Vistra Corp. - FORM 10-Q - August 6, 2018

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EX-32.A - CERTIFICATION OF CURTIS A. MORGAN - Vistra Corp.vistra-2018630xexhibit32a.htm
EX-95.A - MINE SAFETY DISCLOSURES - Vistra Corp.vistra-2018630xexhibit95a.htm
EX-32.B - CERTIFICATION OF J. WILLIAM HOLDEN - Vistra Corp.vistra-2018630xexhibit32b.htm
EX-31.B - CERTIFICATION OF J. WILLIAM HOLDEN - Vistra Corp.vistra-2018630xexhibit31b.htm
EX-31.A - CERTIFICATION OF CURTIS A. MORGAN - Vistra Corp.vistra-2018630xexhibit31a.htm



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 JUNE 30, 2018

— OR —

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


Commission File Number 001-38086


Vistra Energy Corp.

(Exact name of registrant as specified in its charter)

Delaware
 
36-4833255
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
6555 Sierra Drive, Irving, Texas 75039
 
(214) 812-4600
(Address of principal executive offices) (Zip Code)
 
(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.   Yes x    No o

Indicate by check mark whether the registrant has submitted electronically 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 August 2, 2018, there were 518,617,157 shares of common stock, par value $0.01, outstanding of Vistra Energy Corp.
 


TABLE OF CONTENTS
 
 
PAGE
 
PART I.
 
Item 1.
 
 
 
 
 
 
Item 2.
Item 3.
Item 4.
PART II.
Item 1.
Item 1A.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
 

Vistra Energy Corp.'s (Vistra Energy) annual reports, quarterly reports, current reports and any amendments to those reports are made available to the public, free of charge, on the Vistra Energy website at http://www.vistraenergy.com, as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended. The information on Vistra Energy's website shall not be deemed a part of, or incorporated by reference into, this quarterly report on Form 10-Q. The representations and warranties contained in any agreement that we have filed as an exhibit to this quarterly report on Form 10-Q, or that we have or may publicly file in the future, may contain representations and warranties that may (i) be made by and to the parties thereto at specific dates, (ii) be subject to exceptions and qualifications contained in separate disclosure schedules, (iii) represent the parties' risk allocation in the particular transaction, or (iv) be qualified by materiality standards that differ from what may be viewed as material for securities law purposes.

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


i

GLOSSARY

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
2017 Form 10-K
 
Vistra Energy's annual report on Form 10-K for the year ended December 31, 2017, filed with the SEC on February 26, 2018, except for Part II, Items 7 and 8, which were amended in Vistra Energy's current report on Form 8-K filed with the SEC on June 15, 2018
 
 
 
ARO
 
asset retirement and mining reclamation obligation
 
 
 
CAA
 
Clean Air Act
 
 
 
CAISO
 
The California Independent System Operator
 
 
 
CCGT
 
combined cycle gas turbine
 
 
 
CFTC
 
U.S. Commodity Futures Trading Commission
 
 
 
CME
 
Chicago Mercantile Exchange
 
 
 
CO2
 
carbon dioxide
 
 
 
Dynegy
 
Dynegy Inc., and/or its subsidiaries, depending on context
 
 
 
EBITDA
 
earnings (net income) before interest expense, income taxes, depreciation and amortization
 
 
 
Effective Date
 
October 3, 2016, the date our predecessor completed its reorganization under Chapter 11 of the U.S. Bankruptcy Code
 
 
 
Emergence
 
emergence of our predecessor from reorganization under Chapter 11 of the U.S. Bankruptcy Code as subsidiaries of a newly formed company, Vistra Energy, on the Effective Date
 
 
 
EPA
 
U.S. Environmental Protection Agency
 
 
 
ERCOT
 
Electric Reliability Council of Texas, Inc.
 
 
 
FERC
 
U.S. Federal Energy Regulatory Commission
 
 
 
GAAP
 
generally accepted accounting principles
 
 
 
GWh
 
gigawatt-hours
 
 
 
ICE
 
IntercontinentalExchange
 
 
 
IRS
 
U.S. Internal Revenue Service
 
 
 
ISO
 
Independent System Operator
 
 
 
ISO-NE
 
Independent System Operator New England
 
 
 
kW
 
kilowatt
 
 
 
LIBOR
 
London Interbank Offered Rate, an interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market
 
 
 
load
 
demand for electricity
 
 
 
Luminant
 
subsidiaries of Vistra Energy engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management
 
 
 
market heat rate
 
Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier 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
 
 
 

ii

Merger Date
 
April 9, 2018, the date Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement
 
 
 
MISO
 
Midcontinent Independent System Operator, Inc.
 
 
 
MMBtu
 
million British thermal units
 
 
 
MW
 
megawatts
 
 
 
MWh
 
megawatt-hours
 
 
 
NERC
 
North American Electricity Reliability Corporation
 
 
 
NRC
 
U.S. Nuclear Regulatory Commission
 
 
 
NYMEX
 
the New York Mercantile Exchange, a commodity derivatives exchange
 
 
 
NYISO
 
New York Independent System Operator
 
 
 
PJM
 
PJM Interconnection, LLC
 
 
 
Plan of Reorganization
 
Third Amended Joint Plan of Reorganization filed by the parent company of our predecessor in August 2016 and confirmed by the U.S. Bankruptcy Court for the District of Delaware in August 2016 solely with respect to our Predecessor
 
 
 
PrefCo
 
Vistra Preferred Inc.
 
 
 
PrefCo Preferred Stock Sale
 
as part of the Spin-Off, the contribution of certain of the assets of our predecessor and its subsidiaries by a subsidiary of TEX Energy LLC to PrefCo in exchange for all of PrefCo's authorized preferred stock, consisting of 70,000 shares, par value $0.01 per share
 
 
 
PUCT
 
Public Utility Commission of Texas
 
 
 
REP
 
retail electric provider
 
 
 
RCT
 
Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas
 
 
 
S&P
 
Standard & Poor's Ratings (a credit rating agency)
 
 
 
SEC
 
U.S. Securities and Exchange Commission
 
 
 
SG&A
 
selling, general and administrative
 
 
 
Tax Matters Agreement
 
Tax Matters Agreement, dated as of the Effective Date, by and among Energy Future Holdings Corp. (EFH Corp.), Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and EFH Merger Co. LLC
TCEH
 
Texas Competitive Electric Holdings Company LLC, a direct, wholly owned subsidiary of Energy Future Competitive Holdings Company LLC, and, prior to the Effective Date, the parent company of our predecessor, depending on context, that 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 Receivable Agreement, containing certain rights (TRA Rights) to receive payments from Vistra Energy related to certain tax benefits, including those it realized as a result of certain transactions entered into at Emergence (see Note 8 to the Financial Statements)
 
 
 
TXU Energy
 
TXU Energy Retail Company LLC, an indirect, wholly owned subsidiary of Vistra Energy that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers
 
 
 
U.S.
 
United States of America
 
 
 
Vistra Energy
 
Vistra Energy Corp. and/or its subsidiaries, depending on context
 
 
 
Vistra Operations Credit Facilities
 
Vistra Operations Company LLC's $8.342 billion senior secured financing facilities (see Note 10 to the Financial Statements).


iii

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 June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Operating revenues (Note 5)
$
2,574


$
1,296


$
3,338


$
2,653

Fuel, purchased power costs and delivery fees
(1,216
)

(729
)

(1,866
)

(1,411
)
Operating costs
(386
)

(195
)

(580
)

(409
)
Depreciation and amortization
(389
)

(172
)

(542
)

(341
)
Selling, general and administrative expenses
(352
)

(147
)

(514
)

(285
)
Operating income (loss)
231


53


(164
)

207

Other income (Note 19)
7


9


18


18

Other deductions (Note 19)
(1
)

(5
)

(3
)

(5
)
Interest expense and related charges (Note 19)
(146
)

(69
)

(137
)

(93
)
Impacts of Tax Receivable Agreement (Note 8)
(64
)

(22
)

(82
)

(42
)
Equity in earnings of unconsolidated investment
4


—


4


—

Income (loss) before income taxes
31


(34
)

(364
)

85

Income tax benefit (expense) (Note 7)
74


8


163


(33
)
Net income (loss)
$
105


$
(26
)

$
(201
)

$
52

Less: Net loss attributable to noncontrolling interest
(3
)

—


(3
)

—

Net income (loss) attributable to Vistra Energy
$
108


$
(26
)

$
(198
)

$
52

Weighted average shares of common stock outstanding:











Basic
526,332,862


427,587,401


477,662,016


427,585,381

Diluted
533,786,824


427,587,401


477,662,016


427,846,563

Net income (loss) per weighted average share of common stock outstanding:











Basic
$
0.21


$
(0.06
)

$
(0.41
)

$
0.12

Diluted
$
0.20


$
(0.06
)

$
(0.41
)

$
0.12


See Notes to the Condensed Consolidated Financial Statements.

CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)
(Unaudited) (Millions of Dollars)
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Net income (loss)
$
105

 
$
(26
)
 
$
(201
)
 
$
52

Other comprehensive income (loss), net of tax effects:
 
 
 
 
 
 
 
Effect 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)
$
105

 
$
(26
)
 
$
(200
)
 
$
52

Less: Comprehensive loss attributable to noncontrolling interest
(3
)
 
—

 
(3
)
 
—

Comprehensive income (loss) attributable to Vistra Energy
$
108

 
$
(26
)
 
$
(197
)
 
$
52


See Notes to the Condensed Consolidated Financial Statements.

1


VISTRA ENERGY CORP.
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Unaudited) (Millions of Dollars)
 
Six Months Ended June 30,
 
2018
 
2017
 
 
 
 
Cash flows — operating activities:
 
 
 
Net income (loss)
$
(201
)

$
52

Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:
 
 
 
Depreciation and amortization
619


437

Deferred income tax (benefit) expense, net
(159
)

29

Unrealized net (gain) loss from mark-to-market valuations of commodities
199


(54
)
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps
(86
)
 
6

Accretion expense
44


29

Impacts of Tax Receivable Agreement (Note 8)
82


42

Stock-based compensation (Note 16)
59


8

Other, net
(6
)

(7
)
Changes in operating assets and liabilities:



Margin deposits, net
(61
)

147

Accrued interest
(74
)

(29
)
Accrued taxes
(112
)

(73
)
Accrued incentive plan
(31
)

(60
)
Other operating assets and liabilities
(302
)

(194
)
Cash provided by (used in) operating activities
(29
)

333

Cash flows — financing activities:



Repayments/repurchases of debt (Note 10)
(1,338
)

(24
)
Stock repurchase
(63
)

—

Debt financing fee (Note 10)
(46
)

(3
)
Other, net
4


—

Cash used in financing activities
(1,443
)

(27
)
Cash flows — investing activities:



Capital expenditures
(153
)

(63
)
Nuclear fuel purchases
(28
)

(35
)
Cash acquired in the Merger
445


—

Solar development expenditures (Note 3)
(21
)

(96
)
Proceeds from sales of nuclear decommissioning trust fund securities (Note 19)
93


98

Investments in nuclear decommissioning trust fund securities (Note 19)
(103
)

(107
)
Other, net
9


9

Cash provided by (used in) investing activities
242


(194
)






Net change in cash, cash equivalents and restricted cash
(1,230
)

112

Cash, cash equivalents and restricted cash — beginning balance
2,046


1,588

Cash, cash equivalents and restricted cash — ending balance
$
816


$
1,700


See Notes to the Condensed Consolidated Financial Statements.

2


VISTRA ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited) (Millions of Dollars)
 
June 30,
2018
 
December 31,
2017
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
757

 
$
1,487

Restricted cash (Note 19)
59

 
59

Trade accounts receivable — net (Note 19)
1,149

 
582

Income taxes receivable
11

 
—

Inventories (Note 19)
465

 
253

Commodity and other derivative contractual assets (Note 14)
598

 
190

Margin deposits related to commodity contracts
200

 
30

Prepaid expense and other current assets
135

 
72

Total current assets
3,374

 
2,673

Restricted cash (Note 19)
—

 
500

Investments (Note 19)
1,290

 
1,240

Investment in unconsolidated subsidiary (Note 19)
135

 
—

Property, plant and equipment — net (Note 19)
14,981

 
4,820

Goodwill (Note 6)
1,907

 
1,907

Identifiable intangible assets — net (Note 6)
2,698

 
2,530

Commodity and other derivative contractual assets (Note 14)
244

 
58

Accumulated deferred income taxes
1,260

 
710

Other noncurrent assets
581

 
162

Total assets
$
26,470

 
$
14,600

LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Long-term debt due currently (Note 10)
$
156

 
$
44

Trade accounts payable
795

 
473

Commodity and other derivative contractual liabilities (Note 14)
883

 
224

Margin deposits related to commodity contracts
3

 
4

Accrued income taxes
—

 
58

Accrued taxes other than income
143

 
136

Accrued interest
108

 
16

Asset retirement obligations (Note 19)
171

 
99

Other current liabilities
387

 
297

Total current liabilities
2,646

 
1,351

Long-term debt, less amounts due currently (Note 10)
11,807

 
4,379

Commodity and other derivative contractual liabilities (Note 14)
495

 
102

Accumulated deferred income taxes
5

 
—

Tax Receivable Agreement obligation (Note 8)
414

 
333

Asset retirement obligations (Note 19)
2,151

 
1,837

Identifiable intangible liabilities — net (Note 6)
187

 
36

Other noncurrent liabilities and deferred credits (Note 19)
345

 
220

Total liabilities
18,050

 
8,258


3


VISTRA ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited) (Millions of Dollars)
 
June 30,
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: June 30, 2018 — 521,214,879; December 31, 2017 — 428,398,802)
5

 
4

Additional paid-in-capital
10,015

 
7,765

Retained deficit
(1,591
)
 
(1,410
)
Accumulated other comprehensive income
(16
)
 
(17
)
Stockholders' equity
8,413

 
6,342

Noncontrolling interest in subsidiary
7

 
—

Total equity
8,420

 
6,342

Total liabilities and equity
$
26,470

 
$
14,600


See Notes to the Condensed Consolidated Financial Statements.

4

VISTRA ENERGY CORP.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1.
BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES

Description of Business

References in this report to "we," "our," "us" and "the Company" are to Vistra Energy and/or its subsidiaries, as apparent in the context. See Glossary for defined terms.

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

Vistra Energy has six reportable segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv) NY/NE (comprising NYISO and ISO-NE), (v) MISO and (vi) Asset Closure. The Asset Closure segment was established as of January 1, 2018, and we have recast prior period information to reflect this change in reportable segments. See Note 18 for further information concerning reportable business segments.

Merger Transaction

On the Merger Date, Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement entered into in October 2017. Pursuant to the Merger Agreement, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the surviving corporation. Because the Merger closed on April 9, 2018, Vistra Energy's condensed consolidated financial statements and the notes related thereto do not include the financial condition or the operating results of Dynegy prior to April 9, 2018. See Note 2 for a summary of the Merger transaction and business combination accounting.

Basis of Presentation

The condensed consolidated financial statements have been prepared in accordance with U.S. GAAP and on the same basis as the audited financial statements included in our 2017 Form 10-K, with the exception of the changes in reportable segments as detailed above. Adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with U.S. GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by U.S. GAAP, they should be read in conjunction with the audited financial statements and related notes contained in our 2017 Form 10-K. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. dollars unless otherwise indicated.

Use of Estimates

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

Unconsolidated Investments

We use the equity method of accounting for investments in affiliates over which we exercise significant influence. Our share of net income (loss) from these affiliates is recorded to equity in earnings (loss) of unconsolidated investment in the condensed statements of consolidated net income (loss). We use the cost method of accounting where we do not exercise significant influence. See Note 19.


5

Noncontrolling Interest

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

Treasury Stock

Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock, which is presented in our condensed consolidated balance sheets as a reduction to additional paid-in capital. See Note 12.

Adoption of New Accounting Standards

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

As of January 1, 2018, the cumulative effect of the changes made to our condensed consolidated balance sheet for the adoption of the new revenue standard was as follows:
 
December 31, 2017
 
Adoption of New Revenue Standard
 
January 1,
2018
Impact on condensed consolidated balance sheet:
 
 
 
 
 
Assets
 
 
 
 
 
Prepaid expense and other current assets
$
72

 
$
5

 
$
77

Accumulated deferred income taxes
$
710

 
$
(4
)
 
$
706

Other noncurrent assets
$
162

 
$
16

 
$
178

Equity
 
 
 
 
 
Retained deficit
$
(1,410
)
 
$
17

 
$
(1,393
)

The disclosure of the impact of adoption on our condensed statement of consolidated income (loss) and condensed consolidated balance sheet was as follows:
 
Three Months Ended June 30, 2018
 
Six Months Ended June 30, 2018
 
As Reported
 
Amount Without Adoption of New Revenue Standard
 
Effect of Change
Higher (Lower)
 
As Reported
 
Amount Without Adoption of New Revenue Standard
 
Effect of Change
Higher (Lower)
Impact on condensed statement of consolidated income (loss):
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$
2,574

 
$
2,573

 
$
1

 
$
3,338

 
$
3,336

 
$
2

Selling, general and administrative expenses
(352
)
 
(355
)
 
3

 
(514
)
 
(520
)
 
6

Net income (loss)
105

 
102

 
3

 
(201
)
 
(207
)
 
6



6

 
June 30, 2018
 
As Reported
 
Balances Without Adoption of New Revenue Standard
 
Effect of Change
Higher (Lower)
Impact on condensed consolidated balance sheet:
 
 
 
 
 
Assets
 
 
 
 
 
Prepaid expense and other current assets
$
135

 
$
129

 
$
6

Accumulated deferred income taxes
1,260

 
1,264

 
(4
)
Other noncurrent assets
581

 
558

 
23

Equity
 
 
 
 
 
Retained deficit
$
(1,591
)
 
$
(1,614
)
 
$
23


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

Statement of Cash Flows — In November 2016, the FASB issued ASU 2016-18 Statement of Cash Flows (Topic 230): Restricted Cash. The ASU requires restricted cash to be included in the cash and cash equivalents and a reconciliation between the change in cash and cash equivalents and the amounts presented on the balance sheet (see Note 19). 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 six months ended June 30, 2017, our condensed statement of consolidated cash flows previously reflected a source of cash of $31 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 19 for disclosures related to the adoption of this accounting standard.

Changes in Accounting Standards

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


2.    MERGER TRANSACTION AND BUSINESS COMBINATION ACCOUNTING

Merger Transaction

On the Merger Date, Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement entered into in October 2017. Pursuant to the Merger Agreement, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the surviving corporation. The Merger is intended to qualify as a tax-free reorganization under the Internal Revenue Code, as amended, so that none of Vistra Energy, Dynegy or any of the Dynegy stockholders will recognize any gain or loss in the transaction, except that Dynegy stockholders could recognize a gain or loss with respect to cash received in lieu of fractional shares of Vistra Energy's common stock. Vistra Energy is the acquirer for both federal tax and accounting purposes.

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


7

Business Combination Accounting

We believe the Merger provides a number of significant potential strategic benefits and opportunities to Vistra Energy, including increased scale and market diversification, rebalanced asset portfolio and improved earnings and cash flow. The Merger is being accounted for in accordance with ASC 805, Business Combinations (ASC 805), with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the Merger Date. The combined results of operations are reported in our consolidated financial statements beginning as of the Merger Date. A summary of the techniques used to estimate the preliminary fair value of the identifiable assets and liabilities, as well as their classification within the fair value hierarchy (see Note 13), is listed below:

•
Working capital was valued using available market information (Level 2).
•
Acquired property, plant and equipment was valued using a combination of an income approach and a market approach. The income approach utilized a discounted cash flow analysis based upon a debt-free, free cash flow model (Level 3).
•
Acquired derivatives were valued using the methods described in Note 13 (Level 1, Level 2 or Level 3).
•
Contracts with terms that were not at current market prices were also valued using a discounted cash flow analysis (Level 3). The cash flows generated by the contracts were compared with their cash flows based on current market prices with the resulting difference recorded as either an intangible asset or liability.
•
Long-term debt was valued using a market approach (Level 2).
•
AROs were recorded in accordance with ASC 410, Asset Retirement and Environmental Obligations (Level 3).

The following table summarizes the consideration paid and the preliminary allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Merger as of the Merger Date. Based on the opening price of Vistra Energy common stock on the Merger Date, the preliminary purchase price was approximately $2.3 billion. The purchase price allocation is ongoing and is dependent upon final valuation determinations, which have not been completed. The preliminary values included below represent our current best estimates for property plant and equipment, identifiable intangible assets and liabilities, inventories, asset retirement obligations and deferred taxes. The purchase price allocation is preliminary and each of these may change materially based upon the receipt of more detailed information, additional analyses and completed valuations. We currently expect the final purchase price allocation will be completed no later than the second quarter of 2019.
Dynegy shares outstanding as of April 9, 2018 (in millions)
173
Exchange Ratio
0.652

Vistra Energy shares issued for Dynegy shares outstanding (in millions)
113

Opening price of Vistra Energy common stock on April 9, 2018
$
19.87

Purchase price for common stock
$
2,245

Fair value of outstanding stock compensation awards attributable to pre-combination service
$
26

Fair value of outstanding warrants
$
2

Total purchase price
$
2,273



8

Preliminary Purchase Price Allocation
Cash and cash equivalents
$
445

Trade accounts receivables, inventories, prepaid expenses and other current assets
863

Property, plant and equipment
10,362

Accumulated deferred income taxes
391

Identifiable intangible assets
387

Other noncurrent assets
532

Total assets acquired
12,980

Trade accounts payable and other current liabilities
644

Commodity and other derivative contractual assets and liabilities, net
422

Asset retirement obligations, including amounts due currently
419

Long-term debt, including amounts due currently
8,920

Other noncurrent liabilities
292

Total liabilities assumed
10,697

Identifiable net assets acquired
2,283

Noncontrolling interest in subsidiary
10

Total purchase price
$
2,273


Acquisition costs incurred in the Merger totaled $50 million and $52 million for the three and six months ended June 30, 2018, respectively For the period from the Merger Date through June 30, 2018, our condensed statements of consolidated income (loss) include revenues and net income (loss) acquired in the Merger totaling $1.248 billion and $97 million, respectively.

Unaudited Pro Forma Financial Information — The following unaudited pro forma financial information for the six months ended June 30, 2018 and 2017 assumes that the Merger occurred on January 1, 2017. The unaudited pro forma financial information is provided for information purposes only and is not necessarily indicative of the results of operations that would have occurred had the Merger been completed on January 1, 2017, nor is the unaudited pro forma financial information indicative of future results of operations, which may differ materially from the pro forma financial information presented here.
 
Six Months Ended June 30,
 
2018
 
2017
Revenues
$
4,789

 
$
5,213

Net income (loss)
$
(439
)
 
$
18

Net income (loss) attributable to Vistra Energy
$
(435
)
 
$
7

Net income (loss) attributable to Vistra Energy per weighted average share of common stock outstanding — basic
$
(0.83
)
 
$
0.01

Net income (loss) attributable to Vistra Energy per weighted average share of common stock outstanding — diluted
$
(0.83
)
 
$
0.01


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


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.


9

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

Upton Solar Development

In May 2017, we acquired the rights to develop, construct and operate a utility scale solar photovoltaic power generation facility in Upton County, Texas (Upton). As part of this project, we entered a turnkey engineering, procurement and construction agreement to construct the approximately 180 MW facility. For the six months ended June 30, 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 commercial operations began in June 2018.

Battery Energy Storage Project

In June 2018, we announced that, subject to approval by the California Public Utilities Commission (CPUC), we will enter into a 20-year resource adequacy contract with Pacific Gas and Electric Company (PG&E) to develop a 300 MW battery energy storage project at our Moss Landing Power Plant site in California. In late June 2018, PG&E filed its application with the CPUC to approve the contract, and a decision is expected within 90 days of the filing. Pending the receipt of CPUC approval, we anticipate the battery storage project will enter commercial operations by the fourth quarter of 2020.


4.
RETIREMENT OF GENERATION FACILITIES

Two of our non-operated, jointly held power plants acquired in the Merger for which our proportional generation capacity was 883 MW, were retired in May 2018. These units were retired as previously scheduled. No gain or loss was recorded in conjunction with the retirement of these units, and the operational results of these facilities are included in our Asset Closure segment. The following table details the units retired.
Name
 
Location
 
Fuel Type
 
Net Generation Capacity (MW)
 
Ownership Interest
 
Date Units Taken Offline
Killen
 
Manchester, Ohio
 
Coal
 
204

 
33%
 
May 31, 2018
Stuart
 
Aberdeen, Ohio
 
Coal
 
679

 
39%
 
May 24, 2018
Total
 
 
 
 
 
883

 

 
 

In January and February 2018, we retired three power plants with a total installed nameplate generation capacity of 4,167 MW. Luminant decided to retire these units because they were projected to be uneconomic based on then current market conditions and would have faced significant environmental costs associated with operating such units. In the case of the Sandow units, the decision also reflected the execution of a contract termination agreement pursuant to which the Company and Alcoa agreed to an early settlement of a long-standing power and mining agreement. Expected retirement expenses were accrued in the third and fourth quarter of 2017 and, as a result, no retirement expenses were recorded related to these facilities in both the three and six months ended June 30, 2018. The operational results of these facilities are included in our Asset Closure segment. The following table details the units retired.
Name
 
Location (all in the state of Texas)
 
Fuel Type
 
Installed Nameplate Generation Capacity (MW)
 
Number of Units
 
Date Units Taken Offline
Monticello
 
Titus County
 
Lignite/Coal
 
1,880

 
3
 
January 4, 2018
Sandow
 
Milam County
 
Lignite
 
1,137

 
2
 
January 11, 2018
Big Brown
 
Freestone County
 
Lignite/Coal
 
1,150

 
2
 
February 12, 2018
Total
 
 
 
 
 
4,167

 
7
 
 



10

5.
REVENUE

The following tables disaggregate our revenue by major source:
 
Three Months Ended June 30, 2018
 
Retail
 
ERCOT
 
PJM
 
NY/NE
 
MISO
 
Asset
Closure
 
CAISO/Eliminations
 
Consolidated
Revenue from contracts with customers:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Retail energy charge in ERCOT
$
1,111

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
1,111

Retail energy charge in Northeast/Midwest
336

 
—

 
—

 
—

 
—

 
—

 
—

 
336

Wholesale generation revenue from ISO
—

 
208

 
367

 
118

 
180

 
15

 
13

 
901

Capacity revenue
—

 
—

 
119

 
82

 
29

 
10

 
11

 
251

Revenue from other wholesale contracts
—

 
50

 
8

 
6

 
12

 
—

 
2

 
78

Total revenue from contracts with customers
1,447

 
258

 
494

 
206

 
221

 
25

 
26

 
2,677

Other revenues:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Intangible amortization
(15
)
 
—

 
—

 
(2
)
 
(6
)
 
—

 
—

 
(23
)
Hedging and other revenues
22

 
229

 
(161
)
 
(29
)
 
(121
)
 
(25
)
 
5

 
(80
)
Affiliate sales
—

 
840

 
152

 
12

 
163

 
21

 
(1,188
)
 
—

Total other revenues
7

 
1,069

 
(9
)
 
(19
)
 
36

 
(4
)
 
(1,183
)
 
(103
)
Total revenues
$
1,454

 
$
1,327

 
$
485

 
$
187

 
$
257

 
$
21

 
$
(1,157
)
 
$
2,574


 
Six Months Ended June 30, 2018
 
Retail
 
ERCOT
 
PJM
 
NY/NE
 
MISO
 
Asset
Closure
 
CAISO/Eliminations
 
Consolidated
Revenue from contracts with customers:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Retail energy charge in ERCOT
$
2,059

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
2,059

Retail energy charge in Northeast/Midwest
336

 
—

 
—

 
—

 
—

 
—

 
—

 
336

Wholesale generation revenue from ISO
—

 
383

 
367

 
118

 
180

 
51

 
13

 
1,112

Capacity revenue
—

 
—

 
119

 
82

 
29

 
10

 
11

 
251

Revenue from other wholesale contracts
—

 
102

 
8

 
6

 
12

 
1

 
2

 
131

Total revenue from contracts with customers
2,395

 
485

 
494

 
206

 
221

 
62

 
26

 
3,889

Other revenues:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Retail contract amortization
(27
)
 
(1
)
 
—

 
(2
)
 
(6
)
 
—

 
—

 
(36
)
Hedging and other revenues
58

 
(233
)
 
(161
)
 
(29
)
 
(121
)
 
(34
)
 
5

 
(515
)
Affiliate sales
—

 
543

 
152

 
12

 
163

 
21

 
(891
)
 
—

Total other revenues
31

 
309

 
(9
)
 
(19
)
 
36

 
(13
)
 
(886
)
 
(551
)
Total revenues
$
2,426

 
$
794

 
$
485

 
$
187

 
$
257

 
$
49

 
$
(860
)
 
$
3,338


Retail Energy Charges

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


11

Wholesale Generation Revenue from ISOs

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

Capacity Revenue

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

Revenue from Other Wholesale Contracts

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

Contract and Other Customer Acquisition Costs

We defer costs to acquire retail contracts and amortize these costs over the expected life of the contract. The expected life of a retail contract is calculated using historical attrition rates, which we believe to be an accurate indicator of future attrition rates. The deferred acquisition and contract cost balance as of June 30, 2018 and January 1, 2018 was $31 million and $22 million, respectively. The amortization related to these costs during the three and six months ended June 30, 2018 totaled $3 million and $6 million, respectively, recorded as a reduction to selling, general and administrative expenses, and $1 million and $2 million, respectively, recorded as operating revenues in the condensed statement of consolidated income (loss).

Practical Expedients

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

Performance Obligations
 
Performance Obligations as of June 30, 2018
 
 
 
2018
 
2019
 
2020
 
2021
 
2022
 
Thereafter (a)
Total capacity sold (MW)
17,829
 
17,429
 
14,826
 
13,619
 
5,947
 
338
Average price per kW-month
$
5.66

 
$
4.99

 
$
4.22

 
$
4.46

 
$
4.76

 
$
4.39

____________
(a)
Average of performance obligations from 2023-2027.

The table above includes future performance obligations that are unsatisfied, or partially unsatisfied, at the end of the reporting period. Our performance obligations relate to capacity auction volumes awarded through capacity auctions held by the ISO or through bilateral sales. Therefore, an obligation exists as of the date of the results of the respective ISO capacity auction, or the contract execution date for bilateral customers. The transaction price is also set by the results of the capacity auction or executed contract.


12

Accounts Receivable

The following table presents trade accounts receivable relating to both contracts with customers and other activities:
 
June 30, 2018
Trade accounts receivable from contracts with customers — net
$
1,044

Other trade accounts receivable — net
105

Total trade accounts receivable — net
$
1,149



6.
GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES

Goodwill

The carrying value of goodwill totaling $1.907 billion at both June 30, 2018 and December 31, 2017 arose in connection with our application of fresh start reporting at Emergence and was allocated entirely to our ERCOT Retail reporting unit. Of the goodwill recorded at Emergence, $1.686 billion is deductible for tax purposes over 15 years on a straight-line basis.

Identifiable Intangible Assets and Liabilities

Identifiable intangible assets and liabilities are comprised of the following:
 
 
June 30, 2018
 
December 31, 2017
Identifiable Intangible Asset
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Net
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Net
Retail customer relationship
 
$
1,678

 
$
722

 
$
956

 
$
1,648

 
$
572

 
$
1,076

Software and other technology-related assets
 
227

 
76

 
151

 
183

 
47

 
136

Retail and wholesale contracts
 
445

 
126

 
319

 
154

 
87

 
67

Other identifiable intangible assets (a)
 
34

 
11

 
23

 
33

 
11

 
22

Total identifiable intangible assets subject to amortization
 
$
2,384

 
$
935

 
1,449

 
$
2,018

 
$
717

 
1,301

Retail trade names (not subject to amortization)
 
 
 
 
 
1,245

 
 
 
 
 
1,225

Mineral interests (not currently subject to amortization)
 
 
 
 
 
4

 
 
 
 
 
4

Total identifiable intangible assets
 
 
 
 
 
$
2,698

 
 
 
 
 
$
2,530

Identifiable Intangible Liability
 
 
 
 
 
 
 
 
 
 
 
 
Contractual service agreements
 
$
139

 
$
—

 
$
139

 
$
—

 
$
—

 
$
—

Purchase and sales contracts
 
69

 
21

 
48

 
49

 
13

 
36

Total identifiable intangible liabilities
 
$
208

 
$
21

 
$
187

 
$
49

 
$
13

 
$
36

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


13

Amortization expense related to finite-lived identifiable intangible assets and liabilities (including the classification in the condensed statements of consolidated income (loss)) consisted of:
Identifiable Intangible Assets and Liabilities
 
Condensed Statements of Consolidated Income (Loss) Line
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Retail customer relationship
 
Depreciation and amortization
$
77

 
$
105

 
$
150

 
$
210

Software and other technology-related assets
 
Depreciation and amortization
19

 
9

 
30

 
17

Retail and wholesale contracts/purchase and sales contracts
 
Operating revenues/fuel, purchased power costs and delivery fees
23

 
21

 
32

 
45

Other identifiable intangible assets
 
Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization
2

 
4

 
3

 
8

Total amortization expense (a)
$
121

 
$
139

 
$
215

 
$
280

____________
(a)
Amounts recorded in depreciation and amortization totaled $97 million and $116 million for the three months ended June 30, 2018 and 2017, respectively, and $182 million and $231 million for the six months ended June 30, 2018 and 2017, respectively.

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

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

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

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

•
Contractual service agreements – Our acquired contractual service agreements represent the estimated fair value of unfavorable contract obligations with respect to long-term plant maintenance agreements and are being amortized based on the expected usage of the service agreements over the contract terms.

Estimated Amortization of Identifiable Intangible Assets and Liabilities

As of June 30, 2018, the estimated aggregate amortization expense of identifiable intangible assets and liabilities for each of the next five fiscal years is as shown below.
Year
 
Estimated Amortization Expense
2018
 
$
401

2019
 
$
321

2020
 
$
245

2021
 
$
175

2022
 
$
109




14

7.
INCOME TAXES

Income Tax Expense (Benefit)

The calculation of our effective tax rate is as follows:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Income (loss) before income taxes
$
31

 
$
(34
)
 
$
(364
)
 
$
85

Income tax benefit (expense)
$
74

 
$
8

 
$
163

 
$
(33
)
Effective tax rate
(238.7
)%
 
23.5
%
 
44.8
%
 
38.8
%

For the three months ended June 30, 2018, the effective tax rate of (238.7)% related to our income tax benefit was lower than the U.S. federal statutory rate of 21% due primarily to (a) Vistra Energy's expanded state tax footprint requiring a one-time remeasurement of historical Vistra Energy deferred tax balances and (b) the difference in the forecasted effective tax rate and the statutory tax rate applied to mark-to-market unrealized gains, partially offset by an increase in state tax expense. For the six months ended June 30, 2018, the effective tax rate of 44.8% related to our income tax benefit was higher than the U.S. federal statutory rate of 21% due primarily to Vistra Energy's expanded state tax footprint requiring a one-time remeasurement of historical Vistra Energy deferred tax balances and an increase in state tax expense.

For the three months ended June 30, 2017, the effective tax rate of 23.5% 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 losses, offset by nondeductible TRA accretion and the Texas margin tax, net of federal benefit. For the six months ended June 30, 2017, the effective tax rate of 38.8% related to our income tax expense was higher than the U.S. federal statutory rate of 35% 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 gains.

Liability for Uncertain Tax Positions

Vistra Energy and its subsidiaries file income tax returns in U.S. federal and state jurisdictions and are expected to be subject to examinations by the IRS and other taxing authorities. Vistra Energy has limited operational history and filed its first federal tax return in October 2017. Vistra Energy is not currently under audit for any period. Uncertain tax positions totaling $41 million at June 30, 2018 arose in connection with the Merger and our assessment of the assumed liabilities is not complete as discussed in Note 2. We had no uncertain tax positions at December 31, 2017.


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 17).

During the three months ended June 30, 2018, we recorded an increase to the carrying value of the TRA obligation totaling approximately $46 million related to changes in the timing of estimated payments and new multistate tax impacts resulting from the Merger.


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 six months ended June 30, 2018 and 2017:
 
Six Months Ended June 30,
 
2018
 
2017
TRA obligation at the beginning of the period
$
357

 
$
596

Accretion expense
36

 
42

Changes in tax assumptions impacting timing of payments
46

 
—

TRA obligation at the end of the period
439

 
638

Less amounts due currently
(25
)
 
(16
)
Noncurrent TRA obligation at the end of the period
$
414

 
$
622


As of June 30, 2018, the estimated carrying value of the TRA obligation totaled $439 million, which represents the discounted amount of projected payments under the TRA. The primary driver of the change in the obligation for the three months ended June 30, 2018 is the Merger and the addition of estimated multistate tax benefit payments. The projected payments are based on certain assumptions, including but not limited to (a) the federal corporate income tax rate of 21%, (b) estimates of our taxable income in the current and future years and (c) additional states that Vistra Energy now operates in, its relevant tax rate and apportionment factor. Our taxable income takes into consideration the current federal tax code, various relevant state tax laws and reflects our current estimates of future results of the business. These assumptions are subject to change, and those changes could have a material impact on the carrying value of the TRA obligation. The aggregate amount of undiscounted federal and state payments under the TRA is estimated to be approximately $1.4 billion, with more than half of such amount expected to be attributable to the first 15 tax years following Emergence, and the final payment expected to be made approximately 40 years following Emergence (assuming that the TRA is not terminated earlier pursuant to its terms).

The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective interest method. Changes in the amount of this obligation resulting from changes to either the timing or amount of TRA payments are recognized in the period of change and measured using the discount rate inherent in the initial fair value of the obligation. During the three and six months ended June 30, 2018, the Impacts of Tax Receivable Agreement on the condensed statements of consolidated income (loss) totaled expense of $64 million and $82 million, respectively, which represents an increase to the carrying value of the TRA obligation discussed above and accretion expense totaling $18 million and $36 million, respectively. During the three and six months ended June 30, 2017, the Impacts of Tax Receivable Agreement on the condensed statements of consolidated income (loss) totaled $22 million and $42 million, respectively, which represents accretion expense for the period.



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9.
EARNINGS PER SHARE

Basic earnings per share available to common shareholders are based on the weighted average number of common shares outstanding during the period. Diluted earnings per share is calculated using the treasury stock method and includes the effect of all potential issuances of common shares under stock-based incentive compensation arrangements.
 
Three Months Ended June 30, 2018
 
Three Months Ended June 30, 2017
 
Net Income
 
Shares
 
Per Share Amount
 
Net Loss
 
Shares
 
Per Share Amount
Net income (loss) available for common stock — basic (a)
$
108

 
526,332,862

 
$
0.21

 
$
(26
)
 
427,587,401

 
$
(0.06
)
Dilutive securities:
 
 
 
 
 
 
 
 
 
 
 
Stock-based incentive compensation plan
—

 
7,453,962

 
0.01

 
—

 
—

 
—

Net income (loss) available for common stock — diluted
$
108

 
533,786,824

 
$
0.20

 
$
(26
)
 
427,587,401

 
$
(0.06
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2018
 
Six Months Ended June 30, 2017
 
Net Loss
 
Shares
 
Per Share Amount
 
Net Income
 
Shares
 
Per Share Amount
Net income (loss) available for common stock — basic (a)
$
(198
)
 
477,662,016

 
$
(0.41
)
 
$
52

 
427,585,381

 
$
0.12

Dilutive securities:
 
 
 
 
 
 
 
 
 
 
 
Stock-based incentive compensation plan
—

 
—

 
—

 
—

 
261,182

 
—

Net income (loss) available for common stock — diluted
$
(198
)
 
477,662,016

 
$
(0.41
)
 
$
52

 
427,846,563

 
$
0.12

____________
(a)
The minimum settlement amount of tangible equity units, or 15,056,260 shares, are considered to be outstanding and are included in the computation of basic net income (loss) per share (see Note 12).

Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the effect would have been antidilutive totaled 8,064,657 and 1,088,670 shares in the three months ended June 30, 2018 and 2017, respectively, and 18,392,470 and 692,860 shares in the six months ended June 30, 2018 and 2017, respectively.


17

10.
LONG-TERM DEBT

Amounts in the table below represent the categories of long-term debt obligations incurred by the Company.
 
June 30,
2018
 
December 31,
2017
Vistra Operations Credit Facilities
$
5,842

 
$
4,311

Senior Notes:
 
 
 
7.375% Senior Notes, due November 1, 2022
1,750

 
—

5.875% Senior Notes, due June 1, 2023
500

 
—

7.625% Senior Notes, due November 1, 2024
1,250

 
—

8.034% Senior Notes, due February 2, 2024
188

 
—

8.000% Senior Notes, due January 15, 2025
750

 
—

8.125% Senior Notes, due January 30, 2026
850

 
—

Total Senior Notes
5,288

 
—

Other:
 
 
 
7.000% Amortizing Notes, due July 1, 2019
38

 
—

Forward Capacity Agreements
241

 
—

Equipment Financing Agreements
138

 
—

Mandatorily redeemable subsidiary preferred stock (a)
70

 
70

8.82% Building Financing due semiannually through February 11, 2022 (b)
24

 
27

Total other long-term debt
511

 
97

Unamortized debt premiums, discounts and issuance costs
322

 
15

Total long-term debt including amounts due currently
11,963

 
4,423

Less amounts due currently
(156
)
 
(44
)
Total long-term debt less amounts due currently
$
11,807

 
$
4,379

____________
(a)
Shares of mandatorily redeemable preferred stock in PrefCo issued as part of the Plan of Reorganization. This subsidiary preferred stock is accounted for as a debt instrument under relevant accounting guidance.
(b)
Obligation related to a corporate office space capital lease. This obligation will be funded by amounts held in an escrow account that is reflected in other noncurrent assets in our condensed consolidated balance sheets.

Vistra Operations Credit Facilities

At June 30, 2018, the Vistra Operations Credit Facilities consisted of up to $8.342 billion in senior secured, first lien revolving credit commitments and outstanding term loans, consisting of revolving credit commitments of up to $2.5 billion, including a $2.3 billion letter of credit sub-facility (Revolving Credit Facility) and term loans of $2.807 billion (Term Loan B-1 Facility), $985 million (Term Loan B-2 Facility) and $2.050 billion (Term Loan B-3 Facility, and together with the Term Loan B-1 Facility and the Term Loan B-2 Facility, the Term Loan B Facility).

These amounts reflect an amendment to the Vistra Operations Credit Facilities in June 2018 whereby we incurred $2.050 billion of borrowings under the new Term Loan B-3 Facility and obtained $1.640 billion of incremental Revolving Credit Facility commitments. The letter of credit sub-facility was also increased by $1.585 billion. The maturity date of the Revolving Credit Facility was extended from August 4, 2021 to June 14, 2023. As discussed below, the proceeds from the Term Loan B-3 Facility were used to repay borrowings under the credit agreement that Vistra Energy assumed from Dynegy in connection with the Merger. Additionally, letter of credit term loans totaling $500 million (Term Loan C Facility) were repaid using $500 million of cash from collateral accounts used to backstop letters of credit. Fees and expenses related to the amendment to the Vistra Operations Credit Facilities totaled $45 million in the three months ended June 30, 2018, of which $34 million was recorded as interest expense and other charges on the condensed statements of consolidated income (loss) and $11 million was capitalized as a reduction in the carrying amount of the debt.


18

The Vistra Operations Credit Facilities and related available capacity at June 30, 2018 are presented below.
 
 
 
 
June 30, 2018
Vistra Operations Credit Facilities
 
Maturity Date
 
Facility
Limit
 
Cash
Borrowings
 
Available
Capacity
Revolving Credit Facility (a)
 
June 14, 2023
 
$
2,500

 
$
—

 
$
1,065

Term Loan B-1 Facility (b)
 
August 4, 2023
 
2,807

 
2,807

 
—

Term Loan B-2 Facility (b)
 
December 14, 2023
 
985

 
985

 
—

Term Loan B-3 Facility (b)
 
December 31, 2025
 
2,050

 
2,050

 
—

Total Vistra Operations Credit Facilities
 
 
 
$
8,342

 
$
5,842

 
$
1,065

___________
(a)
Facility to be used for general corporate purposes. Facility includes a $2.3 billion letter of credit sub-facility, of which $1.435 billion of letters of credit were outstanding at June 30, 2018 and which reduce our available capacity.
(b)
Cash borrowings under the Term Loan B Facility reflect required scheduled quarterly payment in annual amount equal to 1% of the original principal amount with the balance paid at maturity. Principal amounts paid cannot be reborrowed.

In February and June 2018, certain pricing terms for the Vistra Operations Credit Facilities were amended. We accounted for these transactions as a modification of debt. At June 30, 2018, cash borrowings under the Revolving Credit Facility would bear interest based on applicable LIBOR rates, plus a fixed spread of 1.75%, and there were no outstanding borrowings. Letters of credit issued under the Revolving Credit Facility bear interest of 1.75%. Amounts borrowed under the Term Loan B-1 Facility bear interest based on applicable LIBOR rates plus a fixed spread of 2.00%. Amounts borrowed under the Term Loan B-2 Facility bear interest based on applicable LIBOR rates plus a fixed spread of 2.25%. Amounts borrowed under the Term Loan B-3 Facility bear interest based on applicable LIBOR rates plus a fixed spread of 2.00%. At June 30, 2018, the weighted average interest rates before taking into consideration interest rate swaps on outstanding borrowings were 4.09%, 4.34% and 4.07% under the Term Loan B-1, B-2 and B-3 Facilities, respectively. The Vistra Operations Credit Facilities also provide for certain additional fees payable to the agents and lenders, including fronting fees with respect to outstanding letters of credit and availability fees payable with respect to any unused portion of the Revolving Credit Facility.

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

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

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

The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties, material breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against Vistra Operations. Solely with respect to the Revolving Credit Facility, and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $300 million) exceed 30% of the revolving commitments), the agreement includes a covenant that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first lien debt compared to an EBITDA calculation defined under the terms of the facilities, not to exceed 4.25 to 1.00. As of June 30, 2018, we were in compliance with this financial covenant. Upon the existence of an event of default, the Vistra Operations Credit Facilities provide that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.


19

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

In June 2018, we completed the novation of $1.959 billion of Vistra Energy (legacy Dynegy) interest rate swaps to Vistra Operations Company LLC (Vistra Operations). In June 2018, $238 million of these interest rate swaps expired. The remaining interest rate swaps expire between March 2019 and February 2024.

The interest rate swaps effectively fix the interest rates between 4.13% and 4.38% on $4.721 billion of our variable rate debt. The interest rate swaps that become effective in July 2023 and expire in July 2026 effectively fix the interest rates between 4.97% and 5.04% on $3.0 billion of our variable rate debt during the period. The interest rate swaps are secured by a first lien secured interest on a pari-passu basis with the Vistra Operations Credit Facilities.

Vistra Energy (legacy Dynegy) Credit Agreement

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

Senior Notes

On the Merger Date, Vistra Energy assumed $6.138 billion principal amount of Dynegy's senior notes. In May 2018, $850 million of outstanding 6.75% Senior Notes due 2019 were redeemed at a redemption price of 101.688% of the aggregate principal amount, plus accrued and unpaid interest to but not including the date of redemption. In June 2018, each of the Company's subsidiaries that guaranteed the Vistra Operations Credit Facilities (and did not already guarantee the senior notes) provided a guarantee on the senior notes that remained outstanding.

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

Amortizing Notes

On the Merger Date, Vistra Energy assumed the obligations of Dynegy's senior amortizing note (Amortizing Notes) maturing on July 1, 2019. The Amortizing Notes were issued in connection with the issuance of the tangible equity units (TEUs) by Dynegy (see Note 12). Each installment payment per Amortizing Note will be paid in cash and will constitute a partial repayment of principal and a payment of interest, computed at an annual rate of 7.00%. Interest will be calculated on the basis of a 360-day year consisting of twelve 30-day months. Payments will be applied first to the interest due and payable and then to the reduction of the unpaid principal amount, allocated as set forth in the indenture.


20

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

Forward Capacity Agreements

On the Merger Date, the Company assumed the obligation of Dynegy's agreements under which a portion of the PJM capacity that cleared for Planning Years 2018-2019, 2019-2020 and 2020-2021 was sold to a financial institution (Forward Capacity Agreements). The buyer in this transaction will receive capacity payments from PJM during the Planning Years 2018-2019, 2019-2020 and 2020-2021 in the amounts of $10 million, $121 million and $110 million, respectively. We will continue to be subject to the performance obligations as well as any associated performance penalties and bonus payments for those planning years. As a result, this transaction is accounted for as a debt issuance of $241 million with an implied interest rate of 4.90%.

Equipment Financing Agreements

On the Merger Date, the Company assumed Dynegy's Equipment Financing Agreements. Under certain of our contractual service agreements in which we receive maintenance and capital improvements for our gas-fueled generation fleet, we have obtained parts and equipment intended to increase the output, efficiency and availability of our generation units. We have financed these parts and equipment under agreements with maturities ranging from 2019 to 2026. The portion of future payments attributable to principal will be classified as cash outflows from financing activities, and the portion of future payments attributable to interest will be classified as cash outflows from operating activities in our condensed statements of consolidated cash flows.

Maturities

Long-term debt maturities at June 30, 2018 are as follows:
 
June 30, 2018
Remainder of 2018
$
85

2019
182

2020
204

2021
130

2022
1,824

Thereafter
9,216

Unamortized premiums, discounts and debt issuance costs
322

Total long-term debt, including amounts due currently
$
11,963



21


11.
COMMITMENTS AND CONTINGENCIES

Guarantees

We have entered into contracts, including the assumed Dynegy senior notes described above, that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. As of June 30, 2018, there are no material outstanding claims related to our guarantee obligations, and we do not anticipate we will be required to make any material payments under these guarantees.

Letters of Credit

At June 30, 2018, we had outstanding letters of credit under the Vistra Operations Credit Facilities totaling $1.435 billion as follows:

•
$1.221 billion to support commodity risk management collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and collateral postings with ISOs;
•
$51 million to support executory contracts and insurance agreements;
•
$55 million to support our REP financial requirements with the PUCT, and
•
$108 million for other credit support requirements.

Litigation

Gas Index Pricing Litigation — We, through our subsidiaries, and other energy companies are named as defendants in several lawsuits claiming damages resulting from alleged price manipulation through false reporting of natural gas prices to various index publications, wash trading and churn trading from 2000-2002. The cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices in three states (Kansas, Missouri and Wisconsin) during the relevant time period and seek damages under the respective state antitrust statutes. Four of the cases are putative class actions and one case, Reorganized FLI (nka J.P. Morgan Trust Co., National Assn.) v. Oneok Inc., et al., is an individual action on behalf of Farmland Industries, Inc. (Farmland), with Farmland seeking full consideration damages (i.e., the full amount it paid for natural gas purchases during the relevant timeframe). The cases are consolidated in a multi-district litigation proceeding pending in the U. S. District Court for Nevada. In March 2017, the court denied the class plaintiffs' motions to certify class actions in each of the states, which decision now is on an interlocutory appeal to U.S Court of Appeals for the Ninth Circuit (Ninth Circuit Court); the appeal is fully briefed and was argued in July 2018. As for the Farmland matter, in March 2018, the Ninth Circuit Court reversed a summary judgment in favor of the defendants and it shortly will be remanded for further discovery and other pretrial proceedings. While we cannot predict the outcome of these legal proceedings, or estimate a range of costs, they could have a material impact on our results of operations, liquidity or financial condition.

Advatech Dispute — In September 2016, , Illinois Power Generating Company (Genco), terminated its Second Amended and Restated Newton Flue Gas Desulfurization System Engineering, Procurement, Construction and Commissioning Services Contract dated as of December 15, 2014 with Advatech, LLC (Advatech). Advatech issued Genco its final invoice in September 2016 totaling $81 million. Genco contested the invoice in October 2016 and believes the proper amount is less than $1 million. In October 2016, Advatech initiated the dispute resolution process under the contract and filed for arbitration in March 2017. Settlement discussions required under the dispute resolution process have been unsuccessful. The arbitration hearing is scheduled for October 2018. We dispute the allegations and will defend our position vigorously. While we cannot predict the outcome of this legal proceeding, or estimate a range of costs, it could have a material impact on our results of operations, liquidity or financial condition.

Wood River Rail Dispute — In November 2017, Dynegy Midwest Generation, LLC (DMG) received notification that BNSF Railway Company and Norfolk Southern Railway Company were initiating dispute resolution related to DMG's suspension of its Wood River Rail Transportation Agreement with the railroads. Settlement discussions required under the dispute resolution process have been unsuccessful. In March 2018, BNSF Railway Company and Norfolk Southern Railway Company filed a demand for arbitration. We dispute the railroads' allegations and will defend our position vigorously. While we cannot predict the outcome of this legal proceeding, or estimate a range of costs, it could have a material impact on our results of operations, liquidity or financial condition.


22

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 as a respondent. 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 and dismiss the individual claims with prejudice, and they dismissed without prejudice claims of the putative class following the stockholder vote on March 2, 2018. These cases have been dismissed.

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. The D.C. Circuit Court granted a renewed 60-day abeyance of the case on June 26, 2018, which will expire in August 2018.

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 (NOX) 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 NOX emission budgets, in November 2016, the EPA proposed to withdraw the CSAPR Federal Implementation Plan (FIP) addressing SO2 and annual NOX 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 NOX limits, but remain subject to the CSAPR's ozone season NOX requirements. In October 2016, the EPA issued a CSAPR update, which revised the ozone season NOX limits for 22 eastern states, including Texas. Various parties (including Luminant) filed petitions for review in the D.C. Circuit Court. The case has been fully briefed and is scheduled for oral argument in October 2018. While we cannot predict the outcome of future proceedings related to the CSAPR, based upon our current operating plans, including the retirements of our Monticello, Big Brown and Sandow 4 plants (see Note 4), 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.


23

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's 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.

In March 2016, Luminant and a number of other parties, including the State of Texas, filed petitions for review in the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court) challenging the FIP's Texas requirements. 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 retirements of our Monticello, Big Brown and Sandow 4 plants should have a favorable impact on this rulemaking and litigation. While we cannot predict the outcome of the rulemaking and legal proceedings, or estimate a range of reasonably possible costs, the result could have a material impact on our results of operations, liquidity or financial condition.

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 retirements of our Monticello, Big Brown and Sandow 4 plants will enhance our ability to comply with this BART rule for SO2. For NOX, the rule adopts the CSAPR's ozone program as BART and for particulate matter, the rule approves Texas's SIP that determines that no electric generating units are subject to BART for particulate matter. The National Parks Conservation Association, the Sierra Club and the Environmental Defense Fund filed a petition challenging the rule in the Fifth Circuit Court as well as a petition for reconsideration filed with the EPA. Luminant intervened on behalf of the EPA in the Fifth Circuit Court action. In March 2018, the Fifth Circuit Court granted a joint motion filed by the EPA and the environmental groups involved to abate the Fifth Circuit Court proceedings until the EPA has taken action on the reconsideration petition and concludes the reconsideration process. 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.


24

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 could have a material impact on our results of operations, liquidity or financial condition.

SO2 Designations for Texas

In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Big Brown, Monticello and Martin Lake generation plants. The final designations require Texas to develop nonattainment plans for these areas. In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court. Subsequently, in October 2017, the Fifth Circuit Court granted the EPA's motion to hold the case in abeyance in light of the EPA's representation that it intended to revisit the nonattainment rule. In December 2017, the TCEQ submitted a petition for reconsideration to the EPA. In addition, with respect to Monticello and Big Brown, the retirement of those plants should favorably impact our legal challenge to the nonattainment designations in that the nonattainment designation for Freestone County and Titus County are based solely on the Sierra Club modeling, which we dispute, of alleged SO2 emissions from Monticello and Big Brown. Regardless, considering these retirements, the nonattainment designation for those counties are no longer supported. While we cannot predict the outcome of this matter, or estimate a range of reasonably possible costs, the result could have a material impact on our results of operations, liquidity or financial condition.

Effluent Limitation Guidelines (ELGs)

In November 2015, the EPA revised the ELGs for steam electric generating facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, flue desulfurization, fly ash, bottom ash and flue gas mercury control. Various parties filed petitions for review of the ELG rule, and the petitions were consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions requesting reconsideration of the ELG final rule issued in 2015 and administratively stayed the ELG rule's compliance date deadlines pending ongoing judicial review of the rule. The legal challenges pertaining to bottom ash transport water, flue gas desulfurization wastewater and gasification wastewater have been suspended while the EPA reconsiders the rules.

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

Given the EPA's decision to reconsider the bottom ash transport water and flue gas desulfurization wastewater provisions of the ELG rule, the rule postponing the ELG rule's earliest compliance dates for those provisions, and the intertwined relationship of the ELG rule with the Coal Combustion Residuals rule discussed below, which is also being reconsidered by the EPA, as well as pending legal challenges concerning both rules, substantial uncertainty exists regarding our projected capital expenditures for ELG compliance, including the timing of such expenditures. While we cannot predict the outcome of this matter, or estimate a range of costs, it could have a material impact on our results of operations, liquidity or financial condition.

New Source Review and CAA Matters

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


25

In August 2012, the EPA issued a Notice of Violation (NOV) alleging that projects performed in 1997, 2006 and 2007 at the Newton facility violated Prevention of Significant Deterioration (PSD), Title V permitting and other CAA requirements. The NOV remains unresolved. We believe our defenses to the allegations described in the NOV are meritorious. A decision by the U.S. Court of Appeals for the Seventh Circuit (Seventh Circuit Court) in 2013 held that similar PSD claims older than five years were barred by the statute of limitations. That determination is in line with the majority of other circuit court decisions that have held that PSD claims arise at the time of the projects at issue are not continuing for statute of limitations purposes. This Seventh Circuit Court decision may provide an additional defense to the allegations in the Newton facility NOV. In September 2016, the Newton Unit 2 was retired. While we cannot predict the outcome of this matter, or estimate a range of costs, it could have a material impact on our results of operations, liquidity or financial condition.

In August 2013, the U.S. Department of Justice (DOJ), acting as the attorneys for the EPA, filed a civil enforcement lawsuit against Luminant in federal district court in Dallas, alleging violations of the CAA, including its New Source Review standards, at our Big Brown and Martin Lake generation facilities. In August 2015, the district court granted Luminant's motion to dismiss seven of the nine claims asserted by the EPA in the lawsuit.

In January 2017, the EPA dismissed its two remaining claims with prejudice and the district court entered final judgment in Luminant's favor. In March 2017, the EPA and the Sierra Club appealed the final judgment to the Fifth Circuit Court. After the parties filed their respective briefs in the Fifth Circuit Court, the appeal was argued before the Fifth Circuit Court in March 2018. 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 retirement of the Big Brown plant should have a favorable impact on this litigation. We cannot predict the outcome of these proceedings, including the financial effects, if any.

Zimmer NOVs — In December 2014, the EPA issued an NOV alleging violation of opacity standards at the Zimmer facility. The EPA previously had issued NOVs to Zimmer in 2008 and 2010 alleging violations of the CAA, the Ohio State Implementation Plan and the station's air permits including standards applicable to opacity, sulfur dioxide, sulfuric acid mist and heat input. The NOVs remain unresolved. We are unable to predict the outcome of these matters.

Killen and Stuart NOVs — The EPA issued NOVs in December 2014 for Killen and Stuart, and in February 2017 for Stuart, alleging violations of opacity standards. In May and June 2017, we received two letters from the Sierra Club providing notice of its intent to sue various Dynegy entities and the owner and operator of the Killen and Stuart facilities, respectively, alleging violations of opacity standards under the CAA. The Dayton Power and Light Company, the operator of Killen and Stuart, is expected to act on behalf of itself and the co-owners with respect to these matters. We are unable to predict the outcome of these claims or estimate a range of costs. Both Killen and Stuart ceased operations in May 2018 as previously approved and announced by PJM.

Edwards CAA Citizen Suit — In April 2013, environmental groups filed a CAA citizen suit in the U.S. District Court for the Central District of Illinois alleging violations of opacity and particulate matter limits at our MISO segment's Edwards facility. In August 2016, the District Court granted the plaintiffs’ motion for summary judgment on certain liability issues. We filed a motion seeking interlocutory appeal of the court’s summary judgment ruling. In February 2017, the appellate court denied our motion for interlocutory appeal. The District Court has scheduled the remedy phase trial for March 2019. We dispute the allegations and will defend the case vigorously. We are unable to predict the outcome of these matters.

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


26

Coal Combustion Residuals/Groundwater

On July 30, 2018, the EPA published a final rule that amends certain provisions of the Coal Combustion Residuals (CCR) rule that the agency issued in 2015. The 2018 revisions extend closure deadlines to October 31, 2020, related to the aquifer location restriction and groundwater monitoring requirements. The 2018 revisions also (1) establish groundwater protection standards for cobalt, lithium, molybdenum and lead (2) allow authorized state programs to waive groundwater monitoring requirements when there is a demonstration of no potential for contaminant migration, and (3) allow the permitting authority to issue certifications in lieu of a qualified professional engineer. The 2018 revisions will become effective on August 29, 2018, and we are currently evaluating the impact on our CCR facilities. While we cannot predict the impacts of these rule revisions (including whether and if so how the states in which we operate will utilize the authority delegated to the states through the revisions), or estimate a range of reasonably possible costs related to these revisions, the changes that result from these revisions could have a material impact on our results of operations, liquidity or financial condition.

MISO Segment — In 2012, the Illinois EPA (IEPA) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities' CCR surface impoundments. In 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east, and west fly ash CCR surface impoundments. We are working towards implementation of those closure plans.

At our retired Vermilion facility, which is not subject to the federal CCR rule, we submitted proposed corrective action plans involving closure of two CCR surface impoundments (i.e., the old east and the north impoundments) to the IEPA in 2012, with revised plans submitted in 2014. In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options. By letter dated January 31, 2018, Prairie Rivers Network provided 60-day notice of its intent to sue our subsidiary Dynegy Midwest Generation, LLC under the federal Clean Water Act for alleged unauthorized discharges from the surface impoundments at our Vermilion facility and alleged related violations of the facility's National Pollutant Discharge Elimination System permit. Prairie Rivers Network filed a citizen suit in May 2018, alleging violations of the Clean Water Act for alleged unauthorized discharges. We dispute the allegations and will vigorously defend our position.

In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities' CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the federal CCR rule. In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface impoundments at our retired Vermilion facility.

If remediation measures concerning groundwater are necessary at any of our coal-fired facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations, and cash flows. At this time, in part because of the revisions to the CCR rule that the EPA published on July 30, 2018, we cannot reasonably estimate the costs, or range of costs, of groundwater remediation, if any, that ultimately may be required. CCR surface impoundment and landfill closure costs, as determined by our operations and environmental services teams, are reflected in our AROs.

MISO 2015-2016 Planning Resource Auction

In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 Planning Resource Auction (PRA) conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc., the Illinois Attorney General and Southwestern Electric Cooperative, Inc., have challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO PRA structure going forward. Complainants have also alleged that Dynegy could have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the 2015-2016 PRA. The Independent Market Monitor for MISO (MISO IMM), which was responsible for monitoring the MISO 2015-2016 PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the proposed remedies. We filed our Answer to these complaints and believe that we complied fully with the terms of the MISO tariff in connection with the 2015-2016 PRA, disputed the allegations, and will defend our actions vigorously. In addition, the Illinois Industrial Energy Consumers filed a complaint at FERC against MISO on June 30, 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this complaint.


27

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

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

Other Matters

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


12.
EQUITY

Equity Issuances

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

Share Repurchase Program

In June 2018, we announced that our board of directors had authorized a share repurchase program (Program) under which up to $500 million of our outstanding common stock may be repurchased. The Program was effective as of June 13, 2018, and we intend to implement the Program opportunistically from time to time through the end of 2019. Shares of the Company's common stock may be repurchased in open market transactions at prevailing market prices, in privately negotiated transactions, pursuant to plans complying with the Securities Exchange Act of 1934, as amended, or by other means in accordance with federal securities laws. The actual timing, number and value of shares repurchased under the Program will be determined at our discretion and will depend on a number of factors, including the market price of our stock, general market and economic conditions, applicable legal requirements and compliance with the terms of our debt agreements and the Tax Matters Agreement. Through June 30, 2018, 3,152,073 shares of our common stock had been repurchased for $75 million (including related fees and expenses) at an average price per share of common stock of $23.81. At June 30, 2018, $425 million was available for additional repurchases under the Program.

Dividends and Dividend Restrictions

Vistra Energy did not declare or pay any dividends during the six months ended June 30, 2018 and 2017. The agreement governing the Credit Facilities Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of June 30, 2018, Vistra Operations can distribute approximately $10.4 billion to Vistra Energy Corp. (the Parent) under the Credit Facilities Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to the Parent was partially reduced by distributions made by Vistra Operations to the Parent during the year ended December 31, 2017 of approximately $1.1 billion. In both the three and six months ended June 30, 2018, distributions totaling $2.028 billion were made by Vistra Operations to the Parent. 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 June 30, 2018, the maximum amount of restricted net assets of Vistra Operations that may not be distributed to the Parent totaled approximately $8.2 billion.


28

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

Warrants

At the Merger Date, the Company entered into an agreement whereby holders of each outstanding warrant previously issued by Dynegy will be entitled to receive, upon exercise, the equity securities to which the holder would have been entitled to receive of Dynegy common stock converted into shares of Vistra Energy common stock at the Exchange Ratio. As of June 30, 2018, nine million warrants expiring in 2024 with an exercise price of $35.00 were outstanding, each of which can be redeemed for 0.652 share of Vistra Energy common stock. The warrants are recorded as equity in our condensed consolidated balance sheet.

Tangible Equity Units

At the Merger Date, the Company assumed the obligations of Dynegy's 4,600,000 7.00% tangible equity units, each with a stated amount of $100.00 and each comprised of (i) a prepaid stock purchase contract that will deliver to the holder, not later than July 1, 2019, unless earlier redeemed or settled, not more than 4.0421 shares of Vistra Energy common stock and not less than 3.2731 shares of Vistra Energy common stock per contract based upon the applicable fixed settlement rate in the contract and (ii) a senior amortizing note with an outstanding principal amount of $45 million at the Merger Date that pays an equal quarterly cash installment of $1.75 per amortizing note (see Note 10). 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.

Shareholder's Equity

The following table presents the changes to shareholder's equity for the six months ended June 30, 2018:
 
Common
Stock (a)
 
Additional Paid-in Capital
 
Retained Earnings (Deficit)
 
Accumulated Other Comprehensive Income (Loss)
 
Noncontrolling Interest
 
Total Equity
Balance at December 31, 2017
$
4

 
$
7,765

 
$
(1,410
)
 
$
(17
)
 
$
—

 
$
6,342

Stock issued in connection with the Merger
1

 
1,891

 
—

 
—

 
—

 
1,892

Net loss
—

 
—

 
(198
)
 
—

 
—

 
(198
)
Adoption of accounting standard (Note 1)
—

 
—

 
17

 
—

 
—

 
17

Treasury stock
—

 
(75
)
 
—

 
—

 
—

 
(75
)
Effects of stock-based incentive compensation plans
—

 
63

 
—

 
—

 
—

 
63

Tangible equity units acquired
—

 
369

 
—

 
—

 
—

 
369

Warrants acquired
—

 
2

 
—

 
—

 
—

 
2

Change in unrecognized losses related to pension and OPEB plans
—

 
—

 
—

 
1

 
—

 
1

Investment by noncontrolling interest
—

 
—

 
—

 
—

 
7

 
7

Balance at June 30, 2018
$
5

 
$
10,015

 
$
(1,591
)
 
$
(16
)
 
$
7

 
$
8,420

________________
(a)
Authorized shares totaled 1,800,000,000 at June 30, 2018. Outstanding shares totaled 521,214,879 and 428,398,802 at June 30, 2018 and December 31, 2017, respectively.


29

The following table presents the changes to shareholder's equity for the six months ended June 30, 2017:
 
Common
Stock (a)
 
Additional Paid-in Capital
 
Retained Earnings (Deficit)
 
Accumulated Other Comprehensive Income (Loss)
 
Total Shareholders' Equity
Balance at December 31, 2016
$
4

 
$
7,742

 
$
(1,155
)
 
$
6

 
$
6,597

Net income
—

 
—

 
52

 
—

 
52

Effects of stock-based incentive compensation plans
—

 
8

 
—

 
—

 
8

Other
—

 
—

 
1

 
—

 
1

Balance at June 30, 2017
$
4

 
$
7,750

 
$
(1,102
)
 
$
6

 
$
6,658

________________
(a)
Authorized shares totaled 1,800,000,000 at June 30, 2017. Outstanding shares totaled 427,587,401 and 427,580,232 at June 30, 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.

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.


30

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:
June 30, 2018
 
Level 1
 
Level 2
 
Level 3 (a)
 
Reclassification (b)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Commodity contracts
$
156

 
$
325

 
$
164

 
$
48

 
$
693

Interest rate swaps
—

 
149

 
—

 
—

 
149

Nuclear decommissioning trust –
equity securities (c)
480

 
—

 
—

 
—

 
480

Nuclear decommissioning trust –
debt securities (c)
—

 
429

 
—

 
—

 
429

Sub-total
$
636

 
$
903

 
$
164

 
$
48

 
1,751

Assets measured at net asset value (d):
 
 
 
 
 
 
 
 
 
Nuclear decommissioning trust –
equity securities (c)
 
 
 
 
 
 
 
 
298

Total assets
 
 
 
 
 
 
 
 
$
2,049

Liabilities:
 
 
 
 
 
 
 
 
 
Commodity contracts
$
232

 
$
694

 
$
386

 
$
48

 
$
1,360

Interest rate swaps
—

 
18

 
—

 
—

 
18

Total liabilities
$
232

 
$
712

 
$
386

 
$
48

 
$
1,378


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 19.

31

(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, fuel oil, uranium, coal and emissions agreements and include financial instruments entered into for hedging purposes as well as physical contracts that have not been designated as normal purchases or sales. Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest to fixed rates. See Note 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.

The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations at June 30, 2018 and December 31, 2017:
June 30, 2018
 
 
Fair Value
 
 
 
 
 
 
Contract Type (a)
 
Assets
 
Liabilities
 
Total
 
Valuation Technique
 
Significant Unobservable Input
 
Range (b)
Electricity purchases and sales
 
$
27

 
$
(146
)
 
$
(119
)
 
Valuation Model
 
Hourly price curve shape (c)
 
$0 to $75/ MWh
 
 
 
 
 
 
 
 
 
 
Illiquid delivery periods for ERCOT hub power prices and heat rates (d)
 
$20 to $120/ MWh
Electricity and weather options
 
9

 
(177
)
 
(168
)
 
Option Pricing Model
 
Gas to power correlation (e)
 
15% to 100%
 
 
 
 
 
 
 
 
 
 
Power volatility (e)
 
5% to 375%
Financial transmission rights
 
85

 
(21
)
 
64

 
Market Approach (f)
 
Illiquid price differences between settlement points (g)
 
$0 to $30/ MWh
Other (h)
 
43

 
(42
)
 
1

 
 
 
 
 
 
Total
 
$
164

 
$
(386
)
 
$
(222
)
 
 
 
 
 
 

December 31, 2017
 
 
Fair Value
 
 
 
 
 
 
Contract Type (a)
 
Assets
 
Liabilities
 
Total
 
Valuation Technique
 
Significant Unobservable Input
 
Range (b)
Electricity purchases and sales
 
$
12

 
$
(33
)
 
$
(21
)
 
Valuation Model
 
Hourly price curve shape (c)
 
$0 to $40/ MWh
 
 
 
 
 
 
 
 
 
 
Illiquid delivery periods for ERCOT hub power prices and heat rates (d)
 
$20 to $70/ MWh
Electricity and weather options
 
10

 
(91
)
 
(81
)
 
Option Pricing Model
 
Gas to power correlation (e)
 
30% to 100%
 
 
 
 
 
 
 
 
 
 
Power volatility (e)
 
5% to 180%
Financial transmission rights
 
45

 
(4
)
 
41

 
Market Approach (f)
 
Illiquid price differences between settlement points (g)
 
$0 to $15/ MWh
Other (h)
 
8

 
—

 
8

 
 
 
 
 
 
Total
 
$
75

 
$
(128
)
 
$
(53
)
 
 
 
 
 
 
____________

32

(a)
Electricity purchase and sales contracts include power and heat rate positions in ERCOT, PJM, NYISO, ISO-NE and MISO regions. The forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points are referred to as congestion revenue rights contracts in ERCOT and financial transmission rights in PJM, NYISO, ISO-NE and MISO regions. Electricity options consist of physical electricity options and spread options.
(b)
The range of the inputs may be influenced by factors such as time of day, delivery period, season and location.
(c)
Primarily based on the historical range of forward average hourly ERCOT North Hub prices.
(d)
Primarily based on historical forward ERCOT power price and heat rate variability.
(e)
Based on historical forward correlation and volatility within ERCOT.
(f)
While we use the market approach, there is insufficient market data to consider the valuation liquid.
(g)
Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones.
(h)
Other includes contracts for natural gas, coal options and emissions.

There were no transfers between Level 1 and Level 2 of the fair value hierarchy for the three and six months ended June 30, 2018 and 2017. See the table below for discussion of transfers between Level 2 and Level 3 for the three and six months ended June 30, 2018 and 2017.

The following table presents the changes in fair value of the Level 3 assets and liabilities for the three and six months ended June 30, 2018 and 2017.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Net asset (liability) balance at beginning of period
$
(224
)
 
$
107

 
$
(53
)
 
$
83

Total unrealized valuation gains (losses)
(18
)
 
(32
)
 
(230
)
 
8

Purchases, issuances and settlements (a):
 
 
 
 
 
 
 
Purchases
29

 
26

 
58

 
35

Issuances
(4
)
 
(3
)
 
(7
)
 
(14
)
Settlements
29

 
(23
)
 
45

 
(42
)
Transfers into Level 3 (b)
2

 
—

 
1

 
3

Transfers out of Level 3 (b)
1

 
—

 
1

 
2

Net liabilities assumed in connection with the Merger (Note 2)
(37
)
 
—

 
(37
)
 
—

Net change (c)
2

 
(32
)
 
(169
)
 
(8
)
Net asset (liability) balance at end of period
$
(222
)
 
$
75

 
$
(222
)
 
$
75

Unrealized valuation gains (losses) relating to instruments held at end of period
$
(17
)
 
$
(31
)
 
$
(226
)
 
$
6

____________
(a)
Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received.
(b)
Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2.
(c)
Activity excludes change in fair value in the month positions settle. Substantially all changes in value of commodity contracts (excluding net liabilities assumed in connection with the Merger) are reported as operating revenues in our condensed statements of consolidated income (loss).


33


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, uranium and emission derivative instruments for fuel hedging and other purposes. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy marketing companies. Unrealized gains and losses arising from changes in the fair value of derivative instruments as well as realized gains and losses upon settlement of the instruments are reported in our condensed statements of consolidated income (loss) in operating revenues and fuel, purchased power costs and delivery fees.

Interest Rate Swaps — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate interest rates to fixed rates, thereby hedging future interest costs and related cash flows. Unrealized gains and losses arising from changes in the fair value of the swaps as well as realized gains and losses upon settlement of the swaps are reported in our condensed statements of consolidated income (loss) in interest expense and related charges.

Financial Statement Effects of Derivatives

Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of derivative contractual assets and liabilities as reported in our condensed consolidated balance sheets at June 30, 2018 and December 31, 2017. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract.
 
June 30, 2018
 
Derivative Assets
 
Derivative Liabilities
 
 
 
Commodity Contracts
 
Interest Rate Swaps
 
Commodity Contracts
 
Interest Rate Swaps
 
Total
Current assets
$
575

 
$
15

 
$
8

 
$
—

 
$
598

Noncurrent assets
100

 
134

 
10

 
—

 
244

Current liabilities
(2
)
 
—

 
(877
)
 
(4
)
 
(883
)
Noncurrent liabilities
(28
)
 
—

 
(453
)
 
(14
)
 
(495
)
Net assets (liabilities)
$
645

 
$
149

 
$
(1,312
)
 
$
(18
)
 
$
(536
)

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


34

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 June 30,
 
Six Months Ended June 30,
2018
 
2017
 
2018
 
2017
Commodity contracts (Operating revenues)
$
69

 
$
(8
)
 
$
(376
)
 
$
166

Commodity contracts (Fuel, purchased power costs and delivery fees)
13

 
(1
)
 
12

 
(5
)
Interest rate swaps (Interest expense and related charges)
22

 
(23
)
 
78

 
(20
)
Net gain (loss)
$
104

 
$
(32
)
 
$
(286
)
 
$
141


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:
 
 
June 30, 2018
 
December 31, 2017
 
 
Derivative Assets
and Liabilities
 
Offsetting Instruments (a)
 
Cash Collateral (Received) Pledged (b)
 
Net Amounts
 
Derivative Assets
and Liabilities
 
Offsetting Instruments (a)
 
Cash Collateral (Received) Pledged (b)
 
Net Amounts
Derivative assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
$
645

 
$
(462
)
 
$
(1
)
 
$
182

 
$
220

 
$
(113
)
 
$
(1
)
 
$
106

Interest rate swaps
 
149

 
(15
)
 
—

 
134

 
18

 
—

 
—

 
18

Total derivative assets
 
794

 
(477
)
 
(1
)
 
316

 
238

 
(113
)
 
(1
)
 
124

Derivative liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts
 
(1,312
)
 
462

 
95

 
(755
)
 
(316
)
 
113

 
1

 
(202
)
Interest rate swaps
 
(18
)
 
15

 
—

 
(3
)
 
—

 
—

 
—

 
—

Total derivative liabilities
 
(1,330
)
 
477

 
95

 
(758
)
 
(316
)
 
113

 
1

 
(202
)
Net amounts
 
$
(536
)
 
$
—

 
$
94

 
$
(442
)
 
$
(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.


35

Derivative Volumes

The following table presents the gross notional amounts of derivative volumes at June 30, 2018 and December 31, 2017:
 
 
June 30, 2018
 
December 31, 2017
 
 
Derivative type
 
Notional Volume
 
Unit of Measure
Natural gas (a)
 
4,214

 
1,259

 
Million MMBtu
Electricity
 
237,133

 
114,129

 
GWh
Financial Transmission Rights (b)
 
192,072

 
110,913

 
GWh
Coal
 
51

 
2

 
Million U.S. tons
Fuel oil
 
14

 
5

 
Million gallons
Uranium
 
75

 
325

 
Thousand pounds
Emissions
 
9

 
—

 
Million tons
Interest rate swaps – floating/fixed (c)
 
$
7,721

 
$
3,000

 
Million U.S. dollars
____________
(a)
Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas transactions.
(b)
Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within ISOs.
(c)
Includes notional amounts of interest rate swaps with maturity dates through July 2026.

Credit Risk-Related Contingent Features of Derivatives

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

The following table presents the commodity derivative liabilities subject to credit risk-related contingent features that are not fully collateralized:
 
June 30,
2018
 
December 31,
2017
Fair value of derivative contract liabilities (a)
$
(862
)
 
$
(204
)
Offsetting fair value under netting arrangements (b)
287

 
103

Cash collateral and letters of credit
262

 
41

Liquidity exposure
$
(313
)
 
$
(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 June 30, 2018, total credit risk exposure to all counterparties related to derivative contracts totaled $1.056 billion (including associated accounts receivable). The net exposure to those counterparties totaled $464 million at June 30, 2018 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $68 million. At June 30, 2018, the credit risk exposure to the banking and financial sector represented 42% of the total credit risk exposure and 32% of the net exposure.


36

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.
PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFIT (OPEB) PLANS

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

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

Components of Net Benefit Cost

For the three and six months ended June 30, 2018, net periodic benefit costs consisted of the following:
 
Pension Benefits
 
OPEB Benefits
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
 
2018
 
2017
Service cost
$
4

 
$
1

 
$
5

 
$
3

 
$
1

 
$
1

 
$
1

 
$
1

Other costs
—

 
—

 
—

 
—

 
1

 
1

 
2

 
2

Net periodic benefit cost
$
4

 
$
1

 
$
5

 
$
3

 
$
2

 
$
2

 
$
3

 
$
3



37

16.    STOCK-BASED COMPENSATION

At the Merger Date, Dynegy stock options and equity-based awards outstanding immediately prior to the Merger Date were generally automatically converted upon completion of the Merger into stock options and equity-based awards, respectively, with respect to Vistra Energy's common stock, after giving effect to the Exchange Ratio.
Instrument Type
Dynegy Awards Prior to the Merger Date
Vistra Awards Converted at the Merger Date
Fair Value of Awards (a)
Stock Options
4,096,027

2,670,610

$
10

Restricted Stock Units
5,718,148

3,056,689

61

Performance Units
1,538,133

938,721

18

Total


$
89

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


17.
RELATED PARTY TRANSACTIONS

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

Registration Rights Agreement

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

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

•
if we propose to file certain types of registration statements under the Securities Act of 1933, as amended, with respect to an offering of equity securities, we will be required to use our reasonable best efforts to offer the other parties to the Registration Rights Agreement the opportunity to register all or part of their shares on the terms and conditions set forth in the Registration Rights Agreement; and

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

All expenses of registration under the Registration Rights Agreement, including the legal fees of one counsel retained by or on behalf of the selling stockholders, will be paid by us. Legal fee expenses paid or accrued by Vistra Energy on behalf of the selling stockholders totaled less than $1 million during both the three and six months ended June 30, 2018 and 2017.


38

Tax Receivable Agreement

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


18.
SEGMENT INFORMATION

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

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

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

As discussed in Note 1, the Asset Closure segment was established effective January 1, 2018. The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines. Separately reporting the Asset Closure segment provides management with better information related to the performance and earnings power of Vistra Energy's ongoing operations and facilitates management's focus on minimizing the cost associated with decommissioning and reclamation of retired plants and mines. We have recast prior period information to reflect this change in reportable segments. We have not allocated any unrealized gains or losses on commodity risk management activities to the Asset Closure segment for the generation plants that were retired in January, February and May 2018.

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

Except as noted in Note 1, the accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1 to the Financial Statements in our 2017 Form 10-K. Our chief operating decision maker uses more than one measure to assess segment performance, including segment net income (loss), which is the measure most comparable to consolidated net income (loss) prepared based on GAAP. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices. Certain shared services costs are allocated to the segments.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Operating revenues (a)
 
 
 
 
 
 
 
Retail
$
1,454

 
$
986

 
$
2,426

 
$
1,850

ERCOT
1,327

 
319

 
794

 
1,104

PJM
485

 
—

 
485

 
—

NY/NE
187

 
—

 
187

 
—

MISO
257

 
—

 
257

 
—

Asset Closure
21

 
265

 
49

 
451

Corporate and Other (b)
31

 
—

 
31

 
—

Eliminations
(1,188
)
 
(274
)
 
(891
)
 
(752
)
Consolidated operating revenues
$
2,574

 
$
1,296

 
$
3,338

 
$
2,653


39

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Depreciation and amortization
 
 
 
 
 
 
 
Retail
$
(80
)
 
$
(108
)
 
$
(157
)
 
$
(214
)
ERCOT
(108
)
 
(54
)
 
(173
)
 
(107
)
PJM
(125
)
 
—

 
(125
)
 
—

NY/NE
(49
)
 
—

 
(49
)
 
—

MISO
(3
)
 
—

 
(3
)
 
—

Corporate and Other (b)
(23
)
 
(10
)
 
(35
)
 
(20
)
Eliminations
(1
)
 
—

 
—

 
—

Consolidated depreciation and amortization
$
(389
)
 
$
(172
)
 
$
(542
)
 
$
(341
)
Operating income (loss)
 
 
 
 
 
 
 
Retail (c)
$
(303
)
 
$
176

 
$
455

 
$
57

ERCOT
680

 
(152
)
 
(409
)
 
149

PJM
24

 
—

 
24

 
—

NY/NE
(7
)
 
—

 
(7
)
 
—

MISO
31

 
—

 
31

 
—

Asset Closure
1

 
48

 
(22
)
 
33

Corporate and Other (b)
(196
)
 
(19
)
 
(237
)
 
(32
)
Eliminations
1

 
—

 
1

 
—

Consolidated operating income (loss)
$
231

 
$
53

 
$
(164
)
 
$
207

Net income (loss)
 
 
 
 
 
 

Retail (b)
$
(288
)
 
$
183

 
$
483

 
$
70

ERCOT
679

 
(155
)
 
(407
)
 
147

PJM
23

 
—

 
23

 
—

NY/NE
(5
)
 
—

 
(5
)
 
—

MISO
31

 
—

 
31

 
—

Asset Closure
2

 
50

 
(20
)
 
37

Corporate and Other (b)
(337
)
 
(104
)
 
(306
)
 
(202
)
Consolidated net income (loss)
$
105

 
$
(26
)
 
$
(201
)
 
$
52

____________
(a)
The following unrealized net gains (losses) from mark-to-market valuations of commodity positions are included in operating revenues:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Retail
$
1

 
$
1

 
$
13

 
$
9

ERCOT
668

 
(147
)
 
(398
)
 
148

PJM
(10
)
 
—

 
(10
)
 
—

NY/NE
(24
)
 
—

 
(24
)
 
—

MISO
30

 
—

 
30

 
—

Corporate and Other (b)
1

 
—

 
1

 
—

Eliminations (1)
(463
)
 
88

 
180

 
(82
)
Consolidated unrealized net gains (losses) from mark-to-market valuations of commodity positions included in operating revenues
$
203

 
$
(58
)
 
$
(208
)
 
$
75

____________

40

(1)
Amounts offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results.
(b)
Includes CAISO operations.
(c)
Retail operating loss and net loss is driven by unrealized losses from mark-to-market valuations of commodity positions included in fuel, purchased power costs and delivery fees.

 
June 30,
2018
 
December 31, 2017
Total assets
 
 
 
Retail
$
7,252

 
$
6,156

ERCOT
9,018

 
6,834

PJM
7,932

 
—

NY/NE
2,619

 
—

MISO
500

 
—

Asset Closure
234

 
235

Corporate and Other and Eliminations
(1,085
)
 
1,375

Consolidated total assets
$
26,470

 
$
14,600



41


19.
SUPPLEMENTARY FINANCIAL INFORMATION

Interest Expense and Related Charges
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Interest paid/accrued
$
166

 
$
52

 
$
216

 
$
105

Unrealized mark-to-market net (gains) losses on interest rate swaps
(25
)
 
15

 
(86
)
 
6

Amortization of debt issuance costs, discounts and premiums
3

 
—

 
4

 
—

Debt extinguishment gain
—

 
—

 
—

 
(21
)
Capitalized interest
(4
)
 
(1
)
 
(7
)
 
(4
)
Other
6

 
3

 
10

 
7

Total interest expense and related charges
$
146

 
$
69

 
$
137

 
$
93


The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 10, was 4.16% at June 30, 2018.

Other Income and Deductions
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Other income:
 
 
 
 
 
 
 
Office space sublease rental income (a)
$
2

 
$
3

 
$
4

 
$
6

Mineral rights royalty income (b)
—

 
1

 
—

 
2

Sale of land (b)
—

 
1

 
1

 
3

Interest income
4

 
4

 
10

 
5

All other
1

 
—

 
3

 
2

Total other income
$
7

 
$
9

 
$
18

 
$
18

Other deductions:
 
 
 
 
 
 
 
Other
1

 
5

 
$
3

 
$
5

Total other deductions
$
1

 
$
5

 
$
3

 
$
5

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

Restricted Cash
 
June 30, 2018
 
December 31, 2017
 
Current
Assets
 
Noncurrent Assets
 
Current
Assets
 
Noncurrent Assets
Amounts related to the Vistra Operations Credit Facilities (Note 10)
$
—

 
$
—

 
$
—

 
$
500

Amounts related to restructuring escrow accounts
59

 
—

 
59

 
—

Total restricted cash
$
59

 
$
—

 
$
59

 
$
500



42

Trade Accounts Receivable
 
June 30,
2018
 
December 31,
2017
Wholesale and retail trade accounts receivable
$
1,163

 
$
596

Allowance for uncollectible accounts
(14
)
 
(14
)
Trade accounts receivable — net
$
1,149

 
$
582


Gross trade accounts receivable at June 30, 2018 and December 31, 2017 included unbilled retail revenues of $390 million and $251 million, respectively.

Allowance for Uncollectible Accounts Receivable
 
Six Months Ended June 30,
 
2018
 
2017
Allowance for uncollectible accounts receivable at beginning of period
$
14

 
$
10

Increase for bad debt expense
22

 
16

Decrease for account write-offs
(22
)
 
(17
)
Allowance for uncollectible accounts receivable at end of period
$
14

 
$
9


Inventories by Major Category
 
June 30,
2018
 
December 31,
2017
Materials and supplies
$
266

 
$
149

Fuel stock
181

 
83

Natural gas in storage
18

 
21

Total inventories
$
465

 
$
253


Other Investments
 
June 30,
2018
 
December 31,
2017
Nuclear plant decommissioning trust
$
1,207

 
$
1,188

Assets related to employee benefit plans (Note 15)
34

 
—

Land
49

 
49

Miscellaneous other
—

 
3

Total other investments
$
1,290

 
$
1,240


Investments in Unconsolidated Subsidiaries

On the Merger Date, we assumed Dynegy's 50% interest in Northeast Energy, LP (NELP), a joint venture with NextEra Energy, Inc., which indirectly owns the Bellingham NEA facility and the Sayreville facility. At June 30, 2018, our estimated investment in NELP totaled $135 million based on our preliminary purchase price allocation. Our risk of loss related to our equity method investment is limited to our investment balance (see Note 2).

For the three and six months ended June 30, 2018, equity earnings related to our investment in NELP totaled $4 million and $4 million, respectively, recorded in equity in earnings (loss) of unconsolidated investment in our condensed statements of consolidated net income (loss). For the three months ended June 30, 2018, we received distributions totaling $6 million.


43

Nuclear Decommissioning Trust

Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor Electric Delivery Company LLC's (Oncor) customers as a delivery fee surcharge over the life of the plant and deposited by Vistra Energy in the trust fund. Income and expense associated with the trust fund and the decommissioning liability are offset by a corresponding change in a regulatory asset/liability (currently a regulatory asset 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:
 
June 30, 2018
 
Cost (a)
 
Unrealized gain
 
Unrealized loss
 
Fair market
value
Debt securities (b)
$
432

 
$
6

 
$
(9
)
 
$
429

Equity securities (c)
272

 
506

 
—

 
778

Total
$
704

 
$
512

 
$
(9
)
 
$
1,207


 
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 3.51% and 3.55% at June 30, 2018 and December 31, 2017, respectively, and an average maturity of nine years at both June 30, 2018 and December 31, 2017.
(c)
The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index for U.S. equity investments and the MSCI Inc. EAFE Index for non-U.S. equity investments.

Debt securities held at June 30, 2018 mature as follows: $127 million in one to five years, $107 million in five to 10 years and $195 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 June 30,
 
Six Months Ended June 30,
 
2018
 
2017
 
2018
 
2017
Realized gains
$
1

 
$
1

 
$
1

 
$
2

Realized losses
$
(1
)
 
$
—

 
$
(3
)
 
$
(2
)
Proceeds from sales of securities
$
47

 
$
19

 
$
93

 
$
98

Investments in securities
$
(52
)
 
$
(23
)
 
$
(103
)
 
$
(107
)

Property, Plant and Equipment

At June 30, 2018 and December 31, 2017, property, plant and equipment of $14.981 billion and $4.820 billion, respectively, is stated net of accumulated depreciation and amortization of $788 million and $393 million, respectively.


44

Asset Retirement and Mining Reclamation Obligations (ARO)

These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining and removal of lignite/coal fueled plant ash treatment facilities. There is no earnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through the regulatory process as part of delivery fees charged by Oncor.

At June 30, 2018, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.254 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 $47 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 six months ended June 30, 2018:
 
Nuclear Plant Decommissioning
 
Mining Land Reclamation
 
Coal Ash and Other
 
Total
Liability at December 31, 2017
$
1,233

 
$
438

 
$
265

 
$
1,936

Additions:
 
 
 
 
 
 
 
Accretion
21

 
11

 
12

 
44

Adjustment for change in estimates
—

 
7

 
(43
)
 
(36
)
Obligations assumed in the Merger
—

 
2

 
417

 
419

Reductions:
 
 
 
 
 
 
 
Payments
—

 
(35
)
 
(6
)
 
(41
)
Liability at June 30, 2018
1,254

 
423

 
645

 
2,322

Less amounts due currently
—

 
(110
)
 
(61
)
 
(171
)
Noncurrent liability at June 30, 2018
$
1,254

 
$
313

 
$
584

 
$
2,151


Other Noncurrent Liabilities and Deferred Credits

The balance of other noncurrent liabilities and deferred credits consists of the following:
 
June 30,
2018
 
December 31,
2017
Uncertain tax positions, including accrued interest
$
11

 
$
—

Other, including retirement and other employee benefits
334

 
220

Total other noncurrent liabilities and deferred credits
$
345

 
$
220


Fair Value of Debt
 
 
 
 
June 30, 2018
 
December 31, 2017
Debt:
 
Fair Value Hierarchy
 
Carrying Amount
 
Fair
Value
 
Carrying Amount
 
Fair
Value
Long-term debt under the Vistra Operations Credit Facilities (Note 10)
 
Level 2
 
$
5,856

 
$
5,796

 
$
4,323

 
$
4,334

Senior Notes (Note 10)
 
Level 2
 
5,632

 
5,598

 
—

 
—

7.000% Amortizing Notes (Note 10)
 
Level 2
 
38

 
39

 
—

 
—

Forward Capacity Agreements (Note 10)
 
Level 3
 
221

 
221

 
—

 
—

Equipment Financing Agreements (Note 10)
 
Level 3
 
120

 
120

 
—

 
—

Mandatorily redeemable subsidiary preferred stock (Note 10)
 
Level 2
 
70

 
70

 
70

 
70

Building Financing (Note 10)
 
Level 2
 
26

 
24

 
30

 
27



45

We determine fair value in accordance with accounting standards as discussed in Note 13. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services, such as Bloomberg.

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 June 30, 2018 and December 31, 2017:
 
June 30,
2018
 
December 31,
2017
Cash and cash equivalents
$
757

 
$
1,487

Restricted cash included in current assets
59

 
59

Restricted cash included in noncurrent assets
—

 
500

Total cash, cash equivalents and restricted cash
$
816

 
$
2,046


The following table summarizes our supplemental cash flow information for the six months ended June 30, 2018 and 2017:
 
Six Months Ended June 30,
 
2018
 
2017
Cash payments related to:
 
 
 
Interest paid
$
344

 
$
142

Capitalized interest
(7
)
 
(4
)
Interest paid (net of capitalized interest)
$
337

 
$
138

Income taxes
$
58

 
$
43

Noncash investing and financing activities:
 
 
 
Construction expenditures (a)
$
13

 
$
21

Debt extinguishment gain
$
—

 
$
(21
)
Vistra Energy common stock issued in the Merger (Notes 2 and 12)
$
2,245

 
$
—

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



46

20.
SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Our senior notes are guaranteed by substantially all of our wholly owned subsidiaries. The following condensed consolidating financial statements present the financial information of (i) Vistra Energy Corp. (Parent), which is the ultimate parent company and issuer of the senior notes with effect as of the Merger Date, on a stand-alone, unconsolidated basis, (ii) the guarantor subsidiaries of Vistra Energy (Guarantor Subsidiaries), (iii) the non-guarantor subsidiaries of Vistra Energy (Non-Guarantor Subsidiaries) and (iv) the eliminations necessary to arrive at the information for Vistra Energy on a consolidated basis. The Guarantor Subsidiaries consist of the wholly-owned subsidiaries, which jointly, severally, fully and unconditionally, guarantee the payment obligations under the senior notes. See Note 10 for discussion of the senior notes.

These statements should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto of Vistra Energy. The supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements. The inclusion of Vistra Energy's subsidiaries as either Guarantor Subsidiaries or Non-Guarantor Subsidiaries in the condensed consolidating financial information is determined as of the most recent balance sheet date presented.

Condensed Statements of Consolidating Income (Loss) for the Three Months Ended June 30, 2018
(Millions of Dollars)
 
Parent (Issuer)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Operating revenues
$
—

 
$
2,508

 
$
68

 
$
(2
)
 
$
2,574

Fuel, purchased power costs and delivery fees
—

 
(1,166
)
 
(51
)
 
1

 
(1,216
)
Operating costs
—

 
(370
)
 
(16
)
 
—

 
(386
)
Depreciation and amortization
—

 
(371
)
 
(18
)
 
—

 
(389
)
Selling, general and administrative expenses
(192
)
 
(160
)
 
(2
)
 
2

 
(352
)
Operating income (loss)
(192
)
 
441

 
(19
)
 
1

 
231

Other income
3

 
5

 
—

 
(1
)
 
7

Other deductions
—

 
(1
)
 
—

 
—

 
(1
)
Interest expense and related charges
(87
)
 
(58
)
 
(1
)
 
—

 
(146
)
Impacts of Tax Receivable Agreement
(64
)
 
—

 
—

 
—

 
(64
)
Equity in earnings of unconsolidated investment
—

 
4

 
—

 
—

 
4

Income (loss) before income taxes
(340
)
 
391

 
(20
)
 
—

 
31

Income tax benefit (expense)
102

 
(34
)
 
6

 
—

 
74

Equity in earnings (loss) of subsidiaries, net of tax
343

 
(14
)
 
—

 
(329
)
 
—

Net income (loss)
$
105

 
$
343

 
$
(14
)
 
$
(329
)
 
$
105



47

Condensed Statements of Consolidating Income (Loss) for the Three Months Ended June 30, 2017
(Millions of Dollars)
 
Parent (Issuer)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Operating revenues
$
—

 
$
1,296

 
$
—

 
$
—

 
$
1,296

Fuel, purchased power costs and delivery fees
—

 
(729
)
 
—

 
—

 
(729
)
Operating costs
—

 
(195
)
 
—

 
—

 
(195
)
Depreciation and amortization
—

 
(172
)
 
—

 
—

 
(172
)
Selling, general and administrative expenses
(9
)
 
(138
)
 
—

 
—

 
(147
)
Operating income (loss)
(9
)
 
62

 
—

 
—

 
53

Other income
—

 
9

 
—

 
—

 
9

Other deductions
—

 
(5
)
 
—

 
—

 
(5
)
Interest expense and related charges
1

 
(70
)
 
—

 
—

 
(69
)
Impacts of Tax Receivable Agreement
(22
)
 
—

 
—

 
—

 
(22
)
Income (loss) before income taxes
(30
)
 
(4
)
 
—

 
—

 
(34
)
Income tax benefit (expense)
13

 
(5
)
 
—

 
—

 
8

Equity in loss of subsidiaries, net of tax
(9
)
 
—

 
—

 
9

 
—

Net income (loss)
$
(26
)
 
$
(9
)
 
$
—

 
$
9

 
$
(26
)

Condensed Statements of Consolidating Income (Loss) for the Six Months Ended June 30, 2018
(Millions of Dollars)
 
Parent (Issuer)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Operating revenues
$
—

 
$
3,272

 
$
68

 
$
(2
)
 
$
3,338

Fuel, purchased power costs and delivery fees
—

 
(1,816
)
 
(51
)
 
1

 
(1,866
)
Operating costs
—

 
(564
)
 
(16
)
 
—

 
(580
)
Depreciation and amortization
—

 
(524
)
 
(18
)
 
—

 
(542
)
Selling, general and administrative expenses
(226
)
 
(288
)
 
(2
)
 
2

 
(514
)
Operating income (loss)
(226
)
 
80

 
(19
)
 
1

 
(164
)
Other income
6

 
12

 
1

 
(1
)
 
18

Other deductions
—

 
(3
)
 
—

 
—

 
(3
)
Interest expense and related charges
(87
)
 
(49
)
 
(1
)
 
—

 
(137
)
Impacts of Tax Receivable Agreement
(82
)
 
—

 
—

 
—

 
(82
)
Equity in earnings of unconsolidated investment
—

 
4

 
—

 
—

 
4

Income (loss) before income taxes
(389
)
 
44

 
(19
)
 
—

 
(364
)
Income tax benefit (expense)
117

 
41

 
5

 
—

 
163

Equity in earnings (loss) of subsidiaries, net of tax
71

 
(14
)
 
—

 
(57
)
 
—

Net income (loss)
$
(201
)
 
$
71

 
$
(14
)
 
$
(57
)
 
$
(201
)


48

Condensed Statements of Consolidating Income (Loss) for the Six Months Ended June 30, 2017
(Millions of Dollars)
 
Parent (Issuer)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Operating revenues
$
—

 
$
2,653

 
$
—

 
$
—

 
$
2,653

Fuel, purchased power costs and delivery fees
—

 
(1,411
)
 
—

 
—

 
(1,411
)
Operating costs
—

 
(409
)
 
—

 
—

 
(409
)
Depreciation and amortization
—

 
(341
)
 
—

 
—

 
(341
)
Selling, general and administrative expenses
(14
)
 
(271
)
 
—

 
—

 
(285
)
Operating income (loss)
(14
)
 
221

 
—

 
—

 
207

Other income
—

 
18

 
—

 
—

 
18

Other deductions
—

 
(5
)
 
—

 
—

 
(5
)
Interest expense and related charges
1

 
(94
)
 
—

 
—

 
(93
)
Impacts of Tax Receivable Agreement
(42
)
 
—

 
—

 
—

 
(42
)
Income (loss) before income taxes
(55
)
 
140

 
—

 
—

 
85

Income tax benefit (expense)
25

 
(58
)
 
—

 
—

 
(33
)
Equity in earnings of subsidiaries, net of tax
82

 
—

 
—

 
(82
)
 
—

Net income (loss)
$
52

 
$
82

 
$
—

 
$
(82
)
 
$
52


Condensed Statements of Consolidating Comprehensive Income (Loss) for the Three Months Ended June 30, 2018
(Millions of Dollars)
 
Parent (Issuer)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Net income (loss)
$
105

 
$
343

 
$
(14
)
 
$
(329
)
 
$
105

Other comprehensive income (loss), net of tax effects:
 
 
 
 
 
 
 
 
 
Effect related to pension and other retirement benefit obligations
—

 
—

 
—

 
—

 
—

Total other comprehensive income
—

 
—

 
—

 
—

 
—

Comprehensive income (loss)
$
105

 
$
343

 
$
(14
)
 
$
(329
)
 
$
105


Condensed Statements of Consolidating Comprehensive Income (Loss) for the Three Months Ended June 30, 2017
(Millions of Dollars)
 
Parent (Issuer)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Net income (loss)
$
(26
)
 
$
(9
)
 
$
—

 
$
9

 
$
(26
)
Other comprehensive income (loss), net of tax effects:
 
 
 
 
 
 
 
 
 
Effect related to pension and other retirement benefit obligations
—

 
—

 
—

 
—

 
—

Total other comprehensive income
—

 
—

 
—

 
—

 
—

Comprehensive income (loss)
$
(26
)
 
$
(9
)
 
$
—

 
$
9

 
$
(26
)


49

Condensed Statements of Consolidating Comprehensive Income (Loss) for the Six Months Ended June 30, 2018
(Millions of Dollars)
 
Parent (Issuer)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Net income (loss)
$
(201
)
 
$
71

 
$
(14
)
 
$
(57
)
 
$
(201
)
Other comprehensive income (loss), net of tax effects:
 
 
 
 
 
 
 
 
 
Effect related to pension and other retirement benefit obligations
1

 
—

 
—

 
—

 
1

Total other comprehensive income
1

 
—

 
—

 
—

 
1

Comprehensive income (loss)
$
(200
)
 
$
71

 
$
(14
)
 
$
(57
)
 
$
(200
)

Condensed Statements of Consolidating Comprehensive Income (Loss) for the Six Months Ended June 30, 2017
(Millions of Dollars)
 
Parent (Issuer)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Net income (loss)
$
52

 
$
82

 
$
—

 
$
(82
)
 
$
52

Other comprehensive income (loss), net of tax effects:
 
 
 
 
 
 
 
 
 
Effect related to pension and other retirement benefit obligations
—

 
—

 
—

 
—

 
—

Total other comprehensive income
—

 
—

 
—

 
—

 
—

Comprehensive income (loss)
$
52

 
$
82

 
$
—

 
$
(82
)
 
$
52



50

Condensed Statements of Consolidating Cash Flows for the Six Months Ended June 30, 2018
(Millions of Dollars)
 
Parent (Issuer)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Cash flows — operating activities:
 
 
 
 
 
 
 
 
 
Cash provided by (used in) operating activities
$
(280
)
 
$
(109
)
 
$
360

 
$
—

 
$
(29
)
Cash flows — financing activities:
 
 
 
 
 
 
 
 
 
Repayments/repurchases of debt
(840
)
 
(498
)
 
—

 
—

 
(1,338
)
Stock repurchase
(63
)
 
—

 
—

 
—

 
(63
)
Debt financing fee
(29
)
 
(17
)
 
—

 
—

 
(46
)
Other, net
—

 
4

 
—

 
—

 
4

Cash provided by (used in) financing activities
(932
)
 
(511
)
 
—

 
—

 
(1,443
)
Cash flows — investing activities:
 
 
 
 
 
 
 
 
 
Capital expenditures
(4
)
 
(147
)
 
(2
)
 
—

 
(153
)
Nuclear fuel purchases
—

 
(28
)
 
—

 
—

 
(28
)
Cash acquired in the Merger
418

 
27

 
—

 
—

 
445

Solar development expenditures
—

 
(21
)
 
—

 
—

 
(21
)
Proceeds from sales of nuclear decommissioning trust fund securities
—

 
93

 
—

 
—

 
93

Investments in nuclear decommissioning trust fund securities
—

 
(103
)
 
—

 
—

 
(103
)
Other, net
(4
)
 
358

 
(345
)
 
—

 
9

Cash provided by (used in) investing activities
410

 
179

 
(347
)
 
—

 
242

Net change in cash, cash equivalents and restricted cash
(802
)
 
(441
)
 
13

 
—

 
(1,230
)
Cash, cash equivalents and restricted cash — beginning balance
1,183

 
863

 
—

 
—

 
2,046

Cash, cash equivalents and restricted cash — ending balance
$
381

 
$
422

 
$
13

 
$
—

 
$
816



51

Condensed Statements of Consolidating Cash Flows for the Six Months Ended June 30, 2017
(Millions of Dollars)
 
Parent (Issuer)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
Cash flows — operating activities:
 
 
 
 
 
 
 
 
 
Cash provided by operating activities
$
111

 
$
222

 
$
—

 


 
$
333

Cash flows — financing activities:
 
 
 
 
 
 
 
 
 
Repayments/repurchases of debt
—

 
(24
)
 
—

 
—

 
(24
)
Debt financing fee
—

 
(3
)
 
—

 
—

 
(3
)
Cash used in financing activities
—

 
(27
)
 
—

 
—

 
(27
)
Cash flows — investing activities:
 
 
 
 
 
 
 
 
 
Capital expenditures
—

 
(63
)
 
—

 
—

 
(63
)
Nuclear fuel purchases
—

 
(35
)
 
—

 
—

 
(35
)
Solar development expenditures
—

 
(96
)
 
—

 
—

 
(96
)
Proceeds from sales of nuclear decommissioning trust fund securities
—

 
98

 
—

 
—

 
98

Investments in nuclear decommissioning trust fund securities
—

 
(107
)
 
—

 
—

 
(107
)
Other, net
331

 
(322
)
 
—

 
—

 
9

Cash used in investing activities
331

 
(525
)
 
—

 
—

 
(194
)
Net change in cash, cash equivalents and restricted cash
442

 
(330
)
 
—

 
—

 
112

Cash, cash equivalents and restricted cash — beginning balance
26

 
1,562

 
—

 
—

 
1,588

Cash, cash equivalents and restricted cash — ending balance
$
468

 
$
1,232

 
$
—

 
$
—

 
$
1,700



52

Condensed Consolidating Balance Sheet as of June 30, 2018
(Millions of Dollars)
 
Parent (Issuer)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
322

 
$
422

 
$
13

 
$
—

 
$
757

Restricted cash
59

 
—

 
—

 
—

 
59

Trade accounts receivable — net
8

 
1,142

 
1

 
(2
)
 
1,149

Accounts receivable — affiliates
—

 
275

 
—

 
(275
)
 
—

Notes due from affiliates
—

 
101

 
—

 
(101
)
 
—

Income taxes receivable
11

 
—

 
—

 
—

 
11

Inventories
—

 
451

 
14

 
—

 
465

Commodity and other derivative contractual assets
—

 
598

 
—

 
—

 
598

Margin deposits related to commodity contracts
—

 
200

 
—

 
—

 
200

Prepaid expense and other current assets
—

 
129

 
6

 
—

 
135

Total current assets
400

 
3,318

 
34

 
(378
)
 
3,374

Restricted cash
—

 
—

 
—

 
—

 
—

Investments
—

 
1,256

 
34

 
—

 
1,290

Investment in unconsolidated subsidiary
—

 
135

 
—

 
—

 
135

Investment in affiliated companies
13,542

 
354

 
—

 
(13,896
)
 
—

Property, plant and equipment — net
10

 
14,332

 
639

 
—

 
14,981

Goodwill
—

 
1,907

 
—

 
—

 
1,907

Identifiable intangible assets — net
—

 
2,698

 
—

 
—

 
2,698

Commodity and other derivative contractual assets
—

 
244

 
—

 
—

 
244

Accumulated deferred income taxes
893

 
367

 
—

 
—

 
1,260

Other noncurrent assets
241

 
334

 
7

 
(1
)
 
581

Total assets
$
15,086

 
$
24,945

 
$
714

 
$
(14,275
)
 
$
26,470

LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Long-term debt due currently
$
30

 
$
121

 
$
5

 
$
—

 
$
156

Trade accounts payable
6

 
778

 
11

 
—

 
795

Accounts payable — affiliates
274

 
—

 
2

 
(276
)
 
—

Notes due to affiliates
—

 
—

 
101

 
(101
)
 
—

Commodity and other derivative contractual liabilities
—

 
883

 
—

 
—

 
883

Margin deposits related to commodity contracts
—

 
3

 
—

 
—

 
3

Accrued taxes other than income
7

 
134

 
2

 
—

 
143

Accrued interest
102

 
6

 
2

 
(2
)
 
108

Asset retirement obligations
—

 
171

 
—

 
—

 
171

Other current liabilities
169

 
216

 
2

 
—

 
387

Total current liabilities
588

 
2,312

 
125

 
(379
)
 
2,646

Long-term debt, less amounts due currently
5,639

 
6,135

 
33

 
—

 
11,807

Commodity and other derivative contractual liabilities
—

 
495

 
—

 
—

 
495

Accumulated deferred income taxes
—

 
—

 
134

 
(129
)
 
5

Tax Receivable Agreement obligation
414

 
—

 
—

 
—

 
414

Asset retirement obligations
—

 
2,138

 
13

 
—

 
2,151

Identifiable intangible liabilities — net
—

 
146

 
41

 
—

 
187

Other noncurrent liabilities and deferred credits
25

 
306

 
14

 
—

 
345

Total liabilities
6,666

 
11,532

 
360

 
(508
)
 
18,050

Total equity
8,420

 
13,413

 
354

 
(13,767
)
 
8,420

Total liabilities and equity
$
15,086

 
$
24,945

 
$
714

 
$
(14,275
)
 
$
26,470


53

Condensed Consolidating Balance Sheet as of December 31, 2017
(Millions of Dollars)
 
Parent (Issuer)
 
Guarantor Subsidiaries
 
Non-Guarantor Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
1,124

 
$
363

 
$
—

 
$
—

 
$
1,487

Restricted cash
59

 
—

 
—

 
—

 
59

Trade accounts receivable — net
4

 
578

 
—

 
—

 
582

Inventories
—

 
253

 
—

 
—

 
253

Commodity and other derivative contractual assets
—

 
190

 
—

 
—

 
190

Margin deposits related to commodity contracts
—

 
30

 
—

 
—

 
30

Prepaid expense and other current assets
—

 
72

 
—

 
—

 
72

Total current assets
1,187

 
1,486

 
—

 
—

 
2,673

Restricted cash
—

 
500

 
—

 
—

 
500

Investments
—

 
1,240

 
—

 
—

 
1,240

Investment in affiliated companies
5,632

 
—

 
—

 
(5,632
)
 
—

Property, plant and equipment — net
—

 
4,820

 
—

 
—

 
4,820

Goodwill
—

 
1,907

 
—

 
—

 
1,907

Identifiable intangible assets — net
—

 
2,530

 
—

 
—

 
2,530

Commodity and other derivative contractual assets
—

 
58

 
—

 
—

 
58

Accumulated deferred income taxes
5

 
705

 
—

 
—

 
710

Other noncurrent assets
6

 
156

 
—

 
—

 
162

Total assets
$
6,830

 
$
13,402

 
$
—

 
$
(5,632
)
 
$
14,600

LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Long-term debt due currently
$
—

 
$
44

 
$
—

 
$
—

 
$
44

Trade accounts payable
11

 
462

 
—

 
—

 
473

Commodity and other derivative contractual liabilities
—

 
224

 
—

 
—

 
224

Margin deposits related to commodity contracts
—

 
4

 
—

 
—

 
4

Accrued taxes
58

 
—

 
—

 
—

 
58

Accrued taxes other than income
—

 
136

 
—

 
—

 
136

Accrued interest
—

 
16

 
—

 
—

 
16

Asset retirement obligations
—

 
99

 
—

 
—

 
99

Other current liabilities
86

 
211

 
—

 
—

 
297

Total current liabilities
155

 
1,196

 
—

 
—

 
1,351

Long-term debt, less amounts due currently
—

 
4,379

 
—

 
—

 
4,379

Commodity and other derivative contractual liabilities
—

 
102

 
—

 
—

 
102

Tax Receivable Agreement obligation
333

 
—

 
—

 
—

 
333

Asset retirement obligations
—

 
1,837

 
—

 
—

 
1,837

Identifiable intangible liabilities — net
—

 
36

 
—

 
—

 
36

Other noncurrent liabilities and deferred credits
—

 
220

 
—

 
—

 
220

Total liabilities
488

 
7,770

 
—

 
—

 
8,258

Total equity
6,342

 
5,632

 
—

 
(5,632
)
 
6,342

Total liabilities and equity
$
6,830

 
$
13,402

 
$
—

 
$
(5,632
)
 
$
14,600



54


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

The following discussion and analysis of our financial condition and results of operations for the three and six months ended June 30, 2018 and 2017 should be read in conjunction with our condensed consolidated financial statements and the notes to those statements.

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

Business

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

Operating Segments

Vistra Energy has six reportable segments: (i) Retail, (ii) ERCOT, (iii) PJM, (iv) NY/NE (comprising NYISO and ISO-NE), (v) MISO and Asset Closure. The PJM, NY/NE and MISO segments were established on the Merger Date to reflect markets served by businesses acquired in the Merger. The Asset Closure segment was established as of January 1, 2018, and we have recast information from prior periods to reflect this change in reportable segments. See Note 18 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.

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, except that cash was paid in lieu of fractional shares, which resulted in Vistra Energy's stockholders and Dynegy's stockholders owning approximately 79% and 21%, respectively, of the combined company.

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

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

Battery Energy Storage Project — In June 2018, we announced that, subject to approval by the California Public Utilities Commission (CPUC), we will enter into a 20-year resource adequacy contract with Pacific Gas and Electric Company (PG&E) to develop a 300 MW battery energy storage project at our Moss Landing Power Plant site in California. In late June 2018, PG&E filed its application with the CPUC to approve the contract, and a decision is expected within 90 days of the filing. Pending the receipt of CPUC approval, we anticipate the battery storage project will enter commercial operations by the fourth quarter of 2020.

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


55

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

Retirement of Generation Plants — In January and February 2018, we retired three power plants with a total installed nameplate generation capacity of 4,167 MW. Luminant decided to retire these units because they were projected to be uneconomic based on current market conditions and would have faced significant environmental costs associated with operating such units. In the case of the Sandow units, the decision also reflected the execution of a contract termination agreement pursuant to which the Company and Alcoa agreed to an early settlement of a long-standing power and mining agreement.

Two of our non-operated, jointly held power plants acquired in the Merger for which our proportional generation capacity was 883 MW, were retired in May 2018. These units were retired as previously scheduled.

Debt Activity — We have stated a target to reduce leverage to approximately 2.5x net debt/EBITDA by the end of 2019. The following transactions reflect our commitment to simplify the capital structure and reduce interest expense.

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

•
Aggregate commitments under the Revolving Credit Facility were increased from $860 million to $2.5 billion. The letter of credit sub-facility was also increased from $715 million to $2.3 billion. The maturity date of the Revolving Credit Facility was extended from August 4, 2021 to June 14, 2023. Pricing terms for the Revolving Credit Facility were reduced from LIBOR plus an applicable margin of 2.25% to LIBOR plus an applicable margin of 1.75%. Pricing terms for letters of credit issued under the Revolving Credit Facility were reduced from 2.25% to 1.75%.
•
Pricing terms for the Term Loan B-1 Facility were reduced from LIBOR plus an applicable margin of 2.50% to LIBOR plus an applicable margin of 2.00%.
•
Borrowings under the new Term Loan B-3 Facility of $2.050 billion principal amount were used to repay borrowings under the credit agreement that Vistra Energy assumed from Dynegy in connection with the Merger. Amounts borrowed under the Term Loan B-3 Facility bear interest based on applicable LIBOR rates plus a fixed spread of 2.00%, and the maturity date of the facility is December 31, 2025.
•
Borrowings under the Term Loan C Facility of $500 million were repaid using $500 million of cash from collateral accounts used to backstop letters of credit.

See Note 10 to the Financial Statements for details of the Vistra Operations Credit Facilities.

Redemption of Debt — In May 2018, $850 million of outstanding 6.75% Senior Notes due 2019 were redeemed at a redemption price of 101.688% of the aggregate principal amount, plus accrued and unpaid interest to but not including the date of redemption (see Note 10).

Share Repurchase Program — In June 2018, we announced that our board of directors had authorized a share repurchase program (Program) under which up to $500 million of our outstanding common stock may be repurchased. The Program was effective as of June 13, 2018, and we intend to implement the Program opportunistically from time to time through the end of 2019. Shares of the Company's common stock may be repurchased in open market transactions at prevailing market prices, in privately negotiated transactions or by other means in accordance with the Securities Exchange Act of 1934, as amended, or by other means in accordance with federal securities laws. The actual timing, number and value of shares repurchased under the Program will be determined at our discretion and will depend on a number of factors, including the market price of our stock, general market and economic conditions, applicable legal requirements and compliance with the terms of our debt agreements and the Tax Matters Agreement.


56

Through June 30, 2018, 3,152,073 shares of our common stock had been repurchased for $75 million (including related fees and expenses) at an average price per share of common stock of $23.81, and at June 30, 2018, $425 million was available for additional repurchases under the Program. On a cumulative basis ,through July 31, 2018, 6,392,937 shares of our common stock had been repurchased for $150 million (including related fees and expenses) at an average price per share of common stock of $23.46. At July 31, 2018, $350 million was available for additional repurchases under the Program.

Natural Gas Price and Market Heat Rate Exposure — Taking together forward wholesale, retail electricity sales and other retail customer considerations and all other hedging positions in ERCOT at June 29, 2018, we had effectively hedged an estimated 94% and 91% of the natural gas price exposure related to our overall business for 2018 and 2019, respectively. These percentages assume conversion of generation positions based on market heat rates and an estimate of natural gas generally being on the margin 70% to 90% of the time in the ERCOT market. Additionally, taking into consideration our overall heat rate exposure and related hedging positions in ERCOT at June 29, 2018, we had effectively hedged 89% and 58% of the heat rate exposure to our overall business for 2018 and 2019, respectively. Generation volumes hedged in PJM, NYISO, ISO-NE, MISO and CAISO at June 29, 2018 were as follows:
 
2018
 
2019
PJM
78
%
 
63
%
NYISO/ISO-NE
77
%
 
47
%
MISO/CAISO
74
%
 
57
%

The following sensitivity tables provide approximate estimates of the potential impact of movements in natural gas prices and market heat rates on realized pretax earnings (in millions) taking into account the hedge positions noted in the paragraph above for the periods presented. The estimates related to price sensitivity are based on our expected generation and retail positions, related hedges and forward prices as of June 29, 2018.
 
Balance 2018 (a)
 
2019
ERCOT:
 
 
 
$0.50/MMBtu increase in natural gas price (b)
$ ~25
 
$ ~50
$0.50/MMBtu decrease in natural gas price (b)
$ ~(20)
 
$ ~(30)
1.0/MMBtu/MWh increase in market heat rate (c)
$ ~30
 
$ ~110
1.0/MMBtu/MWh decrease in market heat rate (c)
$ ~(15)
 
$ ~(95)
PJM:
 
 
 
$0.50/MMBtu increase in natural gas price (d)
$ ~20
 
$ ~51
$0.50/MMBtu decrease in natural gas price (d)
$ ~(10)
 
$ ~(31)
1.0/MMBtu/MWh increase in market heat rate (e)
$ ~20
 
$ ~58
1.0/MMBtu/MWh decrease in market heat rate (e)
$ ~(12)
 
$ ~(44)
NYISO/ISO-NE:
 
 
 
$0.50/MMBtu increase in natural gas price (d)
$ ~5
 
$ ~42
$0.50/MMBtu decrease in natural gas price (d)
$ ~(2)
 
$ ~(27)
1.0/MMBtu/MWh increase in market heat rate (f)
$ ~11
 
$ ~48
1.0/MMBtu/MWh decrease in market heat rate (f)
$ ~(4)
 
$ ~(29)
MISO/CAISO:
 
 
 
$0.50/MMBtu increase in natural gas price (d)
$ ~29
 
$ ~91
$0.50/MMBtu decrease in natural gas price (d)
$ ~(15)
 
$ ~(56)
1.0/MMBtu/MWh increase in market heat rate (g)
$ ~17
 
$ ~46
1.0/MMBtu/MWh decrease in market heat rate (g)
$ ~(12)
 
$ ~(35)
___________
(a)
Balance of 2018 is from July 1, 2018 through December 31, 2018.
(b)
Based on Houston Ship Channel natural gas prices at June 29, 2018.
(c)
Based on ERCOT North Hub around-the-clock heat rates at June 29, 2018.
(d)
Based on NYMEX natural gas prices at June 29, 2018.
(e)
Based on AEP Dayton Hub, Northern Illinois Hub and PJM West Hub around-the-clock heat rates at June 29, 2018.
(f)
Based on Massachusetts Hub and NYISO Zone C around-the-clock heat rates at June 29, 2018.
(g)
Based on Indiana Hub and NP15 around-the-clock heat rates at June 29, 2018.


57

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.


RESULTS OF OPERATIONS

Consolidated Financial Results — Three and Six Months Ended June 30, 2018 Compared to Three and Six Months Ended June 30, 2017
 
Three Months Ended June 30,
 
Favorable (Unfavorable)
$ Change
 
Six Months Ended June 30,
 
Favorable (Unfavorable)
$ Change
 
2018
 
2017
 
 
2018
 
2017
 
Operating revenues
$
2,574

 
$
1,296

 
$
1,278

 
$
3,338

 
$
2,653

 
$
685

Fuel, purchased power costs and delivery fees
(1,216
)
 
(729
)
 
(487
)
 
(1,866
)
 
(1,411
)
 
(455
)
Operating costs
(386
)
 
(195
)
 
(191
)
 
(580
)
 
(409
)
 
(171
)
Depreciation and amortization
(389
)
 
(172
)
 
(217
)
 
(542
)
 
(341
)
 
(201
)
Selling, general and administrative expenses
(352
)
 
(147
)
 
(205
)
 
(514
)
 
(285
)
 
(229
)
Operating income (loss)
231

 
53

 
178

 
(164
)
 
207

 
(371
)
Other income
7

 
9

 
(2
)
 
18

 
18

 
—

Other deductions
(1
)
 
(5
)
 
4

 
(3
)
 
(5
)
 
2

Interest expense and related charges
(146
)
 
(69
)
 
(77
)
 
(137
)
 
(93
)
 
(44
)
Impacts of Tax Receivable Agreement
(64
)
 
(22
)
 
(42
)
 
(82
)
 
(42
)
 
(40
)
Equity in earnings of unconsolidated investment
4

 
—

 
4

 
4

 
—

 
4

Income (loss) before income taxes
31

 
(34
)
 
65

 
(364
)
 
85

 
(449
)
Income tax (expense) benefit
74

 
8

 
66

 
163

 
(33
)
 
196

Net income (loss)
$
105

 
$
(26
)
 
$
131

 
$
(201
)
 
$
52

 
$
(253
)

 
Three Months Ended June 30, 2018
 
Retail
 
ERCOT
 
PJM
 
NY/NE
 
MISO
 
Asset
Closure
 
Eliminations / Corporate and Other
 
Vistra
Energy Consolidated
Operating revenues
$
1,454

 
$
1,327

 
$
485

 
$
187

 
$
257

 
$
21

 
$
(1,157
)
 
$
2,574

Fuel, purchased power costs and delivery fees
(1,566
)
 
(337
)
 
(239
)
 
(108
)
 
(133
)
 
(10
)
 
1,177

 
(1,216
)
Operating costs
(9
)
 
(182
)
 
(82
)
 
(25
)
 
(76
)
 
(6
)
 
(6
)
 
(386
)
Depreciation and amortization
(80
)
 
(108
)
 
(125
)
 
(49
)
 
(3
)
 
—

 
(24
)
 
(389
)
Selling, general and administrative expenses
(102
)
 
(20
)
 
(15
)
 
(12
)
 
(14
)
 
(4
)
 
(185
)
 
(352
)
Operating income (loss)
(303
)
 
680

 
24

 
(7
)
 
31

 
1

 
(195
)
 
231

Other income
15

 
8

 
—

 
—

 
—

 
1

 
(17
)
 
7

Other deductions
—

 
(2
)
 
—

 
—

 
—

 
—

 
1

 
(1
)
Interest expense and related charges
—

 
(7
)
 
(2
)
 
(1
)
 
—

 
—

 
(136
)
 
(146
)
Impacts of Tax Receivable Agreement
—

 
—

 
—

 
—

 
—

 
—

 
(64
)
 
(64
)
Equity in earnings of unconsolidated investment
—

 
—

 
1

 
3

 
—

 
—

 
—

 
4

Income (loss) before income taxes
(288
)
 
679

 
23

 
(5
)
 
31

 
2

 
(411
)
 
31

Income tax benefit
—

 
—

 
—

 
—

 
—

 
—

 
74

 
74

Net income (loss)
$
(288
)
 
$
679

 
$
23

 
$
(5
)
 
$
31

 
$
2

 
$
(337
)
 
$
105



58

 
Three Months Ended June 30, 2017
 
Retail
 
ERCOT
 
Asset
Closure
 
Eliminations / Corporate and Other
 
Vistra
Energy Consolidated
Operating revenues
$
986

 
$
319

 
$
265

 
$
(274
)
 
$
1,296

Fuel, purchased power costs and delivery fees
(596
)
 
(245
)
 
(161
)
 
273

 
(729
)
Operating costs
(3
)
 
(140
)
 
(52
)
 
—

 
(195
)
Depreciation and amortization
(108
)
 
(54
)
 
—

 
(10
)
 
(172
)
Selling, general and administrative expenses
(103
)
 
(32
)
 
(4
)
 
(8
)
 
(147
)
Operating income (loss)
176

 
(152
)
 
48

 
(19
)
 
53

Other income
7

 
4

 
2

 
(4
)
 
9

Other deductions
—

 
(3
)
 
—

 
(2
)
 
(5
)
Interest expense and related charges
—

 
(4
)
 
—

 
(65
)
 
(69
)
Impacts of Tax Receivable Agreement
—

 
—

 
—

 
(22
)
 
(22
)
Income (loss) before income taxes
183

 
(155
)
 
50

 
(112
)
 
(34
)
Income tax benefit
—

 
—

 
—

 
8

 
8

Net income (loss)
$
183

 
$
(155
)
 
$
50

 
$
(104
)
 
$
(26
)

For the three months ended June 30, 2018, net income reflects operating results subsequent to the Merger Date and strong operating performance in our operating segments. Consolidated results increased $131 million to net income of $105 million in the three months ended June 30, 2018 compared to the three months ended June 30, 2017. The change in results was driven by additional operations acquired in the Merger, unrealized mark-to-market gains on commodity risk management activity, Retail segment favorable impacts of weather in ERCOT and the impact of the Comanche Peak outage in 2017, partially offset by one-time merger-related expenses including severance and transaction fees and Q1 2018 plant retirements.

Interest expense and related charges increased $77 million to $146 million in the three months ended June 30, 2018 compared to the three months ended June 30, 2017 and reflected a $114 million increase in interest expense incurred reflecting long-term debt assumed in the Merger, partially offset by a $40 million increase in unrealized mark-to-market gains on interest rate swaps. See Note 19 to the Financial Statements.

For the three months ended June 30, 2018, the Impacts of the Tax Receivable Agreement totaled expense of $64 million and reflected a loss due to changes in the estimated amount and timing of TRA payments totaling $46 million and accretion expense totaling $18 million. For the three months ended June 30, 2017, the Impacts of the Tax Receivable Agreement totaled expense of $22 million, which reflected accretion expense for the period. See Note 8 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement Obligation.

For the three months ended June 30, 2018, income tax benefit totaled $74 million and the effective tax rate was (238.7)%. For the three months ended June 30, 2017, income tax benefit totaled $8 million and the effective tax rate was 23.5%. See Note 7 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.


59

 
Six Months Ended June 30, 2018
 
Retail
 
ERCOT
 
PJM
 
NY/NE
 
MISO
 
Asset
Closure
 
Eliminations / Corporate and Other
 
Vistra
Energy Consolidated
Operating revenues
$
2,426

 
$
794

 
$
485

 
$
187

 
$
257

 
$
49

 
$
(860
)
 
$
3,338

Fuel, purchased power costs and delivery fees
(1,601
)
 
(627
)
 
(239
)
 
(108
)
 
(133
)
 
(36
)
 
878

 
(1,866
)
Operating costs
(13
)
 
(347
)
 
(82
)
 
(25
)
 
(76
)
 
(30
)
 
(7
)
 
(580
)
Depreciation and amortization
(157
)
 
(173
)
 
(125
)
 
(49
)
 
(3
)
 
—

 
(35
)
 
(542
)
Selling, general and administrative expenses
(200
)
 
(56
)
 
(15
)
 
(12
)
 
(14
)
 
(5
)
 
(212
)
 
(514
)
Operating income (loss)
455

 
(409
)
 
24

 
(7
)
 
31

 
(22
)
 
(236
)
 
(164
)
Other income
29

 
20

 
—

 
—

 
—

 
2

 
(33
)
 
18

Other deductions
—

 
(3
)
 
—

 
—

 
—

 
—

 
—

 
(3
)
Interest expense and related charges
(1
)
 
(15
)
 
(2
)
 
(1
)
 
—

 
—

 
(118
)
 
(137
)
Impacts of Tax Receivable Agreement
—

 
—

 
—

 
—

 
—

 
—

 
(82
)
 
(82
)
Equity in earnings (loss) of unconsolidated investment
—

 
—

 
1

 
3

 
—

 
—

 
—

 
4

Income (loss) before income taxes
483

 
(407
)
 
23

 
(5
)
 
31

 
(20
)
 
(469
)
 
(364
)
Income tax benefit
—

 
—

 
—

 
—

 
—

 
—

 
163

 
163

Net income (loss)
$
483

 
$
(407
)
 
$
23

 
$
(5
)
 
$
31

 
$
(20
)
 
$
(306
)
 
$
(201
)

 
Six Months Ended June 30, 2017
 
Retail
 
ERCOT
 
Asset
Closure
 
Eliminations / Corporate and Other
 
Vistra
Energy Consolidated
Operating revenues
$
1,850

 
$
1,104

 
$
451

 
$
(752
)
 
$
2,653

Fuel, purchased power costs and delivery fees
(1,368
)
 
(496
)
 
(300
)
 
753

 
(1,411
)
Operating costs
(7
)
 
(293
)
 
(109
)
 
—

 
(409
)
Depreciation and amortization
(214
)
 
(107
)
 
—

 
(20
)
 
(341
)
Selling, general and administrative expenses
(204
)
 
(59
)
 
(9
)
 
(13
)
 
(285
)
Operating income (loss)
57

 
149

 
33

 
(32
)
 
207

Other income
13

 
7

 
4

 
(6
)
 
18

Other deductions
—

 
(4
)
 
—

 
(1
)
 
(5
)
Interest expense and related charges
—

 
(5
)
 
—

 
(88
)
 
(93
)
Impacts of Tax Receivable Agreement
—

 
—

 
—

 
(42
)
 
(42
)
Income (loss) before income taxes
70

 
147

 
37

 
(169
)
 
85

Income tax benefit
—

 
—

 
—

 
(33
)
 
(33
)
Net income (loss)
$
70

 
$
147

 
$
37

 
$
(202
)
 
$
52



60

For the six months ended June 30, 2018, net loss reflects operating results subsequent to the Merger Date and strong operating performance in our operating segments despite unrealized mark-to-market losses on commodity risk management activity reflecting higher forward power prices principally driven by higher market heat rates. Consolidated results decreased $253 million to a net loss of $201 million in the six months ended June 30, 2018 compared to the six months ended June 30, 2017. The change in results was driven by unrealized mark-to-market losses on commodity risk management activity, one-time Merger-related expenses including severance and transaction fees and Q1 2018 plant retirements, partially offset by additional operations acquired in the Merger, Retail segment favorable impacts of weather in ERCOT and the impact of the Comanche Peak outage in 2017.

Interest expense and related charges increased $44 million to $137 million in the six months ended June 30, 2018 compared to the six months ended June 30, 2017 and reflected a $111 million increase in interest expense incurred reflecting long-term debt assumed in the Merger and a $21 million debt extinguishment gain recorded in 2017, partially offset by a $92 million increase in unrealized mark-to-market gains on interest rate swaps. See Note 19 to the Financial Statements.

For the six months ended June 30, 2018, the Impacts of the Tax Receivable Agreement totaled expense of $82 million and reflected a loss due to changes in the estimated amount and timing of TRA payments totaling $46 million and accretion expense totaling $36 million. For the six months ended June 30, 2017, the Impacts of the Tax Receivable Agreement totaled expense of $42 million, which reflected accretion expense for the period. See Note 8 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement Obligation.

For the six months ended June 30, 2018, income tax benefit totaled $163 million and the effective tax rate was 44.8%. For the six months ended June 30, 2017, income tax expense totaled $33 million and the effective tax rate was 38.8%. See Note 7 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate.

Discussion of Adjusted EBITDA

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

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

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

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


61

Adjusted EBITDA — Three and Six Months Ended June 30, 2018 Compared to Three and Six Months Ended June 30, 2017
 
Three Months Ended June 30,
 
Favorable (Unfavorable)
$ Change
 
Six Months Ended June 30,
 
Favorable (Unfavorable)
$ Change
 
2018
 
2017
 
 
2018
 
2017
 
Net income (loss)
$
105

 
$
(26
)
 
$
131

 
$
(201
)
 
$
52

 
$
(253
)
Income tax expense (benefit)
(74
)
 
(8
)
 
(66
)
 
(163
)
 
33

 
(196
)
Interest expense and related charges
146

 
69

 
77

 
137

 
93

 
44

Depreciation and amortization
409

 
189

 
220

 
582

 
389

 
193

EBITDA before Adjustments
586

 
224

 
362

 
355

 
567

 
(212
)
Unrealized net (gain) loss resulting from hedging transactions
(216
)
 
67

 
(283
)
 
199

 
(54
)
 
253

Fresh start/purchase accounting impacts
25

 
24

 
1

 
35

 
51

 
(16
)
Impacts of Tax Receivable Agreement
64

 
22

 
42

 
82

 
42

 
40

Reorganization items and restructuring expenses
1

 
5

 
(4
)
 
2

 
9

 
(7
)
Non-cash compensation expenses
42

 
4

 
38

 
48

 
9

 
39

Transition and merger expenses
156

 
3

 
153

 
184

 
4

 
180

Other, net
—

 
(4
)
 
4

 
(6
)
 
(7
)
 
1

Adjusted EBITDA
$
658

 
$
345

 
$
313

 
$
899

 
$
621

 
$
278


 
Three Months Ended June 30, 2018
 
Retail
 
ERCOT
 
PJM
 
NY/NE
 
MISO
 
Asset
Closure
 
Eliminations / Corporate and Other
 
Vistra
Energy Consolidated
Net income (loss)
$
(288
)
 
$
679

 
$
23

 
$
(5
)
 
$
31

 
$
2

 
$
(337
)
 
$
105

Income tax expense (benefit)
—

 
—

 
—

 
—

 
—

 
—

 
(74
)
 
(74
)
Interest expense and related charges
—

 
7

 
2

 
1

 
—

 
—

 
136

 
146

Depreciation and amortization (a)
80

 
128

 
125

 
49

 
3

 
—

 
24

 
409

EBITDA before Adjustments
(208
)
 
814

 
150

 
45

 
34

 
2

 
(251
)
 
586

Unrealized net (gain) loss resulting from hedging transactions
462

 
(667
)
 
(1
)
 
22

 
(32
)
 
—

 
—

 
(216
)
Fresh start/purchase accounting impacts
15

 
(2
)
 
(1
)
 
4

 
8

 
1

 
—

 
25

Impacts of Tax Receivable Agreement
—

 
—

 
—

 
—

 
—

 
—

 
64

 
64

Non-cash compensation expenses
—

 
—

 
—

 
—

 
—

 
—

 
42

 
42

Transition and merger expenses
—

 
2

 
1

 
—

 
3

 
2

 
148

 
156

Other, net
(9
)
 
(4
)
 
5

 
3

 
5

 
—

 
1

 
1

Adjusted EBITDA
$
260

 
$
143

 
$
154

 
$
74

 
$
18

 
$
5

 
$
4

 
$
658

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


62

 
Three Months Ended June 30, 2017
 
Retail
 
ERCOT
 
Asset
Closure
 
Eliminations / Corporate and Other
 
Vistra
Energy Consolidated
Net income (loss)
$
183

 
$
(155
)
 
$
50

 
$
(104
)
 
$
(26
)
Income tax expense (benefit)
—

 
—

 
—

 
(8
)
 
(8
)
Interest expense and related charges
—

 
4

 
—

 
65

 
69

Depreciation and amortization (a)
108

 
71

 
—

 
10

 
189

EBITDA before Adjustments
291

 
(80
)
 
50

 
(37
)
 
224

Unrealized net (gain) loss resulting from hedging transactions
(89
)
 
157

 
—

 
(1
)
 
67

Fresh start accounting impacts
20

 
—

 
4

 
—

 
24

Impacts of Tax Receivable Agreement
—

 
—

 
—

 
22

 
22

Non-cash compensation expenses
—

 
—

 
—

 
4

 
4

Transition and merger expenses
1

 
2

 
—

 
—

 
3

Other, net
(4
)
 
3

 
—

 
2

 
1

Adjusted EBITDA
$
219

 
$
82

 
$
54

 
$
(10
)
 
$
345

____________
(a)
Includes nuclear fuel amortization of $17 million in ERCOT segment.

 
Six Months Ended June 30, 2018
 
Retail
 
ERCOT
 
PJM
 
NY/NE
 
MISO
 
Asset
Closure
 
Eliminations / Corporate and Other
 
Vistra
Energy Consolidated
Net income (loss)
$
483

 
$
(407
)
 
$
23

 
$
(5
)
 
$
31

 
$
(20
)
 
$
(306
)
 
$
(201
)
Income tax expense (benefit)
—

 
—

 
—

 
—

 
—

 
—

 
(163
)
 
(163
)
Interest expense and related charges
1

 
15

 
2

 
1

 
—

 
—

 
118

 
137

Depreciation and amortization (a)
157

 
213

 
125

 
49

 
3

 
—

 
35

 
582

EBITDA before Adjustments
641

 
(179
)
 
150

 
45

 
34

 
(20
)
 
(316
)
 
355

Unrealized net (gain) loss resulting from hedging transactions
(193
)
 
403

 
(1
)
 
22

 
(32
)
 
—

 
—

 
199

Fresh start/purchase accounting impacts
27

 
(4
)
 
(1
)
 
4

 
8

 
1

 
—

 
35

Impacts of Tax Receivable Agreement
—

 
—

 
—

 
—

 
—

 
—

 
82

 
82

Non-cash compensation expenses
—

 
—

 
—

 
—

 
—

 
—

 
48

 
48

Transition and merger expenses
—

 
4

 
1

 
—

 
3

 
2

 
174

 
184

Other, net
(21
)
 
(12
)
 
5

 
3

 
5

 
—

 
16

 
(4
)
Adjusted EBITDA
$
454

 
$
212

 
$
154

 
$
74

 
$
18

 
$
(17
)
 
$
4

 
$
899

____________
(a)
Includes nuclear fuel amortization of $40 million in ERCOT segment.


63

 
Six Months Ended June 30, 2017
 
Retail
 
ERCOT
 
Asset
Closure
 
Eliminations / Corporate and Other
 
Vistra
Energy Consolidated
Net income (loss)
$
70

 
$
147

 
$
37

 
$
(202
)
 
$
52

Income tax expense (benefit)
—

 
—

 
—

 
33

 
33

Interest expense and related charges
—

 
5

 
—

 
88

 
93

Depreciation and amortization (a)
214

 
154

 
—

 
21

 
389

EBITDA before Adjustments
284

 
306

 
37

 
(60
)
 
567

Unrealized net (gain) loss resulting from hedging transactions
73

 
(127
)
 
—

 
—

 
(54
)
Fresh start accounting impacts
44

 
(1
)
 
8

 
—

 
51

Impacts of Tax Receivable Agreement
—

 
—

 
—

 
42

 
42

Non-cash compensation expenses
—

 
—

 
—

 
9

 
9

Transition and merger expenses
1

 
3

 
—

 
—

 
4

Other, net
(6
)
 
4

 
—

 
4

 
2

Adjusted EBITDA
$
396

 
$
185

 
$
45

 
$
(5
)
 
$
621

____________
(a)
Includes nuclear fuel amortization of $47 million in ERCOT segment.

Adjusted EBITDA increased by $313 million to $658 million in the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily due to the following:
PJM, MISO and NY/NE segments acquired in the Merger
$
246

Increase in ERCOT segment driven by operations acquired in the Merger and the impact of the Comanche Peak outage in 2017
61

Increase in Retail segment driven by favorable impacts of weather in ERCOT
41

Decrease in Asset Closure segment driven by retirement of facilities in first quarter of 2018, partially offset by the change in estimates for certain AROs
(49
)
Corporate and Other
14

Total
$
313


Adjusted EBITDA increased by $278 million to $899 million in the six months ended June 30, 2018 compared to the six months ended June 30, 2017, primarily due to the following:
PJM, MISO and NY/NE segments acquired in the Merger
$
246

Increase in ERCOT segment driven by operations acquired in the Merger and the impact of the Comanche Peak outage in 2017, partially offset by partial Odessa earn-out buybacks
27

Increase in Retail segment driven by favorable impacts of weather in ERCOT
58

Decrease in Asset Closure segment driven by retirement of facilities in first quarter of 2018, partially offset by the change in estimates for certain AROs
(62
)
Corporate and Other
9

Total
$
278



64

Retail Segment — Three and Six Months Ended June 30, 2018 and 2017 Compared to Three and Six Months Ended June 30, 2018 and 2017
 
Three Months Ended June 30,
 
Favorable (Unfavorable)
Change
 
Six Months Ended June 30,
 
Favorable (Unfavorable)
Change
 
2018
 
2017
 
 
2018
 
2017
 
Operating revenues:
 
 
 
 
 
 
 
 
 
 
 
Revenues in ERCOT
$
1,111

 
$
964

 
$
147

 
$
2,059

 
$
1,796

 
$
263

Revenues in Northeast/Midwest
336

 
—

 
336

 
336

 
—

 
336

Amortization expense
(15
)
 
(20
)
 
5

 
(27
)
 
(44
)
 
17

Other revenues
22

 
42

 
(20
)
 
58

 
98

 
(40
)
Total operating revenues
1,454

 
986

 
468

 
2,426

 
1,850

 
576

Fuel, purchased power costs and delivery fees:
 
 
 
 
 
 
 
 
 
 
 
Purchases from affiliates
(716
)
 
(361
)
 
(355
)
 
(1,061
)
 
(669
)
 
(392
)
Unrealized net gains (losses) on hedging activities with affiliates
(463
)
 
88

 
(551
)
 
180

 
(82
)
 
262

Delivery fees
(383
)
 
(321
)
 
(62
)
 
(715
)
 
(615
)
 
(100
)
Other costs
(4
)
 
(2
)
 
(2
)
 
(5
)
 
(2
)
 
(3
)
Total fuel, purchased power costs and delivery fees
(1,566
)
 
(596
)
 
(970
)
 
(1,601
)
 
(1,368
)
 
(233
)
Operating costs
(9
)
 
(3
)
 
(6
)
 
(13
)
 
(7
)
 
(6
)
Depreciation and amortization
(80
)
 
(108
)
 
28

 
(157
)
 
(214
)
 
57

Selling, general and administrative expenses
(102
)
 
(103
)
 
1

 
(200
)
 
(204
)
 
4

Operating income (loss)
(303
)
 
176

 
(479
)
 
455

 
57

 
398

Other income
15

 
7

 
8

 
29

 
13

 
16

Interest expense and related charges
—

 
—

 
—

 
(1
)
 
—

 
(1
)
Net income (loss)
$
(288
)
 
$
183

 
$
(471
)
 
$
483

 
$
70

 
$
413

Interest expense and related charges
—

 
—

 
—

 
1

 
—

 
1

Depreciation and amortization
80

 
108

 
(28
)
 
157

 
214

 
(57
)
EBITDA
(208
)
 
291

 
(499
)
 
641

 
284

 
357

Unrealized net gains (losses) on hedging activities
462

 
(89
)
 
551

 
(193
)
 
73

 
(266
)
Fresh start/purchase accounting impacts
15

 
20

 
(5
)
 
27

 
44

 
(17
)
Transition and merger expenses
—

 
1

 
(1
)
 
—

 
1

 
(1
)
Other, net
(9
)
 
(4
)
 
(5
)
 
(21
)
 
(6
)
 
(15
)
Adjusted EBITDA
$
260

 
$
219

 
$
41

 
$
454

 
$
396

 
$
58

Sales volumes (GWh):
 
 
 
 
 
 
 
 
 
 
 
Retail electricity sales volumes:
 
 
 
 
 
 
 
 
 
 
 
Sales volumes in ERCOT
10,861

 
9,711

 
1,150

 
20,053

 
17,861

 
2,192

Sales volumes in Northeast/Midwest
6,319

 
—

 
6,319

 
6,319

 
—

 
6,319

Total retail electricity sales volumes
17,180

 
9,711

 
7,469

 
26,372

 
17,861

 
8,511

Weather (North Texas average) - percent of normal (a):
 
 
 
 
 
 
 
 
 
 
 
Cooling degree days
118.9
%
 
93.0
%
 
 
 
120.2
%
 
101.4
%
 
 
Heating degree days
181.8
%
 
42.2
%
 
 
 
101.0
%
 
60.2
%
 
 
____________
(a)
Weather data is obtained from Weatherbank, Inc. For the three and six months ended June 30, 2018, normal is defined as the average over the 10-year period from 2007 to 2016. For the three and six months ended June 30, 2017, normal is defined as the average over the 10-year period from 2006 to 2015.

65

Net income (loss) decreased by $471 million to a net loss of $288 million in the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily due to the following:
Unfavorable impact of unrealized net losses on hedging activities
$
(551
)
Favorable margins primarily due to weather in ERCOT
38

Lower depreciation and amortization expenses driven by the retail customer relationship
28

Increased intercompany interest income and decreased corporate allocated costs
6

Lower impact from fresh start and purchase accounting related to retail contracts
5

Other
3

Total
$
(471
)

Net income increased by $413 million to $483 million in the six months ended June 30, 2018 compared to the six months ended June 30, 2017, primarily due to the following:
Favorable impact of unrealized net gains on hedging activities
$
266

Lower depreciation and amortization expenses driven by the retail customer relationship
57

Favorable margins primarily due to weather in ERCOT
54

Lower impact from fresh start and purchase accounting related to retail contracts
17

Increased intercompany interest income
15

Other
4

Total
$
413


Adjusted EBITDA increased by $41 million to $260 million in the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily due to the following:
Favorable margins primarily due to weather in ERCOT
$
38

Other
3

Total
$
41


Adjusted EBITDA increased by $58 million to $454 million in the six months ended June 30, 2018 compared to the six months ended June 30, 2017, primarily due to the following:
Favorable margins primarily due to weather in ERCOT
$
54

Other
4

Total
$
58



66

ERCOT Segment — Three and Six Months Ended June 30, 2018 Compared to Three and Six Months Ended June 30, 2017
 
Three Months Ended June 30,
 
Favorable (Unfavorable)
Change
 
Six Months Ended June 30,
 
Favorable (Unfavorable)
Change
 
2018
 
2017
 
 
2018
 
2017
 
Operating revenues:
 
 
 
 
 
 
 
 
 
 
 
Wholesale electricity sales
$
254

 
$
95

 
$
159

 
$
445

 
$
273

 
$
172

Sales to affiliates
405

 
361

 
44

 
751

 
669

 
82

Rolloff of unrealized net gains (losses) representing positions settled in the current period
131

 
(49
)
 
180

 
167

 
(90
)
 
257

Unrealized net gains (losses) from changes in fair value
102

 
(10
)
 
112

 
(359
)
 
156

 
(515
)
Unrealized net gains (losses) on hedging activities with affiliates
435

 
(88
)
 
523

 
(208
)
 
82

 
(290
)
Other revenues
—

 
10

 
(10
)
 
(2
)
 
14

 
(16
)
Operating revenues
$
1,327

 
$
319

 
$
1,008

 
794

 
1,104

 
(310
)
Fuel, purchased power costs and delivery fees:
 
 
 
 
 
 
 
 
 
 
 
Fuel for generation facilities and purchased power costs
(300
)
 
(213
)
 
(87
)
 
(555
)
 
(426
)
 
(129
)
Unrealized (gains) losses from hedging activities
(2
)
 
(8
)
 
6

 
(3
)
 
(21
)
 
18

Ancillary and other costs
(35
)
 
(24
)
 
(11
)
 
(69
)
 
(49
)
 
(20
)
Fuel, purchased power costs and delivery fees
(337
)
 
(245
)
 
(92
)
 
(627
)
 
(496
)
 
(131
)
Operating costs
(182
)
 
(140
)
 
(42
)
 
(347
)
 
(293
)
 
(54
)
Depreciation and amortization
(108
)
 
(54
)
 
(54
)
 
(173
)
 
(107
)
 
(66
)
Selling, general and administrative expenses
(20
)
 
(32
)
 
12

 
(56
)
 
(59
)
 
3

Operating income (loss)
680

 
(152
)
 
832

 
(409
)
 
149

 
(558
)
Other income
8

 
4

 
4

 
20

 
7

 
13

Other deductions
(2
)
 
(3
)
 
1

 
(3
)
 
(4
)
 
1

Interest expense and related charges
(7
)
 
(4
)
 
(3
)
 
(15
)
 
(5
)
 
(10
)
Net income (loss)
$
679

 
$
(155
)
 
$
834

 
$
(407
)
 
$
147

 
$
(554
)
Interest expense and related charges
7

 
4

 
3

 
15

 
5

 
10

Depreciation and amortization (including nuclear fuel amortization)
128

 
71

 
57

 
213

 
154

 
59

EBITDA
814

 
(80
)
 
894

 
(179
)
 
306

 
(485
)
Unrealized net gains (losses) on hedging activities
(667
)
 
157

 
(824
)
 
403

 
(127
)
 
530

Fresh start/purchase accounting impacts
(2
)
 
—

 
(2
)
 
(4
)
 
(1
)
 
(3
)
Generation plant retirement expenses
—

 
—

 
—

 
—

 
(2
)
 
2

Reorganization items and restructuring expenses
—

 
1

 
(1
)
 
—

 
1

 
(1
)
Transition and merger expenses
2

 
2

 
—

 
4

 
3

 
1

Other, net
(4
)
 
2

 
(6
)
 
(12
)
 
5

 
(17
)
Adjusted EBITDA
$
143

 
$
82

 
$
61

 
$
212

 
$
185

 
$
27

Production volumes (GWh):
 
 
 
 
 
 
 
 
 
 
 
Nuclear facilities
5,279

 
3,457

 
1,822

 
10,547

 
8,710

 
1,837

Lignite and coal facilities
6,967

 
6,451

 
516

 
12,403

 
12,164

 
239

Natural gas facilities
8,030

 
3,952

 
4,078

 
14,421

 
7,470

 
6,951

Solar facilities
134

 
—

 
134

 
134

 
—

 
134


67

 
Three Months Ended June 30,
 
Favorable (Unfavorable)
Change
 
Six Months Ended June 30,
 
Favorable (Unfavorable)
Change
 
2018
 
2017
 
 
2018
 
2017
 
Capacity factors:
 
 
 
 
 
 
 
 
 
 
 
Nuclear facilities
105.1
%
 
68.8
%
 
 
 
105.6
%
 
87.2
%
 
 
Lignite and coal facilities
71.8
%
 
76.7
%
 
 
 
68.8
%
 
72.7
%
 
 
CCGT facilities
47.2
%
 
59.5
%
 
 
 
55.9
%
 
56.9
%
 
 
Market pricing:
 
 
 
 
 
 
 
 
 
 
 
Average ERCOT North power price ($/MWh)
$
27.76

 
$
24.05

 
$
3.71

 
$
26.59

 
$
22.63

 
$
3.96


Net income increased by $834 million to $679 million in the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily due to the following:
Favorable impact of unrealized net gains on hedging activities
$
824

Operating results driven by operations acquired in the Merger
24

Impact related to Comanche Peak outage in second quarter of 2017
28

Lower selling, general and administrative expenses
12

Insurance reimbursement for Comanche Peak in second quarter of 2018
5

Increased depreciation driven by facilities acquired in the Merger
(54
)
Partial buyback of the Odessa earn-out provision in 2018 (a)
(10
)
Other
5

Total
$
834

____________
(a)
Represents cash paid net of inception date fair value and excludes the operating income effects of the repurchased generation length.

Results decreased by $554 million to a net loss of $407 million in the six months ended June 30, 2018 compared to the six months ended June 30, 2017, primarily due to the following:
Unfavorable impact of unrealized net losses on hedging activities
$
(530
)
Increased depreciation driven by facilities acquired in the Merger
(66
)
Partial buybacks of the Odessa earn-out provision in 2018 (a)
(31
)
Impact related to Comanche Peak outage in second quarter of 2017
28

Operating results driven by operations acquired in the Merger
24

Insurance reimbursement for Comanche Peak in second quarter of 2018
5

Other
16

Total
$
(554
)
____________
(a)
Represents cash paid net of inception date fair value and excludes the operating income effects of the repurchased generation length.

Adjusted EBITDA increased by $61 million to $143 million in the three months ended June 30, 2018 compared to the three months ended June 30, 2017, primarily due to the following:
Operating results driven by operations acquired in the Merger
$
24

Lower selling, general and administrative expenses
12

Impact related to Comanche Peak outage in second quarter of 2017
28

Insurance reimbursement for Comanche Peak in second quarter of 2018
5

Partial buybacks of the Odessa earn-out provision in 2018
(10
)
Other
2

Total
$
61



68

Adjusted EBITDA increased by $27 million to $212 million in the six months ended June 30, 2018 compared to the six months ended June 30, 2017, primarily due to the following:
Operating results driven by operations acquired in the Merger
$
24

Impact related to Comanche Peak outage in second quarter of 2017
28

Insurance reimbursement for Comanche Peak in second quarter of 2018
5

Partial buybacks of the Odessa earn-out provision in 2018
(31
)
Other
1

Total
$
27


PJM Segment — Three and Six Months Ended June 30, 2018
 
Three and Six Months Ended
June 30, 2018
Operating revenues:
 
Energy
$
207

Capacity
119

Unrealized net gains on hedging activities
6

Sales to affiliates
168

Unrealized net losses on hedging activities with affiliates
(16
)
Other revenues
1

Operating revenues
485

Fuel, purchased power costs and delivery fees:
 
Fuel for generation facilities and purchased power costs
(243
)
Fuel for generation facilities and purchased power costs from affiliates
(6
)
Unrealized gains from hedging activities
11

Other costs
(1
)
Fuel, purchased power costs and delivery fees
(239
)
Operating costs
(82
)
Depreciation and amortization
(125
)
Selling, general and administrative expenses
(15
)
Operating income
24

Interest expense and related charges
(2
)
Equity in earnings of unconsolidated investment
1

Net income
$
23

Interest expense and related charges
2

Depreciation and amortization
125

EBITDA
150

Unrealized net gains on hedging activities
(1
)
Purchase accounting adjustments
(1
)
Transition and merger expenses
1

Other, net
5

Adjusted EBITDA
$
154

Production volumes (GWh)
11,250

Capacity factors:
 
CCGT facilities
65.0
%
Coal facilities
48.7
%
Weather - percent of normal (a):
 
Cooling degree days
125.8
%
Heating degree days
112.0
%

69

 
Three and Six Months Ended
June 30, 2018
Average Market On-Peak Power Prices ($/MWh) (b):
 
PJM West
$
39.81

AD Hub
$
40.04

Average natural gas price - TetcoM3 ($/MMBtu) (c)
$
2.40

____________
(a) Reflects cooling degree days or heating degree days for the PJM Region based on Weather Services International (WSI) data for second quarter of 2018 only.
(b) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized for second quarter of 2018 only.
(c) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us for second quarter of 2018 only.

Net income totaled $23 million in both the three and six months ended June 30, 2018, primarily reflecting the following:
Generation revenue net of fuel on 11,250 GWh of production
$
126

Capacity revenue
119

Depreciation and amortization
(125
)
Operating costs
(82
)
Selling, general and administrative expenses
(15
)
Unrealized net gains on hedging activities
1

Other
(1
)
Total
$
23


Adjusted EBITDA totaled $154 million in both the three and six months ended June 30, 2018, primarily reflecting the following:
Generation revenue net of fuel on 11,250 GWh of production
$
126

Capacity revenue, net of capacity expense
119

Operating costs
(82
)
Selling, general and administrative expenses
(15
)
Equity income from unconsolidated investment and other
6

Total
$
154



70

NY/NE Segment — Three and Six Months Ended June 30, 2018
 
Three and Six Months Ended
June 30, 2018
Operating revenues:
 
Energy
$
116

Capacity
82

Unrealized net losses on hedging activities
(20
)
Sales to affiliates
16

Unrealized net losses on hedging activities with affiliates
(4
)
Other revenues
(3
)
Operating revenues
187

Fuel, purchased power costs and delivery fees:
 
Fuel for generation facilities and purchased power costs
(107
)
Fuel for generation facilities and purchased power costs from affiliates
(2
)
Unrealized gains from hedging activities
2

Other costs
(1
)
Fuel, purchased power costs and delivery fees
(108
)
Operating costs
(25
)
Depreciation and amortization
(49
)
Selling, general and administrative expenses
(12
)
Operating loss
(7
)
Interest expense and related charges
(1
)
Equity in earnings of unconsolidated investment
3

Net loss
$
(5
)
Interest expense and related charges
1

Depreciation and amortization
49

EBITDA
45

Unrealized net gains (losses) on hedging activities
22

Purchase accounting adjustments
4

Other, net
3

Adjusted EBITDA
$
74

Production volumes (GWh)
3,765

Capacity Factor for CCGT Facilities
40.0
%
Weather - percent of normal (a):
 
Cooling degree days
103.0
%
Heating degree days
114.3
%
Average Market On-Peak Power Prices ($/MWh) (b):
 
New York - Zone C
$
31.03

Mass Hub
$
36.15

Average natural gas price - Algonquin Citygates ($/MMBtu) (c)
$
3.31

____________
(a) Reflects cooling degree days or heating degree days for the ISO-NE Region based on WSI data for second quarter of 2018 only.
(b) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized for second quarter of 2018 only.
(c) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us for second quarter of 2018 only.


71

Net loss totaled $5 million in both the three and six months ended June 30, 2018, primarily reflecting the following:
Capacity revenue
$
82

Generation revenue net of fuel on 3,765 GWh of production
19

Depreciation and amortization
(49
)
Operating costs
(25
)
Unrealized net losses on hedging activities
(22
)
Selling, general and administrative expenses
(12
)
Other
2

Total
(5
)

Adjusted EBITDA totaled $74 million in both the three and six months ended June 30, 2018, primarily reflecting the following:
Capacity revenue
$
82

Generation revenue net of fuel on 3,765 GWh of production
19

Operating costs
(25
)
Other
(2
)
Total
$
74



72

MISO Segment — Three and Six Months Ended June 30, 2018
 
Three and Six Months Ended
June 30, 2018
Operating revenues:
 
Energy
$
81

Capacity
29

Unrealized net losses on hedging activities
(18
)
Sales to affiliates
115

Unrealized net gains on hedging activities with affiliates
48

Other revenues
2

Operating revenues
257

Fuel, purchased power costs and delivery fees:
 
Fuel for generation facilities and purchased power costs
(134
)
Unrealized gains from hedging activities
2

Other costs
(1
)
Fuel, purchased power costs and delivery fees
(133
)
Operating costs
(76
)
Depreciation and amortization
(3
)
Selling, general and administrative expenses
(14
)
Operating income
31

Interest expense and related charges
—

Net income
$
31

Depreciation and amortization
3

EBITDA
34

Unrealized net gains on hedging activities
(32
)
Purchase accounting adjustments
8

Transition and merger expenses
3

Other, net
5

Adjusted EBITDA
$
18

Production volumes (GWh)
6,340

Capacity Factor for Coal Facilities
60.6
%
Weather - percent of normal (a):
 
Cooling degree days
167.8
%
Heating degree days
109.0
%
____________
(a) Reflects cooling degree days or heating degree days for the MISO Region based on WSI data for second quarter of 2018 only.

Net income totaled $31 million in both the three and six months ended June 30, 2018, primarily reflecting the following:
Generation revenue net of fuel on 6,340 GWh of production
$
63

Capacity revenue
29

Unrealized net gains on hedging activities
32

Operating costs
(76
)
Selling, general and administrative expenses
(14
)
Depreciation and amortization
(3
)
Total
31



73

Adjusted EBITDA totaled $18 million in both the three and six months ended June 30, 2018, primarily reflecting the following:
Generation revenue net of fuel on 6,340 GWh of production
$
63

Capacity revenue
29

Operating costs
(76
)
Other
2

Total
$
18


Asset Closure Segment — Three and Six Months Ended June 30, 2018 Compared to Three and Six Months Ended June 30, 2017
 
Three Months Ended June 30,
 
Favorable (Unfavorable)
Change
 
Six Months Ended June 30,
 
Favorable (Unfavorable)
Change
 
2018
 
2017
 
 
2018
 
2017
 
Operating revenues
$
21

 
$
265

 
$
(244
)
 
$
49

 
$
451

 
$
(402
)
Fuel, purchased power costs and delivery fees
(10
)
 
(161
)
 
151

 
(36
)
 
(300
)
 
264

Operating costs
(6
)
 
(52
)
 
46

 
(30
)
 
(109
)
 
79

Depreciation and amortization
—

 
—

 
—

 
—

 
—

 
—

Selling, general and administrative expenses
(4
)
 
(4
)
 
—

 
(5
)
 
(9
)
 
4

Operating income (loss)
1

 
48

 
(47
)
 
(22
)
 
33

 
(55
)
Other income
1

 
2

 
(1
)
 
2

 
4

 
(2
)
Net income (loss)
$
2

 
$
50

 
$
(48
)
 
$
(20
)
 
$
37

 
$
(57
)
Fresh start accounting impacts
1

 
4

 
(3
)
 
1

 
8

 
(7
)
Transition and merger expenses
2

 
—

 
2

 
2

 
—

 
2

Adjusted EBITDA
$
5

 
$
54

 
$
(49
)
 
$
(17
)
 
$
45

 
$
(62
)
Production volumes (GWh)
445

 
6,708

 
(6,263
)
 
1,515

 
11,568

 
(10,053
)

Results for the Asset Closure segment reflect the retirement of the Stuart and Killen plants in May 2018 (acquired in the Merger) and the retirement of the Monticello, Sandow and Big Brown plants in January and February 2018 (see Note 4 to the Financial Statements) and corresponding 93% and 87% decreases in volume in the three and six months ended June 30, 2018, respectively. Operating costs for the three and six months ended June 30, 2018 included ongoing costs associated with closing these plants as well as a favorable adjustment to the estimated asset retirement obligation of $21 million.


74

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

The table below summarizes the changes in commodity contract assets and liabilities for the six months ended June 30, 2018 and 2017. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $199 million in unrealized net losses for the six months ended June 30, 2018 and $54 million in unrealized net gains for the six months ended June 30, 2017 arising from mark-to-market accounting for positions in the commodity contract portfolio.
 
Six Months Ended June 30,
 
2018
 
2017
Commodity contract net asset (liability) at beginning of period
$
(96
)
 
$
64

Settlements/termination of positions (a)
165

 
(107
)
Changes in fair value of positions in the portfolio (b)
(364
)
 
161

Acquired commodity contracts in Merger (c)
(452
)
 
—

Other activity (d)
80

 
(12
)
Commodity contract net asset (liability) at end of period
$
(667
)
 
$
106

____________
(a)
Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). The six months ended June 30, 2018 and 2017 includes reversal of $17 million and $49 million, respectively, of previously recorded unrealized gains related to Vistra Energy beginning balances. The six months ended June 30, 2018 also includes reversal of $23 million of previously recorded unrealized losses related to commodity contracts acquired in the Merger. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.
(b)
Represents unrealized net gains (losses) recognized, reflecting the effect of changes in fair value. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.
(c)
Includes fair value of commodity contracts acquired at the Merger Date (see Note 2 to the Financial Statements).
(d)
Represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses. Amounts are generally related to premiums related to options purchased or sold as well as certain margin deposits classified as settlement for certain transactions on the CME.

Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair values at June 30, 2018, scheduled by the source of fair value and contractual settlement dates of the underlying positions.
 
 
Maturity dates of unrealized commodity contract net liability at June 30, 2018
Source of fair value
 
Less than
1 year
 
1-3 years
 
4-5 years
 
Excess of
5 years
 
Total
Prices actively quoted
 
$
(56
)
 
$
(19
)
 
$
(1
)
 
$
—

 
$
(76
)
Prices provided by other external sources
 
(175
)
 
(194
)
 
—

 
—

 
(369
)
Prices based on models
 
(45
)
 
(150
)
 
(26
)
 
(1
)
 
(222
)
Total
 
$
(276
)
 
$
(363
)
 
$
(27
)
 
$
(1
)
 
$
(667
)


75


FINANCIAL CONDITION

Cash Flows

Six Months Ended June 30, 2018 Compared to Six Months ended June 30, 2017 — Cash used in operating activities totaled $29 million in the six months ended June 30, 2018 compared to cash provided by operating activities of $333 million in the six months ended June 30, 2017. The unfavorable change of $362 million was primarily driven by an increase in cash used for margin deposits related to derivative contracts. In addition, interest paid increased due to the assumption of long-term debt obligations in the Merger.

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 $77 million and $96 million for the six months ended June 30, 2018 and 2017, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the statements of consolidated income (loss) consistent with industry practice, and amortization of intangible net assets and liabilities that are reported in various other statements of condensed consolidated income (loss) line items including operating revenues and fuel and purchased power costs and delivery fees.

Cash used in financing activities totaled $1.443 billion and $27 million in the six months ended June 30, 2018 and 2017, respectively. The increase in cash used in financing activities was driven by the amendment to the Vistra Operations Credit Facilities, including the repayment of $500 million of borrowings under the Term Loan C Facility (see Note 10 to the Financial Statements). In addition, cash used in financing activities in 2018 reflected the redemption of $850 million principal amount of outstanding 6.75% Senior Notes in May 2018 (see Note 10 to the Financial Statements) and $63 million of cash paid for share repurchases in June 2018 (see Note 12 to the Financial Statements).

Cash provided by investing activities totaled $242 million in the six months ended June 30, 2018 compared to cash used in investing activities of $194 million in the six months ended June 30, 2017, respectively. Cash provided by investing activities in 2018 reflected $445 million of cash acquired in the Merger. Capital expenditures (including nuclear fuel purchases) totaled $181 million and $98 million in the six months ended June 30, 2018 and 2017, respectively.

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 six months ended June 30, 2018:
 
June 30, 2018
 
December 31, 2017
 
Change
Cash and cash equivalents (a)
$
757

 
$
1,487

 
$
(730
)
Vistra Operations Credit Facilities — Revolving Credit Facility
1,065

 
834

 
231

Vistra Operations Credit Facilities — Term Loan C Facility (b)
—

 
7

 
(7
)
Total available liquidity
$
1,822

 
$
2,328

 
$
(506
)
___________
(a)
Cash and cash equivalents excludes $500 million of restricted cash held for letter of credit support at December 31, 2017 (see Note 19 to the Financial Statements).
(b)
The Term Loan C Facility was used for issuing letters of credit for general corporate purposes. Borrowings totaling $500 million under this facility were held in collateral accounts at December 31, 2017, and were reported as restricted cash in our condensed consolidated balance sheets. In June 2018, the Vistra Operations Credit Facilities were amended, and the Term Loan C Facility was repaid using $500 million of cash from the collateral accounts used to backstop letters of credit.

The decrease in available liquidity to $1.822 billion in the six months ended June 30, 2018 was primarily driven by the redemption of $850 million principal amount of outstanding 6.75% Senior Notes in May 2018, decreased available cash from operations reflecting an increase in cash used for margin deposits and $63 million in cash paid for share repurchases in June 2018, partially offset by cash acquired in the Merger and increased available capacity under the Revolving Credit Facility.


76

Based upon our current internal financial forecasts, we believe that we will have sufficient liquidity to fund our anticipated cash requirements through at least the next 12 months. Our operational cash flows tend to be seasonal and weighted toward the second half of the year.

Capital Expenditures

Estimated capital expenditures and nuclear fuel purchases for 2018 are expected to total approximately $500 million and include:

•
$323 million for investments in generation and mining facilities:
•
$118 million for nuclear fuel purchases, and
•
$59 million for information technology and other corporate investments.

Liquidity Effects of Commodity Hedging and Trading Activities

We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. We use cash, letters of credit and other forms of credit support to satisfy such collateral posting obligations. See Note 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 June 30, 2018, we received or posted cash and letters of credit for commodity hedging and trading activities as follows:

•
$200 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;
•
$1.221 billion in letters of credit have been posted with counterparties as compared to $390 million posted at December 31, 2017, and
•
$11 million in letters of credit have been received from counterparties as compared to $3 million received at December 31, 2017.

Income Tax Payments

In the next twelve months, we do not expect to make federal income tax payments due to Vistra Energy's forecasted taxable loss position in 2018. We expect to make state income tax payments of approximately $22 million and TRA payments of approximately $25 million in the next twelve months. There were $58 million and $43 million of income tax payments for the six months ended June 30, 2018 and 2017, respectively.

Capitalization

Our capitalization ratios consisted of 58% and 41% long-term debt (less amounts due currently) and 42% and 59% shareholders' equity at June 30, 2018 and December 31, 2017, respectively. Total borrowings under the Vistra Energy Operations Facilities and other long-term debt to capitalization was 59% and 41% at June 30, 2018 and December 31, 2017, respectively.


77

Financial Covenants

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

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 June 30, 2018, Vistra Energy has posted letters of credit in the amount of $55 million with the PUCT, which is subject to adjustments.

The ISOs we operate in have rules in place to assure adequate creditworthiness of parties that participate in the markets operated by those ISOs. Under these rules, Vistra Energy has posted collateral support, in the form of letters of credit, totaling $255 million at June 30, 2018 (which is subject to daily adjustments based on settlement activity with the ISO).

Material Cross Default/Acceleration Provisions

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

A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of $300 million may result in a cross default under the Vistra Operations Credit Facilities. Such a default would allow the lenders to accelerate the maturity of outstanding balances (approximately $5.8 billion at June 30, 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.

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

Additionally, we enter into energy-related physical and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess of thresholds, which may vary by contract.


78

Contractual Obligations and Commitments

The following table summarizes the amounts and related maturities of our contractual cash obligations at June 30, 2018. See Notes 10 and 11 to the Financial Statements for additional disclosures regarding debts and noncancellable purchase obligations.
 
Less Than
One Year (a)
 
One to
Three
Years
 
Three to
Five
Years
 
More
Than Five
Years
 
Total
Debt – principal, including capital leases (b)
$
85

 
$
386

 
$
1,954

 
$
9,216

 
$
11,641

Debt – interest
339

 
1,344

 
1,310

 
940

 
3,933

Operating leases
11

 
32

 
21

 
151

 
215

Obligations under commodity purchase and services agreements (c)
1,011

 
1,158

 
448

 
868

 
3,485

Total contractual cash obligations
$
1,446

 
$
2,920

 
$
3,733

 
$
11,175

 
$
19,274

___________
(a)
Represents the period from July 1 through December 31, 2018.
(b)
Includes $5.842 billion of borrowings under the Vistra Operations Credit Facilities, $5.288 billion principal amount of senior notes and $511 million principal amount of other long-term debt, including mandatorily redeemable preferred stock and capital leases. Excludes unamortized premiums, discounts and debt costs.
(c)
Includes capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear related outsourcing and other purchase commitments. Amounts presented for variable priced contracts reflect the June 29, 2018 price for all periods except where contractual price adjustment or index-based prices are specified.

The following are not included in the table above:

•
contractual service agreement obligations with respect to long-term plant maintenance agreements;
•
asset retirement obligations (see Note 19 to the Financial Statements);
•
the TRA obligation (see Note 8 to the Financial Statements);
•
arrangements between affiliated entities and intercompany debt (see Note 17 to the Financial Statements);
•
individual contracts that have an annual cash requirement of less than $1 million (however, multiple contracts with one counterparty that are more than $1 million on an aggregated basis have been included);
•
contracts that are cancellable without payment of a substantial cancellation penalty, and
•
employment contracts with management.

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.



79

Item 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Risk Oversight

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

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

Commodity Price Risk

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

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

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

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

VaR for Underlying Generation Assets and Energy-Related Contracts — This measurement estimates the potential loss in value, due to changes in market conditions, of all underlying generation assets and contracts, based on a 95% confidence level and an assumed holding period of 60 days for a forward period through December 2019.
 
Three Months
Ended
June 30, 2018
 
Year Ended December 31, 2017
Month-end average VaR:
$
143

 
$
92

Month-end high VaR:
$
205

 
$
140

Month-end low VaR:
$
65

 
$
62



80

The increase in the month-end high VaR risk measure in 2018 reflected operations acquired in the Merger and increased power price volatility.

Interest Rate Risk

At June 30, 2018, the potential reduction of annual pretax earnings over the next twelve months due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $11 million, taking into account the interest rate swaps discussed in Note 10 to Financial Statements.

Credit Risk

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

Credit Exposure — Our gross credit exposure (excluding collateral impacts) associated with retail and wholesale trade accounts receivable and net derivative assets arising from commodity contracts and hedging and trading activities totaled $1.152 billion at June 30, 2018.

At June 30, 2018, Retail segment credit exposure totaled $834 million, including $800 million of trade accounts receivable and $34 million related to derivative assets. Cash deposits and letters of credit held as collateral for these receivables totaled $41 million, resulting in a net exposure of $793 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 June 30, 2018, aggregate ERCOT, PJM, NY/NE and MISO segments credit exposure totaled $318 million including $135 million related to derivative assets and $183 million of trade accounts receivable, after taking into account master netting agreement provisions but excluding collateral impacts.

Including collateral posted to us by counterparties, our net ERCOT, PJM, NY/NE and MISO segments exposure was $303 million, substantially all of which is with investment grade customers as seen in the following table that presents the distribution of credit exposure at June 30, 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
$
284

 
$
5

 
$
279

Below investment grade or no rating
34

 
10

 
24

Totals
$
318

 
$
15

 
$
303


Significant (10% or greater) concentration of credit exposure exists with three counterparties, which represented an aggregate $176 million, or 58%, 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 June 30, 2018, interest rate swap exposure in the Corporate and Other non-segment totaled $135 million. There are no collateral offsets. The counterparty credit rating is investment grade.


81

FORWARD-LOOKING STATEMENTS

This report and other presentations made by us contain "forward-looking statements." All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that may occur in the future, including such matters as activities related to our financial or operational projections, capital allocation, capital expenditures, liquidity, dividend policy, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our businesses and operations (often, but not always, through the use of words or phrases such as "intends," "plans," "will likely," "unlikely," "expected," "anticipated," "estimated," "should," "may," "projection," "target," "goal," "objective" and "outlook"), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and risks and is qualified in its entirety by reference to the discussion under Part II, Item 1A. Risk Factors and Item 2, Management's Discussion and Analysis of Financial Condition and Results of Operations in this quarterly report on Form 10-Q and the following important factors, among others, that could cause our actual results to differ materially from those projected in or implied by such forward-looking statements:

•
the actions and decisions of regulatory authorities;
•
prohibitions and other restrictions on our operations due to the terms of our agreements;
•
prevailing governmental policies and regulatory actions, including those of the legislatures and other government actions of states in which we operate, the U.S. Congress, the FERC, the NERC, the Texas Reliability Entity, Inc., the public utility commissions of states in which we operate, CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM, the RCT, the NRC, the EPA, the environmental regulatory bodies of states in which we operate, the U.S. Mine Safety and Health Administration and the U.S. Commodity Futures Trading Commission, with respect to, among other things:
◦
allowed prices;
◦
industry, market and rate structure;
◦
purchased power and recovery of investments;
◦
operations of nuclear generation facilities;
◦
operations of fossil fueled generation facilities;
◦
operations of mines;
◦
acquisition and disposal of assets and facilities;
◦
development, construction and operation of facilities;
◦
decommissioning costs;
◦
present or prospective wholesale and retail competition;
◦
changes in tax laws and policies;
◦
changes in and compliance with environmental and safety laws and policies, including National Ambient Air Quality Standards, the Cross-State Air Pollution Rule, the Mercury and Air Toxics Standard, regional haze program implementation and greenhouse gas and other climate change initiatives, and
◦
clearing over-the-counter derivatives through exchanges and posting of cash collateral therewith;
•
expectations regarding, or impacts of, environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts, and other laws and regulations that we are, or could become, subject to, which could increase our costs, result in an impairment of our assets, cause us to limit or terminate the operation of certain of our facilities, or otherwise have a negative financial effect;
•
legal and administrative proceedings and settlements;
•
general industry trends;
•
economic conditions, including the impact of an economic downturn;
•
weather conditions, including drought and limitations on access to water, and other natural phenomena, and acts of sabotage, wars or terrorist or cyber security threats or activities;
•
our ability to collect trade receivables from counterparties;
•
our ability to attract and retain profitable customers;
•
our ability to profitably serve our customers;
•
restrictions on competitive retail pricing;
•
changes in wholesale electricity prices or energy commodity prices, including the price of natural gas;
•
changes in prices of transportation of natural gas, coal, fuel oil and other refined products;
•
sufficiency of, access to, and costs associated with coal, fuel oil, and natural gas inventories and transportation and storage thereof;
•
changes in the ability of vendors to provide or deliver commodities as needed;

82

•
beliefs and assumptions about the benefits of state- or federal-based subsidies to our market competition, and the corresponding impacts on us, including if such subsidies are disproportionately available to our competitors;
•
the effects of, our changes to, the power and capacity procurement processes in the markets in which we operate;
•
changes in market heat rates in the CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM electricity markets;
•
our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heat rates and interest rates;
•
population growth or decline, or changes in market supply or demand and demographic patterns, particularly in ERCOT, MISO and PJM;
•
our ability to mitigate forced outage risk, including managing risk associated with CP in PJM and performance incentives in ISO-NE;
•
efforts to identify opportunities to reduce congestion and improve busbar power prices;
•
access to adequate transmission facilities to meet changing demands;
•
changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;
•
changes in operating expenses, liquidity needs and capital expenditures;
•
commercial bank market and capital market conditions and the potential impact of disruptions in U.S. and international credit markets;
•
access to capital, the attractiveness of the cost and other terms of such capital and the success of financing and refinancing efforts, including availability of funds in capital markets;
•
our ability to maintain prudent financial leverage;
•
our ability to generate sufficient cash flow to make principal and interest payments in respect of, or refinance, our debt obligations;
•
our ability to implement our growth strategy, including the completion and integration of mergers, acquisitions and/or joint venture activity and identification and completion of sales and divestitures activity;
•
competition for new energy development and other business opportunities;
•
inability of various counterparties to meet their obligations with respect to our financial instruments;
•
counterparties' collateral demands and other factors affecting our liquidity position and financial condition;
•
changes in technology (including large scale electricity storage) used by and services offered by us;
•
changes in electricity transmission that allow additional power generation to compete with our generation assets;
•
our ability to attract and retain qualified employees;
•
significant changes in our relationship with our employees, including the availability of qualified personnel, and the potential adverse effects if labor disputes or grievances were to occur;
•
changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits, pension and other postretirement employee benefits, and future funding requirements related thereto, including joint and several liability exposure under ERISA;
•
hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resulting from such hazards;
•
the impact of our obligations under the TRA;
•
our ability to optimize our assets through targeted investment in cost-effective technology enhancements and operations performance initiatives;
•
our ability to effectively and efficiently plan, prepare for and execute expected asset retirements and reclamation obligations and the impacts thereof;
•
our ability to successfully integrate the businesses of Vistra Energy and Dynegy and our ability to successfully capture any projected synergies relating to the Merger, and
•
actions by credit rating agencies.

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


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INDUSTRY AND MARKET INFORMATION

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


Item 4.
CONTROLS AND PROCEDURES

An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures in effect at the end of the current period included in this quarterly report on Form 10-Q. On the Merger Date, Dynegy merged with and into Vistra Energy. The evaluation considered that Vistra Energy is currently in the process of integrating certain processes, technology and operations of the combined company and will continue to evaluate the impact of any related changes to the internal control over financial reporting. Based on the evaluation performed, our principal executive officer and principal financial officer concluded that the disclosure controls and procedures were effective. During the fiscal quarter covered by this quarterly report on Form 10-Q, other than the changes resulting from the Merger, there have been no changes in our internal control over financial reporting that have materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.


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PART II. OTHER INFORMATION

Item 1.
LEGAL PROCEEDINGS

Reference is made to the discussion in Note 11 to the Financial Statements regarding legal proceedings.


Item 1A.
RISK FACTORS

As a result of the Merger with Dynegy, which closed on April 9, 2018, below is a series of risk factors related to the Merger, Dynegy and the ongoing business operations of the combined company that amends and restates in full the risk factors discussed in Part I, Item 1A. Risk Factors in our 2017 Form 10-K. The risks described below are not the only risks facing the 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.

Market, Financial and Economic Risks

Our revenues, results of operations and operating cash flows generally may be impacted by price fluctuations in the wholesale power and natural gas, coal and oil markets and other market factors beyond our control.

We are not guaranteed any rate of return on capital investments in our businesses. We conduct integrated power generation and retail electricity activities, focusing on power generation, wholesale electricity sales and purchases, retail sales of electricity and services to end users and commodity risk management. Our wholesale and retail businesses are to some extent countercyclical in nature, particularly for the wholesale power and ancillary services supplied to the retail business. However, we do have a wholesale power position that exceeds the overall load requirements of our retail business and is subject to wholesale power price moves. As a result, our revenues, results of operations and operating cash flows depend in large part upon wholesale market prices for electricity, natural gas, uranium, lignite, coal, fuel and transportation in our regional market and other competitive markets and upon prevailing retail electricity rates, which may be impacted by, among other things, actions of regulatory authorities. Market prices for power, capacity, ancillary services, natural gas, coal and oil are unpredictable and may fluctuate substantially over relatively short periods of time. Unlike most other commodities, electric power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility due to supply and demand imbalances, especially in the day-ahead and spot markets. Demand for electricity can fluctuate dramatically, creating periods of substantial under- or over-supply. Over-supply can also occur as a result of the construction of new power plants, as we have observed in recent years. During periods of over-supply, electricity prices might be depressed. Also, at times there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, bidding rules and other mechanisms to address volatility and other issues in these markets.

The majority of our facilities operate as "merchant" facilities without long-term power sales agreements. As a result, we largely sell electric energy, capacity and ancillary services into the wholesale energy spot market or into other wholesale and retail power markets on a short-term basis and are not guaranteed any rate of return on our capital investments. Consequently, there can be no assurance that we will be able to sell any or all of the electric energy, capacity or ancillary services from those facilities at commercially attractive rates or that our facilities will be able to operate profitably. We depend, in large part, upon prevailing market prices for power, capacity and fuel. Given the volatility of commodity power prices, to the extent we do not secure long-term power sales agreements for the output of our power generation facilities, our revenues and profitability will be subject to volatility, and our financial condition, results of operations and cash flows could be materially adversely affected.

Some of the fuel for our generation facilities is purchased under short-term contracts. Fuel costs (including diesel, natural gas, lignite, coal and nuclear fuel) may be volatile, and the wholesale price for electricity may not change at the same rate as changes in fuel costs. In addition, we purchase and sell natural gas and other energy related commodities, and volatility in these markets may affect costs incurred in meeting obligations. Further, any changes in the costs of coal, fuel oil, natural gas or transportation rates and changes in the relationship between such costs and the market prices of power will affect our financial results. If we are unable to procure fuel for physical delivery at prices we consider favorable, our financial condition, results of operations and cash flows could be materially adversely affected.


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Volatility in market prices for fuel and electricity may result from, among other factors:

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volatility in commodity prices and the supply of commodities, including but not limited to natural gas, coal and oil;
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volatility in market heat rates;
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volatility in coal and rail transportation prices;
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fuel transportation capacity constraints or inefficiencies;
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volatility in nuclear fuel and related enrichment and conversion services;
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severe or unexpected weather conditions, including drought and limitations on access to water;
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seasonality;
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changes in electricity and fuel usage resulting from conservation efforts, changes in technology or other factors;
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illiquidity in the wholesale electricity or other commodity markets;
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transmission or transportation disruptions, constraints, inoperability or inefficiencies, or other changes in power transmission infrastructure;
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development and availability of new fuels, new technologies and new forms of competition for the production and storage of power, including competitively priced alternative energy sources or storage;
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changes in market structure and liquidity;
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changes in the manner in which we operate our facilities, including curtailed operation due to market pricing, environmental regulations and legislation, safety or other factors;
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changes in generation efficiency;
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outages or otherwise reduced output from our generation facilities or those of our competitors;
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changes in electric capacity, including the addition of new supplies of power as a result of the development of new plants, expansion of existing plants, the continued operation of uneconomic power plants due to federal, state or local subsidies, or additional transmission capacity;
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our creditworthiness and liquidity and the willingness of fuel suppliers and transporters to do business with us;
•
changes in the credit risk or payment practices of market participants;
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changes in production and storage levels of natural gas, lignite, coal, uranium, diesel and other refined products;
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natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events, and
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changes in law, including judicial decisions, federal, state and local energy, environmental and other regulation and legislation.

We recently announced the retirement of our Monticello, Sandow 4, Sandow 5, Big Brown, Killen and Stuart units. A sustained decrease in the financial results from, or the value of, our generation units ultimately could result in the retirement or idling of certain other generation units. In recent years, we have operated certain of our lignite- and coal-fueled generation assets only during parts of the year that have higher electricity demand and, therefore, higher related wholesale electricity prices.

Our assets or positions cannot be fully hedged against changes in commodity prices and market heat rates, and hedging transactions may not work as planned or hedge counterparties may default on their obligations.

Our hedging activities do not fully protect us against the risks associated with changes in commodity prices, most notably electricity and natural gas prices, because of the expected useful life of our generation assets and the size of our position relative to the duration of available markets for various hedging activities. Generally, commodity markets that we participate in to hedge our exposure to electricity prices and heat rates have limited liquidity after two to three years. Further, our ability to hedge our revenues by utilizing cross-commodity hedging strategies with natural gas hedging instruments is generally limited to a duration of four to five years. To the extent we have unhedged positions, fluctuating commodity prices and/or market heat rates can materially impact our results of operations, cash flows, liquidity and financial condition, either favorably or unfavorably.

To manage our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge portions of purchase and sale commitments, fuel requirements and inventories of natural gas, lignite, coal, diesel fuel, uranium and refined products, and other commodities, within established risk management guidelines. As part of this strategy, we routinely utilize fixed-price forward physical purchase and sale contracts, futures, financial swaps and option contracts traded in over-the-counter markets or on exchanges. Although we devote a considerable amount of time and effort to the establishment of risk management procedures, as well as the ongoing review of the implementation of these procedures, the procedures in place may not always function as planned and cannot eliminate all the risks associated with these activities. For example, we hedge the expected needs of our wholesale and retail customers, but unexpected changes due to weather, natural disasters, consumer behavior, market constraints or other factors could cause us to purchase electricity to meet unexpected demand in periods of high wholesale market prices or resell excess electricity into the wholesale market in periods of low prices. As a result of these and other factors, risk management decisions may have a material adverse effect on us.


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Based on economic and other considerations, we may not be able to, or we may decide not to, hedge the entire exposure of our operations from commodity price risk. To the extent we do not hedge against commodity price risk and applicable commodity prices change in ways adverse to us, we could be materially and adversely affected. To the extent we do hedge against commodity price risk, those hedges may ultimately prove to be ineffective.

With the tightening of credit markets that began in 2008 and the expansion of regulatory oversight through various financial reforms, there has been a decline in the number of market participants in the wholesale energy commodities markets, resulting in less liquidity. Notably, participation by financial institutions and other intermediaries (including investment banks) in such markets has declined. Extended declines in market liquidity could adversely affect our ability to hedge our financial exposure to desired levels.

To the extent we engage in hedging and risk management activities, we are exposed to the credit risk that counterparties that owe us money, energy or other commodities as a result of these activities will not perform their obligations to us. Should the counterparties to these arrangements fail to perform, we could be forced to enter into alternative hedging arrangements or honor the underlying commitment at then-current market prices. Additionally, our counterparties may seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the Bankruptcy Code. Our credit risk may be exacerbated to the extent collateral held by us cannot be realized or is liquidated at prices not sufficient to recover the full amount due to us. There can be no assurance that any such losses or impairments to the carrying value of our financial assets would not materially and adversely affect our financial condition, results of operations and cash flows. In such event, we could incur losses or forgo expected gains in addition to amounts, if any, already paid to the counterparties. Market participants in the Regional Transmission Organizations (RTOs) and ISOs in which we operate are also exposed to risks that another market participant may default on its obligations to pay such RTO or ISO for electricity or services taken, in which case such costs, to the extent not offset by posted security and other protections available to such RTO or ISO, may be allocated to various non-defaulting market participants in such RTO or ISO, including us.

Competition in wholesale and retail power markets, together with subsidized generation, may have a material adverse effect on our financial condition, results of operations and cash flows.

Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, other energy service companies and financial institutions in the sale of electric energy, capacity and ancillary services, as well as in the procurement of fuel, transmission and transportation services. Moreover, aggregate demand for power may be met by generation capacity based on several competing technologies, as well as power generating facilities fueled by alternative or renewable energy sources, including hydroelectric power, synthetic fuels, solar, wind, wood, geothermal, waste heat and solid waste sources. Regulatory initiatives designed to enhance and/or subsidize renewable generation increases competition from these types of facilities.

We also compete against other energy merchants on the basis of our relative operating skills, financial position and access to credit sources. Electric energy customers, wholesale energy suppliers and transporters often seek financial guarantees, credit support such as letters of credit and other assurances that their energy contracts will be satisfied. Companies with which we compete may have greater resources or experience in these areas. Over time, some of our plants may become unable to compete because of subsidized generation, including public utility commission supported power purchase agreements, and the construction of new plants. Such new plants could have a number of advantages including: more efficient equipment, newer technology that could result in fewer emissions or more advantageous locations on the electric transmission system. Additionally, these competitors may be able to respond more quickly to new laws and regulations because of the newer technology utilized in their facilities or the additional resources derived from owning more efficient facilities.

Other factors may contribute to increased competition in wholesale power markets. New forms of capital and competitors have entered the industry, including financial investors who perceive that asset values are at levels below their true replacement value. As a result, a number of generation facilities in the U.S. are now owned by lenders and investment companies. Furthermore, mergers and asset reallocations in the industry could create powerful new competitors. Under any scenario, we anticipate that we will face competition from numerous companies in the industry.


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In addition, our retail marketing efforts compete for customers in a competitive environment, which impacts the margins that we can earn on the volumes we are able to serve. Further, with retail competition, residential customers where we serve load can switch to and from competitive electric generation suppliers for their energy needs. If fewer customers switch to another supplier than anticipated, the load we must serve will be greater and, if market prices have increased, our costs will increase due to the need to go to the market to cover the incremental supply obligation. If more customers switch to another supplier than anticipated, the load we must serve will be lower and, if market prices have decreased, we could lose opportunities in the market. To the extent that competition increases, our financial condition, results of operations and cash flows may be materially adversely affected.

Certain of our competitors may receive federal- and state-based subsidies that could materially adversely affect our financial condition, results of operations and cash flows.

Certain federal and state entities in jurisdictions in which we operate have either enacted or are considering regulations or legislation to subsidize otherwise uneconomic plants, and attempt to incent the development of new renewable resources as well as increase energy efficiency investments. In addition, in December 2015, federal renewable energy tax credits, including the wind power production tax credit and solar investment tax credits, were extended as part of the Consolidated Appropriations Act of 2016. At this time, the direct impact on the organized power markets is a change in the generation supply stack created by the continued operation of subsidized resources that would retire absent the subsidies. The net combined impact of existing subsidy programs on us is uncertain at this time. Continued growth of energy subsidies could have a material adverse effect on our financial condition, results of operations and cash flows.

Our results of operations and financial condition could be materially and adversely affected if energy market participants continue to construct additional generation facilities (i.e., new-build) or expand or enhance existing generation facilities despite relatively low power prices and such additional generation capacity results in a reduction in wholesale power prices.

Given the overall attractiveness of certain of the markets in which we operate and certain tax benefits associated with renewable energy, among other matters, energy market participants have continued to construct new generation facilities (i.e., new-build) or invest in enhancements or expansions of existing generation facilities despite relatively low wholesale power prices. If this market dynamic continues, our results of operations and financial condition could be materially and adversely affected if such additional generation capacity results in an over-supply of electricity that causes a reduction in wholesale power prices.

Unauthorized hedging and related activities by our employees could result in significant losses.

We have various internal policies, processes, and controls designed to monitor hedging activities and positions. These policies, processes, and controls are designed, in part, to prevent unauthorized purchases or sales of products by our employees or alert our risk management teams of any trades that have not been entered into our risk management systems. We cannot assure, however, that these steps will detect and prevent inaccurate reporting and all potential violations of our risk management policies, processes, and controls, particularly if deception or other intentional misconduct is involved. A significant policy violation that is not detected could result in a substantial financial loss.

Our risk management policies cannot fully eliminate the risk associated with our commodity hedging activities.

Our operations and other commodity hedging activities expose us to risks of commodity price movements. We attempt to manage this exposure through enforcement of established risk limits and risk management policies and procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. As a result, we cannot fully predict the impact that our commodity hedging activities and risk management decisions may have on our business and/or financial condition, results of operations and cash flows.

Economic downturns would likely have a material adverse effect on our businesses.

Our results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including low levels in the market prices for power, generation capacity and natural gas, which can fluctuate substantially. Increased unemployment of residential customers and decreased demand for products and services by commercial and industrial customers resulting from an economic downturn could lead to declines in the demand for energy and an increase in the number of uncollectible customer balances, which would negatively impact our overall sales and cash flows. Additionally, prolonged economic downturns that negatively impact our financial condition, results of operations and cash flows could result in future material impairment charges to write down the carrying value of certain assets to their respective fair values.


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Our liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets or during times of significant fluctuation in commodity prices, and we may be unable to access capital on favorable terms or at all in the future, which could have a material adverse effect on us. We currently maintain non-investment grade credit ratings that could negatively affect our ability to access capital on favorable terms or result in higher collateral requirements, particularly if our credit ratings were to be downgraded in the future.

Our businesses are capital intensive. In general, we rely on access to financial markets and credit facilities as a significant source of liquidity for our capital requirements and other obligations not satisfied by cash-on-hand or operating cash flows. The inability to raise capital or to access credit facilities, particularly on favorable terms, could adversely impact our liquidity and our ability to meet our obligations or sustain and grow our businesses and could increase capital costs and collateral requirements, any of which could have a material adverse effect on us.

Our access to capital and the cost and other terms of acquiring capital are dependent upon, and could be adversely impacted by, various factors, including:

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general economic and capital markets conditions, including changes in financial markets that reduce available liquidity or the ability to obtain or renew credit facilities on favorable terms or at all;
•
conditions and economic weakness in the U.S. power markets;
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regulatory developments;
•
changes in interest rates;
•
a deterioration, or perceived deterioration, of our creditworthiness, enterprise value or financial or operating results;
•
a reduction in Vistra Energy's or its applicable subsidiaries' credit ratings;
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our level of indebtedness and compliance with covenants in our debt agreements;
•
a deterioration of the creditworthiness or bankruptcy of one or more lenders or counterparties under our credit facilities that affects the ability of such lender(s) to make loans to us;
•
security or collateral requirements;
•
general credit availability from banks or other lenders for us and our industry peers;
•
investor confidence in the industry and in us and the wholesale electricity markets in which we operate;
•
volatility in commodity prices that increases credit requirements;
•
a material breakdown in our risk management procedures;
•
the occurrence of changes in our businesses;
•
disruptions, constraints, or inefficiencies in the continued reliable operation of our generation facilities, and
•
changes in or the operation of provisions of tax and regulatory laws.

In addition, we currently maintain non-investment grade credit ratings. As a result, we may not be able to access capital on terms (financial or otherwise) as favorable as companies that maintain investment-grade credit ratings or we may be unable to access capital at all at times when the credit markets tighten. In addition, our non-investment grade credit ratings may result in counterparties requesting collateral support (including cash or letters of credit) in order to enter into transactions with us.

A downgrade in long-term debt ratings generally causes borrowing costs to increase and the potential pool of investors to shrink and could trigger liquidity demands pursuant to contractual arrangements. Future transactions by Vistra Energy or any of its subsidiaries, including the issuance of additional debt, could result in a temporary or permanent downgrade in our credit ratings.

Our indebtedness could adversely affect our ability in the future to raise additional capital to fund our operations. It could also expose us to the risk of increased interest rates and limit our ability to react to changes in the economy, or our industry as well as impact our cash available for distribution.

In connection with the Merger, we assumed all of Dynegy's outstanding indebtedness. As of June 30, 2018, we had approximately $11.8 billion of total indebtedness and approximately $11.0 billion of indebtedness net of cash. Our debt could have negative consequences for our financial condition including:

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increasing our vulnerability to general economic and industry conditions;
•
requiring a substantial portion of our cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to use our cash flow to fund our operations, capital expenditures and future business opportunities;
•
limiting our ability to enter into long-term power sales or fuel purchases which require credit support;
•
limiting our ability to fund operations or future acquisitions;

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•
restricting our ability to make certain distributions with respect to our capital stock and the ability of our subsidiaries to make certain distributions to us, in light of restricted payment and other financial covenants in our credit facilities and other financing agreements;
•
inhibiting the growth of our stock price;
•
exposing us to the risk of increased interest rates because certain of our borrowings, including borrowings under our revolving credit facility, are at variable rates of interest;
•
limiting our ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes, and
•
limiting our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to our competitors who may have less debt.

We may not be successful in obtaining additional capital for these or other reasons. Furthermore, we may be unable to refinance or replace our existing indebtedness on favorable terms or at all upon the expiration or termination thereof. Our failure to obtain additional capital or enter into new or replacement financing arrangements when due may constitute a default under such existing indebtedness and may have a material adverse effect on our business, financial condition, results of operations and cash flows.

The Vistra Operations Credit Facilities impose restrictions on us and any failure to comply with these restrictions could have a material adverse effect on us.

The Vistra Operations Credit Facilities contain restrictions that could adversely affect us by limiting our ability to plan for, or react to, market conditions or to meet our capital needs and could result in an event of default under the Vistra Operations Credit Facilities. The Vistra Operations Credit Facilities contain events of default customary for financings of this type. If we fail to comply with the covenants in the Vistra Operations Credit Facilities and are unable to obtain a waiver or amendment, or a default exists and is continuing, the lenders under such agreements could give notice and declare outstanding borrowings thereunder immediately due and payable. Any such acceleration of outstanding borrowings could have a material adverse effect on us.

Certain of our obligations are required to be secured by letters of credit or cash, which increase our costs. If we are unable to provide such security, it may restrict our ability to conduct our business, which could have a material adverse effect on us.

We undertake certain hedging and commodity activities and enter into certain financing arrangements with various counterparties that require cash collateral or the posting of letters of credit which are at risk of being drawn down in the event we default on our obligations. We currently use margin deposits, prepayments and letters of credit as credit support for commodity procurement and risk management activities. Future cash collateral requirements may increase based on the extent of our involvement in standard contracts and movements in commodity prices, and also based on our credit ratings and the general perception of creditworthiness in the markets in which we operate. In the case of commodity arrangements, the amount of such credit support that must be provided typically is based on the difference between the price of the commodity in a given contract and the market price of the commodity. Significant movements in market prices can result in our being required to provide cash collateral and letters of credit in very large amounts. The effectiveness of our strategy may be dependent on the amount of collateral available to enter into or maintain these contracts, and liquidity requirements may be greater than we anticipate or will be able to meet. Without a sufficient amount of working capital to post as collateral, we may not be able to manage price volatility effectively or to implement our strategy. An increase in the amount of letters of credit or cash collateral required to be provided to our counterparties may have a material adverse effect on us.

We may not be able to integrate our business with Dynegy's business successfully and realize the anticipated synergies and other expected benefits of the Merger on the anticipated timeframe or at all, and we may incur significant expenses in connection with the integration efforts.

We recently completed the Merger of Vistra Energy and Dynegy. We expect to benefit from certain cost savings and operating efficiencies, some of which will take time to realize. We have been, and will continue to be, required to devote significant management attention and resources to the integration of our and Dynegy's business practices and operations. The potential difficulties the combined company may encounter in the integration process include the following:

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the inability to successfully combine our and Dynegy's businesses in a manner that permits the combined company to achieve the cost savings anticipated to result from the Merger, which would result in the anticipated benefits of the Merger not being realized in the timeframe currently anticipated or at all;
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the complexities associated with integrating personnel from the two companies;
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the complexities of combining two companies with different histories, geographic footprints and asset mixes;
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the complexities in combining two companies with separate technology systems;
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potential unknown liabilities and unforeseen increased expenses, delays or conditions associated with the Merger;

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•
failure to perform by third-party service providers who provide key services for the combined company, and
•
performance shortfalls as a result of the diversion of management's attention caused by completing the Merger and integrating the companies' operations.

For all these reasons, it is possible that the integration process could result in the distraction of the combined company's management, the disruption of the combined company's ongoing business or inconsistencies in its operations, services, standards, controls, policies and procedures, any of which could adversely affect the combined company's ability to maintain relationships with operators, vendors and employees, to achieve the anticipated benefits of the Merger, or could otherwise materially and adversely affect its business and financial results.

In addition, we expect to incur significant expenses in connection with the integration of the Company and Dynegy. There are a large number of processes, policies, procedures, operations, technologies and systems at each company that must be integrated, including purchasing, accounting and finance, sales, payroll, pricing, revenue management, commercial operations, risk management, marketing and employee benefits. While we have assumed that a certain level of expenses will be incurred, there are many factors beyond our control that could affect the total amount or the timing of the integration expenses. Moreover, many of the expenses that will be incurred are, by their nature, difficult to estimate accurately. These expenses could, particularly in the near term, exceed the savings that the combined company expects to achieve from the elimination of duplicative expenses and the realization of economies of scale and cost savings. These integration expenses likely will result in us taking significant charges against earnings, and the amount and timing of such charges are uncertain at present.

The allocation of the purchase price to the value amounts recognized for the assets acquired and liabilities assumed related to the Merger with Dynegy as of the Merger Date is preliminary in nature and could differ materially from our initial purchase price allocation.

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

We may not be able to complete future acquisitions or successfully integrate future acquisitions into our business, which could result in unanticipated expenses and losses.

As part of our growth strategy, we have pursued acquisitions, including the Merger with Dynegy, and may continue to do so. Our ability to continue to implement this component of our growth strategy will be limited by our ability to identify appropriate acquisition or joint venture candidates and our financial resources, including available cash and access to capital. Any expense incurred in completing acquisitions or entering into joint ventures, the time it takes to integrate an acquisition or our failure to integrate acquired businesses successfully could result in unanticipated expenses and losses. Furthermore, we may not be able to fully realize the anticipated benefits from any future acquisitions or joint ventures we may pursue. In addition, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and expenses and may require significant financial resources that would otherwise be available for the execution of our business strategy.

Circumstances associated with potential divestitures could adversely affect our results of operations and financial condition.

In evaluating our business and the strategic fit of our various assets, we may determine to sell one or more of such assets. Despite a decision to divest an asset, we may encounter difficulty in finding a buyer willing to purchase the asset at an acceptable price and on acceptable terms and in a timely manner. In addition, a prospective buyer may have difficulty obtaining financing. Divestitures could involve additional risks, including:

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difficulties in the separation of operations and personnel;
•
the need to provide significant ongoing post-closing transition support to a buyer;
•
management's attention may be temporarily diverted;
•
the retention of certain current or future liabilities in order to induce a buyer to complete a divestiture;
•
the obligation to indemnify or reimburse a buyer for certain past liabilities of a divested asset;
•
the disruption of our business, and
•
potential loss of key employees.


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We may not be successful in managing these or any other significant risks that we may encounter in divesting any asset, which could adversely affect our results of operations and financial condition.

If our goodwill, intangible assets, or long-lived assets become impaired, we may be required to record a significant charge to earnings.

We have significant goodwill, intangible assets and long-lived assets recorded on our balance sheet. In accordance with U.S. GAAP, goodwill and non-amortizing intangible assets are required to be tested for impairment at least annually. Additionally, we review goodwill, our intangible assets and long-lived assets for impairment when events or changes in circumstances indicate the carrying value of the asset may not be recoverable. Factors that may be considered include a decline in future cash flows, slower growth rates in the energy industry, and a sustained decrease in the price of our common stock.

We performed our annual goodwill assessment and determined that no impairment was required. However, further goodwill impairment testing will be performed in future periods and may result in an impairment loss, which could be material.

Issuances or acquisitions of our common stock, or sales or dispositions of our common stock by stockholders, that result in an ownership change as defined in Internal Revenue Code (IRC) §382 could further limit our ability to use our federal net operating losses or alternative minimum tax credits to offset our future taxable income.

If an "ownership change," as defined in Section 382 of the IRC (IRC §382) occurs, the amount of NOLs and AMT credits that could be used in any one year following such ownership change could be substantially limited. In general, an "ownership change" would occur when there is a greater than 50 percentage point increase in ownership of a company's stock by stockholders, each of which owns (or is deemed to own under IRC §382) 5 percent or more of such company's stock. Given IRC §382's broad definition, an ownership change could be the unintended consequence of otherwise normal market trading in our stock that is outside our control. Vistra Energy acquired NOLs and AMT credits from its merger with Dynegy, however, Vistra Energy's use of such attributes is limited under IRC §382 because the merger constituted an "ownership change" with respect to Dynegy. If there is an "ownership change" with respect to Vistra Energy (including by the normal trading activity of greater than 5% shareholders), the utilization of all NOLs and AMT credits existing at that time would be subject to additional annual limitations based upon a formula provided under IRC §382 that is based on the fair market value of the Company and prevailing interest rates at the time of the ownership change.

Recent U.S. tax legislation may materially adversely affect Vistra Energy's financial condition, results of operations and cash flows.

On December 22, 2017, President Trump signed into law a comprehensive tax reform bill (the TCJA), that significantly reforms the Internal Revenue Code. The TCJA, among other things, contains significant changes to corporate taxation, including a reduction of the corporate income tax rate, a partial limitation on the deductibility of business interest expense, limitation of the deduction for certain net operating losses to 80% of current year taxable income, an indefinite net operating loss carryforward, immediate deductions for certain new investments instead of deductions for depreciation expense over time and the modification or repeal of many business deductions and credits. While we expect a beneficial impact from the TCJA from the reduction in corporate tax rates and immediate deductions for certain new investments, we continue to examine the tax reform legislation, as its overall impact is uncertain, and note that certain provisions of the TCJA or its interaction with existing law could adversely affect the Company's business and financial condition. The impact of this tax reform legislation on our stockholders is also uncertain and could be adverse.

We may be responsible for U.S. federal and state income tax liabilities that relate to the PrefCo Preferred Stock Sale and Spin-Off.

Pursuant to the Tax Matters Agreement, the parties thereto have agreed to take certain actions and refrain from taking certain actions in order to preserve the intended tax treatment of the Spin-Off and to indemnify the other parties to the extent a breach of such covenant results in additional taxes to the other parties. If we breach such a covenant (or, in certain circumstances, if our stockholders or creditors of our Predecessor take or took certain actions that result in the intended tax treatment of the Spin-Off not to be preserved), we may be required to make substantial indemnification payments to the other parties to the Tax Matters Agreement.


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The Tax Matters Agreement also allocates the responsibility for taxes for periods prior to the Spin-Off between EFH Corp. and us. For periods prior to the Spin-Off, (i) Vistra Energy is generally required to reimburse EFH Corp. with respect to any taxes paid by EFH Corp. that are attributable to us and (ii) EFH Corp. is generally required to reimburse us with respect to any taxes paid by us that are attributable to EFH Corp.

We are also required to indemnify EFH Corp. against certain taxes in the event the IRS or another taxing authority successfully challenges the amount of gain relating to the PrefCo Preferred Stock Sale or the amount or allowance of EFH Corp.'s net operating loss deductions.

Our indemnification obligations to EFH Corp. are not limited by any maximum amount. If we are required to indemnify EFH Corp. or such other persons under the circumstances set forth in the Tax Matters Agreement, we may be subject to substantial liabilities.

We are required to pay the holders of TRA Rights for certain tax benefits, which amounts are expected to be substantial.

On the Effective Date, we entered into the TRA with American Stock Transfer & Trust Company, LLC, as the transfer agent. Pursuant to the TRA, we issued beneficial interests in the rights to receive payments under the TRA (TRA Rights) to the first lien creditors of our Predecessor to be held in escrow for the benefit of the first lien creditors of our Predecessor entitled to receive such TRA Rights under the Plan of Reorganization. Our financial statements reflect a liability of $439 million as of June 30, 2018 related to these future payment obligations (see Note 8 to the Financial Statements). This amount is based on certain assumptions as described more fully in the notes to the financial statements and the actual payments made under the TRA could be materially different than this estimate.

The TRA provides for the payment by us to the holders of TRA Rights of 85% of the amount of cash savings, if any, in U.S. federal, state and local income tax that we and our subsidiaries actually realize as a result of our use of (a) the tax basis step up attributable to the PrefCo Preferred Stock Sale, (b) the entire tax basis of the assets acquired as a result of the purchase and sale agreement, dated as of November 25, 2015 by and between La Frontera Ventures, LLC and Luminant, and (c) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA. The amount and timing of any payments under the TRA will vary depending upon a number of factors, including the amount and timing of the taxable income we generate in the future and the tax rate then applicable, our use of loss carryovers and the portion of our payments under the TRA constituting imputed interest.

Although we are not aware of any issue that would cause the IRS to challenge the tax benefits that are the subject of the TRA, recipients of the payments under the TRA will not be required to reimburse us for any payments previously made if such tax benefits are subsequently disallowed. As a result, in such circumstances, Vistra Energy could make payments under the TRA that are greater than its actual cash tax savings. Any amount of excess payment can be used to reduce future TRA payments, but cannot be immediately recouped, which could adversely affect our liquidity.

Because Vistra Energy is a holding company with no operations of its own, its ability to make payments under the TRA is dependent on the ability of its subsidiaries to make distributions to it. To the extent that Vistra Energy is unable to make payments under the TRA because of the inability of its subsidiaries to make distributions to us for any reason, such payments will be deferred and will accrue interest until paid, which could adversely affect our results of operations and could also affect our liquidity in periods in which such payments are made.

The payments we will be required to make under the TRA could be substantial.

We may be required to make an early termination payment to the holders of TRA Rights under the TRA.

The TRA provides that, in the event that Vistra Energy breaches any of its material obligations under the TRA, or upon certain mergers, asset sales, or other forms of business combination or certain other changes of control, the transfer agent under the TRA may treat such event as an early termination of the TRA, in which case Vistra Energy would be required to make an immediate payment to the holders of the TRA Rights equal to the present value (at a discount rate equal to LIBOR plus 100 basis points) of the anticipated future tax benefits based on certain valuation assumptions.

As a result, upon any such breach or change of control, we could be required to make a lump sum payment under the TRA before we realize any actual cash tax savings and such lump sum payment could be greater than our future actual cash tax savings.


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The aggregate amount of these accelerated payments could be materially more than our estimated liability for payments made under the TRA set forth in our financial statements. Based on this estimation, our obligations under the TRA could have a substantial negative impact on our liquidity.

We are potentially liable for U.S. income taxes of the entire EFH Corp. consolidated group for all taxable years in which we were a member of such group.

Prior to the Spin-Off, EFH Corporate Services Company, EFH Properties Company and certain other subsidiary corporations were included in the consolidated U.S. federal income tax group of which EFH Corp. was the common parent (EFH Corp. Consolidated Group). In addition, pursuant to the private letter ruling from the IRS that we received in connection with the Spin-Off, Vistra Energy will be considered a member of the EFH Corp. Consolidated Group immediately prior to the Spin-Off. Under U.S. federal income tax laws, any corporation that is a member of a consolidated group at any time during a taxable year is severally liable for the group's entire federal income tax liability for the entire taxable year. In addition, entities that are disregarded for U.S. federal income tax purposes may be liable as successors under common law theories or under certain regulations to the extent corporations transferred assets to such entities or merged or otherwise consolidated into such entities, whether under state law or purely as a matter of federal income tax law. Thus, notwithstanding any contractual rights to be reimbursed or indemnified by EFH Corp. pursuant to the Tax Matters Agreement, to the extent EFH Corp. or other members of the EFH Corp. Consolidated Group fail to make any U.S. federal income tax payments required of them by law in respect of taxable years for which the Company or any subsidiary noted above was a member of the EFH Corp. Consolidated Group, the Company or such subsidiary may be liable for the shortfall. At such time, we may not have sufficient cash on hand to satisfy such payment obligation.

Our ability to claim a portion of depreciation deductions may be limited for a period of time.

Under the Internal Revenue Code of 1986, as amended, a corporation's ability to utilize certain tax attributes, including depreciation, may be limited following an ownership change if the corporation's overall asset tax basis exceeds the overall fair market value of its assets (after making certain adjustments). The Spin-Off resulted in an ownership change for the Company and it is expected that the overall tax basis of our assets may have exceeded the overall fair market value of our assets at such time. As a result, there may be a limitation on our ability to claim a portion of our depreciation deductions for a five-year period. This limitation could have a material impact on our tax liabilities and on our obligations under the TRA Rights. In addition, any future ownership change of Vistra Energy following Emergence could likewise result in additional limitations on our ability to use certain tax attributes existing at the time of any such ownership change and have an impact on our tax liabilities and on our obligations under the TRA.

Regulatory and Legislative Risks

Our businesses are subject to ongoing complex governmental regulations and legislation that have impacted, and may in the future impact, our businesses, results of operations, liquidity and financial condition.

Our businesses operate in changing market environments influenced by various state and federal legislative and regulatory initiatives regarding the restructuring of the energy industry, including competition in power generation and sale of electricity. Although we attempt to comply with changing legislative and regulatory requirements, there is a risk that we will fail to adapt to any such changes successfully or on a timely basis.

Our businesses are subject to numerous state and federal laws (including PURA, the Federal Power Act, the Atomic Energy Act, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act (CAA), the Energy Policy Act of 2005 and the Dodd-Frank Wall Street Reform and Consumer Protection Act), changing governmental policy and regulatory actions (including those of the FERC, the NERC, the RCT, the MSHA, the EPA, the NRC, CFTC, state public utility commissions and state environmental regulatory agencies), and the rules, guidelines and protocols of ERCOT, CAISO, ISO-NE, MISO, NYISO and PJM with respect to various matters, including, but not limited to, market structure and design, operation of nuclear generation facilities, construction and operation of other generation facilities, development, operation and reclamation of lignite mines, recovery of costs and investments, decommissioning costs, market behavior rules, present or prospective wholesale and retail competition and environmental matters. We, along with other market participants, are subject to electricity pricing constraints and market behavior and other competition-related rules and regulations under PURA. Changes in, revisions to, or reinterpretations of, existing laws and regulations may have a material adverse effect on us.


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Dynegy's legacy business operates in a number of states and markets outside of our historical operations. As a result of the Merger, we became subject to the regulatory requirements of such markets, including CAISO, ISO-NE, MISO, NYISO and PJM. Because we have historically not been subject to the regulations of such markets, we may incur additional expenses to learn such regulations and ensure that our operations are operating in compliance with such regulations.

We are required to obtain, and to comply with, government permits and approvals.

We are required to obtain, and to comply with, numerous permits and licenses from federal, state and local governmental agencies. The process of obtaining and renewing necessary permits and licenses can be lengthy and complex and can sometimes result in the establishment of conditions that make the project or activity for which the permit or license was sought unprofitable or otherwise unattractive. In addition, such permits or licenses may be subject to denial, revocation or modification under various circumstances. Failure to obtain or comply with the conditions of permits or licenses, or failure to comply with applicable laws or regulations, may result in the delay or temporary suspension of our operations and electricity sales or the curtailment of our delivery of electricity to our customers and may subject us to penalties and other sanctions. Although various regulators routinely renew existing permits and licenses, renewal of our existing permits or licenses could be denied or jeopardized by various factors, including (a) failure to provide adequate financial assurance for closure, (b) failure to comply with environmental, health and safety laws and regulations or permit conditions, (c) local community, political or other opposition and (d) executive, legislative or regulatory action.

Our inability to procure and comply with the permits and licenses required for our operations, or the cost to us of such procurement or compliance, could have a material adverse effect on us. In addition, new environmental legislation or regulations, if enacted, or changed interpretations of existing laws, may cause routine maintenance activities at our facilities to need to be changed in order to avoid violating applicable laws and regulations or elicit claims that historical routine maintenance activities at our facilities violated applicable laws and regulations. In addition to the possible imposition of fines in the case of any such violations, we may be required to undertake significant capital investments in emissions control technology and obtain additional operating permits or licenses, which could have a material adverse effect on us.

Our cost of compliance with existing and new environmental laws could have a material adverse effect on us.

We are subject to extensive environmental regulation by governmental authorities, including the EPA and state environmental agencies and/or attorneys general. We may incur significant additional costs beyond those currently contemplated to comply with these regulatory requirements. If we fail to comply with these regulatory requirements, we could be subject to administrative, civil or criminal liabilities and fines. Existing environmental regulations could be revised or reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air emissions, all of which could result in significant additional costs beyond those currently contemplated to comply with existing requirements. Any of the foregoing could have a material adverse effect on us.

The EPA has recently finalized or proposed several regulatory actions establishing new requirements for control of certain emissions from sources, including electricity generation facilities. In the future, the EPA may also propose and finalize additional regulatory actions that may adversely affect our existing generation facilities or our ability to cost-effectively develop new generation facilities. There is no assurance that the currently installed emissions control equipment at our lignite, coal and/or natural gas-fueled generation facilities will satisfy the requirements under any future EPA or state environmental regulations. Some of the recent regulatory actions and proposed actions, such as the EPA's Regional Haze Federal Implementation Plans (FIP) for reasonable progress and best available retrofit technology (BART), could require us to install significant additional control equipment, resulting in potentially material costs of compliance for our generation units, including capital expenditures, higher operating and fuel costs and potential production curtailments if the rules take effect as proposed or finalized. These costs could have a material adverse effect on us.

We may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, if we fail to obtain, maintain or comply with any such approval or if an approval is retroactively disallowed or adversely modified, the operation of our generation facilities could be stopped, disrupted, curtailed or modified or become subject to additional costs. Any such stoppage, disruption, curtailment, modification or additional costs could have a material adverse effect on us.


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In addition, we may be responsible for any on-site liabilities associated with the environmental condition of facilities that we have acquired, leased or developed, regardless of when the liabilities arose and whether they are now known or unknown. In connection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certain environmental liabilities. Another party could, depending on the circumstances, assert an environmental claim against us or fail to meet its indemnification obligations to us.

We could be materially and adversely affected if current regulations are implemented or if new federal or state legislation or regulations are adopted to address global climate change, or if we are subject to lawsuits for alleged damage to persons or property resulting from greenhouse gas emissions.

There is a concern nationally and internationally about global climate change and how GHG emissions, such as CO2, contribute to global climate change. Over the last several years, the U.S. Congress has considered and debated, and President Obama's administration previously discussed, several proposals intended to address climate change using different approaches, including a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade), a tax on carbon or GHG emissions, incentives for the development of low-carbon technology and federal renewable portfolio standards. In October 2015, the EPA finalized regulations under the CAA to limit CO2emissions from existing generating units, referred to as the Clean Power Plan. If implemented as finalized, the Clean Power Plan would require the closure of a significant number of coal-fueled electric generating units nationwide and in Texas. The Clean Power Plan is currently stayed pending the conclusion of legal challenges on the rule. In October 2017, the EPA proposed the repeal of the Clean Power Plan. In addition, a number of federal court cases have been filed in recent years asserting damage claims related to GHG emissions, and the results in those proceedings could establish adverse precedent that might apply to companies (including us) that produce GHG emissions. We could be materially and adversely affected if new federal and/or state legislation or regulations are adopted to address global climate change, if the Clean Power Plan is implemented as finalized or if we are subject to lawsuits for alleged damage to persons or property resulting from GHG emissions.

Our business may be affected by changes in market structure and state or federal interference in the competitive wholesale marketplace.

Our generation and competitive retail businesses rely on a competitive wholesale marketplace. The competitive wholesale marketplace may be undermined by changes in market structure and out-of-market subsidies provided by federal or state entities, including bailouts of uneconomic plants, imports of power from Canada, renewable mandates or subsidies, as well as out-of-market payments to new generators. These out-of-market subsidies to existing or new generation undermine the competitive wholesale marketplace, which can lead to premature retirement of existing facilities, including those owned by us. If these measures continue, capacity and energy prices may be suppressed, and we may not be successful in its efforts to insulate the competitive market from this interference.

The integration of the Capacity Performance product into the PJM market and the Pay-for-Performance mechanism in ISO-NE could lead to substantial changes in capacity income and non-performance penalties, which could have a material adverse effect on our results of operations, financial condition and cash flows.

Both ISO-NE and PJM operate a pay-for-performance model where capacity payments are modified based on real-time generator performance. Capacity market prices are sensitive to design parameters, as well as additions of new capacity. We may experience substantial changes in capacity income and non-performance penalties, which could have a material adverse effect on our results of operations, financial condition and cash flows.

The availability and cost of emission allowances could adversely impact our costs of operations.

We are required to maintain, through either allocations or purchases, sufficient emission allowances for SO2 and NOX to support our operations in the ordinary course of operating our power generation facilities. These allowances are used to meet the obligations imposed on us by various applicable environmental laws. If our operational needs require more than our allocated allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as not to exceed our available emission allowances, or install costly new emission controls. As we use the emission allowances that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such allowances are available for purchase, but only at significantly higher prices, the purchase of such allowances could materially increase our costs of operations in the affected markets.


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Luminant's mining operations are subject to RCT oversight.

We currently own and operate, or are in the process of reclamation, through Luminant 12 surface lignite coal mines in Texas to provide fuel for our electricity generation facilities. The RCT, which exercises broad authority to regulate reclamation activity, reviews on an ongoing basis whether Luminant is compliant with RCT rules and regulations and whether it has met all of the requirements of its mining permits. Any new rules and regulations adopted by the RCT or the Department of Interior Office of Surface Mining, which also regulates mining activity nationwide, or any changes in the interpretation of existing rules and regulations, could result in higher compliance costs or otherwise adversely affect our financial condition or cause a revocation of a mining permit. Any revocation of a mining permit would mean that Luminant would no longer be allowed to mine lignite at the applicable mine to serve its generation facilities. In addition, Luminant's mining reclamation obligations are secured by a first lien on its assets which is pari passu with the Vistra Operations Credit Facilities, but which would be paid first, up to $975 million, upon any liquidation of Vistra Operations' assets. The RCT could, at any time, require that Luminant's mining reclamation obligations be secured by cash or letters of credit in lieu of such first lien. Any failure to provide any such cash or letter of credit collateral could result in Luminant no longer being able to mine lignite. Any such event could have a material adverse effect on us.

Luminant's lignite mining reclamation activity will require significant resources as existing and retired mining operations are reclaimed over the next several years.

In conjunction with Luminant's recent announcements to retire several power generation assets and related mining operations, along with the continuous reclamation activity at its continuing mining operations for its mines related to the Oak Grove and Martin Lake generation assets, Luminant is expected to spend a significant amount of money, internal resources and time to complete the required reclamation activities. For the next five years, Vistra Energy is projected to spend approximately $350 million (on a nominal basis) to achieve its reclamation objectives.

Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant liabilities and reputation damage that could have a material adverse effect on us.

We are involved in the ordinary course of business in a number of lawsuits involving, among other matters, employment, commercial, and environmental issues, and other claims for injuries and damages. We evaluate litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these evaluations and estimates, when required by applicable accounting rules, we establish reserves and disclose the relevant litigation claims or legal proceedings, as appropriate. These evaluations and estimates are based on the information available to management at the time and involve a significant amount of judgment. Actual outcomes or losses may differ materially from current evaluations and estimates. The settlement or resolution of such claims or proceedings may have a material adverse effect on us. We use appropriate means to contest litigation threatened or filed against us, but the litigation environment poses a significant business risk.

We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings, and we are exposed to the risk that we may become the subject of additional regulatory investigations or administrative proceedings. While we cannot predict the outcome of any regulatory investigation or administrative proceeding, any such regulatory investigation or administrative proceeding could result in us incurring material penalties and/or other costs and have a materially adverse effect on us.

Our retail businesses are subject to changing state rules and regulations that could have a material impact on the profitability of our business.

The competitiveness of our retail businesses partially depends on state regulatory policies that establish the structure, rules, terms and conditions on which services are offered to retail customers. These state policies, which can include controls on the retail rates our retail businesses can charge, the imposition of additional costs on sales, restrictions on our ability to obtain new customers through various marketing channels and disclosure requirements, which can affect the competitiveness of our retail businesses. Additionally, state or federal imposition of net metering or RPS programs can make it more or less expensive for retail customers to supplement or replace their reliance on grid power. Our retail businesses have limited ability to influence development of these policies, and its business model may be more or less effective, depending on changes to the regulatory environment.


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The REP certification of our retail operation is subject to review of the public utility commissions in the states in which we operate.

The public utility commissions and/or the attorney generals of the various jurisdictions in which the Retail segment operates may at any time initiate an investigation into whether our retail operations comply with certain commission rules or state laws and whether we have met the requirements for REP certification, including financial requirements. Any removal or revocation of a REP certification would mean that we would no longer be allowed to provide electricity service to retail customers in the applicable jurisdiction. Such decertification could have a material adverse effect on us. Moreover, any capital or other expenditures that we are required to undertake in order to achieve or maintain any such compliance could also have a material adverse effect on us.

Operational Risks

Our retail operations are subject to significant competition from other REPs, which could result in a loss of existing customers and the inability to attract new customers.

We operate in a very competitive retail market and, as a result, our retail operation faces significant competition for customers. We believe our TXU EnergyTM, Homefield Energy and Dynegy Energy Services brands are viewed favorably in the retail electricity markets in which we operate, but despite our commitment to providing superior customer service and innovative products, customer sentiment toward our brands, including by comparison to our competitors' brands, depends on certain factors beyond our control. For example, competitor REPs may offer different products, lower electricity prices and other incentives, which, despite our long-standing relationship with many customers, may attract customers away from us. If we are unable to successfully compete with competitors in the retail market it is possible our retail customer counts could decline, which could have a material adverse effect on us.

As we try to grow our retail business and operate our business strategy, we compete with various other REPs that may have certain advantages over us. For example, in new markets, our principal competitor for new customers may be the incumbent REP, which has the advantage of long-standing relationships with its customers, including well-known brand recognition. In addition to competition from the incumbent REP, we may face competition from a number of other energy service providers, other energy industry participants, or nationally branded providers of consumer products and services who may develop businesses that will compete with us. Some of these competitors or potential competitors may be larger than we are or have greater resources or access to capital than we have. If there is inadequate potential margin in retail electricity markets with substantial competition to overcome the adverse effect of relatively high customer acquisition costs in such markets, it may not be profitable for us to compete in these markets.

Our retail operations rely on the infrastructure of local utilities or independent transmission system operators to provide electricity to, and to obtain information about, our customers. Any infrastructure failure could negatively impact customer satisfaction and could have a material adverse effect on us.

With the exception of Electric Energy, Inc. (EEI), which we acquired in the Merger and which owns and controls transmission lines interconnecting our Joppa facility in EEI’s control to MISO, Tennessee Valley Authority and Louisville Gas and Electric Company, our retail operations depend on transmission and distribution facilities owned and operated by unaffiliated utilities to deliver the electricity that we sell to our customers. If transmission capacity is inadequate, our ability to sell and deliver electricity may be hindered and we may have to forgo sales or buy more expensive wholesale electricity than is available in the capacity-constrained area, or, with respect to capacity performance in PJM and performance incentives in ISO-NE, we may be subject to significant penalties. For example, during some periods, transmission access is constrained in some areas of the Dallas-Fort Worth metroplex, where we have a significant number of customers. The cost to provide service to these customers may exceed the cost to provide service to other customers, resulting in lower operating margins. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to our customers could negatively impact customer satisfaction with our service. Any of the foregoing could have a material adverse effect on us.

We may suffer material losses, costs and liabilities due to ownership and operation of the Comanche Peak nuclear generation facility.

We own and operate a nuclear generation facility in Glen Rose, Texas (Comanche Peak Facility). The ownership and operation of a nuclear generation facility involves certain risks. These risks include:

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unscheduled outages or unexpected costs due to equipment, mechanical, structural, cyber security or other problems;
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inadequacy or lapses in maintenance protocols;

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the impairment of reactor operation and safety systems due to human error or force majeure;
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the costs of, and liabilities relating to, storage, handling, treatment, transport, release, use and disposal of radioactive materials;
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the costs of procuring nuclear fuel;
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the costs of storing and maintaining spent nuclear fuel at our on-site dry cask storage facility;
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terrorist or cyber security attacks and the cost to protect against any such attack;
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the impact of a natural disaster;
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limitations on the amounts and types of insurance coverage commercially available, and
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uncertainties with respect to the technological and financial aspects of modifying or decommissioning nuclear facilities at the end of their useful lives.

Any prolonged unavailability of the Comanche Peak Facility could have a material adverse effect on our results of operation, cash flows, financial position and reputation. The following are among the more significant related risks:

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Operational Risk - Operations at any generation facility could degrade to the point where the facility would have to be shut down. If such degradations were to occur at the Comanche Peak Facility, the process of identifying and correcting the causes of the operational downgrade to return the facility to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments. Furthermore, a shut-down or failure at any other nuclear generation facility could cause regulators to require a shut-down or reduced availability at the Comanche Peak Facility.
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Regulatory Risk - The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear generation facilities. Unless extended, as to which no assurance can be given, the NRC operating licenses for the two licensed operating units at the Comanche Peak Facility will expire in 2030 and 2033, respectively. Changes in regulations by the NRC, as well as any extension of our operating licenses, could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.
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Nuclear Accident Risk - Although the safety record of the Comanche Peak Facility and other nuclear generation facilities generally has been very good, accidents and other unforeseen problems have occurred both in the U.S. and elsewhere. The consequences of an accident can be severe and include loss of life, injury, lasting negative health impacts and property damage. Any accident, or perceived accident, could result in significant liabilities and damage our reputation. Any such resulting liability from a nuclear accident could exceed our resources, including insurance coverage, and could ultimately result in the suspension or termination of power generation from the Comanche Peak Facility.

The operation and maintenance of power generation facilities and related mining operations involve significant risks that could adversely affect our results of operations, liquidity and financial condition.

The operation and maintenance of power generation facilities and related mining operations involve many risks, including, as applicable, start-up risks, breakdown or failure of facilities, equipment or processes, operator error, lack of sufficient capital to maintain the facilities, the dependence on a specific fuel source, the inability to transport our product to our customers in an efficient manner due to the lack of transmission capacity or the impact of unusual or adverse weather conditions or other natural events, or terrorist attacks, as well as the risk of performance below expected levels of output, efficiency or reliability, the occurrence of any of which could result in substantial lost revenues and/or increased expenses. A significant number of our facilities were constructed many years ago. In particular, older generating equipment, even if maintained or refurbished in accordance with good engineering practices, may require significant capital expenditures to operate at peak efficiency or reliability. The risk of increased maintenance and capital expenditures arises from (a) increased starting and stopping of generation equipment due to the volatility of the competitive generation market and the prospect of continuing low wholesale electricity prices that may not justify sustained or year-round operation of all our generation facilities, (b) any unexpected failure to generate power, including failure caused by equipment breakdown or unplanned outage (whether by order of applicable governmental regulatory authorities, the impact of weather events or natural disasters or otherwise), (c) damage to facilities due to storms, natural disasters, wars, terrorist or cyber/data security acts and other catastrophic events and (d) the passage of time and normal wear and tear. Further, our ability to successfully and timely complete routine maintenance or other capital projects at our existing facilities is contingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful, we could be subject to additional costs or losses and write downs of our investment in the project.


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We cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety laws and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected events (such as natural disasters or terrorist or cyber/data security attacks). The unexpected requirement of large capital expenditures could have a material adverse effect on us. Moreover, if we significantly modify a unit, we may be required to install the best available control technology or to achieve the lowest achievable emission rates as such terms are defined under the new source review provisions of the CAA, which would likely result in substantial additional capital expenditures.

In addition, unplanned outages at any of our generation facilities, whether because of equipment breakdown or otherwise, typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWh or non-performance penalties or require us to incur significant costs as a result of running one of our higher cost units or to procure replacement power at spot market prices in order to fulfill contractual commitments. If we do not have adequate liquidity to meet margin and collateral requirements, we may be exposed to significant losses, may miss significant opportunities and may have increased exposure to the volatility of spot markets, which could have a material adverse effect on us. Further, our inability to operate our generation facilities efficiently, manage capital expenditures and costs, and generate earnings and cash flow from our asset-based businesses could have a material adverse effect on our results of operations, financial condition or cash flows. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance, warranties or performance guarantees may not be adequate to cover our lost revenues, increased expenses or liquidated damages payments should we experience equipment breakdown or non-performance by contractors or vendors.

Operation of power generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on Vistra Energy's revenues and results of operations, and Vistra Energy may not have adequate insurance to cover these risks and hazards. Our employees, contractors, customers and the general public may be exposed to a risk of injury due to the nature of our operations.

Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of equipment and delivering electricity to transmission and distribution systems. In addition to natural risks such as earthquake, flood, lightning, hurricane and wind, other hazards, such as nuclear accidents, dam failure, gas or other explosions, mine area collapses, fire, structural collapse, machinery failure and other dangerous incidents are inherent risks in our operations. These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. Further, our employees and contractors work in, and customers and the general public may be exposed to, potentially dangerous environments at or near our operations. As a result, employees, contractors, customers and the general public are at risk for serious injury, including loss of life.

The occurrence of any one of these events may result in us being named as a defendant in lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties. We maintain an amount of insurance protection that we consider adequate, but we cannot provide any assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject and, even if we do have insurance coverage for a particular circumstance, we may be subject to a large deductible and maximum cap. A successful claim for which we are not fully insured could hurt our financial results and materially harm our financial condition. Further, due to rising insurance costs and changes in the insurance markets, we cannot provide any assurance that our insurance coverage will continue to be available at all or at rates or on terms similar to those presently available. Any losses not covered by insurance could have a material adverse effect on our financial condition, results of operations or cash flows.

We may be materially and adversely affected by the effects of extreme weather conditions and seasonality.

We may be materially affected by weather conditions and our businesses may fluctuate substantially on a seasonal basis as the weather changes. In addition, we could be subject to the effects of extreme weather conditions, including sustained cold or hot temperatures, hurricanes, storms or other natural disasters, which could stress our generation facilities and result in outages, destroy our assets and result in casualty losses that are not ultimately offset by insurance proceeds, and could require increased capital expenditures or maintenance costs, including supply chain costs.


100

Moreover, an extreme weather event could cause disruption in service to customers due to downed wires and poles or damage to other operating equipment, which could result in us foregoing sales of electricity and lost revenue. Similarly, an extreme weather event might affect the availability of generation and transmission capacity, limiting our ability to source or deliver power where it is needed or limit our ability to source fuel for our plants (including due to damage to rail or natural gas pipeline infrastructure). Additionally, extreme weather may result in unexpected increases in customer load, requiring our retail operation to procure additional electricity supplies at wholesale prices in excess of customer sales prices for electricity. These conditions, which cannot be reliably predicted, could have adverse consequences by requiring us to seek additional sources of electricity when wholesale market prices are high or to sell excess electricity when market prices are low, which could have a material adverse effect on us.

We may be materially and adversely affected by insufficient water supplies.

Supplies of water are important for our generation facilities. Water in certain of the states in which we operate is limited and various parties have made conflicting claims regarding the right to access and use such limited supplies of water. In addition, in the recent past certain areas in which we operate, including Texas, have experienced sustained drought conditions that illustrate the effect such conditions may have on the water supply for certain of our generation facilities if adequate rain does not fall in the watersheds that supply our electric generating units. If we are unable to access sufficient supplies of water, it could prevent, restrict or increase the cost of operations at certain of our generation facilities, which could have a material adverse effect on us.

Changes in technology or increased electricity conservation efforts may reduce the value of our generation facilities and may otherwise have a material adverse effect on us.

Technological advances have improved, and are likely to continue to improve, for existing and alternative methods to produce and store power, including gas turbines, wind turbines, fuel cells, micro turbines, photovoltaic (solar) cells, batteries and concentrated solar thermal devices, along with improvements in traditional technologies. Such technological advances have reduced, and are expected to continue to reduce, the costs of power production or storage to a level that will enable these technologies to compete effectively with traditional generation facilities. Consequently, the value of our more traditional generation assets could be significantly reduced as a result of these competitive advances, which could have a material adverse effect on us. In addition, changes in technology have altered, and are expected to continue to alter, the channels through which retail customers buy electricity (i.e., self-generation or distributed-generation facilities). To the extent self-generation facilities become a more cost-effective option for customers, our financial condition, operating cash flows and results of operations could be materially and adversely affected.

Technological advances in demand-side management and increased conservation efforts have resulted, and are expected to continue to result, in a decrease in electricity demand. A significant decrease in electricity demand as a result of such efforts would significantly reduce the value of our generation assets. Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce power consumption. Effective power conservation by our customers could result in reduced electricity demand or significantly slow the growth in such demand. Any such reduction in demand could have a material adverse effect on us. Furthermore, we may incur increased capital expenditures if we are required to increase investment in conservation measures.

The operation of our businesses is subject to cyber-based security and integrity risk. Attacks on our infrastructure that breach cyber/data security measures could expose us to significant liabilities and reputation damage and disrupt business operations, which could have a material adverse effect on us.

Numerous functions affecting the efficient operation of our businesses are dependent on the secure and reliable storage, processing and communication of electronic data and the use of sophisticated computer hardware and software systems and much of our information technology infrastructure is connected (directly or indirectly) to the internet. There have been numerous attacks on government and industry information technology systems through the internet that have resulted in material operational, reputation and/or financial costs. While we have controls in place designed to protect our infrastructure and we are not aware of any significant breaches in the past, a breach of cyber/data security measures that impairs our information technology infrastructure could disrupt normal business operations and affect our ability to control our generation assets, access retail customer information and limit communication with third parties. Any loss of confidential or proprietary data through a breach could adversely affect our reputation, expose us to material legal or regulatory claims and impair our ability to execute our business strategy, which could have a material adverse effect on us. In addition, we may experience increased capital and operating costs to implement increased security for our information technology infrastructure and plants.


101

As part of the continuing development of new and modified reliability standards, the FERC has approved changes to its Critical Infrastructure Protection reliability standards and has established standards for assets identified as "critical cyber assets." Under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1 million per day, per violation) for failure to comply with mandatory electric reliability standards, including standards to protect the power system against potential disruptions from cyber/data and physical security breaches.

Further, our retail business requires access to sensitive customer data in the ordinary course of business. Examples of sensitive customer data are names, addresses, account information, historical electricity usage, expected patterns of use, payment history, credit bureau data, credit and debit card account numbers, drivers' license numbers, social security numbers and bank account information. Our retail business may need to provide sensitive customer data to vendors and service providers who require access to this information in order to provide services, such as call center operations, to the retail business. If a significant breach were to occur, the reputation of our retail business may be adversely affected, customer confidence may be diminished, and our retail business may be subject to substantial legal or regulatory claims, any of which may contribute to the loss of customers and have a material adverse effect on us.

The loss of the services of our key management and personnel could adversely affect our ability to successfully operate our businesses.

Our future success will depend on our ability to continue to attract and retain highly qualified personnel. We compete for such personnel with many other companies, in and outside of our industry, government entities and other organizations. We may not be successful in retaining current personnel or in hiring or retaining qualified personnel in the future. Our failure to attract highly qualified new personnel or retain highly qualified existing personnel could have an adverse effect on our ability to successfully operate our businesses.

We could be materially and adversely impacted by strikes or work stoppages by our unionized employees.

As of June 30, 2018, we had approximately 2,096 employees covered by collective bargaining agreements, of which 970 are subject to collective bargaining agreements entered into by Dynegy and assumed by us in the Merger. The initial term of the legacy Vistra Energy collective bargaining agreements expired on March 31, 2017, but they all remain effective pursuant to evergreen provisions unless and until terminated on prior notice by either party. We are currently negotiating a new collective bargaining agreement with one of our local unions, while new agreements with our two other local unions have been ratified, but not yet executed. In the event that our union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, we would be responsible for procuring replacement labor or we could experience reduced power generation or outages. Our ability to procure such labor is uncertain. Strikes, work stoppages or the inability to negotiate current or future collective bargaining agreements on favorable terms or at all could have a material adverse effect on us.

Risks Related to Our Structure and Ownership of our Common Stock

Vistra Energy is a holding company and its ability to obtain funds from its subsidiaries is structurally subordinated to existing and future liabilities and preferred equity of its subsidiaries.

Vistra Energy is a holding company that does not conduct any business operations of its own. As a result, Vistra Energy's cash flows and ability to meet its obligations are largely dependent upon the operating cash flows of Vistra Energy's subsidiaries and the payment of such operating cash flows to Vistra Energy in the form of dividends, distributions, loans or otherwise. These subsidiaries are separate and distinct legal entities from Vistra Energy and have no obligation (other than any existing contractual obligations) to provide Vistra Energy with funds to satisfy its obligations. Any decision by a subsidiary to provide Vistra Energy with funds to satisfy its obligations, including those under the TRA, whether by dividends, distributions, loans or otherwise, will depend on, among other things, such subsidiary's results of operations, financial condition, cash flows, cash requirements, contractual prohibitions and other restrictions, applicable law and other factors. The deterioration of income from, or other available assets of, any such subsidiary for any reason could limit or impair its ability to pay dividends or make other distributions to Vistra Energy.


102

We may not pay any dividends on our common stock in the future.

We have no present intention to pay cash dividends on our common stock. Any determination to pay dividends to holders of our common stock in the future will be at the sole discretion of the Board and will depend upon many factors, including our historical and anticipated financial condition, cash flows, liquidity and results of operations, capital requirements, market conditions, our growth strategy and the availability of growth opportunities, contractual prohibitions and other restrictions with respect to the payment of dividends, applicable law and other factors that the Board deems relevant.

A small number of stockholders could be able to significantly influence our business and affairs.

The three largest groups of stockholders of Vistra Energy-affiliates of Apollo Management Holdings L.P. (collectively, the Apollo Entities), affiliates of Brookfield Asset Management Private Institutional Capital Adviser (Canada), L.P. (collectively, the Brookfield Entities), and affiliates of Oaktree Capital Management, L.P. (collectively, the Oaktree Entities, and together with the Apollo Entities and the Brookfield Entities, the Principal Stockholders), all of which were first lien creditors of our Predecessor prior to Emergence. Large holders such as the Principal Stockholders may be able to affect matters requiring approval by holders of our common stock, including the election of directors and the approval of any strategic transactions, including the Merger. Furthermore, pursuant to the terms of stockholders' agreements entered into with each of the Brookfield Entities and the Apollo Entities, each such Principal Stockholder is entitled to designate one director to serve on the Board as a Class III director for so long as it beneficially owns, in the aggregate, at least 22,500,000 shares of our common stock.

Conflicts of interest may arise because some members of the Board are representatives of the Principal Stockholders.

The Principal Stockholders could invest in entities that directly or indirectly compete with us. As a result of these relationships, when conflicts arise between the interests of the Principal Stockholders or their affiliates and the interests of other stockholders, members of the Board that are representatives of the Principal Stockholders may not be disinterested. Neither the Principal Stockholders nor the representatives of the Principal Stockholders on the Board, by the terms of the Vistra Energy certificate of incorporation, are required to offer us any transaction opportunity of which they become aware and could take any such opportunity for themselves or offer it to their other affiliates, unless such opportunity is expressly offered to them solely in their capacity as members of the Board.

We are unable to take certain actions because such actions could jeopardize the intended tax treatment of the Spin-Off, and such restrictions could be significant.

The Tax Matters Agreement prohibits us from taking certain actions that could reasonably be expected to undermine the intended tax treatment the Spin-Off or to jeopardize the conclusions of the IRS private letter ruling that we received in connection with the Spin-Off or opinions of counsel received by us or EFH Corp. In particular, for two years after the Spin-Off, we may not:

•
cease the active conduct of our business;
•
cease to hold certain assets;
•
voluntarily dissolve or liquidate;
•
merge or consolidate with any other person in a transaction that does not qualify as a reorganization under Section 368(a) of the Internal Revenue Code of 1986, as amended;
•
redeem or otherwise repurchase (directly or indirectly) any of our equity interests other than pursuant to an open market stock repurchase program that satisfies the requirements in the Tax Matters Agreement, or
•
directly or indirectly acquire any of the PrefCo Preferred Stock.

Nevertheless, we are permitted to take any of the actions described above if (a) we obtain written consent from EFH Corp., (b) such action or transaction is described in or otherwise consistent with the facts in the private letter ruling we obtained from the IRS in connection with the Spin-Off, (c) we obtain a supplemental private letter ruling from the IRS or (d) we obtain an unqualified opinion of a nationally recognized law or accounting firm that is reasonably acceptable to EFH Corp. that the action will not affect the intended tax treatment of the Spin-Off.

The covenants and other limitations with respect to the Tax Matters Agreement may limit our ability to undertake certain transactions that would otherwise be value-maximizing.


103

Provisions in the certificate of incorporation and bylaws and the TRA might discourage, delay or prevent a change in control of Vistra Energy or changes in our management and therefore depress the market price of our common stock.

The certificate of incorporation and bylaws of Vistra Energy and the TRA contain provisions that could depress the market price of our common stock by acting to discourage, delay or prevent a change in control of Vistra Energy or changes in our management that stockholders may deem advantageous. These provisions in our bylaws:

•
authorize the issuance of "blank check" preferred stock that the Board could issue to increase the number of outstanding shares to discourage a takeover attempt;
•
create a classified board of directors;
•
prohibit stockholder action by written consent, and require that all stockholder actions be taken at a meeting of stockholders;
•
provide that the Board is expressly authorized to make, amend or repeal our bylaws, and
•
establish advance notice requirements for nominations for elections to the Board or for proposing matters that can be acted upon by stockholders at stockholder meetings.

In addition, the TRA provides that upon certain mergers, asset sales or other forms of business combination or certain other changes of control, the transfer agent under the TRA may treat such event as an early termination of the TRA, in which case we would be required to make a lump-sum payment under the TRA, which could be significant and could be significantly greater than the amount of the obligation reported in our consolidated balance sheets. This payment obligation may discourage potential buyers from acquiring Vistra Energy.


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

The following table provides information about our repurchase of equity securities that are registered by us pursuant to Section 12 of the Securities Exchange Act of 1934, as amended, during the quarter ended June 30, 2018.
 
 
Total Number of Shares Purchased
 
Average Price Paid per Share
 
Total Number of Shares Purchased as Part of a Publicly Announced Program
 
Maximum Dollar Amount of Shares that may yet be Purchased under the Program (b)
June 1 - June 30 (a)
 
3,152,073
 
$
23.81

 
3,152,073
 
$
425,000,000

For the quarter ended June 30, 2018
 
3,152,073
 
$
23.81

 
3,152,073
 
$
425,000,000

____________
(a)
The Program was effective as of June 13, 2018.
(b)
On a cumulative basis through July 31, 2018, 6,392,937 shares of our common stock had been repurchased for $150 million (including related fees and expenses) at an average price per share of common stock of $23.46, and at July 31, 2018, $350 million was available for additional repurchases under the Program.

In June 2018, we announced that our board of directors had authorized a share repurchase program (the Program) under which up to $500 million of our outstanding common stock may be repurchased. The Program was effective as of June 13, 2018, and we intend to implement the Program opportunistically from time to time through the end of 2019. Shares of the Company’s stock may be repurchased from time to time in open market transactions at prevailing market prices, in privately negotiated transactions, pursuant to plans complying with Rule 10b5-1 and 10b-18 under the Securities Exchange Act of 1934, as amended, or by other means in accordance with federal securities laws. The actual timing, number and value of shares repurchased under the Program will be determined at our discretion and will depend on a number of factors, including the market price of our stock, general market and economic conditions, applicable legal requirements and compliance with the terms of our debt agreements.


Item 3.
DEFAULTS UPON SENIOR SECURITIES

None.



104

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.


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)
 
001-38086
Form 8-K
(filed October 31, 2017)
 
2.1
 
—
 
 
 
 
 
 
 
 
 
 
(4)
 
Instruments Defining the Rights of Security Holders, Including Indentures
 
 
 
 
 
 
 
 
 
4(a)
 
001-33443
Form 8-K
(filed on October 30, 2014)
 
4.8
 
—
 
 
 
 
 
 
 
 
 
 
4(b)
 
001-33443
Form 8-K
(filed on April7, 2015)
 
4.11
 
—
 
 
 
 
 
 
 
 
 
 
4(c)
 
001-33443
Form 8-K
(filed on April 7, 2015)
 
4.12
 
—
 
 
 
 
 
 
 
 
 
 
4(d)
 
001-33443
Form 8-K
(filed on April 8, 2015)
 
4.17
 
—
 
 
 
 
 
 
 
 
 
 
4(e)
 
001-33443
Form10-Q(Quarter ended June 30, 2015)
(filed on August 7, 2015)
 
4.2
 
—
 
 
 
 
 
 
 
 
 
 
4(f)
 
001-33443
Form 10-Q (Quarter ended September 30, 2015)(filed on November 5, 2015)
 
4.2
 
—
 
 
 
 
 
 
 
 
 
 

105

Exhibits
 
Previously Filed With File Number*
 
As
Exhibit
 
 
 
 
4(g)
 
001-33443
Form 10-K (Year ended December 31, 2016) (filed on February 24, 2017)
 
4.24
 
—
 
 
 
 
 
 
 
 
 
 
4(h)
 
001-33443
Form 10-K (Year ended December 31, 2016) (filed on February 24, 2017)
 
4.25
 
—
 
 
 
 
 
 
 
 
 
 
4(i)
 
001-38086
Form 8-K
(filed on April 9, 2018)
 
4.19
 
—
 
 
 
 
 
 
 
 
 
 
4(j)
 
001-38086
Form 8-K
(filed on June 15, 2018)
 
4.1
 
—
 
 
 
 
 
 
 
 
 
 
4(k)
 
001-33443
Form 8-K
(filed on October 30, 2014)
 
4.8
 
—
 
 
 
 
 
 
 
 
 
 
4(l)
 
001-33443
Form 8-K
(filed on May 21, 2013)
 
4.1
 
—
 
 
 
 
 
 
 
 
 
 
4(m)
 
001-33443
Form 10-K (Year ended December 31, 2013)
(filed on February 27, 2014)
 
4.3
 
—
 
 
 
 
 
 
 
 
 
 
4(n)
 
001-33443
Form 8-K
(filed on April 7, 2015)
 
4.20
 
—
 
 
 
 
 
 
 
 
 
 
4(o)
 
001-33443
Form 8-K
(filed on April 8, 2015)
 
4.28
 
—
 
 
 
 
 
 
 
 
 
 
4(p)
 
001-33443
Form10-Q (Quarter ended June 30, 2015)
(filed on August 7, 2015)
 
4.4
 
—
 
 
 
 
 
 
 
 
 
 
4(q)
 
001-33443
Form 10-Q (Quarter ended September 30, 2015) (filed on November 5, 2015)
 
4.4
 
—
 
 
 
 
 
 
 
 
 
 
4(r)
 
001-33443
Form10-K (Year ended December 31, 2016)
(filed on February 24, 2017)
 
4.7
 
—
 
 
 
 
 
 
 
 
 
 
4(s)
 
001-33443
Form10-K (Year ended December 31, 2016)
(filed on February 24, 2017)
 
4.8
 
—
 
 
 
 
 
 
 
 
 
 
4(t)
 
001-38086
Form 8-K
(filed on April 9, 2018)
 
4.29
 
—
 

106

Exhibits
 
Previously Filed With File Number*
 
As
Exhibit
 
 
 
 
 
 
 
 
 
 
 
 
 
4(u)
 
001-38086
Form 8-K
(filed on June 15, 2018)
 
4.2
 
—
 
 
 
 
 
 
 
 
 
 
4(v)
 
001-33443
Form 8-K
(filed on May 21, 2013)
 
4.1
 
—
 
 
 
 
 
 
 
 
 
 
4(w)
 
001-33443
Form 8-K
(filed on October 30, 2014)
 
4.9
 
—
 
 
 
 
 
 
 
 
 
 
4(x)
 
001-33443
Form 8-K
(filed on April 7, 2015)
 
4.14
 
—
 
 
 
 
 
 
 
 
 
 
4(y)
 
001-33443
Form 8-K
(filed on April 7, 2015)
 
4.15
 
—
 
 
 
 
 
 
 
 
 
 
4(z)
 
001-33443
Form 8-K
(filed on April 8, 2015)
 
4.21
 
—
 
 
 
 
 
 
 
 
 
 
4(aa)
 
001-33443
Form10-Q (Quarter ended June 30, 2015)
(filed on August 7, 2015)
 
4.3
 
—
 
 
 
 
 
 
 
 
 
 
4(bb)
 
001-33443
Form 10-Q (Quarter ended September 30, 2015) (filed on November 5, 2015)
 
4.3
 
—
 
 
 
 
 
 
 
 
 
 
4(cc)
 
001-33443
Form10-K (Year ended December 31, 2016)
(filed on February 24, 2017)
 
4.32
 
—
 
 
 
 
 
 
 
 
 
 
4(dd)
 
001-33443
Form10-K (Year ended December 31, 2016)
(filed on February 24, 2017)
 
4.33
 
—
 
 
 
 
 
 
 
 
 
 
4(ee)
 
001-38086
Form 8-K
(filed on April 9, 2018)
 
4.39
 
—
 
 
 
 
 
 
 
 
 
 
4(ff)
 
001-38086
Form 8-K
(filed on June 15, 2018)
 
4.3
 
—
 
 
 
 
 
 
 
 
 
 
4(gg)
 
001-33443
Form of 8-K
(filed on October 30, 2014)
 
4.9
 
—
 
 
 
 
 
 
 
 
 
 
4(hh)
 
001-33443
Form 8-K
(filed on February 7, 2017)
 
4.2
 
—
 
 
 
 
 
 
 
 
 
 

107

Exhibits
 
Previously Filed With File Number*
 
As
Exhibit
 
 
 
 
4(ii)
 
001-33443
Form10-K (Year ended December 31, 2016)
(filed on February 24, 2017)
 
4.41
 
—
 
 
 
 
 
 
 
 
 
 
4(jj)
 
001-38086
Form 8-K
(filed on April 9, 2018)
 
4.43
 
—
 
 
 
 
 
 
 
 
 
 
4(kk)
 
001-38086
Form 8-K
(filed on June 15, 2018)
 
4.4
 
—
 
 
 
 
 
 
 
 
 
 
4(ll)
 
001-33443
Form of 8-K
(filed on February 7, 2017)
 
4.2
 
—
 
 
 
 
 
 
 
 
 
 
4(mm)
 
001-33443 Form 8-K (filed on October 11, 2016)
 
4.1
 
—
 
 
 
 
 
 
 
 
 
 
4(nn)
 
001-33443
Form10-K (Year ended December 31, 2016)
(filed on February 24, 2017)
 
4.35
 
—
 
 
 
 
 
 
 
 
 
 
4(oo)
 
001-33443
Form10-K (Year ended December 31, 2016)
(filed on February 24, 2017)
 
4.36
 
—
 
 
 
 
 
 
 
 
 
 
4(pp)
 
001-38086
Form 8-K
(filed on April 9, 2018)
 
4.48
 
—
 
 
 
 
 
 
 
 
 
 
4(qq)
 
001-38086
Form 8-K
(filed on June 15, 2018)
 
4.5
 
—
 
 
 
 
 
 
 
 
 
 
4(rr)
 
001-33443
Form 8-K (filed on October 11, 2016)
 
4.1
 
—
 
 
 
 
 
 
 
 
 
 
4(ss)
 
001-33443
Form 8-K (filed on August 21, 2017)
 
4.1
 
—
 
 
 
 
 
 
 
 
 
 
4(tt)
 
001-33443
Form 8-K (filed on August 21, 2017)
 
4.2
 
—
 
 
 
 
 
 
 
 
 
 
4(uu)
 
001-38086
Form 8-K
(filed on April 9, 2018)
 
4.52
 
—
 
 
 
 
 
 
 
 
 
 
4(vv)
 
001-38086
Form 8-K
(filed on June 15, 2018)
 
4.6
 
—
 
 
 
 
 
 
 
 
 
 
4(ww)
 
001-33443
Form 8-K
(filed on August 21, 2017)
 
4.1
 
—
 
 
 
 
 
 
 
 
 
 

108

Exhibits
 
Previously Filed With File Number*
 
As
Exhibit
 
 
 
 
4(xx)
 
001-33443
Form 8-K
(filed on June 21, 2016)
 
4.3
 
—
 
 
 
 
 
 
 
 
 
 
4(yy)
 
001-38086
Registration Statement on Form 8-A
(filed on April 9, 2018)
 
4.5
 
—
 
 
 
 
 
 
 
 
 
 
4(zz)
 
001-33443
Form 8-K
(filed on June 21, 2016)
 
4.3
 
—
 
 
 
 
 
 
 
 
 
 
4(aaa)
 
001-33443
Form 8-K
(filed on June 21, 2016)
 
4.3
 
—
 
 
 
 
 
 
 
 
 
 
4(bbb)
 
001-33443
Form 8-K
(filed on June 21, 2016)
 
4.1
 
—
 
 
 
 
 
 
 
 
 
 
4(ccc)
 
001-33443
Form 8-K
(filed on June 21, 2016)
 
4.2
 
—
 
 
 
 
 
 
 
 
 
 
4(ddd)
 
001-38086
Registration Statement on Form 8-A
(filed on April 9, 2018)
 
4.3
 
—
 
 
 
 
 
 
 
 
 
 
4(eee)
 
001-33443
Form 8-K
(filed on June 21, 2016)
 
4.2
 
—
 
 
 
 
 
 
 
 
 
 
4(fff)
 
001-33443
Form of 8-K
(filed on February 7, 2017)
 
4.1
 
—
 
 
 
 
 
 
 
 
 
 
4(ggg)
 
001-38086
Registration Statement on Form 8-A
(filed on April 9, 2018)
 
4.2
 
—
 
 
 
 
 
 
 
 
 
 
4(hhh)
 
001-33443
Form of 8-K
(filed on February 7, 2017)
 
4.1
 
—
 
 
 
 
 
 
 
 
 
 
4(iii)
 
333-215288
Amendment No. 3
to Form S-1
(filed May 1, 2017)
 
4.1
 
—
 
 
 
 
 
 
 
 
 
 
(10)
 
Material Contracts
 
 
 
 
 
 
 
 
 
10(a)
 
001-38086
Form 8-K
(filed on June 15, 2018)
 
10.1
 
—
 

109

Exhibits
 
Previously Filed With File Number*
 
As
Exhibit
 
 
 
 
 
 
 
 
 
 
 
 
 
10(b)
 
001-38086
Form 8-K
(filed on June 15, 2018)
 
10.2
 
—
 
 
 
 
 
 
 
 
 
 
10(c)
 
001-38086
Form 8-K
(filed on June 15, 2018)
 
10.3
 
—
 
 
 
 
 
 
 
 
 
 
10(d)
 
001-38086
Form 8-K
(filed on April 27, 2018)
 
10.1
 
—
 
 
 
 
 
 
 
 
 
 
(31)
 
Rule 13a-14(a) / 15d-14(a) Certifications
 
 
 
 
 
 
 
 
 
31(a)
 
**
 
 
 
—
 
 
 
 
 
 
 
 
 
 
31(b)
 
**
 
 
 
—
 
 
 
 
 
 
 
 
 
 
(32)
 
Section 1350 Certifications
 
 
 
 
 
 
 
 
 
32(a)
 
**
 
 
 
—
 
 
 
 
 
 
 
 
 
 
32(b)
 
**
 
 
 
—
 
 
 
 
 
 
 
 
 
 
(95)
 
Mine Safety Disclosures
 
 
 
 
 
 
 
 
 
95(a)
 
**
 
 
 
—
 
 
 
 
 
 
 
 
 
 
 
 
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

110

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: August 6, 2018



111

Vistra Corp. Reports