.19		$	4.21

____________


(a)	Includes net amounts related to sales and purchases of balancing energy in the ERCOT real-time market.

Wholesale electricity sales and sales to affiliates increased $50 million in the three months ended March 31, 2018 compared to the three months ended March 31, 2017 driven by the increased production from the CCGT facilities related to the Odessa Acquisition (see Note 3 to the Financial Statements), net of a partial buyback of the Odessa earn-out provision, and the increased demand from the Retail Electricity segment.

Unrealized revenues decreased $1.365 billion to negative revenues in the three months ended March 31, 2018 compared to the three months ended March 31, 2017 primarily reflecting an increase in forward power prices principally driven by market heat rates.

Fuel, purchased power costs and delivery fees increased $40 million to $290 million in the three months ended March 31, 2018 compared to the three months ended March 31, 2017 reflecting incremental fuel costs related to the Odessa Acquisition.

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Operating costs increased $11 million to $165 million in the three months ended March 31, 2018 compared to the three months ended March 31, 2017 primarily reflecting incremental operating costs related to the Odessa Acquisition.

Depreciation and amortization expenses increased $11 million to $64 million in the three months ended March 31, 2018 compared to the three months ended March 31, 2017 primarily reflecting incremental depreciation expense related to the Odessa Acquisition.

SG&A increased $7 million to $35 million in the three months ended March 31, 2018 compared to the three months ended March 31, 2017 reflecting higher employee compensation and benefit costs (including functional group costs allocated from Corporate and Other).

Retail Electricity Segment — Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017



	Three Months Ended March 31,						Favorable (Unfavorable) Change
	2018			2017			Favorable (Unfavorable) Change
Revenue from Oncor service area	$	662		$	594		$	68
Revenue from other TDSP service areas	287			261			26
Amortization expense of identifiable intangible assets related to retail contracts (see Note 6 to the Financial Statements)	(12		)	(24		)	12
Other revenues	35			34			1
Operating revenues	972			865			107
Purchases from affiliates	(345		)	(308		)	(37		)
Unrealized net (gains) losses on hedging activities with affiliates	643			(170		)	813
Delivery fees	(333		)	(294		)	(39		)
Other costs	(1		)	—			(1		)
Fuel, purchased power costs and delivery fees	(36		)	(772		)	736
Operating costs	(4		)	(3		)	(1		)
Depreciation and amortization	(76		)	(106		)	30
Selling, general and administrative expenses	(99		)	(102		)	3
Operating income (loss)	757			(118		)	875
Other income	14			5			9
Net income (loss)	$	771		$	(113	)	$	884
Sales volumes (GWh):
Retail electricity sales volumes	9,193			8,150			1,043
Weather (North Texas average) - percent of normal (a):
Heating degree days	95.5		%	61.4		%

____________

(a)

Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the U.S. Department of Commerce). For the three months ended March 31, 2018, normal is defined as the average over the 10-year period from 2007 to 2016. For the three months ended March 31, 2017, normal is defined as the average over the 10-year period from 2006 to 2015.

Retail electricity revenues increased $107 million to $972 million in the three months ended March 31, 2018 compared to the three months ended March 31, 2017. Retail electricity sales were favorably impacted by 1,043 GWh in higher sales volumes in 2018 primarily driven by colder weather.

Purchased power costs, delivery fees and other costs decreased $736 million to $36 million in the three months ended March 31, 2018 compared to the three months ended March 31, 2017. Purchased power and delivery fees were favorably impacted by unrealized net gains on hedging activities with affiliates reflecting increases in forward prices in 2018, partially offset by higher purchases from affiliates and delivery fees reflecting higher sales volumes.

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Depreciation and amortization expenses decreased $30 million to $76 million in the three months ended March 31, 2018 compared to the three months ended March 31, 2017 reflecting lower amortization expense related to the retail customer relationship intangible asset (see Note 6 to the Financial Statements).

SG&A decreased $3 million to $99 million in the three months ended March 31, 2018 compared to the three months ended March 31, 2017 reflecting the deferral of commissions from retail contracts with customers in 2018 that were previously expensed as incurred and lower employee compensation and benefit costs (including functional group costs allocated from Corporate and Other), partially offset by higher bad debt expense.

Asset Closure Segment — Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017



	Three Months Ended March 31,						Favorable (Unfavorable) Change
	2018			2017			Favorable (Unfavorable) Change
Operating revenues	$	28		$	186		$	(158	)
Fuel, purchased power costs and delivery fees	(27		)	(139		)	112
Operating costs	(24		)	(57		)	33
Depreciation and amortization	—			—			—
Selling, general and administrative expenses	—			(5		)	5
Operating loss	(23		)	(15		)	(8		)
Other income	1			2			(1		)
Net income (loss)	$	(22	)	$	(13	)	$	(9	)
Production volumes (GWh):
Lignite and coal facilities	1,070			4,860			(3,790		)

Results for the Asset Closure segment reflect the retirement of the Monticello, Sandow and Big Brown plants in January and February 2018 (see Note 4 to the Financial Statements) and a corresponding 78% decrease in volume in 2018. Operating costs for the three months ended March 31, 2018 included ongoing costs associated with closing those plants.

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

The table below summarizes the changes in commodity contract assets and liabilities for the three months ended March 31, 2018 and 2017. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $415 million in unrealized net losses for the three months ended March 31, 2018 and $120 million in unrealized net gains for the three months ended March 31, 2017 arising from mark-to-market accounting for positions in the commodity contract portfolio.



	Three Months Ended March 31,
	2018			2017
Commodity contract net asset (liability) at beginning of period	$	(96	)	$	64
Settlements/termination of positions (a)	32			(50		)
Changes in fair value of positions in the portfolio (b)	(447		)	170
Other activity (c)	26			10
Commodity contract net asset (liability) at end of period	$	(485	)	$	194

____________

(a)

Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). The three months ended March 31, 2018 and 2017 includes reversal of $10 million and $63 million, respectively, of previously recorded unrealized gains related to Vistra Energy beginning balances. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.


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


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

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Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair values at March 31, 2018, scheduled by the source of fair value and contractual settlement dates of the underlying positions.



	Maturity dates of unrealized commodity contract net asset (liability) at March 31, 2018
Source of fair value	Less than 1 year			1-3 years			4-5 years			Excess of 5 years			Total
Prices actively quoted	$	(13	)	$	(29	)	$	—		$	—		$	(42	)
Prices provided by other external sources	(80		)	(139		)	—			—			(219		)
Prices based on models	(72		)	(126		)	(21		)	(5		)	(224		)
Total	$	(165	)	$	(294	)	$	(21	)	$	(5	)	$	(485	)

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FINANCIAL CONDITION

Cash Flows

Three Months Ended March 31, 2018 Compared to Three Months ended March 31, 2017 — Cash used in operating activities totaled $22 million in the three months ended March 31, 2018 compared to cash provided by operating activities of $141 million in the three months ended March 31, 2017. The unfavorable change of $162 million was primarily driven by an increase in cash used for margin deposits 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 $27 million and $56 million for the three months ended March 31, 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 $9 million and $18 million in the three months ended March 31, 2018 and 2017, respectively. The decrease in cash used in financing activities was driven by lower repayments of debt in 2018 and debt financing fees incurred in 2017.

Cash used in investing activities totaled $77 million and $51 million in the three months ended March 31, 2018 and 2017, respectively. Capital expenditures (including nuclear fuel purchases) totaled $50 million and $43 million in the three months ended March 31, 2018 and 2017, respectively. The increase in cash used in investing activities reflected Upton solar development expenditures totaling $21 million in 2018. The Upton solar development was funded using cash on hand.

Debt Activity

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

Available Liquidity

The following table summarizes changes in available liquidity for the three months ended March 31, 2018:



	March 31, 2018		December 31, 2017		Change
Cash and cash equivalents (a)	$	1,379	$	1,487	$	(108	)
Vistra Operations Credit Facilities — Revolving Credit Facility	584		834		(250		)
Vistra Operations Credit Facilities — Term Loan C Facility (b)	18		7		11
Total available liquidity	$	1,981	$	2,328	$	(347	)

___________


(a)	Cash and cash equivalents excludes $500 million of restricted cash held for letter of credit support at both March 31, 2018 and December 31, 2017 (see Note 17 to the Financial Statements).

(b)

The Term Loan C Facility is used for issuing letters of credit for general corporate purposes. Borrowings totaling $500 million under this facility were held in collateral accounts at both March 31, 2018 and December 31, 2017, and are reported as restricted cash in our condensed consolidated balance sheets. The March 31, 2018 restricted cash balance represents borrowings under the Term Loan C Facility held in collateral accounts that support $482 million in letters of credit outstanding, leaving $18 million in available letter of credit capacity (see Note 10 to the Financial Statements).

The decrease in available liquidity to $1.981 billion in the three months ended March 31, 2018 was primarily driven by increased letter of credit postings and decreased available cash from operations reflecting an increase in cash used for margin deposits.

Based upon our current internal financial forecasts, we believe that we will have sufficient liquidity to fund our anticipated cash requirements through at least the next 12 months.

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Liquidity Effects of Commodity Hedging and Trading Activities

We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. We use cash, letters of credit and other forms of credit support to satisfy such collateral posting obligations. See Note 10 to the Financial Statements for discussion of the Vistra Operations Credit Facilities.

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

At March 31, 2018, we received or posted cash and letters of credit for commodity hedging and trading activities as follows:


•	$93 million in cash has been posted with counterparties as compared to $30 million posted at December 31, 2017;


•	$3 million in cash has been received from counterparties as compared to $4 million received at December 31, 2017;


•	$634 million in letters of credit have been posted with counterparties as compared to $390 million posted at December 31, 2017, and


•	$10 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 expect to make federal income tax payments of approximately $45 million, which represents Vistra Energy's remaining estimated 2017 federal income tax liability. We also expect to make Texas margin tax payments of approximately $19 million and TRA payments of approximately $24 million in the next twelve months. There were no income tax payments for the three months ended March 31, 2018 and 2017.

Financial Covenants

The agreement governing the Vistra Operations Credit Facilities 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 $100 million) exceed 30% of the revolving commitments), that requires the consolidated first lien net leverage ratio not exceed 4.25 to 1.00. Although the period ended March 31, 2018 was not a compliance period, we would have been in compliance with this financial covenant if it was required to be tested at such date.

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

Collateral Support Obligations

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

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, at March 31, 2018, Vistra Energy has posted letters of credit in the amount of $55 million with the PUCT, which is subject to adjustments.

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ERCOT has rules in place to assure adequate creditworthiness of parties that participate in the day-ahead, real-time and congestion revenue rights markets operated by ERCOT. Under these rules, Vistra Energy has posted collateral support, in the form of letters of credit, totaling $110 million at March 31, 2018 (which is subject to daily adjustments based on settlement activity with ERCOT).

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 $4.3 billion at March 31, 2018) under such facilities.

Each of Vistra Operations' (or its subsidiaries') commodity hedging agreements and interest rate swap agreements that are secured with a lien on its assets on a pari passu basis with the Vistra Operations Credit Facilities lenders contains a cross default provision. An event of a default by Vistra Operations or any of its subsidiaries relating to indebtedness 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.

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.

Guarantees

See Note 11 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 11 to the Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

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


Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the risk that in the normal course of business we may experience a loss in value as a result of changes in market conditions that affect economic factors such as commodity prices, interest rates and counterparty credit. Our exposure to market risk is affected by a number of factors, including the size, duration and composition of our energy and financial portfolio, as well as the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swaps to hedge debt costs, as well as exchange-traded, over-the-counter contracts and other contractual arrangements to hedge commodity prices.

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Risk Oversight

We manage the commodity price, counterparty credit and commodity-related operational risk related to the competitive energy business within limitations established by senior management and in accordance with overall risk management 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.

A Monte Carlo simulation methodology is used to calculate VaR and is 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 tables below detail certain VaR measures related to various portfolios of contracts.

VaR for Underlying Generation Assets and Energy-Related Contracts Subject to Mark-to-Market (MtM) Accounting — This measurement estimates the potential loss in fair value, due to changes in market conditions, of all underlying generation assets and contracts marked-to-market in net income (through the end of 2019), based on a 95% confidence level and an assumed holding period of 60 days.



	Three Months Ended March 31, 2018		Year Ended December 31, 2017
Month-end average VaR:	$	100	$	92
Month-end high VaR:	$	121	$	140
Month-end low VaR:	$	65	$	62

The decrease in the month-end high VaR risk measure in 2018 reflected higher seasonal natural gas to power correlations and decreased natural gas volatility.

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Interest Rate Risk

At March 31, 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 $13 million, taking into account the interest rate swaps discussed in Note 10 to Financial Statements.

Credit Risk

Credit risk relates to the risk of loss associated with nonperformance by counterparties. We minimize credit risk by evaluating potential counterparties, monitoring ongoing counterparty risk and assessing overall portfolio risk. This includes review of counterparty financial condition, current and potential credit exposures, credit rating and other quantitative and qualitative credit criteria. We also employ certain risk mitigation practices, including utilization of standardized master agreements that provide for netting and setoff rights, as well as credit enhancements such as margin deposits and customer deposits, letters of credit, parental guarantees and surety bonds. See Note 14 to the Financial Statements for further discussion of this exposure.

Credit Exposure — Our gross credit exposure (excluding collateral impacts) associated with retail and wholesale trade accounts receivable and net derivative assets arising from commodity contracts and hedging and trading activities totaled $620 million at March 31, 2018.

At March 31, 2018, Retail Electricity segment credit exposure totaled $424 million, including $392 million of trade accounts receivable and $32 million related to derivative assets. Cash deposits and letters of credit held as collateral for these receivables totaled $42 million, resulting in a net exposure of $382 million. 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 March 31, 2018, Wholesale Generation segment credit exposure totaled $196 million including $180 million related to derivative assets and $16 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 Wholesale Generation segment exposure was $181 million, substantially all of which is with investment grade customers as seen in the following table that presents the distribution of credit exposure at March 31, 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	$	179	$	5	$	174
Below investment grade or no rating	17		10		7
Totals	$	196	$	15	$	181

Significant (10% or greater) concentration of credit exposure exists with three counterparties, which represented an aggregate $137 million, or 76%, 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 March 31, 2018, interest rate swap exposure in the Corporate and Other non-segment totaled $77 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 I, Item 1A. Risk Factors in our 2017 Form 10-K and Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations in this report 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 Texas Legislature, the Governor of Texas, the U.S. Congress, the FERC, the North American Electric Reliability Corporation, the Texas Reliability Entity, Inc., the PUCT, the RCT, the NRC, the EPA, the TCEQ, 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;


•	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;


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


•	changes in market heat rates in the ERCOT electricity market;


•	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;


•	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;

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•	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:


•	competition for new energy development and other business opportunities;


•	inability of various counterparties to meet their obligations with respect to our financial instruments;


•	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 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.

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 ERCOT, the PUCT 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. 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, there has been no change in our internal control over financial reporting that has 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 11 to the Financial Statements regarding legal proceedings.


Item 1A.	RISK FACTORS

There have been no material changes to the risk factors discussed in Part I, Item 1A. Risk Factors in our 2017 Form 10-K except for the information disclosed elsewhere in this quarterly report on Form 10-Q that provides factual updates to risk factors contained in such prospectus. The risks described in such reports are not the only risks facing our company. 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

None.


Item 3.	DEFAULTS UPON SENIOR SECURITIES

None.


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. 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.

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Item 6.	EXHIBITS


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



Exhibits	Previously Filed With File Number*	As Exhibit

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

2(a)	333-215288 Amendment No. 3 to Form S-1 (filed May 1, 2017)	2.1	—	Order of the United States Bankruptcy Court for the District of Delaware Confirming the Third Amended Joint Plan of Reorganization

2(b)	001-38086 Form 8-K (filed October 31, 2017)	2.1	—	Agreement and Plan of Merger, dated as of October 29, 2017, by and between Vistra Energy Corp. and Dynegy Inc.

(3(i))	Articles of Incorporation

3(a)	333-215288 Amendment No. 3 to Form S-1 (filed May 1, 2017)	3.1		Certification of Incorporation of TCEH Corp.

3(b)	333-215288 Amendment No. 3 to Form S-1 (filed May 1, 2017)	3.2	—	Certificate of Amendment of Certificate of Incorporation of TCEH Corp.

(3(ii))	By-laws

3(c)	333-215288 Amendment No. 3 to Form S-1 (filed May 1, 2017)	3.3	—	Restated Bylaws of Vistra Energy Corp.

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

4(a)	001-33443 Form 8-K (filed on October 30, 2014)	4.7	—	2019 Notes Indenture, dated October 27, 2014, among Dynegy Finance II, Inc. and the Trustee

4(b)	001-33443 Form 8-K (filed on April 7, 2015)	4.8	—	First Supplemental Indenture to the 2019 Notes Indenture, dated April 1, 2015, between Dynegy and the Trustee

4(c)	001-33443 Form 8-K (filed on April 7, 2015).	4.9	—	Second Supplemental Indenture to the 2019 Notes Indenture, dated April 1, 2015, among Dynegy, the Subsidiary Guarantors (as defined therein), and the Trustee

4(d)	001-33443 Form 8-K (filed on April 8, 2015)	4.13	—	Third Supplemental Indenture to the 2019 Notes Indenture, dated April 2, 2015, among Dynegy, the Subsidiary Guarantors

4(e)	001-33443 Form10-Q (Quarter ended June 30, 2015) (filed on August 7, 2015)	4.1	—	Fourth Supplemental Indenture to the 2019 Notes Indenture, dated May 11, 2015, among Dynegy, the Subsidiary Guarantors

4(f)	001-33443 Form 10-Q (Quarter ended September 30, 2015)(filed on November 5, 2015)	4.1	—	Fifth Supplemental Indenture to the 2019 Notes Indenture, dated September 21, 2015, among Dynegy, the Subsidiary Guarantors

4(g)	001-33443 Form 10-K (Year ended December 31, 2016) (filed on February 24, 2017)	4.16	—	Sixth Supplemental Indenture to the 2019 Notes Indenture, dated February 2, 2017, among Dynegy, the Subsidiary Guarantors

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Exhibits	Previously Filed With File Number*	As Exhibit
4(h)	001-33443 Form 10-K (Year ended December 31, 2016) (filed on February 24, 2017)	4.17	—	Seventh Supplemental Indenture to the 2019 Notes Indenture, dated February 7, 2017, among Dynegy, the Subsidiary Guarantors

4(i)	001-38086 Form 8-K (filed on April 9, 2018)	4.9	—	Eighth Supplemental Indenture to the 2019 Notes Indenture, dated April 9, 2018, among the Company, the Subsidiary Guarantors

4(j)	001-33443 Form 8-K (filed on October 30, 2014)	4.7	—	Form of 6.75% Senior Note due 2019

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

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

4(o)	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

4(p)	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

4(q)	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

4(r)	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

4(s)	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

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

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Exhibits	Previously Filed With File Number*	As Exhibit
4(u)	001-33443 Form 8-K (filed on May 21, 2013)	4.1	—	2023 Notes Indenture, dated May 20, 2013, among Dynegy, the Subsidiary Guarantors

4(v)	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

4(w)	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

4(x)	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

4(y)	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(z)	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

4(aa)	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

4(bb)	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

4(cc)	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

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

4(ee)	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(ff)	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(gg)	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

4(hh)	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

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Exhibits	Previously Filed With File Number*	As Exhibit
4(ii)	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

4(jj)	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

4(kk)	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

4(ll)	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

4(mm)	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

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

4(oo)	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(pp)	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

4(qq)	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

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

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

4(tt)	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

4(uu)	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

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Exhibits	Previously Filed With File Number*	As Exhibit
4(vv)	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

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

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

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

4(zz)	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

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

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

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

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

4(jjj)	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(kkk)	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

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Exhibits	Previously Filed With File Number*	As Exhibit
4(lll)	001-33443 Form of 8-K (filed on February 7, 2017)	4.1	—	Form of Warrant

4(mmm)	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 February 22, 2018)	10.1	—	Sixth Amendment to Credit Agreement, dated as of February 20, 2018 (effective February 20, 2018), by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto.

(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

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: May 4, 2018

Attached files

Vistra Corp. Reports

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