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Delaware
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36-4833255
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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6555 Sierra Drive, Irving, Texas 75039
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(214) 812-4600
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(Address of principal executive offices) (Zip Code)
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(Registrant's telephone number, including area code)
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common stock, par value $0.01 per share
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New York Stock Exchange
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PAGE
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CCGT
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combined cycle gas turbine
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CFTC
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U.S. Commodity Futures Trading Commission
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Chapter 11 Cases
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Cases in the U.S. Bankruptcy Court for the District of Delaware (Bankruptcy Court) concerning voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code (Bankruptcy Code) filed on April 29, 2014 by the Debtors. On the Effective Date, the TCEH Debtors (together with the Contributed EFH Debtors) emerged from the Chapter 11 Cases.
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CME
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Chicago Mercantile Exchange
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CO
2
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carbon dioxide
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Contributed EFH Debtors
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certain EFH Debtors that became subsidiaries of Vistra Energy on the Effective Date
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CSAPR
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Cross-State Air Pollution Rule issued by the EPA in July 2011
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DIP Facility
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TCEH's $3.375 billion debtor-in-possession financing facility, which was repaid in August 2016 (see Note 12 to the Financial Statements)
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DIP Roll Facilities
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TCEH's $4.250 billion debtor-in-possession and exit financing facilities, which was converted to the Vistra Operations Credit Facilities on the Effective Date (see Note 12 to the Financial Statements)
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Debtors
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EFH Corp. and the majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities. Prior to the Effective Date, also included the TCEH Debtors and the Contributed EFH Debtors.
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Dynegy
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Dynegy Inc., and/or its subsidiaries, depending on context
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EBITDA
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earnings (net income) before interest expense, income taxes, depreciation and amortization
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EFCH
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Energy Future Competitive Holdings Company LLC, a direct, wholly owned subsidiary of EFH Corp. and, prior to the Effective Date, the indirect parent of the TCEH Debtors, depending on context
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Effective Date
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October 3, 2016, the date the TCEH Debtors and the Contributed EFH Debtors completed their reorganization under the Bankruptcy Code and emerged from the Chapter 11 Cases
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EFH Corp.
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Energy Future Holdings Corp. and/or its subsidiaries, depending on context, whose major subsidiaries include Oncor and, prior to the Effective Date, included the TCEH Debtors and the Contributed EFH Debtors
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EFH Debtors
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EFH Corp. and its subsidiaries that are Debtors in the Chapter 11 Cases, including EFIH and EFIH Finance Inc., but excluding the TCEH Debtors and the Contributed EFH Debtors
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EFIH
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Energy Future Intermediate Holding Company LLC, a direct, wholly owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings
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Emergence
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emergence of the TCEH Debtors and the Contributed EFH Debtors from the Chapter 11 Cases as subsidiaries of a newly formed company, Vistra Energy, on the Effective Date
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EPA
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U.S. Environmental Protection Agency
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Exchange Act
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Exchange Act of 1934, as amended
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ERCOT
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Electric Reliability Council of Texas, Inc., the independent system operator and the regional coordinator of various electricity systems within Texas
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Federal and State Income Tax Allocation Agreements
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An agreement, executed in May 2012 but effective as of January 2010 to which prior to the Effective Date, EFH Corp. and certain of its subsidiaries (including EFCH, EFIH and TCEH, but not including Oncor Holdings and Oncor) were parties. The Agreement was rejected by the TCEH Debtors and the Contributed EFH Debtors on the Effective Date (see Note 8 to the Financial Statements).
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FERC
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U.S. Federal Energy Regulatory Commission
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GAAP
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generally accepted accounting principles
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GHG
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greenhouse gas
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GWh
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gigawatt-hours
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ICE
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IntercontinentalExchange
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IRS
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U.S. Internal Revenue Service
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ISO
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Independent system operator
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LIBOR
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London Interbank Offered Rate, an interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market
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load
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demand for electricity
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LSTC
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liabilities subject to compromise
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Luminant
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subsidiaries of Vistra Energy engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management, all largely in Texas
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market heat rate
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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.
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Merger
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the proposed merger of Dynegy with and into Vistra Energy, with Vistra Energy as the surviving corporation
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Merger Agreement
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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
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Merger Proposal
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the proposal by each of Vistra Energy and Dynegy to their stockholders to adopt the Merger Agreement
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Merger Support Agreements
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the Merger Support Agreements, dated as of October 29, 2017, by and between Dynegy, the Apollo Entities, the Brookfield Entities and the Oaktree Entities, respectively, on the one hand, and by and between Vistra Energy and certain affiliates of Oaktree and Terawatt Holdings, LP, a Delaware limited partnership affiliated with Energy Capital Partners III, LLC, respectively, on the other hand, as they may be amended or modified from time to time
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MMBtu
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million British thermal units
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MSHA
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U.S. Mine Safety and Health Administration
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MW
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megawatts
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MWh
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megawatt-hours
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NERC
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North American Electric Reliability Corporation
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NO
X
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nitrogen oxide
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NRC
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U.S. Nuclear Regulatory Commission
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NYMEX
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the New York Mercantile Exchange, a commodity derivatives exchange
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NYSE
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New York Stock Exchange
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Oncor
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Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., that is engaged in regulated electricity transmission and distribution activities
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Oncor Holdings
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Oncor Electric Delivery Holdings Company LLC, a direct, wholly owned subsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries, depending on context
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Oncor Ring-Fenced Entities
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Oncor Holdings and its direct and indirect subsidiaries, including Oncor
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OPEB
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postretirement employee benefits other than pensions
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Petition Date
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April 29, 2014, the date the Debtors filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code
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Plan of Reorganization
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Third Amended Joint Plan of Reorganization filed by the Debtors in August 2016 and confirmed by the Bankruptcy Court in August 2016 solely with respect to the TCEH Debtors and the Contributed EFH Debtors
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PrefCo
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Vistra Preferred Inc.
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PrefCo Preferred Stock Sale
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as part of the Spin-Off, the contribution of certain of the assets of the 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
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PUCT
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Public Utility Commission of Texas
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PURA
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Texas Public Utility Regulatory Act
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REP
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retail electric provider
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RCT
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Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas
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S&P
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Standard & Poor's Ratings (a credit rating agency)
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SEC
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U.S. Securities and Exchange Commission
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Securities Act
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Securities Act of 1933, as amended
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SG&A
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selling, general and administrative
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Settlement Agreement
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Amended and Restated Settlement Agreement among the Debtors, the Sponsor Group, settling TCEH first lien creditors, settling TCEH second lien creditors, settling TCEH unsecured creditors and the official committee of unsecured creditors of TCEH (collectively, the Settling Parties), approved by the Bankruptcy Court in December 2015.
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SO
2
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sulfur dioxide
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Spin-Off
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the tax-free spin-off from EFH Corp. executed pursuant to the Plan of Reorganization on the Effective Date by the TCEH Debtors and the Contributed EFH Debtors
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Sponsor Group
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Refers, collectively, to certain investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Global, LLC (together with its affiliates, TPG) and GS Capital Partners, an affiliate of Goldman, Sachs & Co., that have an ownership interest in Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group, that owns substantially all of the common stock of EFH Corp.
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Stock Issuance Proposal
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the proposal by Vistra Energy to its stockholders to approve the issuance of Vistra Energy common stock to holders of Dynegy common stock, in connection with the Merger, as contemplated by the Merger Agreement
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Tax Matters Agreement
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Tax Matters Agreement, dated as of the Effective Date, by and among EFH Corp., EFIH, EFIH Finance Inc. and EFH Merger Co. LLC.
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TCJA
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the Tax Cuts and Jobs Act, a comprehensive tax reform bill signed into law in December 2017
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TRA
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Tax Receivables Agreement, containing certain rights (TRA Rights) to receive payments from Vistra Energy related to certain tax benefits, including those it realized as a result of certain transactions entered into at Emergence (see Note 9)
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TRE
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Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with NERC standards and monitors compliance with ERCOT protocols
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TCEH or Predecessor
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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 the TCEH Debtors, 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
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TCEH Debtors
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the subsidiaries of TCEH that were Debtors in the Chapter 11 Cases
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TCEH Senior Secured Facilities
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Refers, collectively, to the TCEH First Lien Term Loan Facilities, TCEH First Lien Revolving Credit Facility and TCEH First Lien Letter of Credit Facility with a total principal amount of $22.616 billion. The claims arising under these facilities were discharged in the Chapter 11 Cases on the Effective Date pursuant to the Plan of Reorganization.
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TCEQ
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Texas Commission on Environmental Quality
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TXU Energy
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TXU Energy Retail Company LLC, a direct, 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
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U.S.
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United States of America
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Vistra Energy or Successor
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Vistra Energy Corp., formerly known as TCEH Corp., and/or its subsidiaries, depending on context. On the Effective Date, the TCEH Debtors and the Contributed EFH Debtors emerged from Chapter 11 and became subsidiaries of Vistra Energy Corp.
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Vistra Operations Credit Facilities
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Vistra Operations Company LLC's $5.210 billion senior secured financing facilities (see Note 12 to the Financial Statements)
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Item 1.
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BUSINESS
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Integrated business model.
We believe the key factor that distinguishes us from others in our industry is the integrated nature of our business (
i.e.
, pairing Luminant's reliable and efficient mining, generating and wholesale commodity risk management capabilities with TXU Energy's retail platform). Our business strategy will be guided by our integrated business model because we believe it is our core competitive advantage and differentiates us from our non-integrated competitors. We believe our integrated business model creates a unique opportunity because, relative to our non-integrated competitors, it reduces the effects of commodity price movements and contributes to earnings stability. Consequently, our integrated business model is at the core of our business strategy.
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Strong balance sheet and disciplined capital allocation.
Like any energy-focused business, we are potentially subject to significant commodity price volatility and capital costs. Accordingly, our strategy has been, and will continue to be, to maintain a strong balance sheet. As a result, we are focused on maintaining prudent financial leverage supported by readily accessible, flexible and diverse sources of liquidity. Our ongoing capital allocation priorities primarily include making necessary capital investments to maintain the safety and reliability of our facilities. Because we believe cost discipline and strong management of our assets and commodity positions are necessary to deliver long-term value to our stakeholders, we generally make capital allocation decisions that we believe will lead to attractive cash returns on investment.
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Superior customer service.
Through TXU Energy, we serve the retail electricity needs of end-use residential, small business, commercial and industrial electricity customers through multiple sales and marketing channels. In addition to benefitting from our integrated business model, we leverage our brand, our commitment to a consistent and reliable product offering, the backstop of the electricity generated by our generation fleet, our wholesale commodity risk management operations and our strong customer service to differentiate our products and services from our competitors. We strive to be at the forefront of innovation with new offerings and customer experiences to reinforce our value proposition. We maintain a focus on solutions that give our customers choice, convenience and control over how and when they use electricity and related services, including Free Nights and Solar Days residential plans, MyEnergy Dashboard
SM
, TXU iThermostat product and mobile solution, the TXU Energy Rewards program, the TXU Energy Green Up
SM
renewable energy credit program and a diverse set of solar options. Our focus on superior customer service will guide our efforts to acquire new residential and commercial customers, serve and retain existing customers and maintain valuable sales channels for our electricity generation resources. We believe our customer service, products and trusted brand have resulted in TXU Energy maintaining the highest residential customer retention rate of any Texas retail electric provider in its respective core market.
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Excellence in operations while maintaining an efficient cost structure.
We believe that operating our facilities in a safe, reliable, environmentally compliant, and cost-effective and efficient manner is a foundation for delivering long-term stakeholder value. We also believe value increases as a function of making disciplined investments that enable our generation facilities to operate not only effectively and efficiently, but also safely, reliably and in an environmentally compliant manner. We believe that an ongoing focus on operational excellence and safety is a key component to success in a highly competitive environment and is part of the unique value proposition of our integrated model. Additionally, we are committed to optimizing our cost structure and implementing enterprise-wide process and operating improvements without compromising the safety of our communities, customers and employees. In connection with Emergence, in addition to significantly reducing our debt levels, we implemented certain cost-reduction actions in order to better align and right-size our cost structure. We believe we have a highly effective and efficient cost structure and that our cost structure supports excellence in our operations.
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•
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Integrated hedging and commercial management.
Our commercial team is focused on managing risk, through opportunistic hedging, and optimizing our assets and business positions. We actively manage our exposure to wholesale electricity prices in ERCOT, on an integrated basis, through contracts for physical delivery of electricity, exchange-traded and over-the-counter financial contracts, ERCOT term, day-ahead and real-time market transactions, and bilateral contracts with other wholesale market participants, including other power generators and end-user electricity customers. These hedging activities include short-term agreements, long-term electricity sales contracts and forward sales of natural gas through financial instruments. The historically positive correlation between natural gas prices and wholesale electricity prices in ERCOT has provided us an opportunity to manage our exposure to the variability of wholesale electricity prices through natural gas hedging activities. We seek to hedge near-term cash flow and optimize long term value through hedging and forward sales contracts. We believe our integrated hedging and commercial management strategy, in combination with a strong balance sheet and strong liquidity profile, will provide a long-term advantage through cycles of higher and lower commodity prices.
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Growth and enhancement.
Our growth strategy leverages our core capabilities of multi-channel retail marketing in a large and competitive market, operating large-scale, environmentally sensitive, and diverse assets across a variety of fuel technologies, fuel logistics and management, commodity risk management, cost control, and energy infrastructure investing. We intend to opportunistically evaluate acquisitions of high-quality energy infrastructure assets and businesses that complement these core capabilities and enable us to achieve operational or financial synergies. While we are intent on growing our business and creating value for our stockholders, we are committed to making disciplined investments that are consistent with our focus on maintaining a strong balance sheet and strong liquidity profile. As a result, consistent with our disciplined capital allocation approval process, growth opportunities we pursue will need to have compelling economic value in addition to fitting with our business strategy.
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Corporate responsibility and citizenship.
We are committed to providing safe, reliable, cost-effective and environmentally compliant electricity for the communities and customers we serve. We strive to improve the quality of life in the communities in which we operate. We are also committed to being a good corporate citizen in the communities in which we conduct operations. We and our employees are actively engaged in programs intended to support and strengthen the communities in which we conduct operations. Our foremost giving initiatives are through the United Way and TXU Energy Aid campaigns. TXU Energy Aid has served as an integral resource for social service agencies that assist families in need across Texas pay their electricity bills.
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•
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our stockholders may be prevented from realizing the anticipated potential benefits of the Merger;
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the market price of our common stock could decline significantly;
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•
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reputational harm due to the adverse public perception of any failure to successfully complete the Merger;
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•
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under certain circumstances, we may be required to pay Dynegy a termination fee of up to $100 million or reimburse its expenses up to $22 million, and
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•
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the attention of our management and employees may be diverted from their day-to-day business and operational matters and our relationships with our customers and suppliers may be disrupted as a result of efforts relating to attempting to consummate the Merger.
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•
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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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•
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the complexities associated with integrating personnel from the two companies;
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•
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the complexities of combining two companies with different histories, geographic footprints and asset mixes;
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•
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the complexities in combining two companies with separate technology systems;
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•
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potential unknown liabilities and unforeseen increased expenses, delays or conditions associated with the Merger;
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•
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failure to perform by third-party service providers who provide key services for the combined company, and
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•
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performance shortfalls as a result of the diversion of management's attention caused by completing the Merger and integrating the companies' operations.
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•
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hindering its ability to adjust to changing market, industry or economic conditions;
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•
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limiting its ability to access the capital markets to raise additional equity or refinance maturing debt on favorable terms or to fund future working capital, capital expenditures, acquisitions or emerging businesses or other general corporate purposes;
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limiting the amount of free cash flow available for future operations, acquisitions, dividends, stock repurchases or other uses;
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•
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making it more vulnerable to economic or industry downturns, including interest rate increases, and
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placing it at a competitive disadvantage compared to less leveraged competitors.
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limited in how it conducts its business;
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unable to raise additional debt or equity financing to operate during general economic or business downturns, or
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•
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unable to compete effectively or take advantage of new business opportunities.
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•
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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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•
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volatility in ERCOT market heat rates;
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•
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volatility in coal and rail transportation prices;
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•
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fuel transportation capacity constraints or inefficiencies;
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•
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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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•
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changes in electricity and fuel usage resulting from conservation efforts, changes in technology or other factors;
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•
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illiquidity in the wholesale electricity or other commodity markets;
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•
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transmission or transportation disruptions, constraints, inoperability or inefficiencies, or other changes in power transmission infrastructure;
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•
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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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•
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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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•
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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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•
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our creditworthiness and liquidity and the willingness of fuel suppliers and transporters to do business with us;
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•
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changes in the credit risk or payment practices of market participants;
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•
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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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•
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natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events, and
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•
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changes in law, including judicial decisions, federal, state and local energy, environmental and other regulation and legislation.
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•
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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;
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•
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conditions and economic weakness in the ERCOT or general U.S. power markets;
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•
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regulatory developments;
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•
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changes in interest rates;
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•
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a deterioration, or perceived deterioration, of our creditworthiness, enterprise value or financial or operating results;
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•
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a reduction in Vistra Energy's or its applicable subsidiaries' credit ratings;
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•
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our level of indebtedness and compliance with covenants in our debt agreements;
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•
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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;
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•
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security or collateral requirements;
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•
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general credit availability from banks or other lenders for us and our industry peers;
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•
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investor confidence in the industry and in us and the ERCOT wholesale electricity market;
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•
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volatility in commodity prices that increases credit requirements;
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•
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a material breakdown in our risk management procedures;
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•
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the occurrence of changes in our businesses;
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•
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disruptions, constraints, or inefficiencies in the continued reliable operation of our generation facilities, and
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•
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changes in or the operation of provisions of tax and regulatory laws.
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•
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difficulties in the separation of operations and personnel;
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•
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the need to provide significant ongoing post-closing transition support to a buyer;
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•
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management’s attention may be temporarily diverted;
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•
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the retention of certain current or future liabilities in order to induce a buyer to complete a divestiture;
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the obligation to indemnify or reimburse a buyer for certain past liabilities of a divested asset;
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the disruption of our business, and
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•
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potential loss of key employees.
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•
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unscheduled outages or unexpected costs due to equipment, mechanical, structural, cyber security or other problems;
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•
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inadequacy or lapses in maintenance protocols;
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•
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the impairment of reactor operation and safety systems due to human error or force majeure;
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•
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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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•
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limitations on the amounts and types of insurance coverage commercially available, and
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•
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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.
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•
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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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•
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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.
|
•
|
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.
|
•
|
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.
|
Item 1B.
|
UNRESOLVED STAFF COMMENTS
|
Item 2.
|
PROPERTIES
|
Name
|
|
Location (all in the state of Texas)
|
|
Fuel Type
|
|
Dispatch Type
|
|
Installed Nameplate Generation Capacity (MW)
|
|
Number of Units
|
|
Comanche Peak
|
|
Somervell County
|
|
Nuclear
|
|
Baseload
|
|
2,300
|
|
|
2
|
Oak Grove
|
|
Robertson County
|
|
Lignite
|
|
Baseload
|
|
1,600
|
|
|
2
|
Martin Lake
|
|
Rusk County
|
|
Lignite/Coal
|
|
Intermediate/Load Following
|
|
2,250
|
|
|
3
|
Forney
|
|
Kaufman County
|
|
Natural Gas (CCGT)
|
|
Intermediate/Load Following
|
|
1,912
|
|
|
8
|
Lamar
|
|
Lamar County
|
|
Natural Gas (CCGT)
|
|
Intermediate/Load Following
|
|
1,076
|
|
|
6
|
Odessa
|
|
Ector County
|
|
Natural Gas (CCGT)
|
|
Intermediate/Load Following
|
|
1,054
|
|
|
6
|
Morgan Creek
|
|
Mitchell County
|
|
Natural Gas (CT)
|
|
Peaking
|
|
390
|
|
|
6
|
Permian Basin
|
|
Ward County
|
|
Natural Gas (CT)
|
|
Peaking
|
|
325
|
|
|
5
|
DeCordova
|
|
Hood County
|
|
Natural Gas (CT)
|
|
Peaking
|
|
260
|
|
|
4
|
Lake Hubbard
|
|
Dallas County
|
|
Natural Gas (Steam)
|
|
Peaking
|
|
921
|
|
|
2
|
Stryker Creek (a)
|
|
Cherokee County
|
|
Natural Gas (Steam)
|
|
Peaking
|
|
685
|
|
|
2
|
Graham (a)
|
|
Young County
|
|
Natural Gas (Steam)
|
|
Peaking
|
|
630
|
|
|
2
|
Trinidad (a)
|
|
Henderson County
|
|
Natural Gas (Steam)
|
|
Peaking
|
|
244
|
|
|
1
|
Total
|
|
|
|
|
|
|
|
13,647
|
|
|
49
|
(a)
|
We are currently conducting a competitive sales process for our Stryker Creek, Graham and Trinidad units (see Note
4
to the Financial Statements).
|
Item 3.
|
LEGAL PROCEEDINGS
|
Item 4.
|
MINE SAFETY DISCLOSURES
|
Item 5.
|
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|
|
2017
|
|
2016
|
||||||||||||||||
|
Fourth
Quarter
|
|
Third
Quarter
|
|
Second
Quarter
|
|
First
Quarter
|
|
Fourth
Quarter
|
||||||||||
High price
|
$
|
20.49
|
|
|
$
|
18.70
|
|
|
$
|
16.86
|
|
|
$
|
17.95
|
|
|
$
|
16.40
|
|
Low price
|
$
|
17.24
|
|
|
$
|
15.88
|
|
|
$
|
14.59
|
|
|
$
|
15.36
|
|
|
$
|
13.60
|
|
Dividends per common share
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2.32
|
|
Item 6.
|
SELECTED FINANCIAL DATA
|
VISTRA ENERGY CORP.
SELECTED CONSOLIDATED FINANCIAL INFORMATION
(Millions of Dollars, Except Per Share Amounts and Ratios
|
||||||||||||||||||||||||
|
Successor
|
|
|
Predecessor
|
||||||||||||||||||||
|
Year Ended
December 31, 2017
|
|
Period from October 3, 2016
through
December 31, 2016
|
|
|
Period from January 1, 2016
through
October 2, 2016
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
|
|
|
2015
|
|
2014
|
|
2013
|
|||||||||||||||
Operating revenues
|
$
|
5,430
|
|
|
$
|
1,191
|
|
|
|
$
|
3,973
|
|
|
$
|
5,370
|
|
|
$
|
5,978
|
|
|
$
|
5,899
|
|
Impairment of goodwill
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
(2,200
|
)
|
|
$
|
(1,600
|
)
|
|
$
|
(1,000
|
)
|
Impairment of long-lived assets
|
$
|
(25
|
)
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
(2,541
|
)
|
|
$
|
(4,670
|
)
|
|
$
|
(140
|
)
|
Operating income (loss)
|
$
|
198
|
|
|
$
|
(161
|
)
|
|
|
$
|
568
|
|
|
$
|
(4,091
|
)
|
|
$
|
(6,015
|
)
|
|
$
|
(1,113
|
)
|
Net income (loss) (a)
|
$
|
(254
|
)
|
|
$
|
(163
|
)
|
|
|
$
|
22,851
|
|
|
$
|
(4,677
|
)
|
|
$
|
(6,229
|
)
|
|
$
|
(2,197
|
)
|
Cash provided by (used in) operating activities
|
$
|
1,386
|
|
|
$
|
81
|
|
|
|
$
|
(238
|
)
|
|
$
|
237
|
|
|
$
|
444
|
|
|
$
|
(270
|
)
|
Net loss per weighted average share of common stock outstanding — basic
|
$
|
(0.59
|
)
|
|
$
|
(0.38
|
)
|
|
|
|
|
|
|
|
|
|
||||||||
Net loss per weighted average share of common stock outstanding — diluted
|
$
|
(0.59
|
)
|
|
$
|
(0.38
|
)
|
|
|
|
|
|
|
|
|
|
||||||||
Dividend declared per share of common stock
|
$
|
—
|
|
|
$
|
2.32
|
|
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||||||
|
At December 31,
|
|
|
At December 31,
|
||||||||||||||||
|
2017
|
|
2016
|
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
Balance Sheet Information:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets (b)(c)
|
$
|
14,600
|
|
|
$
|
15,167
|
|
|
|
$
|
15,658
|
|
|
$
|
21,343
|
|
|
$
|
28,822
|
|
Property, plant and equipment — net (b)(c)
|
$
|
4,820
|
|
|
$
|
4,443
|
|
|
|
$
|
9,349
|
|
|
$
|
12,288
|
|
|
$
|
17,649
|
|
Goodwill and intangible assets
|
$
|
4,437
|
|
|
$
|
5,112
|
|
|
|
$
|
1,331
|
|
|
$
|
3,688
|
|
|
$
|
5,669
|
|
Long-term debt including current maturities (d)
|
$
|
4,423
|
|
|
$
|
4,623
|
|
|
|
$
|
19
|
|
|
$
|
73
|
|
|
$
|
31,758
|
|
Borrowings under debtor-in-possession credit facility
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
1,425
|
|
|
$
|
1,425
|
|
|
$
|
—
|
|
Pre-Petition notes, loans and other debt reported as liabilities subject to compromise (e)
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
31,668
|
|
|
$
|
31,856
|
|
|
$
|
—
|
|
Total equity/membership interests
|
$
|
6,342
|
|
|
$
|
6,597
|
|
|
|
$
|
(22,884
|
)
|
|
$
|
(18,209
|
)
|
|
$
|
(11,982
|
)
|
(a)
|
For the Predecessor period from January 1, 2016 through October 2, 2016, net income includes net gains totaling $22.121 billion related to bankruptcy-related reorganization items including gains on extinguishing claims pursuant to the Plan of Reorganization (see Notes
5
and
6
to the Financial Statements).
|
(b)
|
At December 31, 2017 and 2016, includes the Lamar and Forney natural gas generation facilities purchased in April 2016, and at December 31, 2017 includes the Odessa-Ector natural gas generation facility purchased in August 2017 (see Note
3
to the Financial Statements).
|
(c)
|
Reflects the impacts of impairment charges related to long-lived assets of $2.541 billion and $4.670 billion in the years ended December 31, 2015 and 2014, respectively (see Note
4
to the Financial Statements).
|
(d)
|
As of December 31, 2013, includes borrowings under Predecessor's credit facilities of $2.054 billion.
|
(e)
|
As of December 31, 2015 and 2014, includes both unsecured and under secured obligations incurred prior to the Petition Date, but excludes pre-petition obligations that were fully secured and other obligations that were allowed to be paid as ordered by the Bankruptcy Court. As of December 31, 2014, also excludes $702 million of deferred debt issuance and extension costs.
|
|
Successor
|
||||||||||||||
|
Quarter Ended
|
||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31 (a)
|
||||||||
2017:
|
|
|
|
|
|
|
|
||||||||
Operating revenues
|
$
|
1,357
|
|
|
$
|
1,296
|
|
|
$
|
1,833
|
|
|
$
|
944
|
|
Operating income (loss)
|
$
|
155
|
|
|
$
|
53
|
|
|
$
|
452
|
|
|
$
|
(462
|
)
|
Net income (loss)
|
$
|
78
|
|
|
$
|
(26
|
)
|
|
$
|
273
|
|
|
$
|
(579
|
)
|
Net income (loss) per weighted average share of common stock outstanding — basic
|
$
|
0.18
|
|
|
$
|
(0.06
|
)
|
|
$
|
0.64
|
|
|
$
|
(1.35
|
)
|
Net income (loss) per weighted average share of common stock outstanding — diluted
|
$
|
0.18
|
|
|
$
|
(0.06
|
)
|
|
$
|
0.64
|
|
|
$
|
(1.35
|
)
|
|
Predecessor
|
|
|
Successor
|
||||||||||||
|
Quarter Ended
|
|
Period from July 1 through
October 2 (b)
|
|
|
Period from October 3 through
December 31
|
||||||||||
|
March 31
|
|
June 30
|
|
|
|
||||||||||
2016:
|
|
|
|
|
|
|
|
|
||||||||
Operating revenues
|
$
|
1,049
|
|
|
$
|
1,233
|
|
|
$
|
1,690
|
|
|
|
$
|
1,191
|
|
Operating income (loss)
|
$
|
39
|
|
|
$
|
(112
|
)
|
|
$
|
640
|
|
|
|
$
|
(161
|
)
|
Net income (loss)
|
$
|
(343
|
)
|
|
$
|
(499
|
)
|
|
$
|
23,693
|
|
|
|
$
|
(163
|
)
|
Net loss per weighted average share of common stock outstanding — basic
|
|
|
|
|
|
|
|
$
|
(0.38
|
)
|
||||||
Net loss per weighted average share of common stock outstanding — diluted
|
|
|
|
|
|
|
|
$
|
(0.38
|
)
|
(a)
|
For the Successor quarter ended December 31, 2017, operating loss includes noncash charges of $183 million related to the generation facilities retirement announcements. Net loss reflects the retirements mentioned above as well as a
$451 million
reduction of deferred tax assets related to the decrease in the corporate tax rate due to the TCJA (see Note
8
to the Financial Statements), partially offset by $117 million of impacts of the TRA.
|
(b)
|
For the Predecessor period from July 1, 2016 through October 2, 2016, net income includes net gains totaling $22.239 billion related to bankruptcy-related reorganization items including gains on extinguishing claims pursuant to the Plan of Reorganization (see Notes
5
and
6
to the Financial Statements).
|
Item 7.
|
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
(a)
|
Settled prices represent the average of NYMEX Henry Hub monthly settled prices of financial contracts for the year ending on the date presented. Forward prices represent the three-year average of NYMEX Henry Hub monthly forward prices at the date presented. Three-year forward prices are presented as such period is generally deemed to be a liquid period.
|
•
|
employing disciplined, liquidity-efficient hedging and risk management strategies through physical and financial energy-related contracts intended to partially hedge gross margins;
|
•
|
continuing focus on cost management to better withstand gross margin volatility;
|
•
|
following a retail pricing strategy that appropriately reflects the value of our product offering to customers, the magnitude and costs of commodity price, liquidity risk and retail demand variability, and
|
•
|
improving retail customer service to attract and retain high-value customers.
|
|
Balance 2018 (a)
|
|
2019
|
$0.50/MMBtu increase in natural gas price (b)(c)
|
$ ~25
|
|
$ ~155
|
$0.50/MMBtu decrease in natural gas price (b)(c)
|
$ ~(15)
|
|
$ ~(155)
|
1.0/MMBtu/MWh increase in market heat rate (d)
|
$ ~60
|
|
$ ~110
|
1.0/MMBtu/MWh decrease in market heat rate (d)
|
$ ~(55)
|
|
$ ~(100)
|
(a)
|
Balance of
2018
is from February 1, 2018 through December 31, 2018 for natural gas price sensitivities and January 1, 2018 through December 31, 2018 for market heat rate sensitivities.
|
(b)
|
Assumes conversion of generation positions based on market heat rates and an estimate of natural gas generally being on the margin 70% to 90% of the time in the ERCOT market.
|
(c)
|
Based on Houston Ship Channel natural gas prices at
December 31, 2017
.
|
(d)
|
Based on ERCOT North Hub around-the-clock heat rates at
December 31, 2017
.
|
•
|
Maintaining competitive pricing initiatives on residential service plans;
|
•
|
Actively competing for new customers in areas open to competition within ERCOT, while continuing to strive to enhance the experience of our existing customers; we are focused on continuing to implement initiatives that deliver world-class customer service and improve the overall customer experience;
|
•
|
Establishing and leveraging our TXU Energy
TM
brand in the sale of electricity to residential and commercial customers, as the most innovative retailer in the ERCOT market by continuing to develop tailored product offerings to meet customer needs, and
|
•
|
Focusing market initiatives largely on programs targeted at retaining the existing highest-value customers and to recapturing customers who have switched REPs, including maintaining and continuously refining a disciplined contracting and pricing approach and economic segmentation of the business market to enhance targeted sales and marketing efforts and to more effectively deploy our direct-sales force; tactical programs we have initiated include improved customer service, aided by an enhanced customer management system, new product price/service offerings and a multichannel approach for the small business market.
|
•
|
the amount of tax basis related to (i) the Lamar and Forney acquisition and (ii) step-up resulting from the PrefCo Preferred Stock Sale (which is estimated to be approximately $5.5 billion) and the allocation of such tax basis step-up among the assets subject thereto;
|
•
|
the depreciable lives of the assets subject to such tax basis step-up, which generally is expected to be 15 years for most of such assets;
|
•
|
a federal corporate income tax rate in all future years of 21%;
|
•
|
the Company generally expects to generate sufficient taxable income to be able to utilize the deductions arising out of (i) the tax basis step up attributable to the PrefCo Preferred Stock Sale, (ii) the entire tax basis of the assets acquired as a result of the Lamar and Forney Acquisition, and (iii) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA in the tax year in which such deductions arise; and
|
•
|
a discount rate of 15%, which represents our view of the rate that a market participant would use based on the risk associated with the uncertainty in the amount and timing of the cash flows, at the time of Emergence.
|
|
Successor
|
||||||||||||||
|
Year Ended December 31, 2017
|
||||||||||||||
|
Wholesale Generation
|
|
Retail
Electricity
|
|
Eliminations / Corporate and Other
|
|
Vistra
Energy Consolidated
|
||||||||
Operating revenues
|
$
|
2,758
|
|
|
$
|
4,058
|
|
|
$
|
(1,386
|
)
|
|
$
|
5,430
|
|
Fuel, purchased power costs and delivery fees
|
(1,588
|
)
|
|
(2,733
|
)
|
|
1,386
|
|
|
(2,935
|
)
|
||||
Operating costs
|
(958
|
)
|
|
(14
|
)
|
|
(1
|
)
|
|
(973
|
)
|
||||
Depreciation and amortization (a)
|
(230
|
)
|
|
(430
|
)
|
|
(39
|
)
|
|
(699
|
)
|
||||
Selling, general and administrative expenses
|
(143
|
)
|
|
(420
|
)
|
|
(37
|
)
|
|
(600
|
)
|
||||
Impairment of long-lived assets
|
(25
|
)
|
|
—
|
|
|
—
|
|
|
(25
|
)
|
||||
Operating income (loss)
|
(186
|
)
|
|
461
|
|
|
(77
|
)
|
|
198
|
|
||||
Other income
|
30
|
|
|
34
|
|
|
(27
|
)
|
|
37
|
|
||||
Other deductions
|
(4
|
)
|
|
—
|
|
|
(1
|
)
|
|
(5
|
)
|
||||
Interest expense and related charges
|
(21
|
)
|
|
—
|
|
|
(172
|
)
|
|
(193
|
)
|
||||
Impacts of Tax Receivable Agreement
|
—
|
|
|
—
|
|
|
213
|
|
|
213
|
|
||||
Income before income taxes
|
$
|
(181
|
)
|
|
$
|
495
|
|
|
(64
|
)
|
|
250
|
|
||
Income tax expense
|
|
|
|
|
(504
|
)
|
|
(504
|
)
|
||||||
Net loss
|
|
|
|
|
$
|
(568
|
)
|
|
$
|
(254
|
)
|
(a)
|
Vistra Energy consolidated depreciation and amortization expense does not include $136 million of nuclear fuel amortization, reported as fuel costs, and intangible net assets and liabilities amortization, reported in various other line items including operating revenues and fuel and purchased power costs and delivery fees.
|
•
|
Our Wholesale Generation segment had strong operating performance from our generation fleet during the peak summer operating months, which was offset by unrealized mark-to-market losses on commodity risk management activities totaling $317 million for the period (including $154 million of unrealized losses on positions with the Retail Electricity segment), resulting in an operating loss of
$186 million
for the period. The unrealized losses were driven by the impacts of the reversal of previously recorded unrealized gains on settled positions and an increase in forward power prices, partially offset by unrealized gains due to a decrease in forward natural gas prices during the period. Operating loss also includes a charge of
$206 million
related to the plant retirement announcements and $320 million in depreciation and amortization expense, including nuclear fuel amortization. Additionally, operating loss includes a $74 million unfavorable impact due to an unplanned outage at one of our nuclear generation units that began in June 2017 ($57 million of lower earnings due to lost generation and $17 million of additional operating costs). The outage required repairs to the plant's steam turbine generator, a standard component in all power stations that is unrelated to Comanche Peak's nuclear reactor, which was not impacted by the outage. The unit returned to service in August 2017. Please see the discussion of Wholesale Generation below for further details.
|
•
|
Our Retail Electricity segment had operating income of
$461 million
for the period, which was primarily driven by favorable profit margins and $154 million of unrealized gains in purchased power costs on positions with the Wholesale Generation segment, partially offset by $476 million in depreciation and amortization expense reflecting amortization expense related to retail customer relationship and retail contracts intangible assets. Please see the discussion of Retail Electricity below for further details.
|
•
|
Net operating expense related to Eliminations and Corporate and Other activities totaled
$77 million
and primarily reflected amortization of software and other technology-related assets (see Note
7
to the Financial Statements) and rent expense.
|
|
Successor
|
||||||||||||||
|
Period from October 3, 2016 through December 31, 2016
|
||||||||||||||
|
Wholesale Generation
|
|
Retail
Electricity
|
|
Eliminations / Corporate and Other
|
|
Vistra
Energy Consolidated
|
||||||||
Operating revenues
|
$
|
450
|
|
|
$
|
912
|
|
|
$
|
(171
|
)
|
|
$
|
1,191
|
|
Fuel, purchased power costs and delivery fees
|
(376
|
)
|
|
(515
|
)
|
|
171
|
|
|
(720
|
)
|
||||
Operating costs
|
(205
|
)
|
|
(3
|
)
|
|
—
|
|
|
(208
|
)
|
||||
Depreciation and amortization (a)
|
(53
|
)
|
|
(153
|
)
|
|
(10
|
)
|
|
(216
|
)
|
||||
Selling, general and administrative expenses
|
(71
|
)
|
|
(130
|
)
|
|
(7
|
)
|
|
(208
|
)
|
||||
Operating income (loss)
|
(255
|
)
|
|
111
|
|
|
(17
|
)
|
|
(161
|
)
|
||||
Other income
|
3
|
|
|
3
|
|
|
4
|
|
|
10
|
|
||||
Interest expense and related charges
|
1
|
|
|
—
|
|
|
(61
|
)
|
|
(60
|
)
|
||||
Impacts of Tax Receivable Agreement
|
—
|
|
|
—
|
|
|
(22
|
)
|
|
(22
|
)
|
||||
Income (loss) before income taxes
|
$
|
(251
|
)
|
|
$
|
114
|
|
|
(96
|
)
|
|
(233
|
)
|
||
Income tax benefit
|
|
|
|
|
70
|
|
|
70
|
|
||||||
Net loss
|
|
|
|
|
$
|
(26
|
)
|
|
$
|
(163
|
)
|
(a)
|
Vistra Energy consolidated depreciation and amortization expense does not include $69 million of nuclear fuel amortization, reported as fuel costs, and intangible net assets and liabilities amortization, reported in various other line items including operating revenues and fuel and purchased power costs and delivery fees.
|
•
|
Our Wholesale Generation segment had an operating loss of
$255 million
for the period, which was primarily driven by unrealized mark-to-market losses on commodity risk management activities totaling $273 million for the period (including $113 million of unrealized losses on positions with the Retail Electricity segment and $22 million of unrealized gains on hedging activities for fuel and purchased power costs). The unrealized losses were driven by increases in forward natural gas prices during the period. Please see the discussion of Wholesale Generation below for further details.
|
•
|
Our Retail Electricity segment had an operating income of
$111 million
for the period, which was primarily driven by favorable profit margins, including $113 million of unrealized gains in purchased power costs on positions with the Wholesale Generation segment. Please see the discussion of Retail Electricity below for further details.
|
•
|
Net operating expense related to Eliminations and Corporate and Other activities totaled
$17 million
and primarily reflected $7 million in amortization of software and other technology-related assets (see Note
7
to the Financial Statements) and $4 million of post-Emergence restructuring fees.
|
|
Successor
|
||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||
Sales volumes (GWh):
|
|
|
|
||||
Retail electricity sales volumes:
|
|
|
|
||||
Residential
|
20,536
|
|
|
4,485
|
|
||
Business markets
|
18,496
|
|
|
4,430
|
|
||
Total retail electricity sales volumes
|
39,032
|
|
|
8,915
|
|
||
Wholesale electricity sales volumes (a)
|
48,578
|
|
|
13,806
|
|
||
Production volumes (GWh):
|
|
|
|
||||
Nuclear facilities
|
16,921
|
|
|
5,373
|
|
||
Lignite and coal facilities
|
51,435
|
|
|
13,654
|
|
||
Natural gas facilities
|
18,522
|
|
|
3,138
|
|
||
Capacity factors:
|
|
|
|
||||
Nuclear facilities
|
84.0
|
%
|
|
105.7
|
%
|
||
Lignite and coal facilities
|
73.2
|
%
|
|
77.1
|
%
|
||
CCGT facilities
|
69.3
|
%
|
|
47.0
|
%
|
||
Market pricing:
|
|
|
|
||||
Average ERCOT North power price ($/MWh)
|
$
|
23.26
|
|
|
$
|
26.52
|
|
Weather (North Texas average) - percent of normal (b):
|
|
|
|
||||
Cooling degree days
|
99.1
|
%
|
|
149.2
|
%
|
||
Heating degree days
|
72.1
|
%
|
|
79.5
|
%
|
(a)
|
Includes net amounts related to sales and purchases of balancing energy in the ERCOT real-time market.
|
(b)
|
Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the U.S. Department of Commerce). Normal is defined as the average over the 10-year period from 2006 to 2015 for the year ended December 31, 2017 and 2001 to 2010 for the period from October 3, 2016 through December 31, 2016.
|
•
|
$1.336 billion in third-party wholesale electricity revenue, which included $1.487 billion in electricity sales to third parties, including revenues from the Odessa power generation facility acquired in August 2017 (see Note
3
to the Financial Statements), and $151 million in unrealized losses from hedging activities reflecting the reversal of previously recorded unrealized gains on settled power positions and an increase in forward power prices, partially offset by unrealized gains due to a decrease in forward natural gas prices, and
|
•
|
$1.385 billion in affiliated revenue with the Retail Electricity segment, which included $1.539 billion in sales for the period and $154 million in unrealized losses on hedging activities with affiliate positions reflecting an increase in forward power prices.
|
•
|
$274 million in third-party wholesale electricity revenue, which included $456 million in electricity sales to third parties, partially offset by $182 million in unrealized losses from hedging activities reflecting an increase in forward natural gas prices and by the reversal of previously recorded unrealized gains on settled power positions, and
|
•
|
$171 million in affiliated revenue with the Retail Electricity segment, which included $284 million in sales for the period, partially offset by $113 million in unrealized losses on hedging activities with affiliate positions reflecting an increase in forward commodity prices.
|
|
Successor
|
||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||
Wholesale electricity sales
|
$
|
1,487
|
|
|
$
|
456
|
|
Unrealized net (losses) on hedging activities
|
(151
|
)
|
|
(182
|
)
|
||
Sales to affiliates
|
1,539
|
|
|
284
|
|
||
Unrealized net (losses) on hedging activities with affiliates
|
(154
|
)
|
|
(113
|
)
|
||
Other revenues
|
37
|
|
|
5
|
|
||
Total wholesale electricity revenues
|
$
|
2,758
|
|
|
$
|
450
|
|
|
Successor
|
||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||
Fuel for nuclear facilities
|
$
|
82
|
|
|
$
|
31
|
|
Fuel for lignite and coal facilities
|
793
|
|
|
229
|
|
||
Fuel for natural gas facilities and purchased power costs
|
613
|
|
|
97
|
|
||
Unrealized (gains) losses from hedging activities
|
12
|
|
|
(22
|
)
|
||
Ancillary and other costs
|
88
|
|
|
41
|
|
||
Total fuel and purchased power costs
|
$
|
1,588
|
|
|
$
|
376
|
|
|
Successor
|
||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||
Retail electricity sales
|
$
|
3,916
|
|
|
$
|
907
|
|
Amortization income (expense) of identifiable intangible assets related to retail contracts (see Note 7 to the Financial Statements)
|
(46
|
)
|
|
(36
|
)
|
||
Other revenues
|
188
|
|
|
41
|
|
||
Total retail electricity revenues
|
$
|
4,058
|
|
|
$
|
912
|
|
|
Successor
|
||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||
Purchases from affiliates
|
$
|
1,539
|
|
|
$
|
284
|
|
Unrealized net gains on hedging activities with affiliates
|
(154
|
)
|
|
(113
|
)
|
||
Delivery fees
|
1,345
|
|
|
320
|
|
||
Other costs
|
3
|
|
|
24
|
|
||
Total purchased power costs and delivery fees
|
$
|
2,733
|
|
|
$
|
515
|
|
|
Predecessor
|
||||||
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||
Operating revenues
|
$
|
3,973
|
|
|
$
|
5,370
|
|
Fuel, purchased power costs and delivery fees
|
(2,082
|
)
|
|
(2,692
|
)
|
||
Net gain from commodity hedging and trading activities
|
282
|
|
|
334
|
|
||
Operating costs
|
(664
|
)
|
|
(834
|
)
|
||
Depreciation and amortization
|
(459
|
)
|
|
(852
|
)
|
||
Selling, general and administrative expenses
|
(482
|
)
|
|
(676
|
)
|
||
Impairment of goodwill
|
—
|
|
|
(2,200
|
)
|
||
Impairment of long-lived assets
|
—
|
|
|
(2,541
|
)
|
||
Operating income (loss)
|
568
|
|
|
(4,091
|
)
|
||
Other income
|
19
|
|
|
18
|
|
||
Other deductions
|
(75
|
)
|
|
(93
|
)
|
||
Interest expense and related charges
|
(1,049
|
)
|
|
(1,289
|
)
|
||
Reorganization items
|
22,121
|
|
|
(101
|
)
|
||
Income (loss) before income taxes
|
21,584
|
|
|
(5,556
|
)
|
||
Income tax benefit
|
1,267
|
|
|
879
|
|
||
Net income (loss)
|
$
|
22,851
|
|
|
$
|
(4,677
|
)
|
|
Predecessor
|
||||||
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||
Operating revenues:
|
|
|
|
||||
Retail electricity revenues
|
$
|
3,154
|
|
|
$
|
4,449
|
|
Wholesale electricity revenues and other operating revenues (a)(b)
|
819
|
|
|
921
|
|
||
Total operating revenues
|
$
|
3,973
|
|
|
$
|
5,370
|
|
Fuel, purchased power costs and delivery fees:
|
|
|
|
||||
Fuel for nuclear facilities
|
$
|
92
|
|
|
$
|
146
|
|
Fuel for lignite and coal facilities
|
548
|
|
|
736
|
|
||
Fuel for natural gas facilities and purchased power costs (a)
|
310
|
|
|
252
|
|
||
Other costs
|
108
|
|
|
166
|
|
||
Delivery fees
|
1,024
|
|
|
1,392
|
|
||
Total
|
$
|
2,082
|
|
|
$
|
2,692
|
|
Sales volumes:
|
|
|
|
||||
Retail electricity sales volumes (GWh):
|
|
|
|
||||
Residential
|
16,619
|
|
|
21,923
|
|
||
Business markets
|
14,354
|
|
|
19,289
|
|
||
Total retail electricity
|
30,973
|
|
|
41,212
|
|
||
Wholesale electricity sales volumes (b)
|
25,563
|
|
|
23,533
|
|
||
Production volumes (GWh):
|
|
|
|
||||
Nuclear facilities
|
15,005
|
|
|
19,954
|
|
||
Lignite and coal facilities (c)
|
31,865
|
|
|
41,817
|
|
||
Natural gas facilities
|
8,539
|
|
|
709
|
|
||
Capacity factors:
|
|
|
|
||||
Nuclear facilities
|
99.2
|
%
|
|
99.0
|
%
|
||
Lignite and coal facilities (c)
|
60.5
|
%
|
|
59.5
|
%
|
||
CCGT facilities
|
65.2
|
%
|
|
N/A
|
|
||
Market pricing:
|
|
|
|
||||
Average ERCOT North power price ($/MWh)
|
$
|
20.78
|
|
|
$
|
23.78
|
|
Weather (North Texas average) - percent of normal (d):
|
|
|
|
||||
Cooling degree days
|
102.8
|
%
|
|
105.4
|
%
|
||
Heating degree days
|
81.9
|
%
|
|
103.8
|
%
|
(a)
|
Upon settlement, physical derivative commodity contracts that we mark-to-market in net income, such as certain electricity sales and purchase agreements and coal purchase contracts, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, rather than contract price. The offsetting differences between contract and market prices are reported in net gain from commodity hedging and trading activities.
|
(b)
|
Includes net amounts related to sales and purchases of balancing energy in the ERCOT real-time market.
|
(c)
|
Includes the estimated effects of economic backdown (including seasonal operations) of lignite/coal-fueled units totaling 14,420 GWh and 19,900 GWh for the period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively.
|
(d)
|
Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the U.S. Department of Commerce). Normal is defined as the average over the 10-year period from 2000 to 2010.
|
•
|
For the period from January 1, 2016 through October 2, 2016, retail electricity revenues totaled $3.154 billion and were negatively impacted by declining average prices and reduced volumes reflecting milder than normal weather in 2016. Wholesale revenues totaled $649 million and were positively impacted by increases in generation volumes (approximately 8,048 GWh) driven by the Lamar and Forney generation assets acquired in April 2016 (see Note
3
to the Financial Statements), partially offset by lower average wholesale electricity prices.
|
•
|
For the year ended December 31, 2015, retail electricity revenues totaled $4.449 billion and were favorably impacted by increased sales volumes driven by increased business volumes, partially offset by lower average retail prices primarily for business market customers. Wholesale revenues totaled $680 million and were negatively impacted by decreases in generation volumes driven by increased economic backdown (including seasonal operations) at lignite and coal generation facilities driven by a decline in wholesale electricity prices.
|
|
Predecessor
|
||||||
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||
Realized net gains
|
$
|
320
|
|
|
$
|
217
|
|
Unrealized net gains (losses)
|
(38
|
)
|
|
117
|
|
||
Total
|
$
|
282
|
|
|
$
|
334
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||||||
Commodity contract net asset at beginning of period
|
$
|
64
|
|
|
$
|
181
|
|
|
|
$
|
271
|
|
|
$
|
180
|
|
Settlements/termination of positions (a)
|
(207
|
)
|
|
(95
|
)
|
|
|
(232
|
)
|
|
(263
|
)
|
||||
Changes in fair value of positions in the portfolio (b)
|
62
|
|
|
(71
|
)
|
|
|
194
|
|
|
380
|
|
||||
Other activity (c)
|
(15
|
)
|
|
49
|
|
|
|
(35
|
)
|
|
(26
|
)
|
||||
Commodity contract net asset (liability) at end of period
|
$
|
(96
|
)
|
|
$
|
64
|
|
|
|
$
|
198
|
|
|
$
|
271
|
|
(a)
|
Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). The Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016 includes reversal of $63 million and $90 million, respectively, of previously recorded unrealized gains related to Vistra Energy beginning balances. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.
|
(b)
|
Represents unrealized net gains (losses) recognized, reflecting the effect of changes in fair value. The Successor period for the year ended December 31, 2017 includes a $23 million inception gain related to long-term power derivatives. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.
|
(c)
|
Represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses. Amounts are generally related to certain margin deposits classified as settlement for certain transactions executed on the CME as well as premiums related to options purchased or sold and the initial fair value of the earn-out provision related to the Odessa Acquisition (see Note
3
to the Financial Statements). The Predecessor period from January 1, 2016 through October 2, 2016 includes fair value of acquired commodity contracts as of the date of the Lamar and Forney Acquisition (see Note
3
to the Financial Statements).
|
|
|
Successor
|
||||||||||||||||||
|
|
Maturity dates of unrealized commodity contract net liability at December 31, 2017
|
||||||||||||||||||
Source of fair value
|
|
Less than
1 year
|
|
1-3 years
|
|
4-5 years
|
|
Excess of
5 years
|
|
Total
|
||||||||||
Prices actively quoted
|
|
$
|
11
|
|
|
$
|
(9
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
Prices provided by other external sources
|
|
(12
|
)
|
|
(33
|
)
|
|
—
|
|
|
—
|
|
|
(45
|
)
|
|||||
Prices based on models
|
|
(16
|
)
|
|
(45
|
)
|
|
(1
|
)
|
|
9
|
|
|
(53
|
)
|
|||||
Total
|
|
$
|
(17
|
)
|
|
$
|
(87
|
)
|
|
$
|
(1
|
)
|
|
$
|
9
|
|
|
$
|
(96
|
)
|
•
|
$74 million primarily for our generation operations;
|
•
|
$14 million for environmental expenditures related to generation units;
|
•
|
$62 million for nuclear fuel purchases, and
|
•
|
$26 million for information technology and other corporate investments.
|
•
|
$18 million primarily for our generation operations;
|
•
|
$22 million for environmental expenditures related to generation units;
|
•
|
$41 million for nuclear fuel purchases, and
|
•
|
$8 million for information technology and other corporate investments.
|
•
|
$171 million primarily for our generation operations;
|
•
|
$40 million for environmental expenditures related to generation units;
|
•
|
$33 million for nuclear fuel purchases, and
|
•
|
$19 million for information technology and other corporate investments.
|
•
|
$230 million primarily for our generation operations;
|
•
|
$82 million for environmental expenditures related to generation units;
|
•
|
$123 million for nuclear fuel purchases, and
|
•
|
$25 million for information technology and other corporate investments.
|
|
December 31, 2017
|
|
December 31, 2016
|
|
Change
|
||||||
Cash and cash equivalents (a)
|
$
|
1,487
|
|
|
$
|
843
|
|
|
$
|
644
|
|
Vistra Operations Credit Facilities — Revolving Credit Facility
|
834
|
|
|
860
|
|
|
(26
|
)
|
|||
Vistra Operations Credit Facilities — Term Loan C Facility (b)
|
7
|
|
|
131
|
|
|
(124
|
)
|
|||
Total liquidity
|
$
|
2,328
|
|
|
$
|
1,834
|
|
|
$
|
494
|
|
(a)
|
Cash and cash equivalents excludes $500 million and $650 million of restricted cash held for letter of credit support at
December 31, 2017 and 2016
, respectively (see Note
21
to the Financial Statements).
|
(b)
|
The Term Loan C Facility is used for issuing letters of credit for general corporate purposes. Borrowings totaling $500 million and $650 million under this facility were held in collateral accounts at
December 31, 2017 and 2016
, respectively, and are reported as restricted cash in our consolidated balance sheets. The
December 31, 2017
restricted cash balance represents borrowings under the Term Loan C Facility held in collateral accounts that support
$493 million
in letters of credit outstanding, leaving
$7 million
in available letter of credit capacity (see Note
12
to the Financial Statements).
|
•
|
$248 million for investments in generation and mining facilities, including approximately:
|
•
|
$231 million primarily for our generation operations and
|
•
|
$17 million for environmental expenditures,
|
•
|
$118 million for nuclear fuel purchases, and
|
•
|
$30 million for information technology and other corporate investments.
|
•
|
$30 million
in cash has been posted with counterparties as compared to $213 million posted at
December 31, 2016
;
|
•
|
$4 million
in cash has been received from counterparties as compared to $41 million received at
December 31, 2016
;
|
•
|
$390 million
in letters of credit have been posted with counterparties as compared to $363 million posted at
December 31, 2016
, and
|
•
|
$3 million in letters of credit have been received from counterparties as compared to $10 million received at
December 31, 2016
.
|
Contractual Cash Obligations:
|
Less Than
One Year
|
|
One to
Three
Years
|
|
Three to
Five
Years
|
|
More
Than Five
Years
|
|
Total
|
||||||||||
Debt – principal, including capital leases (a)
|
$
|
44
|
|
|
$
|
88
|
|
|
$
|
87
|
|
|
$
|
4,189
|
|
|
$
|
4,408
|
|
Debt – interest
|
197
|
|
|
389
|
|
|
382
|
|
|
147
|
|
|
1,115
|
|
|||||
Operating leases
|
17
|
|
|
27
|
|
|
18
|
|
|
150
|
|
|
212
|
|
|||||
Obligations under commodity purchase and services agreements (b)
|
520
|
|
|
368
|
|
|
316
|
|
|
582
|
|
|
1,786
|
|
|||||
Total contractual cash obligations
|
$
|
778
|
|
|
$
|
872
|
|
|
$
|
803
|
|
|
$
|
5,068
|
|
|
$
|
7,521
|
|
(a)
|
Includes $4.311 billion of borrowings under the Vistra Operations Credit Facility and $97 million principal amount of long-term debt, including mandatorily redeemable preferred stock and capital leases. Excludes unamortized premiums, discounts and debt costs.
|
(b)
|
Includes a long-term service and maintenance contract related to our generation assets, 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 year-end 2017 price for all periods except where contractual price adjustment or index-based prices are specified.
|
•
|
the TRA obligation (see Note
9
to the Financial Statements);
|
•
|
arrangements between affiliated entities and intercompany debt (see Note
19
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.
|
|
Year Ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
Month-end average VaR:
|
$
|
92
|
|
|
$
|
65
|
|
Month-end high VaR:
|
$
|
140
|
|
|
$
|
119
|
|
Month-end low VaR:
|
$
|
62
|
|
|
$
|
30
|
|
|
Expected Maturity Date
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||
|
(millions of dollars, except percentages)
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
There-after
|
|
2017
Total Carrying
Amount
|
|
2017
Total Fair
Value
|
|
2016
Total Carrying
Amount
|
|
2016
Total Fair
Value
|
||||||||||||||||||||
Long-term debt, including current maturities (a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Variable rate debt amount
|
$
|
39
|
|
|
$
|
39
|
|
|
$
|
39
|
|
|
$
|
39
|
|
|
$
|
39
|
|
|
$
|
4,116
|
|
|
$
|
4,311
|
|
|
$
|
4,334
|
|
|
$
|
4,500
|
|
|
$
|
4,552
|
|
Average interest rate (b)
|
3.98
|
%
|
|
3.98
|
%
|
|
3.98
|
%
|
|
3.98
|
%
|
|
3.98
|
%
|
|
3.98
|
%
|
|
3.98
|
%
|
|
|
|
4.78
|
%
|
|
|
||||||||||||
Debt swapped to fixed (c):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Notional amount
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,000
|
|
|
$
|
3,000
|
|
|
|
|
$
|
3,000
|
|
|
|
||||
Average pay rate
|
4.59
|
%
|
|
4.59
|
%
|
|
4.59
|
%
|
|
4.59
|
%
|
|
4.59
|
%
|
|
4.59
|
%
|
|
4.59
|
%
|
|
|
|
5.82
|
%
|
|
|
||||||||||||
Average receive rate
|
4.11
|
%
|
|
4.11
|
%
|
|
4.11
|
%
|
|
4.11
|
%
|
|
4.11
|
%
|
|
4.11
|
%
|
|
4.11
|
%
|
|
|
|
4.52
|
%
|
|
|
(a)
|
Capital leases, mandatorily redeemable preferred stock and the effects of unamortized premiums and discounts are excluded from the table.
|
(b)
|
The weighted average interest rate presented is based on the rates in effect at
December 31, 2017
.
|
(c)
|
Interest rate swaps became effective in January 2017 and have maturity dates through July 2023.
|
|
Exposure
Before Credit
Collateral
|
|
Credit
Collateral
|
|
Net
Exposure
|
||||||
Investment grade
|
$
|
132
|
|
|
$
|
—
|
|
|
$
|
132
|
|
Below investment grade or no rating
|
10
|
|
|
6
|
|
|
4
|
|
|||
Totals
|
$
|
142
|
|
|
$
|
6
|
|
|
$
|
136
|
|
•
|
the actions and decisions of regulatory authorities;
|
•
|
prohibitions and other restrictions on our operations due to the terms of our agreements;
|
•
|
prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the U.S. Congress, the FERC, the NERC, the TRE, the PUCT, the RCT, the NRC, the EPA, the TCEQ the MSHA and the CFTC, with respect to, among other things:
|
◦
|
allowed prices;
|
◦
|
industry, market and rate structure;
|
◦
|
purchased power and recovery of investments;
|
◦
|
operations of nuclear generation facilities;
|
◦
|
operations of fossil fueled generation facilities;
|
◦
|
operations of mines;
|
◦
|
acquisition and disposal of assets and facilities;
|
◦
|
development, construction and operation of facilities;
|
◦
|
decommissioning costs;
|
◦
|
present or prospective wholesale and retail competition;
|
◦
|
changes in 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 GHG and other climate change initiatives, and
|
◦
|
clearing over-the-counter derivatives through exchanges and posting of cash collateral therewith;
|
•
|
legal and administrative proceedings and settlements;
|
•
|
general industry trends;
|
•
|
economic conditions, including the impact of an economic downturn;
|
•
|
weather conditions, including drought and limitations on access to water, and other natural phenomena, and acts of sabotage, wars or terrorist or cyber security threats or activities;
|
•
|
our ability to collect trade receivables from counterparties;
|
•
|
our ability to attract and retain profitable customers;
|
•
|
our ability to profitably serve our customers;
|
•
|
restrictions on competitive retail pricing;
|
•
|
changes in wholesale electricity prices or energy commodity prices, including the price of natural gas;
|
•
|
changes in prices of transportation of natural gas, coal, fuel oil and other refined products;
|
•
|
changes in the ability of vendors to provide or deliver commodities as needed;
|
•
|
changes in market heat rates in the ERCOT electricity market;
|
•
|
our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heat rates and interest rates;
|
•
|
population growth or decline, or changes in market supply or demand and demographic patterns, particularly in ERCOT;
|
•
|
access to adequate transmission facilities to meet changing demands;
|
•
|
changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;
|
•
|
changes in operating expenses, liquidity needs and capital expenditures;
|
•
|
commercial bank market and capital market conditions and the potential impact of disruptions in U.S. and international credit markets;
|
•
|
access to capital, the attractiveness of the cost and other terms of such capital and the success of financing and refinancing efforts, including availability of funds in capital markets;
|
•
|
our ability to maintain prudent financial leverage;
|
•
|
our ability to generate sufficient cash flow to make principal and interest payments in respect of, or refinance, our debt obligations:
|
•
|
competition for new energy development and other business opportunities;
|
•
|
our ability to successfully complete our solar generation project in a timely and cost-efficient manner or at all;
|
•
|
inability of various counterparties to meet their obligations with respect to our financial instruments;
|
•
|
changes in technology (including large scale electricity storage) used by and services offered by us;
|
•
|
changes in electricity transmission that allow additional power generation to compete with our generation assets;
|
•
|
our ability to attract and retain qualified employees;
|
•
|
significant changes in our relationship with our employees, including the availability of qualified personnel, and the potential adverse effects if labor disputes or grievances were to occur;
|
•
|
changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits, pension and OPEB, 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;
|
•
|
expectations regarding the Merger, including beliefs concerning stockholder and regulatory approvals;
|
•
|
the occurrence of any event that could give rise to the termination of the Merger Agreement, including a termination of the Merger Agreement under circumstances that could require us to pay a termination fee;
|
•
|
our ability to successfully integrate the businesses of Vistra Energy and Dynegy upon consummation of the Merger and our ability to successfully capture any projected synergies relating to the Merger, and
|
•
|
actions by credit rating agencies.
|
Item 8.
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||||||
Operating revenues
|
$
|
5,430
|
|
|
$
|
1,191
|
|
|
|
$
|
3,973
|
|
|
$
|
5,370
|
|
Fuel, purchased power costs and delivery fees
|
(2,935
|
)
|
|
(720
|
)
|
|
|
(2,082
|
)
|
|
(2,692
|
)
|
||||
Net gain from commodity hedging and trading activities
|
—
|
|
|
—
|
|
|
|
282
|
|
|
334
|
|
||||
Operating costs
|
(973
|
)
|
|
(208
|
)
|
|
|
(664
|
)
|
|
(834
|
)
|
||||
Depreciation and amortization
|
(699
|
)
|
|
(216
|
)
|
|
|
(459
|
)
|
|
(852
|
)
|
||||
Selling, general and administrative expenses
|
(600
|
)
|
|
(208
|
)
|
|
|
(482
|
)
|
|
(676
|
)
|
||||
Impairment of goodwill (Note 7)
|
—
|
|
|
—
|
|
|
|
—
|
|
|
(2,200
|
)
|
||||
Impairment of long-lived assets (Note 4)
|
(25
|
)
|
|
—
|
|
|
|
—
|
|
|
(2,541
|
)
|
||||
Operating income (loss)
|
198
|
|
|
(161
|
)
|
|
|
568
|
|
|
(4,091
|
)
|
||||
Other income (Note 21)
|
37
|
|
|
10
|
|
|
|
19
|
|
|
18
|
|
||||
Other deductions (Note 21)
|
(5
|
)
|
|
—
|
|
|
|
(75
|
)
|
|
(93
|
)
|
||||
Interest expense and related charges (Note 10)
|
(193
|
)
|
|
(60
|
)
|
|
|
(1,049
|
)
|
|
(1,289
|
)
|
||||
Impacts of Tax Receivable Agreement (Note 9)
|
213
|
|
|
(22
|
)
|
|
|
—
|
|
|
—
|
|
||||
Reorganization items (Note 5)
|
—
|
|
|
—
|
|
|
|
22,121
|
|
|
(101
|
)
|
||||
Income (loss) before income taxes
|
250
|
|
|
(233
|
)
|
|
|
21,584
|
|
|
(5,556
|
)
|
||||
Income tax (expense) benefit (Note 8)
|
(504
|
)
|
|
70
|
|
|
|
1,267
|
|
|
879
|
|
||||
Net income (loss)
|
$
|
(254
|
)
|
|
$
|
(163
|
)
|
|
|
$
|
22,851
|
|
|
$
|
(4,677
|
)
|
Weighted average shares of common stock outstanding:
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
427,761,460
|
|
|
427,560,620
|
|
|
|
|
|
|
||||||
Diluted
|
427,761,460
|
|
|
427,560,620
|
|
|
|
|
|
|
||||||
Net income (loss) per weighted average share of common stock outstanding:
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
(0.59
|
)
|
|
$
|
(0.38
|
)
|
|
|
|
|
|
||||
Diluted
|
$
|
(0.59
|
)
|
|
$
|
(0.38
|
)
|
|
|
|
|
|
||||
Dividend declared per share of common stock
|
$
|
—
|
|
|
$
|
2.32
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||||||
Net income (loss)
|
$
|
(254
|
)
|
|
$
|
(163
|
)
|
|
|
$
|
22,851
|
|
|
$
|
(4,677
|
)
|
Other comprehensive income (loss), net of tax effects:
|
|
|
|
|
|
|
|
|
||||||||
Effects related to pension and other retirement benefit obligations (net of tax (benefit) expense of $(6), $3, $— and $—)
|
(23
|
)
|
|
6
|
|
|
|
—
|
|
|
—
|
|
||||
Other comprehensive income, net of tax effects —cash flow hedges derivative value net loss related to hedged transactions recognized during the period (net of tax benefit of $— in all periods)
|
—
|
|
|
—
|
|
|
|
1
|
|
|
2
|
|
||||
Total other comprehensive income (loss)
|
(23
|
)
|
|
6
|
|
|
|
1
|
|
|
2
|
|
||||
Comprehensive income (loss)
|
$
|
(277
|
)
|
|
$
|
(157
|
)
|
|
|
$
|
22,852
|
|
|
$
|
(4,675
|
)
|
VISTRA ENERGY CORP.
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
|
||||||||||||||||
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||||||
Cash flows — operating activities:
|
|
|
|
|
|
|
|
|
||||||||
Net income (loss)
|
$
|
(254
|
)
|
|
$
|
(163
|
)
|
|
|
$
|
22,851
|
|
|
$
|
(4,677
|
)
|
Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:
|
|
|
|
|
|
|
|
|
||||||||
Depreciation and amortization
|
835
|
|
|
285
|
|
|
|
532
|
|
|
995
|
|
||||
Deferred income tax expense (benefit), net
|
418
|
|
|
(76
|
)
|
|
|
(1,270
|
)
|
|
(883
|
)
|
||||
Unrealized net (gain) loss from mark-to-market valuations of derivatives
|
116
|
|
|
176
|
|
|
|
36
|
|
|
(119
|
)
|
||||
Gain on extinguishment of liabilities subject to compromise (Note 5)
|
—
|
|
|
—
|
|
|
|
(24,344
|
)
|
|
—
|
|
||||
Net loss from adopting fresh start reporting (Note 6)
|
—
|
|
|
—
|
|
|
|
2,013
|
|
|
—
|
|
||||
Contract claims adjustments of Predecessor (Note 5)
|
—
|
|
|
—
|
|
|
|
13
|
|
|
54
|
|
||||
Noncash adjustment for estimated allowed claims related to debt (Note 5)
|
—
|
|
|
—
|
|
|
|
—
|
|
|
896
|
|
||||
Adjustment to intercompany claims pursuant to Settlement Agreement (Note 5)
|
—
|
|
|
—
|
|
|
|
—
|
|
|
(1,037
|
)
|
||||
Impairment of goodwill (Note 7)
|
—
|
|
|
—
|
|
|
|
—
|
|
|
2,200
|
|
||||
Impairment of long-lived assets (Note 4)
|
25
|
|
|
—
|
|
|
|
—
|
|
|
2,541
|
|
||||
Write-off of intangible and other assets (Note 21)
|
—
|
|
|
—
|
|
|
|
45
|
|
|
84
|
|
||||
Impacts of Tax Receivable Agreement (Note 9)
|
(213
|
)
|
|
22
|
|
|
|
—
|
|
|
—
|
|
||||
Increase in asset retirement obligation liability
|
112
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||
Accretion expense
|
60
|
|
|
6
|
|
|
|
—
|
|
|
—
|
|
||||
Other, net
|
69
|
|
|
1
|
|
|
|
63
|
|
|
57
|
|
||||
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
||||||||
Affiliate accounts receivable/payable — net
|
—
|
|
|
—
|
|
|
|
31
|
|
|
(4
|
)
|
||||
Accounts receivable — trade
|
7
|
|
|
135
|
|
|
|
(216
|
)
|
|
17
|
|
||||
Inventories
|
22
|
|
|
3
|
|
|
|
71
|
|
|
34
|
|
||||
Accounts payable — trade
|
(30
|
)
|
|
(79
|
)
|
|
|
26
|
|
|
40
|
|
||||
Commodity and other derivative contractual assets and liabilities
|
(1
|
)
|
|
(48
|
)
|
|
|
29
|
|
|
27
|
|
||||
Margin deposits, net
|
146
|
|
|
(193
|
)
|
|
|
(124
|
)
|
|
129
|
|
||||
Accrued interest
|
(10
|
)
|
|
32
|
|
|
|
(10
|
)
|
|
2
|
|
||||
Alcoa contract settlement (Note 4)
|
238
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||
Tax Receivable Agreement payment (Note 9)
|
(26
|
)
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||
Major plant outage deferral
|
(66
|
)
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||
Other — net assets
|
4
|
|
|
(2
|
)
|
|
|
(3
|
)
|
|
(22
|
)
|
||||
Other — net liabilities
|
(66
|
)
|
|
(18
|
)
|
|
|
19
|
|
|
(97
|
)
|
||||
Cash provided by (used in) operating activities
|
1,386
|
|
|
81
|
|
|
|
(238
|
)
|
|
237
|
|
VISTRA ENERGY CORP.
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Unaudited) (Millions of Dollars)
|
||||||||||||||||
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||||||
Cash flows — financing activities:
|
|
|
|
|
|
|
|
|
||||||||
Repayments/repurchases of debt (Note 12)
|
(191
|
)
|
|
—
|
|
|
|
(2,655
|
)
|
|
(21
|
)
|
||||
Incremental Term Loan B Facility (Note 12)
|
—
|
|
|
1,000
|
|
|
|
—
|
|
|
—
|
|
||||
Special Dividend (Note 14)
|
—
|
|
|
(992
|
)
|
|
|
—
|
|
|
—
|
|
||||
Net proceeds from issuance of preferred stock (Note 5)
|
—
|
|
|
—
|
|
|
|
69
|
|
|
—
|
|
||||
Payments to extinguish claims of TCEH first lien creditors (Note 5)
|
—
|
|
|
—
|
|
|
|
(486
|
)
|
|
—
|
|
||||
Payment to extinguish claims of TCEH unsecured creditors (Note 5)
|
—
|
|
|
—
|
|
|
|
(429
|
)
|
|
—
|
|
||||
Borrowings under TCEH DIP Roll Facilities and DIP Facility (Note 12)
|
—
|
|
|
—
|
|
|
|
4,680
|
|
|
—
|
|
||||
TCEH DIP Roll Facilities and DIP Facility financing fees
|
—
|
|
|
—
|
|
|
|
(112
|
)
|
|
(9
|
)
|
||||
Other, net
|
(10
|
)
|
|
(2
|
)
|
|
|
(8
|
)
|
|
—
|
|
||||
Cash provided by (used in) financing activities
|
(201
|
)
|
|
6
|
|
|
|
1,059
|
|
|
(30
|
)
|
||||
Cash flows — investing activities:
|
|
|
|
|
|
|
|
|
||||||||
Capital expenditures
|
(114
|
)
|
|
(48
|
)
|
|
|
(230
|
)
|
|
(337
|
)
|
||||
Nuclear fuel purchases
|
(62
|
)
|
|
(41
|
)
|
|
|
(33
|
)
|
|
(123
|
)
|
||||
Solar development expenditures (Note 3)
|
(190
|
)
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||
Odessa acquisition (Note 3)
|
(355
|
)
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||
Lamar and Forney acquisition — net of cash acquired (Note 3)
|
—
|
|
|
—
|
|
|
|
(1,343
|
)
|
|
—
|
|
||||
Changes in restricted cash
|
186
|
|
|
48
|
|
|
|
233
|
|
|
(123
|
)
|
||||
Proceeds from sales of nuclear decommissioning trust fund securities (Note 21)
|
252
|
|
|
25
|
|
|
|
201
|
|
|
401
|
|
||||
Investments in nuclear decommissioning trust fund securities (Note 21)
|
(272
|
)
|
|
(30
|
)
|
|
|
(215
|
)
|
|
(418
|
)
|
||||
Notes/advances due from affiliates
|
—
|
|
|
—
|
|
|
|
(41
|
)
|
|
(37
|
)
|
||||
Other, net
|
14
|
|
|
1
|
|
|
|
8
|
|
|
(13
|
)
|
||||
Cash used in investing activities
|
(541
|
)
|
|
(45
|
)
|
|
|
(1,420
|
)
|
|
(650
|
)
|
||||
|
|
|
|
|
|
|
|
|
||||||||
Net change in cash and cash equivalents
|
644
|
|
|
42
|
|
|
|
(599
|
)
|
|
(443
|
)
|
||||
Cash and cash equivalents — beginning balance
|
843
|
|
|
801
|
|
|
|
1,400
|
|
|
1,843
|
|
||||
Cash and cash equivalents — ending balance
|
$
|
1,487
|
|
|
$
|
843
|
|
|
|
$
|
801
|
|
|
$
|
1,400
|
|
VISTRA ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
|
|||||||
|
Year Ended December 31,
|
||||||
|
2017
|
|
2016
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
1,487
|
|
|
$
|
843
|
|
Restricted cash (Note 21)
|
59
|
|
|
95
|
|
||
Trade accounts receivable — net (Note 21)
|
582
|
|
|
612
|
|
||
Inventories (Note 21)
|
253
|
|
|
285
|
|
||
Commodity and other derivative contractual assets (Note 16)
|
190
|
|
|
350
|
|
||
Margin deposits related to commodity contracts
|
30
|
|
|
213
|
|
||
Prepaid expense and other current assets
|
72
|
|
|
75
|
|
||
Total current assets
|
2,673
|
|
|
2,473
|
|
||
Restricted cash (Note 21)
|
500
|
|
|
650
|
|
||
Investments (Note 21)
|
1,240
|
|
|
1,064
|
|
||
Property, plant and equipment — net (Note 21)
|
4,820
|
|
|
4,443
|
|
||
Goodwill (Note 7)
|
1,907
|
|
|
1,907
|
|
||
Identifiable intangible assets — net (Note 7)
|
2,530
|
|
|
3,205
|
|
||
Commodity and other derivative contractual assets (Note 16)
|
58
|
|
|
64
|
|
||
Accumulated deferred income taxes (Note 8)
|
710
|
|
|
1,122
|
|
||
Other noncurrent assets
|
162
|
|
|
239
|
|
||
Total assets
|
$
|
14,600
|
|
|
$
|
15,167
|
|
LIABILITIES AND EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Long-term debt due currently (Note 12)
|
$
|
44
|
|
|
$
|
46
|
|
Trade accounts payable
|
473
|
|
|
479
|
|
||
Commodity and other derivative contractual liabilities (Note 16)
|
224
|
|
|
359
|
|
||
Margin deposits related to commodity contracts
|
4
|
|
|
41
|
|
||
Accrued taxes
|
58
|
|
|
31
|
|
||
Accrued taxes other than income
|
136
|
|
|
128
|
|
||
Accrued interest
|
16
|
|
|
33
|
|
||
Asset retirement obligations (Note 21)
|
99
|
|
|
55
|
|
||
Other current liabilities
|
297
|
|
|
332
|
|
||
Total current liabilities
|
1,351
|
|
|
1,504
|
|
||
Long-term debt, less amounts due currently (Note 12)
|
4,379
|
|
|
4,577
|
|
||
Commodity and other derivative contractual liabilities (Note 16)
|
102
|
|
|
2
|
|
||
Tax Receivable Agreement obligation (Note 9)
|
333
|
|
|
596
|
|
||
Asset retirement obligations (Note 21)
|
1,837
|
|
|
1,671
|
|
||
Other noncurrent liabilities and deferred credits (Note 21)
|
256
|
|
|
220
|
|
||
Total liabilities
|
8,258
|
|
|
8,570
|
|
VISTRA ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
|
|||||||
|
Year Ended December 31,
|
||||||
Commitments and Contingencies (Note 13)
|
|
|
|
|
|
||
Total equity (Note 14):
|
|
|
|
||||
Common stock (par value — $0.01; number of shares authorized — 1,800,000,000)
(shares outstanding: December 31, 2017 — 428,398,802; December 31, 2016 — 427,580,232) |
4
|
|
|
4
|
|
||
Additional paid-in-capital
|
7,765
|
|
|
7,742
|
|
||
Retained deficit
|
(1,410
|
)
|
|
(1,155
|
)
|
||
Accumulated other comprehensive income (loss)
|
(17
|
)
|
|
6
|
|
||
Total equity
|
6,342
|
|
|
6,597
|
|
||
Total liabilities and equity
|
$
|
14,600
|
|
|
$
|
15,167
|
|
VISTRA ENERGY CORP.
STATEMENTS OF CONSOLIDATED EQUITY
(Millions of Dollars)
|
|||||||||||||||||||
|
Common Stock (Successor) / Capital Account (Predecessor)
|
|
Additional Paid-In Capital (Successor)
|
|
Retained Deficit (Successor)
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
Total
|
||||||||||
Shareholders' equity in Successor:
|
|
|
|
|
|
|
|
|
|
||||||||||
Balances at October 3, 2016
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Shares issued upon Emergence
|
4
|
|
|
7,737
|
|
|
—
|
|
|
—
|
|
|
7,741
|
|
|||||
Effects of stock-based compensation
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|||||
Other issuances of common stock
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Net loss
|
—
|
|
|
—
|
|
|
(163
|
)
|
|
—
|
|
|
(163
|
)
|
|||||
Dividends declared on common stock
|
—
|
|
|
—
|
|
|
(992
|
)
|
|
—
|
|
|
(992
|
)
|
|||||
Pension and OPEB liability — change in funded status
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
6
|
|
|||||
Balances at December 31, 2016
|
$
|
4
|
|
|
$
|
7,742
|
|
|
$
|
(1,155
|
)
|
|
$
|
6
|
|
|
$
|
6,597
|
|
Net income
|
—
|
|
|
—
|
|
|
(254
|
)
|
|
—
|
|
|
(254
|
)
|
|||||
Effects of stock-based compensation
|
—
|
|
|
23
|
|
|
—
|
|
|
—
|
|
|
23
|
|
|||||
Pension and OPEB liability — change in funded status
|
—
|
|
|
—
|
|
|
—
|
|
|
(23
|
)
|
|
(23
|
)
|
|||||
Other
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|||||
Balances at December 31, 2017
|
$
|
4
|
|
|
$
|
7,765
|
|
|
$
|
(1,410
|
)
|
|
$
|
(17
|
)
|
|
$
|
6,342
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Membership interests in Predecessor:
|
|
|
|
|
|
|
|
|
|
||||||||||
Balances at December 31, 2014
|
$
|
(18,174
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(35
|
)
|
|
$
|
(18,209
|
)
|
Net income
|
(4,677
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,677
|
)
|
|||||
Cash flow hedges — change during period
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2
|
|
|||||
Balances at December 31, 2015
|
$
|
(22,851
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(33
|
)
|
|
$
|
(22,884
|
)
|
Net income
|
22,851
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22,851
|
|
|||||
Cash flow hedges — change during period
|
—
|
|
|
—
|
|
|
—
|
|
|
33
|
|
|
33
|
|
|||||
Balances at October 2, 2016
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
1.
|
BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
|
2.
|
MERGER AGREEMENT
|
3.
|
ACQUISITION AND DEVELOPMENT OF GENERATION FACILITIES
|
Cash paid to seller at close
|
|
$
|
603
|
|
Net working capital adjustments
|
|
(4
|
)
|
|
Consideration paid to seller
|
|
599
|
|
|
Cash paid to repay project financing at close
|
|
950
|
|
|
Total cash paid related to acquisition
|
|
$
|
1,549
|
|
Cash and cash equivalents
|
|
$
|
210
|
|
Property, plant and equipment — net
|
|
1,316
|
|
|
Commodity and other derivative contractual assets
|
|
47
|
|
|
Other assets
|
|
44
|
|
|
Total assets acquired
|
|
1,617
|
|
|
Commodity and other derivative contractual liabilities
|
|
53
|
|
|
Trade accounts payable and other liabilities
|
|
15
|
|
|
Total liabilities assumed
|
|
68
|
|
|
Identifiable net assets acquired
|
|
$
|
1,549
|
|
4.
|
DISPOSITION OF GENERATION FACILITIES
|
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
|
|
|
|
Predecessor
|
||||||
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||
Gain on reorganization adjustments (Note 6)
|
$
|
(24,252
|
)
|
|
$
|
—
|
|
Loss from the adoption of fresh start reporting
|
2,013
|
|
|
—
|
|
||
Expenses related to legal advisory and representation services
|
55
|
|
|
141
|
|
||
Expenses related to other professional consulting and advisory services
|
39
|
|
|
69
|
|
||
Contract claims adjustments
|
13
|
|
|
54
|
|
||
Noncash adjustment for estimated allowed claims related to debt
|
—
|
|
|
896
|
|
||
Adjustment to affiliate claims pursuant to Settlement Agreement (Note 19)
|
—
|
|
|
(635
|
)
|
||
Gain on settlement of debt held by affiliates (Note 19)
|
—
|
|
|
(382
|
)
|
||
Gain on settlement of interest on debt held by affiliates
|
—
|
|
|
(20
|
)
|
||
Sponsor management agreement settlement
|
—
|
|
|
(19
|
)
|
||
Contract assumption adjustments
|
—
|
|
|
(14
|
)
|
||
Fees associated with extension/completion of the DIP Facility
|
—
|
|
|
9
|
|
||
Other
|
11
|
|
|
2
|
|
||
Total reorganization items
|
$
|
(22,121
|
)
|
|
$
|
101
|
|
6.
|
FRESH START REPORTING
|
•
|
historical financial information of our Predecessor for recent years and interim periods;
|
•
|
certain internal financial and operating data of our Predecessor;
|
•
|
certain financial, tax and operational forecasts of Vistra Energy;
|
•
|
certain publicly available financial data for comparable companies to the operating business of Vistra Energy;
|
•
|
the Plan of Reorganization and related documents;
|
•
|
certain economic and industry information relevant to the operating business, and
|
•
|
other studies, analyses and inquiries.
|
Business enterprise value
|
$
|
10,500
|
|
Cash excluded from business enterprise value
|
1,594
|
|
|
Deferred asset related to prepaid capital lease obligation
|
38
|
|
|
Current liabilities, excluding short-term portion of debt and capital leases
|
1,123
|
|
|
Noncurrent, non-interest bearing liabilities
|
1,906
|
|
|
Vistra Energy reorganization value of assets
|
$
|
15,161
|
|
|
October 3, 2016
|
||||||||||||||||||
|
TCEH (Predecessor) (1)
|
|
Reorganization
Adjustments (2)
|
|
Fresh Start
Adjustments
|
|
Vistra Energy (Successor)
|
||||||||||||
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Cash and cash equivalents
|
$
|
1,829
|
|
|
$
|
(1,028
|
)
|
|
(3)
|
|
$
|
—
|
|
|
|
|
$
|
801
|
|
Restricted cash
|
12
|
|
|
131
|
|
|
(4)
|
|
—
|
|
|
|
|
143
|
|
||||
Trade accounts receivable — net
|
750
|
|
|
4
|
|
|
|
|
—
|
|
|
|
|
754
|
|
||||
Advances to parents and affiliates of Predecessor
|
78
|
|
|
(78
|
)
|
|
|
|
—
|
|
|
|
|
—
|
|
||||
Inventories
|
374
|
|
|
—
|
|
|
|
|
(86
|
)
|
|
(17)
|
|
288
|
|
||||
Commodity and other derivative contractual assets
|
255
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
255
|
|
||||
Margin deposits related to commodity contracts
|
42
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
42
|
|
||||
Other current assets
|
47
|
|
|
17
|
|
|
|
|
3
|
|
|
|
|
67
|
|
||||
Total current assets
|
3,387
|
|
|
(954
|
)
|
|
|
|
(83
|
)
|
|
|
|
2,350
|
|
||||
Restricted cash
|
650
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
650
|
|
||||
Advance to parent and affiliates of Predecessor
|
17
|
|
|
(21
|
)
|
|
|
|
4
|
|
|
|
|
—
|
|
||||
Investments
|
1,038
|
|
|
1
|
|
|
|
|
9
|
|
|
(18)
|
|
1,048
|
|
||||
Property, plant and equipment — net
|
10,359
|
|
|
53
|
|
|
|
|
(5,970
|
)
|
|
(19)
|
|
4,442
|
|
||||
Goodwill
|
152
|
|
|
—
|
|
|
|
|
1,755
|
|
|
(27)
|
|
1,907
|
|
||||
Identifiable intangible assets — net
|
1,148
|
|
|
4
|
|
|
|
|
2,256
|
|
|
(20)
|
|
3,408
|
|
||||
Commodity and other derivative contractual assets
|
73
|
|
|
—
|
|
|
|
|
(14
|
)
|
|
|
|
59
|
|
||||
Deferred income taxes
|
—
|
|
|
320
|
|
|
(5)
|
|
730
|
|
|
(21)
|
|
1,050
|
|
||||
Other noncurrent assets
|
51
|
|
|
38
|
|
|
|
|
158
|
|
|
(22)
|
|
247
|
|
||||
Total assets
|
$
|
16,875
|
|
|
$
|
(559
|
)
|
|
|
|
$
|
(1,155
|
)
|
|
|
|
$
|
15,161
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Long-term debt due currently
|
$
|
4
|
|
|
$
|
5
|
|
|
|
|
$
|
(1
|
)
|
|
|
|
$
|
8
|
|
Trade accounts payable
|
402
|
|
|
145
|
|
|
(6)
|
|
3
|
|
|
|
|
550
|
|
||||
Trade accounts and other payables to affiliates of Predecessor
|
152
|
|
|
(152
|
)
|
|
(6)
|
|
—
|
|
|
|
|
—
|
|
||||
Commodity and other derivative contractual liabilities
|
125
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
125
|
|
||||
Margin deposits related to commodity contracts
|
64
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
64
|
|
||||
Accrued income taxes
|
12
|
|
|
12
|
|
|
|
|
—
|
|
|
|
|
24
|
|
||||
Accrued taxes other than income
|
119
|
|
|
4
|
|
|
|
|
—
|
|
|
|
|
123
|
|
||||
Accrued interest
|
110
|
|
|
(109
|
)
|
|
(7)
|
|
—
|
|
|
|
|
1
|
|
||||
Other current liabilities
|
243
|
|
|
170
|
|
|
(8)
|
|
5
|
|
|
|
|
418
|
|
||||
Total current liabilities
|
1,231
|
|
|
75
|
|
|
|
|
7
|
|
|
|
|
1,313
|
|
|
October 3, 2016
|
||||||||||||||||||
|
TCEH (Predecessor) (1)
|
|
Reorganization
Adjustments (2)
|
|
Fresh Start
Adjustments
|
|
Vistra Energy (Successor)
|
||||||||||||
Long-term debt, less amounts due currently
|
—
|
|
|
3,476
|
|
|
(9)
|
|
151
|
|
|
(23)
|
|
3,627
|
|
||||
Borrowings under debtor-in-possession credit facilities
|
3,387
|
|
|
(3,387
|
)
|
|
(9)
|
|
—
|
|
|
|
|
—
|
|
||||
Liabilities subject to compromise
|
33,749
|
|
|
(33,749
|
)
|
|
(10)
|
|
—
|
|
|
|
|
—
|
|
||||
Commodity and other derivative contractual liabilities
|
5
|
|
|
—
|
|
|
|
|
3
|
|
|
|
|
8
|
|
||||
Deferred income taxes
|
256
|
|
|
(256
|
)
|
|
(11)
|
|
—
|
|
|
|
|
—
|
|
||||
Tax Receivable Agreement obligation
|
—
|
|
|
574
|
|
|
(12)
|
|
—
|
|
|
|
|
574
|
|
||||
Asset retirement obligations
|
809
|
|
|
—
|
|
|
|
|
854
|
|
|
(24)
|
|
1,663
|
|
||||
Other noncurrent liabilities and deferred credits
|
1,018
|
|
|
117
|
|
|
(13)
|
|
(900
|
)
|
|
(25)
|
|
235
|
|
||||
Total liabilities
|
40,455
|
|
|
(33,150
|
)
|
|
|
|
115
|
|
|
|
|
7,420
|
|
||||
Equity:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Common stock
|
—
|
|
|
4
|
|
|
(14)
|
|
—
|
|
|
|
|
4
|
|
||||
Additional paid-in-capital
|
—
|
|
|
7,737
|
|
|
(15)
|
|
—
|
|
|
|
|
7,737
|
|
||||
Accumulated other comprehensive income (loss)
|
(32
|
)
|
|
22
|
|
|
|
|
10
|
|
|
(26)
|
|
—
|
|
||||
Predecessor membership interests
|
(23,548
|
)
|
|
24,828
|
|
|
(16)
|
|
(1,280
|
)
|
|
(26)
|
|
—
|
|
||||
Total equity
|
(23,580
|
)
|
|
32,591
|
|
|
|
|
(1,270
|
)
|
|
|
|
7,741
|
|
||||
Total liabilities and equity
|
$
|
16,875
|
|
|
$
|
(559
|
)
|
|
|
|
$
|
(1,155
|
)
|
|
|
|
$
|
15,161
|
|
(1)
|
Represents the consolidated balance sheet of TCEH as of October 3, 2016.
|
(2)
|
Includes the addition of certain assets and liabilities associated with the Contributed EFH Entities. Also includes EFH Corp.'s contribution of liabilities associated with certain employee benefit plans to Vistra Energy.
|
(3)
|
Net adjustments to cash, which represent distributions made or funding provided to an escrow account, classified as restricted cash, under the Plan of Reorganization, as follows:
|
Sources (uses):
|
|
||
Net proceeds from PrefCo preferred stock sale
|
$
|
69
|
|
Addition of cash balances from the Contributed EFH Debtors
|
22
|
|
|
Payments to TCEH first lien creditors, including adequate protection
|
(486
|
)
|
|
Payment to TCEH unsecured creditors (including $73 million to escrow)
|
(502
|
)
|
|
Payment of administrative claims to TCEH creditors
|
(53
|
)
|
|
Payment of legal fees, professional fees and other costs (including $52 million to escrow)
|
(78
|
)
|
|
Net use of cash
|
$
|
(1,028
|
)
|
(4)
|
Increase in restricted cash primarily reflects amounts placed in escrow to satisfy certain secured claims, unsecured claims and professional fee obligations associated with the bankruptcy.
|
(5)
|
Reflects the deferred income tax impact of the Plan of Reorganization implementation, including cancellation of debts and adjustment of tax-basis for certain assets of PrefCo that issued mandatorily redeemable preferred stock as part of the Spin-Off.
|
(6)
|
Primarily reflects the reclassification of transmission and distribution service payables to Oncor from payables with affiliates to trade payables with third parties pursuant to the separation of Vistra Energy from EFH Corp. and payment of accrued professional fees and unsecured claimant obligations incurred in conjunction with Emergence.
|
(7)
|
Primarily reflects the payment of accrued interest and adequate protection to the TCEH first lien creditors on the Effective Date.
|
(8)
|
Primarily reflects the following:
|
•
|
Reclassification of
$82 million
from LSTC related to secured and unsecured claims and
$16 million
in accrued professional fees from accounts payable to other current liabilities.
|
•
|
Additional accruals for
$23 million
of change-in-control obligations and
$26 million
in success fees triggered by Emergence,
$7 million
in professional fees, and
$28 million
of accrued liabilities related to the Contributed EFH Entities.
|
•
|
Payment of
$12 million
in professional fees.
|
(9)
|
Reflects the conversion of the TCEH DIP Roll Facilities of
$3.387 billion
to the Vistra Operations Credit Facilities at Emergence, the issuance and sale of mandatorily redeemable preferred stock of PrefCo for
$70 million
, and the obligation related to a corporate office space lease contributed to Vistra Energy pursuant to the Plan of Reorganization. See Note
12
for additional details.
|
(10)
|
Reflects the elimination of TCEH's liabilities subject to compromise pursuant to the Plan of Reorganization (see Note
5
). Liabilities subject to compromise were settled as follows in accordance with the Plan of Reorganization:
|
Notes, loans and other debt
|
$
|
31,668
|
|
Accrued interest on notes, loans and other debt
|
646
|
|
|
Net liability under terminated TCEH interest rate swap and natural gas hedging agreements
|
1,243
|
|
|
Trade accounts payable and other expected allowed claims
|
192
|
|
|
Third-party liabilities subject to compromise
|
33,749
|
|
|
LSTC from the Contributed EFH Entities
|
8
|
|
|
Total liabilities subject to compromise
|
33,757
|
|
|
Fair value of equity issued to TCEH first lien creditors
|
(7,741
|
)
|
|
TRA Rights issued to TCEH first lien creditors
|
(574
|
)
|
|
Cash distributed and accruals for TCEH first lien creditors
|
(377
|
)
|
|
Cash distributed for TCEH unsecured claims
|
(502
|
)
|
|
Cash distributed and accruals for TCEH administrative claims
|
(60
|
)
|
|
Settlement of affiliate balances
|
(99
|
)
|
|
Net liabilities of contributed entities and other items
|
(60
|
)
|
|
Gain on extinguishment of LSTC
|
$
|
24,344
|
|
(11)
|
Reflects the deferred income tax impact of the Plan of Reorganization implementation, including cancellation of debts and adjustment of tax basis of certain assets of PrefCo.
|
(12)
|
Reflects the estimated present value of the TRA obligation. See Note
9
for further discussion of the TRA obligation valuation assumptions.
|
(13)
|
Primarily reflects the following:
|
•
|
Addition of
$122 million
in liabilities primarily related to benefit plan obligations associated with a pension plan and a health and welfare plan assumed by Vistra Energy pursuant to the Plan of Reorganization. See Note
17
for further discussion of the benefit plan obligations.
|
•
|
Payment of
$7 million
in settlements related to split life insurance costs with a prior affiliate entity.
|
(14)
|
Reflects the issuance of approximately
427,500,000
shares of Vistra Energy common stock, par value of
$0.01
per share, to the TCEH first lien creditors. See Note
14
.
|
(15)
|
Reflects adjustments to present Vistra Energy equity value at approximately
$7.741 billion
based on a reconciliation from the
$10.5 billion
enterprise value described above under
Reorganization Value
as depicted below:
|
Enterprise value
|
$
|
10,500
|
|
Vistra Operations Credit Facility – Initial Term Loan B Facility
|
(2,871
|
)
|
|
Vistra Operations Credit Facility – Term Loan C Facility
|
(655
|
)
|
|
Accrual for post-Emergence claims satisfaction
|
(181
|
)
|
|
Tax Receivable Agreement obligation
|
(574
|
)
|
|
Preferred stock of PrefCo
|
(70
|
)
|
|
Other items
|
(2
|
)
|
|
Cash and cash equivalents
|
801
|
|
|
Restricted cash
|
793
|
|
|
Equity value at Emergence
|
$
|
7,741
|
|
Common stock at par value
|
$
|
4
|
|
Additional paid-in capital
|
7,737
|
|
|
Equity value
|
$
|
7,741
|
|
Shares outstanding at October 3, 2016 (in millions)
|
427.5
|
|
|
Per share value
|
$
|
18.11
|
|
(16)
|
Membership Interest impact of Plan of Reorganization are shown below:
|
Gain on extinguishment of LSTC
|
$
|
24,344
|
|
Elimination of accumulated other comprehensive income
|
(22
|
)
|
|
Change in control payments
|
(23
|
)
|
|
Professional fees
|
(33
|
)
|
|
Other items
|
(14
|
)
|
|
Pretax gain on reorganization adjustments (Note 5)
|
24,252
|
|
|
Deferred tax impact of the Plan of Reorganization and Spin-off
|
576
|
|
|
Total impact to membership interests
|
$
|
24,828
|
|
(17)
|
Reflects the reduction of inventory to fair value, including (1) adjustment of fuel inventory to current market prices, and (2) an adjustment to the fair value of materials and supplies inventory primarily used in our lignite/coal-fueled generation assets and related mining operations.
|
(18)
|
Reflects the
$12 million
increase in the fair value of certain real property assets and
$3 million
reduction of the fair value for other investments.
|
(19)
|
Reflects the change in fair value of property, plant and equipment related primarily to generation and mining assets as detailed below:
|
Property, Plant and Equipment
|
Adjustment
|
Fair Value
|
||||
Generation plants and mining assets
|
$
|
(6,057
|
)
|
$
|
3,698
|
|
Land
|
140
|
|
490
|
|
||
Nuclear Fuel
|
(23
|
)
|
157
|
|
||
Other equipment
|
(30
|
)
|
97
|
|
||
Total
|
$
|
(5,970
|
)
|
$
|
4,442
|
|
(20)
|
Reflects the adjustment in fair value of
$2.256 billion
to identifiable intangible assets, including
$1.636 billion
increase related to retail customer relationships,
$270 million
increase related to the retail trade name,
$190 million
increase related to an electricity supply contract,
$164 million
increase related to retail and wholesale contracts and
$4 million
decrease related to other intangible assets (see Note
7
).
|
(21)
|
Reflects the deferred income tax impact of fresh-start adjustments to property, plant, and equipment, inventory, intangibles and debt issuance costs.
|
(22)
|
Primarily reflects the following:
|
•
|
Addition of
$197 million
regulatory asset related to the deficiency of the nuclear decommissioning trust investment as compared to the nuclear generation plant retirement obligation. Pursuant to Texas regulatory provisions, the trust fund for decommissioning our nuclear generation facility is funded by a fee surcharge billed to REPs by Oncor, as a collection agent, and remitted monthly to Vistra Energy.
|
•
|
Adjustment to remove
$26 million
of unamortized debt issuance costs to reflect the Vistra Operations Credit Facilities at fair market value.
|
(23)
|
Reflects the increase in fair value of the Vistra Operations Credit Facilities in the amount of
$151 million
based on the quoted market prices of the facilities.
|
(24)
|
Increase in fair value of asset retirement obligation related to the plant retirement, mining and reclamation retirement, and coal combustion residuals. See Note
21
for further discussion of our asset retirement obligations.
|
(25)
|
Reflects the following:
|
•
|
Reduction in fair value of unfavorable contracts related to wholesale contracts and a portion of an electricity supply contract in the amount of
$476 million
. See footnote (20) above for further detail.
|
•
|
Reduction of
$465 million
related to reduction in liability that represented excess amounts in the nuclear decommissioning trust above the carrying value of the asset retirement obligation related to our nuclear generation plant decommissioning.
|
•
|
Increase in fair value of obligations related to leased property in the amount of
$29 million
.
|
•
|
Increase in fair value of Pension and OPEB obligations in the amount of
$12 million
.
|
(26)
|
Reflects the extinguishment of Predecessor membership interest and accumulated other comprehensive loss per the Plan of Reorganization.
|
(27)
|
Reflects increase in goodwill balance to present final goodwill as the reorganization value in excess of the identifiable tangible assets, intangible assets, and liabilities at Emergence.
|
Business enterprise value
|
$
|
10,500
|
|
Add: Fair value of liabilities excluded from enterprise value
|
3,030
|
|
|
Less: Fair value of tangible assets
|
(8,215
|
)
|
|
Less: Fair value of identified intangible assets
|
(3,408
|
)
|
|
Vistra Energy goodwill
|
$
|
1,907
|
|
7.
|
GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||||||||||
Identifiable Intangible Asset
|
|
Gross
Carrying
Amount
|
|
Accumulated
Amortization
|
|
Net
|
|
Gross
Carrying
Amount
|
|
Accumulated
Amortization
|
|
Net
|
||||||||||||
Retail customer relationship
|
|
$
|
1,648
|
|
|
$
|
572
|
|
|
$
|
1,076
|
|
|
$
|
1,648
|
|
|
$
|
152
|
|
|
$
|
1,496
|
|
Software and other technology-related assets
|
|
183
|
|
|
47
|
|
|
136
|
|
|
147
|
|
|
9
|
|
|
138
|
|
||||||
Electricity supply contract (a)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
190
|
|
|
2
|
|
|
188
|
|
||||||
Retail and wholesale contracts
|
|
154
|
|
|
87
|
|
|
67
|
|
|
164
|
|
|
38
|
|
|
126
|
|
||||||
Other identifiable intangible assets (b)
|
|
33
|
|
|
11
|
|
|
22
|
|
|
30
|
|
|
2
|
|
|
28
|
|
||||||
Total identifiable intangible assets subject to amortization
|
|
$
|
2,018
|
|
|
$
|
717
|
|
|
1,301
|
|
|
$
|
2,179
|
|
|
$
|
203
|
|
|
1,976
|
|
||
Retail trade names (not subject to amortization)
|
|
|
|
|
|
1,225
|
|
|
|
|
|
|
1,225
|
|
||||||||||
Mineral interests (not currently subject to amortization)
|
|
|
|
|
|
4
|
|
|
|
|
|
|
4
|
|
||||||||||
Total identifiable intangible assets
|
|
|
|
|
|
$
|
2,530
|
|
|
|
|
|
|
$
|
3,205
|
|
(a)
|
Contract terminated in October 2017. See Note
4
.
|
(b)
|
Includes mining development costs and environmental allowances and credits.
|
(a)
|
Amounts recorded in depreciation and amortization totaled
$463 million
,
$162 million
,
$58 million
and
$85 million
for the Successor period for the year ended
December 31, 2017
and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended
December 31, 2015
, respectively.
|
•
|
Retail customer relationship
– Retail customer relationship intangible asset represents the fair value of our non-contracted 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 retail trade name intangible asset represents the fair value of the TXU Energy
TM
and 4Change Energy
TM
trade names, and was determined to be an indefinite-lived asset not subject to amortization. This intangible asset is evaluated for impairment at least annually in accordance with accounting guidance related to goodwill and other indefinite-lived intangible assets. Significant assumptions included within the development of the fair value estimate include TXU Energy's and 4Change Energy's estimated gross margins for future periods and implied royalty rates. On the most recent testing date, we determined that it was more likely than not that the fair value of our retail trade name intangible asset exceeded its carrying value at October 1, 2017.
|
•
|
Electricity supply contract
– The electricity supply contract represents a long-term fixed-price supply contract for the sale of electricity from one of our generation facilities that was measured at fair value at Emergence. The value of this contract under our Predecessor was recorded as an unfavorable liability due to prevailing market prices of electricity when the contract was established in 2007. Significant assumptions included in the fair value measurement for this contract include long-term wholesale electricity price forecasts and operating cost forecasts for the respective generation facility. This contract was terminated in October 2017. See Note
4
.
|
•
|
Retail and wholesale contracts
– These intangible assets represent the favorable value of various retail and wholesale contracts (both purchase and sale contracts) that were measured at fair value by utilizing prevailing market prices for commodities or services compared to the fixed prices contained in these agreements. The value of these contracts is being amortized using a method that is based on the monthly value of each contract measured at Emergence.
|
Year
|
|
Estimated Amortization Expense
|
||
2018
|
|
$
|
367
|
|
2019
|
|
$
|
268
|
|
2020
|
|
$
|
191
|
|
2021
|
|
$
|
142
|
|
2022
|
|
$
|
4
|
|
8.
|
INCOME TAXES
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||||||
Current:
|
|
|
|
|
|
|
|
|
||||||||
U.S. Federal
|
$
|
72
|
|
|
$
|
—
|
|
|
|
$
|
(6
|
)
|
|
$
|
(17
|
)
|
State
|
14
|
|
|
6
|
|
|
|
9
|
|
|
21
|
|
||||
Total current
|
86
|
|
|
6
|
|
|
|
3
|
|
|
4
|
|
||||
Deferred:
|
|
|
|
|
|
|
|
|
||||||||
U.S. Federal
|
417
|
|
|
(75
|
)
|
|
|
(1,234
|
)
|
|
(811
|
)
|
||||
State
|
1
|
|
|
(1
|
)
|
|
|
(36
|
)
|
|
(72
|
)
|
||||
Total deferred
|
418
|
|
|
(76
|
)
|
|
|
(1,270
|
)
|
|
(883
|
)
|
||||
Total
|
$
|
504
|
|
|
$
|
(70
|
)
|
|
|
$
|
(1,267
|
)
|
|
$
|
(879
|
)
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||||||
Income (loss) before income taxes
|
$
|
250
|
|
|
$
|
(233
|
)
|
|
|
$
|
21,584
|
|
|
$
|
(5,556
|
)
|
Income taxes at the U.S. federal statutory rate of 35%
|
88
|
|
|
(82
|
)
|
|
|
7,554
|
|
|
(1,945
|
)
|
||||
Nondeductible TRA accretion
|
(80
|
)
|
|
5
|
|
|
|
—
|
|
|
—
|
|
||||
Texas margin tax, net of federal benefit
|
13
|
|
|
3
|
|
|
|
(21
|
)
|
|
—
|
|
||||
Impacts of tax reform legislation on deferred taxes
|
451
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||
Effects of Tax Matters Agreement and tax-free spin-off transaction
|
19
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||
Nondeductible debt restructuring costs
|
—
|
|
|
2
|
|
|
|
38
|
|
|
64
|
|
||||
Nondeductible interest expense
|
—
|
|
|
—
|
|
|
|
12
|
|
|
21
|
|
||||
Nontaxable gain on extinguishment of LSTC
|
—
|
|
|
—
|
|
|
|
(8,593
|
)
|
|
—
|
|
||||
Valuation allowance
|
—
|
|
|
—
|
|
|
|
(210
|
)
|
|
210
|
|
||||
Nondeductible goodwill impairment
|
—
|
|
|
—
|
|
|
|
—
|
|
|
770
|
|
||||
Lignite depletion allowance
|
—
|
|
|
—
|
|
|
|
—
|
|
|
(8
|
)
|
||||
Interest accrued for uncertain tax positions, net of tax
|
—
|
|
|
—
|
|
|
|
—
|
|
|
(2
|
)
|
||||
Other
|
13
|
|
|
2
|
|
|
|
(47
|
)
|
|
11
|
|
||||
Income tax expense (benefit)
|
$
|
504
|
|
|
$
|
(70
|
)
|
|
|
$
|
(1,267
|
)
|
|
$
|
(879
|
)
|
Effective tax rate
|
201.6
|
%
|
|
30.0
|
%
|
|
|
(5.9
|
)%
|
|
15.8
|
%
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
Noncurrent Deferred Income Tax Assets
|
|
|
|
||||
Net operating loss (NOL) carryforwards
|
$
|
—
|
|
|
$
|
8
|
|
Property, plant and equipment
|
520
|
|
|
943
|
|
||
Intangible assets
|
81
|
|
|
29
|
|
||
Long-term debt
|
20
|
|
|
52
|
|
||
Employee benefit obligations
|
56
|
|
|
84
|
|
||
Commodity contracts and interest rate swaps
|
25
|
|
|
—
|
|
||
Other
|
8
|
|
|
6
|
|
||
Total deferred tax assets
|
$
|
710
|
|
|
$
|
1,122
|
|
|
Predecessor
|
||||||
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||
Balance at beginning of period, excluding interest and penalties
|
$
|
36
|
|
|
$
|
65
|
|
Reductions based on tax positions related to prior years
|
(1
|
)
|
|
(11
|
)
|
||
Settlements with taxing authorities
|
(35
|
)
|
|
(18
|
)
|
||
Balance at end of period, excluding interest and penalties
|
$
|
—
|
|
|
$
|
36
|
|
9.
|
TAX RECEIVABLE AGREEMENT OBLIGATION
|
|
Successor
|
||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||
TRA obligation at the beginning of the period
|
$
|
596
|
|
|
$
|
574
|
|
Accretion expense
|
82
|
|
|
22
|
|
||
Payments
|
(26
|
)
|
|
—
|
|
||
Revaluation due to tax reform legislation
|
(233
|
)
|
|
—
|
|
||
Changes in tax assumptions impacting timing of payments
|
(62
|
)
|
|
—
|
|
||
TRA obligation at the end of the period
|
357
|
|
|
596
|
|
||
Less amounts due currently
|
(24
|
)
|
|
—
|
|
||
Noncurrent TRA obligation at the end of the period
|
$
|
333
|
|
|
$
|
596
|
|
10.
|
INTEREST EXPENSE AND RELATED CHARGES
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||||||
Interest paid/accrued post-Emergence
|
$
|
213
|
|
|
$
|
51
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Interest paid/accrued on debtor-in-possession financing
|
—
|
|
|
—
|
|
|
|
76
|
|
|
63
|
|
||||
Adequate protection amounts paid/accrued
|
—
|
|
|
—
|
|
|
|
977
|
|
|
1,233
|
|
||||
Unrealized mark-to-market net (gains) losses on interest rate swaps
|
(29
|
)
|
|
11
|
|
|
|
—
|
|
|
—
|
|
||||
Capitalized interest
|
(7
|
)
|
|
(3
|
)
|
|
|
(9
|
)
|
|
(11
|
)
|
||||
Other
|
16
|
|
|
1
|
|
|
|
5
|
|
|
4
|
|
||||
Total interest expense and related charges
|
$
|
193
|
|
|
$
|
60
|
|
|
|
$
|
1,049
|
|
|
$
|
1,289
|
|
|
Predecessor
|
||||||
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||
Contractual interest on debt classified as LSTC
|
$
|
1,570
|
|
|
$
|
2,070
|
|
Adequate protection amounts paid/accrued
|
930
|
|
|
1,173
|
|
||
Contractual interest on debt classified as LSTC not paid/accrued
|
$
|
640
|
|
|
$
|
897
|
|
11.
|
EARNINGS PER SHARE
|
|
Successor
|
||||||||||||||||||||
|
Year Ended
December 31, 2017
|
|
Period from October 3, 2016 through December 31, 2016
|
||||||||||||||||||
|
Net Loss
|
|
Shares
|
|
Per Share Amount
|
|
Net Loss
|
|
Shares
|
|
Per Share Amount
|
||||||||||
Net loss available for common stock — basic
|
$
|
(254
|
)
|
|
427,761,460
|
|
|
$
|
(0.59
|
)
|
|
$
|
(163
|
)
|
|
427,560,620
|
|
|
$
|
(0.38
|
)
|
Net loss available for common stock — diluted
|
$
|
(254
|
)
|
|
427,761,460
|
|
|
$
|
(0.59
|
)
|
|
$
|
(163
|
)
|
|
427,560,620
|
|
|
$
|
(0.38
|
)
|
12.
|
LONG-TERM DEBT
|
|
December 31,
2017 |
|
December 31,
2016 |
||||
Vistra Operations Credit Facilities (a)
|
$
|
4,323
|
|
|
$
|
4,515
|
|
Mandatorily redeemable subsidiary preferred stock (b)
|
70
|
|
|
70
|
|
||
8.82% Building Financing due semiannually through February 11, 2022 (c)
|
30
|
|
|
36
|
|
||
Capital lease obligations
|
—
|
|
|
2
|
|
||
Total long-term debt including amounts due currently
|
4,423
|
|
|
4,623
|
|
||
Less amounts due currently
|
(44
|
)
|
|
(46
|
)
|
||
Total long-term debt less amounts due currently
|
$
|
4,379
|
|
|
$
|
4,577
|
|
(a)
|
At
December 31, 2017
, borrowings under the Vistra Operations Credit Facilities in our consolidated balance sheet include debt premiums of
$21 million
, debt discounts of
$2 million
and debt issuance costs of
$7 million
. At
December 31, 2016
, borrowings under the Vistra Operations Credit Facilities in our consolidated balance sheet include debt premiums of
$25 million
, debt discounts of
$2 million
and debt issuance costs of
$8 million
.
|
(b)
|
Shares of mandatorily redeemable preferred stock in PrefCo issued as part of the spin-off of Vistra Energy from EFH Corp. (see Note
5
). This subsidiary preferred stock is accounted for as a debt instrument under relevant accounting guidance.
|
(c)
|
Obligation related to a corporate office space capital lease transferred to Vistra Energy pursuant to the Plan of Reorganization. This obligation will be funded by amounts held in an escrow account that is reflected in other noncurrent assets in our consolidated balance sheets.
|
|
|
|
|
December 31, 2017
|
||||||||||
Vistra Operations Credit Facilities
|
|
Maturity Date
|
|
Facility
Limit
|
|
Cash
Borrowings
|
|
Available
Capacity
|
||||||
Revolving Credit Facility (a)
|
|
August 4, 2021
|
|
$
|
860
|
|
|
$
|
—
|
|
|
$
|
834
|
|
Initial Term Loan B Facility (b)(c)
|
|
August 4, 2023
|
|
2,850
|
|
|
2,821
|
|
|
—
|
|
|||
Incremental Term Loan B Facility (c)
|
|
December 14, 2023
|
|
1,000
|
|
|
990
|
|
|
—
|
|
|||
Term Loan C Facility (d)
|
|
August 4, 2023
|
|
650
|
|
|
500
|
|
|
7
|
|
|||
Total Vistra Operations Credit Facilities
|
|
|
|
$
|
5,360
|
|
|
$
|
4,311
|
|
|
$
|
841
|
|
(a)
|
Facility to be used for general corporate purposes. Facility includes a
$715 million
letter of credit sub-facility, of which
$26 million
of letters of credit were outstanding at
December 31, 2017
.
|
(b)
|
Facility used to repay all amounts outstanding under our Predecessor's DIP Facility and issuance costs for the DIP Roll Facilities, with the remaining balance used for general corporate purposes.
|
(c)
|
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. Amounts paid cannot be reborrowed.
|
(d)
|
Facility used for issuing letters of credit for general corporate purposes. Borrowings under this facility were funded to collateral accounts that are reported as restricted cash in our consolidated balance sheets. Cash borrowings reflect a
$150 million
principal reduction paid from restricted cash in December 2017. Amounts paid cannot be reborrowed. At
December 31, 2017
, the restricted cash supported
$493 million
in letters of credit outstanding (see Note
21
), leaving
$7 million
in available letter of credit capacity.
|
|
December 31, 2017
|
||
2018
|
$
|
44
|
|
2019
|
44
|
|
|
2020
|
44
|
|
|
2021
|
45
|
|
|
2022
|
42
|
|
|
Thereafter
|
4,189
|
|
|
Unamortized premiums, discounts and debt issuance costs
|
15
|
|
|
Total long-term debt, including amounts due currently
|
$
|
4,423
|
|
13.
|
COMMITMENTS AND CONTINGENCIES
|
|
Coal purchase and
transportation agreements
|
|
Pipeline transportation and storage reservation fees
|
|
Nuclear
Fuel Contracts
|
|
Other
Contracts
|
||||||||
2018
|
$
|
12
|
|
|
$
|
39
|
|
|
$
|
120
|
|
|
$
|
158
|
|
2019
|
—
|
|
|
28
|
|
|
48
|
|
|
46
|
|
||||
2020
|
—
|
|
|
28
|
|
|
47
|
|
|
55
|
|
||||
2021
|
—
|
|
|
29
|
|
|
55
|
|
|
36
|
|
||||
2022
|
—
|
|
|
29
|
|
|
32
|
|
|
89
|
|
||||
Thereafter
|
—
|
|
|
141
|
|
|
193
|
|
|
194
|
|
||||
Total
|
$
|
12
|
|
|
$
|
294
|
|
|
$
|
495
|
|
|
$
|
578
|
|
|
Operating Leases (a)
|
||
2018
|
$
|
17
|
|
2019
|
15
|
|
|
2020
|
12
|
|
|
2021
|
10
|
|
|
2022
|
8
|
|
|
Thereafter
|
150
|
|
|
Total future minimum lease payments
|
$
|
212
|
|
(a)
|
Includes operating leases with initial or remaining noncancellable lease terms in excess of one year.
|
•
|
$390 million
to support commodity risk management collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and collateral postings with ERCOT;
|
•
|
$45 million
to support executory contracts and insurance agreements;
|
•
|
$55 million
to support our REP financial requirements with the PUCT, and
|
•
|
$29 million
for other credit support requirements.
|
14.
|
EQUITY
|
|
Successor
|
||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||
Shares outstanding at beginning of period
|
427,580,232
|
|
|
—
|
|
Shares issued (a)
|
818,570
|
|
|
427,580,232
|
|
Shares repurchased
|
—
|
|
|
—
|
|
Shares outstanding at end of period
|
428,398,802
|
|
|
427,580,232
|
|
(a)
|
Includes share awards granted to directors and other nonemployees.
|
15.
|
FAIR VALUE MEASUREMENTS
|
•
|
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.
|
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
|
|
December 31, 2016
|
|||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3 (a)
|
|
Reclassification (b)
|
|
Total
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity contracts
|
$
|
167
|
|
|
$
|
131
|
|
|
$
|
98
|
|
|
$
|
—
|
|
|
$
|
396
|
|
Interest rate swaps
|
—
|
|
|
5
|
|
|
—
|
|
|
13
|
|
|
18
|
|
|||||
Nuclear decommissioning trust –
equity securities (c) |
425
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
425
|
|
|||||
Nuclear decommissioning trust –
debt securities (c) |
—
|
|
|
340
|
|
|
—
|
|
|
—
|
|
|
340
|
|
|||||
Sub-total
|
$
|
592
|
|
|
$
|
476
|
|
|
$
|
98
|
|
|
$
|
13
|
|
|
1,179
|
|
|
Assets measured at net asset value (d):
|
|
|
|
|
|
|
|
|
|
||||||||||
Nuclear decommissioning trust –
equity securities (c) |
|
|
|
|
|
|
|
|
247
|
|
|||||||||
Total assets
|
|
|
|
|
|
|
|
|
$
|
1,426
|
|
||||||||
Liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity contracts
|
$
|
302
|
|
|
$
|
15
|
|
|
$
|
15
|
|
|
$
|
—
|
|
|
$
|
332
|
|
Interest rate swaps
|
—
|
|
|
16
|
|
|
—
|
|
|
13
|
|
|
29
|
|
|||||
Total liabilities
|
$
|
302
|
|
|
$
|
31
|
|
|
$
|
15
|
|
|
$
|
13
|
|
|
$
|
361
|
|
(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 consolidated balance sheets.
|
(c)
|
The nuclear decommissioning trust investment is included in the other investments line in our consolidated balance sheets. See Note
21
.
|
(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 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.
|
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 options
|
|
—
|
|
|
(91
|
)
|
|
(91
|
)
|
|
Option Pricing Model
|
|
Gas to power correlation (e)
|
|
30% to 100%
|
|||
|
|
|
|
|
|
|
|
|
|
Power volatility (e)
|
|
5% to 180%
|
||||||
Electricity congestion revenue rights
|
|
45
|
|
|
(4
|
)
|
|
41
|
|
|
Market Approach (f)
|
|
Illiquid price differences between settlement points (g)
|
|
$0 to $15/ MWh
|
|||
Other (h)
|
|
18
|
|
|
—
|
|
|
18
|
|
|
|
|
|
|
|
|||
Total
|
|
$
|
75
|
|
|
$
|
(128
|
)
|
|
$
|
(53
|
)
|
|
|
|
|
|
|
December 31, 2016
|
||||||||||||||||||
|
|
Fair Value
|
|
|
|
|
|
|
||||||||||
Contract Type (a)
|
|
Assets
|
|
Liabilities
|
|
Total
|
|
Valuation Technique
|
|
Significant Unobservable Input
|
|
Range (b)
|
||||||
Electricity purchases and sales
|
|
$
|
32
|
|
|
$
|
—
|
|
|
$
|
32
|
|
|
Valuation Model
|
|
Hourly price curve shape (c)
|
|
$0 to $35/ MWh
|
|
|
|
|
|
|
|
|
|
|
Illiquid delivery periods for ERCOT hub power prices and heat rates (d)
|
|
$30 to $70/ MWh
|
||||||
Electricity congestion revenue rights
|
|
42
|
|
|
(6
|
)
|
|
36
|
|
|
Market Approach (f)
|
|
Illiquid price differences between settlement points (g)
|
|
$0 to $10/ MWh
|
|||
Other (h)
|
|
24
|
|
|
(9
|
)
|
|
15
|
|
|
|
|
|
|
|
|||
Total
|
|
$
|
98
|
|
|
$
|
(15
|
)
|
|
$
|
83
|
|
|
|
|
|
|
|
(a)
|
Electricity purchase and sales contracts include power and heat rate positions in ERCOT regions. Electricity congestion revenue rights contracts consist of forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points within ERCOT. Electricity options consist of physical electricity options and spread options.
|
(b)
|
The range of the inputs may be influenced by factors such as time of day, delivery period, season and location.
|
(c)
|
Based on the historical range of forward average hourly ERCOT North Hub prices.
|
(d)
|
Based on historical forward ERCOT power price and heat rate variability.
|
(e)
|
Based on historical forward correlation and volatility within ERCOT.
|
(f)
|
While we use the market approach, there is insufficient market data to consider the valuation liquid.
|
(g)
|
Based on the historical price differences between settlement points within ERCOT hubs and load zones.
|
(h)
|
Other includes contracts for natural gas, weather options and coal options. December 31, 2016 also includes an immaterial amount of electricity options.
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||||||
Net asset balance at beginning of period (a)
|
$
|
83
|
|
|
$
|
81
|
|
|
|
$
|
37
|
|
|
$
|
35
|
|
Total unrealized valuation gains (losses)
|
(136
|
)
|
|
31
|
|
|
|
122
|
|
|
27
|
|
||||
Purchases, issuances and settlements (b):
|
|
|
|
|
|
|
|
|
||||||||
Purchases
|
69
|
|
|
15
|
|
|
|
37
|
|
|
49
|
|
||||
Issuances
|
(22
|
)
|
|
(7
|
)
|
|
|
(20
|
)
|
|
(13
|
)
|
||||
Settlements
|
(106
|
)
|
|
(30
|
)
|
|
|
(51
|
)
|
|
(48
|
)
|
||||
Transfers into Level 3 (c)
|
4
|
|
|
3
|
|
|
|
1
|
|
|
1
|
|
||||
Transfers out of Level 3 (c)
|
71
|
|
|
(10
|
)
|
|
|
1
|
|
|
(14
|
)
|
||||
Earn-out provision (d)
|
(16
|
)
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||
Net liabilities assumed in the Lamar and Forney Acquisition (Note 3) (e)
|
—
|
|
|
—
|
|
|
|
(30
|
)
|
|
—
|
|
||||
Net change (f)
|
(136
|
)
|
|
2
|
|
|
|
60
|
|
|
2
|
|
||||
Net asset (liability) balance at end of period
|
$
|
(53
|
)
|
|
$
|
83
|
|
|
|
$
|
97
|
|
|
$
|
37
|
|
Unrealized valuation gains (losses) relating to instruments held at end of period
|
$
|
(98
|
)
|
|
$
|
28
|
|
|
|
$
|
98
|
|
|
$
|
18
|
|
(a)
|
The beginning balance for the Successor period from October 3, 2016 through December 31, 2016 reflects a
$16 million
adjustment to the fair value of certain Level 3 assets driven by power prices utilized by the Successor for unobservable delivery periods.
|
(b)
|
Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received.
|
(c)
|
Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. For the year ended December 31, 2017, transfers out of Level 3 primarily consists of electricity derivatives where forward pricing inputs have become observable.
|
(d)
|
Represents initial fair value of the earn-out provision incurred as part of the Odessa Acquisition. See Note
3
.
|
(e)
|
Includes fair value of Level 3 assets and liabilities as of the purchase date and any related rolloff between the purchase date and the period ended October 2, 2016.
|
(f)
|
Activity excludes change in fair value in the month positions settle. For the Successor period, substantially all changes in values of commodity contracts (excluding the initial fair value of the earn-out provision related to the Odessa Acquisition in 2017) are reported as operating revenues in our statements of consolidated income (loss). For the Predecessor period, substantially all changes in values of commodity contracts (excluding net liabilities assumed in the Lamar and Forney Acquisition in 2016) are reported as net gain from commodity hedging and trading activities in the statements of consolidated income (loss).
|
16.
|
COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES
|
|
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
|
)
|
|
December 31, 2016
|
||||||||||||||||||
|
Derivative Assets
|
|
Derivative Liabilities
|
|
|
||||||||||||||
|
Commodity Contracts
|
|
Interest Rate Swaps
|
|
Commodity Contracts
|
|
Interest Rate Swaps
|
|
Total
|
||||||||||
Current assets
|
$
|
350
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
350
|
|
Noncurrent assets
|
46
|
|
|
17
|
|
|
—
|
|
|
1
|
|
|
64
|
|
|||||
Current liabilities
|
—
|
|
|
(12
|
)
|
|
(330
|
)
|
|
(17
|
)
|
|
(359
|
)
|
|||||
Noncurrent liabilities
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
|||||
Net assets (liabilities)
|
$
|
396
|
|
|
$
|
5
|
|
|
$
|
(332
|
)
|
|
$
|
(16
|
)
|
|
$
|
53
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
Derivative (statements of consolidated income (loss) presentation)
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||||||
Commodity contracts (Operating revenues)
|
$
|
56
|
|
|
$
|
(92
|
)
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Commodity contracts (Fuel, purchased power costs and delivery fees)
|
6
|
|
|
21
|
|
|
|
—
|
|
|
—
|
|
||||
Commodity contracts (Net gain from commodity hedging and trading activities)
|
—
|
|
|
—
|
|
|
|
194
|
|
|
380
|
|
||||
Interest rate swaps (Interest expense and related charges)
|
2
|
|
|
(11
|
)
|
|
|
—
|
|
|
—
|
|
||||
Net gain (loss)
|
$
|
64
|
|
|
$
|
(82
|
)
|
|
|
$
|
194
|
|
|
$
|
380
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||||||||||||||||||
|
|
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
|
|
$
|
220
|
|
|
$
|
(113
|
)
|
|
$
|
(1
|
)
|
|
$
|
106
|
|
|
$
|
396
|
|
|
$
|
(193
|
)
|
|
$
|
(20
|
)
|
|
$
|
183
|
|
Interest rate swaps
|
|
18
|
|
|
—
|
|
|
—
|
|
|
18
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
||||||||
Total derivative assets
|
|
238
|
|
|
(113
|
)
|
|
(1
|
)
|
|
124
|
|
|
401
|
|
|
(193
|
)
|
|
(20
|
)
|
|
188
|
|
||||||||
Derivative liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Commodity contracts
|
|
(316
|
)
|
|
113
|
|
|
1
|
|
|
(202
|
)
|
|
(332
|
)
|
|
193
|
|
|
136
|
|
|
(3
|
)
|
||||||||
Interest rate swaps
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(16
|
)
|
|
—
|
|
|
—
|
|
|
(16
|
)
|
||||||||
Total derivative liabilities
|
|
(316
|
)
|
|
113
|
|
|
1
|
|
|
(202
|
)
|
|
(348
|
)
|
|
193
|
|
|
136
|
|
|
(19
|
)
|
||||||||
Net amounts
|
|
$
|
(78
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(78
|
)
|
|
$
|
53
|
|
|
$
|
—
|
|
|
$
|
116
|
|
|
$
|
169
|
|
(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.
|
|
|
December 31, 2017
|
|
December 31, 2016
|
|
|
||||
Derivative type
|
|
Notional Volume
|
|
Unit of Measure
|
||||||
Natural gas (a)
|
|
1,259
|
|
|
1,282
|
|
|
Million MMBtu
|
||
Electricity
|
|
114,129
|
|
|
75,322
|
|
|
GWh
|
||
Congestion Revenue Rights (b)
|
|
110,913
|
|
|
126,573
|
|
|
GWh
|
||
Coal
|
|
2
|
|
|
12
|
|
|
Million U.S. tons
|
||
Fuel oil
|
|
5
|
|
|
34
|
|
|
Million gallons
|
||
Uranium
|
|
325
|
|
|
25
|
|
|
Thousand pounds
|
||
Interest rate swaps – floating/fixed (c)
|
|
$
|
3,000
|
|
|
$
|
3,000
|
|
|
Million U.S. dollars
|
(a)
|
Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas transactions.
|
(b)
|
Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within ERCOT.
|
(c)
|
Includes notional amounts of interest rate swaps that became effective in January 2017 and have maturity dates through July 2023.
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
Fair value of derivative contract liabilities (a)
|
$
|
(204
|
)
|
|
$
|
(31
|
)
|
Offsetting fair value under netting arrangements (b)
|
103
|
|
|
13
|
|
||
Cash collateral and letters of credit
|
41
|
|
|
1
|
|
||
Liquidity exposure
|
$
|
(60
|
)
|
|
$
|
(17
|
)
|
(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.
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||||||
Pension costs
|
$
|
6
|
|
|
$
|
2
|
|
|
|
$
|
4
|
|
|
$
|
8
|
|
OPEB costs
|
6
|
|
|
2
|
|
|
|
—
|
|
|
3
|
|
||||
Total benefit costs recognized as expense
|
$
|
12
|
|
|
$
|
4
|
|
|
|
$
|
4
|
|
|
$
|
11
|
|
|
Successor
|
||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||
Assumptions Used to Determine Net Periodic Pension Cost:
|
|
|
|
||||
Discount rate
|
4.31
|
%
|
|
3.79
|
%
|
||
Expected return on plan assets
|
4.86
|
%
|
|
4.89
|
%
|
||
Expected rate of compensation increase
|
3.50
|
%
|
|
3.50
|
%
|
||
Components of Net Pension Cost:
|
|
|
|
||||
Service cost
|
$
|
5
|
|
|
$
|
2
|
|
Interest cost
|
6
|
|
|
1
|
|
||
Expected return on assets
|
(5
|
)
|
|
(1
|
)
|
||
Net periodic pension cost
|
$
|
6
|
|
|
$
|
2
|
|
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
|
|
|
|
||||
Net (gain) loss
|
$
|
3
|
|
|
$
|
(4
|
)
|
Total recognized in net periodic benefit cost and other comprehensive income
|
$
|
9
|
|
|
$
|
(2
|
)
|
Assumptions Used to Determine Benefit Obligations:
|
|
|
|
||||
Discount rate
|
3.74
|
%
|
|
4.31
|
%
|
||
Expected rate of compensation increase
|
3.62
|
%
|
|
3.50
|
%
|
|
Successor
|
||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||
Change in Pension Obligation:
|
|
|
|
||||
Projected benefit obligation at beginning of period
|
$
|
144
|
|
|
$
|
154
|
|
Service cost
|
5
|
|
|
2
|
|
||
Interest cost
|
6
|
|
|
1
|
|
||
Actuarial (gain) loss
|
13
|
|
|
(12
|
)
|
||
Benefits paid
|
(5
|
)
|
|
(1
|
)
|
||
Projected benefit obligation at end of year
|
$
|
163
|
|
|
$
|
144
|
|
Accumulated benefit obligation at end of year
|
$
|
157
|
|
|
$
|
136
|
|
Change in Plan Assets:
|
|
|
|
||||
Fair value of assets at beginning of period
|
$
|
117
|
|
|
$
|
124
|
|
Actual gain (loss) on assets
|
16
|
|
|
(6
|
)
|
||
Benefits paid
|
(5
|
)
|
|
(1
|
)
|
||
Fair value of assets at end of year
|
$
|
128
|
|
|
$
|
117
|
|
Funded Status:
|
|
|
|
||||
Projected pension benefit obligation
|
$
|
(163
|
)
|
|
$
|
(144
|
)
|
Fair value of assets
|
128
|
|
|
117
|
|
||
Funded status at end of year
|
$
|
(35
|
)
|
|
$
|
(27
|
)
|
Amounts Recognized in the Balance Sheet Consist of:
|
|
|
|
||||
Other current liabilities
|
$
|
—
|
|
|
$
|
—
|
|
Other noncurrent liabilities
|
(35
|
)
|
|
(27
|
)
|
||
Net liability recognized
|
$
|
(35
|
)
|
|
$
|
(27
|
)
|
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
|
|
|
|
||||
Net gain
|
$
|
1
|
|
|
$
|
4
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
Pension Plans with PBO and ABO in Excess Of Plan Assets:
|
|
|
|
||||
Projected benefit obligations
|
$
|
163
|
|
|
$
|
144
|
|
Accumulated benefit obligation
|
$
|
157
|
|
|
$
|
136
|
|
Plan assets
|
$
|
128
|
|
|
$
|
117
|
|
Asset Category:
|
Target Allocation
Ranges
|
|||
Fixed income
|
74
|
%
|
-
|
86%
|
U.S. equities
|
8
|
%
|
-
|
14%
|
International equities
|
6
|
%
|
-
|
12%
|
Retirement Plan
|
||
Asset Class:
|
Expected Long-Term
Rate of Return
|
|
U.S. equity securities
|
6.4
|
%
|
International equity securities
|
7.3
|
%
|
Fixed income securities
|
3.9
|
%
|
Weighted average
|
4.6
|
%
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
Asset Category:
|
|
|
|
||||
Level 2 valuations (see Note 15):
|
|
|
|
||||
Interest-bearing cash
|
$
|
(7
|
)
|
|
$
|
(4
|
)
|
Fixed income securities:
|
|
|
|
||||
Corporate bonds (a)
|
65
|
|
|
54
|
|
||
U.S. Treasuries
|
29
|
|
|
30
|
|
||
Other (b)
|
7
|
|
|
6
|
|
||
Total assets categorized as Level 2
|
94
|
|
|
86
|
|
||
Assets measured at net asset value (c):
|
|
|
|
||||
Interest-bearing cash
|
2
|
|
|
2
|
|
||
Equity securities:
|
|
|
|
||||
U.S.
|
14
|
|
|
14
|
|
||
International
|
13
|
|
|
9
|
|
||
Fixed income securities:
|
|
|
|
||||
Corporate bonds (a)
|
5
|
|
|
6
|
|
||
Total assets measured at net asset value
|
34
|
|
|
31
|
|
||
Total assets
|
$
|
128
|
|
|
$
|
117
|
|
(a)
|
Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's.
|
(b)
|
Other consists primarily of taxable municipal bonds.
|
(c)
|
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. The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to total Vistra Retirement Plan assets.
|
|
Successor
|
||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||
Assumptions Used to Determine Net Periodic Benefit Cost:
|
|
|
|
||||
Discount rate (Vistra Energy Plan)
|
4.11
|
%
|
|
4.00
|
%
|
||
Discount rate (Oncor Plan)
|
4.18
|
%
|
|
3.69
|
%
|
||
Components of Net Postretirement Benefit Cost:
|
|
|
|
||||
Service cost
|
$
|
2
|
|
|
$
|
1
|
|
Interest cost
|
4
|
|
|
1
|
|
||
Plan amendments (a)
|
—
|
|
|
(4
|
)
|
||
Net periodic OPEB cost (income)
|
$
|
6
|
|
|
$
|
(2
|
)
|
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
|
|
|
|
||||
Net (gain) loss and prior service (credit) cost
|
$
|
26
|
|
|
$
|
(5
|
)
|
Total recognized in net periodic benefit cost and other comprehensive income
|
$
|
32
|
|
|
$
|
(7
|
)
|
Assumptions Used to Determine Benefit Obligations at Period End:
|
|
|
|
||||
Discount rate (Vistra Energy Plan)
|
3.67
|
%
|
|
4.11
|
%
|
||
Discount rate (Split-Participant Plan)
|
3.67
|
%
|
|
—
|
%
|
||
Discount rate (Oncor Plan)
|
—
|
%
|
|
4.18
|
%
|
(a)
|
Curtailment gain recognized as other income in the statements of consolidated income (loss) as a result of discontinued life insurance benefits for active employees.
|
|
Successor
|
||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||
Change in Postretirement Benefit Obligation:
|
|
|
|
||||
Benefit obligation at beginning of year
|
$
|
88
|
|
|
$
|
97
|
|
Service cost
|
2
|
|
|
1
|
|
||
Interest cost
|
4
|
|
|
1
|
|
||
Participant contributions
|
2
|
|
|
1
|
|
||
Plan amendments (a)
|
11
|
|
|
(4
|
)
|
||
Actuarial (gain) loss
|
15
|
|
|
(5
|
)
|
||
Benefits paid
|
(7
|
)
|
|
(3
|
)
|
||
Benefit obligation at end of year
|
$
|
115
|
|
|
$
|
88
|
|
Change in Plan Assets:
|
|
|
|
||||
Fair value of assets at beginning of year
|
$
|
—
|
|
|
$
|
—
|
|
Employer contributions
|
5
|
|
|
1
|
|
||
Participant contributions
|
2
|
|
|
1
|
|
||
Benefits paid
|
(7
|
)
|
|
(2
|
)
|
||
Fair value of assets at end of year
|
$
|
—
|
|
|
$
|
—
|
|
Funded Status:
|
|
|
|
||||
Benefit obligation
|
$
|
115
|
|
|
$
|
88
|
|
Funded status at end of year
|
$
|
115
|
|
|
$
|
88
|
|
Amounts Recognized on the Balance Sheet Consist of:
|
|
|
|
||||
Other current liabilities
|
$
|
6
|
|
|
$
|
5
|
|
Other noncurrent liabilities
|
109
|
|
|
83
|
|
||
Net liability recognized
|
$
|
115
|
|
|
$
|
88
|
|
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
|
|
|
|
||||
Net loss and prior service cost
|
$
|
20
|
|
|
$
|
5
|
|
(a)
|
For the year ended December 31, 2017, plan amendments relate to the contractual arrangement with Oncor covering Split Participants. For the period from October 3, 2016 through December 31, 2016, a curtailment gain was recognized as other income in the statements of consolidated income (loss) as a result of discontinued life insurance benefits for active employees.
|
|
Successor
|
||||
|
December 31, 2017
|
|
December 31, 2016
|
||
Assumed Health Care Cost Trend Rates-Not Medicare Eligible:
|
|
|
|
||
Health care cost trend rate assumed for next year
|
7.00
|
%
|
|
5.80
|
%
|
Rate to which the cost trend is expected to decline (the ultimate trend rate)
|
4.50
|
%
|
|
5.00
|
%
|
Year that the rate reaches the ultimate trend rate
|
2026
|
|
|
2024
|
|
Assumed Health Care Cost Trend Rates-Medicare Advantage Eligible (2017) / Medicare Eligible (2016):
|
|
|
|
||
Health care cost trend rate assumed for next year
|
10.66
|
%
|
|
5.70
|
%
|
Rate to which the cost trend is expected to decline (the ultimate trend rate)
|
4.50
|
%
|
|
5.00
|
%
|
Year that the rate reaches the ultimate trend rate
|
2026
|
|
|
2024
|
|
|
1-Percentage Point
Increase
|
|
1-Percentage Point
Decrease
|
||||
Sensitivity Analysis of Assumed Health Care Cost Trend Rates
:
|
|
|
|
||||
Effect on accumulated postretirement obligation
|
$
|
2
|
|
|
$
|
(2
|
)
|
Effect on postretirement benefits cost
|
$
|
—
|
|
|
$
|
—
|
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023-27
|
||||||||||||
Pension benefits
|
$
|
11
|
|
|
$
|
8
|
|
|
$
|
8
|
|
|
$
|
8
|
|
|
$
|
9
|
|
|
$
|
50
|
|
OPEB
|
$
|
6
|
|
|
$
|
7
|
|
|
$
|
8
|
|
|
$
|
8
|
|
|
$
|
8
|
|
|
$
|
39
|
|
|
Successor
|
||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||
Total stock-based compensation expense
|
$
|
19
|
|
|
$
|
3
|
|
Income tax benefit
|
(7
|
)
|
|
(1
|
)
|
||
Stock based-compensation expense, net of tax
|
$
|
12
|
|
|
$
|
2
|
|
|
Successor
|
|||||||||||
|
Year Ended December 31, 2017
|
|||||||||||
|
Stock Options
(in thousands)
|
|
Weighted
Average Exercise Price
|
|
Weighted Average Remaining Contractual Term (Years)
|
|
Aggregate Intrinsic Value (in millions)
|
|||||
Total outstanding at beginning of period
|
7,357
|
|
|
$
|
15.81
|
|
|
9.8
|
|
$
|
—
|
|
Granted
|
1,412
|
|
|
$
|
18.86
|
|
|
|
|
|
|
|
Exercised
|
(281
|
)
|
|
$
|
13.41
|
|
|
|
|
|
|
|
Forfeited or expired
|
(352
|
)
|
|
$
|
13.76
|
|
|
|
|
|
|
|
Total outstanding at end of period
|
8,136
|
|
|
$
|
14.44
|
|
|
9.0
|
|
$
|
32.4
|
|
Expected to vest
|
6,618
|
|
|
$
|
14.65
|
|
|
9.1
|
|
$
|
25.1
|
|
|
Successor
|
|||||||||||
|
Year Ended December 31, 2017
|
|||||||||||
|
Restricted Stock Units
(in thousands)
|
|
Weighted
Average Grant Date Fair Value
|
|
Weighted Average Remaining Contractual Term (Years)
|
|
Aggregate Intrinsic Value (in millions)
|
|||||
Total outstanding at beginning of period
|
2,159
|
|
|
$
|
15.79
|
|
|
2.3
|
|
$
|
33.5
|
|
Granted
|
861
|
|
|
$
|
18.84
|
|
|
|
|
|
|
|
Exercised
|
(538
|
)
|
|
$
|
15.76
|
|
|
|
|
|
|
|
Forfeited or expired
|
(107
|
)
|
|
$
|
15.85
|
|
|
|
|
|
|
|
Total outstanding at end of period
|
2,375
|
|
|
$
|
16.91
|
|
|
1.9
|
|
$
|
43.5
|
|
Expected to vest
|
2,375
|
|
|
$
|
16.91
|
|
|
1.9
|
|
$
|
43.5
|
|
19.
|
RELATED PARTY TRANSACTIONS
|
•
|
we will be required to use reasonable best efforts to convert the Form S-1 registration statement into a registration statement on Form S-3 as soon as reasonably practicable after we become eligible to do so and to have such Form S-3 declared effective as promptly as practicable (but in no event more than
30 days
after it is filed with the SEC);
|
•
|
if we propose to file certain types of registration statements under the Securities Act 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.
|
•
|
Our retail operations (and prior to the Effective Date, our Predecessor) pay Oncor for services it provides, principally the delivery of electricity. Expenses recorded for these services, reported in fuel, purchased power costs and delivery fees, totaled
$700 million
and
$955 million
for the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended
December 31, 2015
, respectively.
|
•
|
A former subsidiary of EFH Corp. billed our Predecessor's subsidiaries for information technology, financial, accounting and other administrative services at cost. These charges, which are largely settled in cash and primarily reported in SG&A expenses, totaled
$157 million
and
$205 million
for the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended
December 31, 2015
, respectively.
|
•
|
Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility is funded by a delivery fee surcharge billed to REPs by Oncor, as collection agent, and remitted monthly to Vistra Energy (and prior to the Effective Date, our Predecessor) for contribution to the trust fund with the intent that the trust fund assets, reported in other investments in our consolidated balance sheets, will ultimately be sufficient to fund the future decommissioning liability, reported in asset retirement obligations in our consolidated balance sheets. The delivery fee surcharges remitted to our Predecessor totaled
$15 million
and
$17 million
for the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended
December 31, 2015
, respectively. Income and expenses associated with the trust fund and the decommissioning liability incurred by Vistra Energy (and prior to the Effective Date, our Predecessor) are offset by a net change in a receivable/payable that ultimately will be settled through changes in Oncor's delivery fee rates.
|
•
|
EFH Corp. files consolidated federal income tax and Texas state margin tax returns that included our results prior to the Effective Date; however, under a Federal and State Income Tax Allocation Agreement, our federal income tax and Texas margin tax expense and related balance sheet amounts, including income taxes payable to or receivable from EFH Corp., were recorded as if our Predecessor filed its own corporate income tax return. For the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended
December 31, 2015
, our Predecessor made income tax payments to EFH Corp. totaling
$22 million
and
$29 million
, respectively. In 2015,
$609 million
of income tax liability was eliminated under the terms of the Settlement Agreement. See Note
8
for discussion of cessation of payment of federal income taxes pursuant to the Settlement Agreement.
|
•
|
Contributions to the EFH Corp. retirement plan by both Oncor and TCEH in 2014, 2015 and 2016 resulted in the EFH Corp. retirement plan being fully funded as calculated under the provisions of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In September 2016, a cash contribution totaling
$2 million
was made to the EFH Corp. retirement plan, all of which was contributed by TCEH, which resulted in the EFH Retirement Plan continuing to be fully funded as calculated under the provisions of ERISA. On the Effective Date, the EFH Retirement Plan was transferred to Vistra Energy pursuant to a separation agreement between Vistra Energy and EFH Corp.
|
•
|
In 2007, TCEH entered into the TCEH Senior Secured Facilities with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of each member of the Sponsor Group have from time to time engaged in commercial banking transactions with TCEH and/or provided financial advisory services to TCEH, in each case in the normal course of business.
|
•
|
Affiliates of GS Capital Partners were parties to certain commodity and interest rate hedging transactions with our Predecessor in the normal course of business.
|
•
|
Affiliates of the Sponsor Group have sold or acquired, and in the future may sell or acquire, debt or debt securities issued by our Predecessor in open market transactions or through loan syndications.
|
•
|
As a result of debt repurchase and exchange transactions in 2009 through 2011, EFH Corp. and EFIH held TCEH debt securities totaling
$382 million
as of the Petition Date. These notes payable were classified as LSTC. The amounts of TCEH debt held by EFIH or EFH Corp. were eliminated as a result of the Settlement Agreement approved by the Bankruptcy Court in December 2015 (see Note
5
). In conjunction with the Settlement Agreement approved by the Bankruptcy Court in December 2015, EFH Corp. and EFIH waived their rights to the claims associated with these debt securities resulting in a gain recorded in reorganization items (see Note
5
). Interest expense on the notes totaled
$1 million
for the year ended
December 31, 2015
. Contractual interest, not paid or recorded, totaled
$37 million
for the year ended
December 31, 2015
. See Note
10
.
|
20.
|
SEGMENT INFORMATION
|
|
Successor
|
||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||
Operating revenues (a)
|
|
|
|
||||
Wholesale Generation
|
$
|
2,758
|
|
|
$
|
450
|
|
Retail Electricity
|
4,058
|
|
|
912
|
|
||
Eliminations
|
(1,386
|
)
|
|
(171
|
)
|
||
Consolidated operating revenues
|
$
|
5,430
|
|
|
$
|
1,191
|
|
Depreciation and amortization
|
|
|
|
||||
Wholesale Generation
|
$
|
230
|
|
|
$
|
53
|
|
Retail Electricity
|
430
|
|
|
153
|
|
||
Corporate and Other
|
40
|
|
|
11
|
|
||
Eliminations
|
(1
|
)
|
|
$
|
(1
|
)
|
|
Consolidated depreciation and amortization
|
$
|
699
|
|
|
$
|
216
|
|
Operating income (loss)
|
|
|
|
||||
Wholesale Generation
|
$
|
(186
|
)
|
|
$
|
(255
|
)
|
Retail Electricity
|
461
|
|
|
111
|
|
||
Corporate and Other
|
(77
|
)
|
|
(17
|
)
|
||
Consolidated operating income (loss)
|
$
|
198
|
|
|
$
|
(161
|
)
|
Interest expense and related charges
|
|
|
|
||||
Wholesale Generation
|
$
|
21
|
|
|
$
|
(1
|
)
|
Corporate and Other
|
252
|
|
|
66
|
|
||
Eliminations
|
(80
|
)
|
|
(5
|
)
|
||
Consolidated interest expense and related charges
|
$
|
193
|
|
|
$
|
60
|
|
Income tax expense (benefit)(all Corporate and Other)
|
$
|
504
|
|
|
$
|
(70
|
)
|
Net income (loss)
|
|
|
|
||||
Wholesale Generation
|
$
|
(177
|
)
|
|
$
|
(251
|
)
|
Retail Electricity
|
495
|
|
|
114
|
|
||
Corporate and Other
|
(572
|
)
|
|
(26
|
)
|
||
Consolidated net income (loss)
|
$
|
(254
|
)
|
|
$
|
(163
|
)
|
Capital expenditures
|
|
|
|
||||
Wholesale Generation
|
$
|
150
|
|
|
$
|
84
|
|
Retail Electricity
|
—
|
|
|
5
|
|
||
Corporate and Other
|
26
|
|
|
—
|
|
||
Consolidated capital expenditures
|
$
|
176
|
|
|
$
|
89
|
|
(a)
|
For the Successor period for the year ended
December 31, 2017
and the period from October 3, 2016 through December 31, 2016, includes third-party unrealized net gains (losses) from mark-to-market valuations of commodity positions of
$(151) million
and
$(182) million
, respectively, recorded to the Wholesale Generation segment and
$18 million
and
$(6) million
, respectively, recorded to the Retail Electricity segment. In addition, for the Successor period for the year ended
December 31, 2017
and the period from October 3, 2016 through December 31, 2016, unrealized net gains (losses) with affiliate of
$(154) million
and
$(113) million
, respectively, were recorded to operating revenues for the Wholesale Generation segment and corresponding unrealized net gains (losses) with affiliate of
$154 million
and
$113 million
, respectively, were recorded to fuel, purchased power costs and delivery fees for the Retail Electricity segment, with no impact to consolidated results.
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
Total assets
|
|
|
|
||||
Wholesale Generation
|
$
|
7,069
|
|
|
$
|
6,952
|
|
Retail Electricity
|
6,156
|
|
|
5,753
|
|
||
Corporate and Other and Eliminations
|
1,375
|
|
|
2,462
|
|
||
Consolidated total assets
|
$
|
14,600
|
|
|
$
|
15,167
|
|
21.
|
SUPPLEMENTARY FINANCIAL INFORMATION
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||||||
Other income:
|
|
|
|
|
|
|
|
|
||||||||
Office space sublease rental income (a)
|
$
|
11
|
|
|
$
|
2
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Mineral rights royalty income (b)
|
3
|
|
|
1
|
|
|
|
3
|
|
|
4
|
|
||||
Sale of land (b)
|
4
|
|
|
—
|
|
|
|
—
|
|
|
—
|
|
||||
Curtailment gain on employee benefit plans (a)
|
—
|
|
|
4
|
|
|
|
—
|
|
|
—
|
|
||||
Insurance settlement
|
—
|
|
|
—
|
|
|
|
9
|
|
|
—
|
|
||||
Interest income
|
15
|
|
|
1
|
|
|
|
3
|
|
|
1
|
|
||||
All other
|
4
|
|
|
2
|
|
|
|
4
|
|
|
13
|
|
||||
Total other income
|
$
|
37
|
|
|
$
|
10
|
|
|
|
$
|
19
|
|
|
$
|
18
|
|
Other deductions:
|
|
|
|
|
|
|
|
|
||||||||
Write-off of generation equipment (b)
|
2
|
|
|
—
|
|
|
|
45
|
|
|
—
|
|
||||
Adjustment to asbestos liability
|
—
|
|
|
—
|
|
|
|
11
|
|
|
—
|
|
||||
Impairment of favorable purchase contracts (Note 7)
|
—
|
|
|
—
|
|
|
|
—
|
|
|
8
|
|
||||
Impairment of emission allowances (Note 7)
|
—
|
|
|
—
|
|
|
|
—
|
|
|
55
|
|
||||
Impairment of mining development costs
|
—
|
|
|
—
|
|
|
|
—
|
|
|
19
|
|
||||
All other
|
3
|
|
|
—
|
|
|
|
19
|
|
|
11
|
|
||||
Total other deductions
|
$
|
5
|
|
|
$
|
—
|
|
|
|
$
|
75
|
|
|
$
|
93
|
|
(a)
|
Reported in Corporate and Other non-segment (Successor period only).
|
(b)
|
Reported in Wholesale Generation segment (Successor period only).
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||
|
Current
Assets |
|
Noncurrent Assets
|
|
Current
Assets |
|
Noncurrent Assets
|
||||||||
Amounts related to the Vistra Operations Credit Facilities (Note 12)
|
$
|
—
|
|
|
$
|
500
|
|
|
$
|
—
|
|
|
$
|
650
|
|
Amounts related to restructuring escrow accounts
|
59
|
|
|
—
|
|
|
90
|
|
|
—
|
|
||||
Other
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
||||
Total restricted cash
|
$
|
59
|
|
|
$
|
500
|
|
|
$
|
95
|
|
|
$
|
650
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
Wholesale and retail trade accounts receivable
|
$
|
596
|
|
|
$
|
622
|
|
Allowance for uncollectible accounts
|
(14
|
)
|
|
(10
|
)
|
||
Trade accounts receivable — net
|
$
|
582
|
|
|
$
|
612
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||||||
Allowance for uncollectible accounts receivable at beginning of period
|
$
|
10
|
|
|
$
|
—
|
|
|
|
$
|
9
|
|
|
$
|
15
|
|
Increase for bad debt expense
|
43
|
|
|
10
|
|
|
|
20
|
|
|
34
|
|
||||
Decrease for account write-offs
|
(39
|
)
|
|
—
|
|
|
|
(16
|
)
|
|
(40
|
)
|
||||
Allowance for uncollectible accounts receivable at end of period
|
$
|
14
|
|
|
$
|
10
|
|
|
|
$
|
13
|
|
|
$
|
9
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
Materials and supplies
|
$
|
149
|
|
|
$
|
173
|
|
Fuel stock
|
83
|
|
|
88
|
|
||
Natural gas in storage
|
21
|
|
|
24
|
|
||
Total inventories
|
$
|
253
|
|
|
$
|
285
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
Nuclear plant decommissioning trust
|
$
|
1,188
|
|
|
$
|
1,012
|
|
Land
|
49
|
|
|
49
|
|
||
Miscellaneous other
|
3
|
|
|
3
|
|
||
Total other investments
|
$
|
1,240
|
|
|
$
|
1,064
|
|
|
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
|
|
|
December 31, 2016
|
||||||||||||||
|
Cost (a)
|
|
Unrealized gain
|
|
Unrealized loss
|
|
Fair market
value
|
||||||||
Debt securities (b)
|
$
|
333
|
|
|
$
|
10
|
|
|
$
|
(3
|
)
|
|
$
|
340
|
|
Equity securities (c)
|
309
|
|
|
368
|
|
|
(5
|
)
|
|
672
|
|
||||
Total
|
$
|
642
|
|
|
$
|
378
|
|
|
$
|
(8
|
)
|
|
$
|
1,012
|
|
(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
3.55%
and
3.56%
at
December 31, 2017 and 2016
, respectively, and an average maturity of
9 years
at both
December 31, 2017 and 2016
.
|
(c)
|
The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index.
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||||||
Realized gains
|
$
|
9
|
|
|
$
|
1
|
|
|
|
$
|
3
|
|
|
$
|
1
|
|
Realized losses
|
$
|
(11
|
)
|
|
$
|
—
|
|
|
|
$
|
(2
|
)
|
|
$
|
(1
|
)
|
Proceeds from sales of securities
|
$
|
252
|
|
|
$
|
25
|
|
|
|
$
|
201
|
|
|
$
|
401
|
|
Investments in securities
|
$
|
(272
|
)
|
|
$
|
(30
|
)
|
|
|
$
|
(215
|
)
|
|
$
|
(418
|
)
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
Wholesale Generation:
|
|
|
|
||||
Generation and mining
|
$
|
4,501
|
|
|
$
|
3,997
|
|
Retail Electricity
|
5
|
|
|
3
|
|
||
Corporate and Other
|
120
|
|
|
107
|
|
||
Total
|
4,626
|
|
|
4,107
|
|
||
Less accumulated depreciation
|
(282
|
)
|
|
(54
|
)
|
||
Net of accumulated depreciation
|
4,344
|
|
|
4,053
|
|
||
Nuclear fuel (net of accumulated amortization of $111 million and $31 million)
|
158
|
|
|
166
|
|
||
Construction work in progress:
|
|
|
|
||||
Wholesale Generation
|
312
|
|
|
210
|
|
||
Retail Electricity
|
—
|
|
|
6
|
|
||
Corporate and Other
|
6
|
|
|
8
|
|
||
Total construction work in progress
|
318
|
|
|
224
|
|
||
Property, plant and equipment — net
|
$
|
4,820
|
|
|
$
|
4,443
|
|
|
Nuclear Plant Decommissioning
|
|
Mining Land Reclamation
|
|
Other
|
|
Total
|
||||||||
Predecessor:
|
|
|
|
|
|
|
|
||||||||
Liability at December 31, 2015
|
$
|
508
|
|
|
$
|
215
|
|
|
$
|
107
|
|
|
$
|
830
|
|
Additions:
|
|
|
|
|
|
|
|
||||||||
Accretion — January 1, 2016 through October 2, 2016
|
22
|
|
|
16
|
|
|
5
|
|
|
43
|
|
||||
Adjustment for new cost estimate
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
||||
Incremental reclamation costs
|
—
|
|
|
14
|
|
|
12
|
|
|
26
|
|
||||
Reductions:
|
|
|
|
|
|
|
|
||||||||
Payments — January 1, 2016 through October 2, 2016
|
—
|
|
|
(37
|
)
|
|
(3
|
)
|
|
(40
|
)
|
||||
Liability at October 2, 2016
|
530
|
|
|
208
|
|
|
122
|
|
|
860
|
|
||||
Less amounts due currently
|
—
|
|
|
(50
|
)
|
|
(1
|
)
|
|
(51
|
)
|
||||
Noncurrent liability at October 2, 2016
|
$
|
530
|
|
|
$
|
158
|
|
|
$
|
121
|
|
|
$
|
809
|
|
Successor:
|
|
|
|
|
|
|
|
||||||||
Fair value of liability established at October 3, 2016
|
$
|
1,192
|
|
|
$
|
374
|
|
|
$
|
152
|
|
|
$
|
1,718
|
|
Additions:
|
|
|
|
|
|
|
|
||||||||
Accretion — October 3, 2016 through December31, 2016
|
8
|
|
|
5
|
|
|
1
|
|
|
14
|
|
||||
Reductions:
|
|
|
|
|
|
|
|
||||||||
Payments — October 3, 2016 through December31, 2016
|
—
|
|
|
(4
|
)
|
|
(2
|
)
|
|
(6
|
)
|
||||
Liability at December 31, 2016
|
1,200
|
|
|
375
|
|
|
151
|
|
|
1,726
|
|
||||
Additions:
|
|
|
|
|
|
|
|
||||||||
Accretion
|
33
|
|
|
18
|
|
|
8
|
|
|
59
|
|
||||
Adjustment for change in estimates (a)
|
—
|
|
|
81
|
|
|
44
|
|
|
125
|
|
||||
Incremental reclamation costs (b)
|
—
|
|
|
—
|
|
|
62
|
|
|
62
|
|
||||
Reductions:
|
|
|
|
|
|
|
|
||||||||
Payments
|
—
|
|
|
(36
|
)
|
|
—
|
|
|
(36
|
)
|
||||
Liability at December 31, 2017
|
1,233
|
|
|
438
|
|
|
265
|
|
|
1,936
|
|
||||
Less amounts due currently
|
—
|
|
|
(93
|
)
|
|
(6
|
)
|
|
(99
|
)
|
||||
Noncurrent liability at December 31, 2017
|
$
|
1,233
|
|
|
$
|
345
|
|
|
$
|
259
|
|
|
$
|
1,837
|
|
(a)
|
Amounts primarily relate to the impacts of accelerating the ARO associated with the retirements of the Sandow 4, Sandow 5, Big Brown and Monticello plants (see Note
4
).
|
(b)
|
Amounts primarily relate to liabilities incurred as part of acquiring certain real property through the Alcoa contract settlement (see Note
4
).
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
Unfavorable purchase and sales contracts
|
$
|
36
|
|
|
$
|
46
|
|
Other, including retirement and other employee benefits
|
220
|
|
|
174
|
|
||
Total other noncurrent liabilities and deferred credits
|
$
|
256
|
|
|
$
|
220
|
|
Year
|
|
Amount
|
||
2018
|
|
$
|
11
|
|
2019
|
|
$
|
9
|
|
2020
|
|
$
|
9
|
|
2021
|
|
$
|
1
|
|
2022
|
|
$
|
3
|
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||||||||||
Debt:
|
|
Carrying Amount
|
|
Fair
Value
|
|
Carrying Amount
|
|
Fair
Value
|
||||||||
Long-term debt under the Vistra Operations Credit Facilities (Note 12)
|
|
$
|
4,323
|
|
|
$
|
4,334
|
|
|
$
|
4,515
|
|
|
$
|
4,552
|
|
Other long-term debt, excluding capital lease obligations (Note 12)
|
|
30
|
|
|
27
|
|
|
36
|
|
|
32
|
|
||||
Mandatorily redeemable subsidiary preferred stock (Note 12)
|
|
70
|
|
|
70
|
|
|
70
|
|
|
70
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
|
Year Ended
December 31, 2015 |
||||||||
Cash payments related to:
|
|
|
|
|
|
|
|
|
||||||||
Interest paid (a)
|
$
|
245
|
|
|
$
|
19
|
|
|
|
$
|
1,064
|
|
|
$
|
1,298
|
|
Capitalized interest
|
(7
|
)
|
|
(3
|
)
|
|
|
(9
|
)
|
|
(11
|
)
|
||||
Interest paid (net of capitalized interest) (a)
|
$
|
238
|
|
|
$
|
16
|
|
|
|
$
|
1,055
|
|
|
$
|
1,287
|
|
Income taxes
|
$
|
63
|
|
|
$
|
(2
|
)
|
|
|
$
|
22
|
|
|
$
|
29
|
|
Reorganization items (b)
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
104
|
|
|
$
|
224
|
|
Noncash investing and financing activities:
|
|
|
|
|
|
|
|
|
||||||||
Construction expenditures (c)
|
$
|
12
|
|
|
$
|
1
|
|
|
|
$
|
53
|
|
|
$
|
75
|
|
(a)
|
Predecessor period includes amounts paid for adequate protection.
|
(b)
|
Represents cash payments made by our Predecessor for legal and other consulting services, including amounts paid on behalf of third parties pursuant to contractual obligations approved by the Bankruptcy Court.
|
(c)
|
Represents end-of-period accruals for ongoing construction projects.
|
Item 9.
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
|
Item 11.
|
EXECUTIVE COMPENSATION
|
Item 12.
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
|
Item 13.
|
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
|
Item 14.
|
PRINCIPAL ACCOUNTING FEES
|
Item 15.
|
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
|
(a)
|
Our financial statements and financial statement schedules are incorporated under Part II, Item 8 of this Annual Report on Form 10-K.
|
(b)
|
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT
|
|
Successor
|
||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||
Selling, general and administrative expense
|
$
|
(47
|
)
|
|
$
|
(7
|
)
|
Loss from operations
|
(47
|
)
|
|
(7
|
)
|
||
Interest income
|
4
|
|
|
—
|
|
||
Impacts of Tax Receivable Agreement
|
213
|
|
|
(22
|
)
|
||
Income (loss) before income taxes and equity earnings
|
170
|
|
|
(29
|
)
|
||
Pretax equity in gains (losses) of consolidated subsidiaries
|
80
|
|
|
(204
|
)
|
||
Income tax (expense) benefit
|
(504
|
)
|
|
70
|
|
||
Net loss
|
$
|
(254
|
)
|
|
$
|
(163
|
)
|
|
Successor
|
||||||
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||
Cash flows — operating activities:
|
|
|
|
||||
Net loss
|
$
|
(254
|
)
|
|
$
|
(163
|
)
|
Adjustments to reconcile net loss to cash provided by (used in) operating activities:
|
|
|
|
||||
Pretax equity in (gains) losses of consolidated subsidiaries
|
(80
|
)
|
|
204
|
|
||
Deferred income tax benefit (expense), net
|
418
|
|
|
(76
|
)
|
||
Impacts of Tax Receivables Agreement
|
(213
|
)
|
|
22
|
|
||
Other, net
|
23
|
|
|
3
|
|
||
Changes in operating assets and liabilities
|
(2
|
)
|
|
(26
|
)
|
||
Cash used in operating activities
|
(108
|
)
|
|
(36
|
)
|
||
Cash flows — financing activities:
|
|
|
|
||||
Special dividend (Note 4)
|
—
|
|
|
(992
|
)
|
||
Other, net
|
(1
|
)
|
|
1
|
|
||
Cash used in financing activities
|
(1
|
)
|
|
(991
|
)
|
||
Cash flows — investing activities:
|
|
|
|
||||
Dividend received from subsidiaries
|
1,505
|
|
|
997
|
|
||
Odessa Acquisition
|
(330
|
)
|
|
—
|
|
||
Changes in restricted cash
|
32
|
|
|
36
|
|
||
Cash provided by financing activities
|
1,207
|
|
|
1,033
|
|
||
Net change in cash and cash equivalents
|
1,098
|
|
|
6
|
|
||
Cash and cash equivalents — beginning balance
|
26
|
|
|
20
|
|
||
Cash and cash equivalents — ending balance
|
$
|
1,124
|
|
|
$
|
26
|
|
|
December 31
|
||||||
|
2017
|
|
2016
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
1,124
|
|
|
$
|
26
|
|
Restricted cash
|
59
|
|
|
90
|
|
||
Other current assets
|
5
|
|
|
3
|
|
||
Total current assets
|
1,188
|
|
|
119
|
|
||
Equity investments in consolidated subsidiaries
|
4,927
|
|
|
6,067
|
|
||
Accumulated deferred income taxes
|
710
|
|
|
1,122
|
|
||
Other noncurrent assets
|
6
|
|
|
7
|
|
||
Total assets
|
$
|
6,831
|
|
|
$
|
7,315
|
|
LIABILITIES AND EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Trade accounts payable
|
$
|
11
|
|
|
$
|
—
|
|
Accrued taxes
|
59
|
|
|
31
|
|
||
Other current liabilities
|
86
|
|
|
91
|
|
||
Total current liabilities
|
156
|
|
|
122
|
|
||
Tax Receivable Agreement obligation
|
333
|
|
|
596
|
|
||
Total liabilities
|
489
|
|
|
718
|
|
||
Total shareholders' equity
|
6,342
|
|
|
6,597
|
|
||
Total liabilities and equity
|
$
|
6,831
|
|
|
$
|
7,315
|
|
1.
|
BASIS OF PRESENTATION
|
2.
|
RESTRICTIONS ON SUBSIDIARIES
|
3.
|
GUARANTEES
|
4.
|
DIVIDEND RESTRICTIONS
|
(c)
|
EXHIBITS:
|
Exhibits
|
|
Previously Filed With File Number*
|
|
As
Exhibit
|
|
|
|
|
10(ff)
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.27
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10(gg)
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.28
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10(hh)
|
|
001-38086
Form 8-K
(filed July 7, 2017)
|
|
10(a)
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10(ii)
|
|
001-38086
Form 8-K
(filed October 31, 2017)
|
|
10.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10(jj)
|
|
001-38086
Form 8-K
(filed October 31, 2017)
|
|
10.2
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
(12)
|
|
Statement Regarding Computation of Ratios
|
||||||
|
|
|
|
|
|
|
|
|
12(a)
|
|
**
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
(21)
|
|
Subsidiaries of the Registrant
|
||||||
|
|
|
|
|
|
|
|
|
21(a)
|
|
**
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
(23)
|
|
Consent of Experts
|
||||||
|
|
|
|
|
|
|
|
|
23(a)
|
|
**
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
(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)
|
|
**
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Exhibits
|
|
Previously Filed With File Number*
|
|
As
Exhibit
|
|
|
|
|
|
|
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
|
Item 16.
|
FORM 10-K SUMMARY
|
|
|
VISTRA ENERGY CORP.
|
|
Date:
|
February 26, 2018
|
By
|
/s/ CURTIS A. MORGAN
|
|
|
|
Curtis A. Morgan (President and Chief Executive Officer)
|
Signature
|
Title
|
Date
|
|
|
|
/s/ CURTIS A. MORGAN
|
Principal Executive Officer and Director
|
February 26, 2018
|
(Curtis A. Morgan, President and Chief Executive Officer)
|
|
|
|
|
|
/s/ J. WILLIAM HOLDEN
|
Principal Financial Officer
|
February 26, 2018
|
(J. William Holden, Executive Vice President and Chief Financial Officer)
|
|
|
|
|
|
/s/ CHRISTY DOBRY
|
Principal Accounting Officer
|
February 26, 2018
|
(Christy Dobry, Vice President and Controller)
|
|
|
|
|
|
/s/ SCOTT B. HELM
|
Chairman of the Board and Director
|
February 26, 2018
|
(Scott B. Helm, Chairman of the Board)
|
|
|
|
|
|
/s/ GAVIN R. BAIERA
|
Director
|
February 26, 2018
|
(Gavin R. Baiera)
|
|
|
|
|
|
/s/ JENNIFER BOX
|
Director
|
February 26, 2018
|
(Jennifer Box)
|
|
|
|
|
|
/s/ BRIAN K. FERRAIOLI
|
Director
|
February 26, 2018
|
(Brian K. Ferraioli)
|
|
|
|
|
|
/s/ JEFF D. HUNTER
|
Director
|
February 26, 2018
|
(Jeff D. Hunter)
|
|
|
|
|
|
/s/ CYRUS MADON
|
Director
|
February 26, 2018
|
(Cyrus Madon)
|
|
|
|
|
|
/s/ GEOFFREY D. STRONG
|
Director
|
February 26, 2018
|
(Geoffrey D. Strong)
|
|
|
|
|
|
Date of Termination
|
Percentage
|
Between Grant Date and March 31, 2019
|
33.33%
|
Between April 1, 2019 and March 31, 2020
|
66.66%
|
On or after April 1, 2020
|
100%
|
|
Successor
|
|
|
Predecessor
|
||||||||||||||||||||
|
Year Ended
December 31, 2017
|
|
Period from October 3, 2016 through December 31, 2016
|
|
|
Period from January 1, 2016 through October 2, 2016 (b)
|
|
Year Ended December 31,
|
||||||||||||||||
|
|
|
|
|
2015
|
|
2014
|
|
2013
|
|||||||||||||||
|
(in millions, except ratios)
|
|||||||||||||||||||||||
EARNINGS:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Net income (loss)
|
$
|
(254
|
)
|
|
$
|
(163
|
)
|
|
|
$
|
22,851
|
|
|
$
|
(4,677
|
)
|
|
$
|
(6,229
|
)
|
|
$
|
(2,304
|
)
|
Add: Total federal income tax expense (benefit)
|
504
|
|
|
(70
|
)
|
|
|
(1,267
|
)
|
|
(879
|
)
|
|
(2,320
|
)
|
|
(732
|
)
|
||||||
Fixed charges (see detail below)
|
223
|
|
|
70
|
|
|
|
1,071
|
|
|
1,318
|
|
|
1,784
|
|
|
1,960
|
|
||||||
Preferred dividends of subsidiaries
|
(7
|
)
|
|
(2
|
)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total earnings (loss)
|
$
|
466
|
|
|
$
|
(165
|
)
|
|
|
$
|
22,655
|
|
|
$
|
(4,238
|
)
|
|
$
|
(6,765
|
)
|
|
$
|
(1,076
|
)
|
FIXED CHARGES (a):
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Interest expense
|
$
|
200
|
|
|
$
|
63
|
|
|
|
$
|
1,058
|
|
|
$
|
1,300
|
|
|
$
|
1,766
|
|
|
$
|
1,941
|
|
Rentals representative of the interest factor
|
23
|
|
|
7
|
|
|
|
13
|
|
|
18
|
|
|
18
|
|
|
19
|
|
||||||
Total fixed charges
|
$
|
223
|
|
|
$
|
70
|
|
|
|
$
|
1,071
|
|
|
$
|
1,318
|
|
|
$
|
1,784
|
|
|
$
|
1,960
|
|
RATIO OF EARNINGS TO FIXED CHARGES (a)
|
2.09
|
|
|
—
|
|
|
|
21.15
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(a)
|
Excludes accretion expense related to the Tax Receivables Agreement.
|
(b)
|
Fixed charges exceeded earnings by $235 million, $5.556 billion, $8.549 billion and $3.036 billion for the Successor period from October 3, 2016 through December 31, 2016 and the Predecessor for the years ended December 31, 2015, 2014 and 2013, respectively.
|
(b)
|
For the Predecessor period from January 1, 2016 through October 2, 2016, the ratio of earnings to fixed charges is not comparable to the other years presented due to net gains related to bankruptcy-related reorganization items including significant gains on extinguishing claims pursuant to the Plan of Reorganization. Excluding the effects of these net gains, fixed charges exceeded earnings by $653 million.
|
|
Jurisdiction
|
Vistra Energy Corp.
|
DE
|
Vistra Intermediate Company LLC
|
DE
|
Vistra Operations Company LLC
|
DE
|
Vistra Corporate Services Company
|
TX
|
Vistra Finance Corp.
|
DE
|
Vistra EP Properties Company
|
TX
|
Luminant Energy Company LLC
|
TX
|
Luminant ET Services Company LLC
|
TX
|
Luminant Energy Trading California Company
|
TX
|
Vistra Asset Company LLC
|
DE
|
Generation SVC Company
|
TX
|
Sandow Power Company LLC
|
TX
|
Luminant Generation Company LLC
|
TX
|
Oak Grove Management Company LLC
|
DE
|
Big Brown Power Company LLC
|
TX
|
La Frontera Holdings, LLC
|
DE
|
Forney Pipeline, LLC
|
DE
|
Luminant Mining Company LLC
|
TX
|
TXU Retail Services Company
|
DE
|
NCA Resources Development Company LLC
|
TX
|
Upton County Solar 2, LLC
|
DE
|
Vistra Preferred Inc. (a)
|
DE
|
Value Based Brands LLC
|
TX
|
TXU Energy Retail Company LLC
|
TX
|
Brighten Energy LLC
|
DE
|
Comanche Peak Power Company LLC
|
DE
|
(a)
|
100% common stock held by Vistra Asset Company LLC. Preferred stock held by outside investors.
|
1.
|
I have reviewed this Annual Report on Form 10-K of Vistra Energy Corp.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
c)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date: February 26, 2018
|
/s/ Curtis A. Morgan
|
|
Curtis A. Morgan
|
|
President and Chief Executive Officer
|
|
(Principal Executive Officer)
|
1.
|
I have reviewed this Annual Report on Form 10-K of Vistra Energy Corp.;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
c)
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
Date: February 26, 2018
|
/s/ J. William Holden
|
|
J. William Holden
|
|
Executive Vice President and Chief Financial Officer
|
|
(Principal Financial Officer)
|
(1)
|
the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.
|
Date: February 26, 2018
|
/s/ Curtis A. Morgan
|
|
Curtis A. Morgan
|
|
President and Chief Executive Officer
|
|
(Principal Executive Officer)
|
(1)
|
the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.
|
Date: February 26, 2018
|
/s/ J. William Holden
|
|
J. William Holden
|
|
Executive Vice President and Chief Financial Officer
|
|
(Principal Financial Officer)
|
Mine (a)
|
|
Section 104
S and S Citations (b) |
|
Section 104(b)
Orders |
|
Section 104(d)
Citations and Orders |
|
Section 110(b)(2)
Violations |
|
Section 107(a)
Orders |
|
Total Dollar Value of MSHA Assessments Proposed (c)
|
|
Total Number of Mining Related Fatalities
|
|
Received Notice of Pattern of Violations Under Section 104(e)
|
|
Received Notice of Potential to Have Pattern Under Section 104(e)
|
|
Legal Actions Pending at Last Day of Period (d)
|
|
Legal Actions Initiated During Period
|
|
Legal Actions Resolved During Period
|
|||||
Big Brown
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
9
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
Kosse
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
7
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
|
1
|
|
Liberty
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
8
|
|
|
—
|
|
—
|
|
—
|
|
1
|
|
|
1
|
|
|
—
|
|
Three Oaks
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
4
|
|
|
—
|
|
—
|
|
—
|
|
1
|
|
|
2
|
|
|
1
|
|
(a)
|
Excludes mines for which there were no applicable events.
|
(b)
|
Includes MSHA citations for health or safety standards that could significantly and substantially contribute to a serious injury if left unabated.
|
(c)
|
Total value in thousands of dollars for proposed assessments received from MSHA for all citations and orders issued in the year ended December 31, 2017, including but not limited to Sections 104, 107 and 110 citations and orders that are not required to be reported.
|
(d)
|
Pending actions before the FMSHRC involving a coal or other mine. All pending legal actions are contests of proposed penalties.
|