|
|
Delaware
|
|
36-4833255
|
(State or other jurisdiction of incorporation or organization)
|
|
(I.R.S. Employer Identification No.)
|
|
|
|
6555 Sierra Drive, Irving, Texas 75039
|
|
(214) 812-4600
|
(Address of principal executive offices) (Zip Code)
|
|
(Registrant's telephone number, including area code)
|
Title of Each Class
|
|
Name of Each Exchange on Which Registered
|
Common stock, par value $0.01 per share
|
|
New York Stock Exchange
|
Warrants, exercisable for common stock at an exercise price of $35 per 0.652 share
|
|
New York Stock Exchange
|
7.00% tangible equity units
|
|
New York Stock Exchange
|
|
|
|
PAGE
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|
2017 Form 10-K
|
|
Vistra Energy's annual report on Form 10-K for the year ended December 31, 2017, filed with the SEC on February 26, 2018, except for Part II, Items 7 and 8, which were amended in Vistra
Energy's current report on Form 8-K filed with the SEC on June 15, 2018
|
ARO
|
|
asset retirement and mining reclamation obligation
|
CAA
|
|
Clean Air Act
|
CAISO
|
|
The California Independent System Operator
|
CCGT
|
|
combined cycle gas turbine
|
CFTC
|
|
U.S. Commodity Futures Trading Commission
|
Chapter 11 Cases
|
|
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.
|
CME
|
|
Chicago Mercantile Exchange
|
CO
2
|
|
carbon dioxide
|
Contributed EFH Debtors
|
|
certain EFH Debtors that became subsidiaries of Vistra Energy on the Effective Date
|
CT
|
|
combustion turbine
|
DIP Facility
|
|
TCEH's $3.375 billion debtor-in-possession financing facility, which was repaid in August 2016 (see Note 14 to the Financial Statements)
|
DIP Roll Facilities
|
|
TCEH's $4.250 billion debtor-in-possession and exit financing facilities, which were converted to the Vistra Operations Credit Facilities on the Effective Date (see Note 14 to the Financial Statements)
|
Debtors
|
|
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.
|
Dynegy
|
|
Dynegy Inc., and/or its subsidiaries, depending on context
|
Dynegy Energy Services
|
|
Dynegy Energy Services, LLC and Dynegy Energy Services (East), LLC (d/b/a Dynegy and Brighten Energy), indirect, wholly owned subsidiaries of Vistra Energy, that are REPs in certain areas of MISO and PJM, respectively, and are engaged in the retail sale of electricity to residential and business customers.
|
EBITDA
|
|
earnings (net income) before interest expense, income taxes, depreciation and amortization
|
EFCH
|
|
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
|
Effective Date
|
|
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
|
EFH Corp.
|
|
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
|
EFH Debtors
|
|
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
|
EFIH
|
|
Energy Future Intermediate Holding Company LLC, a direct, wholly owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings
|
Emergence
|
|
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
|
EPA
|
|
U.S. Environmental Protection Agency
|
Exchange Act
|
|
Exchange Act of 1934, as amended
|
ERCOT
|
|
Electric Reliability Council of Texas, Inc.
|
Federal and State Income Tax Allocation Agreements
|
|
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 9 to the Financial Statements).
|
FERC
|
|
U.S. Federal Energy Regulatory Commission
|
Fitch
|
|
Fitch Ratings Inc. (a credit rating agency)
|
GAAP
|
|
generally accepted accounting principles
|
GHG
|
|
greenhouse gas
|
GWh
|
|
gigawatt-hours
|
Homefield Energy
|
|
Illinois Power Marketing Company (d/b/a Homefield Energy), an indirect, wholly owned subsidiary of Vistra Energy, a REP in certain areas of MISO that is engaged in the retail sale of electricity to municipal customers
|
ICE
|
|
IntercontinentalExchange
|
IRS
|
|
U.S. Internal Revenue Service
|
ISO
|
|
independent system operator
|
ISO-NE
|
|
Independent System Operator New England
|
kW
|
|
kilowatt
|
LIBOR
|
|
London Interbank Offered Rate, an interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market
|
load
|
|
demand for electricity
|
LSTC
|
|
liabilities subject to compromise
|
LTSA
|
|
long term service agreements for plant maintenance
|
Luminant
|
|
subsidiaries of Vistra Energy engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management
|
market heat rate
|
|
Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier (generally natural gas plants), by the market price of natural gas.
|
Merger
|
|
the merger of Dynegy with and into Vistra Energy, with Vistra Energy as the surviving corporation
|
Merger Agreement
|
|
the Agreement and Plan of Merger, dated as of October 29, 2017, by and between Vistra Energy and Dynegy, as it may be amended or modified from time to time
|
Merger Date
|
|
April 9, 2018, the date Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement
|
MISO
|
|
Midcontinent Independent System Operator, Inc.
|
MMBtu
|
|
million British thermal units
|
Moody's
|
|
Moody's Investors Service, Inc. (a credit rating agency)
|
MSHA
|
|
U.S. Mine Safety and Health Administration
|
MW
|
|
megawatts
|
MWh
|
|
megawatt-hours
|
NERC
|
|
North American Electric Reliability Corporation
|
NO
X
|
|
nitrogen oxide
|
NRC
|
|
U.S. Nuclear Regulatory Commission
|
NYMEX
|
|
the New York Mercantile Exchange, a commodity derivatives exchange
|
NYSE
|
|
New York Stock Exchange
|
NYISO
|
|
New York Independent System Operator
|
Oncor
|
|
Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., that is engaged in regulated electricity transmission and distribution activities
|
Oncor Holdings
|
|
Oncor Electric Delivery Holdings Company LLC, a direct, wholly owned subsidiary of EFIH and the direct majority owner of Oncor, and/or its subsidiaries, depending on context
|
Oncor Ring-Fenced Entities
|
|
Oncor Holdings and its direct and indirect subsidiaries, including Oncor
|
OPEB
|
|
postretirement employee benefits other than pensions
|
Petition Date
|
|
April 29, 2014, the date the Debtors filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code
|
PJM
|
|
PJM Interconnection, LLC
|
Plan of Reorganization
|
|
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
|
PrefCo
|
|
Vistra Preferred Inc.
|
PrefCo Preferred Stock Sale
|
|
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
|
PUCT
|
|
Public Utility Commission of Texas
|
PURA
|
|
Texas Public Utility Regulatory Act
|
REP
|
|
retail electric provider
|
RCT
|
|
Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas
|
RTO
|
|
regional transmission organization
|
S&P
|
|
Standard & Poor's Ratings (a credit rating agency)
|
SEC
|
|
U.S. Securities and Exchange Commission
|
Securities Act
|
|
Securities Act of 1933, as amended
|
SG&A
|
|
selling, general and administrative
|
Settlement Agreement
|
|
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.
|
SO
2
|
|
sulfur dioxide
|
Spin-Off
|
|
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
|
Sponsor Group
|
|
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.
|
ST
|
|
steam turbine
|
Tax Matters Agreement
|
|
Tax Matters Agreement, dated as of the Effective Date, by and among EFH Corp., EFIH, EFIH Finance Inc. and EFH Merger Co. LLC.
|
TCJA
|
|
The Tax Cuts and Jobs Act of 2017, federal income tax legislation enacted in December 2017, which significantly changed the tax laws applicable to business entities
|
TRA
|
|
Tax Receivables Agreement, containing certain rights (TRA Rights) to receive payments from Vistra Energy related to certain tax benefits, including those it realized as a result of certain transactions entered into at Emergence (see Note 10)
|
TRE
|
|
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
|
TCEH or Predecessor
|
|
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
|
TCEH Debtors
|
|
the subsidiaries of TCEH that were Debtors in the Chapter 11 Cases
|
TCEH Senior Secured Facilities
|
|
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.
|
TCEQ
|
|
Texas Commission on Environmental Quality
|
TXU Energy
|
|
TXU Energy Retail Company LLC, an indirect, wholly owned subsidiary of Vistra Energy that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers
|
U.S.
|
|
United States of America
|
Value Based Brands
|
|
Value Based Brands LLC (d/b/a 4Change Energy and Express Energy), an indirect, wholly owned subsidiary of Vistra Energy that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers
|
Vistra Energy or Successor
|
|
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.
|
Vistra Operations
|
|
Vistra Operations Company LLC, an indirect, wholly owned subsidiary of Vistra Energy that is the issuer of certain series of notes (see Note 14 to the Financial Statements) and borrower under the Vistra Operations Credit Facilities
|
Vistra Operations Credit Facilities
|
|
Vistra Operations Company LLC's $8.313 billion senior secured financing facilities (see Note 14 to the Financial Statements)
|
Item 1.
|
BUSINESS
|
•
|
Integrated business model.
We believe the key factor that distinguishes us from others in the competitive electricity industry is the integrated nature of our business (
i.e.
, pairing our reliable and efficient mining, diversified generation fleet and wholesale commodity risk management capabilities with our 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 and cash flow stability. Consequently, our integrated business model is at the core of our business strategy.
|
•
|
Disciplined capital allocation.
Vistra takes a balanced approach to capital allocation, focusing on maintaining a strong balance sheet, investing prudently in the maintenance of our existing assets and potential growth acquisitions, and returning capital to shareholders. Maintaining a strong balance sheet ensures Vistra’s interest expense is manageable in a variety of wholesale power price environments while giving Vistra access to flexible and diverse sources of liquidity. We prudently make necessary capital investments to maintain the safety and reliability of our facilities while also investing in new technologies when economic, including solar assets and battery storage systems, resulting in a continued modernization of Vistra’s generation fleet. 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, including by returning capital to our shareholders. In June and November 2018, our board of directors (Board) authorized a share repurchase program under which up to $500 million and $1.25 billion, respectively, of our outstanding common stock may be repurchased. Through
December 31, 2018
, 33,495,016 shares of our common stock had been repurchased under the program in the aggregate for $778 million (including related fees and expenses) at an average price per share of common stock of $23.23. In November 2018, our Board adopted a dividend program pursuant to which we expect to initiate an annual dividend of approximately $0.50 per share, payable quarterly, beginning in the first quarter of 2019.
|
•
|
Superior customer service.
Through TXU Energy and Value Based Brands in Texas, Dynegy Energy Services in Massachusetts, Ohio, Illinois and Pennsylvania and Homefield Energy in Illinois, 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 brands, 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 TXU Energy's Free Nights and Solar Days residential plans, MyEnergy Dashboard
SM
, TXU Energy's 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 TXU Energy brand have resulted in maintaining the highest residential customer retention rate of any Texas retail electric provider in its respective core market.
|
•
|
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, reducing our debt levels and implementing enterprise-wide process and operating improvements without compromising the safety of our communities, customers and employees. We believe we have a highly effective and efficient cost structure and that our cost structure supports excellence in our operations.
|
•
|
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 markets in which we operate, on an integrated basis, through contracts for physical delivery of electricity, exchange-traded and over-the-counter financial contracts, 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 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.
|
•
|
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. We are also focused on enhancing our retail platform in markets outside of Texas, including our recently announced entry into a purchase agreement to acquire Crius Energy Trust discussed below. 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.
|
•
|
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.
|
|
Year Ended December 31,
|
||||||
|
2018
|
|
Estimated 2019
|
||||
ERCOT
|
$
|
9
|
|
|
$
|
6
|
|
PJM
|
3
|
|
|
14
|
|
||
MISO
|
1
|
|
|
14
|
|
||
CAISO
|
—
|
|
|
1
|
|
||
Total
|
$
|
13
|
|
|
$
|
35
|
|
•
|
demand for energy commodities and general economic conditions;
|
•
|
volatility in commodity prices and the supply of commodities, including but not limited to natural gas, coal and oil;
|
•
|
volatility in market heat rates;
|
•
|
volatility in coal and rail transportation prices;
|
•
|
volatility in nuclear fuel and related enrichment and conversion services;
|
•
|
disruption or other constraints or inefficiencies of electricity, gas or coal transmission or transportation;
|
•
|
severe or unexpected weather conditions, including drought and limitations on access to water;
|
•
|
seasonality;
|
•
|
changes in electricity and fuel usage resulting from conservation efforts, changes in technology or other factors;
|
•
|
illiquidity in the wholesale electricity or other commodity markets;
|
•
|
transmission or transportation disruptions, constraints, inoperability or inefficiencies, or other changes in power transmission infrastructure;
|
•
|
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;
|
•
|
changes in market structure and liquidity;
|
•
|
changes in the way we operate our facilities, including curtailed operation due to market pricing, environmental regulations and legislation, safety or other factors;
|
•
|
changes in generation capacity or efficiency;
|
•
|
outages or otherwise reduced output from our generation facilities or those of our competitors;
|
•
|
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;
|
•
|
our creditworthiness and liquidity and the willingness of fuel suppliers and transporters to do business with us;
|
•
|
changes in the credit risk or payment practices of market participants;
|
•
|
changes in production and storage levels of natural gas, lignite, coal, uranium, diesel and other refined products;
|
•
|
natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events, and
|
•
|
changes in law, including judicial decisions, federal, state and local energy, environmental and other regulation and legislation.
|
•
|
general economic and capital markets conditions, including changes in financial markets that reduce available liquidity or the ability to obtain or renew credit facilities on favorable terms or at all;
|
•
|
conditions and economic weakness in the U.S. power markets;
|
•
|
regulatory developments;
|
•
|
changes in interest rates;
|
•
|
a deterioration, or perceived deterioration, of our creditworthiness, enterprise value or financial or operating results;
|
•
|
a reduction in Vistra Energy's or its applicable subsidiaries' credit ratings;
|
•
|
our level of indebtedness and compliance with covenants in our debt agreements;
|
•
|
a deterioration of the creditworthiness or bankruptcy of one or more lenders or counterparties under our credit facilities that affects the ability of such lender(s) to make loans to us;
|
•
|
security or collateral requirements;
|
•
|
general credit availability from banks or other lenders for us and our industry peers;
|
•
|
investor confidence in the industry and in us and the wholesale electricity markets in which we operate;
|
•
|
volatility in commodity prices that increases credit requirements;
|
•
|
a material breakdown in our risk management procedures;
|
•
|
the occurrence of changes in our businesses;
|
•
|
disruptions, constraints, or inefficiencies in the continued reliable operation of our generation facilities, and
|
•
|
changes in or the operation of provisions of tax and regulatory laws.
|
•
|
increasing our vulnerability to general economic and industry conditions;
|
•
|
requiring a substantial portion of our cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to pay dividends to holders of our common stock or to fund our operations, capital expenditures and future business opportunities;
|
•
|
limiting our ability to enter into long-term power sales or fuel purchases which require credit support;
|
•
|
limiting our ability to fund operations or future acquisitions;
|
•
|
restricting our ability to make distributions or pay dividends with respect to our capital stock and the ability of our subsidiaries to make distributions to us, in light of restricted payment and other financial covenants in our credit facilities and other financing agreements;
|
•
|
inhibiting the growth of our stock price;
|
•
|
exposing us to the risk of increased interest rates because certain of our borrowings, including borrowings under the Vistra Operations Credit Facilities, are at variable rates of interest;
|
•
|
limiting our ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes, and
|
•
|
limiting our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to our competitors who may have less debt.
|
•
|
difficulties in the separation of operations and personnel;
|
•
|
the need to provide significant ongoing post-closing transition support to a buyer;
|
•
|
management's attention may be temporarily diverted;
|
•
|
the retention of certain current or future liabilities in order to induce a buyer to complete a divestiture;
|
•
|
the obligation to indemnify or reimburse a buyer for certain past liabilities of a divested asset;
|
•
|
the disruption of our business, and
|
•
|
potential loss of key employees.
|
•
|
varying supply procurement contracts used and the timing of entering into related contracts;
|
•
|
subsequent changes in the overall price of natural gas;
|
•
|
daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices;
|
•
|
transmission constraints and the Company's ability to move power to our customers, and
|
•
|
changes in market heat rate.
|
•
|
unscheduled outages or unexpected costs due to equipment, mechanical, structural, cybersecurity or other problems;
|
•
|
inadequacy or lapses in maintenance protocols;
|
•
|
the impairment of reactor operation and safety systems due to human error or force majeure;
|
•
|
the costs of, and liabilities relating to, storage, handling, treatment, transport, release, use and disposal of radioactive materials;
|
•
|
the costs of procuring nuclear fuel;
|
•
|
the costs of storing and maintaining spent nuclear fuel at our on-site dry cask storage facility;
|
•
|
terrorist or cybersecurity attacks and the cost to protect against any such attack;
|
•
|
the impact of a natural disaster;
|
•
|
limitations on the amounts and types of insurance coverage commercially available, and
|
•
|
uncertainties with respect to the technological and financial aspects of modifying or decommissioning nuclear facilities at the end of their useful lives.
|
•
|
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.
|
•
|
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.
|
•
|
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.
|
Item 1B.
|
UNRESOLVED STAFF COMMENTS
|
Item 2.
|
PROPERTIES
|
Facility
|
|
Location
|
|
RTO/ISO
|
|
Technology
|
|
Primary Fuel
|
|
Net Capacity (MW) (a)
|
|
Ownership Interest
|
|
Ennis
|
|
Ennis, TX
|
|
ERCOT
|
|
CCGT
|
|
Natural Gas
|
|
366
|
|
|
100%
|
Forney
|
|
Forney, TX
|
|
ERCOT
|
|
CCGT
|
|
Natural Gas
|
|
1,912
|
|
|
100%
|
Hays
|
|
San Marcos, TX
|
|
ERCOT
|
|
CCGT
|
|
Natural Gas
|
|
1,047
|
|
|
100%
|
Lamar
|
|
Paris, TX
|
|
ERCOT
|
|
CCGT
|
|
Natural Gas
|
|
1,076
|
|
|
100%
|
Midlothian
|
|
Midlothian, TX
|
|
ERCOT
|
|
CCGT
|
|
Natural Gas
|
|
1,596
|
|
|
100%
|
Odessa
|
|
Odessa, TX
|
|
ERCOT
|
|
CCGT
|
|
Natural Gas
|
|
1,054
|
|
|
100%
|
Wise
|
|
Poolville, TX
|
|
ERCOT
|
|
CCGT
|
|
Natural Gas
|
|
787
|
|
|
100%
|
Coleto Creek
|
|
Goliad, TX
|
|
ERCOT
|
|
ST
|
|
Coal
|
|
650
|
|
|
100%
|
Martin Lake
|
|
Tatum, TX
|
|
ERCOT
|
|
ST
|
|
Coal
|
|
2,250
|
|
|
100%
|
Oak Grove
|
|
Franklin, TX
|
|
ERCOT
|
|
ST
|
|
Coal
|
|
1,600
|
|
|
100%
|
DeCordova
|
|
Granbury, TX
|
|
ERCOT
|
|
CT
|
|
Natural Gas
|
|
260
|
|
|
100%
|
Graham
|
|
Graham, TX
|
|
ERCOT
|
|
ST
|
|
Natural Gas
|
|
630
|
|
|
100%
|
Lake Hubbard
|
|
Dallas, TX
|
|
ERCOT
|
|
ST
|
|
Natural Gas
|
|
921
|
|
|
100%
|
Morgan Creek
|
|
Colorado City, TX
|
|
ERCOT
|
|
CT
|
|
Natural Gas
|
|
390
|
|
|
100%
|
Permian Basin
|
|
Monahans, TX
|
|
ERCOT
|
|
CT
|
|
Natural Gas
|
|
325
|
|
|
100%
|
Stryker Creek
|
|
Rusk, TX
|
|
ERCOT
|
|
ST
|
|
Natural Gas
|
|
685
|
|
|
100%
|
Trinidad
|
|
Trinidad, TX
|
|
ERCOT
|
|
ST
|
|
Natural Gas
|
|
244
|
|
|
100%
|
Wharton
|
|
Boling, TX
|
|
ERCOT
|
|
CT
|
|
Natural Gas
|
|
83
|
|
|
100%
|
Comanche Peak
|
|
Glen Rose, TX
|
|
ERCOT
|
|
Nuclear
|
|
Nuclear
|
|
2,300
|
|
|
100%
|
Upton 2
|
|
Upton County, TX
|
|
ERCOT
|
|
Solar
|
|
Solar
|
|
180
|
|
|
100%
|
Upton 2 Battery Storage
|
|
Upton County, TX
|
|
ERCOT
|
|
Battery
|
|
Battery
|
|
10
|
|
|
100%
|
Total ERCOT Segment
|
|
18,366
|
|
|
|
||||||||
Fayette
|
|
Masontown, PA
|
|
PJM
|
|
CCGT
|
|
Natural Gas
|
|
726
|
|
|
100%
|
Hanging Rock
|
|
Ironton, OH
|
|
PJM
|
|
CCGT
|
|
Natural Gas
|
|
1,430
|
|
|
100%
|
Hopewell
|
|
Hopewell, VA
|
|
PJM
|
|
CCGT
|
|
Natural Gas
|
|
370
|
|
|
100%
|
Kendall
|
|
Minooka, IL
|
|
PJM
|
|
CCGT
|
|
Natural Gas
|
|
1,288
|
|
|
100%
|
Liberty
|
|
Eddystone, PA
|
|
PJM
|
|
CCGT
|
|
Natural Gas
|
|
607
|
|
|
100%
|
Ontelaunee
|
|
Reading, PA
|
|
PJM
|
|
CCGT
|
|
Natural Gas
|
|
600
|
|
|
100%
|
Sayreville
|
|
Sayreville, NJ
|
|
PJM
|
|
CCGT
|
|
Natural Gas
|
|
170
|
|
|
50%
|
Washington
|
|
Beverly, OH
|
|
PJM
|
|
CCGT
|
|
Natural Gas
|
|
711
|
|
|
100%
|
Kincaid
|
|
Kincaid, IL
|
|
PJM
|
|
ST
|
|
Coal
|
|
1,108
|
|
|
100%
|
Miami Fort 7 & 8
|
|
North Bend, OH
|
|
PJM
|
|
ST
|
|
Coal
|
|
1,020
|
|
|
100%
|
Zimmer
|
|
Moscow, OH
|
|
PJM
|
|
ST
|
|
Coal
|
|
1,300
|
|
|
100%
|
Calumet
|
|
Chicago, IL
|
|
PJM
|
|
CT
|
|
Natural Gas
|
|
380
|
|
|
100%
|
Dicks Creek
|
|
Monroe, OH
|
|
PJM
|
|
CT
|
|
Natural Gas
|
|
155
|
|
|
100%
|
Miami Fort (CT)
|
|
North Bend, OH
|
|
PJM
|
|
CT
|
|
Oil
|
|
77
|
|
|
100%
|
Pleasants
|
|
Saint Marys, WV
|
|
PJM
|
|
CT
|
|
Natural Gas
|
|
388
|
|
|
100%
|
Richland
|
|
Defiance, OH
|
|
PJM
|
|
CT
|
|
Natural Gas
|
|
423
|
|
|
100%
|
Stryker
|
|
Stryker, OH
|
|
PJM
|
|
CT
|
|
Oil
|
|
16
|
|
|
100%
|
Total PJM Segment
|
|
10,769
|
|
|
|
Facility
|
|
Location
|
|
RTO/ISO
|
|
Technology
|
|
Primary Fuel
|
|
Net Capacity (MW) (a)
|
|
Ownership Interest
|
|
Bellingham
|
|
Bellingham, MA
|
|
ISO-NE
|
|
CCGT
|
|
Natural Gas
|
|
566
|
|
|
100%
|
Bellingham NEA
|
|
Bellingham, MA
|
|
ISO-NE
|
|
CCGT
|
|
Natural Gas
|
|
157
|
|
|
50%
|
Blackstone
|
|
Blackstone, MA
|
|
ISO-NE
|
|
CCGT
|
|
Natural Gas
|
|
544
|
|
|
100%
|
Casco Bay
|
|
Veazie, ME
|
|
ISO-NE
|
|
CCGT
|
|
Natural Gas
|
|
543
|
|
|
100%
|
Independence
|
|
Oswego, NY
|
|
NYISO
|
|
CCGT
|
|
Natural Gas
|
|
1,212
|
|
|
100%
|
Lake Road
|
|
Dayville, CT
|
|
ISO-NE
|
|
CCGT
|
|
Natural Gas
|
|
827
|
|
|
100%
|
MASSPOWER
|
|
Indian Orchard, MA
|
|
ISO-NE
|
|
CCGT
|
|
Natural Gas
|
|
281
|
|
|
100%
|
Milford
|
|
Milford, CT
|
|
ISO-NE
|
|
CCGT
|
|
Natural Gas
|
|
600
|
|
|
100%
|
Total NY/NE Segment
|
|
4,730
|
|
|
|
||||||||
Baldwin
|
|
Baldwin, IL
|
|
MISO
|
|
ST
|
|
Coal
|
|
1,185
|
|
|
100%
|
Havana
|
|
Havana, IL
|
|
MISO
|
|
ST
|
|
Coal
|
|
434
|
|
|
100%
|
Hennepin
|
|
Hennepin, IL
|
|
MISO
|
|
ST
|
|
Coal
|
|
294
|
|
|
100%
|
Coffeen
|
|
Coffeen, IL
|
|
MISO/PJM
|
|
ST
|
|
Coal
|
|
915
|
|
|
100%
|
Duck Creek
|
|
Canton, IL
|
|
MISO/PJM
|
|
ST
|
|
Coal
|
|
425
|
|
|
100%
|
Edwards
|
|
Bartonville, IL
|
|
MISO/PJM
|
|
ST
|
|
Coal
|
|
585
|
|
|
100%
|
Newton
|
|
Newton, IL
|
|
MISO/PJM
|
|
ST
|
|
Coal
|
|
615
|
|
|
100%
|
Joppa/EEI
|
|
Joppa, IL
|
|
MISO
|
|
ST
|
|
Coal
|
|
802
|
|
|
80%
|
Joppa CT 1-3
|
|
Joppa, IL
|
|
MISO
|
|
CT
|
|
Natural Gas
|
|
165
|
|
|
100%
|
Joppa CT 4-5
|
|
Joppa, IL
|
|
MISO
|
|
CT
|
|
Natural Gas
|
|
56
|
|
|
80%
|
Total MISO Segment
|
|
5,476
|
|
|
|
||||||||
Moss Landing 1 & 2
|
|
Moss Landing, CA
|
|
CAISO
|
|
CCGT
|
|
Natural Gas
|
|
1,020
|
|
|
100%
|
Oakland
|
|
Oakland, CA
|
|
CAISO
|
|
CT
|
|
Oil
|
|
165
|
|
|
100%
|
Total CAISO
|
|
1,185
|
|
|
|
||||||||
Total capacity
|
|
40,526
|
|
|
|
(a)
|
Unit capabilities are based on winter capacity and are reflected at our net ownership interest. We have not included units that have been retired or are out of operation.
|
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
|
|
|
Total Number of Shares Purchased
|
|
Average Price Paid per Share
|
|
Total Number of Shares Purchased as Part of a Publicly Announced Program
|
|
Maximum Dollar Amount of Shares that may yet be Purchased under the Program (in millions)
|
||||||
October 1 - October 31, 2018
|
|
3,150,820
|
|
|
$
|
24.38
|
|
|
3,150,820
|
|
|
$
|
—
|
|
November 1 - November 30, 2018
|
|
6,238,950
|
|
|
$
|
22.99
|
|
|
6,238,950
|
|
|
$
|
1,107
|
|
December 1 - December 31, 2018
|
|
5,834,141
|
|
|
$
|
22.99
|
|
|
5,834,141
|
|
|
$
|
972
|
|
For the quarter ended December 31, 2018
|
|
15,223,911
|
|
|
$
|
23.28
|
|
|
15,223,911
|
|
|
$
|
972
|
|
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, 2018 (a)
|
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
|
||||||||||||||||
Operating revenues
|
$
|
9,144
|
|
$
|
5,430
|
|
|
$
|
1,191
|
|
|
|
$
|
3,973
|
|
|
$
|
5,370
|
|
|
$
|
5,978
|
|
Impairment of goodwill
|
$
|
—
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
(2,200
|
)
|
|
$
|
(1,600
|
)
|
Impairment of long-lived assets
|
$
|
—
|
|
$
|
(25
|
)
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
(2,541
|
)
|
|
$
|
(4,670
|
)
|
Operating income (loss)
|
$
|
491
|
|
$
|
198
|
|
|
$
|
(161
|
)
|
|
|
$
|
568
|
|
|
$
|
(4,091
|
)
|
|
$
|
(6,015
|
)
|
Net income (loss) attributable to Vistra Energy/the Predecessor (b)
|
$
|
(54
|
)
|
$
|
(254
|
)
|
|
$
|
(163
|
)
|
|
|
$
|
22,851
|
|
|
$
|
(4,677
|
)
|
|
$
|
(6,229
|
)
|
Cash provided by (used in) operating activities
|
$
|
1,471
|
|
$
|
1,386
|
|
|
$
|
81
|
|
|
|
$
|
(238
|
)
|
|
$
|
237
|
|
|
$
|
444
|
|
Net loss per weighted average share of common stock outstanding — basic
|
$
|
(0.11
|
)
|
$
|
(0.59
|
)
|
|
$
|
(0.38
|
)
|
|
|
|
|
|
|
|
||||||
Net loss per weighted average share of common stock outstanding — diluted
|
$
|
(0.11
|
)
|
$
|
(0.59
|
)
|
|
$
|
(0.38
|
)
|
|
|
|
|
|
|
|
||||||
Dividend declared per share of common stock
|
$
|
—
|
|
$
|
—
|
|
|
$
|
2.32
|
|
|
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||||||
|
At December 31,
|
|
|
At December 31,
|
||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
|
2015
|
|
2014
|
||||||||||
Balance Sheet Information:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total assets (c)(d)
|
$
|
26,024
|
|
|
$
|
14,600
|
|
|
$
|
15,167
|
|
|
|
$
|
15,658
|
|
|
$
|
21,343
|
|
Property, plant and equipment — net (c)(d)
|
$
|
14,612
|
|
|
$
|
4,820
|
|
|
$
|
4,443
|
|
|
|
$
|
9,349
|
|
|
$
|
12,288
|
|
Goodwill and intangible assets (e)
|
$
|
4,561
|
|
|
$
|
4,437
|
|
|
$
|
5,112
|
|
|
|
$
|
1,331
|
|
|
$
|
3,688
|
|
Long-term debt including current maturities (e)
|
$
|
11,065
|
|
|
$
|
4,423
|
|
|
$
|
4,623
|
|
|
|
$
|
19
|
|
|
$
|
73
|
|
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 stockholders' equity/membership interests
|
$
|
7,863
|
|
|
$
|
6,342
|
|
|
$
|
6,597
|
|
|
|
$
|
(22,884
|
)
|
|
$
|
(18,209
|
)
|
(a)
|
For the year ended December 31, 2018, reflects the results of operations acquired in the Merger.
|
(b)
|
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
7
to the Financial Statements).
|
(c)
|
At December 31, 2018, includes assets acquired in the Merger.
|
(d)
|
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).
|
(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.
|
Item 7.
|
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
•
|
Aggregate commitments under the Revolving Credit Facility were increased from $860 million to
$2.5 billion
. The letter of credit sub-facility was also increased from $715 million to
$2.3 billion
. The maturity date of the Revolving Credit Facility was extended from August 4, 2021 to June 14, 2023. Pricing terms for the Revolving Credit Facility were reduced from LIBOR plus an applicable margin of 2.25% to LIBOR plus an applicable margin of 1.75%. Pricing terms for letters of credit issued under the Revolving Credit Facility were reduced from 2.25% to 1.75%.
|
•
|
Pricing terms for the Term Loan B-1 Facility were reduced from LIBOR plus an applicable margin of 2.50% to LIBOR plus an applicable margin of 2.00%.
|
•
|
Borrowings under the new Term Loan B-3 Facility of
$2.040 billion
principal amount were used to repay borrowings under the credit agreement that Vistra Energy assumed from Dynegy in connection with the Merger. Amounts borrowed under the Term Loan B-3 Facility bear interest based on applicable LIBOR rates plus a fixed spread of 2.00%, and the maturity date of the facility is December 31, 2025.
|
•
|
Borrowings under the Term Loan C Facility of $500 million were repaid using $500 million of cash from collateral accounts used to backstop letters of credit.
|
|
2018-2019
|
|
2019-2020
|
|
2020-2021
|
|
2021-2022
|
||||||||||||||||
|
Base
|
|
CP
|
|
Base
|
|
CP
|
|
CP
|
|
CP
|
||||||||||||
|
(price per MW-day)
|
||||||||||||||||||||||
RTO zone (a)
|
$
|
149.98
|
|
|
$
|
164.77
|
|
|
$
|
80.00
|
|
|
$
|
100.00
|
|
|
$
|
88.32
|
|
|
$
|
140.00
|
|
ComEd zone
|
200.21
|
|
|
215.00
|
|
|
182.77
|
|
|
202.77
|
|
|
188.12
|
|
|
195.55
|
|
||||||
MAAC zone
|
149.98
|
|
|
164.77
|
|
|
80.00
|
|
|
100.00
|
|
|
86.04
|
|
|
140.00
|
|
||||||
EMAAC zone
|
210.63
|
|
|
225.42
|
|
|
99.77
|
|
|
119.77
|
|
|
187.87
|
|
|
165.73
|
|
||||||
ATSI zone
|
149.88
|
|
|
164.77
|
|
|
80.00
|
|
|
100.00
|
|
|
76.53
|
|
|
171.33
|
|
||||||
PPL zone
|
75.00
|
|
|
164.77
|
|
|
80.00
|
|
|
100.00
|
|
|
86.04
|
|
|
140.00
|
|
(a)
|
Planning Year 2020-2021 includes Duke Energy Ohio Kentucky (DEOK) zone which cleared at $130.00 per MW-day. RTO Zone excluding DEOK Zone was $76.53 per MW-day.
|
|
2018-2019
|
|
2019-2020
|
|
2020-2021
|
|
2021-2022
|
|||||||||
Base auction capacity sold, net (MW)
|
1,420
|
|
|
893
|
|
|
—
|
|
|
—
|
|
|||||
CP auction capacity sold, net (MW)
|
7,771
|
|
|
8,144
|
|
|
8,642
|
|
|
9,053
|
|
|||||
Bilateral capacity sold, net (MW)
|
285
|
|
—
|
|
200
|
|
|
200
|
|
|
200
|
|
||||
Total segment capacity sold, net (MW)
|
9,476
|
|
|
9,237
|
|
|
8,842
|
|
|
9,253
|
|
|||||
Average price per MW-day
|
$
|
186.40
|
|
|
$
|
135.56
|
|
|
$
|
129.30
|
|
|
$
|
159.22
|
|
|
Summer
2018
|
|
Winter
2018 - 2019
|
||||
Price per kW-month
|
$
|
1.75
|
|
|
$
|
0.35
|
|
|
Winter
2018 - 2019
|
|
Summer
2019
|
|
Winter
2019 - 2020
|
|
Summer
2020
|
|
Winter
2020 - 2021
|
|
Summer
2021
|
||||||||||||
Auction capacity sold (MW)
|
88
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Bilateral capacity sold (MW)
|
989
|
|
|
540
|
|
|
210
|
|
|
75
|
|
|
38
|
|
|
20
|
|
||||||
Total capacity sold (MW)
|
1,077
|
|
|
540
|
|
|
210
|
|
|
75
|
|
|
38
|
|
|
20
|
|
||||||
Average price per kW-month
|
$
|
1.37
|
|
|
$
|
2.71
|
|
|
$
|
2.57
|
|
|
$
|
3.15
|
|
|
$
|
3.13
|
|
|
$
|
3.08
|
|
|
2018-2019
|
|
2019-2020
|
|
2020-2021
|
|
2021-2022
|
|
2022-2023
|
||||||||||
Price per kW-month
|
$
|
9.55
|
|
|
$
|
7.03
|
|
|
$
|
5.30
|
|
|
$
|
4.63
|
|
|
$
|
3.80
|
|
|
2018-2018
|
|
2019-2020
|
|
2020-2021
|
|
2021-2022
|
|
2022-2023
|
||||||||||
Auction capacity sold (MW)
|
3,108
|
|
|
3,161
|
|
|
3,079
|
|
|
2,592
|
|
|
3,137
|
|
|||||
Bilateral capacity sold (MW)
|
239
|
|
|
75
|
|
|
150
|
|
|
170
|
|
|
95
|
|
|||||
Total capacity sold (MW)
|
3,347
|
|
|
3,236
|
|
|
3,229
|
|
|
2,762
|
|
|
3,232
|
|
|||||
Average price per kW-month
|
$
|
9.80
|
|
|
$
|
7.02
|
|
|
$
|
5.40
|
|
|
$
|
4.80
|
|
|
$
|
3.92
|
|
|
2018-2019
|
||
Price per MW-day
|
$
|
10.00
|
|
|
2018-2019
|
|
2019-2020
|
|
2020-2021
|
|
2021-2022
|
||||||||
Bilateral capacity sold in MISO (MW)
|
2,533
|
|
|
2,047
|
|
|
1,663
|
|
|
667
|
|
||||
Base auction capacity sold in PJM (MW)
|
227
|
|
|
260
|
|
|
—
|
|
|
—
|
|
||||
CP auction capacity sold in PJM (MW)
|
835
|
|
|
356
|
|
|
444
|
|
|
798
|
|
||||
Total MISO segment capacity sold (MW)
|
3,595
|
|
|
2,663
|
|
|
2,107
|
|
|
1,465
|
|
||||
Average price per kW-month
|
$
|
3.70
|
|
|
$
|
3.62
|
|
|
$
|
3.81
|
|
|
$
|
4.22
|
|
|
2019
|
|
2020
|
|
2021
|
|||
Bilateral capacity sold (Avg MW)
|
890
|
|
|
—
|
|
|
—
|
|
(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.
|
|
2019
|
|
2020
|
||
PJM
|
87
|
%
|
|
57
|
%
|
NYISO/ISO-NE
|
81
|
%
|
|
29
|
%
|
MISO/CAISO
|
65
|
%
|
|
35
|
%
|
|
Balance 2019 (a)
|
|
2020
|
ERCOT:
|
|
|
|
$0.50/MMBtu increase in natural gas price (b)
|
$ ~50
|
|
$ ~115
|
$0.50/MMBtu decrease in natural gas price (b)
|
$ ~(35)
|
|
$ ~(100)
|
1.0/MMBtu/MWh increase in market heat rate (c)
|
$ ~60
|
|
$ ~165
|
1.0/MMBtu/MWh decrease in market heat rate (c)
|
$ ~(45)
|
|
$ ~(150)
|
PJM:
|
|
|
|
$0.50/MMBtu increase in natural gas price (d)
|
$ ~32
|
|
$ ~93
|
$0.50/MMBtu decrease in natural gas price (d)
|
$ ~(22)
|
|
$ ~(72)
|
1.0/MMBtu/MWh increase in market heat rate (e)
|
$ ~33
|
|
$ ~71
|
1.0/MMBtu/MWh decrease in market heat rate (e)
|
$ ~(26)
|
|
$ ~(68)
|
NYISO/ISO-NE:
|
|
|
|
$0.50/MMBtu increase in natural gas price (d)
|
$ ~11
|
|
$ ~66
|
$0.50/MMBtu decrease in natural gas price (d)
|
$ ~(5)
|
|
$ ~(54)
|
1.0/MMBtu/MWh increase in market heat rate (f)
|
$ ~23
|
|
$ ~62
|
1.0/MMBtu/MWh decrease in market heat rate (f)
|
$ ~(11)
|
|
$ ~(50)
|
MISO/CAISO:
|
|
|
|
$0.50/MMBtu increase in natural gas price (d)
|
$ ~85
|
|
$ ~145
|
$0.50/MMBtu decrease in natural gas price (d)
|
$ ~(68)
|
|
$ ~(116)
|
1.0/MMBtu/MWh increase in market heat rate (g)
|
$ ~47
|
|
$ ~73
|
1.0/MMBtu/MWh decrease in market heat rate (g)
|
$ ~(42)
|
|
$ ~(65)
|
(a)
|
Balance of
2019
is from February 1,
2019
through December 31,
2019
.
|
(b)
|
Based on Houston Ship Channel natural gas prices at
December 31, 2018
.
|
(c)
|
Based on ERCOT North Hub around-the-clock heat rates at
December 31, 2018
.
|
(d)
|
Based on NYMEX natural gas prices at
December 31, 2018
.
|
(e)
|
Based on AEP Dayton Hub, Northern Illinois Hub and PJM West Hub around-the-clock heat rates at
December 31, 2018
.
|
(f)
|
Based on Massachusetts Hub and NYISO Zone C around-the-clock heat rates at
December 31, 2018
.
|
(g)
|
Based on Indiana Hub and NP15 around-the-clock heat rates at
December 31, 2018
.
|
•
|
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 blended federal/state corporate income tax rate in all future years of 23%;
|
•
|
future taxable income by year for future years;
|
•
|
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;
|
•
|
a discount rate of 15%, which represented our view at the Emergence Date 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, and
|
•
|
additional states that Vistra Energy now operates in, the relevant tax rates of those states and how income will be apportioned to those states.
|
|
Successor
|
||||||||||||||
|
Year Ended December 31,
|
|
Favorable (Unfavorable)
$ Change
|
|
Period from October 3, 2016
through December 31, 2016 |
||||||||||
|
2018
|
|
2017
|
|
|
||||||||||
Operating revenues
|
$
|
9,144
|
|
|
$
|
5,430
|
|
|
$
|
3,714
|
|
|
$
|
1,191
|
|
Fuel, purchased power costs and delivery fees
|
(5,036
|
)
|
|
(2,935
|
)
|
|
(2,101
|
)
|
|
(720
|
)
|
||||
Operating costs
|
(1,297
|
)
|
|
(973
|
)
|
|
(324
|
)
|
|
(208
|
)
|
||||
Depreciation and amortization
|
(1,394
|
)
|
|
(699
|
)
|
|
(695
|
)
|
|
(216
|
)
|
||||
Selling, general and administrative expenses
|
(926
|
)
|
|
(600
|
)
|
|
(326
|
)
|
|
(208
|
)
|
||||
Impairment of long-lived assets
|
—
|
|
|
(25
|
)
|
|
25
|
|
|
—
|
|
||||
Operating income
|
491
|
|
|
198
|
|
|
293
|
|
|
(161
|
)
|
||||
Other income
|
47
|
|
|
37
|
|
|
10
|
|
|
10
|
|
||||
Other deductions
|
(5
|
)
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
||||
Interest expense and related charges
|
(572
|
)
|
|
(193
|
)
|
|
(379
|
)
|
|
(60
|
)
|
||||
Impacts of Tax Receivable Agreement
|
(79
|
)
|
|
213
|
|
|
(292
|
)
|
|
(22
|
)
|
||||
Equity in earnings of unconsolidated investment
|
17
|
|
|
—
|
|
|
17
|
|
|
—
|
|
||||
Income before income taxes
|
(101
|
)
|
|
250
|
|
|
(351
|
)
|
|
(233
|
)
|
||||
Income tax (expense) benefit
|
45
|
|
|
(504
|
)
|
|
549
|
|
|
70
|
|
||||
Net income (loss)
|
$
|
(56
|
)
|
|
$
|
(254
|
)
|
|
$
|
198
|
|
|
$
|
(163
|
)
|
|
Successor
|
||||||||||||||||||||||||||||||
|
Year Ended December 31, 2018
|
||||||||||||||||||||||||||||||
|
Retail
|
|
ERCOT
|
|
PJM
|
|
NY/NE
|
|
MISO
|
|
Asset
Closure
|
|
Eliminations / Corporate and Other
|
|
Vistra
Energy Consolidated
|
||||||||||||||||
Operating revenues
|
$
|
5,597
|
|
|
$
|
2,634
|
|
|
$
|
1,725
|
|
|
$
|
817
|
|
|
$
|
720
|
|
|
$
|
50
|
|
|
$
|
(2,399
|
)
|
|
$
|
9,144
|
|
Fuel, purchased power costs and delivery fees
|
(4,126
|
)
|
|
(1,521
|
)
|
|
(917
|
)
|
|
(485
|
)
|
|
(420
|
)
|
|
(40
|
)
|
|
2,473
|
|
|
(5,036
|
)
|
||||||||
Operating costs
|
(39
|
)
|
|
(677
|
)
|
|
(243
|
)
|
|
(74
|
)
|
|
(202
|
)
|
|
(43
|
)
|
|
(19
|
)
|
|
(1,297
|
)
|
||||||||
Depreciation and amortization
|
(318
|
)
|
|
(416
|
)
|
|
(413
|
)
|
|
(152
|
)
|
|
(9
|
)
|
|
—
|
|
|
(86
|
)
|
|
(1,394
|
)
|
||||||||
Selling, general and administrative expenses
|
(424
|
)
|
|
(90
|
)
|
|
(52
|
)
|
|
(36
|
)
|
|
(53
|
)
|
|
(17
|
)
|
|
(254
|
)
|
|
(926
|
)
|
||||||||
Operating income (loss)
|
690
|
|
|
(70
|
)
|
|
100
|
|
|
70
|
|
|
36
|
|
|
(50
|
)
|
|
(285
|
)
|
|
491
|
|
||||||||
Other income
|
29
|
|
|
34
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
(19
|
)
|
|
47
|
|
||||||||
Other deductions
|
—
|
|
|
(7
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
3
|
|
|
(5
|
)
|
||||||||
Interest expense and related charges
|
(7
|
)
|
|
(12
|
)
|
|
(8
|
)
|
|
(2
|
)
|
|
(1
|
)
|
|
—
|
|
|
(542
|
)
|
|
(572
|
)
|
||||||||
Impacts of Tax Receivable Agreement
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(79
|
)
|
|
(79
|
)
|
||||||||
Equity in earnings of unconsolidated investment
|
—
|
|
|
—
|
|
|
7
|
|
|
11
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
17
|
|
||||||||
Income (loss) before income taxes
|
712
|
|
|
(55
|
)
|
|
100
|
|
|
79
|
|
|
35
|
|
|
(49
|
)
|
|
(923
|
)
|
|
(101
|
)
|
||||||||
Income tax benefit
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
45
|
|
|
45
|
|
||||||||
Net income (loss)
|
$
|
712
|
|
|
$
|
(55
|
)
|
|
$
|
100
|
|
|
$
|
79
|
|
|
$
|
35
|
|
|
$
|
(49
|
)
|
|
$
|
(878
|
)
|
|
$
|
(56
|
)
|
|
Successor
|
||||||||||||||||||
|
Year Ended December 31, 2017
|
||||||||||||||||||
|
Retail
|
|
ERCOT
|
|
Asset
Closure
|
|
Eliminations / Corporate and Other
|
|
Vistra
Energy Consolidated
|
||||||||||
Operating revenues
|
$
|
4,058
|
|
|
$
|
1,794
|
|
|
$
|
964
|
|
|
$
|
(1,386
|
)
|
|
$
|
5,430
|
|
Fuel, purchased power costs and delivery fees
|
(2,733
|
)
|
|
(981
|
)
|
|
(607
|
)
|
|
1,386
|
|
|
(2,935
|
)
|
|||||
Operating costs
|
(14
|
)
|
|
(578
|
)
|
|
(380
|
)
|
|
(1
|
)
|
|
(973
|
)
|
|||||
Depreciation and amortization
|
(430
|
)
|
|
(229
|
)
|
|
(1
|
)
|
|
(39
|
)
|
|
(699
|
)
|
|||||
Selling, general and administrative expenses
|
(420
|
)
|
|
(124
|
)
|
|
(19
|
)
|
|
(37
|
)
|
|
(600
|
)
|
|||||
Impairment of long-lived assets
|
—
|
|
|
—
|
|
|
(25
|
)
|
|
—
|
|
|
(25
|
)
|
|||||
Operating income (loss)
|
461
|
|
|
(118
|
)
|
|
(68
|
)
|
|
(77
|
)
|
|
198
|
|
|||||
Other income
|
34
|
|
|
24
|
|
|
6
|
|
|
(27
|
)
|
|
37
|
|
|||||
Other deductions
|
—
|
|
|
(3
|
)
|
|
(1
|
)
|
|
(1
|
)
|
|
(5
|
)
|
|||||
Interest expense and related charges
|
—
|
|
|
(21
|
)
|
|
—
|
|
|
(172
|
)
|
|
(193
|
)
|
|||||
Impacts of Tax Receivable Agreement
|
—
|
|
|
—
|
|
|
—
|
|
|
213
|
|
|
213
|
|
|||||
Income (loss) before income taxes
|
495
|
|
|
(118
|
)
|
|
(63
|
)
|
|
(64
|
)
|
|
250
|
|
|||||
Income tax expense
|
—
|
|
|
—
|
|
|
—
|
|
|
(504
|
)
|
|
(504
|
)
|
|||||
Net income (loss)
|
$
|
495
|
|
|
$
|
(118
|
)
|
|
$
|
(63
|
)
|
|
$
|
(568
|
)
|
|
$
|
(254
|
)
|
|
Successor
|
||||||||||||||||||
|
Period from October 3, 2016 through December 31, 2016
|
||||||||||||||||||
|
Retail
|
|
ERCOT
|
|
Asset Closure
|
|
Eliminations / Corporate and Other
|
|
Vistra
Energy Consolidated
|
||||||||||
Operating revenues
|
$
|
912
|
|
|
$
|
212
|
|
|
$
|
238
|
|
|
$
|
(171
|
)
|
|
$
|
1,191
|
|
Fuel, purchased power costs and delivery fees
|
(515
|
)
|
|
(214
|
)
|
|
(162
|
)
|
|
171
|
|
|
(720
|
)
|
|||||
Operating costs
|
(3
|
)
|
|
(151
|
)
|
|
(54
|
)
|
|
—
|
|
|
(208
|
)
|
|||||
Depreciation and amortization
|
(153
|
)
|
|
(53
|
)
|
|
—
|
|
|
(10
|
)
|
|
(216
|
)
|
|||||
Selling, general and administrative expenses
|
(130
|
)
|
|
(65
|
)
|
|
(6
|
)
|
|
(7
|
)
|
|
(208
|
)
|
|||||
Operating income (loss)
|
111
|
|
|
(271
|
)
|
|
16
|
|
|
(17
|
)
|
|
(161
|
)
|
|||||
Other income
|
3
|
|
|
2
|
|
|
1
|
|
|
4
|
|
|
10
|
|
|||||
Interest expense and related charges
|
—
|
|
|
1
|
|
|
—
|
|
|
(61
|
)
|
|
(60
|
)
|
|||||
Impacts of Tax Receivable Agreement
|
—
|
|
|
—
|
|
|
—
|
|
|
(22
|
)
|
|
(22
|
)
|
|||||
Income (loss) before income taxes
|
114
|
|
|
$
|
(268
|
)
|
|
$
|
17
|
|
|
(96
|
)
|
|
(233
|
)
|
|||
Income tax benefit
|
—
|
|
|
—
|
|
|
—
|
|
|
70
|
|
|
70
|
|
|||||
Net income (loss)
|
$
|
114
|
|
|
$
|
(268
|
)
|
|
$
|
17
|
|
|
$
|
(26
|
)
|
|
$
|
(163
|
)
|
•
|
Retail segment net income of
$114 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 ERCOT segment.
|
•
|
ERCOT segment net loss of
$268 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 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.
|
|
Successor
|
||||||||||||||
|
Year Ended December 31,
|
|
Favorable (Unfavorable)
$ Change
|
|
Period from October 3, 2016
through December 31, 2016 |
||||||||||
|
2018
|
|
2017
|
|
|
||||||||||
Net income (loss)
|
$
|
(56
|
)
|
|
$
|
(254
|
)
|
|
$
|
198
|
|
|
$
|
(163
|
)
|
Income tax expense (benefit)
|
(45
|
)
|
|
504
|
|
|
(549
|
)
|
|
(70
|
)
|
||||
Interest expense and related charges
|
572
|
|
|
193
|
|
|
379
|
|
|
60
|
|
||||
Depreciation and amortization (a)
|
1,472
|
|
|
781
|
|
|
691
|
|
|
247
|
|
||||
EBITDA before Adjustments
|
1,943
|
|
|
1,224
|
|
|
719
|
|
|
74
|
|
||||
Unrealized net loss resulting from hedging transactions
|
380
|
|
|
146
|
|
|
234
|
|
|
165
|
|
||||
Generation plant retirement expenses
|
—
|
|
|
206
|
|
|
(206
|
)
|
|
—
|
|
||||
Fresh start/purchase accounting impacts
|
41
|
|
|
59
|
|
|
(18
|
)
|
|
35
|
|
||||
Impacts of Tax Receivable Agreement
|
79
|
|
|
(213
|
)
|
|
292
|
|
|
22
|
|
||||
Reorganization items and restructuring expenses
|
—
|
|
|
3
|
|
|
(3
|
)
|
|
18
|
|
||||
Non-cash compensation expenses
|
73
|
|
|
19
|
|
|
54
|
|
|
—
|
|
||||
Transition and merger expenses
|
233
|
|
|
27
|
|
|
206
|
|
|
—
|
|
||||
Severance
|
—
|
|
|
—
|
|
|
—
|
|
|
44
|
|
||||
Other, net
|
(7
|
)
|
|
(16
|
)
|
|
9
|
|
|
10
|
|
||||
Adjusted EBITDA, including Odessa earnout buybacks
|
$
|
2,742
|
|
|
$
|
1,455
|
|
|
$
|
1,287
|
|
|
$
|
368
|
|
Odessa earnout buybacks
|
18
|
|
|
—
|
|
|
18
|
|
|
|
|||||
Adjusted EBITDA
|
$
|
2,760
|
|
|
$
|
1,455
|
|
|
$
|
1,305
|
|
|
|
(a)
|
Includes nuclear fuel amortization in the ERCOT segment of
$78 million
,
$82 million
and $31 million for the Successor period for the years ended
December 31, 2018 and 2017
and the period from October 3, 2016 through December 31, 2016, respectively.
|
|
Successor
|
||||||||||||||||||||||||||||||
|
Year Ended December 31, 2018
|
||||||||||||||||||||||||||||||
|
Retail
|
|
ERCOT
|
|
PJM
|
|
NY/NE
|
|
MISO
|
|
Asset
Closure
|
|
Eliminations / Corporate and Other
|
|
Vistra
Energy Consolidated
|
||||||||||||||||
Net income (loss)
|
$
|
712
|
|
|
$
|
(55
|
)
|
|
$
|
100
|
|
|
$
|
79
|
|
|
$
|
35
|
|
|
$
|
(49
|
)
|
|
$
|
(878
|
)
|
|
$
|
(56
|
)
|
Income tax benefit
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(45
|
)
|
|
(45
|
)
|
||||||||
Interest expense and related charges
|
7
|
|
|
12
|
|
|
8
|
|
|
2
|
|
|
1
|
|
|
—
|
|
|
542
|
|
|
572
|
|
||||||||
Depreciation and amortization (a)
|
318
|
|
|
494
|
|
|
413
|
|
|
152
|
|
|
9
|
|
|
—
|
|
|
86
|
|
|
1,472
|
|
||||||||
EBITDA before Adjustments
|
1,037
|
|
|
451
|
|
|
521
|
|
|
233
|
|
|
45
|
|
|
(49
|
)
|
|
(295
|
)
|
|
1,943
|
|
||||||||
Unrealized net (gain) loss resulting from hedging transactions
|
(206
|
)
|
|
498
|
|
|
42
|
|
|
40
|
|
|
(9
|
)
|
|
—
|
|
|
15
|
|
|
380
|
|
||||||||
Fresh start/purchase accounting impacts
|
26
|
|
|
(6
|
)
|
|
(1
|
)
|
|
9
|
|
|
12
|
|
|
1
|
|
|
—
|
|
|
41
|
|
||||||||
Impacts of Tax Receivable Agreement
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
79
|
|
|
79
|
|
||||||||
Non-cash compensation expenses
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
73
|
|
|
73
|
|
||||||||
Transition and merger expenses
|
1
|
|
|
9
|
|
|
14
|
|
|
2
|
|
|
9
|
|
|
2
|
|
|
196
|
|
|
233
|
|
||||||||
Other, net
|
(13
|
)
|
|
(2
|
)
|
|
16
|
|
|
9
|
|
|
9
|
|
|
(3
|
)
|
|
(23
|
)
|
|
(7
|
)
|
||||||||
Adjusted EBITDA, including Odessa earnout buybacks
|
845
|
|
|
950
|
|
|
592
|
|
|
293
|
|
|
66
|
|
|
(49
|
)
|
|
$
|
45
|
|
|
2,742
|
|
|||||||
Odessa earnout buybacks
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
18
|
|
||||||||||||||
Adjusted EBITDA
|
$
|
845
|
|
|
$
|
968
|
|
|
$
|
592
|
|
|
$
|
293
|
|
|
$
|
66
|
|
|
$
|
(49
|
)
|
|
$
|
45
|
|
|
$
|
2,760
|
|
(a)
|
Includes nuclear fuel amortization of
$78 million
in ERCOT segment.
|
|
Successor
|
||||||||||||||||||
|
Year Ended December 31, 2017
|
||||||||||||||||||
|
Retail
|
|
ERCOT
|
|
Asset
Closure
|
|
Eliminations / Corporate and Other
|
|
Vistra
Energy Consolidated
|
||||||||||
Net income (loss)
|
$
|
495
|
|
|
$
|
(118
|
)
|
|
$
|
(63
|
)
|
|
$
|
(568
|
)
|
|
$
|
(254
|
)
|
Income tax expense
|
—
|
|
|
—
|
|
|
—
|
|
|
504
|
|
|
504
|
|
|||||
Interest expense and related charges
|
—
|
|
|
21
|
|
|
—
|
|
|
172
|
|
|
193
|
|
|||||
Depreciation and amortization (a)
|
430
|
|
|
311
|
|
|
1
|
|
|
39
|
|
|
781
|
|
|||||
EBITDA before Adjustments
|
925
|
|
|
214
|
|
|
(62
|
)
|
|
147
|
|
|
1,224
|
|
|||||
Unrealized net (gain) loss resulting from hedging transactions
|
(171
|
)
|
|
317
|
|
|
—
|
|
|
—
|
|
|
146
|
|
|||||
Generation plant retirement expenses
|
—
|
|
|
—
|
|
|
206
|
|
|
—
|
|
|
206
|
|
|||||
Fresh start accounting impacts
|
46
|
|
|
(1
|
)
|
|
14
|
|
|
—
|
|
|
59
|
|
|||||
Impacts of Tax Receivable Agreement
|
—
|
|
|
—
|
|
|
—
|
|
|
(213
|
)
|
|
(213
|
)
|
|||||
Reorganization items and restructuring expenses
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
3
|
|
|||||
Non-cash compensation expenses
|
—
|
|
|
—
|
|
|
—
|
|
|
19
|
|
|
19
|
|
|||||
Transition and merger expenses
|
1
|
|
|
8
|
|
|
—
|
|
|
18
|
|
|
27
|
|
|||||
Other, net
|
(22
|
)
|
|
—
|
|
|
—
|
|
|
6
|
|
|
(16
|
)
|
|||||
Adjusted EBITDA
|
$
|
779
|
|
|
$
|
538
|
|
|
$
|
158
|
|
|
$
|
(20
|
)
|
|
$
|
1,455
|
|
(a)
|
Includes nuclear fuel amortization of
$82 million
in ERCOT segment.
|
PJM, MISO and NY/NE segments acquired in the Merger
|
$
|
950
|
|
Increase in ERCOT segment driven by operations acquired in the Merger and Odessa, higher realized prices and the impact of the Comanche Peak outage in 2017 and related insurance proceeds in 2018
|
430
|
|
|
Increase in Retail segment driven by favorable volumes in ERCOT and Midwest/Northeast retail businesses acquired in the Merger
|
66
|
|
|
Decrease in Asset Closure segment driven by retirement of facilities in first quarter of 2018, partially offset by the change in estimates for certain AROs in 2018
|
(207
|
)
|
|
Corporate and Other due in part to operations acquired in the Merger
|
66
|
|
|
Total
|
$
|
1,305
|
|
|
Successor
|
||||||||||||||||||
|
Period from October 3, 2016 through December 31, 2016
|
||||||||||||||||||
|
Retail
|
|
ERCOT
|
|
Asset
Closure
|
|
Eliminations / Corporate and Other
|
|
Vistra
Energy Consolidated
|
||||||||||
Net income (loss)
|
$
|
114
|
|
|
$
|
(268
|
)
|
|
$
|
17
|
|
|
$
|
(26
|
)
|
|
$
|
(163
|
)
|
Income tax benefit
|
—
|
|
|
—
|
|
|
—
|
|
|
(70
|
)
|
|
(70
|
)
|
|||||
Interest expense and related charges
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
61
|
|
|
60
|
|
|||||
Depreciation and amortization (a)
|
153
|
|
|
84
|
|
|
—
|
|
|
10
|
|
|
247
|
|
|||||
EBITDA before Adjustments
|
267
|
|
|
(185
|
)
|
|
17
|
|
|
(25
|
)
|
|
74
|
|
|||||
Unrealized net (gain) loss resulting from hedging transactions
|
(107
|
)
|
|
272
|
|
|
—
|
|
|
—
|
|
|
165
|
|
|||||
Fresh start accounting impacts
|
36
|
|
|
(4
|
)
|
|
3
|
|
|
—
|
|
|
35
|
|
|||||
Impacts of Tax Receivable Agreement
|
—
|
|
|
—
|
|
|
—
|
|
|
22
|
|
|
22
|
|
|||||
Reorganization items and restructuring expenses
|
7
|
|
|
7
|
|
|
—
|
|
|
4
|
|
|
18
|
|
|||||
Severance
|
9
|
|
|
33
|
|
|
2
|
|
|
—
|
|
|
44
|
|
|||||
Other, net
|
1
|
|
|
9
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|||||
Adjusted EBITDA
|
$
|
213
|
|
|
$
|
132
|
|
|
$
|
22
|
|
|
$
|
1
|
|
|
$
|
368
|
|
(a)
|
Includes nuclear fuel amortization of $31 million in ERCOT segment.
|
|
Year Ended December 31,
|
|
Favorable (Unfavorable)
Change
|
||||||||
|
2018
|
|
2017
|
|
|||||||
Operating revenues:
|
|
|
|
|
|
||||||
Revenues in ERCOT
|
$
|
4,426
|
|
|
$
|
4,002
|
|
|
$
|
424
|
|
Revenues in Northeast/Midwest
|
1,123
|
|
|
—
|
|
|
1,123
|
|
|||
Amortization expense
|
(26
|
)
|
|
(46
|
)
|
|
20
|
|
|||
Other revenues
|
74
|
|
|
102
|
|
|
(28
|
)
|
|||
Total operating revenues
|
$
|
5,597
|
|
|
$
|
4,058
|
|
|
$
|
1,539
|
|
Fuel, purchased power costs and delivery fees:
|
|
|
|
|
|
||||||
Purchases from affiliates
|
(2,846
|
)
|
|
(1,539
|
)
|
|
(1,307
|
)
|
|||
Unrealized net gains on hedging activities with affiliates
|
218
|
|
|
154
|
|
|
64
|
|
|||
Delivery fees
|
(1,493
|
)
|
|
(1,345
|
)
|
|
(148
|
)
|
|||
Other costs
|
(5
|
)
|
|
(3
|
)
|
|
(2
|
)
|
|||
Total fuel, purchased power costs and delivery fees
|
$
|
(4,126
|
)
|
|
$
|
(2,733
|
)
|
|
$
|
(1,393
|
)
|
Net income
|
$
|
712
|
|
|
$
|
495
|
|
|
$
|
217
|
|
Adjusted EBITDA
|
$
|
845
|
|
|
$
|
779
|
|
|
$
|
66
|
|
Sales volumes (GWh):
|
|
|
|
|
|
||||||
Retail electricity sales volumes:
|
|
|
|
|
|
||||||
Sales volumes in ERCOT
|
42,992
|
|
|
39,032
|
|
|
3,960
|
|
|||
Sales volumes in Northeast/Midwest
|
20,739
|
|
|
—
|
|
|
20,739
|
|
|||
Total retail electricity sales volumes
|
63,731
|
|
|
39,032
|
|
|
24,699
|
|
|||
Weather (North Texas average) - percent of normal (a):
|
|
|
|
|
|
||||||
Cooling degree days
|
103.0
|
%
|
|
99.1
|
%
|
|
|
||||
Heating degree days
|
112.0
|
%
|
|
72.0
|
%
|
|
|
(a)
|
Weather data is obtained from Weatherbank, Inc. For the year ended December 31, 2018, normal is defined as the average over the 10-year period from 2008 to 2017. For the year ended December 31, 2017, normal is defined as the average over the 10-year period from 2007 to 2016.
|
Favorable volumes primarily due to weather in ERCOT
|
$
|
53
|
|
Margins in Midwest/Northeast acquired in the Merger
|
34
|
|
|
Unfavorable margins in ERCOT primarily due to higher power costs
|
(21
|
)
|
|
Change in Adjusted EBITDA
|
$
|
66
|
|
Lower depreciation and amortization expenses driven by reduced amortization of the retail customer relationship
|
132
|
|
|
Favorable impact of unrealized net gains on hedging activities
|
34
|
|
|
Higher other expenses
|
(15
|
)
|
|
Change in Net income
|
$
|
217
|
|
|
Year Ended December 31,
|
|
Favorable (Unfavorable)
Change
|
||||||||
|
2018
|
|
2017
|
|
|||||||
Operating revenues:
|
|
|
|
|
|
||||||
Wholesale electricity sales
|
$
|
1,289
|
|
|
$
|
523
|
|
|
$
|
766
|
|
Sales to affiliates
|
1,829
|
|
|
1,539
|
|
|
290
|
|
|||
Rolloff of unrealized net gains (losses) representing positions settled in the current period
|
404
|
|
|
(184
|
)
|
|
588
|
|
|||
Unrealized net gains (losses) from changes in fair value
|
(689
|
)
|
|
33
|
|
|
(722
|
)
|
|||
Unrealized net losses on hedging activities with affiliates
|
(198
|
)
|
|
(154
|
)
|
|
(44
|
)
|
|||
Other revenues
|
(1
|
)
|
|
37
|
|
|
(38
|
)
|
|||
Operating revenues
|
$
|
2,634
|
|
|
$
|
1,794
|
|
|
$
|
840
|
|
Fuel, purchased power costs and delivery fees:
|
|
|
|
|
|
||||||
Fuel for generation facilities and purchased power costs
|
(1,367
|
)
|
|
(881
|
)
|
|
(486
|
)
|
|||
Unrealized losses from hedging activities
|
(15
|
)
|
|
(12
|
)
|
|
(3
|
)
|
|||
Ancillary and other costs
|
(139
|
)
|
|
(88
|
)
|
|
(51
|
)
|
|||
Fuel, purchased power costs and delivery fees
|
$
|
(1,521
|
)
|
|
$
|
(981
|
)
|
|
$
|
(540
|
)
|
Net loss
|
$
|
(55
|
)
|
|
$
|
(118
|
)
|
|
$
|
63
|
|
Adjusted EBITDA
|
$
|
968
|
|
|
$
|
538
|
|
|
$
|
430
|
|
Production volumes (GWh):
|
|
|
|
|
|
||||||
Nuclear facilities
|
20,416
|
|
|
16,921
|
|
|
3,495
|
|
|||
Lignite and coal facilities
|
29,151
|
|
|
26,043
|
|
|
3,108
|
|
|||
Natural gas facilities
|
35,790
|
|
|
18,522
|
|
|
17,268
|
|
|||
Solar facilities
|
344
|
|
|
—
|
|
|
344
|
|
|||
Capacity factors:
|
|
|
|
|
|
||||||
Nuclear facilities
|
101.3
|
%
|
|
84.0
|
%
|
|
|
||||
Lignite and coal facilities
|
76.9
|
%
|
|
77.2
|
%
|
|
|
||||
CCGT facilities
|
58.8
|
%
|
|
52.3
|
%
|
|
|
||||
Market pricing:
|
|
|
|
|
|
||||||
Average ERCOT North power price ($/MWh)
|
$
|
29.96
|
|
|
$
|
23.26
|
|
|
$
|
6.70
|
|
Favorable margins driven by higher realized power prices and increased production from legacy gas and coal generation
|
$
|
180
|
|
Impact of operations acquired in the Merger
|
73
|
|
|
Impact related to Comanche Peak outage in 2017
|
74
|
|
|
Impact of full year of operations from Odessa acquired in 2017
|
86
|
|
|
Lower selling, general and administrative expenses
|
34
|
|
|
Insurance reimbursement for Comanche Peak
|
21
|
|
|
Other
|
(38
|
)
|
|
Change in Adjusted EBITDA
|
$
|
430
|
|
Increased depreciation and amortization driven by facilities acquired in the Merger
|
(183
|
)
|
|
Unfavorable impact of unrealized net losses on hedging activities
|
(182
|
)
|
|
Partial buybacks of the Odessa earn-out provision in 2018
|
(18
|
)
|
|
Other
|
(2
|
)
|
|
Change in Net loss
|
$
|
63
|
|
|
Year Ended December 31, 2018
|
||||||||||
|
PJM
|
|
NY/NE
|
|
MISO
|
||||||
Operating revenues:
|
|
|
|
|
|
||||||
Energy
|
$
|
775
|
|
|
$
|
582
|
|
|
$
|
370
|
|
Capacity
|
369
|
|
|
239
|
|
|
53
|
|
|||
Unrealized net gains (losses) on hedging activities
|
(17
|
)
|
|
(37
|
)
|
|
(13
|
)
|
|||
Sales to affiliates
|
628
|
|
|
44
|
|
|
302
|
|
|||
Unrealized net gains (losses) on hedging activities with affiliates
|
(33
|
)
|
|
(3
|
)
|
|
16
|
|
|||
Other revenues
|
3
|
|
|
(8
|
)
|
|
(8
|
)
|
|||
Operating revenues
|
$
|
1,725
|
|
|
$
|
817
|
|
|
$
|
720
|
|
Fuel, purchased power costs and delivery fees:
|
|
|
|
|
|
||||||
Fuel for generation facilities and purchased power costs
|
(916
|
)
|
|
(479
|
)
|
|
(449
|
)
|
|||
Fuel for generation facilities and purchased power costs from affiliates
|
(8
|
)
|
|
—
|
|
|
30
|
|
|||
Unrealized gains from hedging activities
|
8
|
|
|
—
|
|
|
6
|
|
|||
Other costs
|
(1
|
)
|
|
(6
|
)
|
|
(7
|
)
|
|||
Fuel, purchased power costs and delivery fees
|
$
|
(917
|
)
|
|
$
|
(485
|
)
|
|
$
|
(420
|
)
|
Net income
|
$
|
100
|
|
|
$
|
79
|
|
|
$
|
35
|
|
Adjusted EBITDA
|
$
|
592
|
|
|
$
|
293
|
|
|
$
|
66
|
|
Production volumes (GWh)
|
40,533
|
|
|
14,605
|
|
|
21,324
|
|
|||
Capacity factors:
|
|
|
|
|
|
||||||
CCGT facilities
|
67.8
|
%
|
|
48.2
|
%
|
|
—
|
%
|
|||
Coal facilities
|
63.2
|
%
|
|
—
|
%
|
|
63.3
|
%
|
|||
Weather - percent of normal (a):
|
|
|
|
|
|
||||||
Cooling degree days
|
121.0
|
%
|
|
118.0
|
%
|
|
134.0
|
%
|
|||
Heating degree days
|
101.0
|
%
|
|
102.0
|
%
|
|
95.0
|
%
|
|||
Average Market On-Peak Power Prices ($/MWh) (b):
|
|
|
|
|
|
||||||
PJM West
|
$
|
41.79
|
|
|
|
|
|
||||
AD Hub
|
$
|
40.47
|
|
|
|
|
|
||||
New York - Zone C
|
|
|
$
|
37.03
|
|
|
|
||||
Mass Hub
|
|
|
$
|
50.11
|
|
|
|
||||
Average natural gas price - TetcoM3 ($/MMBtu) (c)
|
$
|
3.69
|
|
|
|
|
|
||||
Average natural gas price - Algonquin Citygates ($/MMBtu) (c)
|
|
|
$
|
4.84
|
|
|
|
|
PJM
|
|
NY/NE
|
|
MISO
|
||||||
Generation revenue net of fuel
|
$
|
481
|
|
|
$
|
116
|
|
|
$
|
229
|
|
Capacity revenue
|
369
|
|
|
260
|
|
|
61
|
|
|||
Operating costs
|
(243
|
)
|
|
(74
|
)
|
|
(202
|
)
|
|||
Selling, general and administrative expenses
|
(52
|
)
|
|
(37
|
)
|
|
(52
|
)
|
|||
Equity income from unconsolidated investment and other
|
7
|
|
|
11
|
|
|
—
|
|
|||
Other
|
30
|
|
|
17
|
|
|
30
|
|
|||
Adjusted EBITDA
|
$
|
592
|
|
|
$
|
293
|
|
|
$
|
66
|
|
Depreciation and amortization
|
(413
|
)
|
|
(152
|
)
|
|
(9
|
)
|
|||
Unrealized net gains (losses) on hedging activities
|
(42
|
)
|
|
(40
|
)
|
|
9
|
|
|||
Purchase accounting impacts
|
1
|
|
|
(9
|
)
|
|
(12
|
)
|
|||
Transition and merger expenses
|
(14
|
)
|
|
(2
|
)
|
|
(9
|
)
|
|||
Other
|
(24
|
)
|
|
(11
|
)
|
|
(10
|
)
|
|||
Net income
|
$
|
100
|
|
|
$
|
79
|
|
|
$
|
35
|
|
|
Year Ended December 31,
|
|
Favorable (Unfavorable)
Change
|
||||||||
|
2018
|
|
2017
|
|
|||||||
Operating revenues
|
$
|
50
|
|
|
$
|
964
|
|
|
$
|
(914
|
)
|
Fuel, purchased power costs and delivery fees
|
(40
|
)
|
|
(607
|
)
|
|
567
|
|
|||
Operating costs
|
(43
|
)
|
|
(380
|
)
|
|
337
|
|
|||
Depreciation and amortization
|
—
|
|
|
(1
|
)
|
|
1
|
|
|||
Selling, general and administrative expenses
|
(17
|
)
|
|
(19
|
)
|
|
2
|
|
|||
Impairment of long-lived assets
|
—
|
|
|
(25
|
)
|
|
25
|
|
|||
Operating income (loss)
|
(50
|
)
|
|
(68
|
)
|
|
18
|
|
|||
Other income
|
2
|
|
|
6
|
|
|
(4
|
)
|
|||
Other deductions
|
(1
|
)
|
|
(1
|
)
|
|
—
|
|
|||
Income (loss) before income taxes
|
(49
|
)
|
|
(63
|
)
|
|
14
|
|
|||
Income tax expense
|
—
|
|
|
—
|
|
|
—
|
|
|||
Net income (loss)
|
$
|
(49
|
)
|
|
$
|
(63
|
)
|
|
$
|
14
|
|
Depreciation and amortization
|
—
|
|
|
1
|
|
|
(1
|
)
|
|||
EBITDA
|
(49
|
)
|
|
(62
|
)
|
|
13
|
|
|||
Generation plant retirement expenses
|
—
|
|
|
206
|
|
|
(206
|
)
|
|||
Fresh start accounting impacts
|
1
|
|
|
14
|
|
|
(13
|
)
|
|||
Transition and merger expenses
|
2
|
|
|
—
|
|
|
2
|
|
|||
Other
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
|||
Adjusted EBITDA
|
$
|
(49
|
)
|
|
$
|
158
|
|
|
$
|
(207
|
)
|
Production volumes (GWh)
|
1,159
|
|
|
25,392
|
|
|
(24,233
|
)
|
|
Predecessor
|
||
|
Period from January 1, 2016
through October 2, 2016 |
||
Operating revenues
|
$
|
3,973
|
|
Fuel, purchased power costs and delivery fees
|
(2,082
|
)
|
|
Net gain from commodity hedging and trading activities
|
282
|
|
|
Operating costs
|
(664
|
)
|
|
Depreciation and amortization
|
(459
|
)
|
|
Selling, general and administrative expenses
|
(482
|
)
|
|
Operating income (loss)
|
568
|
|
|
Other income
|
19
|
|
|
Other deductions
|
(75
|
)
|
|
Interest expense and related charges
|
(1,049
|
)
|
|
Reorganization items
|
22,121
|
|
|
Income (loss) before income taxes
|
21,584
|
|
|
Income tax benefit
|
1,267
|
|
|
Net income (loss)
|
$
|
22,851
|
|
|
Predecessor
|
||
|
Period from January 1, 2016
through October 2, 2016 |
||
Operating revenues:
|
|
||
Retail electricity revenues
|
$
|
3,154
|
|
Wholesale electricity revenues and other operating revenues (a)(b)
|
819
|
|
|
Total operating revenues
|
$
|
3,973
|
|
Fuel, purchased power costs and delivery fees:
|
|
||
Fuel for generation facilities and purchased power costs (a)
|
$
|
950
|
|
Other costs
|
108
|
|
|
Delivery fees
|
1,024
|
|
|
Total
|
$
|
2,082
|
|
Sales volumes (GWh):
|
|
||
Retail electricity sales volumes
|
30,973
|
|
|
Wholesale electricity sales volumes (b)
|
25,563
|
|
|
Production volumes (GWh):
|
|
||
Nuclear facilities
|
15,005
|
|
|
Lignite and coal facilities (c)
|
31,865
|
|
|
Natural gas facilities
|
8,539
|
|
|
Capacity factors:
|
|
||
Nuclear facilities
|
99.2
|
%
|
|
Lignite and coal facilities (c)
|
60.5
|
%
|
|
CCGT facilities
|
65.2
|
%
|
|
Market pricing:
|
|
||
Average ERCOT North power price ($/MWh)
|
$
|
20.78
|
|
Weather (North Texas average) - percent of normal (d):
|
|
||
Cooling degree days
|
102.8
|
%
|
|
Heating degree days
|
81.9
|
%
|
(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 for the period from January 1, 2016 through October 2, 2016.
|
(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.
|
|
Predecessor
|
||
|
Period from January 1, 2016
through October 2, 2016 |
||
Realized net gains
|
$
|
320
|
|
Unrealized net gains (losses)
|
(38
|
)
|
|
Total
|
$
|
282
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended
December 31, 2018 |
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
||||||||
Commodity contract net asset (liability) at beginning of period
|
$
|
(96
|
)
|
|
$
|
64
|
|
|
$
|
181
|
|
|
|
$
|
271
|
|
Settlements/termination of positions (a)
|
457
|
|
|
(207
|
)
|
|
(95
|
)
|
|
|
(232
|
)
|
||||
Changes in fair value of positions in the portfolio (b)
|
(837
|
)
|
|
62
|
|
|
(71
|
)
|
|
|
194
|
|
||||
Acquired commodity contracts in Merger (c)
|
(454
|
)
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Other activity (d)
|
80
|
|
|
(15
|
)
|
|
49
|
|
|
|
(35
|
)
|
||||
Commodity contract net asset (liability) at end of period
|
$
|
(850
|
)
|
|
$
|
(96
|
)
|
|
$
|
64
|
|
|
|
$
|
198
|
|
(a)
|
Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). The years ended December 31, 2018 and 2017 include reversals of $17 million and $63 million, respectively of previously recorded unrealized gains related to Vistra Energy beginning balances. The year ended December 31, 2018 also includes reversal of $320 million of previously recorded unrealized losses related to commodity contracts acquired in the Merger. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.
|
(b)
|
Represents unrealized net gains (losses) recognized, reflecting the effect of changes in fair value. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.
|
(c)
|
Includes fair value of commodity contracts acquired at the Merger Date (see Note 2 to the Financial Statements).
|
(d)
|
Represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses. Amounts are generally related to premiums related to options purchased or sold as well as certain margin deposits classified as settlement for certain transactions executed on the CME.
|
|
|
Successor
|
||||||||||||||||||
|
|
Maturity dates of unrealized commodity contract net liability at December 31, 2018
|
||||||||||||||||||
Source of fair value
|
|
Less than
1 year
|
|
1-3 years
|
|
4-5 years
|
|
Excess of
5 years
|
|
Total
|
||||||||||
Prices actively quoted
|
|
$
|
(106
|
)
|
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(101
|
)
|
Prices provided by other external sources
|
|
(507
|
)
|
|
(107
|
)
|
|
—
|
|
|
—
|
|
|
(614
|
)
|
|||||
Prices based on models
|
|
(59
|
)
|
|
(64
|
)
|
|
(12
|
)
|
|
—
|
|
|
(135
|
)
|
|||||
Total
|
|
$
|
(672
|
)
|
|
$
|
(166
|
)
|
|
$
|
(12
|
)
|
|
$
|
—
|
|
|
$
|
(850
|
)
|
•
|
cash tender offers to purchase $1.542 billion of senior notes assumed in the Merger;
|
•
|
the amendment to the Vistra Operations Credit Facilities, including the repayment of $500 million in borrowings under the Term C Facility;
|
•
|
the redemption of $850 million principal amount of outstanding 6.75% Senior Notes in May 2018;
|
•
|
the repurchases of $119 million principal amount of outstanding Vistra Energy senior notes in November and December 2018;
|
•
|
premium amounts paid in connection with the debt tender offer and other debt financing fees totaling $236 million, and
|
•
|
$763 million
of cash paid for share repurchases during 2018,
|
•
|
the issuance of $1.0 billion principal amount of Vistra Operations 5.500% senior notes due 2026, and
|
•
|
proceeds of $339 million from the accounts receivable securitization program.
|
•
|
$208 million primarily for our generation and mining operations;
|
•
|
$118 million
for nuclear fuel purchases;
|
•
|
$70 million for information technology, other corporate investments and Comanche Peak repairs, and
|
•
|
$100 million for LTSA prepayments.
|
•
|
$88 million primarily for our generation and mining operations;
|
•
|
$62 million for nuclear fuel purchases, and
|
•
|
$26 million for information technology and other corporate investments.
|
•
|
$40 million primarily for our generation and mining operations;
|
•
|
$41 million for nuclear fuel purchases, and
|
•
|
$8 million for information technology and other corporate investments.
|
•
|
$211 million primarily for our generation and mining operations;
|
•
|
$33 million for nuclear fuel purchases, and
|
•
|
$19 million for information technology and other corporate investments.
|
|
December 31, 2018
|
|
December 31, 2017
|
|
Change
|
||||||
Cash and cash equivalents (a)
|
$
|
636
|
|
|
$
|
1,487
|
|
|
$
|
(851
|
)
|
Vistra Operations Credit Facilities — Revolving Credit Facility
|
1,135
|
|
|
834
|
|
|
301
|
|
|||
Vistra Operations Credit Facilities — Term Loan C Facility (b)
|
—
|
|
|
7
|
|
|
(7
|
)
|
|||
Total available liquidity
|
$
|
1,771
|
|
|
$
|
2,328
|
|
|
$
|
(557
|
)
|
(a)
|
Cash and cash equivalents excludes $500 million of restricted cash held for letter of credit support at December 31, 2017 (see Note
23
to the Financial Statements).
|
(b)
|
The Term Loan C Facility was used for issuing letters of credit for general corporate purposes. Borrowings totaling $500 million were held in collateral accounts at December 31, 2017, and were reported as restricted cash in our consolidated balance sheets. In June 2018, the Vistra Operations Credit Facilities were amended, and the Term Loan C Facility was repaid using $500 million of cash from the collateral accounts used to backstop letters of credit.
|
•
|
$432 million for investments in generation and mining facilities;
|
•
|
$74 million for nuclear fuel purchases;
|
•
|
$80 million for information technology and other corporate investments, and
|
•
|
$43 million for growth and development.
|
•
|
$361 million
in cash has been posted with counterparties as compared to $30 million posted at
December 31, 2017
;
|
•
|
$4 million
in cash has been received from counterparties as compared to $4 million received at
December 31, 2017
;
|
•
|
$1.185 billion
in letters of credit have been posted with counterparties as compared to $390 million posted at
December 31, 2017
, and
|
•
|
$12 million in letters of credit have been received from counterparties as compared to $3 million received at
December 31, 2017
.
|
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)
|
$
|
191
|
|
|
$
|
334
|
|
|
$
|
5,932
|
|
|
$
|
4,453
|
|
|
$
|
10,910
|
|
Debt – interest
|
611
|
|
|
1,207
|
|
|
990
|
|
|
474
|
|
|
3,282
|
|
|||||
Operating leases
|
35
|
|
|
54
|
|
|
39
|
|
|
168
|
|
|
296
|
|
|||||
Long-term service and maintenance contracts
|
175
|
|
|
316
|
|
|
316
|
|
|
2,619
|
|
|
3,426
|
|
|||||
Obligations under commodity purchase and services agreements (b)
|
1,589
|
|
|
912
|
|
|
460
|
|
|
709
|
|
|
3,670
|
|
|||||
Total contractual cash obligations
|
$
|
2,601
|
|
|
$
|
2,823
|
|
|
$
|
7,737
|
|
|
$
|
8,423
|
|
|
$
|
21,584
|
|
(a)
|
Includes
$5.813 billion
of borrowings under the Vistra Operations Credit Facility,
$3.626 billion
principal amount of Vistra Energy senior notes,
$1.0 billion
principal amount of Vistra Operations senior notes and
$471 million
principal amount of long-term debt, including forward capacity agreements, equipment financing agreements and mandatorily redeemable preferred stock. Excludes unamortized premiums, discounts and debt costs.
|
(b)
|
Includes capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear related outsourcing and other purchase commitments. Amounts presented for variable priced contracts reflect the year-end 2018 price for all periods except where contractual price adjustment or index-based prices are specified.
|
•
|
the TRA obligation (see Note
10
to the Financial Statements);
|
•
|
asset retirement obligations (see Note
23
to the Financial Statements);
|
•
|
arrangements between affiliated entities and intercompany debt (see Note
21
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,
|
||||||
|
2018
|
|
2017
|
||||
Month-end average VaR
|
$
|
182
|
|
|
$
|
92
|
|
Month-end high VaR
|
$
|
267
|
|
|
$
|
140
|
|
Month-end low VaR
|
$
|
65
|
|
|
$
|
62
|
|
|
Expected Maturity Date
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||
|
(millions of dollars, except percentages)
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
There-after
|
|
2018
Total Carrying
Amount
|
|
2018
Total Fair
Value
|
|
2017
Total Carrying
Amount
|
|
2017
Total Fair
Value
|
||||||||||||||||||||
Long-term debt, including current maturities (a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Variable rate debt amount
|
$
|
59
|
|
|
$
|
59
|
|
|
$
|
59
|
|
|
$
|
59
|
|
|
$
|
3,640
|
|
|
$
|
1,937
|
|
|
$
|
5,813
|
|
|
$
|
5,599
|
|
|
$
|
4,311
|
|
|
$
|
4,334
|
|
Average interest rate (b)
|
4.55
|
%
|
|
4.55
|
%
|
|
4.55
|
%
|
|
4.55
|
%
|
|
4.59
|
%
|
|
4.47
|
%
|
|
4.55
|
%
|
|
|
|
3.98
|
%
|
|
|
||||||||||||
Debt swapped to fixed (c):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Notional amount
|
$
|
159
|
|
|
$
|
358
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,000
|
|
|
$
|
4,200
|
|
|
$
|
7,717
|
|
|
|
|
$
|
3,000
|
|
|
|
||||
Average pay rate
|
4.16
|
%
|
|
4.10
|
%
|
|
4.07
|
%
|
|
4.07
|
%
|
|
4.34
|
%
|
|
5.01
|
%
|
|
4.38
|
%
|
|
|
|
4.59
|
%
|
|
|
||||||||||||
Average receive rate
|
4.56
|
%
|
|
4.57
|
%
|
|
4.57
|
%
|
|
4.57
|
%
|
|
4.53
|
%
|
|
4.45
|
%
|
|
4.53
|
%
|
|
|
|
4.11
|
%
|
|
|
(a)
|
Unamortized premiums, discounts and debt issuance costs are excluded from the table.
|
(b)
|
The weighted average interest rate presented is based on the rates in effect at
December 31, 2018
.
|
(c)
|
Interest rate swaps have maturity dates through July 2026.
|
|
Exposure
Before Credit
Collateral
|
|
Credit
Collateral
|
|
Net
Exposure
|
||||||
Investment grade
|
$
|
247
|
|
|
$
|
—
|
|
|
$
|
247
|
|
Below investment grade or no rating
|
45
|
|
|
11
|
|
|
34
|
|
|||
Totals
|
$
|
292
|
|
|
$
|
11
|
|
|
$
|
281
|
|
•
|
the actions and decisions of judicial and regulatory authorities;
|
•
|
prohibitions and other restrictions on our operations due to the terms of our agreements;
|
•
|
prevailing federal, state and local governmental policies and regulatory actions, including those of the legislatures and other government actions of states in which we operate, the U.S. Congress, the FERC, the NERC, the TRE, the public utility commissions of states and locales in which we operate, CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM, the RCT, the NRC, the EPA, the environmental regulatory bodies of states in which we operate, the 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 federal, state and local tax laws, rates and policies, including additional regulation, interpretations, amendments, or technical corrections to the TCJA;
|
◦
|
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;
|
•
|
expectations regarding, or impacts of, environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts, and other laws and regulations that we are, or could become, subject to, which could increase our costs, result in an impairment of our assets, cause us to limit or terminate the operation of certain of our facilities, or otherwise have a negative financial effect;
|
•
|
legal and administrative proceedings and settlements;
|
•
|
general industry trends;
|
•
|
economic conditions, including the impact of an economic downturn;
|
•
|
weather conditions, including drought and limitations on access to water, and other natural phenomena, and acts of sabotage, wars or terrorist or cybersecurity threats or activities;
|
•
|
our ability to collect trade receivables from counterparties;
|
•
|
our ability to attract and retain profitable customers;
|
•
|
our ability to profitably serve our customers;
|
•
|
restrictions on competitive retail pricing;
|
•
|
changes in wholesale electricity prices or energy commodity prices, including the price of natural gas;
|
•
|
changes in prices of transportation of natural gas, coal, fuel oil and other refined products;
|
•
|
sufficiency of, access to, and costs associated with coal, fuel oil, and natural gas inventories and transportation and storage thereof;
|
•
|
changes in the ability of vendors to provide or deliver commodities as needed;
|
•
|
beliefs and assumptions about the benefits of state- or federal-based subsidies to our market competition, and the corresponding impacts on us, including if such subsidies are disproportionately available to our competitors;
|
•
|
the effects of, or changes to, market design and the power and capacity procurement processes in the markets in which we operate;
|
•
|
changes in market heat rates in the CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM electricity markets;
|
•
|
our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heat rates and interest rates;
|
•
|
population growth or decline, or changes in market supply or demand and demographic patterns, particularly in ERCOT, MISO and PJM;
|
•
|
our ability to mitigate forced outage risk, including managing risk associated with CP in PJM and performance incentives in ISO-NE;
|
•
|
efforts to identify opportunities to reduce congestion and improve busbar power prices;
|
•
|
access to adequate transmission facilities to meet changing demands;
|
•
|
changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;
|
•
|
changes in operating expenses, liquidity needs and capital expenditures;
|
•
|
commercial bank market and capital market conditions and the potential impact of disruptions in U.S. and international credit markets;
|
•
|
access to capital, the attractiveness of the cost and other terms of such capital and the success of financing and refinancing efforts, including availability of funds in capital markets;
|
•
|
our ability to maintain prudent financial leverage;
|
•
|
our ability to generate sufficient cash flow to make principal and interest payments in respect of, or refinance, our debt obligations;
|
•
|
our ability to implement our growth strategy, including the completion and integration of mergers, acquisitions and/or joint venture activity and identification and completion of sales and divestitures activity;
|
•
|
competition for new energy development and other business opportunities;
|
•
|
inability of various counterparties to meet their obligations with respect to our financial instruments;
|
•
|
counterparties' collateral demands and other factors affecting our liquidity position and financial condition;
|
•
|
changes in technology (including large scale electricity storage) used by and services offered by us;
|
•
|
changes in electricity transmission that allow additional power generation to compete with our generation assets;
|
•
|
our ability to attract and retain qualified employees;
|
•
|
significant changes in our relationship with our employees, including the availability of qualified personnel, and the potential adverse effects if labor disputes or grievances were to occur;
|
•
|
changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits, pension and 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;
|
•
|
our ability to optimize our assets through targeted investment in cost-effective technology enhancements and operations performance initiatives;
|
•
|
our ability to effectively and efficiently plan, prepare for and execute expected asset retirements and reclamation obligations and the impacts thereof;
|
•
|
our ability to successfully complete the integration of the businesses of Vistra Energy and Dynegy and our ability to successfully capture the full amount of 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,
|
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
||||||||||
|
2018
|
|
2017
|
|
|
|
||||||||||
Operating revenues
|
$
|
9,144
|
|
|
$
|
5,430
|
|
|
$
|
1,191
|
|
|
|
$
|
3,973
|
|
Fuel, purchased power costs and delivery fees
|
(5,036
|
)
|
|
(2,935
|
)
|
|
(720
|
)
|
|
|
(2,082
|
)
|
||||
Net gain from commodity hedging and trading activities
|
—
|
|
|
—
|
|
|
—
|
|
|
|
282
|
|
||||
Operating costs
|
(1,297
|
)
|
|
(973
|
)
|
|
(208
|
)
|
|
|
(664
|
)
|
||||
Depreciation and amortization
|
(1,394
|
)
|
|
(699
|
)
|
|
(216
|
)
|
|
|
(459
|
)
|
||||
Selling, general and administrative expenses
|
(926
|
)
|
|
(600
|
)
|
|
(208
|
)
|
|
|
(482
|
)
|
||||
Impairment of long-lived assets
|
—
|
|
|
(25
|
)
|
|
—
|
|
|
|
—
|
|
||||
Operating income (loss)
|
491
|
|
|
198
|
|
|
(161
|
)
|
|
|
568
|
|
||||
Other income (Note 23)
|
47
|
|
|
37
|
|
|
10
|
|
|
|
19
|
|
||||
Other deductions (Note 23)
|
(5
|
)
|
|
(5
|
)
|
|
—
|
|
|
|
(75
|
)
|
||||
Interest expense and related charges (Note 11)
|
(572
|
)
|
|
(193
|
)
|
|
(60
|
)
|
|
|
(1,049
|
)
|
||||
Impacts of Tax Receivable Agreement (Note 10)
|
(79
|
)
|
|
213
|
|
|
(22
|
)
|
|
|
—
|
|
||||
Equity in earnings of unconsolidated investment (Note 23)
|
17
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Reorganization items (Note 5)
|
—
|
|
|
—
|
|
|
—
|
|
|
|
22,121
|
|
||||
Income (loss) before income taxes
|
(101
|
)
|
|
250
|
|
|
(233
|
)
|
|
|
21,584
|
|
||||
Income tax (expense) benefit (Note 9)
|
45
|
|
|
(504
|
)
|
|
70
|
|
|
|
1,267
|
|
||||
Net income (loss)
|
(56
|
)
|
|
(254
|
)
|
|
(163
|
)
|
|
|
22,851
|
|
||||
Less: Net loss attributable to noncontrolling interest
|
2
|
|
|
—
|
|
|
—
|
|
|
|
|
|
||||
Net loss attributable to Vistra Energy
|
$
|
(54
|
)
|
|
$
|
(254
|
)
|
|
$
|
(163
|
)
|
|
|
|
|
|
Weighted average shares of common stock outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Basic
|
504,954,371
|
|
|
427,761,460
|
|
|
427,560,620
|
|
|
|
|
|
||||
Diluted
|
504,954,371
|
|
|
427,761,460
|
|
|
427,560,620
|
|
|
|
|
|
||||
Net loss per weighted average share of common stock outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Basic
|
$
|
(0.11
|
)
|
|
$
|
(0.59
|
)
|
|
$
|
(0.38
|
)
|
|
|
|
|
|
Diluted
|
$
|
(0.11
|
)
|
|
$
|
(0.59
|
)
|
|
$
|
(0.38
|
)
|
|
|
|
|
|
Dividend declared per share of common stock
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2.32
|
|
|
|
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended December 31,
|
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
||||||||||
|
2018
|
|
2017
|
|
|
|
||||||||||
Net income (loss)
|
$
|
(56
|
)
|
|
$
|
(254
|
)
|
|
$
|
(163
|
)
|
|
|
$
|
22,851
|
|
Other comprehensive income (loss), net of tax effects:
|
|
|
|
|
|
|
|
|
||||||||
Effects related to pension and other retirement benefit obligations (net of tax (benefit) expense of $(2), $(6), $3 and $—)
|
(6
|
)
|
|
(23
|
)
|
|
6
|
|
|
|
—
|
|
||||
Adoption of new accounting standard (Note 1)
|
1
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Other comprehensive income, net of tax effects — cash flow hedges (net of tax benefit of $— in all periods)
|
—
|
|
|
—
|
|
|
—
|
|
|
|
1
|
|
||||
Total other comprehensive income (loss)
|
(5
|
)
|
|
(23
|
)
|
|
6
|
|
|
|
1
|
|
||||
Comprehensive income (loss)
|
(61
|
)
|
|
(277
|
)
|
|
(157
|
)
|
|
|
22,852
|
|
||||
Less: Comprehensive loss attributable to noncontrolling interest
|
2
|
|
|
—
|
|
|
—
|
|
|
|
|
|||||
Comprehensive loss attributable to Vistra Energy
|
$
|
(59
|
)
|
|
$
|
(277
|
)
|
|
$
|
(157
|
)
|
|
|
|
VISTRA ENERGY CORP.
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
|
||||||||||||||||
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended December 31,
|
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
||||||||||
|
2018
|
|
2017
|
|
|
|
||||||||||
Cash flows — operating activities:
|
|
|
|
|
|
|
|
|
||||||||
Net income (loss)
|
$
|
(56
|
)
|
|
$
|
(254
|
)
|
|
$
|
(163
|
)
|
|
|
$
|
22,851
|
|
Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities:
|
|
|
|
|
|
|
|
|
||||||||
Depreciation and amortization
|
1,533
|
|
|
835
|
|
|
285
|
|
|
|
532
|
|
||||
Deferred income tax expense (benefit), net
|
(62
|
)
|
|
418
|
|
|
(76
|
)
|
|
|
(1,270
|
)
|
||||
Unrealized net (gain) loss from mark-to-market valuations of commodities
|
380
|
|
|
145
|
|
|
165
|
|
|
|
36
|
|
||||
Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps
|
5
|
|
|
(29
|
)
|
|
11
|
|
|
|
—
|
|
||||
Gain on extinguishment of liabilities subject to compromise (Note 6)
|
—
|
|
|
—
|
|
|
—
|
|
|
|
(24,344
|
)
|
||||
Net loss from adopting fresh start reporting (Note 5)
|
—
|
|
|
—
|
|
|
—
|
|
|
|
2,013
|
|
||||
Contract claims adjustments of Predecessor (Note 5)
|
—
|
|
|
—
|
|
|
—
|
|
|
|
13
|
|
||||
Impairment of long-lived assets (Note 4)
|
—
|
|
|
25
|
|
|
—
|
|
|
|
—
|
|
||||
Write-off of intangible and other assets (Note 23)
|
—
|
|
|
—
|
|
|
—
|
|
|
|
45
|
|
||||
Impacts of Tax Receivable Agreement (Note 10)
|
79
|
|
|
(213
|
)
|
|
22
|
|
|
|
—
|
|
||||
Change in asset retirement obligation liability
|
(27
|
)
|
|
112
|
|
|
—
|
|
|
|
—
|
|
||||
Asset retirement obligation accretion expense
|
50
|
|
|
60
|
|
|
6
|
|
|
|
—
|
|
||||
Stock-based compensation
|
73
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Other, net
|
92
|
|
|
69
|
|
|
1
|
|
|
|
63
|
|
||||
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
||||||||
Affiliate accounts receivable/payable — net
|
—
|
|
|
—
|
|
|
—
|
|
|
|
31
|
|
||||
Accounts receivable — trade
|
(207
|
)
|
|
7
|
|
|
135
|
|
|
|
(216
|
)
|
||||
Inventories
|
61
|
|
|
22
|
|
|
3
|
|
|
|
71
|
|
||||
Accounts payable — trade
|
90
|
|
|
(30
|
)
|
|
(79
|
)
|
|
|
26
|
|
||||
Commodity and other derivative contractual assets and liabilities
|
(80
|
)
|
|
(1
|
)
|
|
(48
|
)
|
|
|
29
|
|
||||
Margin deposits, net
|
(221
|
)
|
|
146
|
|
|
(193
|
)
|
|
|
(124
|
)
|
||||
Accrued interest
|
(105
|
)
|
|
(10
|
)
|
|
32
|
|
|
|
(10
|
)
|
||||
Accrued taxes
|
(64
|
)
|
|
33
|
|
|
12
|
|
|
|
(13
|
)
|
||||
Accrued employee incentive
|
40
|
|
|
(24
|
)
|
|
24
|
|
|
|
(30
|
)
|
||||
Alcoa contract settlement (Note 4)
|
—
|
|
|
238
|
|
|
—
|
|
|
|
—
|
|
||||
Tax Receivable Agreement payment (Note 10)
|
(16
|
)
|
|
(26
|
)
|
|
—
|
|
|
|
—
|
|
||||
Major plant outage deferral
|
(22
|
)
|
|
(66
|
)
|
|
—
|
|
|
|
—
|
|
||||
Other — net assets
|
73
|
|
|
4
|
|
|
(2
|
)
|
|
|
(3
|
)
|
||||
Other — net liabilities
|
(145
|
)
|
|
(75
|
)
|
|
(54
|
)
|
|
|
62
|
|
||||
Cash provided by (used in) operating activities
|
1,471
|
|
|
1,386
|
|
|
81
|
|
|
|
(238
|
)
|
||||
Cash flows — financing activities:
|
|
|
|
|
|
|
|
|
||||||||
Issuances of long-term debt (Note 14)
|
1,000
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Repayments/repurchases of debt (Note 14)
|
(3,075
|
)
|
|
(191
|
)
|
|
—
|
|
|
|
(2,655
|
)
|
||||
Net borrowings under accounts receivable securitization program (Note 13)
|
339
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Debt tender offer and other debt financing fee
|
(236
|
)
|
|
(8
|
)
|
|
—
|
|
|
|
—
|
|
||||
Stock repurchase (Note 16)
|
(763
|
)
|
|
—
|
|
|
—
|
|
|
|
—
|
|
VISTRA ENERGY CORP.
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
|
||||||||||||||||
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended December 31,
|
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
||||||||||
|
2018
|
|
2017
|
|
|
|
||||||||||
Incremental Term Loan B Facility (Note 14)
|
—
|
|
|
—
|
|
|
1,000
|
|
|
|
—
|
|
||||
Special Dividend (Note 16)
|
—
|
|
|
—
|
|
|
(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 14)
|
—
|
|
|
—
|
|
|
—
|
|
|
|
4,680
|
|
||||
TCEH DIP Roll Facilities and DIP Facility financing fees
|
—
|
|
|
—
|
|
|
—
|
|
|
|
(112
|
)
|
||||
Other, net
|
12
|
|
|
(2
|
)
|
|
(2
|
)
|
|
|
(8
|
)
|
||||
Cash provided by (used in) financing activities
|
(2,723
|
)
|
|
(201
|
)
|
|
6
|
|
|
|
1,059
|
|
||||
Cash flows — investing activities:
|
|
|
|
|
|
|
|
|
||||||||
Capital expenditures, including LTSA prepayments
|
(378
|
)
|
|
(114
|
)
|
|
(48
|
)
|
|
|
(230
|
)
|
||||
Nuclear fuel purchases
|
(118
|
)
|
|
(62
|
)
|
|
(41
|
)
|
|
|
(33
|
)
|
||||
Development and growth expenditures (Note 3)
|
(34
|
)
|
|
(190
|
)
|
|
—
|
|
|
|
—
|
|
||||
Cash acquired in the Merger
|
445
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Odessa acquisition (Note 3)
|
—
|
|
|
(355
|
)
|
|
—
|
|
|
|
—
|
|
||||
Lamar and Forney acquisition — net of cash acquired (Note 3)
|
—
|
|
|
—
|
|
|
—
|
|
|
|
(1,343
|
)
|
||||
Changes in restricted cash (Predecessor)
|
—
|
|
|
—
|
|
|
—
|
|
|
|
233
|
|
||||
Proceeds from sales of nuclear decommissioning trust fund securities (Note 23)
|
252
|
|
|
252
|
|
|
25
|
|
|
|
201
|
|
||||
Investments in nuclear decommissioning trust fund securities (Note 23)
|
(274
|
)
|
|
(272
|
)
|
|
(30
|
)
|
|
|
(215
|
)
|
||||
Notes/advances due from affiliates
|
—
|
|
|
—
|
|
|
—
|
|
|
|
(41
|
)
|
||||
Other, net
|
6
|
|
|
14
|
|
|
1
|
|
|
|
8
|
|
||||
Cash used in investing activities
|
(101
|
)
|
|
(727
|
)
|
|
(93
|
)
|
|
|
(1,420
|
)
|
||||
Net change in cash, cash equivalents and restricted cash (Successor); Net change in cash and cash equivalents (Predecessor)
|
(1,353
|
)
|
|
458
|
|
|
(6
|
)
|
|
|
(599
|
)
|
||||
Cash, cash equivalents and restricted cash — beginning balance (Successor); Cash and cash equivalents — beginning balance (Predecessor)
|
2,046
|
|
|
1,588
|
|
|
1,594
|
|
|
|
1,400
|
|
||||
Cash, cash equivalents and restricted cash — ending balance (Successor); Cash and cash equivalents — ending balance (Predecessor)
|
$
|
693
|
|
|
$
|
2,046
|
|
|
$
|
1,588
|
|
|
|
$
|
801
|
|
VISTRA ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
|
|||||||
|
Year Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
ASSETS
|
|
|
|
||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
636
|
|
|
$
|
1,487
|
|
Restricted cash (Note 23)
|
57
|
|
|
59
|
|
||
Trade accounts receivable — net (Note 23)
|
1,087
|
|
|
582
|
|
||
Inventories (Note 23)
|
412
|
|
|
253
|
|
||
Commodity and other derivative contractual assets (Note 18)
|
730
|
|
|
190
|
|
||
Margin deposits related to commodity contracts
|
361
|
|
|
30
|
|
||
Prepaid expense and other current assets
|
152
|
|
|
72
|
|
||
Total current assets
|
3,435
|
|
|
2,673
|
|
||
Restricted cash (Note 23)
|
—
|
|
|
500
|
|
||
Investments (Note 23)
|
1,250
|
|
|
1,240
|
|
||
Investment in unconsolidated subsidiary (Note 23)
|
131
|
|
|
—
|
|
||
Property, plant and equipment — net (Note 23)
|
14,612
|
|
|
4,820
|
|
||
Goodwill (Note 8)
|
2,068
|
|
|
1,907
|
|
||
Identifiable intangible assets — net (Note 8)
|
2,493
|
|
|
2,530
|
|
||
Commodity and other derivative contractual assets (Note 18)
|
109
|
|
|
58
|
|
||
Accumulated deferred income taxes (Note 9)
|
1,336
|
|
|
710
|
|
||
Other noncurrent assets
|
590
|
|
|
162
|
|
||
Total assets
|
$
|
26,024
|
|
|
$
|
14,600
|
|
LIABILITIES AND EQUITY
|
|
|
|
||||
Current liabilities:
|
|
|
|
||||
Accounts receivable securitization program (Note 13)
|
$
|
339
|
|
|
$
|
—
|
|
Long-term debt due currently (Note 14)
|
191
|
|
|
44
|
|
||
Trade accounts payable
|
945
|
|
|
473
|
|
||
Commodity and other derivative contractual liabilities (Note 18)
|
1,376
|
|
|
224
|
|
||
Margin deposits related to commodity contracts
|
4
|
|
|
4
|
|
||
Accrued taxes
|
10
|
|
|
58
|
|
||
Accrued taxes other than income
|
182
|
|
|
136
|
|
||
Accrued interest
|
77
|
|
|
16
|
|
||
Asset retirement obligations (Note 23)
|
156
|
|
|
99
|
|
||
Other current liabilities
|
345
|
|
|
297
|
|
||
Total current liabilities
|
3,625
|
|
|
1,351
|
|
||
Long-term debt, less amounts due currently (Note 14)
|
10,874
|
|
|
4,379
|
|
||
Commodity and other derivative contractual liabilities (Note 18)
|
270
|
|
|
102
|
|
||
Accumulated deferred income taxes (Note 9)
|
10
|
|
|
—
|
|
||
Tax Receivable Agreement obligation (Note 10)
|
420
|
|
|
333
|
|
||
Asset retirement obligations (Note 23)
|
2,217
|
|
|
1,837
|
|
||
Identifiable intangible liabilities — net (Note 8)
|
401
|
|
|
36
|
|
||
Other noncurrent liabilities and deferred credits (Note 23)
|
340
|
|
|
220
|
|
||
Total liabilities
|
18,157
|
|
|
8,258
|
|
VISTRA ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
|
|||||||
|
Year Ended December 31,
|
||||||
Commitments and Contingencies (Note 15)
|
|
|
|
|
|
||
Total equity (Note 16):
|
|
|
|
||||
Common stock (par value — $0.01; number of shares authorized — 1,800,000,000)
(shares outstanding: December 31, 2018 — 493,215,309; December 31, 2017 — 428,398,802) |
5
|
|
|
4
|
|
||
Additional paid-in-capital
|
9,329
|
|
|
7,765
|
|
||
Retained deficit
|
(1,449
|
)
|
|
(1,410
|
)
|
||
Accumulated other comprehensive income (loss)
|
(22
|
)
|
|
(17
|
)
|
||
Stockholders' equity
|
7,863
|
|
|
6,342
|
|
||
Noncontrolling interest in subsidiary
|
4
|
|
|
—
|
|
||
Total equity
|
7,867
|
|
|
6,342
|
|
||
Total liabilities and equity
|
$
|
26,024
|
|
|
$
|
14,600
|
|
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 Stockholders' Equity
|
|
Noncontrolling Interests (Successor)
|
|
Total Equity
|
||||||||||||||
Equity in Successor:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Balances at October 3, 2016
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Shares issued upon Emergence
|
4
|
|
|
7,737
|
|
|
—
|
|
|
—
|
|
|
7,741
|
|
|
—
|
|
|
7,741
|
|
|||||||
Effects of stock-based compensation
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
|||||||
Other issuances of common stock
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|||||||
Net loss
|
—
|
|
|
—
|
|
|
(163
|
)
|
|
—
|
|
|
(163
|
)
|
|
—
|
|
|
(163
|
)
|
|||||||
Dividends declared on common stock
|
—
|
|
|
—
|
|
|
(992
|
)
|
|
—
|
|
|
(992
|
)
|
|
—
|
|
|
(992
|
)
|
|||||||
Pension and OPEB liability — change in funded status
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
6
|
|
|
—
|
|
|
6
|
|
|||||||
Balances at December 31, 2016
|
$
|
4
|
|
|
$
|
7,742
|
|
|
$
|
(1,155
|
)
|
|
$
|
6
|
|
|
$
|
6,597
|
|
|
$
|
—
|
|
|
$
|
6,597
|
|
Effects of stock-based compensation
|
—
|
|
|
23
|
|
|
—
|
|
|
—
|
|
|
23
|
|
|
—
|
|
|
23
|
|
|||||||
Net loss
|
—
|
|
|
—
|
|
|
(254
|
)
|
|
—
|
|
|
(254
|
)
|
|
—
|
|
|
(254
|
)
|
|||||||
Pension and OPEB liability — change in funded status
|
—
|
|
|
—
|
|
|
—
|
|
|
(23
|
)
|
|
(23
|
)
|
|
—
|
|
|
(23
|
)
|
|||||||
Other
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|||||||
Balances at December 31, 2017
|
$
|
4
|
|
|
$
|
7,765
|
|
|
$
|
(1,410
|
)
|
|
$
|
(17
|
)
|
|
$
|
6,342
|
|
|
$
|
—
|
|
|
$
|
6,342
|
|
Stock and stock compensation awards issued in connection with the Merger
|
1
|
|
|
1,901
|
|
|
—
|
|
|
—
|
|
|
1,902
|
|
|
—
|
|
|
1,902
|
|
|||||||
Treasury stock
|
—
|
|
|
(778
|
)
|
|
—
|
|
|
—
|
|
|
(778
|
)
|
|
—
|
|
|
(778
|
)
|
|||||||
Effects of stock-based compensation
|
—
|
|
|
72
|
|
|
—
|
|
|
—
|
|
|
72
|
|
|
—
|
|
|
72
|
|
|||||||
Tangible equity units acquired
|
—
|
|
|
369
|
|
|
—
|
|
|
—
|
|
|
369
|
|
|
—
|
|
|
369
|
|
|||||||
Warrants acquired
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|||||||
Net loss
|
—
|
|
|
—
|
|
|
(54
|
)
|
|
—
|
|
|
(54
|
)
|
|
(2
|
)
|
|
(56
|
)
|
|||||||
Adoption of new accounting standards (Note 1)
|
—
|
|
|
—
|
|
|
16
|
|
|
1
|
|
|
17
|
|
|
—
|
|
|
17
|
|
|||||||
Pension and OPEB liability — change in funded status
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
(6
|
)
|
|
—
|
|
|
(6
|
)
|
|||||||
Investment by noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
6
|
|
|||||||
Other
|
—
|
|
|
(2
|
)
|
|
(1
|
)
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
|||||||
Balances at December 31, 2018
|
$
|
5
|
|
|
$
|
9,329
|
|
|
$
|
(1,449
|
)
|
|
$
|
(22
|
)
|
|
$
|
7,863
|
|
|
$
|
4
|
|
|
$
|
7,867
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Membership interests in Predecessor:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
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
|
|
December 31, 2017
|
|
Adoption of New Revenue Standard
|
|
January 1,
2018
|
||||||
Impact on consolidated balance sheet:
|
|
|
|
|
|
||||||
Assets
|
|
|
|
|
|
||||||
Prepaid expense and other current assets
|
$
|
72
|
|
|
$
|
5
|
|
|
$
|
77
|
|
Accumulated deferred income taxes
|
$
|
710
|
|
|
$
|
(4
|
)
|
|
$
|
706
|
|
Other noncurrent assets
|
$
|
162
|
|
|
$
|
16
|
|
|
$
|
178
|
|
Equity
|
|
|
|
|
|
||||||
Retained deficit
|
$
|
(1,410
|
)
|
|
$
|
17
|
|
|
$
|
(1,393
|
)
|
|
Year Ended December 31, 2018
|
||||||||||
|
As Reported
|
|
Amount Without Adoption of New Revenue Standard
|
|
Effect of Change
Higher (Lower)
|
||||||
Impact on statement of consolidated income (loss):
|
|
|
|
|
|
||||||
Operating revenues
|
$
|
9,144
|
|
|
$
|
9,141
|
|
|
$
|
3
|
|
Selling, general and administrative expenses
|
(926
|
)
|
|
(939
|
)
|
|
13
|
|
|||
Net income (loss)
|
(56
|
)
|
|
(68
|
)
|
|
12
|
|
|
December 31, 2018
|
||||||||||
|
As Reported
|
|
Balances Without Adoption of New Revenue Standard
|
|
Effect of Change
Higher (Lower)
|
||||||
Impact on consolidated balance sheet:
|
|
|
|
|
|
||||||
Assets
|
|
|
|
|
|
||||||
Prepaid expense and other current assets
|
$
|
152
|
|
|
$
|
145
|
|
|
$
|
7
|
|
Accumulated deferred income taxes
|
1,336
|
|
|
1,349
|
|
|
(13
|
)
|
|||
Other noncurrent assets
|
590
|
|
|
559
|
|
|
31
|
|
|||
Equity
|
|
|
|
|
|
||||||
Retained deficit
|
$
|
(1,449
|
)
|
|
$
|
(1,478
|
)
|
|
$
|
29
|
|
2.
|
MERGER TRANSACTION AND BUSINESS COMBINATION ACCOUNTING
|
•
|
Working capital was valued using available market information (Level 2).
|
•
|
Acquired property, plant and equipment was valued using a combination of an income approach and a market approach. The income approach utilized a discounted cash flow analysis based upon a debt-free, free cash flow model (Level 3).
|
•
|
Acquired derivatives were valued using the methods described in Note
17
(Level 1, Level 2 or Level 3).
|
•
|
Contracts with terms that were not at current market prices were also valued using a discounted cash flow analysis (Level 3). The cash flows generated by the contracts were compared with their cash flows based on current market prices with the resulting difference discounted to present value and recorded as either an intangible asset or liability.
|
•
|
Long-term debt was valued using a market approach (Level 2).
|
•
|
AROs were recorded in accordance with ASC 410,
Asset Retirement and Environmental Obligations
(Level 3).
|
Dynegy shares outstanding as of April 9, 2018 (in millions)
|
144.8
|
|
|
Exchange Ratio
|
0.652
|
|
|
Vistra Energy shares issued for Dynegy shares outstanding (in millions)
|
94.4
|
|
|
Opening price of Vistra Energy common stock on April 9, 2018
|
$
|
19.87
|
|
Purchase price for common stock
|
$
|
1,876
|
|
Fair value of equity component of tangible equity units
|
$
|
369
|
|
Fair value of outstanding stock compensation awards attributable to pre-combination service
|
$
|
26
|
|
Fair value of outstanding warrants
|
$
|
2
|
|
Total purchase price
|
$
|
2,273
|
|
Preliminary Purchase Price Allocation
|
|||
Cash and cash equivalents
|
$
|
445
|
|
Trade accounts receivables, inventories, prepaid expenses and other current assets
|
856
|
|
|
Property, plant and equipment
|
10,520
|
|
|
Accumulated deferred income taxes
|
492
|
|
|
Identifiable intangible assets
|
351
|
|
|
Goodwill
|
161
|
|
|
Other noncurrent assets
|
423
|
|
|
Total assets acquired
|
13,248
|
|
|
Trade accounts payable and other current liabilities
|
687
|
|
|
Commodity and other derivative contractual assets and liabilities, net
|
422
|
|
|
Asset retirement obligations, including amounts due currently
|
477
|
|
|
Long-term debt, including amounts due currently
|
8,920
|
|
|
Other noncurrent liabilities
|
464
|
|
|
Total liabilities assumed
|
10,970
|
|
|
Identifiable net assets acquired
|
2,278
|
|
|
Noncontrolling interest in subsidiary
|
5
|
|
|
Total purchase price
|
$
|
2,273
|
|
|
Year Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
Revenues
|
$
|
10,595
|
|
|
$
|
10,509
|
|
Net loss
|
$
|
(268
|
)
|
|
$
|
(969
|
)
|
Net loss attributable to Vistra Energy
|
$
|
(265
|
)
|
|
$
|
(983
|
)
|
Net loss attributable to Vistra Energy per weighted average share of common stock outstanding — basic
|
$
|
(0.52
|
)
|
|
$
|
(1.83
|
)
|
Net loss attributable to Vistra Energy per weighted average share of common stock outstanding — diluted
|
$
|
(0.52
|
)
|
|
$
|
(1.83
|
)
|
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.
|
RETIREMENT OF GENERATION FACILITIES
|
Name
|
|
Location
|
|
Fuel Type
|
|
Net Generation Capacity (MW)
|
|
Ownership Interest
|
|
Date Units Taken Offline
|
|
Killen
|
|
Manchester, Ohio
|
|
Coal
|
|
204
|
|
|
33%
|
|
May 31, 2018
|
Stuart
|
|
Aberdeen, Ohio
|
|
Coal
|
|
679
|
|
|
39%
|
|
May 24, 2018
|
Total
|
|
|
|
|
|
883
|
|
|
|
|
|
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 |
||
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
|
|
|
Expenses related to other professional consulting and advisory services
|
39
|
|
|
Contract claims adjustments
|
13
|
|
|
Other
|
11
|
|
|
Total reorganization items
|
$
|
(22,121
|
)
|
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
14
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
10
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
19
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
16
.
|
(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
8
).
|
(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
23
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.
|
REVENUE
|
|
Year Ended December 31, 2018
|
||||||||||||||||||||||||||||||
|
Retail
|
|
ERCOT
|
|
PJM
|
|
NY/NE
|
|
MISO
|
|
Asset
Closure
|
|
CAISO/Eliminations
|
|
Consolidated
|
||||||||||||||||
Revenue from contracts with customers:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Retail energy charge in ERCOT
|
$
|
4,426
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4,426
|
|
Retail energy charge in Northeast/Midwest
|
1,123
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,123
|
|
||||||||
Wholesale generation revenue from ISO/RTO
|
—
|
|
|
1,151
|
|
|
792
|
|
|
544
|
|
|
420
|
|
|
52
|
|
|
167
|
|
|
3,126
|
|
||||||||
Capacity revenue
|
—
|
|
|
—
|
|
|
369
|
|
|
240
|
|
|
53
|
|
|
6
|
|
|
30
|
|
|
698
|
|
||||||||
Revenue from other wholesale contracts
|
—
|
|
|
214
|
|
|
29
|
|
|
42
|
|
|
133
|
|
|
—
|
|
|
6
|
|
|
424
|
|
||||||||
Total revenue from contracts with customers
|
5,549
|
|
|
1,365
|
|
|
1,190
|
|
|
826
|
|
|
606
|
|
|
58
|
|
|
203
|
|
|
9,797
|
|
||||||||
Other revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Intangible amortization
|
(26
|
)
|
|
(1
|
)
|
|
2
|
|
|
(9
|
)
|
|
(9
|
)
|
|
—
|
|
|
—
|
|
|
(43
|
)
|
||||||||
Hedging and other revenues (a)
|
74
|
|
|
(362
|
)
|
|
(62
|
)
|
|
(41
|
)
|
|
(195
|
)
|
|
(31
|
)
|
|
7
|
|
|
(610
|
)
|
||||||||
Affiliate sales
|
—
|
|
|
1,632
|
|
|
595
|
|
|
41
|
|
|
318
|
|
|
23
|
|
|
(2,609
|
)
|
|
—
|
|
||||||||
Total other revenues
|
48
|
|
|
1,269
|
|
|
535
|
|
|
(9
|
)
|
|
114
|
|
|
(8
|
)
|
|
(2,602
|
)
|
|
(653
|
)
|
||||||||
Total revenues
|
$
|
5,597
|
|
|
$
|
2,634
|
|
|
$
|
1,725
|
|
|
$
|
817
|
|
|
$
|
720
|
|
|
$
|
50
|
|
|
$
|
(2,399
|
)
|
|
$
|
9,144
|
|
(a)
|
Includes
$380 million
of unrealized net losses from mark-to-market valuations of commodity positions. See Note
22
for unrealized net gains (losses) by segment.
|
|
December 31, 2018
|
||
Trade accounts receivable from contracts with customers — net
|
$
|
951
|
|
Other trade accounts receivable — net
|
136
|
|
|
Total trade accounts receivable — net
|
$
|
1,087
|
|
8.
|
GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||||||||||
Identifiable Intangible Asset
|
|
Gross
Carrying
Amount
|
|
Accumulated
Amortization
|
|
Net
|
|
Gross
Carrying
Amount
|
|
Accumulated
Amortization
|
|
Net
|
||||||||||||
Retail customer relationship
|
|
$
|
1,680
|
|
|
$
|
876
|
|
|
$
|
804
|
|
|
$
|
1,648
|
|
|
$
|
572
|
|
|
$
|
1,076
|
|
Software and other technology-related assets
|
|
270
|
|
|
105
|
|
|
165
|
|
|
183
|
|
|
47
|
|
|
136
|
|
||||||
Retail and wholesale contracts
|
|
316
|
|
|
138
|
|
|
178
|
|
|
154
|
|
|
87
|
|
|
67
|
|
||||||
Contractual service agreements
|
|
70
|
|
|
—
|
|
|
70
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Other identifiable intangible assets (a)
|
|
42
|
|
|
15
|
|
|
27
|
|
|
33
|
|
|
11
|
|
|
22
|
|
||||||
Total identifiable intangible assets subject to amortization
|
|
$
|
2,378
|
|
|
$
|
1,134
|
|
|
1,244
|
|
|
$
|
2,018
|
|
|
$
|
717
|
|
|
1,301
|
|
||
Retail trade names (not subject to amortization)
|
|
|
|
|
|
1,245
|
|
|
|
|
|
|
1,225
|
|
||||||||||
Mineral interests (not currently subject to amortization)
|
|
|
|
|
|
4
|
|
|
|
|
|
|
4
|
|
||||||||||
Total identifiable intangible assets
|
|
|
|
|
|
$
|
2,493
|
|
|
|
|
|
|
$
|
2,530
|
|
(a)
|
Includes mining development costs and environmental allowances and credits.
|
|
|
Year Ended December 31,
|
||||||
|
|
2018
|
|
2017
|
||||
Identifiable Intangible Liability
|
|
|
|
|
||||
Contractual service agreements
|
|
$
|
136
|
|
|
$
|
—
|
|
Purchase and sale contracts
|
|
195
|
|
|
36
|
|
||
Environmental allowances
|
|
$
|
70
|
|
|
$
|
—
|
|
Total identifiable intangible liabilities
|
|
$
|
401
|
|
|
$
|
36
|
|
(a)
|
Amounts recorded in depreciation and amortization totaled
$370 million
,
$463 million
,
$162 million
and
$58 million
for the Successor period for the years ended
December 31, 2018 and 2017
and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016, respectively. Excludes contractual services agreements.
|
•
|
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
, 4Change Energy
TM
, Homefield and Dynegy Energy Services 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 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, 2018.
|
•
|
Retail and wholesale contracts/purchase and sale contracts
– These intangible assets represent the value of various retail and wholesale contracts and purchase and sale contracts. The contracts were identified as either assets or liabilities based on the respective fair values as of the Effective Date or the Merger Date utilizing prevailing market prices for commodities or services compared to the fixed prices contained in these agreements. The intangible assets or liabilities are being amortized in relation to the economic terms of the related contracts.
|
•
|
Contractual service agreements
– Our acquired contractual service agreements represent the estimated fair value of favorable or unfavorable contract obligations with respect to long-term plant maintenance agreements, rail transportation agreements and rail car leases, and are being amortized based on the expected usage of the service agreements over the contract terms. The majority of the plant maintenance services relate to capital improvements and the related amortization of the plant maintenance agreements is recorded to property, plant and equipment. Amortization of rail transportation and rail car lease agreements is recorded to fuel, purchased power costs and delivery fees.
|
Year
|
|
Estimated Amortization Expense
|
||
2019
|
|
$
|
299
|
|
2020
|
|
$
|
201
|
|
2021
|
|
$
|
154
|
|
2022
|
|
$
|
91
|
|
2023
|
|
$
|
67
|
|
9.
|
INCOME TAXES
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended December 31,
|
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
||||||||||
|
2018
|
|
2017
|
|
|
|
||||||||||
Current:
|
|
|
|
|
|
|
|
|
||||||||
U.S. Federal
|
$
|
(13
|
)
|
|
$
|
72
|
|
|
$
|
—
|
|
|
|
$
|
(6
|
)
|
State
|
30
|
|
|
14
|
|
|
6
|
|
|
|
9
|
|
||||
Total current
|
17
|
|
|
86
|
|
|
6
|
|
|
|
3
|
|
||||
Deferred:
|
|
|
|
|
|
|
|
|
||||||||
U.S. Federal
|
(8
|
)
|
|
417
|
|
|
(75
|
)
|
|
|
(1,234
|
)
|
||||
State
|
(54
|
)
|
|
1
|
|
|
(1
|
)
|
|
|
(36
|
)
|
||||
Total deferred
|
(62
|
)
|
|
418
|
|
|
(76
|
)
|
|
|
(1,270
|
)
|
||||
Total
|
$
|
(45
|
)
|
|
$
|
504
|
|
|
$
|
(70
|
)
|
|
|
$
|
(1,267
|
)
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended December 31,
|
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
||||||||||
|
2018
|
|
2017
|
|
|
|
||||||||||
Income (loss) before income taxes
|
$
|
(101
|
)
|
|
$
|
250
|
|
|
$
|
(233
|
)
|
|
|
$
|
21,584
|
|
US federal statutory rate
|
21
|
%
|
|
35
|
%
|
|
35
|
%
|
|
|
35
|
%
|
||||
Income taxes at the U.S. federal statutory rate
|
(20
|
)
|
|
88
|
|
|
(82
|
)
|
|
|
7,554
|
|
||||
Nondeductible TRA accretion
|
8
|
|
|
(80
|
)
|
|
5
|
|
|
|
—
|
|
||||
State tax, net of federal benefit
|
22
|
|
|
13
|
|
|
3
|
|
|
|
(21
|
)
|
||||
Impacts of tax reform legislation on deferred taxes
|
—
|
|
|
451
|
|
|
—
|
|
|
|
—
|
|
||||
Return to provision adjustment
|
(12
|
)
|
|
19
|
|
|
—
|
|
|
|
—
|
|
||||
Remeasurement of historical Vistra Energy deferred taxes for expanded state footprint
|
(54
|
)
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Effect of refundable minimum tax credits no longer subject to sequestration
|
(15
|
)
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Nondeductible compensation
|
8
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Nondeductible transaction costs
|
3
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Equity awards
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Nondeductible debt restructuring costs
|
—
|
|
|
—
|
|
|
2
|
|
|
|
38
|
|
||||
Nondeductible interest expense
|
—
|
|
|
—
|
|
|
—
|
|
|
|
12
|
|
||||
Nontaxable gain on extinguishment of LSTC
|
—
|
|
|
—
|
|
|
—
|
|
|
|
(8,593
|
)
|
||||
Valuation allowance on state NOLs
|
20
|
|
|
—
|
|
|
—
|
|
|
|
(210
|
)
|
||||
Other
|
(2
|
)
|
|
13
|
|
|
2
|
|
|
|
(47
|
)
|
||||
Income tax expense (benefit)
|
$
|
(45
|
)
|
|
$
|
504
|
|
|
$
|
(70
|
)
|
|
|
$
|
(1,267
|
)
|
Effective tax rate
|
44.6
|
%
|
|
201.6
|
%
|
|
30.0
|
%
|
|
|
(5.9
|
)%
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Noncurrent Deferred Income Tax Assets
|
|
|
|
||||
Tax credit carryforwards
|
$
|
76
|
|
|
$
|
—
|
|
Loss carryforwards
|
958
|
|
|
—
|
|
||
Property, plant and equipment
|
—
|
|
|
520
|
|
||
Identifiable intangible assets
|
184
|
|
|
81
|
|
||
Long-term debt
|
188
|
|
|
20
|
|
||
Employee benefit obligations
|
109
|
|
|
56
|
|
||
Commodity contracts and interest rate swaps
|
212
|
|
|
25
|
|
||
Other
|
40
|
|
|
8
|
|
||
Total deferred tax assets
|
$
|
1,767
|
|
|
$
|
710
|
|
Noncurrent Deferred Income Tax Liabilities
|
|
|
|
||||
Property, plant and equipment
|
406
|
|
|
—
|
|
||
Total deferred tax liabilities
|
406
|
|
|
—
|
|
||
Valuation allowance
|
35
|
|
|
—
|
|
||
Net Deferred Income Tax Asset
|
$
|
1,326
|
|
|
$
|
710
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended December 31,
|
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
||||||||||
|
2018
|
|
2017
|
|
|
|
||||||||||
Balance at beginning of period, excluding interest and penalties
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
36
|
|
Additions allocated in the Merger
|
39
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Reductions based on tax positions related to prior years
|
—
|
|
|
—
|
|
|
—
|
|
|
|
(1
|
)
|
||||
Settlements with taxing authorities
|
—
|
|
|
—
|
|
|
—
|
|
|
|
(35
|
)
|
||||
Balance at end of period, excluding interest and penalties
|
$
|
39
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
10.
|
TAX RECEIVABLE AGREEMENT OBLIGATION
|
|
Successor
|
||||||||||
|
Year Ended December 31,
|
|
Period from October 3, 2016
through December 31, 2016 |
||||||||
|
2018
|
|
2017
|
|
|||||||
TRA obligation at the beginning of the period
|
$
|
357
|
|
|
$
|
596
|
|
|
$
|
574
|
|
Accretion expense
|
65
|
|
|
82
|
|
|
22
|
|
|||
Payments
|
(16
|
)
|
|
(26
|
)
|
|
—
|
|
|||
Changes in tax assumptions impacting timing of payments
|
14
|
|
|
(62
|
)
|
|
—
|
|
|||
Revaluation due to tax reform legislation
|
—
|
|
|
(233
|
)
|
|
—
|
|
|||
TRA obligation at the end of the period
|
420
|
|
|
357
|
|
|
596
|
|
|||
Less amounts due currently
|
—
|
|
|
(24
|
)
|
|
—
|
|
|||
Noncurrent TRA obligation at the end of the period
|
$
|
420
|
|
|
$
|
333
|
|
|
$
|
596
|
|
11.
|
INTEREST EXPENSE AND RELATED CHARGES
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended December 31,
|
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
||||||||||
|
2018
|
|
2017
|
|
|
|
||||||||||
Interest paid/accrued post-Emergence
|
$
|
537
|
|
|
$
|
213
|
|
|
$
|
51
|
|
|
|
$
|
—
|
|
Interest paid/accrued on debtor-in-possession financing
|
—
|
|
|
—
|
|
|
—
|
|
|
|
76
|
|
||||
Adequate protection amounts paid/accrued
|
—
|
|
|
—
|
|
|
—
|
|
|
|
977
|
|
||||
Unrealized mark-to-market net (gains) losses on interest rate swaps
|
5
|
|
|
(29
|
)
|
|
11
|
|
|
|
—
|
|
||||
Amortization of debt issuance costs, discounts and premiums
|
—
|
|
|
4
|
|
|
(1
|
)
|
|
|
4
|
|
||||
Debt extinguishment loss
|
27
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Capitalized interest
|
(12
|
)
|
|
(7
|
)
|
|
(3
|
)
|
|
|
(9
|
)
|
||||
Other
|
15
|
|
|
12
|
|
|
2
|
|
|
|
1
|
|
||||
Total interest expense and related charges
|
$
|
572
|
|
|
$
|
193
|
|
|
$
|
60
|
|
|
|
$
|
1,049
|
|
|
Predecessor
|
||
|
Period from January 1, 2016
through October 2, 2016 |
||
Contractual interest on debt classified as LSTC
|
$
|
1,570
|
|
Adequate protection amounts paid/accrued
|
930
|
|
|
Contractual interest on debt classified as LSTC not paid/accrued
|
$
|
640
|
|
12.
|
EARNINGS PER SHARE
|
|
Successor
|
||||||||||
|
Year Ended
December 31, 2018 |
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||||
Net loss attributable to common stock — basic (a)
|
$
|
(54
|
)
|
|
$
|
(254
|
)
|
|
$
|
(163
|
)
|
Weighted average shares of common stock outstanding — basic
|
504,954,371
|
|
|
427,761,460
|
|
|
427,560,620
|
|
|||
Net loss per weighted average share of common stock outstanding — basic
|
$
|
(0.11
|
)
|
|
$
|
(0.59
|
)
|
|
$
|
(0.38
|
)
|
Weighted average shares of common stock outstanding — diluted
|
504,954,371
|
|
|
427,761,460
|
|
|
427,560,620
|
|
|||
Net loss per weighted average share of common stock outstanding — diluted
|
$
|
(0.11
|
)
|
|
$
|
(0.59
|
)
|
|
$
|
(0.38
|
)
|
(a)
|
The minimum settlement amount of tangible equity units, or 15,056,260 shares, are considered to be outstanding and are
|
13.
|
ACCOUNTS RECEIVABLE SECURITIZATION PROGRAM
|
14.
|
LONG-TERM DEBT
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Vistra Operations Credit Facilities
|
$
|
5,813
|
|
|
$
|
4,311
|
|
Vistra Operations 5.500% Senior Notes, due September 1, 2026
|
1,000
|
|
|
—
|
|
||
Vistra Energy Senior Notes:
|
|
|
|
||||
7.375% Senior Notes, due November 1, 2022
|
1,707
|
|
|
—
|
|
||
5.875% Senior Notes, due June 1, 2023
|
500
|
|
|
—
|
|
||
7.625% Senior Notes, due November 1, 2024
|
1,147
|
|
|
—
|
|
||
8.034% Senior Notes, due February 2, 2024
|
25
|
|
|
—
|
|
||
8.000% Senior Notes, due January 15, 2025
|
81
|
|
|
—
|
|
||
8.125% Senior Notes, due January 30, 2026
|
166
|
|
|
—
|
|
||
Total Vistra Energy Senior Notes
|
3,626
|
|
|
—
|
|
||
Other:
|
|
|
|
||||
7.000% Amortizing Notes, due July 1, 2019
|
24
|
|
|
—
|
|
||
Forward Capacity Agreements
|
236
|
|
|
—
|
|
||
Equipment Financing Agreements
|
120
|
|
|
—
|
|
||
Mandatorily redeemable subsidiary preferred stock (a)
|
70
|
|
|
70
|
|
||
8.82% Building Financing due semiannually through February 11, 2022 (b)
|
21
|
|
|
27
|
|
||
Total other long-term debt
|
471
|
|
|
97
|
|
||
Unamortized debt premiums, discounts and issuance costs (c)
|
155
|
|
|
15
|
|
||
Total long-term debt including amounts due currently
|
11,065
|
|
|
4,423
|
|
||
Less amounts due currently
|
(191
|
)
|
|
(44
|
)
|
||
Total long-term debt less amounts due currently
|
$
|
10,874
|
|
|
$
|
4,379
|
|
(a)
|
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.
|
(b)
|
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.
|
(c)
|
Includes impact of recording debt assumed in the Merger at fair value.
|
|
|
|
|
December 31, 2018
|
||||||||||
Vistra Operations Credit Facilities
|
|
Maturity Date
|
|
Facility
Limit
|
|
Cash
Borrowings
|
|
Available
Capacity
|
||||||
Revolving Credit Facility (a)
|
|
June 14, 2023
|
|
$
|
2,500
|
|
|
$
|
—
|
|
|
$
|
1,135
|
|
Term Loan B-1 Facility
|
|
August 4, 2023
|
|
2,793
|
|
|
2,793
|
|
|
—
|
|
|||
Term Loan B-2 Facility
|
|
December 14, 2023
|
|
980
|
|
|
980
|
|
|
—
|
|
|||
Term Loan B-3 Facility
|
|
December 31, 2025
|
|
2,040
|
|
|
2,040
|
|
|
—
|
|
|||
Total Vistra Operations Credit Facilities
|
|
|
|
$
|
8,313
|
|
|
$
|
5,813
|
|
|
$
|
1,135
|
|
(a)
|
Facility to be used for general corporate purposes. Facility includes a
$2.3 billion
letter of credit sub-facility, of which
$1.365 billion
of letters of credit were outstanding at
December 31, 2018
and which reduce our available capacity.
|
•
|
$26 million
of
7.625%
senior notes due 2024;
|
•
|
$163 million
of
8.034%
senior notes due 2024;
|
•
|
$669 million
of
8.000%
senior notes due 2025, and
|
•
|
$684 million
of
8.125%
senior notes due 2026.
|
|
December 31, 2018
|
||
2019
|
$
|
191
|
|
2020
|
205
|
|
|
2021
|
129
|
|
|
2022
|
1,782
|
|
|
2023
|
4,150
|
|
|
Thereafter
|
4,453
|
|
|
Unamortized premiums, discounts and debt issuance costs
|
155
|
|
|
Total long-term debt, including amounts due currently
|
$
|
11,065
|
|
15.
|
COMMITMENTS AND CONTINGENCIES
|
|
Long-Term Service and Maintenance Contracts
|
|
Coal purchase and
transportation agreements
|
|
Pipeline transportation and storage reservation fees
|
|
Nuclear
Fuel Contracts
|
|
Other
Contracts
|
||||||||||
2019
|
$
|
175
|
|
|
$
|
765
|
|
|
$
|
101
|
|
|
$
|
69
|
|
|
$
|
101
|
|
2020
|
181
|
|
|
227
|
|
|
95
|
|
|
71
|
|
|
74
|
|
|||||
2021
|
135
|
|
|
118
|
|
|
72
|
|
|
58
|
|
|
20
|
|
|||||
2022
|
183
|
|
|
103
|
|
|
48
|
|
|
38
|
|
|
13
|
|
|||||
2023
|
133
|
|
|
64
|
|
|
35
|
|
|
46
|
|
|
9
|
|
|||||
Thereafter
|
2,619
|
|
|
186
|
|
|
145
|
|
|
155
|
|
|
68
|
|
|||||
Total
|
$
|
3,426
|
|
|
$
|
1,463
|
|
|
$
|
496
|
|
|
$
|
437
|
|
|
$
|
285
|
|
|
Operating Leases (a)
|
||
2019
|
$
|
35
|
|
2020
|
29
|
|
|
2021
|
25
|
|
|
2022
|
20
|
|
|
2023
|
19
|
|
|
Thereafter
|
168
|
|
|
Total future minimum lease payments
|
$
|
296
|
|
(a)
|
Includes operating leases with initial or remaining noncancellable lease terms in excess of one year.
|
•
|
$1.185 billion
to support commodity risk management collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and collateral postings with ISOs or RTOs;
|
•
|
$53 million
to support executory contracts and insurance agreements;
|
•
|
$55 million
to support our REP financial requirements with the PUCT, and
|
•
|
$72 million
for other credit support requirements.
|
16.
|
EQUITY
|
|
Successor
|
|||||||
|
Year Ended
December 31, 2018 |
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|||
Shares outstanding at beginning of period
|
428,398,802
|
|
|
427,580,232
|
|
|
—
|
|
Shares issued (a)
|
97,639,105
|
|
|
818,570
|
|
|
427,580,232
|
|
Shares retired
|
(6,815
|
)
|
|
—
|
|
|
—
|
|
Shares repurchased (b)
|
(32,815,783
|
)
|
|
—
|
|
|
—
|
|
Shares outstanding at end of period
|
493,215,309
|
|
|
428,398,802
|
|
|
427,580,232
|
|
(a)
|
Includes share awards granted to nonemployee directors. The year ended
December 31, 2018
includes
94,409,573
shares issued in connection with the Merger (see Note
2
).
|
(b)
|
Treasury shares totaled
32,815,783
shares at
December 31, 2018
, all of which were acquired during the year ended
December 31, 2018
in connection with the share repurchase program described below.
|
17.
|
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, 2018
|
|||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3 (a)
|
|
Reclassification (b)
|
|
Total
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity contracts
|
$
|
456
|
|
|
$
|
152
|
|
|
$
|
153
|
|
|
$
|
1
|
|
|
$
|
762
|
|
Interest rate swaps
|
—
|
|
|
77
|
|
|
—
|
|
|
—
|
|
|
77
|
|
|||||
Nuclear decommissioning trust –
equity securities (c) |
449
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
449
|
|
|||||
Nuclear decommissioning trust –
debt securities (c) |
—
|
|
|
443
|
|
|
—
|
|
|
—
|
|
|
443
|
|
|||||
Sub-total
|
$
|
905
|
|
|
$
|
672
|
|
|
$
|
153
|
|
|
$
|
1
|
|
|
1,731
|
|
|
Assets measured at net asset value (d):
|
|
|
|
|
|
|
|
|
|
||||||||||
Nuclear decommissioning trust –
equity securities (c) |
|
|
|
|
|
|
|
|
278
|
|
|||||||||
Total assets
|
|
|
|
|
|
|
|
|
$
|
2,009
|
|
||||||||
Liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity contracts
|
$
|
557
|
|
|
$
|
766
|
|
|
$
|
288
|
|
|
$
|
1
|
|
|
$
|
1,612
|
|
Interest rate swaps
|
—
|
|
|
34
|
|
|
—
|
|
|
—
|
|
|
34
|
|
|||||
Total liabilities
|
$
|
557
|
|
|
$
|
800
|
|
|
$
|
288
|
|
|
$
|
1
|
|
|
$
|
1,646
|
|
December 31, 2017
|
|||||||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3 (a)
|
|
Reclassification (b)
|
|
Total
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity contracts
|
$
|
47
|
|
|
$
|
98
|
|
|
$
|
75
|
|
|
$
|
2
|
|
|
$
|
222
|
|
Interest rate swaps
|
—
|
|
|
18
|
|
|
—
|
|
|
8
|
|
|
26
|
|
|||||
Nuclear decommissioning trust –
equity securities (c) |
468
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
468
|
|
|||||
Nuclear decommissioning trust –
debt securities (c) |
—
|
|
|
430
|
|
|
—
|
|
|
—
|
|
|
430
|
|
|||||
Sub-total
|
$
|
515
|
|
|
$
|
546
|
|
|
$
|
75
|
|
|
$
|
10
|
|
|
1,146
|
|
|
Assets measured at net asset value (d):
|
|
|
|
|
|
|
|
|
|
||||||||||
Nuclear decommissioning trust –
equity securities (c) |
|
|
|
|
|
|
|
|
290
|
|
|||||||||
Total assets
|
|
|
|
|
|
|
|
|
$
|
1,436
|
|
||||||||
Liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity contracts
|
$
|
45
|
|
|
$
|
143
|
|
|
$
|
128
|
|
|
$
|
2
|
|
|
$
|
318
|
|
Interest rate swaps
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|
8
|
|
|||||
Total liabilities
|
$
|
45
|
|
|
$
|
143
|
|
|
$
|
128
|
|
|
$
|
10
|
|
|
$
|
326
|
|
(a)
|
See table below for description of Level 3 assets and liabilities.
|
(b)
|
Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or vice versa, as presented in our consolidated balance sheets.
|
(c)
|
The nuclear decommissioning trust investment is included in the other investments line in our consolidated balance sheets. See Note
23
.
|
(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, 2018
|
||||||||||||||||||
|
|
Fair Value
|
|
|
|
|
|
|
||||||||||
Contract Type (a)
|
|
Assets
|
|
Liabilities
|
|
Total
|
|
Valuation Technique
|
|
Significant Unobservable Input
|
|
Range (b)
|
||||||
Electricity purchases and sales
|
|
$
|
22
|
|
|
$
|
(48
|
)
|
|
$
|
(26
|
)
|
|
Valuation Model
|
|
Hourly price curve shape (c)
|
|
$0 to $110/ MWh
|
|
|
|
|
|
|
|
|
|
|
Illiquid delivery periods for ERCOT hub power prices and heat rates (d)
|
|
$20 to $120/ MWh
|
||||||
Electricity and weather options
|
|
31
|
|
|
(192
|
)
|
|
(161
|
)
|
|
Option Pricing Model
|
|
Gas to power correlation (e)
|
|
15% to 95%
|
|||
|
|
|
|
|
|
|
|
|
|
Power volatility (e)
|
|
5% to 435%
|
||||||
Financial transmission rights
|
|
85
|
|
|
(20
|
)
|
|
65
|
|
|
Market Approach (f)
|
|
Illiquid price differences between settlement points (g)
|
|
$(10) to $50/ MWh
|
|||
Other (h)
|
|
15
|
|
|
(28
|
)
|
|
(13
|
)
|
|
|
|
|
|
|
|||
Total
|
|
$
|
153
|
|
|
$
|
(288
|
)
|
|
$
|
(135
|
)
|
|
|
|
|
|
|
December 31, 2017
|
||||||||||||||||||
|
|
Fair Value
|
|
|
|
|
|
|
||||||||||
Contract Type (a)
|
|
Assets
|
|
Liabilities
|
|
Total
|
|
Valuation Technique
|
|
Significant Unobservable Input
|
|
Range (b)
|
||||||
Electricity purchases and sales
|
|
$
|
12
|
|
|
$
|
(33
|
)
|
|
$
|
(21
|
)
|
|
Valuation Model
|
|
Hourly price curve shape (c)
|
|
$0 to $40/ MWh
|
|
|
|
|
|
|
|
|
|
|
Illiquid delivery periods for ERCOT hub power prices and heat rates (d)
|
|
$20 to $70/ MWh
|
||||||
Electricity and weather options
|
|
—
|
|
|
(91
|
)
|
|
(91
|
)
|
|
Option Pricing Model
|
|
Gas to power correlation (e)
|
|
30% to 100%
|
|||
|
|
|
|
|
|
|
|
|
|
Power volatility (e)
|
|
5% to 180%
|
||||||
Financial transmission rights
|
|
45
|
|
|
(4
|
)
|
|
41
|
|
|
Market Approach (f)
|
|
Illiquid price differences between settlement points (g)
|
|
$0 to $15/ MWh
|
|||
Other (h)
|
|
18
|
|
|
—
|
|
|
18
|
|
|
|
|
|
|
|
|||
Total
|
|
$
|
75
|
|
|
$
|
(128
|
)
|
|
$
|
(53
|
)
|
|
|
|
|
|
|
(a)
|
Electricity purchase and sales contracts include power and heat rate positions in ERCOT, PJM, NYISO, ISO-NE and MISO regions. The forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points within are referred to as congestion revenue rights in ERCOT and financial transmission rights in PJM, NYISO, ISO-NE and MISO regions. Electricity options consist of physical electricity options and spread options.
|
(b)
|
The range of the inputs may be influenced by factors such as time of day, delivery period, season and location.
|
(c)
|
Primarily based on the historical range of forward average hourly ERCOT North Hub prices.
|
(d)
|
Primarily based on historical forward ERCOT power price and heat rate variability.
|
(e)
|
Based on historical forward correlation and volatility within ERCOT.
|
(f)
|
While we use the market approach, there is insufficient market data to consider the valuation liquid.
|
(g)
|
Primarily based on the historical price differences between settlement points within ERCOT hubs and load zones.
|
(h)
|
Other includes contracts for natural gas, coal options and emissions.
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended December 31,
|
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
||||||||||
|
2018
|
|
2017
|
|
|
|
||||||||||
Net asset (liability) balance at beginning of period (a)
|
$
|
(53
|
)
|
|
$
|
83
|
|
|
$
|
81
|
|
|
|
$
|
37
|
|
Total unrealized valuation gains (losses)
|
(363
|
)
|
|
(136
|
)
|
|
31
|
|
|
|
122
|
|
||||
Purchases, issuances and settlements (b):
|
|
|
|
|
|
|
|
|
||||||||
Purchases
|
146
|
|
|
69
|
|
|
15
|
|
|
|
37
|
|
||||
Issuances
|
(41
|
)
|
|
(22
|
)
|
|
(7
|
)
|
|
|
(20
|
)
|
||||
Settlements
|
76
|
|
|
(106
|
)
|
|
(30
|
)
|
|
|
(51
|
)
|
||||
Transfers into Level 3 (c)
|
4
|
|
|
4
|
|
|
3
|
|
|
|
1
|
|
||||
Transfers out of Level 3 (c)
|
133
|
|
|
71
|
|
|
(10
|
)
|
|
|
1
|
|
||||
Net liabilities assumed in connections with the Merger
|
(37
|
)
|
|
—
|
|
|
—
|
|
|
|
—
|
|
||||
Earn-out provision (d)
|
—
|
|
|
(16
|
)
|
|
—
|
|
|
|
—
|
|
||||
Net liabilities assumed in the Lamar and Forney Acquisition (Note 3) (e)
|
—
|
|
|
—
|
|
|
—
|
|
|
|
(30
|
)
|
||||
Net change (f)
|
(82
|
)
|
|
(136
|
)
|
|
2
|
|
|
|
60
|
|
||||
Net asset (liability) balance at end of period
|
$
|
(135
|
)
|
|
$
|
(53
|
)
|
|
$
|
83
|
|
|
|
$
|
97
|
|
Unrealized valuation gains (losses) relating to instruments held at end of period
|
$
|
(174
|
)
|
|
$
|
(98
|
)
|
|
$
|
28
|
|
|
|
$
|
98
|
|
(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 years ended
December 31, 2018 and 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 agreed to 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 net liabilities assumed in connection with the Merger and 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).
|
18.
|
COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES
|
|
December 31, 2018
|
||||||||||||||||||
|
Derivative Assets
|
|
Derivative Liabilities
|
|
|
||||||||||||||
|
Commodity Contracts
|
|
Interest Rate Swaps
|
|
Commodity Contracts
|
|
Interest Rate Swaps
|
|
Total
|
||||||||||
Current assets
|
$
|
707
|
|
|
$
|
22
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
730
|
|
Noncurrent assets
|
54
|
|
|
55
|
|
|
—
|
|
|
—
|
|
|
109
|
|
|||||
Current liabilities
|
—
|
|
|
—
|
|
|
(1,374
|
)
|
|
(2
|
)
|
|
(1,376
|
)
|
|||||
Noncurrent liabilities
|
—
|
|
|
—
|
|
|
(238
|
)
|
|
(32
|
)
|
|
(270
|
)
|
|||||
Net assets (liabilities)
|
$
|
761
|
|
|
$
|
77
|
|
|
$
|
(1,611
|
)
|
|
$
|
(34
|
)
|
|
$
|
(807
|
)
|
|
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
|
)
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended December 31,
|
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
||||||||||
Derivative (statements of consolidated income (loss) presentation)
|
2018
|
|
2017
|
|
|
|
||||||||||
Commodity contracts (Operating revenues)
|
$
|
(855
|
)
|
|
$
|
56
|
|
|
$
|
(92
|
)
|
|
|
$
|
—
|
|
Commodity contracts (Fuel, purchased power costs and delivery fees)
|
18
|
|
|
6
|
|
|
21
|
|
|
|
—
|
|
||||
Commodity contracts (Net gain from commodity hedging and trading activities)
|
—
|
|
|
—
|
|
|
—
|
|
|
|
194
|
|
||||
Interest rate swaps (Interest expense and related charges)
|
(11
|
)
|
|
2
|
|
|
(11
|
)
|
|
|
—
|
|
||||
Net gain (loss)
|
$
|
(848
|
)
|
|
$
|
64
|
|
|
$
|
(82
|
)
|
|
|
$
|
194
|
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||||||||||||||||||
|
|
Derivative Assets
and Liabilities
|
|
Offsetting Instruments (a)
|
|
Cash Collateral (Received) Pledged (b)
|
|
Net Amounts
|
|
Derivative Assets
and Liabilities
|
|
Offsetting Instruments (a)
|
|
Cash Collateral (Received) Pledged (b)
|
|
Net Amounts
|
||||||||||||||||
Derivative assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Commodity contracts
|
|
$
|
761
|
|
|
$
|
(593
|
)
|
|
$
|
(1
|
)
|
|
$
|
167
|
|
|
$
|
220
|
|
|
$
|
(113
|
)
|
|
$
|
(1
|
)
|
|
$
|
106
|
|
Interest rate swaps
|
|
77
|
|
|
(26
|
)
|
|
—
|
|
|
51
|
|
|
18
|
|
|
—
|
|
|
—
|
|
|
18
|
|
||||||||
Total derivative assets
|
|
838
|
|
|
(619
|
)
|
|
(1
|
)
|
|
218
|
|
|
238
|
|
|
(113
|
)
|
|
(1
|
)
|
|
124
|
|
||||||||
Derivative liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Commodity contracts
|
|
(1,611
|
)
|
|
593
|
|
|
109
|
|
|
(909
|
)
|
|
(316
|
)
|
|
113
|
|
|
1
|
|
|
(202
|
)
|
||||||||
Interest rate swaps
|
|
(34
|
)
|
|
26
|
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total derivative liabilities
|
|
(1,645
|
)
|
|
619
|
|
|
109
|
|
|
(917
|
)
|
|
(316
|
)
|
|
113
|
|
|
1
|
|
|
(202
|
)
|
||||||||
Net amounts
|
|
$
|
(807
|
)
|
|
$
|
—
|
|
|
$
|
108
|
|
|
$
|
(699
|
)
|
|
$
|
(78
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(78
|
)
|
(a)
|
Amounts presented exclude trade accounts receivable and payable related to settled financial instruments.
|
(b)
|
Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin requirements.
|
|
|
December 31, 2018
|
|
December 31, 2017
|
|
|
||||
Derivative type
|
|
Notional Volume
|
|
Unit of Measure
|
||||||
Natural gas (a)
|
|
7,011
|
|
|
1,259
|
|
|
Million MMBtu
|
||
Electricity
|
|
317,572
|
|
|
114,129
|
|
|
GWh
|
||
Financial Transmission Rights (b)
|
|
172,611
|
|
|
110,913
|
|
|
GWh
|
||
Coal
|
|
45
|
|
|
2
|
|
|
Million U.S. tons
|
||
Fuel oil
|
|
60
|
|
|
5
|
|
|
Million gallons
|
||
Uranium
|
|
50
|
|
|
325
|
|
|
Thousand pounds
|
||
Emissions
|
|
10
|
|
|
—
|
|
|
Million tons
|
||
Interest rate swaps – floating/fixed (c)
|
|
$
|
7,717
|
|
|
$
|
3,000
|
|
|
Million U.S. dollars
|
(a)
|
Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas transactions.
|
(b)
|
Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within ISOs or RTOs.
|
(c)
|
Includes notional amounts of interest rate swaps with maturity dates through July 2026.
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Fair value of derivative contract liabilities (a)
|
$
|
(856
|
)
|
|
$
|
(204
|
)
|
Offsetting fair value under netting arrangements (b)
|
218
|
|
|
103
|
|
||
Cash collateral and letters of credit
|
190
|
|
|
41
|
|
||
Liquidity exposure
|
$
|
(448
|
)
|
|
$
|
(60
|
)
|
(a)
|
Excludes fair value of contracts that contain contingent features that do not provide specific amounts to be posted if features are triggered, including provisions that generally provide the right to request additional collateral (material adverse change, performance assurance and other clauses).
|
(b)
|
Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master netting arrangements.
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended
December 31, 2018 |
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
||||||||
Pension costs
|
$
|
14
|
|
|
$
|
6
|
|
|
$
|
2
|
|
|
|
$
|
4
|
|
OPEB costs
|
9
|
|
|
6
|
|
|
2
|
|
|
|
—
|
|
||||
Total benefit costs recognized as expense
|
$
|
23
|
|
|
$
|
12
|
|
|
$
|
4
|
|
|
|
$
|
4
|
|
|
Successor
|
||||||||||
|
Year Ended
December 31, 2018 |
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||||
Assumptions Used to Determine Net Periodic Pension Cost:
|
|
|
|
|
|
||||||
Discount rate (Vistra Energy Plan)
|
3.74
|
%
|
|
4.31
|
%
|
|
3.79
|
%
|
|||
Discount rate (Dynegy Plan & EEI Plan)
|
4.05
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Expected return on plan assets (Vistra Energy Plan)
|
4.56
|
%
|
|
4.86
|
%
|
|
4.89
|
%
|
|||
Expected return on plan assets (Dynegy Plan)
|
5.94
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Expected return on plan assets (EEI Plan)
|
4.74
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Expected rate of compensation increase (Vistra Energy Plan)
|
3.62
|
%
|
|
3.50
|
%
|
|
3.50
|
%
|
|||
Expected rate of compensation increase (Dynegy Plan & EEI Plan)
|
3.50
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Interest crediting rate for cash balance plans (Vistra Energy Plan)
|
3.50
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
|||
Interest crediting rate for cash balance plans (Dynegy Plan & EEI Plan)
|
4.25
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Components of Net Pension Cost:
|
|
|
|
|
|
||||||
Service cost
|
$
|
15
|
|
|
$
|
5
|
|
|
$
|
2
|
|
Interest cost
|
21
|
|
|
6
|
|
|
1
|
|
|||
Expected return on assets
|
(23
|
)
|
|
(5
|
)
|
|
(1
|
)
|
|||
Immediate pension cost
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Net periodic pension cost
|
$
|
14
|
|
|
$
|
6
|
|
|
$
|
2
|
|
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
|
|
|
|
|
|
||||||
Net (gain) loss
|
$
|
14
|
|
|
$
|
3
|
|
|
$
|
(4
|
)
|
Total recognized in net periodic benefit cost and other comprehensive income
|
$
|
28
|
|
|
$
|
9
|
|
|
$
|
(2
|
)
|
Assumptions Used to Determine Benefit Obligations:
|
|
|
|
|
|
||||||
Discount rate (Vistra Plan)
|
4.37
|
%
|
|
3.74
|
%
|
|
4.31
|
%
|
|||
Expected rate of compensation increase (Vistra Plan)
|
3.35
|
%
|
|
3.62
|
%
|
|
3.50
|
%
|
|||
Discount rate (Dynegy Plan)
|
4.37
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Expected rate of compensation increase (Dynegy Plan)
|
3.35
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Interest crediting rate for cash balance plans (Vistra Energy Plan)
|
3.50
|
%
|
|
3.50
|
%
|
|
4.00
|
%
|
|||
Interest crediting rate for cash balance plans (Dynegy Plan & EEI)
|
3.50
|
%
|
|
—
|
%
|
|
—
|
%
|
|
Successor
|
||||||
|
Year Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
Change in Pension Obligation:
|
|
|
|
||||
Projected benefit obligation at beginning of period
|
$
|
163
|
|
|
$
|
144
|
|
Acquisitions
|
502
|
|
|
—
|
|
||
Service cost
|
15
|
|
|
5
|
|
||
Interest cost
|
21
|
|
|
6
|
|
||
Settlement
|
(28
|
)
|
|
—
|
|
||
Actuarial (gain) loss
|
(34
|
)
|
|
13
|
|
||
Benefits paid
|
(24
|
)
|
|
(5
|
)
|
||
Projected benefit obligation at end of year
|
$
|
615
|
|
|
$
|
163
|
|
Accumulated benefit obligation at end of year
|
$
|
611
|
|
|
$
|
157
|
|
Change in Plan Assets:
|
|
|
|
||||
Fair value of assets at beginning of period
|
$
|
128
|
|
|
$
|
117
|
|
Acquisitions
|
428
|
|
|
—
|
|
||
Employer contributions
|
12
|
|
|
—
|
|
||
Settlement
|
(28
|
)
|
|
—
|
|
||
Actual gain (loss) on assets
|
(26
|
)
|
|
16
|
|
||
Benefits paid
|
(24
|
)
|
|
(5
|
)
|
||
Fair value of assets at end of year
|
$
|
490
|
|
|
$
|
128
|
|
Funded Status:
|
|
|
|
||||
Projected pension benefit obligation
|
$
|
(615
|
)
|
|
$
|
(163
|
)
|
Fair value of assets
|
490
|
|
|
128
|
|
||
Funded status at end of year
|
$
|
(125
|
)
|
|
$
|
(35
|
)
|
Amounts Recognized in the Balance Sheet Consist of:
|
|
|
|
||||
Other current liabilities
|
$
|
—
|
|
|
$
|
—
|
|
Other noncurrent liabilities
|
(125
|
)
|
|
(35
|
)
|
||
Net liability recognized
|
$
|
(125
|
)
|
|
$
|
(35
|
)
|
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
|
|
|
|
||||
Net gain (loss)
|
$
|
(13
|
)
|
|
$
|
1
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Pension Plans with PBO and ABO in Excess Of Plan Assets:
|
|
|
|
||||
Projected benefit obligations
|
$
|
615
|
|
|
$
|
163
|
|
Accumulated benefit obligation
|
$
|
611
|
|
|
$
|
157
|
|
Plan assets
|
$
|
490
|
|
|
$
|
128
|
|
|
Target Allocation Ranges
|
|||||||||||||
Asset Category:
|
Vistra Energy Plan
|
|
Dynegy Plan
|
|
EEI Plan
|
|||||||||
Fixed income
|
65
|
%
|
-
|
75%
|
|
45
|
%
|
-
|
55%
|
|
43
|
%
|
-
|
53%
|
Global equity securities
|
16
|
%
|
-
|
24%
|
|
29
|
%
|
-
|
37%
|
|
30
|
%
|
-
|
38%
|
Real estate
|
4
|
%
|
-
|
8%
|
|
8
|
%
|
-
|
12%
|
|
9
|
%
|
-
|
13%
|
Credit strategies
|
3
|
%
|
-
|
7%
|
|
6
|
%
|
-
|
10%
|
|
6
|
%
|
-
|
10%
|
|
Retirement Plan
|
|||||||
|
Expected Long-Term Rate of Return
|
|||||||
Asset Class:
|
Vistra Energy Plan
|
|
Dynegy Plan
|
|
EEI Plan
|
|||
Fixed income securities
|
4.0
|
%
|
|
3.9
|
%
|
|
3.9
|
%
|
Global equity securities
|
7.5
|
%
|
|
7.5
|
%
|
|
7.5
|
%
|
Real estate
|
5.4
|
%
|
|
5.4
|
%
|
|
5.4
|
%
|
Credit strategies
|
6.8
|
%
|
|
6.8
|
%
|
|
6.8
|
%
|
Weighted average
|
4.8
|
%
|
|
5.3
|
%
|
|
5.6
|
%
|
|
December 31,
|
||||||||||||||
|
2018
|
|
2017
|
||||||||||||
|
Level 1
|
|
Level 2
|
|
Total
|
|
Level 2
|
||||||||
Asset Category:
|
|
|
|
|
|
|
|
||||||||
Interest-bearing cash
|
$
|
—
|
|
|
$
|
(6
|
)
|
|
$
|
(6
|
)
|
|
$
|
(7
|
)
|
Fixed income securities:
|
|
|
|
|
|
|
|
||||||||
Corporate bonds (a)
|
57
|
|
|
61
|
|
|
118
|
|
|
65
|
|
||||
U.S. Treasuries
|
—
|
|
|
25
|
|
|
25
|
|
|
29
|
|
||||
Other (b)
|
—
|
|
|
6
|
|
|
6
|
|
|
7
|
|
||||
Total assets categorized as Level 1 or 2
|
57
|
|
|
86
|
|
|
143
|
|
|
94
|
|
||||
Assets measured at net asset value (c):
|
|
|
|
|
|
|
|
||||||||
Commingled trusts
|
|
|
|
|
18
|
|
|
2
|
|
||||||
Equity securities:
|
|
|
|
|
|
|
|
||||||||
U.S.
|
|
|
|
|
119
|
|
|
14
|
|
||||||
International
|
|
|
|
|
73
|
|
|
13
|
|
||||||
Fixed income securities:
|
|
|
|
|
|
|
|
||||||||
Corporate bonds (a)
|
|
|
|
|
137
|
|
|
5
|
|
||||||
Total assets measured at net asset value
|
|
|
|
|
347
|
|
|
34
|
|
||||||
Total assets
|
|
|
|
|
|
|
$
|
490
|
|
|
$
|
128
|
|
(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, 2018
|
|
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)
|
3.67
|
%
|
|
4.11
|
%
|
|
4.00
|
%
|
|||
Discount rate (Oncor Plan)
|
—
|
%
|
|
4.18
|
%
|
|
3.69
|
%
|
|||
Discount rate (Dynegy Plan)
|
4.04
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Expected return on plan assets (EEI Union)
|
5.10
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Expected return on plan assets (EEI Salaried)
|
4.47
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Components of Net Postretirement Benefit Cost:
|
|
|
|
|
|
||||||
Service cost
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
1
|
|
Interest cost
|
5
|
|
|
4
|
|
|
1
|
|
|||
Expected return on plan assets
|
(1
|
)
|
|
—
|
|
|
—
|
|
|||
Amortization of unrecognized amounts
|
3
|
|
|
—
|
|
|
—
|
|
|||
Plan amendments (a)
|
—
|
|
|
—
|
|
|
(4
|
)
|
|||
Net periodic OPEB cost (income)
|
$
|
9
|
|
|
$
|
6
|
|
|
$
|
(2
|
)
|
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income:
|
|
|
|
|
|
||||||
Net (gain) loss and prior service (credit) cost
|
$
|
(6
|
)
|
|
$
|
26
|
|
|
$
|
(5
|
)
|
Total recognized in net periodic benefit cost and other comprehensive income
|
$
|
3
|
|
|
$
|
32
|
|
|
$
|
(7
|
)
|
Assumptions Used to Determine Benefit Obligations at Period End:
|
|
|
|
|
|
||||||
Discount rate (Vistra Energy Plan)
|
4.35
|
%
|
|
3.67
|
%
|
|
4.11
|
%
|
|||
Discount rate (Split-Participant Plan)
|
4.35
|
%
|
|
3.67
|
%
|
|
—
|
%
|
|||
Discount rate (Oncor Plan)
|
—
|
%
|
|
—
|
%
|
|
4.18
|
%
|
|||
Discount rate (Dynegy Plan)
|
4.35
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Expected return on plan assets (EEI Union)
|
5.36
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Expected return on plan assets (EEI Salaried)
|
4.70
|
%
|
|
—
|
%
|
|
—
|
%
|
(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.
|
|
Year Ended December 31,
|
||||||
|
2018
|
|
2017
|
||||
Change in Postretirement Benefit Obligation:
|
|
|
|
||||
Benefit obligation at beginning of year
|
$
|
115
|
|
|
$
|
88
|
|
Acquisition
|
37
|
|
|
—
|
|
||
Service cost
|
2
|
|
|
2
|
|
||
Interest cost
|
5
|
|
|
4
|
|
||
Participant contributions
|
2
|
|
|
2
|
|
||
Plan amendments (a)
|
4
|
|
|
11
|
|
||
Actuarial (gain) loss
|
(9
|
)
|
|
15
|
|
||
Benefits paid
|
(12
|
)
|
|
(7
|
)
|
||
Benefit obligation at end of year
|
$
|
144
|
|
|
$
|
115
|
|
Change in Plan Assets:
|
|
|
|
||||
Fair value of assets at beginning of year
|
$
|
—
|
|
|
$
|
—
|
|
Acquisition
|
32
|
|
|
—
|
|
||
Employer contributions
|
8
|
|
|
5
|
|
||
Participant contributions
|
2
|
|
|
2
|
|
||
Benefits paid
|
(12
|
)
|
|
(7
|
)
|
||
Actual loss on assets
|
(1
|
)
|
|
—
|
|
||
Fair value of assets at end of year
|
$
|
29
|
|
|
$
|
—
|
|
Funded Status:
|
|
|
|
||||
Benefit obligation
|
$
|
(144
|
)
|
|
$
|
(115
|
)
|
Fair value of assets
|
29
|
|
|
—
|
|
||
Funded status at end of year
|
$
|
(115
|
)
|
|
$
|
(115
|
)
|
Amounts Recognized on the Balance Sheet Consist of:
|
|
|
|
||||
Other noncurrent assets
|
$
|
14
|
|
|
$
|
—
|
|
Other current liabilities
|
$
|
(8
|
)
|
|
$
|
(6
|
)
|
Other noncurrent liabilities
|
(121
|
)
|
|
(109
|
)
|
||
Net liability recognized
|
$
|
(115
|
)
|
|
$
|
(115
|
)
|
Amounts Recognized in Accumulated Other Comprehensive Income Consist of:
|
|
|
|
||||
Net loss and prior service cost
|
$
|
15
|
|
|
$
|
20
|
|
(a)
|
For the year ended December 31, 2018, plan amendments relate to changes in Dynegy plans and retiree medical cost structure. For the year ended December 31, 2017, plan amendments relate to the contractual arrangement with Oncor covering Split Participants.
|
|
Successor
|
||||
|
December 31, 2018
|
|
December 31, 2017
|
||
Assumed Health Care Cost Trend Rates-Not Medicare Eligible:
|
|
|
|
||
Health care cost trend rate assumed for next year
|
6.70
|
%
|
|
7.00
|
%
|
Rate to which the cost trend is expected to decline (the ultimate trend rate)
|
4.50
|
%
|
|
4.50
|
%
|
Year that the rate reaches the ultimate trend rate
|
2026
|
|
|
2026
|
|
Assumed Health Care Cost Trend Rates-Medicare Eligible:
|
|
|
|
||
Health care cost trend rate assumed for next year
|
9.90
|
%
|
|
10.66
|
%
|
Rate to which the cost trend is expected to decline (the ultimate trend rate)
|
4.50
|
%
|
|
4.50
|
%
|
Year that the rate reaches the ultimate trend rate
|
2027
|
|
|
2026
|
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
2024-28
|
||||||||||||
Pension benefits
|
$
|
46
|
|
|
$
|
45
|
|
|
$
|
46
|
|
|
$
|
46
|
|
|
$
|
46
|
|
|
$
|
216
|
|
OPEB
|
$
|
10
|
|
|
$
|
11
|
|
|
$
|
11
|
|
|
$
|
11
|
|
|
$
|
11
|
|
|
$
|
49
|
|
Instrument Type
|
Dynegy Awards Prior to the Merger Date
|
Vistra Awards Converted at the Merger Date
|
Fair Value of Awards (a)
|
||||
Stock Options
|
4,096,027
|
|
2,670,610
|
|
$
|
10
|
|
Restricted Stock Units
|
5,718,148
|
|
3,056,689
|
|
61
|
|
|
Performance Units
|
1,538,133
|
|
938,721
|
|
18
|
|
|
Total
|
|
|
$
|
89
|
|
(a)
|
$26 million
was attributable to pre-combination service and considered part of the purchase price (see Note
2
).
$33 million
was recognized immediately as compensation expense due to accelerated vesting as a result of the Merger.
$30 million
will be amortized as compensation expense over the remaining service period and is recorded in additional paid in capital in the consolidated balance sheet.
|
|
Successor
|
||||||||||
|
Year Ended December 31,
|
|
Period from October 3, 2016
through December 31, 2016 |
||||||||
|
2018
|
|
2017
|
|
|||||||
Total stock-based compensation expense
|
$
|
73
|
|
|
$
|
19
|
|
|
$
|
3
|
|
Income tax benefit
|
(15
|
)
|
|
(7
|
)
|
|
(1
|
)
|
|||
Stock based-compensation expense, net of tax
|
$
|
58
|
|
|
$
|
12
|
|
|
$
|
2
|
|
|
Successor
|
|||||||||||
|
Year Ended December 31, 2018
|
|||||||||||
|
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
|
8,136
|
|
|
$
|
14.44
|
|
|
9.0
|
|
$
|
32.4
|
|
Awards converted at Merger Date
|
2,671
|
|
|
$
|
23.19
|
|
|
|
|
|
||
Granted
|
5,268
|
|
|
$
|
19.67
|
|
|
|
|
|
|
|
Exercised
|
(1,082
|
)
|
|
$
|
13.91
|
|
|
|
|
|
|
|
Forfeited or expired
|
(494
|
)
|
|
$
|
15.14
|
|
|
|
|
|
|
|
Total outstanding at end of period
|
14,499
|
|
|
$
|
17.97
|
|
|
7.3
|
|
$
|
85.1
|
|
Exercisable at December 31, 2018
|
4,696
|
|
|
$
|
18.88
|
|
|
5.2
|
|
$
|
32.6
|
|
|
Successor
|
|||||||||||
|
Year Ended December 31, 2018
|
|||||||||||
|
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
|
2,375
|
|
|
$
|
16.91
|
|
|
1.9
|
|
$
|
43.5
|
|
Awards converted at Merger Date
|
3,057
|
|
|
$
|
15.52
|
|
|
|
|
|
||
Granted
|
133
|
|
|
$
|
22.41
|
|
|
|
|
|
|
|
Exercised
|
(2,114
|
)
|
|
$
|
15.48
|
|
|
|
|
|
|
|
Forfeited or expired
|
(225
|
)
|
|
$
|
16.69
|
|
|
|
|
|
|
|
Total outstanding at end of period
|
3,226
|
|
|
$
|
16.77
|
|
|
1.1
|
|
$
|
73.8
|
|
Expected to vest
|
3,222
|
|
|
$
|
16.85
|
|
|
1.0
|
|
$
|
73.7
|
|
21.
|
RELATED PARTY TRANSACTIONS
|
•
|
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
for the Predecessor period from January 1, 2016 through October 2, 2016.
|
•
|
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
for the Predecessor period from January 1, 2016 through October 2, 2016.
|
•
|
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
for the Predecessor period from January 1, 2016 through October 2, 2016. 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, our Predecessor made income tax payments to EFH Corp. totaling
$22 million
.
|
•
|
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 debt or debt securities issued by our Predecessor in open market transactions or through loan syndications.
|
22.
|
SEGMENT INFORMATION
|
|
Successor
|
||||||||||
|
Year Ended
December 31, 2018 |
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||||
Operating revenues (a)
|
|
|
|
|
|
||||||
Retail
|
$
|
5,597
|
|
|
$
|
4,058
|
|
|
$
|
912
|
|
ERCOT
|
2,634
|
|
|
1,794
|
|
|
212
|
|
|||
PJM
|
1,725
|
|
|
—
|
|
|
—
|
|
|||
NY/NE
|
817
|
|
|
—
|
|
|
—
|
|
|||
MISO
|
720
|
|
|
—
|
|
|
—
|
|
|||
Asset Closure
|
50
|
|
|
964
|
|
|
238
|
|
|||
Corporate and Other (b)
|
208
|
|
|
—
|
|
|
—
|
|
|||
Eliminations
|
(2,607
|
)
|
|
(1,386
|
)
|
|
(171
|
)
|
|||
Consolidated operating revenues
|
$
|
9,144
|
|
|
$
|
5,430
|
|
|
$
|
1,191
|
|
Depreciation and amortization
|
|
|
|
|
|
||||||
Retail
|
$
|
(318
|
)
|
|
$
|
(430
|
)
|
|
$
|
(153
|
)
|
ERCOT
|
(416
|
)
|
|
(229
|
)
|
|
(53
|
)
|
|||
PJM
|
(413
|
)
|
|
—
|
|
|
—
|
|
|||
NY/NE
|
(152
|
)
|
|
—
|
|
|
—
|
|
|||
MISO
|
(9
|
)
|
|
—
|
|
|
—
|
|
|||
Asset Closure
|
—
|
|
|
(1
|
)
|
|
—
|
|
|||
Corporate and Other (b)
|
(86
|
)
|
|
(40
|
)
|
|
(11
|
)
|
|||
Eliminations
|
|
|
|
1
|
|
|
$
|
1
|
|
||
Consolidated depreciation and amortization
|
$
|
(1,394
|
)
|
|
$
|
(699
|
)
|
|
$
|
(216
|
)
|
Operating income (loss)
|
|
|
|
|
|
||||||
Retail
|
$
|
690
|
|
|
$
|
461
|
|
|
$
|
111
|
|
ERCOT
|
(70
|
)
|
|
(118
|
)
|
|
(271
|
)
|
|||
PJM
|
100
|
|
|
—
|
|
|
—
|
|
|||
NY/NE
|
70
|
|
|
—
|
|
|
—
|
|
|||
MISO
|
36
|
|
|
—
|
|
|
—
|
|
|||
Asset Closure
|
(50
|
)
|
|
(68
|
)
|
|
16
|
|
|||
Corporate and Other (b)
|
(281
|
)
|
|
(78
|
)
|
|
(17
|
)
|
|||
Eliminations
|
(4
|
)
|
|
1
|
|
|
—
|
|
|||
Consolidated operating income (loss)
|
$
|
491
|
|
|
$
|
198
|
|
|
$
|
(161
|
)
|
Interest expense and related charges
|
|
|
|
|
|
||||||
Retail
|
$
|
(7
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
ERCOT
|
(12
|
)
|
|
(21
|
)
|
|
1
|
|
|||
PJM
|
(8
|
)
|
|
—
|
|
|
—
|
|
|||
NY/NE
|
(2
|
)
|
|
—
|
|
|
—
|
|
|||
MISO
|
(1
|
)
|
|
—
|
|
|
—
|
|
|||
Corporate and Other (b)
|
(613
|
)
|
|
(252
|
)
|
|
(66
|
)
|
|||
Eliminations
|
71
|
|
|
80
|
|
|
5
|
|
|||
Consolidated interest expense and related charges
|
$
|
(572
|
)
|
|
$
|
(193
|
)
|
|
$
|
(60
|
)
|
|
Successor
|
||||||||||
|
Year Ended
December 31, 2018 |
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||||
Income tax (expense) benefit (all Corporate and Other)
|
$
|
45
|
|
|
$
|
(504
|
)
|
|
$
|
70
|
|
Net income (loss)
|
|
|
|
|
|
||||||
Retail
|
$
|
712
|
|
|
$
|
495
|
|
|
$
|
114
|
|
ERCOT
|
(55
|
)
|
|
(114
|
)
|
|
(268
|
)
|
|||
PJM
|
100
|
|
|
—
|
|
|
—
|
|
|||
NY/NE
|
79
|
|
|
—
|
|
|
—
|
|
|||
MISO
|
35
|
|
|
—
|
|
|
—
|
|
|||
Asset Closure
|
(49
|
)
|
|
(63
|
)
|
|
17
|
|
|||
Corporate and Other (b)
|
(876
|
)
|
|
(573
|
)
|
|
(26
|
)
|
|||
Eliminations
|
(2
|
)
|
|
1
|
|
|
—
|
|
|||
Consolidated net income (loss)
|
$
|
(56
|
)
|
|
$
|
(254
|
)
|
|
$
|
(163
|
)
|
Capital expenditures, excluding LTSA
|
|
|
|
|
|
||||||
Retail
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
5
|
|
ERCOT
|
283
|
|
|
150
|
|
|
84
|
|
|||
PJM
|
41
|
|
|
—
|
|
|
—
|
|
|||
NY/NE
|
10
|
|
|
—
|
|
|
—
|
|
|||
MISO
|
3
|
|
|
—
|
|
|
—
|
|
|||
Corporate and Other (b)
|
58
|
|
|
26
|
|
|
—
|
|
|||
Consolidated capital expenditures
|
$
|
396
|
|
|
$
|
176
|
|
|
$
|
89
|
|
(a)
|
The following unrealized net gains (losses) from mark-to-market valuations of commodity positions are included in operating revenues:
|
|
Successor
|
||||||||||
|
Year Ended
December 31, 2018 |
|
Year Ended
December 31, 2017 |
|
Period from October 3, 2016
through December 31, 2016 |
||||||
Retail
|
$
|
(12
|
)
|
|
$
|
18
|
|
|
$
|
(6
|
)
|
ERCOT
|
(483
|
)
|
|
(305
|
)
|
|
(295
|
)
|
|||
PJM
|
(50
|
)
|
|
—
|
|
|
—
|
|
|||
NY/NE
|
(40
|
)
|
|
—
|
|
|
—
|
|
|||
MISO
|
3
|
|
|
—
|
|
|
—
|
|
|||
Corporate and Other (b)
|
(15
|
)
|
|
—
|
|
|
—
|
|
|||
Eliminations (1)
|
217
|
|
|
154
|
|
|
113
|
|
|||
Consolidated unrealized net losses from mark-to-market valuations of commodity positions included in operating revenues
|
$
|
(380
|
)
|
|
$
|
(133
|
)
|
|
$
|
(188
|
)
|
(1)
|
Amounts offset in fuel, purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results.
|
(b)
|
Other includes CAISO operations. Income tax expense is not reflected in net income of the segments but is reflected entirely in Corporate net income.
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Total assets
|
|
|
|
||||
Retail
|
$
|
7,699
|
|
|
$
|
6,156
|
|
ERCOT
|
9,347
|
|
|
6,821
|
|
||
PJM
|
7,188
|
|
|
—
|
|
||
NY/NE
|
2,722
|
|
|
—
|
|
||
MISO
|
836
|
|
|
—
|
|
||
Asset Closure
|
254
|
|
|
248
|
|
||
Corporate and Other and Eliminations
|
(2,022
|
)
|
|
1,375
|
|
||
Consolidated total assets
|
$
|
26,024
|
|
|
$
|
14,600
|
|
23.
|
SUPPLEMENTARY FINANCIAL INFORMATION
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended December 31,
|
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
||||||||||
|
2018
|
|
2017
|
|
|
|
||||||||||
Other income:
|
|
|
|
|
|
|
|
|
||||||||
Office space sublease rental income (a)
|
$
|
8
|
|
|
$
|
11
|
|
|
$
|
2
|
|
|
|
$
|
—
|
|
Mineral rights royalty income (b)
|
—
|
|
|
3
|
|
|
1
|
|
|
|
3
|
|
||||
Sale of land (b)
|
3
|
|
|
4
|
|
|
—
|
|
|
|
—
|
|
||||
Curtailment gain on employee benefit plans (a)
|
—
|
|
|
—
|
|
|
4
|
|
|
|
—
|
|
||||
Insurance settlement
|
16
|
|
|
—
|
|
|
—
|
|
|
|
9
|
|
||||
Interest income
|
18
|
|
|
15
|
|
|
1
|
|
|
|
3
|
|
||||
All other
|
2
|
|
|
4
|
|
|
2
|
|
|
|
4
|
|
||||
Total other income
|
$
|
47
|
|
|
$
|
37
|
|
|
$
|
10
|
|
|
|
$
|
19
|
|
Other deductions:
|
|
|
|
|
|
|
|
|
||||||||
Write-off of generation equipment (b)
|
—
|
|
|
2
|
|
|
—
|
|
|
|
45
|
|
||||
Adjustment to asbestos liability
|
—
|
|
|
—
|
|
|
—
|
|
|
|
11
|
|
||||
All other
|
5
|
|
|
3
|
|
|
—
|
|
|
|
19
|
|
||||
Total other deductions
|
$
|
5
|
|
|
$
|
5
|
|
|
$
|
—
|
|
|
|
$
|
75
|
|
(a)
|
Reported in Corporate and Other non-segment (Successor period only).
|
(b)
|
Reported in ERCOT segment (Successor period only).
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||
|
Current
Assets |
|
Noncurrent Assets
|
|
Current
Assets |
|
Noncurrent Assets
|
||||||||
Amounts related to the Vistra Operations Credit Facilities (Note 14)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
500
|
|
Amounts related to restructuring escrow accounts
|
57
|
|
|
—
|
|
|
59
|
|
|
—
|
|
||||
Total restricted cash
|
$
|
57
|
|
|
$
|
—
|
|
|
$
|
59
|
|
|
$
|
500
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Wholesale and retail trade accounts receivable
|
$
|
1,106
|
|
|
$
|
596
|
|
Allowance for uncollectible accounts
|
(19
|
)
|
|
(14
|
)
|
||
Trade accounts receivable — net
|
$
|
1,087
|
|
|
$
|
582
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended December 31,
|
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
||||||||||
|
2018
|
|
2017
|
|
|
|
||||||||||
Allowance for uncollectible accounts receivable at beginning of period
|
$
|
14
|
|
|
$
|
10
|
|
|
$
|
—
|
|
|
|
$
|
9
|
|
Increase for bad debt expense
|
56
|
|
|
43
|
|
|
10
|
|
|
|
20
|
|
||||
Decrease for account write-offs
|
(51
|
)
|
|
(39
|
)
|
|
—
|
|
|
|
(16
|
)
|
||||
Allowance for uncollectible accounts receivable at end of period
|
$
|
19
|
|
|
$
|
14
|
|
|
$
|
10
|
|
|
|
$
|
13
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Materials and supplies
|
$
|
286
|
|
|
$
|
149
|
|
Fuel stock
|
115
|
|
|
83
|
|
||
Natural gas in storage
|
11
|
|
|
21
|
|
||
Total inventories
|
$
|
412
|
|
|
$
|
253
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Nuclear plant decommissioning trust
|
$
|
1,170
|
|
|
$
|
1,188
|
|
Assets related to employee benefit plans (Note 19)
|
31
|
|
|
—
|
|
||
Land
|
49
|
|
|
49
|
|
||
Miscellaneous other
|
—
|
|
|
3
|
|
||
Total other investments
|
$
|
1,250
|
|
|
$
|
1,240
|
|
|
December 31, 2018
|
||||||||||||||
|
Cost (a)
|
|
Unrealized gain
|
|
Unrealized loss
|
|
Fair market value
|
||||||||
Debt securities (b)
|
$
|
444
|
|
|
$
|
7
|
|
|
$
|
(8
|
)
|
|
$
|
443
|
|
Equity securities (c)
|
280
|
|
|
448
|
|
|
(1
|
)
|
|
727
|
|
||||
Total
|
$
|
724
|
|
|
$
|
455
|
|
|
$
|
(9
|
)
|
|
$
|
1,170
|
|
|
December 31, 2017
|
||||||||||||||
|
Cost (a)
|
|
Unrealized gain
|
|
Unrealized loss
|
|
Fair market value
|
||||||||
Debt securities (b)
|
$
|
418
|
|
|
$
|
14
|
|
|
$
|
(2
|
)
|
|
$
|
430
|
|
Equity securities (c)
|
265
|
|
|
495
|
|
|
(2
|
)
|
|
758
|
|
||||
Total
|
$
|
683
|
|
|
$
|
509
|
|
|
$
|
(4
|
)
|
|
$
|
1,188
|
|
(a)
|
Includes realized gains and losses on securities sold.
|
(b)
|
The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody's Investors Services, Inc. The debt securities are heavily weighted with government and municipal bonds and investment grade corporate bonds. The debt securities had an average coupon rate of
3.69%
and
3.55%
at
December 31, 2018 and 2017
, respectively, and an average maturity of
8 years
and
9 years
at
December 31, 2018 and 2017
, respectively.
|
(c)
|
The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index for U.S. equity investments and the MSCI Inc. EAFE Index for non-U.S. equity investments.
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended December 31,
|
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
||||||||||
|
2018
|
|
2017
|
|
|
|
||||||||||
Realized gains
|
$
|
2
|
|
|
$
|
9
|
|
|
$
|
1
|
|
|
|
$
|
3
|
|
Realized losses
|
$
|
(9
|
)
|
|
$
|
(11
|
)
|
|
$
|
—
|
|
|
|
$
|
(2
|
)
|
Proceeds from sales of securities
|
$
|
252
|
|
|
$
|
252
|
|
|
$
|
25
|
|
|
|
$
|
201
|
|
Investments in securities
|
$
|
(274
|
)
|
|
$
|
(272
|
)
|
|
$
|
(30
|
)
|
|
|
$
|
(215
|
)
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Power generation and structures
|
$
|
14,604
|
|
|
$
|
3,966
|
|
Land
|
642
|
|
|
540
|
|
||
Office and other equipment
|
182
|
|
|
120
|
|
||
Total
|
15,428
|
|
|
4,626
|
|
||
Less accumulated depreciation
|
(1,284
|
)
|
|
(282
|
)
|
||
Net of accumulated depreciation
|
14,144
|
|
|
4,344
|
|
||
Nuclear fuel (net of accumulated amortization of $189 million and $111 million)
|
191
|
|
|
158
|
|
||
Construction work in progress
|
277
|
|
|
318
|
|
||
Property, plant and equipment — net
|
$
|
14,612
|
|
|
$
|
4,820
|
|
|
Nuclear Plant Decommissioning
|
|
Mining Land Reclamation
|
|
Coal Ash and Other
|
|
Total
|
||||||||
Successor:
|
|
|
|
|
|
|
|
||||||||
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
|
|
||||
Additions:
|
|
|
|
|
|
|
|
||||||||
Accretion
|
43
|
|
|
22
|
|
|
28
|
|
|
93
|
|
||||
Adjustment for change in estimates
|
—
|
|
|
56
|
|
|
(89
|
)
|
|
(33
|
)
|
||||
Obligations assumed in the Merger
|
—
|
|
|
2
|
|
|
475
|
|
|
477
|
|
||||
Reductions:
|
|
|
|
|
|
|
|
||||||||
Payments
|
—
|
|
|
(76
|
)
|
|
(24
|
)
|
|
(100
|
)
|
||||
Liability at December 31, 2018
|
1,276
|
|
|
442
|
|
|
655
|
|
|
2,373
|
|
||||
Less amounts due currently
|
—
|
|
|
(106
|
)
|
|
(50
|
)
|
|
(156
|
)
|
||||
Noncurrent liability at December 31, 2018
|
$
|
1,276
|
|
|
$
|
336
|
|
|
$
|
605
|
|
|
$
|
2,217
|
|
(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,
|
||||||
|
2018
|
|
2017
|
||||
Retirement and other employee benefits
|
$
|
270
|
|
|
$
|
166
|
|
Uncertain tax positions, including accrued interest
|
4
|
|
|
—
|
|
||
Other
|
66
|
|
|
54
|
|
||
Total other noncurrent liabilities and deferred credits
|
$
|
340
|
|
|
$
|
220
|
|
|
|
|
December 31, 2018
|
|
December 31, 2017
|
||||||||||||
Long-Term Debt (see Note 14):
|
Fair Value Hierarchy
|
|
Carrying Amount
|
|
Fair
Value
|
|
Carrying Amount
|
|
Fair
Value
|
||||||||
Long-term debt under the Vistra Operations Credit Facilities
|
Level 2
|
|
$
|
5,820
|
|
|
$
|
5,599
|
|
|
$
|
4,323
|
|
|
$
|
4,334
|
|
Vistra Operations Senior Notes
|
Level 2
|
|
987
|
|
|
963
|
|
|
—
|
|
|
—
|
|
||||
Vistra Energy Senior Notes
|
Level 2
|
|
3,819
|
|
|
3,765
|
|
|
—
|
|
|
—
|
|
||||
7.000% Amortizing Notes
|
Level 2
|
|
23
|
|
|
24
|
|
|
—
|
|
|
—
|
|
||||
Forward Capacity Agreements
|
Level 3
|
|
221
|
|
|
221
|
|
|
—
|
|
|
—
|
|
||||
Equipment Financing Agreements
|
Level 3
|
|
102
|
|
|
102
|
|
|
—
|
|
|
—
|
|
||||
Mandatorily redeemable subsidiary preferred stock
|
Level 2
|
|
70
|
|
|
70
|
|
|
70
|
|
|
70
|
|
||||
Building Financing
|
Level 2
|
|
23
|
|
|
21
|
|
|
30
|
|
|
27
|
|
|
December 31,
|
||||||
|
2018
|
|
2017
|
||||
Cash and cash equivalents
|
$
|
636
|
|
|
$
|
1,487
|
|
Restricted cash included in current assets
|
57
|
|
|
59
|
|
||
Restricted cash included in noncurrent assets
|
—
|
|
|
500
|
|
||
Total cash, cash equivalents and restricted cash
|
$
|
693
|
|
|
$
|
2,046
|
|
|
Successor
|
|
|
Predecessor
|
||||||||||||
|
Year Ended December 31,
|
|
Period from October 3, 2016
through December 31, 2016 |
|
|
Period from January 1, 2016
through October 2, 2016 |
||||||||||
|
2018
|
|
2017
|
|
|
|
||||||||||
Cash payments related to:
|
|
|
|
|
|
|
|
|
||||||||
Interest paid (a)
|
$
|
651
|
|
|
$
|
245
|
|
|
$
|
19
|
|
|
|
$
|
1,064
|
|
Capitalized interest
|
(12
|
)
|
|
(7
|
)
|
|
(3
|
)
|
|
|
(9
|
)
|
||||
Interest paid (net of capitalized interest) (a)
|
$
|
639
|
|
|
$
|
238
|
|
|
$
|
16
|
|
|
|
$
|
1,055
|
|
Income taxes
|
$
|
67
|
|
|
$
|
63
|
|
|
$
|
(2
|
)
|
|
|
$
|
22
|
|
Reorganization items (b)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
104
|
|
Noncash investing and financing activities:
|
|
|
|
|
|
|
|
|
||||||||
Construction expenditures (c)
|
$
|
79
|
|
|
$
|
12
|
|
|
$
|
1
|
|
|
|
$
|
53
|
|
Vistra Energy common stock issued in the Merger (Notes 2 and 16)
|
$
|
2,245
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
(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.
|
|
Successor
|
||||||||||||||
|
Quarter Ended
|
||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31 (b)
|
||||||||
2018(a):
|
|
|
|
|
|
|
|
||||||||
Operating revenues
|
$
|
765
|
|
|
$
|
2,574
|
|
|
$
|
3,243
|
|
|
$
|
2,562
|
|
Operating income (loss)
|
$
|
(394
|
)
|
|
$
|
231
|
|
|
$
|
650
|
|
|
$
|
4
|
|
Net income (loss)
|
$
|
(306
|
)
|
|
$
|
105
|
|
|
$
|
331
|
|
|
$
|
(186
|
)
|
Net income (loss) attributable to Vistra Energy
|
$
|
(306
|
)
|
|
$
|
108
|
|
|
$
|
330
|
|
|
$
|
(186
|
)
|
Net income (loss) per weighted average share of common stock outstanding — basic
|
$
|
(0.71
|
)
|
|
$
|
0.21
|
|
|
$
|
0.62
|
|
|
$
|
(0.35
|
)
|
Net income (loss) per weighted average share of common stock outstanding — diluted
|
$
|
(0.71
|
)
|
|
$
|
0.20
|
|
|
$
|
0.61
|
|
|
$
|
(0.35
|
)
|
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) attributable to Vistra Energy
|
$
|
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
|
)
|
(a)
|
For the year ended December 31, 2018, reflects the results of operations acquired in the Merger.
|
(b)
|
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
9
), partially offset by
$117 million
of impacts of the TRA.
|
24.
|
SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION
|
|
Parent (Issuer)
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Operating revenues
|
$
|
—
|
|
|
$
|
9,043
|
|
|
$
|
174
|
|
|
$
|
(73
|
)
|
|
$
|
9,144
|
|
Fuel, purchased power costs and delivery fees
|
—
|
|
|
(4,968
|
)
|
|
(92
|
)
|
|
24
|
|
|
(5,036
|
)
|
|||||
Operating costs
|
—
|
|
|
(1,255
|
)
|
|
(42
|
)
|
|
—
|
|
|
(1,297
|
)
|
|||||
Depreciation and amortization
|
—
|
|
|
(1,337
|
)
|
|
(57
|
)
|
|
—
|
|
|
(1,394
|
)
|
|||||
Selling, general and administrative expenses
|
(266
|
)
|
|
(660
|
)
|
|
(49
|
)
|
|
49
|
|
|
(926
|
)
|
|||||
Operating income (loss)
|
(266
|
)
|
|
823
|
|
|
(66
|
)
|
|
—
|
|
|
491
|
|
|||||
Other income
|
9
|
|
|
41
|
|
|
—
|
|
|
(3
|
)
|
|
47
|
|
|||||
Other deductions
|
—
|
|
|
(6
|
)
|
|
1
|
|
|
—
|
|
|
(5
|
)
|
|||||
Interest expense and related charges
|
(257
|
)
|
|
(309
|
)
|
|
(9
|
)
|
|
3
|
|
|
(572
|
)
|
|||||
Impacts of Tax Receivable Agreement
|
(79
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(79
|
)
|
|||||
Equity in earnings of unconsolidated investment
|
—
|
|
|
17
|
|
|
—
|
|
|
—
|
|
|
17
|
|
|||||
Income (loss) before income taxes
|
(593
|
)
|
|
566
|
|
|
(74
|
)
|
|
—
|
|
|
(101
|
)
|
|||||
Income tax expense
|
282
|
|
|
(284
|
)
|
|
47
|
|
|
—
|
|
|
45
|
|
|||||
Equity in earnings (loss) of subsidiaries, net of tax
|
257
|
|
|
(25
|
)
|
|
—
|
|
|
(232
|
)
|
|
—
|
|
|||||
Net income (loss)
|
(54
|
)
|
|
257
|
|
|
(27
|
)
|
|
(232
|
)
|
|
(56
|
)
|
|||||
Net loss attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|||||
Net income (loss) attributable to Vistra Energy
|
$
|
(54
|
)
|
|
$
|
257
|
|
|
$
|
(25
|
)
|
|
$
|
(232
|
)
|
|
$
|
(54
|
)
|
|
Parent (Issuer)
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Operating revenues
|
$
|
—
|
|
|
$
|
5,430
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5,430
|
|
Fuel, purchased power costs and delivery fees
|
—
|
|
|
(2,935
|
)
|
|
—
|
|
|
—
|
|
|
(2,935
|
)
|
|||||
Operating costs
|
—
|
|
|
(973
|
)
|
|
—
|
|
|
—
|
|
|
(973
|
)
|
|||||
Depreciation and amortization
|
—
|
|
|
(699
|
)
|
|
—
|
|
|
—
|
|
|
(699
|
)
|
|||||
Selling, general and administrative expenses
|
(47
|
)
|
|
(553
|
)
|
|
—
|
|
|
—
|
|
|
(600
|
)
|
|||||
Impairment of long-lived assets
|
—
|
|
|
(25
|
)
|
|
—
|
|
|
—
|
|
|
(25
|
)
|
|||||
Operating income (loss)
|
(47
|
)
|
|
245
|
|
|
—
|
|
|
—
|
|
|
198
|
|
|||||
Other income
|
—
|
|
|
37
|
|
|
—
|
|
|
—
|
|
|
37
|
|
|||||
Other deductions
|
—
|
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
|||||
Interest Income
|
4
|
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Interest expense and related charges
|
—
|
|
|
(193
|
)
|
|
—
|
|
|
—
|
|
|
(193
|
)
|
|||||
Impacts of Tax Receivable Agreement
|
213
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
213
|
|
|||||
Income before income taxes
|
170
|
|
|
80
|
|
|
—
|
|
|
—
|
|
|
250
|
|
|||||
Income tax benefit (expense)
|
80
|
|
|
(584
|
)
|
|
—
|
|
|
—
|
|
|
(504
|
)
|
|||||
Equity in earnings (losses) of subsidiaries, net of tax
|
(504
|
)
|
|
—
|
|
|
—
|
|
|
504
|
|
|
—
|
|
|||||
Net income (loss)
|
$
|
(254
|
)
|
|
$
|
(504
|
)
|
|
$
|
—
|
|
|
$
|
504
|
|
|
$
|
(254
|
)
|
|
Parent (Issuer)
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Operating revenues
|
$
|
—
|
|
|
$
|
1,191
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,191
|
|
Fuel, purchased power costs and delivery fees
|
—
|
|
|
(720
|
)
|
|
—
|
|
|
—
|
|
|
(720
|
)
|
|||||
Operating costs
|
—
|
|
|
(208
|
)
|
|
—
|
|
|
—
|
|
|
(208
|
)
|
|||||
Depreciation and amortization
|
—
|
|
|
(216
|
)
|
|
—
|
|
|
—
|
|
|
(216
|
)
|
|||||
Selling, general and administrative expenses
|
(7
|
)
|
|
(201
|
)
|
|
—
|
|
|
—
|
|
|
(208
|
)
|
|||||
Operating income (loss)
|
(7
|
)
|
|
(154
|
)
|
|
—
|
|
|
—
|
|
|
(161
|
)
|
|||||
Other income
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|||||
Interest expense and related charges
|
—
|
|
|
(60
|
)
|
|
—
|
|
|
—
|
|
|
(60
|
)
|
|||||
Impacts of Tax Receivable Agreement
|
(22
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(22
|
)
|
|||||
Income (loss) before income taxes
|
(29
|
)
|
|
(204
|
)
|
|
—
|
|
|
—
|
|
|
(233
|
)
|
|||||
Income tax expense
|
(204
|
)
|
|
274
|
|
|
—
|
|
|
—
|
|
|
70
|
|
|||||
Equity in earnings (loss) of subsidiaries, net of tax
|
70
|
|
|
—
|
|
|
—
|
|
|
(70
|
)
|
|
—
|
|
|||||
Net income (loss)
|
(163
|
)
|
|
70
|
|
|
—
|
|
|
(70
|
)
|
|
(163
|
)
|
|
Parent (Issuer)
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Net income (loss)
|
$
|
(54
|
)
|
|
$
|
257
|
|
|
$
|
(27
|
)
|
|
$
|
(232
|
)
|
|
$
|
(56
|
)
|
Other comprehensive income (loss), net of tax effects:
|
|
|
|
|
|
|
|
|
|
||||||||||
Effect related to pension and other retirement benefit obligations
|
—
|
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|||||
Adoption of accounting standard
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Total other comprehensive income
|
1
|
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
|||||
Comprehensive income (loss)
|
(53
|
)
|
|
251
|
|
|
(27
|
)
|
|
(232
|
)
|
|
(61
|
)
|
|||||
Comprehensive loss attributable to noncontrolling interest
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|||||
Comprehensive income (loss) attributable to Vistra Energy
|
$
|
(53
|
)
|
|
$
|
251
|
|
|
$
|
(25
|
)
|
|
$
|
(232
|
)
|
|
$
|
(59
|
)
|
|
Parent (Issuer)
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Net income (loss)
|
$
|
(254
|
)
|
|
$
|
(504
|
)
|
|
$
|
—
|
|
|
$
|
504
|
|
|
$
|
(254
|
)
|
Other comprehensive income (loss), net of tax effects:
|
|
|
|
|
|
|
|
|
|
||||||||||
Effect related to pension and other retirement benefit obligations
|
(23
|
)
|
|
(29
|
)
|
|
—
|
|
|
29
|
|
|
(23
|
)
|
|||||
Total other comprehensive income
|
(23
|
)
|
|
(29
|
)
|
|
—
|
|
|
29
|
|
|
(23
|
)
|
|||||
Comprehensive income (loss)
|
$
|
(277
|
)
|
|
$
|
(533
|
)
|
|
$
|
—
|
|
|
$
|
533
|
|
|
$
|
(277
|
)
|
|
Parent (Issuer)
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Net income (loss)
|
$
|
(163
|
)
|
|
$
|
70
|
|
|
$
|
—
|
|
|
$
|
(70
|
)
|
|
$
|
(163
|
)
|
Other comprehensive income (loss), net of tax effects:
|
|
|
|
|
|
|
|
|
|
||||||||||
Effect related to pension and other retirement benefit obligations
|
6
|
|
|
6
|
|
|
—
|
|
|
(6
|
)
|
|
6
|
|
|||||
Total other comprehensive income
|
6
|
|
|
6
|
|
|
—
|
|
|
(6
|
)
|
|
6
|
|
|||||
Comprehensive income (loss)
|
(157
|
)
|
|
76
|
|
|
—
|
|
|
(76
|
)
|
|
(157
|
)
|
|
Parent (Issuer)
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Cash flows — operating activities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash provided by (used in) operating activities
|
$
|
(125
|
)
|
|
$
|
1,917
|
|
|
$
|
(321
|
)
|
|
$
|
—
|
|
|
$
|
1,471
|
|
Cash flows — financing activities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Issuances of long-term debt
|
—
|
|
|
1,000
|
|
|
—
|
|
|
—
|
|
|
1,000
|
|
|||||
Repayments/repurchases of debt
|
(4,543
|
)
|
|
1,468
|
|
|
—
|
|
|
—
|
|
|
(3,075
|
)
|
|||||
Borrowings under accounts receivable securitization program
|
—
|
|
|
—
|
|
|
339
|
|
|
|
|
|
339
|
|
|||||
Cash dividend paid
|
—
|
|
|
(4,668
|
)
|
|
—
|
|
|
4,668
|
|
|
—
|
|
|||||
Stock repurchase
|
(763
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(763
|
)
|
|||||
Debt tender offer and other financing fees
|
(179
|
)
|
|
(57
|
)
|
|
—
|
|
|
—
|
|
|
(236
|
)
|
|||||
Other, net
|
12
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|||||
Cash provided by (used in) financing activities
|
(5,473
|
)
|
|
(2,257
|
)
|
|
339
|
|
|
4,668
|
|
|
(2,723
|
)
|
|||||
Cash flows — investing activities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Capital expenditures
|
(24
|
)
|
|
(351
|
)
|
|
(3
|
)
|
|
—
|
|
|
(378
|
)
|
|||||
Nuclear fuel purchases
|
—
|
|
|
(118
|
)
|
|
—
|
|
|
—
|
|
|
(118
|
)
|
|||||
Cash acquired in the Merger
|
—
|
|
|
445
|
|
|
—
|
|
|
—
|
|
|
445
|
|
|||||
Development and growth expenditures
|
—
|
|
|
(31
|
)
|
|
(3
|
)
|
|
—
|
|
|
(34
|
)
|
|||||
Proceeds from sales of nuclear decommissioning trust fund securities
|
—
|
|
|
252
|
|
|
—
|
|
|
—
|
|
|
252
|
|
|||||
Investments in nuclear decommissioning trust fund securities
|
—
|
|
|
(274
|
)
|
|
—
|
|
|
—
|
|
|
(274
|
)
|
|||||
Dividend received from subsidiaries
|
4,668
|
|
|
|
|
|
|
|
|
(4,668
|
)
|
|
—
|
|
|||||
Other, net
|
(1
|
)
|
|
7
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|||||
Cash provided by (used in) investing activities
|
4,643
|
|
|
(70
|
)
|
|
(6
|
)
|
|
(4,668
|
)
|
|
(101
|
)
|
|||||
Net change in cash, cash equivalents and restricted cash
|
(955
|
)
|
|
(410
|
)
|
|
12
|
|
|
—
|
|
|
(1,353
|
)
|
|||||
Cash, cash equivalents and restricted cash — beginning balance
|
1,183
|
|
|
863
|
|
|
—
|
|
|
—
|
|
|
2,046
|
|
|||||
Cash, cash equivalents and restricted cash — ending balance
|
$
|
228
|
|
|
$
|
453
|
|
|
$
|
12
|
|
|
$
|
—
|
|
|
$
|
693
|
|
|
Parent (Issuer)
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Cash flows — operating activities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash provided by (used in) operating activities
|
$
|
(108
|
)
|
|
$
|
1,494
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,386
|
|
Cash flows — financing activities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Repayments/repurchases of debt
|
—
|
|
|
(191
|
)
|
|
—
|
|
|
—
|
|
|
(191
|
)
|
|||||
Cash dividend paid
|
—
|
|
|
(1,505
|
)
|
|
—
|
|
|
1,505
|
|
|
—
|
|
|||||
Debt financing fees
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|||||
Other, net
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|||||
Cash provided by (used in) financing activities
|
—
|
|
|
(1,706
|
)
|
|
—
|
|
|
1,505
|
|
|
(201
|
)
|
|||||
Cash flows — investing activities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Capital expenditures
|
—
|
|
|
(114
|
)
|
|
—
|
|
|
—
|
|
|
(114
|
)
|
|||||
Nuclear fuel purchases
|
—
|
|
|
(62
|
)
|
|
—
|
|
|
—
|
|
|
(62
|
)
|
|||||
Development and growth expenditures
|
—
|
|
|
(190
|
)
|
|
—
|
|
|
—
|
|
|
(190
|
)
|
|||||
Odessa acquisition
|
(330
|
)
|
|
(25
|
)
|
|
—
|
|
|
—
|
|
|
(355
|
)
|
|||||
Proceeds from sales of nuclear decommissioning trust fund securities
|
—
|
|
|
252
|
|
|
—
|
|
|
—
|
|
|
252
|
|
|||||
Investments in nuclear decommissioning trust fund securities
|
—
|
|
|
(272
|
)
|
|
—
|
|
|
—
|
|
|
(272
|
)
|
|||||
Dividend received from subsidiaries
|
1,505
|
|
|
|
|
|
|
|
|
(1,505
|
)
|
|
—
|
|
|||||
Other, net
|
—
|
|
|
14
|
|
|
—
|
|
|
—
|
|
|
14
|
|
|||||
Cash provided by (used in) investing activities
|
1,175
|
|
|
(397
|
)
|
|
—
|
|
|
(1,505
|
)
|
|
(727
|
)
|
|||||
Net change in cash, cash equivalents and restricted cash
|
1,067
|
|
|
(609
|
)
|
|
—
|
|
|
—
|
|
|
458
|
|
|||||
Cash, cash equivalents and restricted cash — beginning balance
|
116
|
|
|
1,472
|
|
|
—
|
|
|
—
|
|
|
1,588
|
|
|||||
Cash, cash equivalents and restricted cash — ending balance
|
$
|
1,183
|
|
|
$
|
863
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,046
|
|
|
Parent (Issuer)
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Cash flows — operating activities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash provided by (used in) operating activities
|
$
|
(36
|
)
|
|
$
|
117
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
81
|
|
Cash flows — financing activities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Issuances of long-term debt
|
—
|
|
|
1,000
|
|
|
—
|
|
|
—
|
|
|
1,000
|
|
|||||
Cash dividend paid
|
—
|
|
|
(997
|
)
|
|
—
|
|
|
997
|
|
|
—
|
|
|||||
Special dividends
|
(992
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(992
|
)
|
|||||
Other, net
|
1
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|||||
Cash provided by (used in) financing activities
|
(991
|
)
|
|
—
|
|
|
—
|
|
|
997
|
|
|
6
|
|
|||||
Cash flows — investing activities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Capital expenditures
|
—
|
|
|
(48
|
)
|
|
—
|
|
|
—
|
|
|
(48
|
)
|
|||||
Nuclear fuel purchases
|
—
|
|
|
(41
|
)
|
|
—
|
|
|
—
|
|
|
(41
|
)
|
|||||
Proceeds from sales of nuclear decommissioning trust fund securities
|
—
|
|
|
25
|
|
|
—
|
|
|
—
|
|
|
25
|
|
|||||
Investments in nuclear decommissioning trust fund securities
|
—
|
|
|
(30
|
)
|
|
—
|
|
|
—
|
|
|
(30
|
)
|
|||||
Dividend received from subsidiaries
|
997
|
|
|
—
|
|
|
—
|
|
|
(997
|
)
|
|
—
|
|
|||||
Other, net
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|||||
Cash provided by (used in) investing activities
|
997
|
|
|
(93
|
)
|
|
—
|
|
|
(997
|
)
|
|
(93
|
)
|
|||||
Net change in cash, cash equivalents and restricted cash
|
(30
|
)
|
|
24
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|||||
Cash, cash equivalents and restricted cash — beginning balance
|
146
|
|
|
1,448
|
|
|
—
|
|
|
—
|
|
|
1,594
|
|
|||||
Cash, cash equivalents and restricted cash — ending balance
|
$
|
116
|
|
|
$
|
1,472
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,588
|
|
Condensed Consolidating Balance Sheet as of December 31, 2018
(Millions of Dollars)
|
|||||||||||||||||||
|
Parent (Issuer)
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
ASSETS
|
|
|
|
|
|
|
|
|
|
||||||||||
Current assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
171
|
|
|
$
|
453
|
|
|
$
|
12
|
|
|
$
|
—
|
|
|
$
|
636
|
|
Restricted cash
|
57
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
57
|
|
|||||
Advances to affiliates
|
11
|
|
|
11
|
|
|
—
|
|
|
(22
|
)
|
|
—
|
|
|||||
Trade accounts receivable — net
|
4
|
|
|
729
|
|
|
464
|
|
|
(110
|
)
|
|
1,087
|
|
|||||
Accounts receivable — affiliates
|
—
|
|
|
245
|
|
|
—
|
|
|
(245
|
)
|
|
—
|
|
|||||
Notes due from affiliates
|
—
|
|
|
101
|
|
|
—
|
|
|
(101
|
)
|
|
—
|
|
|||||
Income taxes receivable
|
—
|
|
|
1
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|||||
Inventories
|
—
|
|
|
391
|
|
|
21
|
|
|
—
|
|
|
412
|
|
|||||
Commodity and other derivative contractual assets
|
—
|
|
|
730
|
|
|
—
|
|
|
—
|
|
|
730
|
|
|||||
Margin deposits related to commodity contracts
|
—
|
|
|
361
|
|
|
—
|
|
|
—
|
|
|
361
|
|
|||||
Prepaid expense and other current assets
|
2
|
|
|
134
|
|
|
16
|
|
|
—
|
|
|
152
|
|
|||||
Total current assets
|
245
|
|
|
3,156
|
|
|
513
|
|
|
(479
|
)
|
|
3,435
|
|
|||||
Investments
|
—
|
|
|
1,218
|
|
|
32
|
|
|
—
|
|
|
1,250
|
|
|||||
Investment in unconsolidated subsidiary
|
—
|
|
|
131
|
|
|
—
|
|
|
—
|
|
|
131
|
|
|||||
Investment in affiliated companies
|
11,186
|
|
|
263
|
|
|
—
|
|
|
(11,449
|
)
|
|
—
|
|
|||||
Property, plant and equipment — net
|
15
|
|
|
14,017
|
|
|
580
|
|
|
—
|
|
|
14,612
|
|
|||||
Goodwill
|
—
|
|
|
2,068
|
|
|
—
|
|
|
—
|
|
|
2,068
|
|
|||||
Identifiable intangible assets — net
|
10
|
|
|
2,480
|
|
|
3
|
|
|
—
|
|
|
2,493
|
|
|||||
Commodity and other derivative contractual assets
|
—
|
|
|
109
|
|
|
—
|
|
|
—
|
|
|
109
|
|
|||||
Accumulated deferred income taxes
|
809
|
|
|
599
|
|
|
—
|
|
|
(72
|
)
|
|
1,336
|
|
|||||
Other noncurrent assets
|
255
|
|
|
330
|
|
|
5
|
|
|
—
|
|
|
590
|
|
|||||
Total assets
|
$
|
12,520
|
|
|
$
|
24,371
|
|
|
$
|
1,133
|
|
|
$
|
(12,000
|
)
|
|
$
|
26,024
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Accounts receivable securitization program
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
339
|
|
|
$
|
—
|
|
|
$
|
339
|
|
Advances from affiliates
|
—
|
|
|
—
|
|
|
22
|
|
|
(22
|
)
|
|
—
|
|
|||||
Long-term debt due currently
|
23
|
|
|
163
|
|
|
5
|
|
|
—
|
|
|
191
|
|
|||||
Trade accounts payable
|
2
|
|
|
928
|
|
|
121
|
|
|
(106
|
)
|
|
945
|
|
|||||
Accounts payable — affiliates
|
236
|
|
|
—
|
|
|
9
|
|
|
(245
|
)
|
|
—
|
|
|||||
Notes due to affiliates
|
—
|
|
|
—
|
|
|
101
|
|
|
(101
|
)
|
|
—
|
|
|||||
Commodity and other derivative contractual liabilities
|
—
|
|
|
1,376
|
|
|
—
|
|
|
—
|
|
|
1,376
|
|
|||||
Margin deposits related to commodity contracts
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|||||
Accrued taxes
|
11
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
10
|
|
|||||
Accrued taxes other than income
|
—
|
|
|
181
|
|
|
1
|
|
|
—
|
|
|
182
|
|
|||||
Accrued interest
|
48
|
|
|
29
|
|
|
4
|
|
|
(4
|
)
|
|
77
|
|
|||||
Asset retirement obligations
|
—
|
|
|
156
|
|
|
—
|
|
|
—
|
|
|
156
|
|
|||||
Other current liabilities
|
74
|
|
|
267
|
|
|
4
|
|
|
—
|
|
|
345
|
|
|||||
Total current liabilities
|
394
|
|
|
3,104
|
|
|
606
|
|
|
(479
|
)
|
|
3,625
|
|
Condensed Consolidating Balance Sheet as of December 31, 2018
(Millions of Dollars)
|
|||||||||||||||||||
|
Parent (Issuer)
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
Long-term debt, less amounts due currently
|
3,819
|
|
|
7,027
|
|
|
28
|
|
|
—
|
|
|
10,874
|
|
|||||
Commodity and other derivative contractual liabilities
|
—
|
|
|
270
|
|
|
—
|
|
|
—
|
|
|
270
|
|
|||||
Accumulated deferred income taxes
|
—
|
|
|
—
|
|
|
82
|
|
|
(72
|
)
|
|
10
|
|
|||||
Tax Receivable Agreement obligation
|
420
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
420
|
|
|||||
Asset retirement obligations
|
—
|
|
|
2,203
|
|
|
14
|
|
|
—
|
|
|
2,217
|
|
|||||
Identifiable intangible liabilities — net
|
—
|
|
|
278
|
|
|
123
|
|
|
—
|
|
|
401
|
|
|||||
Other noncurrent liabilities and deferred credits
|
20
|
|
|
303
|
|
|
17
|
|
|
—
|
|
|
340
|
|
|||||
Total liabilities
|
4,653
|
|
|
13,185
|
|
|
870
|
|
|
(551
|
)
|
|
18,157
|
|
|||||
Total stockholders' equity
|
7,867
|
|
|
11,186
|
|
|
259
|
|
|
(11,449
|
)
|
|
7,863
|
|
|||||
Noncontrolling interest in subsidiary
|
—
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
|||||
Total liabilities and equity
|
$
|
12,520
|
|
|
$
|
24,371
|
|
|
$
|
1,133
|
|
|
$
|
(12,000
|
)
|
|
$
|
26,024
|
|
|
Parent (Issuer)
|
|
Guarantor Subsidiaries
|
|
Non-Guarantor Subsidiaries
|
|
Eliminations
|
|
Consolidated
|
||||||||||
ASSETS
|
|
|
|
|
|
|
|
|
|
||||||||||
Current assets:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
1,124
|
|
|
$
|
363
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,487
|
|
Restricted cash
|
59
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
59
|
|
|||||
Trade accounts receivable — net
|
4
|
|
|
578
|
|
|
—
|
|
|
—
|
|
|
582
|
|
|||||
Inventories
|
—
|
|
|
253
|
|
|
—
|
|
|
—
|
|
|
253
|
|
|||||
Commodity and other derivative contractual assets
|
—
|
|
|
190
|
|
|
—
|
|
|
—
|
|
|
190
|
|
|||||
Margin deposits related to commodity contracts
|
—
|
|
|
30
|
|
|
—
|
|
|
—
|
|
|
30
|
|
|||||
Prepaid expense and other current assets
|
—
|
|
|
72
|
|
|
—
|
|
|
—
|
|
|
72
|
|
|||||
Total current assets
|
1,187
|
|
|
1,486
|
|
|
—
|
|
|
—
|
|
|
2,673
|
|
|||||
Restricted cash
|
—
|
|
|
500
|
|
|
—
|
|
|
—
|
|
|
500
|
|
|||||
Investments
|
—
|
|
|
1,240
|
|
|
—
|
|
|
—
|
|
|
1,240
|
|
|||||
Investment in affiliated companies
|
5,632
|
|
|
—
|
|
|
—
|
|
|
(5,632
|
)
|
|
—
|
|
|||||
Property, plant and equipment — net
|
—
|
|
|
4,820
|
|
|
—
|
|
|
—
|
|
|
4,820
|
|
|||||
Goodwill
|
—
|
|
|
1,907
|
|
|
—
|
|
|
—
|
|
|
1,907
|
|
|||||
Identifiable intangible assets — net
|
—
|
|
|
2,530
|
|
|
—
|
|
|
—
|
|
|
2,530
|
|
|||||
Commodity and other derivative contractual assets
|
—
|
|
|
58
|
|
|
—
|
|
|
—
|
|
|
58
|
|
|||||
Accumulated deferred income taxes
|
5
|
|
|
705
|
|
|
—
|
|
|
—
|
|
|
710
|
|
|||||
Other noncurrent assets
|
6
|
|
|
156
|
|
|
—
|
|
|
—
|
|
|
162
|
|
|||||
Total assets
|
$
|
6,830
|
|
|
$
|
13,402
|
|
|
$
|
—
|
|
|
$
|
(5,632
|
)
|
|
$
|
14,600
|
|
LIABILITIES AND EQUITY
|
|
|
|
|
|
|
|
|
|
||||||||||
Current liabilities:
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-term debt due currently
|
—
|
|
|
44
|
|
|
—
|
|
|
—
|
|
|
44
|
|
|||||
Trade accounts payable
|
11
|
|
|
462
|
|
|
—
|
|
|
—
|
|
|
473
|
|
|||||
Commodity and other derivative contractual liabilities
|
—
|
|
|
224
|
|
|
—
|
|
|
—
|
|
|
224
|
|
|||||
Margin deposits related to commodity contracts
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|||||
Accrued taxes
|
58
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
58
|
|
|||||
Accrued taxes other than income
|
—
|
|
|
136
|
|
|
—
|
|
|
—
|
|
|
136
|
|
|||||
Accrued interest
|
—
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
16
|
|
|||||
Asset retirement obligations
|
—
|
|
|
99
|
|
|
—
|
|
|
—
|
|
|
99
|
|
|||||
Other current liabilities
|
86
|
|
|
211
|
|
|
—
|
|
|
—
|
|
|
297
|
|
|||||
Total current liabilities
|
155
|
|
|
1,196
|
|
|
—
|
|
|
—
|
|
|
1,351
|
|
|||||
Long-term debt, less amounts due currently
|
—
|
|
|
4,379
|
|
|
—
|
|
|
—
|
|
|
4,379
|
|
|||||
Commodity and other derivative contractual liabilities
|
—
|
|
|
102
|
|
|
—
|
|
|
—
|
|
|
102
|
|
|||||
Tax Receivable Agreement obligation
|
333
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
333
|
|
|||||
Asset retirement obligations
|
—
|
|
|
1,837
|
|
|
—
|
|
|
—
|
|
|
1,837
|
|
|||||
Identifiable intangible liabilities — net
|
—
|
|
|
36
|
|
|
—
|
|
|
—
|
|
|
36
|
|
|||||
Other noncurrent liabilities and deferred credits
|
—
|
|
|
220
|
|
|
—
|
|
|
—
|
|
|
220
|
|
|||||
Total liabilities
|
488
|
|
|
7,770
|
|
|
—
|
|
|
—
|
|
|
8,258
|
|
|||||
Total equity
|
6,342
|
|
|
5,632
|
|
|
—
|
|
|
(5,632
|
)
|
|
6,342
|
|
|||||
Total liabilities and equity
|
$
|
6,830
|
|
|
$
|
13,402
|
|
|
$
|
—
|
|
|
$
|
(5,632
|
)
|
|
$
|
14,600
|
|
Item 9.
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
|
/s/ Curtis A. Morgan
|
Curtis A. Morgan
|
President and Chief Executive Officer
|
(Principal Executive Officer)
|
/s/ J. William Holden
|
J. William Holden
|
Executive Vice President and Chief Financial Officer
|
(Principal Financial Officer)
|
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)
|
EXHIBITS:
|
Exhibits
|
|
Previously Filed With File Number*
|
|
As
Exhibit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2)
|
|
Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession
|
||||||
|
|
|
|
|
|
|
|
|
2.1
|
|
333-215288
Form S-1
(filed December 23, 2016)
|
|
2.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
2.2
|
|
001-38086
Form 8-K
(filed October 31, 2017)
|
|
2.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
(3(i))
|
|
Articles of Incorporation
|
||||||
|
|
|
|
|
|
|
|
|
3.1
|
|
333-215288
Form S-1
(filed December 23, 2016)
|
|
3.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.2
|
|
333-215288
Form S-1
(filed December 23, 2016)
|
|
3.2
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
(3(ii))
|
|
By-laws
|
||||||
|
|
|
|
|
|
|
|
|
3.3
|
|
333-215288
Form S-1
(filed December 23, 2016)
|
|
3.3
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
(4)
|
|
Instruments Defining the Rights of Security Holders, Including Indentures
|
||||||
|
|
|
|
|
|
|
|
|
4.1
|
|
001-33443
Form 8-K
(filed on October 30, 2014)
|
|
4.8
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.2
|
|
001-33443
Form 8-K
(filed on April7, 2015)
|
|
4.11
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.3
|
|
001-33443
Form 8-K
(filed on April 7, 2015)
|
|
4.12
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.4
|
|
001-33443
Form 8-K
(filed on April 8, 2015)
|
|
4.17
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.5
|
|
001-33443
Form 10-Q (Quarter ended June 30, 2015)
(filed on August 7, 2015)
|
|
4.2
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.6
|
|
001-33443
Form 10-Q (Quarter ended September 30, 2015) (filed on November 5, 2015)
|
|
4.2
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Exhibits
|
|
Previously Filed With File Number*
|
|
As
Exhibit
|
|
|
|
|
4.7
|
|
001-33443
Form 10-K (Year ended December 31, 2016) (filed on February 24, 2017)
|
|
4.24
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.8
|
|
001-33443
Form 10-K (Year ended December 31, 2016) (filed on February 24, 2017)
|
|
4.25
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.9
|
|
001-38086
Form 8-K
(filed on April 9, 2018)
|
|
4.19
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.10
|
|
001-38086
Form 8-K
(filed on June 15, 2018)
|
|
4.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.11
|
|
001-38086
Form 8-K
(filed on February 9, 2019)
|
|
4.4
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.12
|
|
001-33443
Form 8-K
(filed on October 30, 2014)
|
|
4.8
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.13
|
|
001-33443
Form 8-K
(filed on May 21, 2013)
|
|
4.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.14
|
|
001-33443
Form 10-K (Year ended December 31, 2013) (filed on February 27, 2014)
|
|
4.3
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.15
|
|
001-33443
Form 8-K
(filed on April 7, 2015)
|
|
4.20
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.16
|
|
001-33443
Form 8-K
(filed on April 8, 2015)
|
|
4.28
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.17
|
|
001-33443
Form 10-Q (Quarter ended June 30, 2015)
(filed on August 7, 2015)
|
|
4.4
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.18
|
|
001-33443
Form 10-Q (Quarter ended September 30, 2015) (filed on November 5, 2015)
|
|
4.4
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.19
|
|
001-33443
Form10-K (Year ended December 31, 2016) (filed on February 24, 2017)
|
|
4.7
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.20
|
|
001-33443
Form10-K (Year ended December 31, 2016) (filed on February 24, 2017)
|
|
4.8
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.21
|
|
001-38086
Form 8-K
(filed on April 9, 2018)
|
|
4.29
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Exhibits
|
|
Previously Filed With File Number*
|
|
As
Exhibit
|
|
|
|
|
4.22
|
|
001-38086
Form 8-K
(filed on June 15, 2018)
|
|
4.2
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.23
|
|
001-33443
Form 8-K
(filed on May 21, 2013)
|
|
4.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.24
|
|
001-33443
Form 8-K
(filed on October 30, 2014)
|
|
4.9
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.25
|
|
001-33443
Form 8-K
(filed on April 7, 2015)
|
|
4.14
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.26
|
|
001-33443
Form 8-K
(filed on April 7, 2015)
|
|
4.15
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.27
|
|
001-33443
Form 8-K
(filed on April 8, 2015)
|
|
4.21
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.28
|
|
001-33443
Form 10-Q (Quarter ended June 30, 2015)
(filed on August 7, 2015)
|
|
4.3
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.29
|
|
001-33443
Form 10-Q (Quarter ended September 30, 2015) (filed on November 5, 2015)
|
|
4.3
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.30
|
|
001-33443
Form 10-K (Year ended December 31, 2016) (filed on February 24, 2017)
|
|
4.32
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.31
|
|
001-33443
Form 10-K (Year ended December 31, 2016) (filed on February 24, 2017)
|
|
4.33
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.32
|
|
001-38086
Form 8-K
(filed on April 9, 2018)
|
|
4.39
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.33
|
|
001-38086
Form 8-K
(filed on June 15, 2018)
|
|
4.3
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.34
|
|
001-33443
Form of 8-K
(filed on October 30, 2014)
|
|
4.9
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.35
|
|
001-33443 Form 8-K
(filed on October 11, 2016)
|
|
4.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.36
|
|
001-33443
Form 10-K (Year ended December 31, 2016) (filed on February 24, 2017)
|
|
4.35
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.37
|
|
001-33443
Form 10-K (Year ended December 31, 2016) (filed on February 24, 2017)
|
|
4.36
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Exhibits
|
|
Previously Filed With File Number*
|
|
As
Exhibit
|
|
|
|
|
4.38
|
|
001-38086
Form 8-K
(filed on April 9, 2018)
|
|
4.48
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.39
|
|
001-38086
Form 8-K
(filed on June 15, 2018)
|
|
4.5
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.40
|
|
001-38086
Form 8-K
(filed on August 23, 2018)
|
|
4.6
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.41
|
|
001-33443
Form 8-K
(filed on October 11, 2016)
|
|
4.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.42
|
|
001-33443
Form 8-K
(filed on August 21, 2017)
|
|
4.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.43
|
|
001-33443
Form 8-K
(filed on August 21, 2017)
|
|
4.2
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.44
|
|
001-38086
Form 8-K
(filed on April 9, 2018)
|
|
4.52
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.45
|
|
001-38086
Form 8-K
(filed on June 15, 2018)
|
|
4.6
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.46
|
|
001-38086
Form 8-K
(filed on August 23, 2018)
|
|
4.4
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.47
|
|
001-33443
Form 8-K
(filed on August 21, 2017)
|
|
4.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.48
|
|
001-38086
Form 8-K
(filed on August 23, 2018)
|
|
4.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.49
|
|
001-38086
Form 8-K
(filed on August 23, 2018)
|
|
4.2
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.50
|
|
001-38086
Form 8-K
(filed on August 23, 2018)
|
|
4.3
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.51
|
|
001-38086
Form 8-K
(filed on February 6, 2019)
|
|
4.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.52
|
|
001-38086
Form 8-K
(filed on February 6, 2019)
|
|
4.2
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
4.53
|
|
001-38086
Form 8-K
(filed on February 6, 2019)
|
|
4.3
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Exhibits
|
|
Previously Filed With File Number*
|
|
As
Exhibit
|
|
|
|
|
10.1
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.6
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.2
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.7
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.3
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.8
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.4
|
|
001-33443
Form10-K (Year ended December 31, 2017) (filed on February 26, 2018)
|
|
10(d)
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.5
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.9
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.6
|
|
**
|
|
—
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.7
|
|
**
|
|
—
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.8
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.10
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.9
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.11
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.10
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.12
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.11
|
|
001-38086
Form 8-K
(filed April 27, 2018)
|
|
10.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.12
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.19
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.13
|
|
001-38086
Form 8-K
(filed May 4, 2018)
|
|
10.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.14
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.20
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Exhibits
|
|
Previously Filed With File Number*
|
|
As
Exhibit
|
|
|
|
|
10.28
|
|
001-38086
Form 8-K
(filed December 14, 2017)
|
|
10.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.29
|
|
001-38086
Form 8-K
(filed February 22, 2018)
|
|
10.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.30
|
|
001-38086
Form 8-K
(filed June 15, 2018)
|
|
10.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.31
|
|
001-38086
Form 8-K
(filed on August 7, 2018)
|
|
10.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.32
|
|
001-38086
Form 8-K
(filed on January 24, 2019)
|
|
10.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.33
|
|
001-38086
Form 8-K
(filed on April 9, 2018)
|
|
10.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.34
|
|
001-38086
Form 8-K
(filed on April 9, 2018)
|
|
10.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.35
|
|
001-38086
Form 8-K
(filed on April 9, 2018)
|
|
10.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.36
|
|
001-38086
Form 8-K
(filed on April 9, 2018)
|
|
10.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Material Contracts
|
||||||
10.37
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.5
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.38
|
|
001-38086
Form 8-K
(filed on June 15, 2018)
|
|
10.2
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Exhibits
|
|
Previously Filed With File Number*
|
|
As
Exhibit
|
|
|
|
|
10.39
|
|
001-38086
Form 8-K
(filed on June 15, 2018)
|
|
10.3
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.40
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.13
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.41
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.14
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.42
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.15
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.43
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.16
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.44
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.17
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.45
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.18
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.46
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.27
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.47
|
|
333-215288
Amendment No. 2
to Form S-1
(filed April 5, 2017)
|
|
10.28
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.48
|
|
001-38086
Form 8-K
(filed July 7, 2017)
|
|
10(a)
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.49
|
|
001-38086
Form 8-K
(filed October 31, 2017)
|
|
10.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
10.50
|
|
001-38086
Form 8-K
(filed October 31, 2017)
|
|
10.2
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Exhibits
|
|
Previously Filed With File Number*
|
|
As
Exhibit
|
|
|
|
|
10.51
|
|
001-38086
Form 8-K
(filed on August 23, 2018)
|
|
10.1
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
(21)
|
|
Subsidiaries of the Registrant
|
||||||
|
|
|
|
|
|
|
|
|
21.1
|
|
**
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
(23)
|
|
Consent of Experts
|
||||||
|
|
|
|
|
|
|
|
|
23.1
|
|
**
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
(31)
|
|
Rule 13a-14(a) / 15d-14(a) Certifications
|
||||||
|
|
|
|
|
|
|
|
|
31.1
|
|
**
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
31.2
|
|
**
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
(32)
|
|
Section 1350 Certifications
|
||||||
|
|
|
|
|
|
|
|
|
32.1
|
|
**
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
32.2
|
|
**
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
(95)
|
|
Mine Safety Disclosures
|
||||||
|
|
|
|
|
|
|
|
|
95.1
|
|
**
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 28, 2019
|
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 28, 2019
|
(Curtis A. Morgan, President and Chief Executive Officer)
|
|
|
|
|
|
/s/ J. WILLIAM HOLDEN
|
Principal Financial Officer
|
February 28, 2019
|
(J. William Holden, Executive Vice President and Chief Financial Officer)
|
|
|
|
|
|
/s/ CHRISTY DOBRY
|
Principal Accounting Officer
|
February 28, 2019
|
(Christy Dobry, Vice President and Controller)
|
|
|
|
|
|
/s/ SCOTT B. HELM
|
Chairman of the Board and Director
|
February 28, 2019
|
(Scott B. Helm, Chairman of the Board)
|
|
|
|
|
|
/s/ HILARY E. ACKERMANN
|
Director
|
February 28, 2019
|
(Hilary E. Ackermann)
|
|
|
|
|
|
/s/ GAVIN R. BAIERA
|
Director
|
February 28, 2019
|
(Gavin R. Baiera)
|
|
|
|
|
|
/s/ PAUL M. BARBAS
|
Director
|
February 28, 2019
|
(Paul M. Barbas)
|
|
|
|
|
|
/s/ BRIAN K. FERRAIOLI
|
Director
|
February 28, 2019
|
(Brian K. Ferraioli)
|
|
|
|
|
|
/s/ JEFF D. HUNTER
|
Director
|
February 28, 2019
|
(Jeff D. Hunter)
|
|
|
|
|
|
/s/ CYRUS MADON
|
Director
|
February 28, 2019
|
(Cyrus Madon)
|
|
|
|
|
|
/s/ GEOFFREY D. STRONG
|
Director
|
February 28, 2019
|
(Geoffrey D. Strong)
|
|
|
|
|
|
/s/ JOHN R. SULT
|
Director
|
February 28, 2019
|
(John R. Sult)
|
|
|
|
|
|
/s/ BRUCE ZIMMERMAN
|
Director
|
February 28, 2019
|
(Bruce Zimmerman)
|
|
|
•
|
Non-GAAP performance measures included in any of the Company’s SEC filings;
|
•
|
Line items on the Company’s income statement, including but not limited to net interest income, total other income, total costs and expenses, income before taxes, net income and/or earnings per share;
|
•
|
Line items on the Company’s balance sheet, including but not limited to debt or other similar financial obligations of the Company, which may be calculated net of cash balances and/or other offsets and adjustments as may be established by the Committee in its sole discretion;
|
•
|
Line items on the Company’s statement of cash flows, including but not limited to net cash provided in (used by) operating activities, investing activities, and/or financing activities;
|
•
|
Market share;
|
•
|
Operational metrics, including but not limited to generation performance, customer churn, residential ending customer count, customer satisfaction, average days sales outstanding, energizing events issues/success, customer complaints/success, systems availability and downtime, contribution margin, and safety and environmental improvements;
|
•
|
Financial ratios, including but not limited to operating margin, return on equity, return on assets, and/or return on invested capital; or
|
•
|
Total shareholder return, the fair market value of a share of Common Stock, or the growth in value of an investment in the Common Stock assuming the reinvestment of dividends.
|
Title:
|
Executive Vice President and Chief Administrative Officer
|
If to the Company:
|
Vistra Energy Corp.
|
If to Executive:
|
At the most recent address on file in the Company’s records.
|
If to the Company:
|
Vistra Energy Corp.
|
If to Executive:
|
At the most recent address on file in the Company’s records.
|
SUBSIDIARY
|
|
STATE OR COUNTRY OF INCORPORATION OR ORGANIZATION
|
||
1
|
|
ANP Bellingham Energy Company, LLC
|
|
Delaware
|
2
|
|
ANP Blackstone Energy Company, LLC
|
|
Delaware
|
3
|
|
Casco Bay Energy Company, LLC
|
|
Delaware
|
4
|
|
Coleto Creek Power, LLC
|
|
Delaware
|
5
|
|
Comanche Peak Power Company LLC
|
|
Delaware
|
6
|
|
Dynegy Coal Generation, LLC
|
|
Delaware
|
7
|
|
Dynegy Coal Holdco, LLC
|
|
Delaware
|
8
|
|
Dynegy Commercial Asset Management, LLC
|
|
Delaware
|
9
|
|
Dynegy Energy Services (East), LLC
|
|
Delaware
|
10
|
|
Dynegy Energy Services, LLC
|
|
Delaware
|
11
|
|
Dynegy Fayette II, LLC
|
|
Delaware
|
12
|
|
Dynegy Hanging Rock II, LLC
|
|
Delaware
|
13
|
|
Dynegy Marketing and Trade, LLC
|
|
Delaware
|
14
|
|
Dynegy Miami Fort, LLC
|
|
Delaware
|
15
|
|
Dynegy Midwest Generation, LLC
|
|
Delaware
|
16
|
|
Dynegy Moss Landing, LLC
|
|
Delaware
|
17
|
|
Dynegy Power Generation, Inc.
|
|
Delaware
|
18
|
|
Dynegy Power, LLC
|
|
Delaware
|
19
|
|
Dynegy Resource II, LLC
|
|
Delaware
|
20
|
|
Dynegy Zimmer, LLC
|
|
Delaware
|
21
|
|
Electric Energy, Inc.
|
|
Illinois
|
22
|
|
Ennis Power Company, LLC
|
|
Delaware
|
23
|
|
Equipower Resources Corp.
|
|
Delaware
|
24
|
|
Hays Energy, LLC
|
|
Delaware
|
25
|
|
Hopewell Power Generation, LLC
|
|
Delaware
|
26
|
|
Illinois Power Generating Company
|
|
Illinois
|
27
|
|
Illinois Power Marketing Company
|
|
Illinois
|
28
|
|
Illinois Power Resources Generating, LLC
|
|
Delaware
|
29
|
|
Illinois Power Resources, LLC
|
|
Delaware
|
30
|
|
IPH, LLC
|
|
Delaware
|
31
|
|
Kincaid Generation, L.L.C.
|
|
Virginia
|
32
|
|
La Frontera Holdings, LLC
|
|
Delaware
|
33
|
|
Lake Road Generating Company, LLC
|
|
Delaware
|
34
|
|
Liberty Electric Power, LLC
|
|
Delaware
|
35
|
|
Luminant Energy Company LLC
|
|
Texas
|
36
|
|
Luminant Mining Company LLC
|
|
Texas
|
37
|
|
Masspower, LLC
|
|
Massachusetts
|
38
|
|
Midlothian Energy, LLC
|
|
Delaware
|
39
|
|
Midwest Electric Power, Inc.
|
|
Illinois
|
40
|
|
Milford Power Company, LLC
|
|
Delaware
|
41
|
|
North Jersey Energy Associates, LP
|
|
New Jersey
|
42
|
|
Northeast Energy Associates, LP
|
|
Massachusetts
|
43
|
|
Northeastern Power Company
|
|
Pennsylvania
|
44
|
|
Oak Grove Management Company LLC
|
|
Delaware
|
45
|
|
Ontelaunee Power Operating Company, LLC
|
|
Delaware
|
46
|
|
Pleasants Energy, LLC
|
|
Delaware
|
47
|
|
Sithe Energies, Inc.
|
|
Delaware
|
48
|
|
Sithe/Independence Power Partners, LP
|
|
Delaware
|
49
|
|
Sithe/Independence, LLC
|
|
Delaware
|
50
|
|
TXU Energy Retail Company LLC
|
|
Texas
|
51
|
|
Vistra Asset Company LLC
|
|
Delaware
|
52
|
|
Vistra EP Properties Company
|
|
Texas
|
53
|
|
Vistra Intermediate Company LLC
|
|
Delaware
|
54
|
|
Vistra Operations Company LLC
|
|
Delaware
|
55
|
|
Vistra Preferred Inc.
|
|
Delaware
|
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 28, 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 28, 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 28, 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 28, 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
|
|||||
Kosse
|
|
8
|
|
|
—
|
|
1
|
|
—
|
|
—
|
|
6
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
Liberty
|
|
3
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
1
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
|
1
|
|
Northeastern Power Cogeneration Facility
|
|
3
|
|
|
—
|
|
1
|
|
—
|
|
—
|
|
4
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
Tatum
|
|
6
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
3
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
—
|
|
|
—
|
|
Three Oaks
|
|
—
|
|
|
—
|
|
—
|
|
—
|
|
—
|
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—
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1
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(a)
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Excludes mines for which there were no applicable events.
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(b)
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Includes MSHA citations for mandatory health or safety standards that could significantly and substantially contribute to a serious injury if left unabated.
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(c)
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Total value in thousands of dollars for proposed assessments received from MSHA for all citations and orders issued in the year ended December 31, 2018, including but not limited to Sections 104, 107 and 110 citations and orders that are not required to be reported.
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(d)
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There were no pending actions before the FMSHRC involving a coal or other mine.
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