S-1 1 d312912ds1.htm FORM S-1 Form S-1
Table of Contents

As filed with the Securities and Exchange Commission on December 23, 2016

Registration No.            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

VISTRA ENERGY CORP.

(Exact Name of Registrant as Specified in its Charter)

 

 

 

Delaware   4911   36-4833255
(State or Other Jurisdiction of
Incorporation or Organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification No.)

1601 Bryan Street

Dallas, Texas 75201-3411

(214) 812-4600

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)

 

 

Stephanie Zapata Moore

Vistra Energy Corp.

Executive Vice President and General Counsel

1601 Bryan Street

Dallas, Texas 75201-3411

(214) 812-4600

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent of Service)

 

 

With a copy to:

 

William D. Howell
Sidley Austin LLP
2021 McKinney Avenue

Dallas, Texas 75201
(214) 981-3418

  

Edward F. Petrosky
Sidley Austin LLP
787 7th Avenue

New York, New York 10019
(212) 839-5455

 

 

Approximate date of commencement of proposed sale to the public: From time to time after the effective date of this registration statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  ☒

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer      Accelerated filer  
Non-accelerated filer   ☒  (Do not check if a smaller reporting company)    Smaller reporting company  

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities to Be Registered

  Amount
to Be
Registered
  Proposed
Maximum
Offering Price
per Unit (1)
  Proposed
Maximum
Aggregate
Offering Price (1)
  Amount of
Registration Fee

Common stock, par value $0.01 per share

  168,748,919   $14.095   $2,378,516,013   $275,670.01

 

 

(1) Estimated solely for the purpose of calculating the registration fee for the securities pursuant to Rule 457(c) under the Securities Act of 1933, as amended. The price per share and aggregate offering price are based on the average of the high and low price of the registrant’s common stock on December 19, 2016, as reported on the OTCQX U.S. market.

 

 

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


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The information in this prospectus is not complete and may be changed. None of the selling stockholders of our common stock may sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting offers to buy these securities in any jurisdiction where such offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED DECEMBER 23, 2016

Vistra Energy Corp.

168,748,919 Shares of Common Stock

 

 

This prospectus relates to 168,748,919 shares of Vistra Energy Corp. common stock, par value $.01 per share, which we refer to as our common stock or the Vistra Energy common stock, which may be offered for resale from time to time by the stockholders named under the heading “Selling Stockholders,” whom we refer to as the selling stockholders. The shares of our common stock offered under this prospectus may be resold by the selling stockholders at fixed prices, prevailing market prices at the times of sale, prices related to such prevailing market prices, varying prices determined at the times of sale or negotiated prices and, accordingly, we cannot determine the price or prices at which shares of our common stock may be resold. The shares of our common stock offered by this prospectus and any prospectus supplement may be resold by the selling stockholders directly to investors or to or through underwriters, dealers or other agents, as described in more detail in this prospectus. For more information, see “Plan of Distribution.” We do not know if, when or in what amounts a selling stockholder may offer shares of our common stock for resale. The selling stockholders may resell all, some or none of the shares of our common stock offered by this prospectus in one or multiple transactions.

We will not receive any of the proceeds from the resale of the shares of our common stock by the selling stockholders, but we have agreed to pay certain registration expenses.

Our common stock is quoted on the OTCQX U.S. market under the symbol “VSTE.” On December 19, 2016, the closing sales price of our common stock as reported on the OTCQX market was $14.23 per share. We have applied to list our common stock for trading on the             , which we refer to as             , under the symbol “              .”

 

 

Investing in our common stock involves risks. Before making a decision to invest in our common stock, you should carefully consider the information referred to under the heading “Risk Factors” beginning on page 24.

Neither the Securities and Exchange Commission nor any state or other securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

 

 

The date of this prospectus is                 ,         .


Table of Contents

Table of Contents

 

     Page  

About This Prospectus

     iii   

Prospectus Summary

     1   

Risk Factors

     24   

Special Note Regarding Forward-Looking Statements

     44   

Industry and Market Information

     47   

Use of Proceeds

     48   

Market Prices and Dividend Policy

     49   

Capitalization

     50   

The Reorganization and Emergence

     51   

Selected Historical Consolidated Financial Information

     54   

Unaudited Pro Forma Condensed Consolidated Financial Information

     56   

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     68   

Business

     97   

Management

     117   

Principal and Selling Stockholders

     128   

Certain Relationships and Related Party Transactions

     129   

Description of Indebtedness

     134   

Description of Capital Stock

     137   

Material U.S. Federal Income Tax Considerations for Non-U.S. Holders

     143   

Shares Eligible for Future Sales

     147   

Plan of Distribution

     149   

LEGAL MATTERS

     152   

EXPERTS

     152   

WHERE YOU CAN FIND MORE INFORMATION

     153   

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

     F-1   

 

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About This Prospectus

In this prospectus, except as otherwise indicated herein, or as the context may otherwise require, all references to “Vistra Energy,” “the Company,” “we,” “us” and “our” refer to (a) Vistra Energy Corp. and, unless the context otherwise requires, its direct and indirect subsidiaries and (b) prior to its emergence from bankruptcy (Emergence), Texas Competitive Electric Holdings Company LLC, a Delaware limited liability company, and, unless the context otherwise requires, its direct and indirect subsidiaries (our Predecessor).

This prospectus is part of a resale registration statement that we have filed with the Securities and Exchange Commission (the Commission), using a “shelf” registration process. Under this shelf registration process, the selling stockholders may offer and resell, from time to time, an aggregate of up to 168,748,919 shares of our common stock under this prospectus in one or more offerings. In some cases, the selling stockholders will also be required to provide a prospectus supplement containing specific information about them and the terms on which they are offering and reselling our common stock. We may also add, update or change in a prospectus supplement information contained in this prospectus. To the extent any statement made in a future prospectus supplement is inconsistent with statements made in this prospectus, the statements made in such prospectus supplement shall control and the statements made in this prospectus will be deemed modified or superseded by those made in such prospectus supplement. As a result, you should read this prospectus and any accompanying prospectus supplement, as well as any post-effective amendments to the registration statement of which this prospectus is a part, before you make any investment decision with respect to shares of our common stock.

The selling stockholders named herein acquired their shares of our common stock as part of the Third Amended Joint Plan of Reorganization (the Plan) under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) of Energy Future Holdings Corp. (EFH Corp.) and the substantial majority of its direct and indirect subsidiaries (collectively, the Debtors), including Energy Future Intermediate Holding Company LLC (EFIH), Energy Future Competitive Holdings Company LLC (EFCH) and our Predecessor, but excluding Oncor Electric Delivery Holdings Company LLC and its direct and indirect subsidiaries (collectively, Oncor). For more information see “Prospectus Summary — Reorganization and Emergence” and “The Reorganization and Emergence.”

Except as otherwise explicitly stated, the historical financial information and accompanying financial statements and corresponding notes contained in this prospectus reflect the actual historical consolidated results of operations, cash flows and financial condition of our Predecessor for the periods presented and do not give effect to the Plan, Emergence or the adoption of fresh-start reporting. Thus, such financial information may not be representative of our results of operations, cash flows or financial condition subsequent to the Effective Date. Because our Predecessor ceased owning and operating its historical business upon Emergence and Vistra Energy will continue to own and operate, directly and indirectly, substantially the same business that our Predecessor owned and operated prior to Emergence, references herein to “our” historical consolidated financial information (or data derived therefrom) should be read to refer to the historical consolidated financial information of our Predecessor.

The selling stockholders may only offer to resell, and seek offers to buy, shares of our common stock in jurisdictions where offers and sales are permitted. You should rely only on the information contained in this prospectus and any accompanying prospectus supplement. Neither we, nor the selling stockholders, have authorized anyone to provide you with information other than that contained in this prospectus or any accompanying prospectus supplement and, if such information is provided to you, then you should not rely on it. Neither we, nor the selling stockholders, take any responsibility for, and can provide no assurance as to the accuracy or completeness of, any other information that others may give you. Neither we, nor the selling stockholders, have authorized any other person to provide you with different or additional information, and neither we nor the selling stockholders are making an offer to sell the shares in any jurisdiction where the offer or sale is not permitted. The information contained in this prospectus speaks only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of shares of our common stock hereunder. Our business, financial condition, cash flows, results of operations and prospects may have changed since the date on the front cover of this prospectus.

 

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GLOSSARY

When the following industry terms and abbreviations appear in this prospectus, they have the meanings indicated below (unless otherwise expressly set forth or as the context otherwise indicates).

 

CCGT    Combined cycle gas turbine
CFTC    United States Commodity Futures Trading Commission
CO2    Carbon dioxide
CSAPR    Cross-State Air Pollution Rule issued by the EPA in July 2011
CTs    Combustion turbines
DOE    United States Department of Energy
EPA    United States Environmental Protection Agency
ERCOT    Electric Reliability Council of Texas, Inc., the independent system operator and the regional coordinator of various electricity systems within Texas
FERC    United States Federal Energy Regulatory Commission
fossil fuel    A natural fuel, such as coal, oil or natural gas, formed in the geological past from the remains of living organisms
GHG    Greenhouse gas
GWh    Gigawatt-hours
IPP    Independent power producer
ISO    Independent system operator
load    Demand for electricity
market heat rate    The wholesale market price of electricity divided by the market price of natural gas
MATS    Mercury and Air Toxics Standard established by the EPA
MMBtu    Million British thermal units
MW    Megawatts
MWh    Megawatt-hours
MSHA    United States Mine Safety and Health Administration
NERC    North American Electric Reliability Corporation
NOx    Nitrogen oxide
NRC    United States Nuclear Regulatory Commission
NYMEX    The New York Mercantile Exchange, a commodity derivatives exchange
ORDC    Operating Reserve Demand Curve, pursuant to which wholesale electricity prices in the ERCOT real-time market increase automatically as available operating reserves decrease below defined threshold levels
PPAs    Power purchase agreements
PURA    Public Utility Regulatory Act

 

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PUCT    Public Utility Commission of Texas
RCT    Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas
REP    Retail electric provider
SO2    Sulfur dioxide
TCEQ    Texas Commission on Environmental Quality
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
TWh    Terawatt-hours
VOLL    Value of lost load

 

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PROSPECTUS SUMMARY

This summary highlights the more detailed information contained elsewhere in this prospectus. This summary may not contain all the information that may be important to you. You should carefully read the entire prospectus before making an investment decision, especially the information presented under the heading “Risk Factors.” In this prospectus, except as otherwise indicated herein, or as the context may otherwise require, all references to “Vistra Energy,” “the Company,” “we,” “us” and “our” refer to (a) Vistra Energy Corp. and, unless the context otherwise requires, its direct and indirect subsidiaries and (b) prior to its emergence from bankruptcy (Emergence), Texas Competitive Electric Holdings Company LLC, a Delaware limited liability company, and, unless the context otherwise requires, its direct and indirect subsidiaries (our Predecessor).

Our Company

Vistra Energy is a leading energy company operating an integrated power business in Texas, which includes TXU Energy and Luminant. Through TXU Energy and Luminant, our integrated business engages in retail sales of electricity and related services to end users, wholesale electricity sales and purchases, power generation, commodity risk management, fuel production and fuel logistics management. We are committed to providing superior customer service, maintaining operational excellence, applying an integrated approach to managing risk, applying a disciplined approach to managing costs, continuing our track record of superior corporate responsibility and citizenship and effectively managing through varying business cycles in the competitive power markets. Our goal is to deliver long-term value to our stockholders by maintaining a strong balance sheet and strong liquidity profile in order to provide us with the flexibility to pursue a range of capital deployment strategies, including investing in our current business, funding attractive organic and acquisition-driven growth opportunities and returning capital to our stockholders.

We operate as an integrated company that provides complete electricity solutions to our customers and to the broader ERCOT market. Our company is comprised of:

 

    our brand name retail electricity provider business, TXU Energy™, which is the largest retailer of electricity in Texas with approximately 1.7 million residential, commercial and industrial customers as of September 30, 2016, and maintains the highest residential customer retention rate of any Texas retail provider in its respective core market;

 

    our market-leading electricity generation business, Luminant, which operates approximately 17,000 MW of fuel-diverse installed capacity in Texas as of September 30, 2016, including the electricity that TXU Energy uses to supply its retail customers and that we sell to third parties in the wholesale market or otherwise;

 

    our premier wholesale commodity risk management operation, which dispatches our generation fleet in response to market conditions, markets the electricity generated by our facilities to our customers (including TXU Energy) and the broader ERCOT market, procures fuel from third parties for use at our electric generating facilities and performs the risk management services for Luminant and TXU Energy that enables the delivery of cost-effective electricity to the wholesale market and retail end-users;

 

    our well-established mining, fuel handling and logistics operations, which supply fuel to our diverse fleet of electric generating facilities and manage our real property holdings throughout the enterprise; and

 

    our efficient, low-cost support organizations, which provide the necessary services to meet our compliance obligations, support our integrated electricity solutions and assist in conducting our business in an environmentally responsible and regulatory-compliant manner.

All of our operations teams (mining and fuel handling; wholesale commodity risk management, asset optimization and generation fleet dispatch; power generation; retail electricity marketing, sales and services; and

 



 

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strategic sourcing, supply chain and procurement) are integrated. The integrated nature of these operations allows us, where appropriate, to manage these operations with close alignment, which we believe provides us better market insight and a reduction of the impact of commodity price volatility as compared to our non-integrated competitors. The balance between our retail and wholesale operations creates a uniquely integrated company that is the largest power generator and retail provider of electricity in Texas. We sell retail electricity and value-added services, primarily through TXU Energy, to approximately 1.7 million residential, commercial and industrial customers in Texas as of September 30, 2016. Additionally, we sell electricity and related products generated by our fleet of electric generating units, which had an aggregate of approximately 17,000 MW of generating capacity as of September 30, 2016. We also procure wholesale electricity and related commodities to fuel our generation facilities and supply our retail business. We also manage a well-established mining operation that has over 40 years of experience in supplying fuel to our fleet in a safe and environmentally responsible manner. Our generation portfolio is diverse and flexible in terms of fuel types and dispatch characteristics, which enables us to respond to changing market conditions and regulatory developments. The charts below show our market-leading position among power generators and electricity retailers in Texas. We believe the combination of these charts illustrates the unique opportunity that is created from our integrated business model.

 

LOGO    LOGO

Date: 2015

Source: SNL

  

Date: 2015

Source: EIA

Note: Rankings do not combine a company that may own multiple brands.

 



 

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Our Integrated Business Model

We believe the key factor that distinguishes us from others in our industry is the integrated nature of our business (i.e., pairing Luminant’s reliable and efficient mining, generating and wholesale commodity risk management capabilities with TXU Energy’s retail platform) which, in our view, represents a unique company structure in the competitive ERCOT market and other competitive electricity markets across the country. We believe our integrated business model creates a unique opportunity because, relative to our non-integrated competitors, it insulates us from commodity price movements and provides unique earnings stability. Consequently, our integrated business model will be at the core of our business strategy.

The chart below depicts the integrated nature of our business and summarizes the unique advantages of our integrated business model.

 

 

LOGO

 



 

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To further illustrate the benefits of our integrated business model, the chart below highlights the competitive advantages of our integrated business model as compared to our non-integrated competitors (i.e., pure-play IPPs and non-integrated REPs).

 

                     
       

 

IPP Model –

Competitive Pressures

     

Retail Model –

Competitive Pressures

         

Vistra Energy –

Integrated Advantage

    
                 

Commodity

Exposure Related

 

LOGO

 

  Low price environment puts pressure on “long” commodity IPP model

  Lack of depth of wholesale market makes meaningful long term hedging challenging

   

  Lowprice environment encourages competitive entry

  Lackof market depth to hedge supply requirements presents risk management issue

     

  Mitigatescash flow volatility from exposure to commodity prices

  Retailchannel provides an internal offset to generation (and vice versa)

  Lowerhedging transaction and collateral costs

 

   
                                 
                 

Impact of Technology

 

LOGO

 

  Technology advancement in, and subsidization of, wind, solar, and storage

  Low load growth environment; trends toward distributed generation and efficiency

   

  Trend towards energy efficiency and “green” products

     

  Opportunity to use customer channels to expand integrated model to new technology

  Creates new ways to engage customers and promotes long term relationships

 

   
                                 
                 

New

Entrants

 

LOGO

 

  Continued new build at questionable economics leads to high reserve margins & volatility in capacity prices

   

  Very aggressive / unsustainable pricing from new entrants / competitors

     

  Retail and wholesale diversification provides earnings stability and capital efficiencies relative to pure-play new entrants

 

   
                                 
                 

Regulatory/ Political

 

LOGO

 

  Regulatoryand political focus on emissions

  Considerableoversight with numerous restrictions on market behavior

  Onerousrules regarding asset retirement

   

  ERCOT is only fully competitive retail market in North America (price-to-beat expired in 2007)

  Non ERCOT retail market faces structural challenges

-    Default provider sets effective ceiling price

-    Utilities retain most customers and the customer interface, limiting opportunities to differentiate

     

  As largest retail provider in ERCOT, the only fully deregulated retail market, TXU Energy lowers risk profile of overall portfolio compared to competitors in other markets

   
                     

 



 

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Our Operations

Our primary operations consist of electricity solutions, including retail sales of electricity and related products to end users, power generation (including operations and maintenance and outage and project management) and sales of electric generating unit output in the wholesale marketplace, asset optimization and commodity risk management performed on an integrated basis for our retail and wholesale positions, and fuel logistics and management. These operations work together on an integrated basis, which allows us to realize efficiencies and alignment in all aspects of the electricity generation and sales operation.

We operate solely in the growing ERCOT electricity market, which we view as one of the most attractive power markets in the United States. As described in more detail below, ERCOT is an ISO that manages the flow of electricity to approximately 24 million Texas customers, representing 90% of the state’s load, and spanning approximately 75% of its geography, as of September 30, 2016.

Texas has one of the fastest growing populations of any state in the United States and has a diverse economy, which has resulted in a significant and growing competitive retail electricity market. We are an active participant in the competitive ERCOT market and continue to be a market leader, which we believe is driven by, among other things, having one of the lowest customer complaint rates, according to the PUCT, having an integrated power generation operation that allows us to efficiently obtain the electricity needed to serve our customers at the lowest cost, and leveraging the experience of our wholesale commodity risk management operations to optimize our cost to procure electricity and other products on behalf of our customers. We provided electricity to approximately 24% and 19% of the residential and commercial customers in ERCOT, respectively, as of September 30, 2016. We have differentiated ourselves by providing a distinctive customer experience predicated on delivering reliable and innovative power products and solutions to our customers, such as Free Nights and Weekends residential plans, MyEnergy DashboardSM, TXU Energy’s iThermostat product and mobile solutions, the TXU Energy Rewards program, the TXU Energy Green UPSM renewable energy credit program and a diverse set of solar options, which give our customers choice, convenience and control over how and when they use electricity and related services. We competitively market our retail electricity and related services to acquire, serve and retain both retail and wholesale customers. Our wholesale customers represent a cross section of industrial users, other competitive retail electric providers, municipalities, cooperatives and other end-users of electricity. We are able to better serve our retail customers through our unique affiliation with our wholesale commodity risk management personnel who are able to structure products and contracts in a way that offers significant value compared to stand-alone retail electric providers. Additionally, our generation business protects our retail business from power price volatility, by allowing it to bypass bid-ask spread in the market (particularly for illiquid products and time periods), which results in significantly lower collateral costs for our retail business as compared to other, non-integrated retail electric providers. Moreover, our retail business insulates, to some extent, our wholesale generation business. This is because the retail load requirements of our retail operations (primarily TXU Energy) provides a natural offset to the length of Luminant’s generation portfolio thereby reducing the exposure to wholesale power price volatility as compared to a non-integrated pure-play IPP.

Our power generation fleet is diverse and flexible in terms of dispatch characteristics as our fleet includes baseload, intermediate/load-following and peaking generation. Our wholesale commodity risk management business is responsible for dispatching our generation fleet in response to market needs after implementing portfolio optimization strategies, thus linking and integrating the generation fleet production with our retail customer and wholesale sales opportunities. Market demand, also known as load, faced by an electric power system such as ERCOT varies from moment to moment as a result of changes in business and residential demand, much of which is driven by weather. Unlike most other commodities, the production and consumption of electricity must remain balanced on an instantaneous basis. There is a certain baseline demand for electricity across an electric power system that occurs throughout the day, which is typically satisfied by baseload generating units with low variable operating costs. Baseload generating units can also increase output to satisfy

 



 

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certain incremental demand and reduce output when demand is unusually low. Intermediate/load-following generating units, which can more efficiently change their output to satisfy increases in demand, typically satisfy a large proportion of changes in intraday load as they respond to daily increases in demand or unexpected changes in supply created by reduced generation from renewable resources or other generator outages. Peak daily loads are typically satisfied by peaking units. Peaking units are typically the most expensive to operate, but they can quickly start up and shut down to meet brief peaks in demand. In general, baseload units, intermediate/load-following units and peaking units are dispatched into the ERCOT grid in order from lowest to highest variable cost. Price formation in ERCOT, as with other competitive power markets in the United States, is typically based on the highest variable cost unit that clears the market to satisfy system demand at a given point in time.

As of September 30, 2016, our generation fleet consisted of 50 electric generating units, all of which are wholly owned, with the fuel types, dispatch characteristics and total installed nameplate generating capacity as shown in the table below:

 

Fuel Type

  

Dispatch

   Installed Nameplate
Generation
Capacity (MW)
     Number of
Plant Sites
     Number of Units  

Nuclear

   Baseload      2,300         1         2   

Lignite

   Baseload      2,737         2         4   

Lignite/Coal

   Intermediate/Load-Following      5,280         3         8   

Natural Gas (CCGT)

   Intermediate/Load-Following      2,988         2         14   

Natural Gas (Steam and CTs)

   Peaking      3,455         7         22   
     

 

 

    

 

 

    

 

 

 

Total

        16,760         15         50   
     

 

 

    

 

 

    

 

 

 

Our wholesale commodity risk management business also procures renewable energy credits from wind generation to support our electricity sales to wholesale and retail to satisfy the increasing demand for renewable resources from customers. As of September 30, 2016, we had long-term PPAs to annually procure 390 MW of renewable energy. These renewable generation sources deliver electricity when conditions make them available, and, when on-line, they generally compete with baseload units. Because they cannot be relied upon to meet demand continuously due to their dependence on weather and time of day, these generation sources are categorized as non-dispatchable and create the need for intermediate/load-following resources to respond to changes in their output.

 



 

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Our generation resources, which represented approximately 18% of the generation capacity in ERCOT as of September 30, 2016, allow us to annually generate, procure and sell approximately 75-85 TWh of electricity to wholesale and retail customers from nuclear, natural gas, lignite, coal and renewable generation resources. The chart below shows the diversification of our generation fleet in terms of fuel types and dispatch characteristics as of September 30, 2016.

Generation

2016; % MWs

 

 

LOGO

 



 

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The map below shows our significant footprint in Texas and further demonstrates the integrated nature of our business.

 

LOGO

 

Our Competitive Strengths

We believe we are well-positioned to execute our business strategy of delivering long-term value to our stakeholders based on, among others, the following competitive strengths:

Uniquely situated integrated energy infrastructure company. We believe the key factor that distinguishes us from others in our industry is the integrated nature of our business (i.e., pairing Luminant’s reliable and efficient mining, generating and wholesale commodity risk management capabilities with TXU Energy’s retail platform). We believe this is a unique company structure in the competitive ERCOT market and other competitive electricity markets across the country. It is our view that our integrated business model provides us a competitive advantage and results in more stable earnings under all market environments relative to our non-integrated competitors. In general, non-integrated electricity retailers are subject to wholesale power price and resulting cash flow volatility when demand increases or supply tightens, which can potentially result in significant losses if an electricity retailer is not appropriately hedged. However, because of the risk mitigation created by our integrated business model, we believe our retail operations (primarily TXU Energy) are not as exposed to wholesale power price volatility as non-integrated retail power companies. Moreover, given the retail load requirements of our retail operations (primarily TXU Energy), the length of Luminant’s generation portfolio is not as exposed to wholesale power price volatility as compared to a non-integrated pure-play IPP. Additionally, our mining operations provide an alternative to other coal procurement sources and give us more flexibility in reaching the most cost-effective arrangements for our coal-fueled facilities. We believe these advantages make our business less subject to volatility risk than pure-play IPPs and non-integrated retail electric

 



 

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providers. Furthermore, we believe our integrated business model allows us to reduce sourcing and transaction costs and minimize credit and collateral requirements.

Highly valued retail brand and customer-focused operations. Our TXU Energy™ brand enjoys long-standing and strong brand recognition throughout ERCOT, enabling us to effectively acquire, serve and retain a broad spectrum of retail electricity customers. Our TXU Energy™ brand is viewed by customers as a symbol of a trustworthy, customer-centric, innovative and dependable electricity service. By leveraging our retail marketing capabilities, commitment to product innovation and deep knowledge of the ERCOT market and its customer base, we believe that we can maintain and grow our position as the largest retailer of electricity in the highly competitive ERCOT retail market. We have an operating model that has delivered attractive margins and strong customer satisfaction that has been consistently ranked by the PUCT as having among the lowest customer complaint rates in the ERCOT market. We drive positive results in our retail electricity business by functioning as a technology driven, multi-channel marketer with advanced analytics and product development capabilities. We have leveraged these capabilities and the TXU Energy™ brand to deliver a wide range of innovative power products and services to our customers, including Free Nights and Weekends residential plans, MyEnergy DashboardSM, TXU Energy’s iThermostat product and mobile solutions, the TXU Energy Rewards program, the TXU Energy Green UpSM renewable energy credit program and a diverse set of solar options, which give our customers choice, convenience and control over how and when they use electricity and related services. We believe our strong customer service, innovative products and trusted brand recognition have resulted in us maintaining the highest residential customer retention rate of any Texas retail electric provider in its respective core market.

Diversified generation sources and critical energy infrastructure. We maintain operational flexibility to provide reliable and responsive power under a variety of market conditions by utilizing generation sources that are diverse and flexible in terms of fuel types (nuclear, lignite, coal, natural gas and renewables) and dispatch characteristics (baseload, intermediate/load-following, peaking and non-dispatchable). These generation sources feature the following characteristics:

 

    Except for periods of scheduled maintenance activities, our nuclear-fueled units are generally available to run at capacity.

 

    Except for periods of scheduled maintenance activities, our lignite- and coal-fueled units are available to run at capacity or seasonally, depending on market conditions (i.e., during periods when wholesale electricity prices are greater than the unit’s variable production costs). Certain of these units run only during the summer peak period and at times go into seasonal layup during the months with lower seasonal demand.

 

    Our CCGT units generally run during the intermediate/load-following periods of the daily supply curve.

 

    Our natural gas-fueled generation peaking units supplement the aggregate nuclear-, lignite- and coal-fueled and CCGT generation capacity in meeting demand during peak load periods because production from certain of these units, particularly combustion-turbine units, can be more quickly adjusted up or down as demand warrants. With this quick-start capability, we are able to increase generation during periods of supply or demand volatility in ERCOT and capture scarcity pricing in the wholesale electricity market. These natural gas-fueled generation peaking units also help us mitigate unit-contingent outage risk by allowing us to meet demand even if one or more of our nuclear, lignite, coal or CCGT units is taken offline for maintenance.

 

    The CCGT and natural gas-fueled generation peaking units also play a pivotal and increasing role in the ERCOT market by supplementing intermittent renewable generation through their versatile operations. We expect this versatility to increase in value over time as the ERCOT market continues to expand into renewable resources.

 



 

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    Our long-term PPAs with various renewable energy providers deliver electricity when natural conditions make renewable resources available. These resources position us to meet the market’s increasing demand for sustainable, low-carbon power solutions.

In addition, the commodity risk management and asset optimization strategies executed by our commercial operation supplement the electricity generated by our fleet with electricity procured in market transactions to ensure that we are supplying our customer obligations with the most cost-effective electricity options.

Competitive scale and highly effective, low-cost support operations. Our integrated company includes the largest power generator and retailer of electricity in Texas, as complemented by our mining and fuel handling operations and our wholesale commodity risk management business. As an integrated energy company with approximately 17,000 MW of generation capacity and approximately 1.7 million retail electricity customers, each as of September 30, 2016, we operate with significant scale. This scale enables us to conduct our business with certain operational synergies that are not available to smaller power generation or retail electricity businesses. The benefits of our significant scale include improved leverage of our low fixed costs, opportunities to share expertise across the portfolio of assets, enhanced procurement opportunities, development of, and the ability to offer, a wide array of products and services to our customers, shared expertise of employees, diversity of cash flows and a breadth of positive relationships with regulatory and governmental authorities. We believe these advantages, combined with a strong balance sheet and strong liquidity profile, enable us to operate with more financial flexibility than our competitors, and will enable us to prudently grow our existing business and pursue attractive growth opportunities in the future.

Positioned to capture upside in the attractive ERCOT market. We believe that the location of our business, solely in ERCOT, offers attractive upside opportunities. ERCOT is the only fully deregulated electricity market in the United States in that both the wholesale and retail markets are truly competitive. In addition to having a robust wholesale market, the ERCOT residential retail market does not have regulated providers or a standard offer service, which is unique among competitive retail markets in the United States. We believe our integrated business model uniquely positions us to benefit from this attractive, robust marketplace. The ERCOT market represents approximately 90% of the load in Texas, a state that is the seventh-largest power market in the world, according to the United States Energy Information Administration (EIA), and had a population growth rate of 8.8% between July 2010 and July 2015, more than double the United States population growth rate of 3.9% during the same period, according to the U.S. Census Bureau. ERCOT has shown historically above-average load growth compared to other power markets in the United States, according to the EIA, and ERCOT can be viewed as a “power island” due to its limited import and export capacity, which we believe creates a favorable power supply and demand dynamic. Total ERCOT power demand has grown at a compounded annual growth rate of approximately 1.5% from 2005 through 2015, compared to a range of -0.6% to 0.8% in other United States markets, according to ERCOT and the EIA, respectively.

We consider ERCOT to be one of the most well-developed power markets in the United States, providing a stable regulatory environment and significant price transparency, market liquidity and support to competitive generators and retail electric providers like us. The energy-only wholesale market structure in ERCOT offers a variety of potential revenue streams in addition to energy revenues such as ancillary services and the ORDC, which ERCOT implemented on June 1, 2014. A unique feature of the ERCOT energy market is the system-wide offer cap of $9,000/MWh, which is substantially higher than other markets with capacity markets. While the ERCOT market is currently oversupplied, we expect reserve margins to be forecasted to continue to compress over time due to growing demand, potential generation retirements and limited announced new-build projects, particularly of non-intermittent projects, further tightening the supply and demand balance and creating conditions that may generate increased price volatility and higher wholesale electricity prices. We believe that our existing asset base and integrated business model (including our integrated approach to risk management) will enable us to take advantage of these opportunities in a disciplined manner. See “— The ERCOT Market” below for more information about ERCOT and the ORDC.

 



 

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In addition, in general, Luminant’s generation portfolio (primarily the nuclear, lignite and coal generation facilities) is positioned to increase in value to the extent there is a rebound in forward natural gas prices. We cannot predict, however, whether or not forward natural gas prices will rebound or the timing of any such rebound if it were to occur in the future.

Strong balance sheet and strong liquidity profile. In connection with Emergence, a substantial amount of the debt of our Predecessor was eliminated. As a result, we believe our balance sheet is strong given our low leverage relative to the cash flows generated from our integrated business. Further, we believe our financial leverage is prudent and, together with our strong cash flow and strong liquidity profile, provides us with significant competitive advantages relative to our competitors, especially those that have much more leverage than we do. Moreover, it is our view that our integrated business model combined with our strong balance sheet sets us apart from other non-integrated pure-play IPPs in our industry, particularly those that have much more leverage than we do. We believe that our integrated business model further improves our liquidity profile relative to our non-integrated competitors because such integration reduces our retail operations’ exposure to wholesale electricity price volatility resulting in our retail operations having lower collateral requirements with counterparties and ERCOT. We also believe a strong balance sheet allows us to manage through periods of commodity price volatility that may require incremental liquidity and positions us well to pursue a range of capital deployment strategies, including investing in our current business, funding attractive organic and acquisition-driven growth opportunities and returning capital to our stockholders. 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.

Proven, experienced management team. The members of our senior management team have significant industry experience, including experience operating in a competitive retail electricity environment, operating sophisticated power generation facilities, operating a safe and cost-efficient mining organization and managing the risks of competitive wholesale and retail electricity businesses. We believe that our management team’s history of safe and reliable operations in our industry, breadth of positive relationships with regulatory and legislative authorities and commitment to a disciplined and prudent operating cost structure and capital allocation will benefit our stakeholders. Moreover, between personal investments in our common stock and our incentive compensation arrangements, our management team has a meaningful stake in Vistra Energy, thereby closely aligning incentives between management and our stockholders.

Our Business Strategy

Our business strategy is to deliver long-term stakeholder value through a multi-faceted focus on the following areas:

Integrated business model. 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 insulates us from commodity price movements and provides unique earnings stability. Consequently, our integrated business model will be at the core of our business strategy.

Superior customer service. Through TXU Energy, we serve the retail electricity needs of end-use residential, small business, commercial and industrial electricity customers through multiple sales and marketing channels. In addition to benefitting from our integrated business model, we leverage our strong brand, our commitment to a consistent and reliable product offering, the backstop of the electricity generated by our generation fleet, our industry-leading wholesale commodity risk management operations and exceptional, innovative and dependable 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

 



 

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proposition. We maintain a focus on solutions that give our customers choice, convenience and control over how and when they use electricity and related services, including Free Nights and Weekends residential plans, MyEnergy DashboardSM, TXU Energy’s iThermostat product and mobile solutions, the TXU Energy Rewards program, the TXU Energy Green UpSM 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 strong customer service, innovative products and trusted brand have resulted in us 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 and implementing enterprise-wide process and operating improvements without compromising the safety of our communities, customers and employees. In connection with Emergence, we implemented certain cost-reduction actions in order to better align and right-size our cost structure. We believe we have a highly effective and efficient cost structure and that our cost structure supports excellence in our operations. We will continue to refine and optimize our cost structure as opportunities arise.

Integrated hedging and commercial management. Our commercial team is focused on managing risk, through opportunistic hedging, and optimizing our assets and business positions. We actively manage our exposure to wholesale electricity prices in ERCOT, on an integrated basis, through contracts for physical delivery of electricity, exchange-traded and over-the-counter financial contracts, ERCOT term, day-ahead and real-time market transactions and bilateral contracts with other wholesale market participants, including other power generators and end-user electricity customers. These hedging activities include short-term agreements, long-term electricity sales contracts and forward sales of natural gas through financial instruments. The historically positive correlation between natural gas prices and wholesale electricity prices in the ERCOT market 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.

Disciplined capital allocation. Like any energy-focused business, we are potentially subject to significant commodity price volatility and capital costs. Accordingly, our strategy is to maintain a balance sheet with prudent financial leverage supported by readily accessible, flexible and diverse sources of liquidity. Our ongoing capital allocation priorities primarily include making necessary capital investments to maintain the safety and reliability of our facilities. Because we believe cost discipline and strong management of our assets and commodity positions are necessary to deliver long-term value to our stakeholders, we generally make capital allocation decisions that we believe will lead to attractive cash returns on investment. We are focused on optimal deployment of capital and intend to evaluate a range of capital deployment strategies including return of capital to stockholders in the form of dividends and/or share repurchases, investments in our current business and acquisition-driven growth investments.

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,

 



 

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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. To that end, our primary focus will target growth opportunities that expand or enhance our business position within ERCOT and are consistent with our integrated business model (including our stable earnings profile as compared to our non-integrated competitors). While we solely operate within ERCOT currently, we intend to evaluate energy infrastructure growth opportunities outside ERCOT that offer compelling value creation opportunities, including cost and operational improvements, organic growth opportunities and attractive and stable earnings profiles featuring multiple revenue streams. We also believe that there will continue to be significant acquisition opportunities for competitive power generation assets and retail electricity businesses in power markets in the United States based on, among other things, the continuing trend of separating competitive power generation assets from regulated utility assets. 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 our operations. Our company and our employees are actively engaged in programs intended to support and strengthen the communities in which we conduct our operations. Our foremost giving initiatives, the United Way and TXU Energy Aid campaigns, have raised more than $30 million in employee and corporate contributions since 2000. Additionally, for more than 30 years, TXU Energy Aid has served as an integral resource for social service agencies that assist families in need, having helped more than 500,000 customers across Texas pay their electricity bills.

 



 

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The ERCOT Market

ERCOT is an ISO that manages the flow of electricity from approximately 77,000 MW of installed capacity to 24 million Texas customers, representing 90% of the state’s electric load and spanning approximately 75% of its geography, as of September 30, 2016. ERCOT is a highly competitive wholesale electricity market with historically above-average demand growth, limited import and export capacity and increasing wholesale price caps, and is the seventh-largest power market in the world, according to the EIA. Population growth in Texas is currently expanding at well above the national average rate, with a growth rate of 8.8% between July 2010 and July 2016, more than double the United States population growth rate of 3.9% during the same period, according to the U.S. Census Bureau. ERCOT accounts for approximately 32% of the competitively served retail load in the United States and residential consumers in the ERCOT market consume approximately 32% more electricity than the average United States residential consumer according to the EIA. Total ERCOT power demand has grown at a compounded annual growth rate of approximately 1.5% from 2005 through 2015, compared to a range of -0.6% to 0.8% in other United States markets, according to ERCOT and the EIA, respectively. ERCOT was formed in 1970 and became the first ISO in the United States in September 1996. The following map illustrates ERCOT by regions:

 

 

LOGO

As an energy-only market, ERCOT’s market design is distinct from other competitive electricity markets in the United States. Other markets maintain a minimum reserve margin through regulated planning, resource adequacy requirements and/or capacity markets. In contrast, ERCOT’s resource adequacy is predominately dependent on free-market processes and energy-market price signals. On June 1, 2014, ERCOT implemented the ORDC, pursuant to which wholesale electricity prices in the real-time electricity market increase automatically as available operating reserves decrease below defined threshold levels, creating a price adder. When operating reserves drop to 2,000 MW or less, the ORDC automatically adjusts power prices to the established VOLL, which is set at $9,000/MWh. Because ERCOT has limited excess generation capacity to meet high demand days due to its minimal import capacity, and peaking facilities have high operating costs, the marginal price of supply rapidly increases during periods of high demand. Historically, elevated temperatures in the summer months have driven high electricity demand in ERCOT. Many generators benefit from these sporadic periods of “scarcity pricing” in which power prices may increase significantly, up to the current $9,000/MWh price cap.

 



 

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Transactions in ERCOT take place in two key markets: the day-ahead market and the real-time market. The day-ahead market is a voluntary, forward electricity market conducted the day before each operating day in which generators and purchasers of electricity may bid for one or more hours of electricity supply or consumption. The real-time market is a spot market in which electricity may be sold in five-minute intervals. The day-ahead market provides market participants with visibility into where prices are expected to clear, and the prices are not impacted by subsequent events. Conversely, the real-time market exposes purchasers to the risk of transient operational events and price spikes. These two markets allow market participants to manage their risk profile by adjusting their participation in each market. In addition, ERCOT uses ancillary services to maintain system reliability, including regulation service — up, regulation service — down, responsive reserve service and non-spinning reserve service. Regulation service up and down are used to balance the grid in a near-instantaneous fashion when supply and demand fluctuate due to a variety of factors, such as weather, generation outages, renewable production intermittency and transmission outages. Responsive reserves and non-spinning reserves are used by ERCOT when the grid is at, near or recovering from a state of emergency due to inadequate generation. Because ERCOT has one of the highest concentrations of wind capacity generation among United States markets, the ERCOT market is more susceptible to fluctuations in wholesale electricity supply due to intermittent wind production, making ERCOT more vulnerable to periods of generation scarcity.

Reorganization and Emergence

On April 29, 2014, Energy Future Holdings Corp. (EFH Corp.) and the substantial majority of its direct and indirect subsidiaries, including Energy Future Intermediate Holding Company LLC (EFIH), Energy Future Competitive Holdings Company LLC (EFCH) and our Predecessor, Texas Competitive Electric Holdings Company LLC, but excluding Oncor Electric Holdings Company LLC and its direct and indirect subsidiaries (Oncor), filed for bankruptcy protection (the Bankruptcy Filing or Petition) pursuant to Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code). We refer to EFH Corp. and the other entities that filed for bankruptcy collectively as the Debtors.

The Bankruptcy Filing resulted primarily from the adverse effects on the Debtors’ (including our Predecessor’s) business of lower wholesale electricity prices in ERCOT driven by the sustained decline in natural gas prices since mid-2008, together with the obligations from the substantial amount of debt EFH Corp. (including our Predecessor) had previously incurred as a result of the leveraged buy-out of EFH Corp. in October 2007. These market conditions challenged the results of operations and cash flows of EFH Corp. and our Predecessor and resulted in the inability to support their significant interest payments and pending debt maturities.

On August 29, 2016, the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court) confirmed the Debtors’ Third Amended Joint Plan of Reorganization (the Plan) solely with respect to EFCH and its subsidiaries (including our Predecessor) and certain other subsidiaries of EFH Corp. described in the Plan. We refer to these Debtors collectively as the T-Side Debtors. All of the other Debtors, which include EFH Corp. and EFIH, remain in bankruptcy and are referred to collectively as the EFH Debtors.

On October 3, 2016 (the Effective Date), the Plan with respect to the T-Side Debtors, including our Predecessor, became effective and the T-Side Debtors consummated their reorganization under the Bankruptcy Code and emerged from bankruptcy. Pursuant to the Plan, in connection with Emergence, among other actions, Vistra Energy was formed and became the ultimate parent holding company for the subsidiaries of our Predecessor and certain other subsidiaries of EFH Corp. identified in the Plan. In exchange for the cancellation of their allowed claims against our Predecessor, first-lien creditors of our Predecessor, including the selling stockholders named in this prospectus, received, among other things, newly issued shares of Vistra Energy common stock as well as certain rights (the TRA Rights) to receive payments from Vistra Energy of certain tax

 



 

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benefits, including those it realized as a result of the transactions entered into at Emergence under the terms of a tax receivable agreement (the Tax Receivable Agreement). See “Certain Relationships and Related Party Transactions — Tax Receivable Agreement.”

On the Effective Date, we entered into a number of agreements, including a Registration Rights Agreement (the Registration Rights Agreement), pursuant to which we agreed, among other matters, to register for resale with the Securities and Exchange Commission (the Commission) the shares of our common stock issued to the selling stockholders in connection with Emergence transactions. See “Certain Relationship and Related Party Transactions —Registration Rights Agreement.”

 



 

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The following chart shows the ownership structure of Vistra Energy and certain of its key subsidiaries after giving effect to Emergence.

 

 

LOGO

As of December 15, 2016

 

* 100% Common Stock held by Vistra Asset Company LLC. Preferred stock held by outside investors

For a more detailed discussion of the Bankruptcy Filing and Emergence see “The Reorganization and Emergence.”

 



 

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Recent Developments

On December 8, 2016, the board of directors of Vistra Energy (the Board) approved the payment of a special cash dividend in the aggregate amount of approximately $1 billion (the 2016 Special Dividend) to holders of record of our common stock on December 19, 2016. On December 14, 2016, Vistra Operations Company LLC (Vistra Operations) obtained (i) $1 billion aggregate principal amount of incremental term loans (the 2016 Incremental Term Loans) and (ii) $110 million of incremental revolving credit commitments under the Vistra Operations Credit Facilities (as defined herein). See “Description of Indebtedness — Credit Facilities” for further information. Proceeds from the 2016 Incremental Term Loans will be used to make the 2016 Special Dividend.

 



 

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The Offering

The selling stockholders may offer all, some or none of their shares of our common stock from time to time. Please see “Plan of Distribution.”

The following table provides information regarding our common stock. The outstanding share information shown below is based on shares of our common stock outstanding as of December 15, 2016.

 

Issuer

Vistra Energy Corp.

 

Outstanding common stock that may be offered by the selling stockholders

Up to 168,748,919 shares

 

Common stock outstanding as of December 15, 2016

427,580,232 shares (1)

 

Use of proceeds

We will not receive any of the proceeds from the resale of our common stock by the selling stockholders. See “Use of Proceeds” and “Principal and Selling Stockholders.”

 

Symbol for common stock

“                     ”

 

Determination of offering price

The selling stockholders may resell all or any part of the shares of our common stock offered hereby from time to time at fixed prices, prevailing market prices at the times of sale, prices related to such prevailing market prices, varying prices determined at the times of sale or negotiated prices.

 

Dividend policy

Except for the 2016 Special Dividend, we have no present intention to pay cash dividends on our common stock. However, we are focused on optimal deployment of capital and intend to evaluate a range of capital deployment strategies, including the return of capital to stockholders in the form of dividends and/or share repurchases.

 

  Any determination to pay dividends to holders of our common stock or to repurchase our common stock in the future will be at the sole discretion of the Board and will depend upon many factors, including our historical and anticipated financial condition, cash flows, liquidity and results of operations, capital requirements, market conditions, our growth strategy and the availability of growth opportunities, contractual prohibitions, applicable law and other factors that the Board deems relevant. See “Market Prices and Dividend Policy—Dividends and Dividend Policy.”

 

Risk factors

Before making a decision to invest in our common stock, you should carefully consider the information referred to under the heading “Risk Factors” beginning on page 24.

 

(1) Unless indicated otherwise in this prospectus, the number of shares outstanding does not include:

 

    7,296,854 shares of common stock issuable upon exercise of stock options issued pursuant to our 2016 Incentive Plan (as defined herein);

 



 

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    2,139,999 shares of common stock issuable following vesting in settlement of restricted stock units outstanding under our 2016 Incentive Plan; and

 

    13,063,147 shares of common stock reserved for future issuance under our 2016 Incentive Plan.

 



 

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Summary Historical and Unaudited Pro Forma Condensed Consolidated Financial Information

Summary Historical Financial Information

The following table sets forth summary historical consolidated financial information for our Predecessor and its consolidated subsidiaries. The summary historical consolidated financial information as of December 31, 2015 and 2014 and for the years ended December 31, 2015, 2014 and 2013 are derived from our Predecessor’s audited consolidated financial statements included elsewhere in this prospectus. The summary historical consolidated financial information as of September 30, 2016 and for the nine months ended September 30, 2016 and 2015 are derived from our Predecessor’s unaudited condensed consolidated financial statements included elsewhere in this prospectus, which have been prepared on a basis consistent with our Predecessor’s audited consolidated financial statements. The summary historical consolidated financial information as of December 31, 2013 has been derived from our Predecessor’s historical audited consolidated balance sheet not included in this prospectus. These tables should be read in conjunction with “Selected Historical Consolidated Financial Information,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the condensed consolidated financial statements as well as our pro forma condensed consolidated financial statements and, in each case, the related notes included elsewhere in this prospectus. In addition, as you review the consolidated Predecessor financial statements set forth herein you should be aware that such Predecessor financial statements will not be comparable to our future financial statements because such Predecessor financial statements do not take into account the effects of the Plan and Emergence or any required adjustments for fresh-start reporting, in each case, which will be taken into account in our future financial statements.

 

     Nine Months Ended September 30,     Year Ended December 31,  
         2016             2015         2015     2014     2013  
     (in millions)  

Operating revenues

   $ 3,973      $ 4,265      $ 5,370      $ 5,978      $ 5,899   

Impairment of goodwill

   $     $ (1,400   $ (2,200   $ (1,600   $ (1,000

Impairment of long-lived assets

   $     $ (1,971   $ (2,541   $ (4,670   $ (140

Net loss attributable to our Predecessor

   $ (656   $ (3,067   $ (4,677   $ (6,229   $ (2,197

Cash provided by (used in) operating activities

   $ (196   $ 209     $ 237      $ 444      $ (270

 

     At September 30,      At December 31,  
     2016      2015      2014      2013  
     (in millions)  

Total assets (a)(b)

   $ 16,875       $ 15,658       $ 21,343       $ 28,822   

Property, plant & equipment — net (a)(b)

   $ 10,359       $ 9,349       $ 12,288       $ 17,649   

Goodwill and intangible assets

   $ 1,300       $ 1,331       $ 3,688       $ 5,669   

Borrowings, debt and pre-petition loans and other debt

           

Borrowings under debtor-in-possession credit facilities (c)

   $ 3,387       $ 1,425       $ 1,425       $  

Debt (d)

   $      $ 3       $ 51       $ 26,146   

Pre-Petition notes, loans and other debt reported as liabilities subject to compromise (e)

   $ 31,668       $ 31,668       $ 31,856       $  

Borrowings under credit and other facilities (f)

   $      $      $      $ 2,054   

 

(a) As of September 30, 2016, amount includes the Lamar and Forney natural gas generation facilities purchased in April 2016. See Note 3 to the September 30, 2016 Quarterly Financial Statements for further discussion.
(b) 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 8 to the 2015 Annual Financial Statements).

 



 

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(c) Borrowings under debtor-in-possession credit facilities are classified as noncurrent as of September 30, 2016 and December 31, 2014 and due currently as of December 31, 2015.
(d) For all periods presented, excludes amounts with contractual maturity dates in the following twelve months.
(e) As of September 30, 2016 and 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.
(f) Excludes borrowings under debtor-in-possession credit facilities.

 



 

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Summary Unaudited Pro Forma Condensed Consolidated Financial Information

The following tables set forth summary unaudited pro forma condensed consolidated financial information which combines the condensed consolidated financial information of our Predecessor as of and for the nine months ended September 30, 2016 and for the year ended December 31, 2015 after giving effect to (i) the implementation of all reorganization transactions contemplated by the Plan, (ii) the application of fresh-start reporting for the emerged entity, Vistra Energy, and (iii) the incurrence of the $1 billion 2016 Incremental Term Loans and the related 2016 Special Dividend in the approximate amount of $1 billion expected to be paid on December 30, 2016. The unaudited pro forma condensed consolidated statements of income (loss) for the year ended December 31, 2015 and nine months ended September 30, 2016 give effect to the pro forma adjustments as if each adjustment had occurred on January 1, 2015, the first day of the last fiscal year presented. The unaudited pro forma condensed consolidated balance sheet as of September 30, 2016 gives effect to the pro forma adjustments as if each adjustment had occurred on September 30, 2016, the latest balance sheet date presented. The summary unaudited pro forma condensed consolidated financial information is provided for illustrative purposes only and does not purport to represent what our actual condensed consolidated results of operations or condensed consolidated financial position would have been had the adjustments occurred on the dates assumed, nor is it necessarily indicative of future condensed consolidated results of operations or condensed consolidated financial position.

This information is only a summary and should be read in conjunction with “Risk Factors,” “Selected Historical Consolidated Financial Information,” “Unaudited Pro Forma Condensed Consolidated Financial Information” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” which are included elsewhere in this prospectus. Among other things, the pro forma financial statements included in “Unaudited Pro Forma Condensed Consolidated Financial Information” provide more detailed information regarding the basis of presentation for, and the adjustments and assumptions underlying, the information in the following tables.

 

     Nine Months Ended
September 30, 2016
    Year Ended December 31,
2015
 
     Our
Predecessor
As Reported
    Vistra Energy
Pro Forma As
Adjusted
    Our
Predecessor
As Reported
    Vistra Energy
Pro Forma As
Adjusted
 

Statement of Income (Loss) Information:

        

Operating revenues

   $ 3,973      $ 3,934      $ 5,370      $ 5,231   

Interest expense and related charges

   $ (1,049   $ (163   $ (1,289   $ (225

Net income (loss)

   $ (656   $ 217      $ (4,677   $ 279   

 

     September 30, 2016  
     Our
Predecessor As
Reported
     Vistra Energy
Pro Forma As
Adjusted
 

Balance Sheet Information (at period end):

     

Cash and cash equivalents

   $ 1,829       $ 775   

Total current assets

   $ 3,387       $ 2,277   

Total assets

   $ 16,875       $ 14,611   

Total current liabilities

   $ 1,229       $ 1,178   

Borrowings under debtor-in-possession credit facilities

   $ 3,387       $  

Long-term debt, less amounts due currently

   $      $ 4,556   

Total liabilities and equity

   $ 16,875       $ 14,611   

 



 

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Risk Factors

Important factors, in addition to others specifically addressed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” that could have a material adverse effect on our business, results of operations, liquidity, financial condition and prospects and the market prices of our common stock, which we refer to collectively as a material adverse effect on us (or comparable phrases), or could cause results or outcomes to differ materially from those contained in or implied by any forward-looking statement in this prospectus, are described below. There may be further risks and uncertainties that are not currently known or that are not currently believed to be material that may adversely affect our business, results of operations, liquidity, financial condition and prospects and the market price of our common stock in the future. The realization of any of these factors could cause investors in our common stock to lose all or a substantial portion of their investment.

Market, Financial and Economic Risks

Our revenues, results of operations and operating cash flows generally are negatively impacted by decreases in market prices for electricity.

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

Some of the fuel for our generation facilities is purchased under short-term contracts. Fuel costs (including diesel, natural gas, lignite, coal and nuclear fuel) may be volatile, and the wholesale price for electricity may not change at the same rate as changes in fuel costs. In addition, we purchase and sell natural gas and other energy related commodities, and volatility in these markets may affect costs incurred in meeting obligations.

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

 

    volatility in natural gas prices;

 

    volatility in ERCOT market heat rates;

 

    volatility in coal and rail transportation prices;

 

    volatility in nuclear fuel and related enrichment and conversion services;

 

    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;

 

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    availability of competitively-priced alternative energy sources or storage;

 

    changes in market structure and liquidity;

 

    changes in the manner in which we operate our facilities, including curtailed operation due to market pricing, environmental, safety or other factors;

 

    changes in generation efficiency;

 

    outages or otherwise reduced output from our generation facilities or those of our competitors;

 

    the addition of new electric capacity, including the construction of new power plants;

 

    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

 

    federal, state and local energy, environmental and other regulation and legislation.

All of our generation facilities are located in the ERCOT market, a market with limited interconnections to other markets. The price of electricity in the ERCOT market is typically set by natural gas-fueled generation facilities, with wholesale electricity prices generally tracking increases or decreases in the price of natural gas. A substantial portion of our supply volumes in 2015 and the nine months ended September 30, 2016 were produced by our nuclear-, lignite- and coal-fueled generation assets. Natural gas prices have generally trended downward since mid-2008 (from $11.12 per MMBtu in mid-2008 to $2.66 per MMBtu for the average settled price for the year ended December 31, 2015). Furthermore, in recent years, natural gas supply has outpaced demand primarily as a result of development and expansion of hydraulic fracturing in natural gas extraction, and the supply/demand imbalance has resulted in historically low natural gas prices. Because our baseload generating units and a substantial portion of our load following generating units are nuclear-, lignite- and coal-fueled, our results of operations and operating cash flows have been negatively impacted by the effect of low natural gas prices on wholesale electricity prices without a significant decrease in our operating cost inputs. Various industry experts expect this supply/demand imbalance to persist for a number of years, thereby depressing natural gas prices for a long-term period. As a result, the financial results from, and the value of, our generation assets could remain depressed or could materially decrease in the future unless natural gas prices rebound materially.

Wholesale electricity prices also track ERCOT market heat rates, which can be affected by a number of factors, including generation availability and the efficiency of the marginal supplier (generally natural gas-fueled generation facilities) in generating electricity. Our market heat rate exposure is impacted by changes in the availability of generating resources, such as additions and retirements of generation facilities, and the mix of generation assets in ERCOT. For example, increasing renewable (wind and solar) generation capacity generally depresses market heat rates. Additionally, construction of more efficient generation capacity also depresses market heat rates. Decreases in market heat rates decrease the value of all of our generation assets because lower market heat rates generally result in lower wholesale electricity prices. Even though market heat rates have generally increased over the past several years, wholesale electricity prices have declined due to the greater effect of falling natural gas prices. As a result, the financial results from, and the value of, our nuclear-, lignite- and coal-fueled generation assets could significantly decrease in profitability and value and our financial condition and results of operations may be negatively impacted if ERCOT market heat rates decline.

A sustained decrease in the financial results from, or the value of, our generation units ultimately could result in the retirement or idling of certain generation units. In recent years, we have operated certain of our lignite- and coal-fueled generation assets only during parts of the year that have higher electricity demand and, therefore, higher related wholesale electricity prices.

 

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

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

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

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

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

To the extent we engage in hedging and risk management activities, we are exposed to the credit risk that counterparties that owe us money, energy or other commodities as a result of these activities will not perform their obligations to us. Should the counterparties to these arrangements fail to perform, we could be forced to enter into alternative hedging arrangements or honor the underlying commitment at then-current market prices. In such event, we could incur losses or forgo expected gains in addition to amounts, if any, already paid to the counterparties. ERCOT market participants are also exposed to risks that another ERCOT market participant may default on its obligations to pay ERCOT for electricity or services taken, in which case such costs, to the extent not offset by posted security and other protections available to ERCOT, may be allocated to various non-defaulting ERCOT market participants, including us.

 

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

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

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

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

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

 

    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 ERCOT or general United States 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 Corp.’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 ERCOT wholesale electricity market;

 

    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.

 

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

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

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

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

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

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

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

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

 

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operations may result in unforeseen operating difficulties and expenses and may require significant financial resources that would otherwise be available for the execution of our business strategy.

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

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

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

We are also required to indemnify EFH Corp. against certain taxes in the event the IRS or another taxing authority successfully challenges the amount of gain relating to the PrefCo Preferred Stock Sale (as defined in “The Reorganization and Emergence”) or the amount or allowance of EFH Corp.’s net operating loss deductions.

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

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

On the Effective Date, we entered into a tax receivable agreement (the Tax Receivable Agreement) with American Stock Transfer & Trust Company, LLC, as the transfer agent. Pursuant to the Tax Receivable Agreement, we issued beneficial interests in the rights to receive payments under the Tax Receivable Agreement (the TRA Rights) to the first lien creditors of our Predecessor to be held in escrow for the benefit of the first lien creditors of our Predecessor entitled to receive such TRA Rights under the Plan. Our pro forma financial statements included elsewhere in this prospectus reflect a liability of $938 million related to these future payment obligations. This amount is based on certain assumptions as described more fully in the notes to the pro forma financial statements, including assumptions on the current corporate tax rates remaining unchanged, and the actual payments made under the Tax Receivable Agreement could materially exceed this estimate.

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

 

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Although we are not aware of any issue that would cause the IRS to challenge the tax benefits that are the subject of the Tax Receivable Agreement, recipients of the payments under the Tax Receivable Agreement will not be required to reimburse us for any payments previously made if such tax benefits are subsequently disallowed. As a result, in such circumstances, Vistra Energy Corp. could make payments under the Tax Receivable Agreement that are greater than its actual cash tax savings and may not be able to recoup those payments, which could adversely affect our liquidity.

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

The payments we will be required to make under the Tax Receivable Agreement could be substantial.

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

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

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

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

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

Prior to the Spin-Off, EFH Corporate Services Company, EFH Properties Company and certain other subsidiary corporations were included in the consolidated United States federal income tax group of which EFH Corp. was the common parent (the EFH Corp. Consolidated Group). In addition, pursuant to the private letter ruling from the IRS we received in connection with the Spin-Off, Vistra Energy will be considered a member of the EFH Corp. Consolidated Group prior to the Spin-Off. Under United States federal income tax laws, any corporation that is a member of a consolidated group at any time during a taxable year is jointly and severally liable for the group’s entire federal income tax liability for the entire taxable year. In addition, entities that are disregarded for federal income tax purposes may be liable as successors under common law theories or under certain regulations to the extent corporations transferred assets to such entities or merged or otherwise consolidated into such entities, whether under state law or purely as a matter of federal income tax law. Thus, notwithstanding any contractual rights to be reimbursed or indemnified by EFH Corp. pursuant to the Tax Matters Agreement, to the extent EFH Corp. or other members of the EFH Corp. Consolidated Group fail to make any federal income tax payments required of them by law in respect of taxable years for which we were a

 

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member of the EFH Corp. Consolidated Group, we may be liable for the shortfall. At such time, we may not have sufficient cash on hand to satisfy such payment obligation.

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

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

The costs of providing postretirement benefits and related funding requirements are subject to changes in value of fund assets, benefit costs, demographics and actuarial assumptions and may have a material adverse effect on us.

To a limited extent, we provide pension benefits and certain health care and life insurance benefits to certain of our eligible employees and their eligible dependents upon the retirement of such employees. Our costs of providing such benefits and related funding requirements are dependent upon numerous factors, assumptions and estimates and are subject to changes in these factors, assumptions and estimates, including the market value of the assets funding the pension and Other Post-Employment Benefits (OPEB) plans.

The values of the investments that fund the pension and OPEB plans are subject to changes in financial market conditions. Significant decreases in the values of these investments could increase the expenses of the pension plans and the costs of the OPEB plans and related funding requirements in the future. Our costs of providing such benefits and related funding requirements are also subject to changing employee demographics (including, but not limited to age, compensation levels and years of accredited service), the level of contributions made to retiree plans, expected and actual earnings on plan assets and the discount rates used in determining the projected benefit obligation. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in financial market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.

Regulatory and Legislative Risks

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

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

Our businesses are subject to numerous state and federal laws (including PURA, the Federal Power Act, the Atomic Energy Act, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act (the CAA), the Energy Policy Act of 2005 and the Dodd-Frank Wall Street Reform and Consumer Protection Act), changing governmental policy and regulatory actions (including those of the PUCT, the NERC, the TRE, the RCT, the TCEQ, the FERC, the MSHA, the EPA, the NRC and the CFTC) and the rules, guidelines and protocols of ERCOT with respect to various matters, including, but not limited to, market structure and design, operation of nuclear generation facilities, construction and operation of other generation facilities, development, operation and

 

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reclamation of lignite mines, recovery of costs and investments, decommissioning costs, market behavior rules, present or prospective wholesale and retail competition and environmental matters. We, along with other market participants, are subject to electricity pricing constraints and market behavior and other competition-related rules and regulations under PURA that are administered by the PUCT and ERCOT. Changes in, revisions to, or reinterpretations of, existing laws and regulations may have a material adverse effect on us. Further, in the future we could expand our business, through acquisitions or otherwise, to geographic areas outside of Texas and the ERCOT market. Such expansion would subject us to additional state regulatory requirements that could have material adverse effect on us.

The Texas Legislature meets every two years. The next regular legislative session is scheduled to begin in January 2017. However, at any time the governor of Texas may convene a special session of the legislature. During any regular or special session, bills may be introduced that, if adopted, could materially and adversely affect our businesses, results of operations, liquidity and financial condition.

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

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

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

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

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

The EPA has recently finalized or proposed several regulatory actions establishing new requirements for control of certain emissions from sources, including electricity generation facilities. In the future, the EPA may

 

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

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

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

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

There is a concern nationally and internationally about global climate change and how GHG emissions, such as CO2, contribute to global climate change. Over the last several years, the United States Congress has considered and debated, and President Obama’s administration has discussed, several proposals intended to address climate change using different approaches, including a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade), a tax on carbon or GHG emissions, incentives for the development of low-carbon technology and federal renewable portfolio standards. The EPA has also finalized regulations under the Clean Air Act to limit CO2 emissions from existing generating units, referred to as the Clean Power Plan. While currently the subject of a legal challenge, if implemented as finalized, the Clean Power Plan would require the closure of a significant number of coal-fueled electric generating units nationwide and in Texas. In addition, a number of federal court cases have been filed in recent years asserting damage claims related to GHG emissions, and the results in those proceedings could establish adverse precedent that might apply to companies (including us) that produce GHG emissions. For more detailed discussion of recent global climate change legislation and regulation, see “Business — Legal Proceedings and Regulatory Matters.” We could be materially and adversely affected if new federal and/or state legislation or regulations are adopted to address global climate change, if the Clean Power Plan is implemented as finalized or if we are subject to lawsuits for alleged damage to persons or property resulting from GHG emissions.

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

We are required to maintain, through either allocations or purchases, sufficient emission allowances for SO2 and NOx to support our operations in the ordinary course of operating our power generation facilities. These allowances are used to meet the obligations imposed on us by various applicable environmental laws. If our operational needs require more than our allocated allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as not to exceed our available emission allowances,

 

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or install costly new emission controls. As we use the emission allowances that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such allowances are available for purchase, but only at significantly higher prices, the purchase of such allowances could materially increase our costs of operations in the affected markets.

Luminant’s mining operations are subject to RCT oversight.

We currently own and operate through Luminant 11 surface lignite coal mines in Texas to provide fuel for our electricity generation facilities. The RCT, which exercises broad authority to regulate reclamation activity, reviews on an ongoing basis whether Luminant is compliant with RCT rules and regulations and whether it has met all of the requirements of its mining permits. Any new rules and regulations adopted by the RCT or the Department of Interior Office of Surface Mining, which also regulates mining activity nationwide, or any changes in the interpretation of existing rules and regulations, could result in higher compliance costs or otherwise adversely affect our financial condition or cause a revocation of a mining permit. Any revocation of a mining permit would mean that Luminant would no longer be allowed to mine lignite at the applicable mine to serve its generation facilities. In addition, Luminant’s mining reclamation obligations are secured by a first lien on its assets which is pari passu with the Vistra Operations Credit Facilities (but which would be paid first (up to $975 million) upon any liquidation of Vistra Operations Company LLC’s (Vistra Operations) assets). The RCT could, at any time, require that Luminant’s mining reclamation obligations be secured by cash or letters of credit in lieu of such first lien. Any failure to provide any such cash or letter of credit collateral could result in Luminant no longer being able to mine lignite. Any such event could have a material adverse effect on us.

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

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

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

The REP certification of our retail operation is subject to PUCT review.

The PUCT may at any time initiate an investigation into whether our retail operation complies with certain PUCT rules and whether we have met all of the requirements for REP certification, including financial requirements. Any removal or revocation of an REP certification would mean that we would no longer be allowed to provide electricity service to retail customers. Such decertification could have a material adverse effect on us. Moreover, any capital or other expenditures that we are required by the PUCT to undertake in order to achieve or maintain any such compliance could also have a material adverse effect on us.

 

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Operational Risks

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

We operate in a very competitive retail market and, as a result, our retail operation faces significant competition for customers. We believe our TXU EnergyTM brand is viewed favorably in the retail electricity markets in which we operate, but despite our commitment to providing superior customer service and innovative products, customer sentiment toward our brand, including by comparison to our competitors’ brands, depends on certain factors beyond our control. For example, competitor REPs may offer lower electricity prices and other incentives, which, despite our long-standing relationship with many customers, may attract customers away from us. This and other competitive retail activity has resulted in retail customer churn and our total retail customer counts have declined approximately 1% during the nine months ended September 30, 2016. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Significant Activities and Events and Items Influencing Future Performance — Competitive Retail Markets and Customer Retention.” If we are unable to successfully compete with competitors in the retail market it is possible our retail customer counts could continue to decline, which could have a material adverse effect on us.

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

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

Our retail operations depend on transmission and distribution facilities owned and operated by unaffiliated utilities to deliver the electricity that we sell to our customers. If transmission capacity is inadequate, our ability to sell and deliver electricity may be hindered and we may have to forgo sales or buy more expensive wholesale electricity than is available in the capacity-constrained area. For example, during some periods, transmission access is constrained in some areas of the Dallas-Fort Worth metroplex, where we have a significant number of customers. The cost to provide service to these customers may exceed the cost to provide service to other customers, resulting in lower operating margins. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to our customers could negatively impact customer satisfaction with our service. Any of the foregoing could have a material adverse effect on us.

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

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

 

    unscheduled outages or unexpected costs due to equipment, mechanical, structural, cyber security or other problems;

 

    inadequacy or lapses in maintenance protocols;

 

    the impairment of reactor operation and safety systems due to human error or force majeure;

 

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    the costs of, and liabilities relating to, storage, handling, treatment, transport, release, use and disposal of radioactive materials;

 

    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 cyber security 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.

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

 

    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, including potential regulation as a result of the NRC’s ongoing analysis and response to the effects of the natural disaster on nuclear generation facilities in Japan in 2010, 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 United States and elsewhere. The consequences of an accident can be severe and include loss of life, injury, lasting negative health impacts and property damage. Any accident, or perceived accident, could result in significant liabilities and damage our reputation. Any such resulting liability from a nuclear accident could exceed our resources, including insurance coverage, and could ultimately result in the suspension or termination of power generation from the Comanche Peak Facility.

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

The operation and maintenance of power generation facilities and related mining operations involve many risks, including, as applicable, start-up risks, breakdown or failure of facilities, operator error, lack of sufficient capital to maintain the facilities, the dependence on a specific fuel source or the impact of unusual or adverse weather conditions or other natural events, or terrorist attacks, as well as the risk of performance below expected levels of output, efficiency or reliability, the occurrence of any of which could result in substantial lost revenues and/or increased expenses. A significant number of our facilities were constructed many years ago. In particular, older generating equipment, even if maintained in accordance with good engineering practices, may require

 

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significant capital expenditures to operate at peak efficiency or reliability. The risk of increased maintenance and capital expenditures arises from (a) increased starting and stopping of generation equipment due to the volatility of the competitive generation market and the prospect of continuing low wholesale electricity prices that may not justify sustained or year-round operation of all our generation facilities, (b) any unexpected failure to generate power, including failure caused by equipment breakdown or unplanned outage (whether by order of applicable governmental regulatory authorities, the impact of weather events or natural disasters or otherwise), (c) damage to facilities due to storms, natural disasters, wars, terrorist or cyber security acts and other catastrophic events and (d) the passage of time and normal wear and tear. Further, our ability to successfully and timely complete routine maintenance or other capital projects at our existing facilities is contingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful, we could be subject to additional costs or losses and write downs of our investment in the project.

We cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety laws and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected events (such as natural disasters or terrorist or cyber security attacks). The unexpected requirement of large capital expenditures could have a material adverse effect on us.

In addition, if any of our generation facilities experiences unplanned outages, whether because of equipment breakdown or otherwise, we may be required to procure replacement power at spot market prices in order to fulfill contractual commitments. If we do not have adequate liquidity to meet margin and collateral requirements, we may be exposed to significant losses, may miss significant opportunities and may have increased exposure to the volatility of spot markets, which could have a material adverse effect on us.

Our employees, contractors, customers and the general public may be exposed to a risk of injury due to the nature of our operations.

Our employees and contractors work in, and customers and the general public may be exposed to, potentially dangerous environments at or near our operations. As a result, employees, contractors, customers and the general public are at risk for serious injury, including loss of life. Significant examples of such risks include nuclear accidents, dam failure, gas explosions, mine area collapses and other dangerous incidents.

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

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

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

Moreover, an extreme weather event could cause disruption in service to customers due to downed wires and poles or damage to other operating equipment, which could result in us foregoing sales of electricity and lost

 

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

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

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

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

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

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

Attacks on our infrastructure that breach cyber/data security measures could expose us to significant liabilities and reputation damage and disrupt business operations, which could have a material adverse effect on us.

Much of our information technology infrastructure is connected (directly or indirectly) to the internet. There have been numerous attacks on government and industry information technology systems through the internet that have resulted in material operational, reputation and/or financial costs. While we have controls in place designed to protect our infrastructure and we are not aware of any significant breaches in the past, a breach of cyber/data security measures that impairs our information technology infrastructure could disrupt normal

 

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business operations and affect our ability to control our generation assets, access retail customer information and limit communication with third parties. Any loss of confidential or proprietary data through a breach could adversely affect our reputation, expose us to material legal or regulatory claims and impair our ability to execute our business strategy, which could have a material adverse effect on us.

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

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

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

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

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

As of December 15, 2016, we had 1,782 employees covered by collective bargaining agreements, all of which expire on March 31, 2017. In the event that our union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, we would be responsible for procuring replacement labor or we could experience reduced power generation or outages. Our ability to procure such labor is uncertain. Strikes, work stoppages or the inability to negotiate future collective bargaining agreements on favorable terms or at all could have a material adverse effect on us.

Risks Related to Our Structure and Ownership of our Common Stock

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

Vistra Energy Corp. is a holding company that does not conduct any business operations of its own. As a result, Vistra Energy Corp.’s cash flows and ability to meet its obligations are largely dependent upon the operating cash flows of Vistra Energy Corp.’s subsidiaries and the payment of such operating cash flows to Vistra Energy Corp. in the form of dividends, distributions, loans or otherwise. These subsidiaries are separate and distinct legal entities from Vistra Energy Corp. and have no obligation (other than any existing contractual obligations) to provide Vistra Energy Corp. with funds to satisfy its obligations. Any decision by a subsidiary to provide Vistra Energy Corp. with funds to satisfy its obligations, including those under the Tax Receivable Agreement, whether by dividends, distributions, loans or otherwise, will depend on, among other things, such

 

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subsidiary’s results of operations, financial condition, cash flows, cash requirements, contractual prohibitions and other restrictions, applicable law and other factors. The deterioration of income from, or other available assets of, any such subsidiary for any reason could limit or impair its ability to pay dividends or make other distributions to Vistra Energy Corp.

No prior public trading market existed for our common stock prior to October 4, 2016, and an active trading market may not develop or be sustained following the registration of our common stock on                     , which may cause the market price of our common stock to decline significantly and make it difficult for investors to sell their shares in the future.

There was no public market for our common stock prior to commencing trading on the OTCQX market on October 4, 2016, and we have applied to list our common stock for trading on                     under the symbol “                      .” However, listing on                      does not ensure that an active trading market for our common shares will develop or be sustained. Accordingly, no assurance can be given as to:

 

    the likelihood that an active trading market for our shares of common stock will develop or be sustained;

 

    the liquidity of any such market;

 

    the ability of our stockholders to sell their shares of common stock when desired; or

 

    the price that our stockholders may obtain for their shares of common stock.

The stock markets, including                     , have from time to time experienced significant price and volume fluctuations. As a result, the market price of our common stock may be similarly volatile, and investors in shares of our common stock may from time to time experience a decrease in the market price of their shares, including decreases unrelated to our financial performance or prospects. The market price of shares of our common stock could be subject to wide fluctuations in response to a number of factors, including those listed in this ‘‘Risk Factors’’ section of this prospectus and others such as:

 

    our historical and anticipated operating performance and the performance of other similar companies;

 

    actual or anticipated differences in our quarterly or annual operating results than expected;

 

    actual or anticipated changes in our, our customers’ or our competitors’ businesses or prospects;

 

    changes in our revenues or earnings estimates or recommendations by securities analysts;

 

    publication of research reports about us or the power generation or electricity sales industries;

 

    the current state of the credit and capital markets, and our ability to obtain financing on favorable terms;

 

    increased competition in power generation and electricity sales in our markets;

 

    strategic decisions by us or our competitors, such as acquisitions, divestments, spin-offs, joint ventures, strategic investments or changes in business growth strategy;

 

    the passage of legislation or other regulatory developments that adversely affect us or our industry;

 

    adverse speculation in the press or investment community;

 

    actions by institutional stockholders;

 

    adverse market reaction to any indebtedness we may incur or equity or equity-related securities we may issue in the future;

 

    additions of departures of key personnel;

 

    actual, potential or perceived accounting problems;

 

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    changes in accounting principles;

 

    failure to comply with the rules of the Commission or                      or to maintain the listing of our common stock on                     ;

 

    terrorist acts, natural or man-made disasters or threatened or actual armed conflicts; and

 

    general market and local, regional and national economic conditions, including factors unrelated to our operating performance and prospects.

No assurance can be given that the market price of our common stock will not fluctuate or decline significantly in the future or that holders of shares of our common stock will be able to sell their shares when desired on favorable terms, or at all. From time to time in the past, securities class action litigation has been instituted against companies following periods of extreme volatility in their stock price. This type of litigation could result in substantial costs and divert our management’s attention and resources.

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

Except for the payment of the 2016 Special Dividend, we have no present intention to pay cash dividends on our common stock. Any determination to pay dividends to holders of our common stock in the future will be at the sole discretion of the Board and will depend upon many factors, including our historical and anticipated financial condition, cash flows, liquidity and results of operations, capital requirements, market conditions, our growth strategy and the availability of growth opportunities, contractual prohibitions and other restrictions with respect to the payment of dividends, applicable law and other factors that the Board deems relevant.

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

The three largest groups of stockholders of Vistra Energy Corp., affiliates of Apollo Management Holdings L.P. (collectively, the Apollo Entities), affiliates of Brookfield Asset Management Private Institutional Capital Adviser (Canada), L.P. (collectively, the Brookfield Entities), and affiliates of Oaktree Capital Management, L.P. (collectively, the Oaktree Entities, and together with the Apollo Entities and the Brookfield Entities, the Principal Stockholders), all of which were first lien creditors of our Predecessor prior to Emergence, collectively own approximately 39% of our common stock outstanding. Large holders such as the Principal Stockholders may be able to affect matters requiring approval by Vistra Energy Corp. stockholders, including the election of directors and the approval of mergers or other business combination transactions. Furthermore, pursuant to the terms of stockholders’ agreements entered into with each of the Principal Stockholders (each, a Stockholder’s Agreement), each Principal Stockholder is entitled to designate one director to serve on the Board as a Class III director for so long as it beneficially owns, in the aggregate, at least 22,500,000 shares of our common stock. See “Certain Relationships and Related Party Transactions — Stockholder’s Agreements.”

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

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

 

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

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

 

    cease the active conduct of our business;

 

    cease to hold certain assets;

 

    voluntarily dissolve or liquidate;

 

    merge or consolidate with any other person in a transaction that does not qualify as a reorganization under Section 368(a) of the Code;

 

    redeem or otherwise repurchase (directly or indirectly) any of our equity interests other than pursuant to an open market stock repurchase program that satisfies the requirements in the Tax Matters Agreement; or

 

    directly or indirectly acquire any of the PrefCo Preferred Stock.

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

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

Provisions in the Charter and bylaws and the Tax Receivable Agreement might discourage, delay or prevent a change in control of Vistra Energy Corp. or changes in our management and therefore depress the market price of our common stock.

The Charter and bylaws of Vistra Energy Corp. (the Bylaws), and the Tax Receivable Agreement contain provisions that could depress the market price of our common stock by acting to discourage, delay or prevent a change in control of Vistra Energy Corp. or changes in our management that stockholders may deem advantageous. These provisions in our Charter and Bylaws:

 

    authorize the issuance of “blank check” preferred stock that the Board could issue to increase the number of outstanding shares to discourage a takeover attempt;

 

    create a classified board of directors;

 

    prohibit stockholder action by written consent, and require that all stockholder actions be taken at a meeting of stockholders;

 

    provide that the Board is expressly authorized to make, amend or repeal our Bylaws; and

 

    establish advance notice requirements for nominations for elections to the Board or for proposing matters that can be acted upon by stockholders at stockholder meetings.

In addition, the Tax Receivable Agreement provides that upon certain mergers, asset sales or other forms of business combination or certain other changes of control, the transfer agent under the Tax Receivable Agreement may treat such event as an early termination of the Tax Receivable Agreement, in which case we would be

 

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required to make a lump-sum payment under the Tax Receivable Agreement, which could be significant. This payment obligation may discourage potential buyers from acquiring Vistra Energy Corp.

 

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Special Note Regarding Forward-Looking Statements

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

 

    the actions and decisions of regulatory authorities;

 

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

 

    prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the United States Congress, the FERC, the NERC, the TRE, the PUCT, the RCT, the NRC, the EPA, the TCEQ, the United States Mine Safety and Health Administration and the CFTC, with respect to, among other things:

 

    allowed prices;

 

    industry, market and rate structure;

 

    purchased power and recovery of investments;

 

    operations of nuclear generation facilities;

 

    operations of fossil fueled generation facilities;

 

    operations of mines;

 

    acquisition and disposal of assets and facilities;

 

    development, construction and operation of facilities;

 

    decommissioning costs;

 

    present or prospective wholesale and retail competition;

 

    changes in tax laws and policies;

 

    changes in and compliance with environmental and safety laws and policies, including the CSAPR, MATS, regional haze program implementation and GHG and other climate change initiatives; and

 

    clearing over-the-counter derivatives through exchanges and posting of cash collateral therewith;

 

    legal and administrative proceedings and settlements;

 

    general industry trends;

 

    economic conditions, including the impact of an economic downturn;

 

    weather conditions, including drought and limitations on access to water, and other natural phenomena, and acts of sabotage, wars or terrorist or cyber security threats or activities;

 

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    our ability to collect trade receivables from our customers;

 

    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;

 

    the construction of additional generation facilities in ERCOT that results in an over-supply of electricity in ERCOT causing a reduction in wholesale power prices;

 

    changes in prices of transportation of natural gas, coal, fuel and other refined products;

 

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

 

    changes in market heat rates in the ERCOT electricity market;

 

    our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heat rates and interest rates;

 

    population growth or decline, or changes in market supply or demand and demographic patterns, particularly in ERCOT;

 

    access to adequate transmission facilities to meet changing demands;

 

    changes in interest rates, commodity prices, rates of inflation or foreign exchange rates;

 

    changes in operating expenses, liquidity needs and capital expenditures;

 

    commercial bank market and capital market conditions and the potential impact of disruptions in United States 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 the capital markets;

 

    our ability to maintain prudent financial leverage;

 

    our ability to generate sufficient cash flow to make principal and interest payments in respect of, or refinance, our debt obligations;

 

    competition for new energy development and other business opportunities;

 

    the ability of various counterparties to meet their obligations with respect to our financial instruments;

 

    changes in technology (including large scale electricity storage) used by and services offered by us;

 

    changes in electricity transmission that allow additional power generation to compete with our generation assets;

 

    our ability to attract and retain qualified employees;

 

    significant changes in our relationship with our employees, including the availability of qualified personnel, and the potential adverse effects if labor disputes or grievances were to occur;

 

    changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits, pension and postretirement employee benefits other than pensions (OPEB), and future funding requirements related thereto, including joint and several liability exposure under the Employee Retirement Income Security Act of 1974, as amended (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 Tax Receivable Agreement; and

 

    actions by credit rating agencies.

 

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

 

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Industry and Market Information

Certain industry and market data and other statistical information used throughout this prospectus are based on, independent industry publications, government publications, reports by market research firms or other published independent sources, including certain data published by ERCOT, the PUCT and NYMEX. We did not commission any of these publications, reports or other sources. Some data is also based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sources listed above. Industry publications, reports and other sources generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of these publications, reports and other sources is reliable, we have not independently investigated or verified the information contained or referred to therein and make no representation as to the accuracy or completeness of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we often do not know what assumptions were used in preparing such forecasts. Statements regarding industry and market data and other statistical information used throughout this prospectus involve risks and uncertainties and are subject to change based on various factors, including those discussed under the headings “Special Note Regarding—Forward Looking Statements” and “Risk Factors.”

 

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Use of Proceeds

This prospectus relates to shares of our common stock that may be offered for resale by the selling stockholders. We will not receive any proceeds from any resale of the shares of our common stock offered by this prospectus. The net proceeds from any resale of such shares will be received by the applicable selling stockholders.

 

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Market Prices and Dividend Policy

Our common stock is quoted on the OTCQX U.S. market under the symbol “VSTE” and has been trading since October 4, 2016. No established trading market existed for our common stock prior to this date. The following table sets forth the per share high and low closing prices for our common stock as reported on the OTCQX U.S. market for the periods presented.

 

     High      Low  

October 4, 2016 (through December 15, 2016)

   $ 25.24       $ 13.50   

On December 15, 2016, the closing price of our common stock as reported on the OTCQX U.S. market was $14.19 per share. As of December 15, 2016, there were 357 stockholders of record of our common stock, not including beneficial owners of shares registered in nominee or street name.

We have applied to list our common stock for trading on                     , which we refer to as                 , under the symbol “          .”

Dividends and Dividend Policy

We have not paid any dividends since our formation in October 2016. On December 8, 2016, the Board approved the payment of the 2016 Special Dividend in the aggregate amount of approximately $1 billion to holders of record of our common stock on December 19, 2016. Proceeds from the $1 billion aggregate principal amount of incremental term loans obtained by Vistra Operations on December 14, 2016 (the 2016 Incremental Term Loans) will be used to make the 2016 Special Dividend. The 2016 Special Dividend is expected to be paid on December 30, 2016.

Aside from the 2016 Special Dividend, we have no present intention to pay cash dividends on our common stock. We are focused, however, on optimal deployment of capital and intend to evaluate a range of capital deployment strategies, including the return of capital to stockholders in the form of dividends and/or share repurchases.

Any determination to pay dividends to holders of our common stock or to repurchase shares of our common stock in the future will be at the sole discretion of the Board and will depend upon many factors and then-existing conditions, including our historical and anticipated financial condition, cash flows and results of operations, capital requirements, contractual prohibitions, our level of indebtedness, restrictions imposed by applicable law, general business conditions and other factors that the Board deems relevant. There can be no assurance we will pay any dividends to holders of our common stock in the future, or if declared, the amount of such dividends.

 

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Capitalization

The following table sets forth our cash and cash equivalents and capitalization as of September 30, 2016 on an as-adjusted basis to give effect to the pro forma adjustments contained in the pro forma condensed consolidated financial statements and accompanying notes included elsewhere in this prospectus, which include the transactions that occurred in connection with the Plan and Emergence, the anticipated payment of the 2016 Special Dividend and the related incurrence of $1 billion 2016 Incremental Term Loans. You should read the information set forth below together with “Unaudited Pro Forma Condensed Consolidated Financial Information.”

 

     As of September 30,
2016
 
     Pro Forma  
     (in millions)  

Cash and Cash Equivalents

   $ 775   

Deposit Letter of Credit Collateral Account

   $ 650   

Revolving Credit Facility (a)

      

Term Loan C Facility (a)

   $ 650   

Term Loan B Facility (a)

   $ 2,850   

2016 Incremental Term Loans

   $ 1,000   

Capital Leases or Other (b)

   $ 4   
  

 

 

 

Total Funded Debt (c)

   $ 4,504   

Preferred Equity (d)

   $ 70   

Equity

   $ 6,477   
  

 

 

 

Total Capitalization

   $ 11,051   
  

 

 

 

 

(a) As defined in “Unaudited Pro Forma Condensed Consolidated Financial Information.”
(b) Excludes a capital lease related to office space ($36 million) as the amounts due under this lease were prepaid into an escrow account.
(c) Amount does not reflect debt issuance costs and debt discounts.
(d) Included in Long-term Debt on our Pro Forma Condensed Consolidated Balance Sheet. See “Unaudited Pro Forma Condensed Consolidated Financial Information” for further discussion.

 

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The Reorganization and Emergence

This section provides a description of the bankruptcy filing made by the Debtors (the Bankruptcy Filing), the reorganization of the Debtors pursuant to a Joint Plan of Reorganization, and Emergence.

Bankruptcy Filing

On April 29, 2014, EFH Corp. and the other Debtors, including our Predecessor, filed the Bankruptcy Filing in the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court). While in bankruptcy, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

The Bankruptcy Filing resulted primarily from the adverse effects on the Debtors’ (including our Predecessor’s) businesses of persistently lower wholesale electricity prices in ERCOT driven by the sustained decline in natural gas prices since mid-2008, together with obligations from the substantial amount of debt EFH Corp. and our Predecessor had previously incurred in connection with the leveraged buy-out of EFH Corp. in 2007. These market conditions challenged the results of operations and cash flows of EFH Corp. and our Predecessor and resulted in the inability to support their significant interest payments and debt maturities and the inability to refinance and/or extend the maturities of its outstanding debt.

The Plan

On April 14, 2015, the Debtors, including our Predecessor and its subsidiaries, filed a proposed Joint Plan of Reorganization with the Bankruptcy Court. The Plan was subsequently amended and supplemented multiple times based upon discussions with the Debtors’ creditors and other interested parties and in response to creditor claims and objections and the requirements of the Bankruptcy Code and the Bankruptcy Court. On August 29, 2016, the Bankruptcy Court entered an order confirming the Plan solely as it pertains to EFCH, our Predecessor and the subsidiaries of our Predecessor that were Debtors, and certain other subsidiaries of EFH Corp. identified in the Plan (collectively, the T-Side Debtors). The Plan provided that the confirmation and effective date of the plan of reorganization with respect to the T-Side Debtors was to occur separate from, and independent of, the confirmation and effective date of the plan of reorganization with respect to EFH Corp., EFIH and their subsidiaries that are Debtors, excluding the T-Side Debtors.

On October 3, 2016, which we refer to as the Effective Date, the Plan with respect to the T-Side Debtors became effective and the T-Side Debtors, including our Predecessor, consummated their reorganization under the Bankruptcy Code and emerged from the Chapter 11 Cases.

Transactions in Connection with Emergence

On the Effective Date and pursuant to the Plan, the T-Side Debtors, including our Predecessor, executed the following transactions as part of a tax-free spin-off from EFH Corp. (the Spin-Off):

 

    Pursuant to the Plan and the Separation Agreement (the Separation Agreement), (a) our Predecessor contributed all of its interests in its subsidiaries, (b) each of our Predecessor, EFH Corp. and Energy Future Competitive Holdings LLC contributed certain assets and liabilities related to the operations of our Predecessor and its subsidiaries and (c) EFH Corp. transferred sponsorship of certain employee benefit plans (including related assets), programs and policies, to a recently formed limited liability company named TEX Energy LLC, in exchange for which our Predecessor received 100% of the equity interests in TEX Energy LLC;

 

   

A subsidiary of TEX Energy LLC contributed certain of the assets of our Predecessor and its subsidiaries to Vistra Preferred Inc. (PrefCo) in exchange for all of PrefCo’s authorized (a) preferred

 

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stock (the PrefCo Preferred Stock Sale), consisting of 70,000 shares, par value $0.01 per share (the PrefCo Preferred Stock), and (b) common stock, consisting of 10,000,000 shares, par value $0.01 per share, and immediately thereafter the subsidiary sold all of the PrefCo Preferred Stock to certain investors in exchange for cash and distributed the cash proceeds from such sale to our Predecessor to fund recoveries under the Plan;

 

    TEX Energy LLC converted from a Delaware limited liability company into a Delaware corporation and ultimately changed its name to Vistra Energy Corp.; and

 

    Our Predecessor (a) distributed (i) (1) 427,500,000 shares of common stock of Vistra Energy Corp. and (2) approximately $370,000,000 of cash to the former first lien creditors of our Predecessor in exchange for the cancellation of their allowed claims against our Predecessor, and (ii) the right to receive recoveries under the unsecured claim of our Predecessor against EFH Corp. allowed in the amount of $700 million (the TCEH Settlement Claim), provided, that from and after the Effective Date, Vistra Energy Corp. nominally holds the right to receive recoveries under the TCEH Settlement Claim but the former first lien creditors of our Predecessor (and their assigns) hold all legal and equitable entitlement to receive recoveries under the TCEH Settlement Claim, and (b) deposited the TRA Rights described in more detail under “Certain Relationships and Related Party Transactions — Tax Receivable Agreement” into an escrow account for subsequent distribution to eligible first lien creditors of our Predecessor.

Also on the Effective Date, the debtor-in-possession credit facilities of our Predecessor converted into the Vistra Operations Credit Facilities and Vistra Operations assumed all of the rights and obligations of our Predecessor thereunder. For additional information about the Vistra Operations Credit Facilities, see “Description of Indebtedness.”

 

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As a result of the Spin-Off, with effect as of Emergence, the competitive businesses previously owned by our Predecessor are no longer indirect wholly owned subsidiaries of EFH Corp., and while EFH Corp. is the parent holding company of the regulated business of Oncor, it is no longer the parent holding company of the competitive businesses of TXU Energy and Luminant. Set forth below is a diagram setting forth the structure of Vistra Energy Corp. and certain of its key subsidiaries following Emergence:

 

LOGO

As of December 15, 2016

 

* 100% Common Stock held by Vistra Asset Company LLC. Preferred stock held by outside investors

 

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Selected Historical Consolidated Financial Information

The following table sets forth our selected historical consolidated financial information as of and for the periods indicated. The selected historical consolidated financial information as of December 31, 2015 and 2014 and for the years ended December 31, 2015, 2014 and 2013 has been derived from our Predecessor’s audited historical consolidated financial statements and related notes included elsewhere in this prospectus. The selected historical condensed consolidated financial information as of September 30, 2016 and for the nine months ended September 30, 2016 and 2015 has been derived from our Predecessor’s unaudited condensed consolidated financial statements and related notes included elsewhere in this prospectus, which have been prepared on a basis consistent with our Predecessor’s historical audited consolidated financial statements. The interim results of operations and cash flows are not necessarily indicative of those for the year ending December 31, 2016. The selected historical consolidated financial information as of December 31, 2013, 2012 and 2011 and for the years ended December 31, 2012 and 2011 has been derived from our Predecessor’s historical audited consolidated financial statements and related notes that are not included in this prospectus. The selected historical consolidated financial information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited and unaudited condensed consolidated financial statements, as well as our pro forma condensed consolidated financial statements, and, in each case, related notes included elsewhere in this prospectus. In addition, as you review the consolidated Predecessor financial statements set forth herein, you should be aware that such Predecessor financial statements will not be comparable to our future financial statements because such Predecessor financial statements do not take into account the effects of the Plan and Emergence or any required adjustments for fresh-start reporting, which, in each case, will be taken into account in our future financial statements.

 

    Nine Months
Ended
September 30,
    Year
Ended
December 31,
 
    2016     2015     2015     2014     2013     2012     2011  
    (in millions)  

Operating revenues

  $ 3,973      $ 4,265      $ 5,370      $ 5,978      $ 5,899      $ 5,636      $ 7,040   

Impairment of goodwill

  $     $ (1,400   $ (2,200   $ (1,600   $ (1,000   $ (1,200   $  

Impairment of long-lived assets

  $     $ (1,971   $ (2,541   $ (4,670   $ (140   $     $ (9

Net loss attributable to our Predecessor

  $ (656   $ (3,067   $ (4,677   $ (6,229   $ (2,197   $ (2,948   $ (1,740

Cash provided by (used in) operating activities

  $ (196   $ 209      $ 237      $ 444      $ (270   $ (237   $ 1,240   

 

    At
September 30,
    At
December 31,
 
    2016     2015     2014     2013     2012     2011  
    (in millions)  

Balance Sheet Information:

           

Total assets (a)(b)

  $ 16,875      $ 15,658      $ 21,343      $ 28,822      $ 32,969      $ 37,335   

Property, plant & equipment — net (a)(b)

  $ 10,359      $ 9,349      $ 12,288      $ 17,649      $ 18,556      $ 19,218   

Goodwill and intangible assets

  $ 1,300      $ 1,331      $ 3,688      $ 5,669      $ 6,733      $ 7,978   

Borrowings, debt and pre-Petition notes, loans and other debt

           

Borrowings under debtor-in-possession credit facilities (c)

  $ 3,387      $ 1,425      $ 1,425      $     $     $  

Debt (d)

  $     $ 3      $ 51      $ 26,146      $ 29,795      $ 29,677   

Pre-Petition notes, loans and other debt reported as liabilities subject to compromise (e)

  $ 31,668      $ 31,668      $ 31,856      $     $     $  

Borrowings under credit and other facilities (f)

  $     $     $     $ 2,054      $ 2,136      $ 774   

 

(a) As of September 30, 2016, amount includes the Lamar and Forney natural gas generation facilities purchased in April 2016. See Note 3 to the September 30, 2016 Quarterly Financial Statements for further discussion.

 

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(b) Reflects impact of impairment charges for long-lived assets of $2.541 billion and $4.670 billion in the years ended December 31, 2015 and 2014, respectively (see Note 8 to the 2015 Annual Financial Statements).
(c) Borrowings under debtor-in-possession credit facilities are classified as noncurrent as of September 30, 2016 and December 31, 2014 and due currently as of December 31, 2015.
(d) For all periods presented, excludes amounts with contractual maturity dates in the following twelve months.
(e) As of September 30, 2016 and 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.
(f) Excludes borrowings under debtor-in-possession credit facilities.

 

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Unaudited Pro Forma Condensed Consolidated Financial Information

We prepared the following unaudited pro forma condensed consolidated financial statements by applying certain pro forma adjustments to the condensed consolidated financial statements of our Predecessor (also referred to herein as TCEH). The pro forma adjustments give effect to (i) the implementation of all reorganization transactions contemplated by the Plan, (ii) the application of fresh-start reporting for the emerged entity, Vistra Energy, and (iii) the incurrence of the $1 billion 2016 Incremental Term Loans and the related 2016 Special Dividend in the approximate amount of $1 billion expected to be paid on December 30, 2016.

The unaudited pro forma condensed consolidated statements of income (loss) for the year ended December 31, 2015 and nine months ended September 30, 2016 give effect to the pro forma adjustments as if each adjustment had occurred on January 1, 2015, the first day of the last fiscal year presented. The unaudited pro forma condensed consolidated balance sheet as of September 30, 2016 gives effect to the pro forma adjustments as if each adjustment had occurred on September 30, 2016, the latest balance sheet date presented.

The pro forma adjustments include the following Plan and Emergence-related adjustments:

 

    the conversion of the TCEH DIP Roll Facilities into the Vistra Operations Credit Facilities on the Effective Date, which includes the following:

 

    $2.85 billion of senior secured term loan (the Initial Term Loan B Facility);

 

    $650 million fully-funded senior secured term loan letter of credit facility (the Term Loan C Facility);

 

    $750 million senior secured revolving credit facility (the Initial Revolving Credit Facility), which remained undrawn as of the date of Emergence, increased to $860 million (the 2016 Incremental Revolving Credit Commitments, and together with the Initial Revolving Credit Facility, the Revolving Credit Facility) in connection with the 2016 Incremental Term Loans borrowings in December 2016 described below and remaining undrawn; and

 

    the cancelation or repayment of the indebtedness of TCEH and its subsidiaries, including liabilities subject to compromise and the cancelation of the existing membership equity interest of TCEH;

 

    the distribution to the holders of the TCEH first lien debt of substantially all shares of Vistra Energy common stock;

 

    the issuance and sale of approximately $70 million of mandatorily redeemable preferred stock of PrefCo as part of the Spin-Off;

 

    the distribution to the holders of the TCEH first lien debt of rights under the Tax Receivable Agreement described in “Certain Relationships and Related Party Transactions” that are reflected as a liability estimated at fair value;

 

    our use of cash on hand and proceeds generated above as described further in “The Reorganization and Emergence,” including to settle our Predecessor’s liabilities subject to compromise, repay certain other claims, pay fees and expenses under the Plan and provide adequate liquidity to Vistra Energy subsequent to Emergence; and

 

    the contribution of equity interests in an entity that employs personnel who perform corporate service functions and an entity that leases office space, along with the contribution of liabilities associated with certain employee benefit plans as required by the Plan.

The transactions reflected in the pro forma adjustments pursuant to the Plan and Emergence are described elsewhere in this prospectus under the heading “The Reorganization and Emergence.”

 

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The pro forma adjustments also reflect preliminary fair value adjustments arising from the application of fresh-start reporting in accordance with Financial Accounting Standards Board Accounting Standards Codification (ASC) 852, Reorganizations (ASC 852).

A third-party valuation specialist submitted an expert report to the Bankruptcy Court in July 2016 assuming an Emergence from bankruptcy as of December 31, 2016. This report provided an estimated value range for the total Vistra Energy enterprise. Management used an estimated enterprise value within that range of $10.5 billion as the basis for determining the reorganization value for this preliminary fresh-start allocation.

Under ASC 852, reorganization value is generally allocated, first, to identifiable tangible assets, identifiable intangible assets and liabilities, then any remaining excess reorganization value is allocated to goodwill. Vistra Energy estimates its reorganization value of assets at approximately $14.611 billion as of September 30, 2016, which consists of the following:

 

    (in millions)  

Business enterprise value

  $ 10,500   

Cash excluded from business enterprise value

    1,441   

Deferred asset related to prepaid capital lease obligation

    39   

Current liabilities excluding short-term portion of debt and capital leases

    1,169   

Noncurrent, non-interest bearing liabilities

    1,462   
 

 

 

 

Vistra Energy total assets (reorganization value)

  $ 14,611   
 

 

 

 

For purposes of determining pro forma interest expense from the Vistra Operations Credit Facilities (including the 2016 Incremental Term Loans), we have assumed an interest rate of 5.0% and 4.0%, respectively (each such rate consisting of LIBOR (subject to a floor) plus an applicable margin), per annum on borrowings thereunder. This assumed rate is based on the terms of our debt and market conditions when the debt was incurred.

Additional Information

We have based the pro forma adjustments upon available information and certain assumptions that we believe are reasonable under the circumstances. We describe in greater detail the assumptions underlying the pro forma adjustments in the accompanying footnotes, which should be read in conjunction with these unaudited pro forma condensed consolidated financial statements. In many cases, we based these assumptions on preliminary information and estimates. Accordingly, the actual adjustments that will appear in our condensed consolidated financial statements will differ from these pro forma adjustments, and those differences may be material.

The valuations for assets and liabilities used in this prospectus represent estimates based on available data. However, updates to these preliminary valuations will be completed in the future as of the Effective Date based on the results of asset and liability valuations, as well as the related calculation of deferred income taxes and any valuation allowance considerations. Final fair value measurements and allocations will be included in our annual condensed consolidated financial statements for the period ended December 31, 2016. The differences between the final valuations and the current estimated valuations used in preparing the pro forma condensed consolidated financial information may be material and will be reflected in our future balance sheets and may affect amounts, including depreciation and amortization expense, we will recognize in our statement of operations after Emergence. In addition, we may recognize certain nonrecurring expenses subsequent to Emergence related to our Chapter 11 reorganization. As a result, the pro forma financial information may not accurately represent our post-Emergence financial condition or results from operations and any differences may be material.

We provide these preliminary unaudited pro forma condensed consolidated financial statements for informational purposes only. These unaudited pro forma condensed consolidated financial statements do not

 

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purport to represent what our results of operations or financial condition would have been had the assumed transactions actually occurred on the assumed dates, nor do they purport to project our results of operations or financial condition for any future period or future date. Our unaudited pro forma condensed consolidated financial statements should be read in conjunction with “Capitalization”, “Selected Historical Consolidated Financial Information”, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, and the historical audited and unaudited financial statements of our Predecessor, including the related notes thereto, appearing elsewhere in this prospectus.

 

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Unaudited Pro Forma Condensed Consolidated Balance Sheet of Vistra Energy

(In Millions)

 

    September 30, 2016  
    Our Predecessor
As Reported (a)
    Plan Effects
and Other
          Fresh—  Start
Adjustments
(q)
          Vistra
Energy Pro
Forma
As Adjusted
 

ASSETS

           

Current assets:

           

Cash and cash equivalents

    1,829        (1,054     (b)(n)                 775   

Restricted cash

    12        4        (n)                 16   

Trade accounts receivable-net

    750                          750   

Advances to parent and affiliates

    78        (78                  

Inventories

    374                          374   

Commodity and other derivative contractual assets

    256                          256   

Margin deposits related to commodity contracts

    42                          42   

Other current assets

    46        18        (n)                 64   
 

 

 

   

 

 

     

 

 

     

 

 

 

Total current assets

    3,387        (1,110                2,277   

Restricted cash

    650                          650   

Advances to parent and affiliates

    17        (17                  

Investments

    1,038        1                   1,039   

Property, plant and equipment-net

    10,359        67        (n)        (5,831     (r)        4,595   

Goodwill

    152                 1,732        (w)        1,884   

Identifiable intangible assets-net

    1,148        (10     (n)        2,006        (s)        3,144   

Commodity and other derivative contractual assets

    72                          72   

Accumulated deferred income taxes

                    886        (u)        886   

Other noncurrent assets

    52        37        (n)        (25     (t)        64   
 

 

 

   

 

 

     

 

 

     

 

 

 

Total assets

    16,875        (1,032       (1,232       14,611   
 

 

 

   

 

 

     

 

 

     

 

 

 

LIABILITIES AND EQUITY

           

Current liabilities:

           

Long-term debt due currently

    4        5                   9   

Trade accounts payable

    402        142        (c)(d)(n)                 544   

Trade accounts and other payables to affiliates

    152        (152     (d)                   

Commodity and other derivative contractual liabilities

    125                          125   

Margin deposits related to commodity contracts

    64                          64   

Accrued income taxes payable

    10        6        (n)                 16   

Accrued taxes other than income

    119        3        (n)                 122   

Accrued interest

    110        (109     (e)                 1   

Other current liabilities

    243        54        (f)(n)                 297   
 

 

 

   

 

 

     

 

 

     

 

 

 

Total current liabilities

    1,229        (51                1,178   

Borrowings under debtor-in-possession credit facilities

    3,387        (3,387     (g)                   

Long-term debt, less amounts due currently

           4,477        (g)(h)(n)        79        (t)        4,556   

Liabilities subject to compromise

    33,749        (33,749     (i)                   

Commodity and other derivative contractual liabilities

    5                          5   

Accumulated deferred income taxes

    217        (217     (j)                   

Tax Receivable Agreement obligation

           938        (k)                 938   

Other noncurrent liabilities and deferred credits

    1,827        116        (l)(n)        (486     (s)        1,457   

Total liabilities

    40,414        (31,873       (407       8,134   
 

 

 

   

 

 

     

 

 

     

 

 

 

Membership interests capital account (Predecessor)

    (23,507     23,507        (m)                   

Common stock (Vistra Energy)

           4        (o)                 4   

Additional paid-in capital (Vistra Energy)

           7,330        (p)        (857     (v)        6,473   

Accumulated other comprehensive (loss) income

    (32              32        (v)          

Total liabilities and equity

    16,875        (1,032       (1,232       14,611   
 

 

 

   

 

 

     

 

 

     

 

 

 

 

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Unaudited Pro Forma Condensed Consolidated Statement of Income (Loss) of Vistra Energy

(In Millions, Except Per Share Amounts)

 

     Nine Months Ended September 30, 2016  
     Our
Predecessor As
Reported (x)
    Pro Forma
Adjustments (y)
         Vistra Energy
Pro Forma As
Adjusted
 

Operating revenues

     3,973        (39   (z)      3,934   

Fuel, purchased power costs and delivery fees

     (2,082     68      (aa)      (2,014

Net gain from commodity hedging and trading activities

     282                  282   

Operating costs

     (664               (664

Depreciation and amortization

     (459     85      (bb)      (374

Selling, general and administrative expenses

     (482     13           (469

Other income

     16        11           27   

Other deductions

     (75     (6        (81

Interest income

     3                  3   

Interest expense and related charges

     (1,049     886      (dd)      (163

Tax Receivable Agreement obligation

            (93   (ee)      (93

Reorganization items

     (116     116      (ff)        
  

 

 

   

 

 

      

 

 

 

Income (loss) before income taxes

     (653     1,041      (gg)      388   

Income tax benefit (expense)

     (3     (168   (hh)      (171
  

 

 

   

 

 

      

 

 

 

Net income (loss)

     (656     873           217   
  

 

 

   

 

 

      

 

 

 

Basic and Diluted income per share available to common stockholders

   $          $ 0.508   

Basic and Diluted shares outstanding

                427,580,232   

Unaudited Pro Forma Condensed Consolidated Statement of Income (Loss) of Vistra Energy

(In Millions, Except Per Share Amounts)

 

     Year Ended December 31, 2015  
     Our
Predecessor As
Reported (x)
    Pro Forma
Adjustments (y)
         Vistra Energy
Pro Forma As
Adjusted
 

Operating revenues

     5,370        (139   (z)      5,231   

Fuel, purchased power costs and delivery fees

     (2,692     128      (aa)      (2,564

Net gain from commodity hedging and trading activities

     334                  334   

Operating costs

     (834               (834

Depreciation and amortization

     (852     254      (bb)      (598

Selling, general and administrative expenses

     (676     (4        (680

Impairment of goodwill

     (2,200     2,200      (cc)        

Impairment of long-lived assets

     (2,541     2,541      (cc)        

Other income

     17        17           34   

Other deductions

     (93               (93

Interest income

     1                  1   

Interest expense and related charges

     (1,289     1,064      (dd)      (225

Tax Receivable Agreement obligation

            (113   (ee)      (113

Reorganization items

     (101     101      (ff)        
  

 

 

   

 

 

      

 

 

 

Income (loss) before income taxes

     (5,556     6,049      (gg)      493   

Income tax benefit (expense)

     879        (1,093   (hh)      (214
  

 

 

   

 

 

      

 

 

 

Net income (loss)

     (4,677     4,956           279   
  

 

 

   

 

 

      

 

 

 

Basic and Diluted income per share available to common stockholders

   $          $ 0.653   

Basic and Diluted shares outstanding

                427,580,232   

 

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Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements of Vistra Energy

Our Predecessor As Reported

 

(a) The Unaudited Pro Forma Condensed Consolidated Balance Sheet is derived from the unaudited historical condensed consolidated balance sheet of our Predecessor, as of September 30, 2016.

Plan Effects and Other (Unaudited Pro Forma Condensed Consolidated Balance Sheet)

 

(b) Pro forma adjustments include the adjustments to cash and cash equivalents detailed below, primarily resulting from distributions made under the Plan.

 

     (in millions)  

Payment to TCEH first lien creditors

   $ (370

Payment to TCEH unsecured creditors

     (511

Payment of adequate protection and interest to TCEH first lien creditors

     (116

Payment of administrative claims to TCEH creditors

     (53

Payment of reorganized professional fees

     (63

Payment of fees in conjunction with Vistra Operations Credit Facilities

     (8

Settlements with former affiliate

     (7

Payment of other benefits obligations

     (6

Addition of cash balances from contributed entities

     22   

Net proceeds from preferred stock sale

     69   

Net proceeds from borrowings subsequent to Emergence

     989   

Payment of dividend subsequent to Emergence

     (1,000
  

 

 

 

Net adjustments to cash

   $ (1,054
  

 

 

 

 

(c) Reflects payment of $15 million related to accrued professional fees incurred in conjunction with bankruptcy.

 

(d) Primarily reflects the reclassification of $148 million 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 Oncor.

 

(e) Reflects the payment of accrued interest and adequate protection to the TCEH first lien creditors on the Effective Date.

 

(f) Reflects the following:

 

    Cash payment at Effective Date of $37 million related to reorganization and professional fee accruals.

 

    Addition of accruals for $51 million of severance triggered by provisions of the Plan at Emergence, $13 million portion of EFH Corp. federal alternative minimum tax obligation triggered by separation, and $33 million of accrued liabilities from entities contributed as part of the Plan.

 

(g) Reflects the conversion of the TCEH DIP Roll Facilities to Vistra Operations Credit Facilities at Emergence.

 

(h) Reflects the following:

 

    Issuance and sale of $70 million of mandatorily redeemable Preferred Stock shares of PrefCo, as part of the Spin-Off, to be treated as long-term debt.

 

    Borrowing of $1 billion of Term Loan B Facility subsequent to Emergence, net of $11 million of original discount based on market conditions and issuance costs.

 

    Addition of $31 million obligation related to a corporate office space lease contributed to Vistra Energy pursuant to the Plan.

 

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(i) Reflects the elimination of our Predecessor’s liabilities subject to compromise pursuant to the Plan, as detailed below:

 

     (in millions)  

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 estimated allowed claims

     191   

Other

     1   
  

 

 

 

Total liabilities subject to compromise

   $ 33,749   
  

 

 

 

 

(j) Reflects the deferred income tax impact of the Plan implementation, including cancellation of debts and adjustment of tax-basis for certain assets of PrefCo issuing mandatory redeemable preferred stock as part of the Spin-Off.

 

(k) Reflects the estimated value of the Tax Receivable Agreement obligation, representing 85% of the estimated net cash savings, if any, in United States federal, state and local income tax or franchise tax that Vistra Energy is expected to realize (or is deemed to realize in certain circumstances) in periods after Emergence as a result of (i) any tax basis increases resulting from the PrefCo Preferred Stock Sale, (ii) the tax basis of all assets acquired in connection with the Lamar and Forney Acquisition in April 2016 and (iii) imputed interest deemed to be paid by Vistra Energy as a result of any payments Vistra Energy makes under the Tax Receivable Agreement. This obligation is estimated at fair value based on a discounted cash flow calculation that utilized estimated cash outflows for the agreement based on assumptions of current taxability. See “Certain Relationships and Related Party Transactions” for further discussion of the Tax Receivable Agreement.

 

(l) Reflects the following:

 

    Addition of $123 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.

 

    Payment of $7 million in settlements related to split life insurance costs with prior affiliated entity.

 

(m) Reflects the extinguishment of Predecessor membership equity interest per the Plan.

 

(n) Pro forma adjustments also include the addition of certain immaterial assets and obligations associated with the contribution of equity interests in an entity that employs personnel who perform corporate service functions, an entity that leases office space, along with the contribution of liabilities associated with certain employee benefit plans, contributed to Vistra Energy by EFH Corp. pursuant to the Plan.

 

(o) Reflects the issuance of 427,500,000 shares of Vistra Energy common stock, par value of $.01 per share, to TCEH first lien creditors.

 

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(p) Equity impact of Plan and 2016 Special Dividend adjustments are shown below:

 

     (in millions)  

Elimination of TCEH debt, including related accrued interest and deferred financing costs

   $ 32,314   

Elimination of obligations related to interest rate swaps

     1,243   

Elimination of other TCEH liabilities subject to compromise

     192   

Deferred tax impact of reorganization per the Plan

     217   

Elimination of other intercompany balances with debtor entities

     (91

Extinguishment of TCEH membership equity interest

     (23,507

Issuance of common stock par value

     (4

Recognition of tax receivable agreement obligation

     (938

Disbursement of cash to satisfy TCEH impaired claims

     (881

Disbursement of cash to satisfy TCEH administrative claims

     (53

Addition of contributed entities, assets and obligations per the Plan

     (71

Payment of additional reorganization professional fees

     (11

Payment of Vistra Operations Credit Facilities transaction costs incurred at Emergence

     (8

Payment of additional adequate protection

     (7

Accrual of severance costs per the Plan

     (51

Accrual of obligations with EFH Corp. due to separation

     (13

Payment of dividend subsequent to Emergence

     (1,000

Other adjustments

     (1
  

 

 

 

Equity impact of effects of Plan

   $ 7,330   
  

 

 

 

Fresh-Start Adjustments (Unaudited Pro Forma Condensed Consolidated Balance Sheet)

 

(q) Vistra Energy is currently in the process of developing and finalizing the fresh-start valuations, utilizing a fresh-start reporting date of October 3, 2016. As such, current draft valuations for assets and liabilities could be significantly different from the final valuations. These differences will materially impact the presentation of the unaudited pro forma condensed consolidated balance sheet.

 

(r) Reflects the change in fair value of property, plant and equipment, as detailed below.

 

     Valuation
Adjustment
     Fair
Value
 
     (in millions)  

Property, Plant, and Equipment

  

Generation plants and mining assets

   $ (5,670    $ 4,083   

Land

     (85      266   

Nuclear fuel

     (76      104   

Other equipment and corporate assets

             142   
  

 

 

    

 

 

 

Net adjustments to property, plant and equipment

   $ (5,831    $ 4,595   
  

 

 

    

 

 

 

 

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(s) Reflects the adjustments in fair value of identifiable intangibles, as detailed below.

 

     Valuation
Adjustment
     Fair
Value
 
     (in millions)  

Identifiable intangible assets:

  

Retail customer relationship

   $ 1,438       $ 1,450   

Retail trade name

     205         1,160   

Retail contracts

     113         113   

Wholesale contracts (1)

     16         16   

Electricity supply contract (2)

     223         223   

Transportation contract

     30         30   

Mineral interests

             5   

Computer software

             134   

Mining development costs and other

     (14      10   

Other

     (5      3   
  

 

 

    

 

 

 

Net adjustments to identifiable intangible assets

   $ 2,006       $ 3,144   
  

 

 

    

 

 

 

Identifiable intangible liabilities:

     

Wholesale contracts (1)

   $ 39       $ 39   

Electricity supply contract (2)

     (525        
  

 

 

    

 

 

 

Net adjustments to identifiable intangible liabilities

   $ (486    $ 39   
  

 

 

    

 

 

 

 

  (1) Balances contain wholesale contracts pertaining to wind generation and other types of agreements. Balances have been separated by type and presented as assets or liabilities depending on the favorability of the arrangement.
  (2) Intangible balance attributable to an electricity supply contract deemed to be favorable. As such, the historical unfavorable liability was adjusted to zero, and a favorable asset of $223 million was recorded.

 

(t) Reflects the adjustment to remove certain unamortized debt issuance costs to reflect the Vistra Operations Credit Facilities at fair market value.

 

(u) Reflects the deferred income tax impact of the fresh-start adjustments related to fair value adjustments to property, plant, and equipment, inventory, intangibles and debt issuance costs.

 

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(v) Reflects equity adjustments to reset retained earnings including accumulated other comprehensive income and present Vistra Energy common stock at $6.5 billion based on a reconciliation from the $10.5 billion enterprise value as depicted below:

 

     (in millions)  

Enterprise value

   $ 10,500   

Initial Term Loan B Facility

     (2,822

Term Loan C Facility

     (644

2016 Incremental Term Loans issued subsequent to Emergence

     (989

Tax receivable agreement obligation

     (938

Preferred stock of PrefCo

     (70

Capital lease obligations, net of prepayments

     (1

Cash and cash equivalents

     775   

Restricted cash

     666   
  

 

 

 

Equity value

   $ 6,477   
  

 

 

 

Common stock at par value

   $ 4   

Additional paid-in capital

     6,473   
  

 

 

 

Equity value

   $ 6,477   
  

 

 

 

 

(w) 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.

 

     (in millions)  

Business enterprise value

   $ 10,500   

Add: Fair value of liabilities excluded from enterprise value

     2,630   

Less: Fair value of tangible assets

     (8,102

Less: Fair value of identified intangible assets

     (3,144
  

 

 

 

Vistra Energy goodwill

   $ 1,884   
  

 

 

 

Notes to Unaudited Pro Forma Condensed Consolidated Statement of Income (Loss) of Vistra Energy

Our Predecessor As Reported

 

(x) The Unaudited Pro Forma Condensed Consolidated Statement of Income (Loss) is derived from the unaudited condensed consolidated statement of income (loss) of our Predecessor, as of September 30, 2016.

Plan Effects and Fresh Start Adjustments

 

(y) Vistra Energy is currently in the process of developing and finalizing the fresh-start valuation adjustments, utilizing a fresh-start reporting date of October 3, 2016. As such, current draft valuations for assets and liabilities could be significantly different from the final valuations. These differences may materially impact the presentation of the unaudited pro forma condensed consolidated statement of income including estimated depreciation and amortization adjustments of certain assets and liabilities.

 

(z) Reflects the decrease in operating revenues as a result of amortization expense related to the fair value adjustment to intangible assets and liabilities related to electric supply agreements and retail contracts.

(aa) Reflects the following:

 

    $66 million and $112 million decrease in amortization expense as a result of the fair value adjustment to property, plant, and equipment related to nuclear fuel for the nine months ended September 30, 2016 and the year ended December 31, 2015 respectively.

 

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    $2 million and $16 million decrease in fuel expense amortization as a result of the fair value adjustment to intangible assets related to emissions credits, wholesale power purchase agreements and transportation contracts for the nine months ended September 30, 2016 and the year ended December 31, 2015 respectively.

(bb) Reflects the following:

 

    $291 million and $657 million decrease in depreciation expense as a result of the fair value adjustment to property, plant, and equipment for the nine months ended September 30, 2016 and the year ended December 31, 2015, respectively.

 

    $198 million and $392 million increase in amortization expense as a result of the fair value adjustment to intangible assets related to retail customer relationships for the nine months ended September 30, 2016 and the year ended December 31, 2015, respectively.

 

    $8 million and $11 million of depreciation expense related to capital lease asset transferred from contributed entities as part of the Plan for the nine months ended September 30, 2016 and the year ended December 31, 2015, respectively.

 

(cc) Reflects the removal of impairment charges incurred in the year ended December 31, 2015 due to the remeasurement of long-lived assets and intangible assets at fair value and the new goodwill measurement.

 

(dd) Reflects the following:

 

    Elimination of $1.064 billion and $1.302 billion of interest expense related to interest and adequate protection payments on Predecessor debt with third-parties and notes with affiliates for the nine months ended September 30, 2016 and the year ended December 31, 2015, respectively.

 

    Addition of $166 million and $222 million of interest expense related to our Vistra Operations Credit Facilities for the nine months ended September 30, 2016 and the year ended December 31, 2015, respectively.

For purposes of estimating the pro forma interest expense, we used an interest rate of: 5.0% per annum for our variable interest rate, Vistra Operations Credit Facilities, which is based on the following information when the debt was incurred: LIBOR (subject to a floor of 1.0%) plus a 400 basis point fixed margin; and (2) a 5.00% rate for our variable interest rate senior secured debt facilities, which is based on the following estimated terms: (a) an annualized floating interest rate of LIBOR plus a 400 basis point fixed margin, and (b) a minimum LIBOR rate floor of 1.00%. We used an annualized interest rate of 4.0% for our additional borrowing subsequent to Emergence, which is based on the market conditions when the debt was incurred: (a) an annualized floating interest rate of LIBOR plus a 325 basis point fixed margin, and (b) a minimum LIBOR rate floor of 0.75%.

 

    Addition of $7 million and $9 million of interest expense related to debt balances transferred from contributed entities as part of the Plan for the nine months ended September 30, 2016 and the year ended December 31, 2015, respectively.

 

    Addition of $5 million and $7 million of interest expense related to the $70 million of mandatorily redeemable preferred stock of PrefCo, recorded as a debt instrument with a fixed 10% coupon rate, for the nine months ended September 30, 2016 and the year ended December 31, 2015, respectively.

 

(ee) Reflects the accretion expense related to the discounted tax receivable agreement obligation. The obligation was valued using a present value utilizing a risk-adjusted discount rate which yields the estimated accretion of the obligation.

 

(ff) Reflects the elimination of bankruptcy-related reorganization expenses that will not be incurred after Emergence.

 

(gg) Additionally, reflects the income effects for various line items related to entities contributed as part of the Plan for the nine months ended September 30, 2016 and the year ended December 31, 2015.

 

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(hh) Reflects the tax impact of the Plan effects and fresh-start adjustments. Pro forma adjustments to tax expense result in an effective tax rate that is lower than the U.S. federal statutory tax rate of 35% due to tax benefits resulting from the reversal of our Predecessor’s valuation allowance and the elimination of nondeductible interest expense, bankruptcy-related reorganization expense, and goodwill impairment from which no tax benefit was derived, offset by tax expenses associated with nondeductible TRA accretion. Adjustments to the income tax benefit (expense) amount results in pro forma effective income tax rates of 44% and 43% for the nine months ended September 30, 2016 and the year ended December 31, 2015, respectively.

 

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Management’s Discussion and Analysis of

Financial Condition and Results of Operations

This section provides a discussion of our historical financial condition, cash flows and results of operations for the periods indicated as required by the registration statement of which this prospectus is a part. Except as otherwise indicated herein, or as the context may otherwise require, all references to “Vistra Energy,” “the Company,” “we,” “us” and “our” refer to (i) Vistra Energy Corp. and, unless the context otherwise requires, its direct and indirect subsidiaries and (ii) prior to its emergence from bankruptcy (Emergence) on October 3, 2016 (the Effective Date), Texas Competitive Electric Holdings Company LLC, a Delaware limited liability company, and, unless the context otherwise requires, its direct and indirect subsidiaries (TCEH or our Predecessor). Except where otherwise noted, the discussion in this section does not reflect, among other things, any effects of the transactions described in “The Reorganization and Emergence,” including entry into the Tax Receivable Agreement described in more detail in “Certain Relationships and Related Party Transactions — Tax Receivable Agreement,” or any fresh-start reporting, and may not be representative of Vistra Energy’s financial condition, cash flows or results of operations subsequent to the Effective Date. In addition, comparisons of year-over-year results are impacted by the effects of the Bankruptcy Filing (defined under “— Significant Activities and Events and Items Influencing Future Performance” below) and the application of Financial Accounting Standards Board Accounting Standards Codification (ASC) 852, Reorganizations. The following discussion and analysis of our financial condition, cash flows and results of operations should be read in conjunction with “Selected Historical Consolidated Financial Information” and our audited and unaudited condensed consolidated financial statements and our pro forma condensed consolidated financial statements, included herein, and, in each case, the notes to those statements included elsewhere in this prospectus, as well as the discussion in the section of this prospectus entitled “Business.” This discussion contains forward-looking statements that involve numerous risks and uncertainties. The forward-looking statements are subject to a number of important factors, including those factors discussed under “Risk Factors” and “Special Note Regarding Forward-Looking Statements,” that could cause actual results to differ materially from the results described or implied by such forward-looking statements. All dollar amounts in the tables in the following discussion and analysis are stated in millions of United States dollars unless otherwise indicated.

Basis of Presentation and Fresh-Start Reporting

The consolidated financial statements contained herein are those of our Predecessor. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States from time to time (U.S. GAAP). The consolidated financial statements have been prepared as if our Predecessor was a going concern and contemplated the realization of assets and liabilities in the normal course of business. The consolidated financial statements reflect the application of Financial Accounting Standards Board Accounting Standards Codification 852, Reorganizations (ASC 852), which applies to entities that have filed a petition for bankruptcy under Chapter 11 of the United States Bankruptcy Code (Bankruptcy Code). During the bankruptcy proceedings, our Predecessor and its subsidiaries operated their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. ASC 852 requires that transactions and events directly associated with the reorganization be distinguished from the ongoing operations of the business. In addition, ASC 852 provides for changes in the accounting and presentation of liabilities. See “— Application of Critical Accounting Policies” for a detailed discussion of these accounting and reporting changes. Since the Effective Date occurred after the end of the fiscal quarter ended September 30, 2016, ASC 852 continued to apply to our Predecessor at and for the nine months ended September 30, 2016.

As of the Effective Date and in connection with Emergence, Vistra Energy will adopt the fresh-start reporting provisions under the applicable provisions of ASC 852. Fresh-start reporting includes (1) distinguishing the consolidated financial statements of the entity that was previously in restructuring from the consolidated financial statements of the entity that emerges from restructuring, (2) assigning the reorganized value of the successor entity by measuring all assets and liabilities of the successor entity at fair value, and (3) selecting accounting policies for the successor entity. As you review the consolidated Predecessor financial statements set forth in this prospectus you should be aware that such Predecessor financial statements will not be comparable to

 

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our future financial statements because such Predecessor financial statements do not take into account the effects of the Plan and Emergence or any required adjustments for fresh-start reporting, which, in each case, will be taken into account in our future financial statements.

Items Affecting Comparability

Our Predecessor’s historical results of operations, including the impacts of long-lived asset impairment charges, goodwill impairment charges and bankruptcy and restructuring activities, are provided in detail below. These items are related primarily to the bankruptcy process and activities necessitated by the Plan and our Emergence and are not the result of our current operations. Management does not believe these items are applicable subsequent to the Effective Date.

Some of the significant items impacting the historical comparability of reported income from operations are noted in the table below:

 

     Nine Months Ended
September 30,
     Year Ended
December 31,
 
         2016              2015          2015      2014      2013  
     (in millions)  

Bankruptcy-related reorganization items

   $ 116       $ 152       $ 101       $ 520       $  

Impairment of goodwill

   $      $ 1,400       $ 2,200       $ 1,600       $ 1,000   

Impairment of long-lived assets

   $      $ 1,971       $ 2,541       $ 4,670       $ 140   

Significant Activities and Events and Items Influencing Future Performance

Chapter 11 Cases and Emergence — As more fully described in the section entitled “The Reorganization and Emergence,” on April 29, 2014 (the Petition Date), Energy Future Holdings Corp. (EFH Corp.) and the substantial majority of its direct and indirect subsidiaries (collectively, the Debtors), including Energy Future Intermediate Holding Company LLC (EFIH), Energy Future Competitive Holdings Company LLC (EFCH) and our Predecessor, but excluding Oncor Electric Delivery Holdings Company LLC and its direct and indirect subsidiaries (collectively, Oncor) filed voluntary petitions for relief (the Bankruptcy Filing) under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court). The cases in the Bankruptcy Court concerning the Bankruptcy Filing are collectively referred to herein as the Chapter 11 Cases.

On August 29, 2016, the Bankruptcy Court entered an order confirming the Third Amended Joint Plan of Reorganization of the Debtors, including TCEH and its subsidiaries (the Plan), solely as it pertains to EFCH, TCEH and the subsidiaries of TCEH that were Debtors (the TCEH Debtors) and the EFH Shared Services Debtors (as defined in the Plan and, together with the TCEH Debtors, the T-Side Debtors). The Plan allowed the confirmation and effective date of the plan of reorganization with respect to the T-Side Debtors to occur separate from, and independent of, the confirmation and effective date of the plan of reorganization with respect to EFH Corp., EFIH and their subsidiaries that are Debtors, excluding the T-Side Debtors (the EFH Debtors). On the Effective Date of October 3, 2016, the Plan with respect to the T-Side Debtors became effective and the T-Side Debtors completed their reorganization under the Bankruptcy Code and emerged from the Chapter 11 Cases. Pursuant to the Plan and the transactions contemplated therein, in accordance with Emergence, among other actions, Vistra Energy was formed and became the ultimate parent holding company for the subsidiaries of our Predecessor, and first lien creditors of our Predecessor received, among other things, Vistra Energy common stock in exchange for the cancellation of their allowed claims against our Predecessor.

For more detail, see “The Reorganization and Emergence” above.

Workforce Reduction — In October 2016, we reduced our workforce by approximately 500 people in order to better align our cost structure to current market conditions, particularly as it relates to support functions within

 

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the business. These market conditions include persistently low wholesale electricity prices, environmental regulatory pressure and a highly competitive retail market. As part of these reductions, we expect to incur severance costs of approximately $60 million.

Lamar and Forney Acquisition — In April 2016, our subsidiaries that engaged in competitive market activities consisting of power generation and wholesale electricity sales and purchases as well as commodity risk management (collectively, Luminant) purchased all of the membership equity interests in La Frontera Holdings, LLC, the indirect owner of two natural gas-fueled generation facilities representing nearly 3,000 megawatts (MW) of capacity located in ERCOT, from La Frontera Ventures, LLC, a subsidiary of NextEra Energy, Inc. (the Lamar and Forney Acquisition). The facility in Forney, Texas has a capacity of 1,912 MW and the facility in Paris, Texas has a capacity of 1,076 MW. The aggregate purchase price was approximately $1.313 billion, which included the repayment of approximately $950 million of existing project financing indebtedness, plus approximately $236 million for cash and net working capital subject to final settlement. The purchase price was funded by cash-on-hand and additional borrowings under our Predecessor’s $3.375 billion debtor-in-possession financing facility at the time (the TCEH DIP Facility), totaling $1.1 billion. See Note 3 to the September 30, 2016 Quarterly Financial Statements for further discussion of the acquisition.

Conversion of TCEH DIP Roll Facilities to Vistra Operations Credit Facilities  In August 2016, our Predecessor entered into certain $4.250 billion debtor-in-possession and exit financing facilities (the TCEH DIP Roll Facilities). Prior to the Effective Date, the TCEH DIP Roll Facilities provided for up to $4.250 billion in senior secured, super-priority financing consisting of a revolving credit facility of up to $750 million (the TCEH DIP Roll Revolving Credit Facility), a term loan letter of credit facility of up to $650 million (the TCEH DIP Roll Term Loan Letter of Credit Facility) and a term loan facility of up to $2.850 billion (the TCEH DIP Roll Term Loan Facility). As of September 30, 2016, approximately $3.5 billion was outstanding under the TCEH DIP Roll Facilities, approximately $2.65 billion of which was used to repay all amounts outstanding under the TCEH DIP Facility, and the balance of which was used for general business purposes. Upon the Effective Date, the TCEH DIP Roll Facilities were converted into senior secured exit facilities (the Vistra Operations Credit Facilities) of Vistra Operations Company LLC (Vistra Operations) with maturity dates of August 2021 for the revolving credit facility and August 2023 for the term loan facilities. See “Description of Indebtedness.” As of November 30, 2016, approximately $3.5 billion, consisting of a $2.85 billion term loan under the senior secured term loan (the Initial Term Loan B Facility) and a $650 million term loan under the fully-funded senior secured term loan letter of credit facility (the Term Loan C Facility), was outstanding under the Vistra Operations Credit Facilities. In addition, we incurred the 2016 Incremental Term Loans, with a maturity in December 2023 and a variable annual interest rate of LIBOR plus 325 basis points subject to a 75 basis point floor, in the amount of $1.0 billion in December 2016.

 

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Natural Gas Price and Market Heat Rate Exposure  The price of power in the ERCOT market is typically set by natural gas-fueled generation facilities, with wholesale electricity prices generally tracking increases or decreases in the price of natural gas. In recent years, natural gas supply has outpaced demand primarily as a result of development and expansion of hydraulic fracturing in natural gas extraction; the supply/demand imbalance has resulted in historically low natural gas prices, and such prices have historically been volatile. The table below shows the general decline in forward natural gas prices over the last several years (amounts are prices per MMBtu).

 

LOGO

 

(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 annual average of NYMEX Henry Hub monthly forward prices at the date presented. Three year forward prices are presented as we believe such period is generally deemed to be a liquid period.

In contrast to our natural gas-fueled generation facilities, changes in natural gas prices have no significant effect on the cost of generating power at our nuclear-, lignite- and coal-fueled facilities, which represent the substantial majority of our generation capacity and are used to meet baseload demand. Consequently, all other factors being equal, these nuclear-, lignite- and coal-fueled generation assets increase or decrease in value as natural gas prices and market heat rates rise or fall, respectively, because of the effect on our operating margins

 

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from changes in wholesale electricity prices in ERCOT. A persistent decline in the price of natural gas, and the corresponding decline in the price of power in the ERCOT market, would likely have a material adverse effect on our results of operations, liquidity and financial condition, predominantly related to the production of power generation volumes in excess of the volumes utilized to service our retail customer load requirements.

The wholesale market price of electricity divided by the market price of natural gas represents the market heat rate. Market heat rate can be affected by a number of factors, including generation availability, mix of assets and the efficiency of the marginal supplier (generally, natural gas-fueled generation facilities) in generating electricity. Our market heat rate exposure is impacted by changes in the availability of generation resources, such as additions and retirements of generation facilities, and the mix of generation assets in ERCOT. For example, increasing renewable (wind and solar) generation capacity generally depresses market heat rates. Our market heat rate exposure is also impacted by the potential economic backdown of our generation assets. Decreases in market heat rates generally decrease the value of our generation assets because lower market heat rates generally result in lower wholesale electricity prices, and vice versa. However, even though market heat rates have generally increased over the past several years, wholesale electricity prices have declined due to the greater effect of falling natural gas prices.

As a result of our exposure to the variability of natural gas prices and market heat rates in ERCOT, retail sales price management and hedging activities are critical to our operating results and maintaining consistent cash flow levels.

Our integrated power generation and retail electricity business provides us opportunities to hedge our generation position through retail sales. In addition, our approach to managing electricity price risk focuses on the following:

 

    employing disciplined, liquidity-efficient, opportunistic hedging and risk management strategies through physical and financial energy-related (electricity and natural gas) 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.

We have engaged in natural gas hedging activities to mitigate the risk of lower wholesale electricity prices that have corresponded to declines in natural gas prices. While current and forward natural gas prices are currently depressed, we continue to seek opportunities to manage our wholesale electricity price exposure through hedging activities, including forward wholesale and retail electricity sales.

Taking together forward wholesale and retail electricity sales with all hedging positions, at September 30, 2016, we had effectively hedged an estimated 85% and 79%, respectively, of the price exposure, on a natural gas equivalent basis, related to our expected generation output for the remainder of 2016 and 2017 (assuming an 8.5 heat rate), as compared to 94% and 18%, respectively, at December 31, 2015.

We mitigate market heat rate risk through retail and wholesale electricity sales contracts and shorter-term heat rate hedging transactions. We evaluate opportunities to mitigate heat rate risk over extended periods through longer-term electricity sales contracts where practical, considering pricing, credit, liquidity and related factors.

On an ongoing basis, we will continue monitoring our overall commodity risks and seek to balance our portfolio based on our desired level of exposure to natural gas prices and market heat rates and potential changes to our operational forecasts of overall generation and consumption in our businesses (which are also subject to

 

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volatility resulting from customer churn, weather, economic and other factors). Portfolio balancing may include the execution of incremental transactions, including heat rate hedges, the unwinding of existing transactions and the substitution of natural gas hedges with commitments for the sale of electricity at fixed prices. As a result, commodity price exposures and their effect on our results of operations, liquidity and financial condition could materially change from time to time.

The following sensitivity table provides estimates of the potential impact of movements in natural gas prices and market heat rates on realized pretax earnings for the periods presented. The estimates related to price sensitivity are based on our unhedged position and forward prices at September 30, 2016, which for natural gas reflects estimates of power generation less amounts under existing wholesale and retail electricity sales contracts and amounts related to hedging positions. On a rolling basis, generally twelve-months, the substantial majority of retail electricity sales under month-to-month arrangements are deemed to be under contract.

 

     Balance 2016      2017  

$1.00/MMBtu change in natural gas price (a)(b)

   $  ~12       $  ~90   

0.1/million British thermal units (MMBtu)/megawatt-hour (MWh) change in market heat rate (c)

   $  ~ —       $  ~7   

 

(a) Balance of 2016 is from November 1, 2016 through December 31, 2016.
(b) Assumes conversion of electricity positions based on an approximate 8.5 market heat rate with natural gas generally being on the margin 70% to 90% of the time in the ERCOT market (i.e., when coal is forecast to be on the margin, no natural gas position is assumed to be generated). Excludes the impact of economic backdown.
(c) Based on Houston Ship Channel natural gas prices at September 30, 2016.

Competitive Retail Markets and Customer Retention

Competitive retail activity in ERCOT has resulted in retail customer churn as customers switch electricity retail providers for various reasons. Based on number of meters, our total retail customer counts declined approximately 1% during the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015, and less than 1% in 2015, 1% in 2014 and 3% in 2013. Based upon 2015 results discussed below in “— Results of Operations,” a 1% decline in retail customers would result in a decline in annual revenues of approximately $29 million. In responding to the competitive landscape in the ERCOT market, we have attempted to reduce overall customer losses by focusing on the following key initiatives:

 

    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 TXU Energy Retail Company LLC, our direct wholly owned subsidiary that is a REP in competitive areas of ERCOT and leverages our TXU EnergyTM brand in the retail sale of electricity to residential and commercial customers (TXU Energy), as the most innovative retailer in the ERCOT market by continuing to develop tailored product offerings to meet customer needs; and

 

    Focusing business market initiatives largely on programs targeted at retaining the existing highest-value customers and 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.

 

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Exposures Related to Nuclear Asset Outages

Our nuclear assets are comprised of two generation units at the Comanche Peak facility, each with an installed nameplate generation capacity of 1,150 MW. As of December 15, 2016, these units represented approximately 14% of our total generation capacity. The nuclear generation units represent our lowest marginal cost source of electricity. Assuming both nuclear generation units experienced an outage at the same time, the unfavorable impact to pretax earnings is estimated (based upon forward electricity market prices for 2016 at September 30, 2016) to be approximately $1 million per day before consideration of any costs to repair the cause of such outages or receipt of any insurance proceeds. See “Business — Nuclear Insurance” for additional information.

The inherent complexities and related regulations associated with operating nuclear generation facilities result in environmental, regulatory and financial risks. The operation of nuclear generation facilities is subject to continuing review and regulation by the Nuclear Regulatory Commission (NRC), including potential regulation as a result of the NRC’s ongoing analysis and response to the effects of the natural disaster on nuclear generation facilities in Fukushima, Japan in 2010, covering, among other things, operations, maintenance, emergency planning, security, and environmental and safety protection. The NRC may implement changes in regulations that result in increased capital or operating costs and may require extended outages, modify, suspend or revoke operating licenses and impose fines for failure to comply with its existing regulations and the provisions of the Atomic Energy Act. In addition, an unplanned outage at another nuclear generation facility could result in the NRC taking action to shut down our Comanche Peak units as a precautionary measure.

We participate in industry groups and with regulators to keep current on the latest developments in nuclear safety, operation and maintenance and on emerging threats and mitigation techniques. These groups include, but are not limited to, the NRC, the Institute of Nuclear Power Operations (INPO) and the Nuclear Energy Institute (NEI). We also apply the knowledge gained through our continuing investment in technology, processes and services to improve our operations and to detect, mitigate and protect our nuclear generation assets. The Comanche Peak facility has not experienced an extended unplanned outage, and management continues to focus on safe, reliable and efficient operations at the facility.

Application of Critical Accounting Policies

We follow U.S. GAAP. Application of these accounting policies in the preparation of our consolidated financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenues and expenses, including fair value measurements and estimates of expected allowed claims, during the periods covered. The following is a summary of certain critical accounting policies that are impacted by judgments and uncertainties and under which different amounts might be reported using different assumptions or estimation methodologies.

Derivative Instruments and Mark-to-Market Accounting

We enter into contracts for the purchase and sale of energy-related commodities, and also enter into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. Under accounting standards related to derivative instruments and hedging activities, these instruments are subject to mark-to-market accounting, and the determination of market values for these instruments is based on numerous assumptions and estimation techniques.

Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as market prices change. Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net income with an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. In computing fair value for derivatives, each forward pricing curve is separated into liquid and illiquid periods. The liquid period varies by delivery point and commodity. Generally, the liquid

 

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period is supported by exchange markets, broker quotes and frequent trading activity. For illiquid periods, fair value is estimated based on forward price curves developed using modeling techniques that take into account available market information and other inputs that might not be readily observable in the market. We estimate fair value as described in Note 13 to the September 30, 2016 Quarterly Financial Statements and Note 15 to the 2015 Annual Financial Statements and discussed under “Fair Value Measurements” below.

Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. Normal purchases and sales are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business and are not subject to mark-to-market accounting if the election as normal is made. Hedge accounting designations are made with the intent to match the accounting recognition of the contract’s financial performance to that of the transaction the contract is intended to hedge. The intent of our hedging activity is generally to enter into positions that reduce our exposure to future variable cash flows; such hedges are referred to as cash flow hedges.

Under hedge accounting, changes in fair value of instruments designated as cash flow hedges are recorded in other comprehensive income with an offset to derivative assets and liabilities to the extent the change in value is effective; that is, it mirrors the offsetting change in fair value of the forecasted hedged transaction. Changes in value that represent ineffectiveness of the hedge are recognized in net income immediately, and the effective portion of changes in fair value initially recorded in other comprehensive income are reclassified to net income in the period that the hedged transactions are recognized in net income. At September 30, 2016 and December 31, 2015 and 2014, we did not have any derivatives designated as cash flow hedges.

We report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting arrangements that we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in our consolidated balance sheets.

See Note 14 to the September 30, 2016 Quarterly Financial Statements and Note 16 to the 2015 Annual Financial Statements for further discussion regarding derivative instruments, including the termination of interest rate swaps and certain natural gas hedging agreements shortly after the Bankruptcy Filing.

Fair Value Measurements

For certain accounting measurements that require fair value determinations, we calculate value under the fair value hierarchy established in U.S. GAAP. We utilize several valuation techniques to measure the fair value, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis.

Under the fair value hierarchy, Level 1 and Level 2 valuations generally apply to our commodity-related contracts for natural gas, electricity and fuel, including coal and uranium, derivative instruments entered into for hedging purposes, securities associated with the nuclear decommissioning trust and interest rate swaps intended to fix interest payments on our debt. Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. Level 2 valuations are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.

Level 3 valuations generally apply to our interest rate swaps on our Predecessor’s debt, congestion revenue rights, certain coal contracts, options to purchase or sell electricity, and electricity purchase and sales agreements for which the valuations include unobservable inputs, including the hourly shaping of the price curve. Level 3 valuations use largely unobservable inputs, with little or no supporting market activity, and assets and liabilities

 

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are classified as Level 3 if such inputs are significant to the fair value determination. Valuation risk is mitigated through the performance of stress testing of the significant inputs to understand the impact that varying assumptions may have on the valuation and other review processes performed to ensure appropriate valuation.

As part of our valuation of assets subject to fair value measurement, counterparty credit risk is taken into consideration by measuring the extent of netting arrangements in place with the counterparty along with credit enhancements and the estimated credit ratings, default rate factors and debt trading values of the counterparty. Our valuation of liabilities subject to fair value accounting takes into consideration the market’s view of our credit risk along with the existence of netting arrangements in place with the counterparty and credit enhancements posted by us. We consider the credit risk adjustment to be a Level 3 input since judgment is used to assign credit ratings, recovery rate factors and default rate factors. Valuations of Level 3 assets and liabilities can be sensitive to the assumptions used for the significant inputs. Where market data is available, the inputs used for valuation reflect that information as of our valuation date. In periods of extreme volatility, lessened liquidity or in illiquid markets, there may be more variability in market pricing or a lack of market data to use in the valuation process. An illiquid market is one in which little or no observable activity has occurred or one that lacks willing buyers.

Valuations of several of our Level 3 assets and liabilities are sensitive to changes in discount rates, option-pricing model inputs such as volatility factors and credit risk adjustments. At September 30, 2016 and December 31, 2015, a 10% change in electricity price (per MWh) assumptions across unobservable inputs for delivery periods and locational basis for electricity congestion hedges would result in an approximate $60 million and $4 million, respectively, change in net Level 3 assets and liabilities.

See Note 13 to the September 30, 2016 Quarterly Financial Statements and Note 15 to the 2015 Annual Financial Statements for additional information about fair value measurements, including information on unobservable inputs and related valuation sensitivities and, in the 2015 Annual Financial Statements, a table presenting the changes in Level 3 assets and liabilities for the years ended December 31, 2015, 2014 and 2013.

Revenue Recognition

Our revenue includes an estimate for unbilled revenue related to our retail electricity customers that represents estimated daily kWh consumption after the meter read date to the end of the period multiplied by the applicable billing rates. Estimated daily kWh usage is derived using metered consumption as well as historical kWh usage information adjusted for weather and other measurable factors affecting consumption. Calculations of unbilled revenues during certain interim periods are generally subject to more estimation variability because of seasonal changes in demand. Accrued unbilled revenues totaled $245 million, $231 million, $239 million and $272 million at September 30, 2016, and December 31, 2015, 2014 and 2013, respectively.

Accounting for Income Taxes

EFH Corp. files a United States federal income tax return that includes the results of EFCH, EFIH, Oncor Holdings and TCEH. EFH Corp. is the corporate parent of the EFH Corp. consolidated group, while each of EFIH, Oncor Holdings, EFCH and TCEH were classified as a disregarded entity for United States federal income tax purposes. Pursuant to applicable United States Treasury regulations and published guidance of the Internal Revenue Service (IRS), corporations that are members of a consolidated group have joint and several liability for the taxes of such group. Subsequent to the Effective Date, the T-Side Debtors will no longer be included in the EFH Corp. consolidated group and will be included in a consolidated group of which Vistra Energy is the corporate parent.

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 to a Federal and State Income Tax Allocation Agreement, which provided, among other things, that any corporate member or disregarded entity in the EFH Corp. group is required to make payments to EFH Corp. in an amount calculated to approximate the amount of

 

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tax liability such entity would have owed if it filed a separate corporate tax return. Pursuant to the Plan, the T-Side Debtors rejected this agreement on the Effective Date. See Note 2 to the September 30, 2016 Quarterly Financial Statements for a discussion of the Tax Matters Agreement that was entered on the Effective Date between EFH Corp. and Vistra Energy. Additionally, since the date of the Amended and Restated Settlement Agreement among the Debtors, certain investment funds that own Texas Holdings (the Sponsor Group), and certain settling creditors of TCEH, approved by the Bankruptcy Court in December 2015 (the Settlement Agreement), no further cash payments among the Debtors were made in respect of federal income taxes. EFH Corp. has elected to continue to allocate federal income taxes among the entities that are parties to the Federal and State Income Tax Allocation Agreement. The Settlement Agreement did not alter the allocation and payment for state income taxes, which continued to be settled prior to the Effective Date.

Accounting in Reorganization and Fresh-Start Reporting

The consolidated financial statements of our Predecessor reflect the application of ASC 852. During the Chapter 11 Cases, the Debtors, including our Predecessor and its subsidiaries, operated their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. ASC 852 applies to entities that have filed a petition for bankruptcy under Chapter 11 of the Bankruptcy Code. The guidance requires that transactions and events directly associated with the reorganization be distinguished from the ongoing operations of the business. In addition, the guidance provides for changes in the accounting and presentation of liabilities. Expenses and income directly associated with the Chapter 11 Cases are reported separately in the consolidated statements of consolidated income (loss) as reorganization items. Reorganization items also include adjustments to reflect the carrying value of liabilities subject to compromise (LSTC) at their estimated allowed claim amounts, as such adjustments are determined. See Note 8 and Note 10 to the September 30, 2016 Quarterly Financial Statements. Since the Effective Date occurred after the end of the fiscal quarter ended September 30, 2016, ASC 852 continued to apply to our Predecessor at and for the nine months ended September 30, 2016.

As of the Effective Date, Vistra Energy began applying fresh-start reporting under the applicable provisions of ASC 852. Fresh-start reporting includes (1) distinguishing the consolidated financial statements of the entity that was previously in restructuring from the consolidated financial statements of the entity that emerges from restructuring, (2) assigning the reorganized value of the successor entity by measuring all assets and liabilities of the successor entity at fair value, and (3) selecting accounting policies for the successor entity. The consolidated financial statements of Vistra Energy for periods subsequent to the Effective Date will not be comparable to the financial statements of our Predecessor for periods prior to the Effective Date, as those previous periods do not give effect to any adjustments to the carrying values of assets or amounts of liabilities that might be necessary as a consequence of the Plan or the related application of fresh-start reporting.

Impairment of Goodwill and Other Long-Lived Assets

We evaluate long-lived assets (including intangible assets with finite lives) for impairment, in accordance with accounting standards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. For our generation assets, possible indications include an expectation of continuing long-term declines in natural gas prices and/or market heat rates or an expectation that “more likely than not” a generation asset will be sold or otherwise disposed of significantly before the end of its estimated useful life. The determination of the existence of these and other indications of impairment involves judgments that are subjective in nature and may require the use of estimates in forecasting future results of operations and cash flows related to an asset, group of assets or investment in an unconsolidated subsidiary. Further, the unique nature of our property, plant and equipment, which includes a fleet of generation assets with a diverse fuel mix and individual generation units that have varying production or output rates, requires the use of significant judgments in determining the existence of impairment indications and the grouping of assets for impairment testing. We generally utilize an income approach measurement to derive fair values for our long-lived generation assets. The income approach involves estimates of future performance that reflect

 

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assumptions regarding, among other things, forward natural gas and electricity prices, market heat rates, the effects of environmental rules, generation plant performance, forecasted capital expenditures and forecasted fuel prices. Any significant change to one or more of these factors can have a material impact on the fair value measurement of our long-lived assets. As a result of the decrease in forecasted wholesale electricity prices and changes to our operating plans in 2015 and 2014, we evaluated the recoverability of our generation assets and recorded impairment charges of $2.54 billion and $4.67 billion, respectively. In 2013, we evaluated the recoverability of the assets of our joint venture to develop additional nuclear generation units and recorded impairment charges of $140 million. See Note 6 to the September 30, 2015 Quarterly Financial Statements and Note 8 to the annual financial statements of our Predecessor dated December 31, 2015 (the 2015 Annual Financial Statements) for a discussion of the impairment charges related to certain of those assets.

Goodwill and intangible assets with indefinite useful lives are required to be tested for impairment at least annually (we have selected December 1 as our annual test date) or whenever events or changes in circumstances indicate an impairment may exist, such as the indicators used to evaluate impairments to long-lived assets discussed above or declines in values of comparable public companies in our industry. As required by accounting guidance related to goodwill, our Predecessor allocated goodwill to its reporting unit. Under this goodwill impairment analysis, if at the assessment date, a reporting unit’s carrying value exceeds its estimated fair value (enterprise value), the estimated enterprise value of the reporting unit is compared to the estimated fair values of the reporting unit’s assets (including identifiable intangible assets) and liabilities at the assessment date, and the resultant implied goodwill amount is then compared to the recorded goodwill amount. Any excess of the recorded goodwill amount over the implied goodwill amount is written off as an impairment charge.

The determination of enterprise value involves a number of assumptions and estimates. We use a combination of fair value measurements to estimate enterprise values of our reporting unit: internal discounted cash flow analyses (income approach) and comparable publicly traded company values (market approach). The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity prices, market heat rates, the effects of environmental regulations, generation plant performance, forecasted capital expenditures and retail sales volume trends, as well as determination of a terminal value. Another key variable in the income approach is the discount rate, or weighted average cost of capital, applied to the forecasted cash flows. The determination of the discount rate takes into consideration the capital structure, credit ratings and current debt yields of comparable publicly traded companies as well as an estimate of return on equity that reflects historical market returns and current market volatility for the industry. The market approach involves using trading multiples of earnings (net income) before interest expense, income taxes, depreciation and amortization (EBITDA) of those selected publicly traded companies to derive appropriate multiples to apply to the EBITDA of our reporting units. Critical judgments include the selection of publicly traded comparable companies and the weighting of the value metrics in developing the best estimate of enterprise value.

See Note 4 to the September 30, 2016 Quarterly Financial Statements and Note 4 to the 2015 Annual Financial Statements for additional discussion of goodwill impairment charges.

 

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Results of Operations

Financial Results

See below for a discussion of significant variances in financial results for the nine months ended September 30, 2016 when compared to the nine months ended September 30, 2015, the year ended December 31, 2015 compared to year ended December 31, 2014 and the year ended December 31, 2014 compared to December 31, 2013.

 

     Nine Months Ended
September 30,
    Year Ended December 31,  
     2016     2015     2015     2014     2013  

Operating revenues

   $ 3,973      $ 4,265      $ 5,370      $ 5,978      $ 5,899   

Fuel, purchased power costs and delivery fees

     (2,082     (2,090     (2,692     (2,842     (2,848

Net gain (loss) from commodity hedging and trading activities

     282        226        334        11        (54

Operating costs

     (664     (598     (834     (914     (881

Depreciation and amortization

     (459     (634     (852     (1,270     (1,333

Selling, general and administrative expenses

     (482     (495     (676     (708     (756

Impairment of goodwill

           (1,400     (2,200     (1,600     (1,000

Impairment of long-lived assets

           (1,971     (2,541     (4,670     (140

Other income

     16        15        17        16        9   

Other deductions

     (75     (86     (93     (281     (22

Interest income

     3        1        1              6   

Interest expense and related charges

     (1,049     (964     (1,289     (1,749     (1,916

Reorganization items

     (116     (152     (101     (520      
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

     (653     (3,883     (5,556     (8,549     (3,036

Income tax benefit (expense)

     (3     816        879        2,320        732   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net loss

     (656     (3,067     (4,677     (6,229     (2,304

Net loss attributable to noncontrolling interests

                             107   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net loss attributable to our Predecessor

   $ (656   $ (3,067   $ (4,677   $ (6,229   $ (2,197
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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Operating Statistics

 

    Nine Months Ended
September 30,
    %
Change
    Year Ended December 31,     2015     2014  
    2016     2015       2015     2014     2013     %
Change
    %
Change
 
    (in millions, except percentage amounts)  

Operating revenues:

         

Retail electricity revenues:

         

Residential

  $ 2,084      $ 2,362        (11.8 )%    $ 2,931      $ 2,970      $ 2,984        (1.3 )%      (0.5 )% 

Business markets

    1,070        1,177        (9.1 )%      1,518        1,443        1,355        5.2  %      6.5  % 
 

 

 

   

 

 

     

 

 

   

 

 

   

 

 

     

Total retail electricity revenues

    3,154        3,539        (10.9 )%      4,449        4,413        4,339        0.8  %      1.7  % 

Wholesale electricity and other operating revenues (a)(b)

    819        726        12.8  %      921        1,565        1,560        (41.2 )%      0.3  % 
 

 

 

   

 

 

     

 

 

   

 

 

   

 

 

     

Total operating revenues

  $ 3,973      $ 4,265        (6.8 )%    $ 5,370      $ 5,978      $ 5,899        (10.2 )%      1.3  % 
 

 

 

   

 

 

     

 

 

   

 

 

   

 

 

     

Sales volumes:

         

Retail electricity sales volumes —(GWh):

         

Residential

    16,619        17,667        (5.9 )%      21,923        21,910        22,791        0.1  %      (3.9 )% 

Business markets

    14,354        14,796        (3.0 )%      19,289        16,601        15,203        16.2  %      9.2  % 
 

 

 

   

 

 

     

 

 

   

 

 

   

 

 

     

Total retail electricity

    30,973        32,463        (4.6 )%      41,212        38,511        37,994        7.0  %      1.4  % 

Wholesale electricity sales volumes (b)

    25,563        17,526        45.9  %      23,533        32,965        38,320        (28.6 )%      (14.0 )% 
 

 

 

   

 

 

     

 

 

   

 

 

   

 

 

     

Total sales volumes

    56,536        49,989        13.1  %      64,745        71,476        76,314        (9.4 )%      (6.3 )% 
 

 

 

   

 

 

     

 

 

   

 

 

   

 

 

     

Fuel, purchased power costs and delivery fees:

         

Fuel for nuclear facilities

  $ 92      $ 118        (22.0 )%    $ 146      $ 147      $ 173        (0.7 )%      (15.0 )% 

Fuel for lignite and coal facilities

    548        560        (2.1 )%      736        784        869        (6.1 )%      (9.8 )% 

Fuel for natural gas facilities and purchased power costs (a)

    310        199        55.8  %      252        316        292        (20.3 )%      8.2  % 

Other costs

    108        128        (15.6 )%      166        267        233        (37.8 )%      14.6  % 

Delivery fees

    1,024        1,085        (5.6 )%      1,392        1,328        1,281        4.8  %      3.7  % 
 

 

 

   

 

 

     

 

 

   

 

 

   

 

 

     

Total

  $ 2,082      $ 2,090        (0.4 )%    $ 2,692      $ 2,842      $ 2,848        (5.3 )%      (0.2 )% 
 

 

 

   

 

 

     

 

 

   

 

 

   

 

 

     

Production and purchased power volumes (GWh):

         

Nuclear facilities

    15,005        15,830        (5.2 )%      19,954        18,636        20,487        7.1  %      (9.0 )% 

Lignite and coal facilities (c)

    31,865        31,784        0.3  %      41,817        48,878        52,023        (14.4 )%      (6.0 )% 

CCGT facilities

    8,048               %                         %       % 

Other natural gas facilities

    491        689        (28.7 )%      709        816        899        (13.1 )%      (9.2 )% 

Capacity factors:

         

Nuclear facilities

    99.2     105.1     (5.6 )%      99.0     92.5     101.7     7.0  %      (9.0 )% 

Lignite and coal facilities (c)

    60.5     60.5      %      59.5     69.6     74.1     (14.5 )%      (6.1 )% 

CCGT facilities

    65.2          %                   %       % 

Market pricing:

               

Average ERCOT North power price per MWh

  $ 20.78      $ 25.69        (19.1 )%    $ 23.78      $ 36.44      $ 30.50        (34.7 )%      19.5  % 

 

(a) Upon settlement of 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 U.S. GAAP, rather than contract price. The offsetting differences between contract and market prices are reported in net gain from commodity hedging and trading activities.

 

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(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- and coal-fueled units totaling 14,420 GWh and 15,300 GWh for the nine months ended September 30, 2016 and 2015, respectively, and 19,900 GWh, 15,770 GWh and 12,460 GWh in 2015, 2014 and 2013, respectively.

Financial Results — Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015

The overall $3.23 billion decrease in loss before income taxes during the nine months ended September 30, 2016 relative to the comparable 2015 period primarily reflected the noncash impairments of goodwill and certain long-lived assets during the nine months ended September 30, 2015, partially offset by lower operating revenues during the nine months ended September 30, 2016, relative to the comparable 2015 period. In 2015, a noncash impairment of goodwill totaling $1.4 billion and noncash impairments of certain long-lived assets totaling $1.971 billion were recorded.

Operating revenues during the nine months ended September 30, 2016 decreased $292 million relative to the comparable 2015 period, driven by a decrease in retail electricity revenues, partially offset by an increase in wholesale electricity revenues. Retail electricity revenues decreased $385 million during the nine months ended September 30, 2016 relative to the comparable 2015 period reflecting a $223 million decrease due to 7% lower average pricing and a $162 million decrease due to a 5% decrease in sales volumes driven by milder weather. Wholesale electricity revenues increased $110 million during the nine months ended September 30, 2016 relative to the comparable 2015 period due to a 7,106 GWh increase in generation volumes driven by the Lamar and Forney Acquisition in April 2016, partially offset by lower average wholesale electricity prices.

The $8 million decrease in fuel, purchased power costs and delivery fees during the nine months ended September 30, 2016 relative to the comparable 2015 period reflected a $61 million decrease in delivery fees, $38 million decrease in nuclear, lignite and coal facilities fuel costs, $28 million in lower purchased power costs and a $16 million decrease in other fuel costs and ancillary service costs, partially offset by a $139 million increase in fuel costs for natural gas facilities, which reflects the impact of the Lamar and Forney Acquisition in April 2016.

Following is an analysis of amounts reported as net gain from commodity hedging and trading activities. The results are primarily related to natural gas and power hedging activity.

 

     Nine Months Ended September 30,  
       2016         2015          Change    
     (in millions)  

Net gain from commodity hedging and trading activities

  

Realized net gains (losses)

   $ 320      $ 121       $ 199   

Unrealized net gains (losses)

     (38     105         (143
  

 

 

   

 

 

    

 

 

 

Total

   $ 282      $ 226       $ 56   
  

 

 

   

 

 

    

 

 

 

The decrease in operating revenues during the nine months ended September 30, 2016 relative to the comparable 2015 period was partially offset by a $199 million increase in realized net gains during the nine months ended September 30, 2016 relative to the comparable 2015 period, which reflected settled gains due to declining market prices. These gains were primarily related to natural gas positions.

The $143 million unfavorable change in unrealized net gains (losses) during the nine months ended September 30, 2016 relative to the comparable 2015 period reflected a larger reversal of previously recorded unrealized net gains on settled positions in 2016 and higher unrealized net gains recorded in 2015 due to an increase in forward natural gas and power prices on hedge positions.

The $66 million increase in operating costs during the nine months ended September 30, 2016 relative to the comparable 2015 period reflected higher nuclear maintenance costs due to a spring nuclear outage in 2016 compared to a fall outage in 2015 and incremental operating and maintenance costs associated with the Lamar and Forney Acquisition in April 2016.

 

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Depreciation and amortization expenses decreased $175 million during the nine months ended September 30, 2016 relative to the comparable 2015 period, driven by the effect of noncash impairments of certain long-lived assets recorded in 2015, partially offset by incremental expense associated with the Lamar and Forney Acquisition in April 2016.

For the nine months ended September 30, 2016, results include $32 million of severance expense, primarily reported in fuel, purchased power and delivery fees and operating costs, associated with certain actions taken to reduce costs related to our mining and lignite and coal generation operations.

See Note 16 to the September 30, 2016 Quarterly Financial Statements for details of other income and deductions. See Note 7 to the September 30, 2016 Quarterly Financial Statements for details of interest expense and related charges. See Note 8 to the September 30, 2016 Quarterly Financial Statements for details of reorganization items. See Note 5 to the September 30, 2016 Quarterly Financial Statements for reconciliation of comparable effective tax rates to the United States federal statutory rate.

Financial Results — Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Loss before income taxes decreased $2.993 billion in 2015 from 2014 to a loss of $5.556 billion. The decrease primarily reflected the larger noncash impairment charges of certain long-lived assets in 2014 and the decrease in interest expense, the decrease in depreciation and amortization expense and a decrease in reorganization items expense in 2015.

Operating revenues decreased $608 million in 2015 from 2014, as a result of a decrease in wholesale electricity revenues, partially offset by an increase in retail electricity revenues. Wholesale electricity revenues decreased $587 million in 2015 from 2014 reflecting a $362 million decrease in sales volumes and a $225 million decrease due to lower average wholesale electricity prices. The decrease in wholesale electricity sales volumes was driven by lower generation volumes from increased economic backdown (including seasonal operations) at our lignite and coal generation facilities, which was driven by a 35% decline in average wholesale electricity prices, driven by lower natural gas prices. Retail electricity revenues increased $36 million in 2015 from 2014 primarily reflecting a $310 million increase due to sales volumes driven by an increase in business sales volumes, partially offset by a $274 million decrease due to lower average prices primarily for business markets customers.

Fuel, purchased power costs and delivery fees decreased $150 million in 2015 from 2014. Fuel for lignite and coal facilities decreased $48 million in 2015 from 2014 due to a 14% decrease in generation volumes, partially offset by higher lignite mining costs and more western coal in the fuel blend. Fuel for natural gas facilities and purchased power costs decreased $64 million in 2015 from 2014 driven by a 28% decrease in purchased power volumes, lower natural gas prices and a 13% decrease in generation volumes from natural gas generation units. Other costs decreased $101 million in 2015 from 2014, reflecting a $49 million decrease in natural gas purchases for resale and $34 million decrease in amortization of favorable purchase contracts due to impairments recorded at the end of 2014. Delivery fees increased $64 million in 2015 from 2014, primarily reflecting higher retail volumes.

Following is an analysis of amounts reported as net gain from commodity hedging and trading activities. The results are primarily related to natural gas and power hedging activity.

 

     Year Ended December 31,  
     2015      2014      Change  
     (in millions)  

Realized net gains

   $ 217       $ 387       $ (170

Unrealized net gains (losses)

     117         (376      493   
  

 

 

    

 

 

    

 

 

 

Total

   $ 334       $ 11       $ 323   
  

 

 

    

 

 

    

 

 

 

 

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Realized net gains on hedging and trading positions decreased $170 million, or 43.9%, in 2015 from 2014, reflecting lower gains due to the 2014 termination of our favorable long-term natural gas hedging program, partially offset by other realized gains from declining market prices in 2015.

The $493 million favorable change in unrealized net gains in 2015 from 2014 primarily reflected the 2014 reversal of previously recorded unrealized gains related to the favorable pricing of our long-term natural gas hedging program that terminated in 2014 along with favorable unrealized gains in 2015 due to the impact of declining natural gas prices on our hedging positions.

Operating costs decreased $80 million in 2015 from 2014, driven by $55 million in lower nuclear maintenance costs, reflecting a spring refueling in 2014 that was absent in 2015, as well as lower lignite and coal facilities operating costs reflecting lower generation.

Depreciation and amortization expenses decreased $418 million in 2015 from 2014, primarily reflecting reduced depreciation expense resulting from the effect of noncash impairments of certain long-lived assets recorded at the end of 2014 and during 2015.

See Note 4 to the 2015 Annual Financial Statements for details of noncash impairments of goodwill. See Note 7 to the 2015 Annual Financial Statements for details of other income and deductions. See Note 8 to the 2015 Annual Financial Statements for details of noncash impairments of certain long lived assets. See Note 9 to the 2015 Annual Financial Statements for details of interest expense and related charges. See Note 10 to the 2015 Annual Financial Statements for details of reorganization items.

Financial Results — Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Loss before income taxes increased $5.513 billion in 2014 from 2013, primarily driven by the 2014 noncash impairments of certain long-lived assets of $4.670 billion, the 2014 noncash impairment of goodwill of $1.6 billion and 2014 reorganization items of $520 million, partially offset by the 2013 noncash impairment of goodwill of $1.0 billion, the decrease in interest expense and related charges of $167 million and the 2013 noncash impairment of the assets of the nuclear generation development joint venture of $140 million.

Operating revenues increased $79 million in 2014 from 2013, as a result of an increase in retail electricity revenues, partially offset by a decrease in wholesale electricity revenues. Wholesale electricity revenues decreased $15 million in 2014 from 2013, reflecting a $179 million decrease due to lower sales volumes, largely offset by a $164 million increase due to higher average prices. The decrease in wholesale sales volumes was driven by 7% decrease in nuclear and lignite and coal generation volumes due to higher economic backdown and nuclear refueling outages. Higher average prices were driven by an overall 16% increase in natural gas prices in 2014, predominately in the first half of the year. Retail electricity revenues increased $74 million in 2014 from 2013, reflecting a $59 million increase in sales volumes and $15 million in higher average prices. Retail sales volumes increased 1% reflecting higher sales growth in small and large business that was largely offset by a decline in residential volumes. The decrease in residential volumes reflects milder weather and a 1% decline in customer counts.

Fuel, purchased power costs and delivery fees decreased $6 million in 2014 from 2013. Lignite and coal fuel costs decreased $85 million reflecting lower generation volumes and higher lignite in the fuel blend, partially offset by higher western coal prices. Nuclear fuel costs decreased $26 million in 2014 from 2013, reflecting lower generation volumes due to the refueling outage and the discontinuance of Department of Energy (DOE) billing for spent fuel handling costs beginning in May 2014. These decreases were largely offset by $47 million increase in delivery rates, $26 million increase in ERCOT ancillary fees related to cold weather in the first quarter of 2014 and $24 million increase in fuel for natural gas facilities and purchase power costs also related to first quarter 2014 cold weather.

 

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Following is an analysis of amounts reported as net gain from commodity hedging and trading activities. The results are primarily related to natural gas and power hedging activity.

 

     Year Ended December 31,  
     2014      2013      Total  
     (in millions)  

Realized net gains

   $ 387       $ 1,057       $ (670

Unrealized net losses

     (376      (1,111      735   
  

 

 

    

 

 

    

 

 

 

Total

   $ 11       $ (54    $ 65   
  

 

 

    

 

 

    

 

 

 

Realized net gains on hedging and trading positions decreased by $670 million in 2014 from 2013, reflecting lower hedging gains from the natural gas hedging program in 2014 due to lower hedge prices.

The favorable change in unrealized net losses on hedging and trading positions of $735 million in 2014 from 2013 also reflected the lower gains in the natural gas hedging program. As realized gains were recognized, unrealized losses were recognized for the reversal of previously recognized unrealized gains.

Operating costs increased $33 million in 2014 from 2013, due to $57 million in higher nuclear maintenance costs primarily reflecting refueling outages for both generation units in 2014 as compared to only one unit in 2013 and maintenance costs incurred during the unplanned outage time experienced during the 2014 fall refueling outage, partially offset by lower maintenance and other costs of $14 million at lignite- and coal-fueled generation units and $5 million at natural gas-fueled plants.

Depreciation and amortization expenses decreased $63 million in 2014 from 2013, reflecting reduced depreciation expense resulting from the effect of noncash impairments of certain long-lived assets and the useful lives of certain lignite and coal generation equipment being longer than originally estimated.

Selling, general and administrative expenses decreased $48 million in 2014 from 2013, reflecting $41 million in lower legal and other professional services costs associated with the Chapter 11 Cases prior to the Petition Date of April 29, 2014, and $29 million in lower allocated Sponsor Group management fees, partially offset by $14 million in higher employee compensation and benefit costs. Legal and other professional services costs associated with the Chapter 11 Cases subsequent to the Petition Date are reported in reorganization items as discussed herein.

See Note 4 to the 2015 Annual Financial Statements for details of noncash impairments of goodwill. See Note 7 to the 2015 Annual Financial Statements for details of other income and deductions. See Note 8 to the 2015 Annual Financial Statements for details of noncash impairments of certain long lived assets. See Note 9 to the 2015 Annual Financial Statements for details of interest expense and related charges. See Note 10 to the 2015 Annual Financial Statements for details of reorganization items.

 

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

The table below summarizes the changes in commodity contract assets and liabilities for the nine months ended September 30, 2016 and 2015 and for the years ended December 31, 2015, 2014 and 2013. The net change in these assets and liabilities, excluding “other activity” as described below, reflects $38 million in unrealized net losses and $105 million in unrealized net gains in the nine months ended September 30, 2016 and 2015, respectively, and $117 million in unrealized net gains, $368 million in unrealized net losses and $1.093 billion in unrealized net losses in 2015, 2014 and 2013, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.

 

         Nine Months Ended    
September 30,
    Year Ended December 31,  
     2016     2015     2015     2014     2013  
     (in millions)  

Commodity contract net asset at beginning of period

   $ 271      $ 180      $ 180      $ 525      $ 1,664   

Settlements/termination of positions (a)

     (232     (176     (263     (385     (1,039

Changes in fair value of positions in the portfolio (b)

     194        281        380        17        (54

Other activity (c)

     (35     (26     (26     23        (46
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Commodity contract net asset at end of period

   $ 198      $ 259      $ 271      $ 180      $ 525   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(a) Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). 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) These amounts do not represent unrealized gains or losses. Includes initial values of positions involving the receipt or payment of cash or other consideration, generally related to options purchased/sold. The nine month values also include fair value of acquired commodity contracts as of the date of the Lamar and Forney Acquisition.

Maturity Table — The following tables presents the commodity contract net asset arising from recognition of fair values at September 30, 2016, scheduled by the source of fair value and contractual maturity dates of the underlying positions.

 

     Maturity dates of unrealized commodity
contract net asset at September 30, 2016
 

Source of fair value

   Less than
1 year
     1-3 years      4-5 years      Total  
     (in millions)  

Prices actively quoted

   $ 28       $ (6    $ (1    $ 21   

Prices provided by other external sources

     57         23                80   

Prices based on models

     53         40         4         97   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 138       $ 57       $ 3       $ 198   
  

 

 

    

 

 

    

 

 

    

 

 

 

Liquidity and Capital Resources

Operating Cash Flows

Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. Cash used in operating activities totaled $196 million in 2016 and cash provided by operating activities totaled $209 million in 2015. The increase in cash used of $405 million was primarily driven by a $232 million decrease in cash provided by margin deposits and higher cash interest payments.

 

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Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. Cash provided by operating activities totaled $237 million in 2015 compared to cash provided by operating activities of $444 million in 2014. The decrease of $207 million was driven by higher cash used to pay for reorganization costs and higher cash interest payments.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. Cash provided by operating activities totaled $444 million in 2014 compared to cash used in operating activities of $270 million in 2013. The increase in cash provided by operating activities of $714 million was primarily driven by lower cash interest payments due to the discontinuation of interest paid on pre-Petition debt and a decrease in cash used for margin deposits, partially offset by lower cash received from commodity hedging and trading activities reflecting lower gains on the natural gas hedging program.

Financing Cash Flows

Nine Months Ended September 30, 2016 Compared to Nine Months Ended September, 2015. Cash provided by financing activities totaled $1.913 billion in 2016 compared to cash used in financing activities of $20 million in 2015. Activity in 2016 reflected $2.040 billion in net borrowings under the TCEH DIP Roll Facilities and the TCEH DIP Facility, including $870 million in net borrowings to fund the Lamar and Forney Acquisition. Activity in 2016 also reflected $112 million in fees related to the issuance of the TCEH DIP Roll Facilities. Activity in 2016 and 2015 reflected debt repayments of $15 million and $20 million, respectively.

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. Cash used in financing activities totaled $30 million in 2015 compared to cash provided by financing activities of $1.111 billion in 2014. Activity in 2015 reflected the repayments of certain debt principal and fees. Activity in 2014 reflected $1.425 billion in borrowings from the TCEH DIP Facility, partially offset by $223 million in principal payments for pollution control revenue bonds and $92 million in fees associated with establishment of the TCEH DIP Facility.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. Cash provided by financing activities totaled $1.111 billion in 2014 compared to cash used in financing activities of $175 million in 2013. Activity in 2014 reflected $1.425 billion in borrowings from the TCEH DIP Facility, partially offset by $223 million in principal payments for pollution control revenue bonds and $92 million in payment of fees associated with establishment of the TCEH DIP Facility. Activity in 2013 reflected scheduled repayments of debt and an $82 million repayment resulting from the termination of the accounts receivable securitization program.

See Notes 11 and 12 to the 2015 Annual Financial Statements for further details of the TCEH DIP Facility and pre-Petition debt.

Investing Cash Flows

Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015. Cash used in investing activities totaled $1.288 billion and $330 million in 2016 and 2015, respectively. Cash used in 2016 reflected payments of $1.343 billion related to the Lamar and Forney Acquisition net of cash acquired and capital expenditures (including nuclear fuel purchases) totaling $263 million, partially offset by a $365 million decrease in restricted cash used to backstop letters of credit.

Capital expenditures, including nuclear fuel, during the nine months ended September 30, 2016 totaled $263 million and consisted of:

 

    $171 million, primarily for our existing generation operations;

 

    $40 million for environmental expenditures related to generation units;

 

    $33 million for nuclear fuel purchases, and

 

    $19 million for information technology, nuclear generation and other corporate investments.

 

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Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. Cash used in investing activities totaled $650 million and $458 million in 2015 and 2014, respectively. Cash used in 2015 reflected capital expenditures (including nuclear fuel purchases) totaling $460 million and a $123 million increase in restricted cash largely for supporting letters of credit issued under the TCEH DIP Facility. Cash used in 2014 reflected capital expenditures (including nuclear fuel purchases) totaling $413 million and a $350 million increase in restricted cash supporting letters of credit issued under the TCEH DIP Facility, partially offset by $392 million in restricted cash released from an escrow account when certain letters of credit were drawn.

Capital expenditures, including nuclear fuel, in 2015 totaled $460 million and consisted of:

 

    $230 million, primarily for our existing generation operations;

 

    $82 million for environmental expenditures related to generation units;

 

    $123 million for nuclear fuel purchases, and

 

    $25 million for information technology and other corporate investments.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013. Cash used in investing activities totaled $458 million in 2014 and cash provided by investing activities totaled $16 million in 2013. The increase in cash used in investing activities of $474 million reflected $698 million in cash provided in 2013 from EFH Corp.’s repayment of the TCEH demand notes. This was partially offset by a net $42 million source of cash from restricted cash activity in 2014 reflecting a $392 million source of cash from a collateral account when certain letters of credit were drawn, partially offset by a $350 million use of restricted cash supporting new letters of credit issued under the TCEH DIP Facility. Other favorable changes in investing activity in 2014 included a reduction in capital expenditures (including nuclear fuel purchases) of $175 million to $413 million, due to scope and timing of capital projects, including certain cancelled or deferred mining and generation projects, timing and costs of nuclear fuel purchases and pre-Petition payments that were stayed due to the Bankruptcy Filing. Investing cash flows were also favorably affected by $40 million in cash used in 2013 to acquire the owner participant interest in a trust established to lease six natural gas-fired combustion turbines to us.

Capital expenditures, including nuclear fuel, in 2014 totaled $413 million and consisted of:

 

    $248 million, primarily for our existing generation operations;

 

    $76 million for environmental expenditures related to generation units;

 

    $77 million for nuclear fuel purchases, and

 

    $12 million for information technology, nuclear generation development and other corporate investments.

Debt Activity

In August 2016, our Predecessor entered into a $4.25 billion senior secured super-priority TCEH DIP Roll Facility consisting of (1) the TCEH DIP Roll Revolving Credit Facility with borrowing capacity of $750 million, none of which was outstanding at September 30, 2016, (2) the TCEH DIP Roll Term Loan Letter of Credit Facility with borrowing capacity of $650 million, which was fully funded at September 30, 2016 and (3) the TCEH DIP Roll Term Loan Facility with a borrowing capacity of $2.85 billion, which was fully funded at September 30, 2016. The maturity date of the TCEH DIP Roll Facilities was the earlier of (a) October 31, 2017 or (b) the Effective Date. Net proceeds from the TCEH DIP Roll Facilities totaled $3.465 billion and were used to repay $2.65 billion outstanding under the TCEH DIP Facility, fund a $650 million collateral account used to backstop the issuances of letters of credit and pay $107 million of issuance costs. The remaining balance was used for general business purposes. In the September 30, 2016 condensed consolidated balance sheet, the borrowings under the TCEH DIP Roll Facilities were reported as noncurrent liabilities.

On the Effective Date, the TCEH DIP Roll Facilities were converted into the Vistra Operations Credit Facilities of Vistra Operations Company LLC. As of the Effective Date, the Vistra Operations Credit Facilities

 

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consisted of (i) a senior secured first lien revolving credit facility in an aggregate principal amount of $750 million, with a 5-year maturity, including both a letter of credit sub-facility and a swingline loan facility, which we refer to as the Initial Revolving Credit Facility, (ii) a senior secured term loan B facility in an aggregate principal amount of $2.85 billion, with a 7-year maturity, which we refer to as the Initial Term Loan B Facility, and (iii) a senior secured term loan C facility in an aggregate principal amount of $650 million, with a 7-year maturity, which we refer to as the Term Loan C Facility. On December 14, 2016, Vistra Operations obtained (i) $1 billion aggregate principal amount of incremental term loans, which we refer to as the 2016 Incremental Term Loans, and together with the Initial Term Loan B Facility, the Term Loan B Facility, and (ii) $110 million of incremental revolving credit commitments, which we refer to as the 2016 Incremental Revolving Credit Commitments, and together with the Initial Revolving Credit Facility, the Revolving Credit Facility. In addition, Vistra Operations increased the aggregate amount of letters of credit available under the Revolving Credit Facility from $500 million to $600 million. We refer to the Term Loan B Facility and the Term Loan C Facility as the Term Loan Facilities and to the Revolving Credit Facility and the Term Loan Facilities as the Vistra Operations Credit Facilities.

As of December 15, 2016, after giving effect to the borrowing of the 2016 Incremental Term Loans, $0, $3.85 billion and $650 million of loans were outstanding under the Revolving Credit Facility, the Term Loan B Facility and the Term Loan C Facility, respectively. Additionally, the size of the Revolving Credit Facility, the Term Loan B Facility and the Term Loan C Facility can each be increased, subject to a limit set forth in the credit agreement, pursuant to an uncommitted incremental facility.

Borrowings under the Revolving Credit Facility bear interest at a rate equal to, at our option, either a LIBOR plus an applicable margin of 3.25% or a base rate plus an applicable margin of 2.25%. Borrowings under the Initial Term Loan B Facility and the Term Loan C Facility bear interest at a rate equal to, at our option, either a LIBOR (subject to a LIBOR floor of 1.0%) plus an applicable margin of 4.00% or a base rate plus an applicable margin of 3.00%. The 2016 Incremental Term Loans bear interest at a rate equal to, at our option, either a LIBOR (subject to a LIBOR floor of .75%) plus an applicable margin of 3.25% or a base rate plus an applicable margin of 2.25%.

In December 2016, Vistra Operations executed $3 billion aggregate notional amount of pay fixed, receive floating interest rate swaps to hedge a portion of its LIBOR interest rate exposure on its outstanding term loans.

We are required to make scheduled quarterly payments on the Term Loan B Facility in annual amounts equal to 1.0% of the original principal amount of the Term Loan B Facility for six years and three quarters, with the balance paid at maturity.

In addition, we are required to prepay outstanding loans under the Term Loan Facilities, subject to certain exceptions, with:

 

    100% of the net cash proceeds of any issuance or incurrence of debt, other than proceeds from debt permitted under the Vistra Operations Credit Facilities; and

 

    100% of the net cash proceeds of all non-ordinary course asset sales, other dispositions of property or certain casualty events, in each case subject to certain exceptions and provided that we may reinvest those proceeds in assets to be used in its business or in certain other permitted investments.

We may make voluntary prepayments of outstanding loans under the Term Loan B Facilities and the Revolving Credit Facility and voluntary reductions of the unutilized portion of the commitments under the Revolving Credit Facility without penalty, subject to customary “breakage” costs with respect to LIBOR loans.

Term loans under the Term Loan B Facility and the Term Loan C Facility are prepayable at any time without premium or penalty; provided that there will be a 1.00% prepayment premium in connection with any repricing of such term loans that reduces the interest rate prior to (i) February 4, 2017, with respect to any term loans under the Initial Term Loan B Facility or Term Loan C Facility or (ii) June 14, 2017, with respect to any 2016 Incremental Term Loans.

 

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The Revolving Credit Facility requires that we, subject to a testing threshold, comply on a quarterly basis with a maximum consolidated first lien net leverage ratio of 4.25 to 1.00. The testing threshold will be satisfied at any time at which the sum of outstanding revolving credit facility loans and revolving letters of credit (excluding up to $100 million of undrawn revolving letters of credit and cash collateralized or backstopped letters of credit) exceeds 30% of the outstanding commitments under the Revolving Credit Facility at such time.

The Vistra Operations Credit Facilities contain restrictive covenants that limit Vistra Operations’ ability and the ability of its restricted subsidiaries to, among other things, (i) incur additional indebtedness or issue certain preferred shares, (ii) make certain investments, loans, and advances (including acquisitions), (iii) consolidate, merge, sell or otherwise dispose of all or any part of its assets, (iv) pay dividends or make distributions or other restricted payments, (v) create liens on certain assets, (vi) sell assets, (vii) enter into certain transactions with affiliates, (viii) enter into sale-leaseback transactions, (ix) restrict dividends from our subsidiaries or restrict liens and (x) modify the terms of certain debt agreements. Each of these covenants is subject to customary or agreed-upon exceptions, baskets and thresholds.

The Vistra Operations Credit Facilities also contain certain other customary affirmative covenants, including requirements to provide financial and other information to agents, to not change our lines of business and events of default, including events of default resulting from non-payment of any principal, interest or fees, material breaches of representations and warranties, failure to comply with the consolidated first lien net leverage rates covenant with respect to the Revolving Credit Facility, defaults under other agreements and instruments and the entry of a final judgment exceeding $300 million against Vistra Operations and its restricted subsidiaries, each subject to customary or agreed-upon exceptions, baskets and thresholds (including equity cure provisions).

Available Liquidity

The following table summarizes changes in available liquidity at December 15, 2016, September 30, 2016 and December 31, 2015:

 

     Available Liquidity  
     December 15,
2016
     September 30,
2016
     December 31,
2015
 
     (in millions)  

Cash and cash equivalents (a)

   $ 1,836       $ 1,829       $ 1,400   

TCEH DIP Roll Revolving Credit Facility

     N/A         750          

Original TCEH debtor-in-possession revolving credit facility

     N/A                1,950   

TCEH DIP Roll Term Loan Letter of Credit Facility

     N/A         104          

Revolving Credit Facility (b)

     860         N/A         N/A   

Initial Term Loan B Facility

            N/A         N/A   

Term Loan C Facility

     124         N/A         N/A   
  

 

 

    

 

 

    

 

 

 

Total liquidity

   $ 2,820       $ 2,683       $ 3,350   
  

 

 

    

 

 

    

 

 

 

 

(a) Includes proceeds from the 2016 Incremental Term Loans that will be used to fund the 2016 Special Dividend. Cash and cash equivalents at December 15, 2016, September 30, 2016 and December 31, 2015 exclude $650 million, $650 million and $1.026 billion, respectively, of restricted cash held for letter of credit support.
(b) The 2016 Incremental Revolving Credit Commitments increased borrowing capacity from $750 million to $860 million in December 2016 in connection with the 2016 Incremental Term Loans. See “— Debt Activity.”

The decrease in available liquidity of $667 million in the nine months ended September 30, 2016 compared to December 31, 2015 was primarily driven by $2.040 billion in net borrowings under the TCEH DIP Roll Facilities and the TCEH DIP Facility, including $870 million in net borrowings to fund the Lamar and Forney

 

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Acquisition, $1.064 billion in cash interest payments (including adequate protection payments), $263 million in capital expenditures (including nuclear fuel purchases) and $104 million of cash used to pay for reorganization expenses.

Based upon our current internal financial forecasts, we believe that we will have sufficient amounts available under the Vistra Operations Credit Facilities, plus cash generated from operations, to fund our anticipated cash requirements through at least the next 12 months.

Capital Expenditures

Capital expenditures and nuclear fuel purchases for 2016 are expected to total approximately $375 million and include:

 

    $260 million for investments in generation facilities, including approximately:

 

    $210 million for major maintenance and

 

    $50 million for environmental expenditures related to the MATS and other regulations;

 

    $75 million for nuclear fuel purchases; and

 

    $40 million for information technology and other corporate investments.

Pension and OPEB Plan Funding

See Note 18 to the 2015 Annual Financial Statements.

Liquidity Effects of Commodity Hedging and Trading Activities

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

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

At September 30, 2016, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:

 

    $42 million in cash has been posted with counterparties as compared to $6 million posted at December 31, 2015;

 

    $64 million in cash has been received from counterparties as compared to $152 million received at December 31, 2015;

 

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    $399 million in letters of credit have been posted with counterparties as compared to $230 million posted at December 31, 2015; and

 

    $2 million in letters of credit have been received from counterparties as compared to $3 million received at December 31, 2015.

Income Tax Matters

See “— Application of Critical Accounting Policies — Accounting for Income Taxes” above.

EFH Corp files a U.S. federal income tax return that, prior to the Effective Date, included the results of our Predecessor, which was classified as a disregarded entity for U.S. federal income tax purposes. Subsequent to the Effective Date, the TCEH Debtors and the EFH Shared Services Debtors are no longer included in the EFH Corp. consolidated group and will be included in a consolidated group of which Vistra Energy is the corporate parent. Prior to the Effective Date, EFH Corp. and certain of its subsidiaries (including EFCH and TCEH) were parties to a Federal and State Income Tax Allocation Agreement, which provided, among other things, that any corporate member or disregarded entity in the EFH Corp. group was required to make payments to EFH Corp. in an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return. Pursuant to the Plan of Reorganization, the TCEH Debtors and the EFH Shared Services Debtors rejected this agreement on the Effective Date. Additionally, since the date of the Settlement Agreement, no further cash payments among the Debtors were made in respect of federal income taxes. EFH Corp. has elected to continue to allocate federal income taxes among the entities that are parties to the Federal and State Income Tax Allocation Agreement. The Settlement Agreement did not alter the allocation and payment for state income taxes, which continued to be settled prior to the Effective Date.

The T-Side Debtors and the EFH Shared Services Debtors emerged from the Chapter 11 Cases on the Effective Date in a tax-free spin-off from EFH Corp that was part of a series of transactions that included a taxable component, which generated a taxable gain that will be offset with available net operating losses (NOLs) of EFH Corp., substantially reducing the NOLs available to EFH Corp. in the future. The EFH Corp. consolidated group’s NOLs as of December 31, 2016 (including current year losses and prior year carryforwards) prior to taking into account Emergence transaction impacts are estimated to be approximately $7.4 billion, and we expect that approximately $5.5 billion to $6.0 billion of those losses will be used to offset the taxable gain from Emergence.

Capitalization

At September 30, 2016, our capitalization ratios consisted of 304.4% borrowings under the TCEH DIP Roll Facilities, debt (less amounts due currently) and pre-Petition notes, loans and other debt reported as liabilities subject to compromise, and (204.4)% membership equity interests. Total borrowings under the TCEH DIP Roll Facilities, debt and pre-Petition notes, loans and other debt reported as liabilities subject to compromise to capitalization was 304.3% at September 30, 2016.

At December 31, 2015, our capitalization ratios consisted of 324.1% borrowings under the TCEH DIP Facility (classified as due currently), debt (less amounts due currently) and pre-Petition notes, loans and other debt reported as liabilities subject to compromise, and (224.1)% membership equity interests. Total borrowings under the TCEH DIP Facility, debt and pre-Petition notes, loans and other debt reported as liabilities subject to compromise to capitalization was 323.7% at December 31, 2015.

At December 31, 2014, our capitalization ratios consisted of 220.4% borrowings under the TCEH DIP Facility, debt (less amounts due currently) and pre-Petition notes, loans and other debt reported as liabilities subject to compromise, and (120.4%) membership equity interests. Total borrowings under the TCEH DIP Facility, debt and pre-Petition notes, loans and other debt reported as liabilities subject to compromise to capitalization was 220.2% at December 31, 2014.

 

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Collateral Support Obligations

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

The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, at September 30, 2016, TCEH posted letters of credit in the amount of $55 million, which is subject to adjustments. Such amount remains posted.

ERCOT has rules in place to assure adequate creditworthiness of parties that participate in the day-ahead, real-time and congestion revenue rights markets operated by ERCOT. Under these rules, TCEH has posted collateral support, in the form of letters of credit, totaling $110 million at September 30, 2016 (which is subject to daily adjustments based on settlement activity with ERCOT). Such amount remains posted.

Off-Balance Sheet Arrangements

See Notes 1 and 11 to the September 30, 2016 Quarterly Financial Statements regarding VIEs and guarantees, respectively, and Notes 13 and 19 to the 2015 Annual Financial Statements regarding guarantees and VIEs, respectively.

Contractual Obligations and Commitments

The following table summarizes the amounts and related maturities of our contractual cash obligations at September 30, 2016. Borrowings under the 2016 Incremental Term Loans and the Tax Receivable Agreement obligation are not included in the table below. Pre-Petition liabilities subject to compromise (i.e., obligations incurred or accrued prior to the Bankruptcy Filing) were, at September 30, 2016, being administered by the Bankruptcy Court and are excluded from the table below due to the uncertainty, at September 30, 2016, related to when those obligations will mature. As part of the Chapter 11 Cases, we have rejected or renegotiated certain contractual obligations and commitments, including certain leases, commodity purchase and service agreements. These new terms are reflected in the table below.

 

Contractual Cash Obligations:    Less Than
One Year (a)
     One to
Three
Years
     Three to
Five
Years
     More
Than Five
Years
     Total  
     (in millions)  

Debt — principal, including capital leases (b)

   $ 3       $ 3,501       $      $      $ 3,504   

Debt — interest (c)

     44         148                       192   

Operating leases

     5         45         40         85         175   

Obligations under commodity purchase and services agreements (d)

     194         295         123         442         1,054   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual cash obligations

   $ 246       $ 3,989       $ 163       $ 527       $ 4,925   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) Represents the period from October 1, 2016 to December 31, 2016.
(b) Includes $3.5 billion of borrowings under the TCEH DIP Roll Facilities and $4 million principal amount of long-term debt, including capital leases. Excludes unamortized discounts and fair value premiums and discounts related to purchase accounting. On the Effective Date, the TCEH DIP Roll Facilities converted to the Vistra Operations Credit Facilities, with maturity dates of August 2021 for the revolving credit facility and August 2023 for the term loan facilities (see Note 2 to the September 30, 2016 Quarterly Financial Statements).

 

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(c) Contractual and adequate protection interest payments are excluded.
(d) 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 2015 price for all periods except where contractual price adjustment or index-based prices are specified.

The following are not included in the table above:

 

    liabilities subject to compromise;

 

    arrangements between affiliated entities and intercompany debt;

 

    individual contracts that have an annual cash requirement of less than $1 million (however, multiple contracts with one counterparty that are more than $1 million on an aggregated basis have been included);

 

    contracts that are cancellable without payment of a substantial cancellation penalty; and

 

    employment contracts with management.

Guarantees — See Note 11 to the September 30, 2016 Quarterly Financial Statements and Note 13 to the 2015 Annual Financial Statements for a discussion of guarantees.

Quantitative and Qualitative Disclosures about Market Risk

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

Risk Oversight

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

Commodity Price Risk

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

 

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

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

A Monte Carlo simulation methodology is used to calculate VaR and is considered by management to be the most effective way to estimate changes in a portfolio’s value based on assumed market conditions for liquid markets. The use of this method requires a number of key assumptions, such as use of: (i) an assumed confidence level; (ii) an assumed holding period (i.e., the time necessary for management action, such as to liquidate positions); and (iii) historical estimates of volatility and correlation data. The tables below detail certain VaR measures related to various portfolios of contracts.

VaR for Energy-Related Contracts Subject to Mark-to-Market (MtM) Accounting — This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts marked-to-market in net income (principally hedges not accounted for as cash flow hedges), based on a 95% confidence level and an assumed holding period of five to 60 days.

 

     September 30,
2016
     December 31,
2015
 
     (in millions)  

Month-end average MtM VaR:

   $ 63       $ 68   

Month-end high MtM VaR:

   $ 118       $ 97   

Month-end low MtM VaR:

   $ 30       $ 49   

The increase in the month-end high MtM VaR risk measure reflected increased commodity positions, higher natural gas prices and increased price volatility during the second quarter of 2016.

 

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Interest Rate Risk

The following table provides information concerning our financial instruments at September 30, 2016 and December 31, 2015, 2014 and 2013 that are sensitive to changes in interest rates, which include debtor-in-possession financing and pre-Petition obligations that are fully secured and other obligations that are allowed to be paid as ordered by the Bankruptcy Court. Other pre-Petition obligations (i.e., obligations incurred or accrued prior to the Bankruptcy Filing) were, at each applicable date, being administered by the Bankruptcy Court and are excluded from the table below due to the uncertainty, at such time, related to when those obligations will mature.

 

    September 30,
2016

Total
Carrying

Amount
    September 30,
2016

Total Fair
Value
    December 31,
2015

Total
Carrying

Amount
    December 31,
2015

Total Fair
Value
    December 31,
2014

Total
Carrying

Amount
    December 31,
2014

Total Fair
Value
    December 31,
2013

Total
Carrying

Amount
    December 31,
2013

Total Fair
Value
 
    (in millions, except percentage amounts)  

Debt amounts (a):

               

Long-term debt not subject to compromise

  $ 2      $ 2      $ 15      $ 15      $ 31      $ 27        9,455        2,122   

Average interest rate

    1.74       6.71       6.98       11.13  

Borrowings under applicable debtor-in-possession credit facility

  $ 3,500      $ 3,526      $ 1,425      $ 1,411      $ 1,425      $ 1,430        20,787        14,394   

Average interest
rate (b)

    5.00       3.75       3.75       4.50  
     

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total debt

  $ 3,502      $ 3,528      $ 1,440      $ 1,426      $ 1,456      $ 1,457        30,242        16,516   
     

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(a) Capital leases and the effects of unamortized premiums and discounts are excluded from the table.
(b) The weighted average interest rate presented is based on the rate in effect at each applicable date.

In December 2016, Vistra Operations executed $3 billion aggregate notional amount of pay fixed, receive floating interest rate swaps to hedge a portion of its LIBOR interest rate exposure on its outstanding term loans.

Credit Risk

Credit risk relates to the risk of loss associated with nonperformance by counterparties. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies prescribe practices for evaluating a potential counterparty’s financial condition and liquidity, credit rating and other quantitative and qualitative credit criteria and authorize specific risk mitigation tools, including, but not limited to, use of standardized master agreements that allow for netting of positive and negative exposures associated with a single counterparty. We have processes for monitoring and managing credit exposure of our businesses, including methodologies to analyze counterparties’ financial strength, measurement of current and potential future exposures and contract language that provides rights for netting and setoff. Credit enhancements such as parental guarantees, letters of credit, surety bonds, margin deposits and customer deposits are also utilized. Additionally, individual counterparties and credit portfolios are managed to assess overall credit exposure.

Credit Exposure — Our gross exposure to credit risk associated with trade accounts receivable (retail and wholesale) and net asset positions (before collateral) arising from commodity contracts and hedging and trading activities totaled $871 million at September 30, 2016. The components of this exposure are discussed in more detail below.

Assets subject to credit risk at September 30, 2016 include $532 million in retail trade accounts receivable before taking into account cash deposits held as collateral for these receivables totaling $50 million. We believe the risk of material loss (after consideration of bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition or liquidity of large business customers.

The remaining credit exposure arises from wholesale trade receivables and amounts associated with derivative instruments related to hedging and trading activities. Counterparties to these transactions include energy companies, financial

 

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institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy marketing companies. At September 30, 2016, the exposure to credit risk from these counterparties totaled $339 million consisting of accounts receivable of $138 million and net asset positions related to commodity contracts of $201 million, after taking into account the netting provisions of the master agreements described above but before taking into account $66 million in collateral (cash, letters of credit and other credit support). The net exposure (after collateral) of $273 million decreased $59 million in the nine months ended September 30, 2016.

Of this $273 million net exposure, 93% is with investment grade customers and counterparties, as determined by our internal credit evaluation process, which is based on publicly available information such as major rating agencies’ published ratings as well as internal credit methodologies and credit scoring models. We routinely monitor and manage credit exposure to these customers and counterparties based on, but not limited to, our assigned credit rating, margining and collateral management.

The following table presents the distribution of credit exposure at September 30, 2016. This credit exposure largely represents wholesale trade accounts receivable and net asset positions related to commodity contracts and hedging and trading activities recognized as derivative assets in our condensed consolidated balance sheet, after taking into consideration netting provisions within each contract, setoff provisions in the event of default and any master netting contracts with counterparties. Credit collateral includes cash and letters of credit, but excludes other credit enhancements such as liens on assets.

 

     September 30, 2016  
     Exposure
Before Credit
Collateral
    Credit
Collateral
     Net
Exposure
 
     (in millions, except percentage amounts)  

Investment grade

   $ 303      $ 49       $ 254   

Below investment grade or no rating

     36        17         19   
  

 

 

   

 

 

    

 

 

 

Totals

   $ 339      $ 66       $ 273   
  

 

 

   

 

 

    

 

 

 

Investment grade

     89.4        93.0

Below investment grade or no rating

     10.6        7.0

In addition to the exposures in the table above, contracts classified as “normal” purchase or sale and non-derivative contractual commitments are not marked-to-market in the financial statements. Such contractual commitments may contain pricing that is favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform. Nonperformance could have a material impact on future results of operations, liquidity and financial condition.

Significant (10% or greater) concentration of credit exposure exists with two counterparties, which represented 39% and 14% of our $273 million net exposure. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the counterparties’ credit ratings, each of which we rate as investment grade, the counterparties’ market role and deemed creditworthiness and the importance of our business relationship with the counterparties. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts such as margin deposits are owed to the counterparties or delays in receipts of expected settlements owed to us. While the potential concentration of risk with these counterparties is viewed to be within an acceptable risk tolerance, the exposure to hedge counterparties is managed through the various ongoing risk management measures described above.

 

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Business

Our Company

Vistra Energy is a leading energy company operating an integrated power business in Texas, which includes TXU Energy and Luminant. Through TXU Energy and Luminant, our integrated business engages in retail sales of electricity and related services to end users, wholesale electricity sales and purchases, power generation, commodity risk management, fuel production and fuel logistics management. We are committed to providing superior customer service, maintaining operational excellence, applying an integrated approach to managing risk, applying a disciplined approach to managing costs, continuing our track record of superior corporate responsibility and citizenship and effectively managing through varying business cycles in the competitive power markets. Our goal is to deliver long-term value to our stockholders by maintaining a strong balance sheet and strong liquidity profile in order to provide us with the flexibility to pursue a range of capital deployment strategies, including investing in our current business, funding attractive organic and acquisition-driven growth opportunities and returning capital to our stockholders.

We operate as an integrated company that provides complete electricity solutions to our customers and to the broader ERCOT market. Our company is comprised of:

 

    our brand name retail electricity provider business, TXU Energy™, which is the largest retailer of electricity in Texas with approximately 1.7 million residential, commercial and industrial customers as of September 30, 2016, and maintains the highest residential customer retention rate of any Texas retail provider in its respective core market;

 

    our market-leading electricity generation business, Luminant, which operates approximately 17,000 MW of fuel-diverse installed capacity in Texas as of September 30, 2016, including the electricity that TXU Energy uses to supply its retail customers and that we sell to third parties in the wholesale market or otherwise;

 

    our premier wholesale commodity risk management operation, which dispatches our generation fleet in response to market conditions, markets the electricity generated by our facilities to our customers (including TXU Energy) and the broader ERCOT market, procures fuel from third parties for use at our electric generating facilities and performs the risk management services for Luminant and TXU Energy that enables the delivery of cost-effective electricity to the wholesale market and retail end-users;

 

    our well-established mining, fuel handling and logistics operations, which supply fuel to our diverse fleet of electric generating facilities and manage our real property holdings throughout the enterprise; and

 

    our efficient, low-cost support organizations, which provide the necessary services to meet our compliance obligations, support our integrated electricity solutions and assist in conducting our business in an environmentally responsible and regulatory-compliant manner.

All of our operations teams (mining and fuel handling; wholesale commodity risk management, asset optimization and generation fleet dispatch; power generation; retail electricity marketing, sales and services; and strategic sourcing, supply chain and procurement) are integrated. The integrated nature of these operations allows us, where appropriate, to manage these operations with close alignment, which we believe provides us better market insight and a reduction of the impact of commodity price volatility as compared to our non-integrated competitors. The balance between our retail and wholesale operations creates a uniquely integrated company that is the largest power generator and retail provider of electricity in Texas. We sell retail electricity and value-added services, primarily through TXU Energy, to approximately 1.7 million residential, commercial and industrial customers in Texas as of September 30, 2016. Additionally, we sell electricity and related products generated by our fleet of electric generating units, which had an aggregate of approximately 17,000 MW of generating capacity as of September 30, 2016. We also procure wholesale electricity and related commodities to fuel our generation facilities and supply our retail business. We also manage a well-established mining operation that has

 

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over 40 years of experience in supplying fuel to our fleet in a safe and environmentally responsible manner. Our generation portfolio is diverse and flexible in terms of fuel types and dispatch characteristics, which enables us to respond to changing market conditions and regulatory developments. The charts below show our market-leading position among power generators and electricity retailers in Texas. We believe the combination of these charts illustrates the unique opportunity that is created from our integrated business model.

 

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Date: 2015

Source: SNL

 

Date: 2015

Source: EIA

Note: Rankings do not combine a company that may own multiple brands.

 

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Our Integrated Business Model

We believe the key factor that distinguishes us from others in our industry is the integrated nature of our business (i.e., pairing Luminant’s reliable and efficient mining, generating and wholesale commodity risk management capabilities with TXU Energy’s retail platform) which, in our view, represents a unique company structure in the competitive ERCOT market and other competitive electricity markets across the country. We believe our integrated business model creates a unique opportunity because, relative to our non-integrated competitors, it insulates us from commodity price movements and provides unique earnings stability. Consequently, our integrated business model will be at the core of our business strategy.

The chart below depicts the integrated nature of our business and summarizes the unique advantages of our integrated business model.

 

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To further illustrate the benefits of our integrated business model, the chart below highlights the competitive advantages of our integrated business model as compared to our non-integrated competitors (i.e., pure-play IPPs and non-integrated REPs).

 

                     
       

 

IPP Model –

Competitive Pressures

     

Retail Model –

Competitive Pressures

         

Vistra Energy –

Integrated Advantage

    
                 

Commodity

Exposure Related

 

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  Low price environment puts pressure on “long” commodity IPP model

  Lack of depth of wholesale market makes meaningful long term hedging challenging

   

  Lowprice environment encourages competitive entry

  Lackof market depth to hedge supply requirements presents risk management issue

     

  Mitigatescash flow volatility from exposure to commodity prices

  Retailchannel provides an internal offset to generation (and vice versa)

  Lowerhedging transaction and collateral costs

 

   
                                 
                 

Impact of Technology

 

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  Technology advancement in, and subsidization of, wind, solar, and storage

  Low load growth environment; trends toward distributed generation and efficiency

   

  Trend towards energy efficiency and “green” products

     

  Opportunity to use customer channels to expand integrated model to new technology

  Creates new ways to engage customers and promotes long term relationships

 

   
                                 
                 

New

Entrants

 

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  Continued new build at questionable economics leads to high reserve margins & volatility in capacity prices

   

  Very aggressive / unsustainable pricing from new entrants / competitors

     

  Retail and wholesale diversification provides earnings stability and capital efficiencies relative to pure-play new entrants

 

   
                                 
                 

Regulatory/ Political

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  Regulatoryand political focus on emissions

  Considerableoversight with numerous restrictions on market behavior

  Onerousrules regarding asset retirement

   

  ERCOT is only fully competitive retail market in North America (price-to-beat expired in 2007)

  Non ERCOT retail market faces structural challenges

-    Default provider sets effective ceiling price

-    Utilities retain most customers and the customer interface, limiting opportunities to differentiate

     

  As largest retail provider in ERCOT, the only fully deregulated retail market, TXU Energy lowers risk profile of overall portfolio compared to competitors in other markets

   
                     

Our Operations

Our primary operations consist of electricity solutions, including retail sales of electricity and related products to end users, power generation (including operations and maintenance and outage and project management) and sales of electric generating unit output in the wholesale marketplace, asset optimization and commodity risk management performed on an integrated basis for our retail and wholesale positions, and fuel logistics and management. These operations work together on an integrated basis, which allows us to realize efficiencies and alignment in all aspects of the electricity generation and sales operation.

We operate solely in the growing ERCOT electricity market, which we view as one of the most attractive power markets in the United States. As described in more detail below, ERCOT is an ISO that manages the flow of electricity to approximately 24 million Texas customers, representing 90% of the state’s load, and spanning approximately 75% of its geography, as of September 30, 2016.

Texas has one of the fastest growing populations of any state in the United States and has a diverse economy, which has resulted in a significant and growing competitive retail electricity market. We are an active participant in the competitive ERCOT market and continue to be a market leader, which we believe is driven by, among other

 

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things, having one of the lowest customer complaint rates, according to the PUCT, having an integrated power generation operation that allows us to efficiently obtain the electricity needed to serve our customers at the lowest cost, and leveraging the experience of our wholesale commodity risk management operations to optimize our cost to procure electricity and other products on behalf of our customers. We provided electricity to approximately 24% and 19% of the residential and commercial customers in ERCOT, respectively, as of September 30, 2016. We have differentiated ourselves by providing a distinctive customer experience predicated on delivering reliable and innovative power products and solutions to our customers, such as Free Nights and Weekends residential plans, MyEnergy DashboardSM, TXU Energy’s iThermostat product and mobile solutions, the TXU Energy Rewards program, the TXU Energy Green UPSM renewable energy credit program and a diverse set of solar options, which give our customers choice, convenience and control over how and when they use electricity and related services. We competitively market our retail electricity and related services to acquire, serve and retain both retail and wholesale customers. Our wholesale customers represent a cross section of industrial users, other competitive retail electric providers, municipalities, cooperatives and other end-users of electricity. We are able to better serve our retail customers through our unique affiliation with our wholesale commodity risk management personnel who are able to structure products and contracts in a way that offers significant value compared to stand-alone retail electric providers. Additionally, our generation business protects our retail business from power price volatility, by allowing it to bypass bid-ask spread in the market (particularly for illiquid products and time periods), which results in significantly lower collateral costs for our retail business as compared to other, non-integrated retail electric providers. Moreover, our retail business insulates, to some extent, our wholesale generation business. This is because the retail load requirements of our retail operations (primarily TXU Energy) provides a natural offset to the length of Luminant’s generation portfolio thereby reducing the exposure to wholesale power price volatility as compared to a non-integrated pure-play IPP.

Our power generation fleet is diverse and flexible in terms of dispatch characteristics as our fleet includes baseload, intermediate/load-following and peaking generation. Our wholesale commodity risk management business is responsible for dispatching our generation fleet in response to market needs after implementing portfolio optimization strategies, thus linking and integrating the generation fleet production with our retail customer and wholesale sales opportunities. Market demand, also known as load, faced by an electric power system such as ERCOT varies from moment to moment as a result of changes in business and residential demand, much of which is driven by weather. Unlike most other commodities, the production and consumption of electricity must remain balanced on an instantaneous basis. There is a certain baseline demand for electricity across an electric power system that occurs throughout the day, which is typically satisfied by baseload generating units with low variable operating costs. Baseload generating units can also increase output to satisfy certain incremental demand and reduce output when demand is unusually low. Intermediate/load-following generating units, which can more efficiently change their output to satisfy increases in demand, typically satisfy a large proportion of changes in intraday load as they respond to daily increases in demand or unexpected changes in supply created by reduced generation from renewable resources or other generator outages. Peak daily loads are typically satisfied by peaking units. Peaking units are typically the most expensive to operate, but they can quickly start up and shut down to meet brief peaks in demand. In general, baseload units, intermediate/load-following units and peaking units are dispatched into the ERCOT grid in order from lowest to highest variable cost. Price formation in ERCOT, as with other competitive power markets in the United States, is typically based on the highest variable cost unit that clears the market to satisfy system demand at a given point in time.

 

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As of September 30, 2016, our generation fleet consisted of 50 electric generating units, all of which are wholly owned, with the fuel types, dispatch characteristics and total installed nameplate generating capacity as shown in the table below:

 

Fuel Type

  

Dispatch

   Installed Nameplate
Generation
Capacity (MW)
     Number of
Plant Sites
     Number of
Units
 

Nuclear

   Baseload      2,300         1         2   

Lignite

   Baseload      2,737         2         4   

Lignite/Coal

   Intermediate/Load-Following      5,280         3         8   

Natural Gas (CCGT)

   Intermediate/Load-Following      2,988         2         14   

Natural Gas (Steam and CTs)

   Peaking      3,455         7         22   
     

 

 

    

 

 

    

 

 

 

Total

        16,760         15         50   
     

 

 

    

 

 

    

 

 

 

Our wholesale commodity risk management business also procures renewable energy credits from wind generation to support our electricity sales to wholesale and retail to satisfy the increasing demand for renewable resources from customers. As of September 30, 2016, we had long-term PPAs to annually procure 390 MW of renewable energy. These renewable generation sources deliver electricity when conditions make them available, and, when on-line, they generally compete with baseload units. Because they cannot be relied upon to meet demand continuously due to their dependence on weather and time of day, these generation sources are categorized as non-dispatchable and create the need for intermediate/load-following resources to respond to changes in their output.

Our generation resources, which represented approximately 18% of the generation capacity in ERCOT as of September 30, 2016, allow us to annually generate, procure and sell approximately 75-85 TWh of electricity to wholesale and retail customers from nuclear, natural gas, lignite, coal and renewable generation resources. The chart below shows the diversification of our generation fleet in terms of fuel types and dispatch characteristics as of September 30, 2016.

Generation

2016; % MWs

 

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The map below shows our significant footprint in Texas and further demonstrates the integrated nature of our business.

 

 

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Our Competitive Strengths

We believe we are well-positioned to execute our business strategy of delivering long-term value to our stakeholders based on, among others, the following competitive strengths:

Uniquely situated integrated energy company.

We believe the key factor that distinguishes us from others in our industry is the integrated nature of our business (i.e., pairing Luminant’s reliable and efficient mining, generating and wholesale commodity risk management capabilities with TXU Energy’s retail platform). We believe this is a unique company structure in the competitive ERCOT market and other competitive electricity markets across the country. It is our view that our integrated business model provides us a competitive advantage and results in more stable earnings under all market environments relative to our non-integrated competitors. In general, non-integrated electricity retailers are subject to wholesale power price and resulting cash flow volatility when demand increases or supply tightens, which can potentially result in significant losses if an electricity retailer is not appropriately hedged. However, because of the risk mitigation created by our integrated business model, we believe our retail operations (primarily TXU Energy) are not as exposed to wholesale power price volatility as non-integrated retail power companies. Moreover, given the retail load requirements of our retail operations (primarily TXU Energy), the length of Luminant’s generation portfolio is not as exposed to wholesale power price volatility as compared to a non-integrated pure-play IPP. Additionally, our mining operations provide an alternative to other coal procurement sources and give us more flexibility in reaching the most cost-effective arrangements for our coal-fueled facilities. We believe these advantages make our business less subject to volatility risk than pure-play IPPs and non-integrated retail electric providers. Furthermore, we believe our integrated business model allows us to reduce sourcing and transaction costs and minimize credit and collateral requirements.

 

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Highly valued retail brand and customer-focused operations.

Our TXU Energy™ brand enjoys long-standing and strong brand recognition throughout ERCOT, enabling us to effectively acquire, serve and retain a broad spectrum of retail electricity customers. Our TXU Energy™ brand is viewed by customers as a symbol of a trustworthy, customer-centric, innovative and dependable electricity service. By leveraging our retail marketing capabilities, commitment to product innovation and deep knowledge of the ERCOT market and its customer base, we believe that we can maintain and grow our position as the largest retailer of electricity in the highly competitive ERCOT retail market. We have an operating model that has delivered attractive margins and strong customer satisfaction that has been consistently ranked by the PUCT as having among the lowest customer complaint rates in the ERCOT market. We drive positive results in our retail electricity business by functioning as a technology driven, multi-channel marketer with advanced analytics and product development capabilities. We have leveraged these capabilities and the TXU Energy™ brand to deliver a wide range of innovative power products and services to our customers, including Free Nights and Weekends residential plans, MyEnergy DashboardSM, TXU Energy’s iThermostat product and mobile solutions, the TXU Energy Rewards program, the TXU Energy Green UpSM renewable energy credit program and a diverse set of solar options, which give our customers choice, convenience and control over how and when they use electricity and related services. We believe our strong customer service, innovative products and trusted brand recognition have resulted in us maintaining the highest residential customer retention rate of any Texas retail electric provider in its respective core market.

Diversified generation sources and critical energy infrastructure.

We maintain operational flexibility to provide reliable and responsive power under a variety of market conditions by utilizing generation sources that are diverse and flexible in terms of fuel types (nuclear, lignite, coal, natural gas and renewables) and dispatch characteristics (baseload, intermediate/load-following, peaking and non-dispatchable). These generation sources feature the following characteristics:

 

    Except for periods of scheduled maintenance activities, our nuclear-fueled units are generally available to run at capacity.

 

    Except for periods of scheduled maintenance activities, our lignite- and coal-fueled units are available to run at capacity or seasonally, depending on market conditions (i.e., during periods when wholesale electricity prices are greater than the unit’s variable production costs). Certain of these units run only during the summer peak period and at times go into seasonal layup during the months with lower seasonal demand.

 

    Our CCGT units generally run during the intermediate/load-following periods of the daily supply curve.

 

    Our natural gas-fueled generation peaking units supplement the aggregate nuclear-, lignite- and coal-fueled and CCGT generation capacity in meeting demand during peak load periods because production from certain of these units, particularly combustion-turbine units, can be more quickly adjusted up or down as demand warrants. With this quick-start capability, we are able to increase generation during periods of supply or demand volatility in ERCOT and capture scarcity pricing in the wholesale electricity market. These natural gas-fueled generation peaking units also help us mitigate unit-contingent outage risk by allowing us to meet demand even if one or more of our nuclear, lignite, coal or CCGT units is taken offline for maintenance.

 

    The CCGT and natural gas-fueled generation peaking units also play a pivotal and increasing role in the ERCOT market by supplementing intermittent renewable generation through their versatile operations. We expect this versatility to increase in value over time as the ERCOT market continues to expand into renewable resources.

 

    Our long-term PPAs with various renewable energy providers deliver electricity when natural conditions make renewable resources available. These resources position us to meet the market’s increasing demand for sustainable, low-carbon power solutions.

 

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In addition, the commodity risk management and asset optimization strategies executed by our commercial operation supplement the electricity generated by our fleet with electricity procured in market transactions to ensure that we are supplying our customer obligations with the most cost-effective electricity options.

Competitive scale and highly effective, low-cost support operations.

Our integrated company includes the largest power generator and retailer of electricity in Texas, as complemented by our mining and fuel handling operations and our wholesale commodity risk management business. As an integrated energy company with approximately 17,000 MW of generation capacity and approximately 1.7 million retail electricity customers, each as of September 30, 2016, we operate with significant scale. This scale enables us to conduct our business with certain operational synergies that are not available to smaller power generation or retail electricity businesses. The benefits of our significant scale include improved leverage of our low fixed costs, opportunities to share expertise across the portfolio of assets, enhanced procurement opportunities, development of, and the ability to offer, a wide array of products and services to our customers, shared expertise of employees, diversity of cash flows and a breadth of positive relationships with regulatory and governmental authorities. We believe these advantages, combined with a strong balance sheet and strong liquidity profile, enable us to operate with more financial flexibility than our competitors, and will enable us to prudently grow our existing business and pursue attractive growth opportunities in the future.

Positioned to capture upside in the attractive ERCOT market.

We believe that the location of our business, solely in ERCOT, offers attractive upside opportunities. ERCOT is the only fully deregulated electricity market in the United States in that both the wholesale and retail markets are truly competitive. In addition to having a robust wholesale market, the ERCOT residential retail market does not have regulated providers or a standard offer service, which is unique among competitive retail markets in the United States. We believe our integrated business model uniquely positions us to benefit from this attractive, robust marketplace. The ERCOT market represents approximately 90% of the load in Texas, a state that is the seventh-largest power market in the world, according to the United States Energy Information Administration (EIA), and had a population growth rate of 8.8% between July 2010 and July 2015, more than double the United States population growth rate of 3.9% during the same period, according to the U.S. Census Bureau. ERCOT has shown historically above-average load growth compared to other power markets in the United States, according to the EIA, and ERCOT can be viewed as a “power island” due to its limited import and export capacity, which we believe creates a favorable power supply and demand dynamic. Total ERCOT power demand has grown at a compounded annual growth rate of approximately 1.5% from 2005 through 2015, compared to a range of -0.6% to 0.8% in other United States markets, according to ERCOT and the EIA, respectively.

We consider ERCOT to be one of the most well-developed power markets in the United States, providing a stable regulatory environment and significant price transparency, market liquidity and support to competitive generators and retail electric providers like us. The energy-only wholesale market structure in ERCOT offers a variety of potential revenue streams in addition to energy revenues such as ancillary services and the ORDC, which ERCOT implemented on June 1, 2014. A unique feature of the ERCOT energy market is the system-wide offer cap of $9,000/MWh, which is substantially higher than other markets with capacity markets. While the ERCOT market is currently oversupplied, we expect reserve margins to be forecasted to continue to compress over time due to growing demand, potential generation retirements and limited announced new-build projects, particularly of non-intermittent projects, further tightening the supply and demand balance and creating conditions that may generate increased price volatility and higher wholesale electricity prices. We believe that our existing asset base and integrated business model (including our integrated approach to risk management) will enable us to take advantage of these opportunities in a disciplined manner. See “— The ERCOT Market” below for more information about ERCOT and the ORDC.

In addition, in general, Luminant’s generation portfolio (primarily the nuclear, lignite and coal generation facilities) is positioned to increase in value to the extent there is a rebound in forward natural gas prices. We

 

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cannot predict, however, whether or not forward natural gas prices will rebound or the timing of any such rebound if it were to occur in the future.

Strong balance sheet and strong liquidity profile.

In connection with Emergence, a substantial amount of the debt of our Predecessor was eliminated. As a result, we believe our balance sheet is strong given our low leverage relative to the cash flows generated from our integrated business. Further, we believe that our financial leverage is prudent and, together with our strong cash flow and strong liquidity profile, provides us with significant competitive advantages relative to our competitors, especially those that have much more leverage than we do. Moreover, it is our view that our integrated business model combined with our strong balance sheet sets us apart from other non-integrated pure-play IPPs in our industry, particularly those that have much more leverage than we do. We believe that our integrated business model further improves our liquidity profile relative to our non-integrated competitors because such integration reduces our retail operations’ exposure to wholesale electricity price volatility resulting in our retail operations having lower collateral requirements with counterparties and ERCOT. We also believe a strong balance sheet allows us to manage through periods of commodity price volatility that may require incremental liquidity and positions us well to pursue a range of capital deployment strategies, including investing in our current business, funding attractive organic and acquisition-driven growth opportunities and returning capital to our stockholders. 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.

Proven, experienced management team.

The members of our senior management team have significant industry experience, including experience operating in a competitive retail electricity environment, operating sophisticated power generation facilities, operating a safe and cost-efficient mining organization and managing the risks of competitive wholesale and retail electricity businesses. We believe that our management team’s history of safe and reliable operations in our industry, breadth of positive relationships with regulatory and legislative authorities and commitment to a disciplined and prudent operating cost structure and capital allocation will benefit our stakeholders. Moreover, between personal investments in our common stock and our incentive compensation arrangements, our management team has a meaningful stake in Vistra Energy, thereby closely aligning incentives between management and our stockholders.

Our Business Strategy

Our business strategy is to deliver long-term stakeholder value through a multi-faceted focus on the following areas:

Integrated business model.

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 insulates us from commodity price movements and provides unique earnings stability. Consequently, our integrated business model will be at the core of our business strategy.

Superior customer service.

Through TXU Energy, we serve the retail electricity needs of end-use residential, small business, commercial and industrial electricity customers through multiple sales and marketing channels. In addition to benefitting from our integrated business model, we leverage our strong brand, our commitment to a consistent

 

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and reliable product offering, the backstop of the electricity generated by our generation fleet, our industry-leading wholesale commodity risk management operations and exceptional, innovative and dependable customer service to differentiate our products and services from our competitors. We strive to be at the forefront of innovation with new offerings and customer experiences to reinforce our value proposition. We maintain a focus on solutions that give our customers choice, convenience and control over how and when they use electricity and related services, including Free Nights and Weekends residential plans, MyEnergy DashboardSM, TXU Energy’s iThermostat product and mobile solutions, the TXU Energy Rewards program, the TXU Energy Green UpSM 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 strong customer service, innovative products and trusted brand have resulted in us 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 and implementing enterprise-wide process and operating improvements without compromising the safety of our communities, customers and employees. In connection with Emergence, we implemented certain cost-reduction actions in order to better align and right-size our cost structure. We believe we have a highly effective and efficient cost structure and that our cost structure supports excellence in our operations. We will continue to refine and optimize our cost structure as opportunities arise.

Integrated hedging and commercial management.

Our commercial team is focused on managing risk, through opportunistic hedging, and optimizing our assets and business positions. We actively manage our exposure to wholesale electricity prices in ERCOT, on an integrated basis, through contracts for physical delivery of electricity, exchange-traded and over-the-counter financial contracts, ERCOT term, day-ahead and real-time market transactions and bilateral contracts with other wholesale market participants, including other power generators and end-user electricity customers. These hedging activities include short-term agreements, long-term electricity sales contracts and forward sales of natural gas through financial instruments. The historically positive correlation between natural gas prices and wholesale electricity prices in ERCOT has provided us an opportunity to manage our exposure to the variability of wholesale electricity prices through natural gas hedging activities. We seek to hedge near-term cash flow and optimize long-term value through hedging and forward sales contracts. We believe our integrated hedging and commercial management strategy, in combination with a strong balance sheet and strong liquidity profile, will provide a long-term advantage through cycles of higher and lower commodity prices.

Disciplined capital allocation.

Like any energy-focused business, we are potentially subject to significant commodity price volatility and capital costs. Accordingly, our strategy is to maintain a balance sheet with prudent financial leverage supported by readily accessible, flexible and diverse sources of liquidity. Our ongoing capital allocation priorities primarily include making necessary capital investments to maintain the safety and reliability of our facilities. Because we believe cost discipline and strong management of our assets and commodity positions are necessary to deliver long-term value to our stakeholders, we generally make capital allocation decisions that we believe will lead to attractive cash returns on investment. We are focused on optimal deployment of capital and intend to evaluate a range of capital deployment strategies including return of capital to stockholders in the form of dividends and/or share repurchases, investments in our current business and acquisition-driven growth investments.

 

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Growth and enhancement.

Our growth strategy leverages our core capabilities of multi-channel retail marketing in a large and competitive market, operating large-scale, environmentally sensitive, and diverse assets across a variety of fuel technologies, fuel logistics and management, commodity risk management, cost control, and energy infrastructure investing. We intend to opportunistically evaluate acquisitions of high-quality energy infrastructure assets and businesses that complement these core capabilities and enable us to achieve operational or financial synergies. To that end, our primary focus will target growth opportunities that expand or enhance our business position within ERCOT and are consistent with our integrated business model (including our stable earnings profile as compared to our non-integrated competitors). While we solely operate within ERCOT currently, we intend to evaluate energy infrastructure growth opportunities outside ERCOT that offer compelling value creation opportunities, including cost and operational improvements, organic growth opportunities and attractive and stable earnings profiles featuring multiple revenue streams. We also believe that there will continue to be significant acquisition opportunities for competitive power generation assets and retail electricity businesses in power markets in the United States based on, among other things, the continuing trend of separating competitive power generation assets from regulated utility assets. 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 our operations. Our company and our employees are actively engaged in programs intended to support and strengthen the communities in which we conduct our operations. Our foremost giving initiatives, the United Way and TXU Energy Aid campaigns, have raised more than $30 million in employee and corporate contributions since 2000. Additionally, for more than 30 years, TXU Energy Aid has served as an integral resource for social service agencies that assist families in need, having helped more than 500,000 customers across Texas pay their electricity bills.

 

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The ERCOT Market

ERCOT is an ISO that manages the flow of electricity from approximately 77,000 MW of installed capacity to 24 million Texas customers, representing 90% of the state’s electric load and spanning approximately 75% of its geography, as of September 30, 2016. ERCOT is a highly competitive wholesale electricity market with historically above-average demand growth, limited import and export capacity and increasing wholesale price caps, and is the seventh-largest power market in the world, according to the EIA. Population growth in Texas is currently expanding at well above the national average rate, with a growth rate of 8.8% between July 2010 and July 2016, more than double the United States population growth rate of 3.9% during the same period, according to the U.S. Census Bureau. ERCOT accounts for approximately 32% of the competitively served retail load in the United States and residential consumers in the ERCOT market consume approximately 32% more electricity than the average United States residential consumer according to the EIA. Total ERCOT power demand has grown at a compounded annual growth rate of approximately 1.5% from 2005 through 2015, compared to a range of -0.6% to 0.8% in other United States markets, according to ERCOT and the EIA, respectively. ERCOT was formed in 1970 and became the first ISO in the United States in September 1996. The following map illustrates ERCOT by regions:

 

 

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As an energy-only market, ERCOT’s market design is distinct from other competitive electricity markets in the United States. Other markets maintain a minimum reserve margin through regulated planning, resource adequacy requirements and/or capacity markets. In contrast, ERCOT’s resource adequacy is predominately dependent on free-market processes and energy-market price signals. On June 1, 2014, ERCOT implemented the ORDC, pursuant to which wholesale electricity prices in the real-time electricity market increase automatically as available operating reserves decrease below defined threshold levels, creating a price adder. When operating reserves drop to 2,000 MW or less, the ORDC automatically adjusts power prices to the established VOLL, which is set at $9,000/MWh. Because ERCOT has limited excess generation capacity to meet high demand days due to its minimal import capacity, and peaking facilities have high operating costs, the marginal price of supply rapidly increases during periods of high demand. Historically, elevated temperatures in the summer months have driven high electricity demand in ERCOT. Many generators benefit from these sporadic periods of “scarcity pricing” in which power prices may increase significantly, up to the current $9,000/MWh price cap.

Transactions in ERCOT take place in two key markets: the day-ahead market and the real-time market. The day-ahead market is a voluntary, forward electricity market conducted the day before each operating day in

 

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which generators and purchasers of electricity may bid for one or more hours of electricity supply or consumption. The real-time market is a spot market in which electricity may be sold in five-minute intervals. The day-ahead market provides market participants with visibility into where prices are expected to clear, and the prices are not impacted by subsequent events. Conversely, the real-time market exposes purchasers to the risk of transient operational events and price spikes. These two markets allow market participants to manage their risk profile by adjusting their participation in each market. In addition, ERCOT uses ancillary services to maintain system reliability, including regulation service — up, regulation service — down, responsive reserve service and non-spinning reserve service. Regulation service up and down are used to balance the grid in a near-instantaneous fashion when supply and demand fluctuate due to a variety of factors, such as weather, generation outages, renewable production intermittency and transmission outages. Responsive reserves and non-spinning reserves are used by ERCOT when the grid is at, near or recovering from a state of emergency due to inadequate generation. Because ERCOT has one of the highest concentrations of wind capacity generation among United States markets, the ERCOT market is more susceptible to fluctuations in wholesale electricity supply due to intermittent wind production, making ERCOT more vulnerable to periods of generation scarcity.

Legal Proceedings and Regulatory Matters

Proceedings against the Debtors

Substantially all liabilities of the Debtors were resolved under the Plan. Please see “The Reorganization and Emergence” for more detailed information regarding the Plan and the treatment of claims under the Plan.

Environmental Matters

Litigation relating to EPA Reviews

In June 2008, the United States Environmental Protection Agency (EPA) issued an initial request for information to our Predecessor under the EPA’s authority under Section 114 of the Clean Air Act (CAA). The stated purpose of the request is to obtain information necessary to determine compliance with the CAA, including New Source Review standards and air permits issued by the Texas Commission on Environmental Quality (TCEQ) for the Big Brown, Monticello and Martin Lake generation facilities. In April 2013, our Predecessor received an additional information request from the EPA under Section 114 related to the Big Brown, Martin Lake and Monticello facilities as well as an initial information request related to the Sandow 4 generation facility.

In July 2012, the EPA sent our Predecessor a notice of violation alleging noncompliance with the CAA’s New Source Review standards and the air permits at our Martin Lake and Big Brown generation facilities. In July 2013, the EPA sent our Predecessor a second notice of violation al