Filed Pursuant to Rule 424(b)(3)
Registration No. 333-215288

PROSPECTUS

Vistra Energy Corp.

168,779,076 Shares of Common Stock

This prospectus relates to 168,779,076 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 “Principal and 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 listed on the New York Stock Exchange (the “NYSE”) under the symbol “VST.” On March 20, 2018, the closing sales price of our common stock as reported on the NYSE was $19.82 per share.

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” in Part I, Item 1A of the Vistra 2017 Form 10-K, which is incorporated by reference herein.

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 March 21, 2018.

Table of Contents

	Page
About this Prospectus		ii
Prospectus Summary		1
Risk Factors		4
Special Note Regarding Forward-Looking Statements		5
Industry and Market Information		7
Use of Proceeds		8
Market Prices and Dividend Policy		9
Management		10
Executive Compensation		17
Principal and Selling Stockholders		18
Certain Relationships and Related Party Transactions		23
Description of Capital Stock		28
Material U.S. Federal Income Tax Considerations for Non-U.S. Holders		34
Shares Eligible for Future Sale		38
Plan of Distribution		39
Incorporation by Reference of Certain Documents		42
Legal Matters		42
Experts		42
Where You Can Find More Information		43
Information About The Merger and Dynegy		44
General		44
Unaudited Pro Forma Condensed Combined Consolidated Financial Information		45
Notes to Unaudited Pro Forma Condensed Combined Consolidated Financial Information		49
Information about Dynegy		57
Risk Factors Related to Dynegy		60
Dynegy Selected Historical Consolidated Financial Information		69
Dynegy Management’s Discussion and Analysis of Financial Condition and Results of Operations		71
Dynegy Inc. Index to Consolidated Financial Statements		F-1

i

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 168,779,076 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.

As permitted under the rules of the Commission, this prospectus incorporates important business and financial information about the Company that is contained in documents that we file with the Commission, but that are not included in or delivered with this prospectus. You may obtain copies of these documents, without charge, from the website maintained by the Commission at www.sec.gov, as well as other sources. See “Where You Can Find More Information” in this prospectus. Before you invest in our securities, you should read carefully the registration statement (including the exhibits thereto) of which this prospectus forms a part, this prospectus, any prospectus supplement, or any accompanying prospectus supplement, and any document incorporated by reference herein, including our Annual Report on Form 10-K (the “Vistra 2017 Form 10-K”) for the year ended December 31, 2017, filed with the Commission on February 26, 2018. You should rely only on the information contained in this prospectus and in the Vistra 2017 Form 10-K. We have not authorized anyone to provide you with additional or different information from that contained in this prospectus or the Vistra 2017 Form 10-K.

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 of Energy Future Holdings Corp. and the substantial majority of its direct and indirect subsidiaries, including Energy Future Intermediate Holding Company LLC, Energy Future Competitive Holdings Company LLC and our Predecessor, but excluding Oncor Electric Delivery Holdings Company LLC and its direct and indirect subsidiaries.

The historical financial information and accompanying financial statements and corresponding notes contained or incorporated by reference in this prospectus for periods prior to October 3, 2016 (the “Effective Date”) reflect the actual historical consolidated results of operations, cash flows and financial condition of our Predecessor and do not give effect to the Plan, Emergence or the adoption of fresh-start reporting. Thus, such financial information is not 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 continues to own and operate, directly and indirectly, substantially the same business that our Predecessor owned and operated prior to Emergence and, as of the Effective Date, Vistra Energy applied fresh-start reporting in its financial statements, 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 for periods prior to Emergence and to Vistra Energy for periods subsequent to Emergence. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation, in the Vistra 2017 Form 10-K for further information.

ii

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.

iii

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 Vistra Energy Corp., a Delaware corporation, and, unless the context otherwise requires, its direct and indirect subsidiaries.

Our Company

Vistra Energy is a holding company operating an integrated power business in Texas. Through our Luminant and TXU Energy subsidiaries, we are engaged in competitive electricity market activities including electricity generation, wholesale energy sales and purchases, commodity risk management activities, and retail sales of electricity to end users, all largely in the Electric Reliability Council of Texas, Inc. (“ERCOT”) market.

TXU Energy is the largest retailer of electricity in Texas, with approximately 1.7 million residential, commercial and industrial customers. Luminant is the largest generator of electricity in ERCOT, operating approximately 13,600 MW of installed capacity in ERCOT.

We have two reportable segments: our Wholesale Generation segment, consisting largely of Luminant, and our Retail Electricity segment, consisting largely of TXU Energy.

As of December 31, 2017, we had approximately 4,150 full-time employees, including approximately 1,630 employees under collective bargaining agreements.

Merger with Dynegy

General

On October 29, 2017, Vistra Energy and Dynegy Inc., a Delaware corporation (“Dynegy”), entered into an Agreement and Plan of Merger (the “Merger Agreement”) pursuant to which, upon closing, Dynegy will merge with and into Vistra Energy (the “Merger”), with Vistra Energy surviving the Merger and the shareholders of Vistra Energy and Dynegy receiving 79% and 21%, respectively, of the equity of the combined company. Consummation of the Merger is subject to a number of conditions. We expect the Merger to close in the second quarter of 2018. See “Information About the Merger and Dynegy” below for a more detailed description of the Merger and the Merger Agreement.

Information about the Company Following the Merger

The combined company will retain the name “Vistra Energy Corp.” and will continue to be a Delaware corporation. The combined company is expected to serve approximately 240,000 commercial and industrial customers and 2.7 million residential customers in five top retail states, with estimated retail sales of 75 TWh in 2018. The common stock of the combined company will continue to be listed on the New York Stock Exchange, trading under the symbol “VST”. The combined company’s principal executive offices will be located at 6555 Sierra Drive, Irving, Texas 75039.

Unaudited Pro Forma Condensed Combined Consolidated Financial Information

For the unaudited pro forma financial information of the combined company see “Information About the Merger and Dynegy – Unaudited Pro Forma Financial Information.”

1

Information About Dynegy

For information about Dynegy, including a description of its business, certain risk factors related to its business, its historical financial statements for the years ended December 31, 2017, 2016 and 2015, and its management’s discussion and analysis of its financial condition and results of operation, all of which come from Dynegy’s Annual Report on Form 10-K that was filed with the Securities and Exchange Commission on February 22, 2018, see “Information About the Merger and Dynegy.”

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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 February 28, 2018.

Issuer	Vistra Energy Corp.
Outstanding common stock that may be offered by the selling stockholders	Up to 168,779,076 shares
Common stock outstanding	428,454,256 shares
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	“VST”
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	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 (including, but not limited to, the Tax Matters Agreement (as defined herein)), our level of indebtedness and other restrictions with respect to the payment of dividends, 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 4.

3

Risk Factors

Investing in our securities involves a high degree of risk. You should carefully consider the risks described herein and in the documents incorporated by reference in this prospectus, as well as other information we include or incorporate by reference into this prospectus, before making an investment decision. In particular, you should consider the risk factors under the heading “Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2017, filed with the Securities and Exchange Commission (the “Commission”) on February 26, 2018 (the “Vistra 2017 Form 10-K”).

4

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 under Item 1A, Risk Factors and under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in each case, in the Vistra 2017 Form 10-K, which is incorporated herein by reference, and the following important factors, among others, that could cause our actual results to differ materially from those projected in or implied by such forward-looking statements:

• the actions and decisions of regulatory authorities;

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

• prevailing governmental policies and regulatory actions, including those of the Texas Legislature, the Governor of Texas, the United States Congress, the United States Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, the Texas Reliability Entity, Inc., the Public Utility Commission of Texas, the Railroad Commission of Texas, the United States Nuclear Regulatory Commission, the Environmental Protection Agency, the Texas Commission on Environmental Quality, the United States Mine Safety and Health Administration and the United States Commodity Futures Trading Commission, with respect to, among other things:

• allowed prices;

• industry, market and rate structure;

• purchased power and recovery of investments;

• operations of nuclear generation facilities;

• operations of fossil fueled generation facilities;

• operations of mines;

• acquisition and disposal of assets and facilities;

• development, construction and operation of facilities;

• decommissioning costs;

• present or prospective wholesale and retail competition;

• changes in tax laws and policies;

• changes in and compliance with environmental and safety laws and policies, including National Ambient Air Quality Standards, the Cross-State Air Pollution Rule, the Mercury and Air Toxics Standard, regional haze program implementation and greenhouse gas and other climate change initiatives, and

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

• legal and administrative proceedings and settlements;

• general industry trends;

• economic conditions, including the impact of an economic downturn;

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

• our ability to collect trade receivables from counterparties;

• our ability to attract and retain profitable customers;

• our ability to profitably serve our customers;

• restrictions on competitive retail pricing;

• changes in wholesale electricity prices or energy commodity prices, including the price of natural gas;

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

5

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

• changes in market heat rates in the Electric Reliability Council of Texas, Inc. (“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 US and international credit markets;

• access to capital, the attractiveness of the cost and other terms of such capital and the success of financing and refinancing efforts, including availability of funds in capital markets;

• our ability to maintain prudent financial leverage;

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

• competition for new energy development and other business opportunities;

• our ability to successfully complete our solar generation project in a timely and cost-efficient manner or at all;

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

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

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

• our ability to attract and retain qualified employees;

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

• changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits, pension and other post-employment benefits, and future funding requirements related thereto, including joint and several liability exposure under the Employee Retirement Income Security Act of 1974, as amended;

• 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 Receivables Agreement, dated as of the Effective Date, by and between the Company and American Stock Transfer & Trust Company, LLC, as Transfer Agent;

• expectations regarding the proposed merger (the “Merger”) of Dynegy, Inc. (“Dynegy”) with and into the Company pursuant to the terms and subject to the conditions of that certain Agreement and Plan of Merger, dated as of October 29, 2017, by and between the Company and Dynegy (the “Merger Agreement”), including beliefs concerning regulatory approvals;

• the occurrence of any event that could give rise to the termination of the Merger Agreement, including a termination of the Merger Agreement under circumstances that could require us to pay a termination fee;

• our ability to successfully integrate the businesses of Vistra Energy and Dynegy upon consummation of the Merger and our ability to successfully capture any projected synergies relating to the Merger; and

• actions by credit rating agencies.

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

6

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 Public Utility Commission of Texas and the New York Mercantile Exchange. 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.”

7

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.

8

Market Prices and Dividend Policy

Vistra Energy’s authorized capital stock consists of 1,800,000,000 shares of common stock with a par value of $0.01 per share.

Since May 10, 2017, Vistra Energy’s common stock has been listed on the NYSE under the symbol “VST”. Upon Emergence and through May 9, 2017, Vistra Energy’s common stock was listed on the OTCQX U.S. under the symbol “VSTE”.

As of February 28, 2018, there were 428,454,256 shares of common stock issued and outstanding and 111 shareholders of record.

The following table sets forth the per share high and low closing prices and per share cash dividends declared per common share for the periods presented.

	2017								2016
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter		Fourth Quarter
High price	$	20.49	$	18.70	$	16.86	$	17.95	$	16.40
Low price	$	17.24	$	15.88	$	14.59	$	15.36	$	13.60
Dividends per common share	$	—	$	—	$	—	$	—	$	2.32

Other than a one-time dividend in the aggregate amount of approximately $1 billion ($2.32 per share of common stock) to holders of record of our common stock on December 19, 2016, Vistra Energy has never paid a dividend on our common stock, and the board of directors of Vistra Energy (the “Board”) has no present intention to declare or pay dividends in the future. For additional details, see the section entitled “Risk Factors” and Note 14 to the Vistra Energy Consolidated Financial Statements, incorporated herein by reference to the Vistra 2017 Form 10-K.

Subject to limitations under applicable Delaware law, preferences that may apply to any outstanding shares of our preferred stock and contractual restrictions, holders of our common stock are entitled to receive dividends or other distributions ratably, when, as and if declared by the Board. The ability of the Board to declare dividends with respect to our common stock, however, will be subject to such limitations, preferences and restrictions and the availability of sufficient funds under the Delaware General Corporation Law to pay such dividends.

9

Management

Current Composition

The following table sets forth information regarding our current executive officers and directors as of the date hereof. Ages are as of April 3, 2018.

Name	Age	Position
Curtis A. Morgan	57	President, Chief Executive Officer and Director
Gavin R. Baiera	42	Director
Jennifer Box	36	Director
Brian K. Ferraioli	62	Director
Scott B. Helm	53	Director, Chairman of the Board
Jeff D. Hunter	52	Director
Cyrus Madon	52	Director
Geoffrey D. Strong	43	Director
James A. Burke	49	Executive Vice President and Chief Operating Officer
J. William Holden	57	Executive Vice President and Chief Financial Officer
Carrie Lee Kirby	50	Executive Vice President and Chief Administrative Officer
Stephanie Zapata Moore	44	Executive Vice President and General Counsel
Sara Graziano	35	Senior Vice President of Corporate Development and Strategy
Scott A. Hudson	54	Senior Vice President and President Retail
Stephen J. Muscato	47	Senior Vice President and Chief Commercial Officer

Executive Officers

The executive officers of the Company consist of the following executives:

Curtis A. Morgan, President, Chief Executive Officer and Director, has served as the President, Chief Executive Officer and Director of Vistra Energy since October 3, 2016. Prior to joining Vistra Energy, he served as an Operating Partner with Energy Capital Partners, and prior to this position Mr. Morgan served as the Chief Executive Officer and President of EquiPower Resources Corp., a power generation company, since May 2010. Prior to joining EquiPower Resources Corp., he served as an Operating Partner of Energy Capital Partners from May 2009 to May 2010. Prior to joining Energy Capital partners, he served as President and Chief Executive Officer of FirstLight Power Enterprises from November 2006 to April 2009. Mr. Morgan has also held various leadership roles at NRG Energy, Mirant Corporation, Reliant Energy and Amoco Corporation.

10

James A. “Jim” Burke, Executive Vice President and Chief Operating Officer, has served as the Executive Vice President and Chief Operating Officer of Vistra Energy since October 3, 2016. Prior to joining Vistra Energy, he served as Executive Vice President of EFH Corp. since February 2013 and President and Chief Executive of TXU Energy, a subsidiary of Vistra Energy, since August 2005. Previously, Mr. Burke was Senior Vice President Consumer Markets of TXU Energy. Mr. Burke started his career with Deloitte Consulting, and held a variety of roles with The Coca-Cola Company, Reliant Energy and Gexa Energy prior to TXU Energy. Mr. Burke also serves as the Chairman of the board of directors of Marucci Sports.

J. William “Bill” Holden, Executive Vice President and Chief Financial Officer, has served as the Executive Vice President and Chief Financial Officer of Vistra Energy since December 5, 2016. Prior to joining Vistra Energy, Mr. Holden served as an Executive Vice President and Senior Advisor at The Taffrail Group, LLC, an international strategic-advisory firm, from February 2013 until December 2016, where he advised a range of domestic and overseas clients on mergers, acquisitions and post-merger integration. From December 2010 until January 2013, Mr. Holden served as the Executive Vice President and Chief Financial Officer of GenOn Energy, Inc., where he was responsible for overseeing the accounting, finance, tax, risk control, human resources and information technology groups. Prior to serving in that role, he held various treasury, risk, operational, business development and international positions during his tenure at GenOn Energy, Inc./Mirant Corporation. Mr. Holden started his career with Southern Company and held various corporate finance roles over almost a decade at Southern.

Scott A. Hudson, Senior Vice President and President of TXU Energy, has served as Senior Vice President of Vistra Corporate Services Company since October 3, 2016, and President of TXU Energy since March 2017. Prior to joining Vistra Energy, he served as Chief Operating Officer of TXU Energy since 2011. Previously, Mr. Hudson held senior leadership positions with MBNA America, ChoicePoint and LexisNexis and practiced as a commercial lawyer with Troutman Sanders LLP.

Sara Graziano, Senior Vice President of Corporate Development and Strategy, has served as the Senior Vice President of Corporate Development of Vistra Energy since October 3, 2016. Prior to joining Vistra Energy in October 2016, Ms. Graziano was a Principal at Energy Capital Partners, a private equity firm focused on investing in North American energy infrastructure, with more than $13 billion in commitments and a track record of investments in the power generation space. She was involved in all areas of the firm’s investment activities, including fossil and renewable power generation, midstream oil and gas, and energy and industrial services. Prior to joining Energy Capital Partners, Ms. Graziano led the strategies and analysis group at FirstLight Power Enterprises, an Energy Capital portfolio company that owned and operated approximately 1,400 MW of primarily hydroelectric plants in New England. Her group was responsible for asset optimization, commodity trading and hedging strategies, and business development activities. Before joining FirstLight, Ms. Graziano spent four years at Charles River Associates, consulting for clients in the power and natural gas industries, with a particular focus on the development of proprietary tools for fundamental and statistical modeling of commodity prices and volatility for use in asset valuation and risk management. Ms. Graziano served on the Board of Directors of USD Partners LP from October 2014 – October 2016. Ms. Graziano received a bachelor of arts in Economics from Wellesley College and a master’s of business administration from Harvard Business School, where she was a Baker Scholar.

Carrie Lee Kirby, Executive Vice President and Chief Administrative Officer, has served as the Executive Vice President and Chief Administrative Officer of Vistra Energy since October 3, 2016. Prior to this, Ms. Kirby was the Executive Vice President of Human Resources for Vistra Energy’s predecessor, EFH Corp., leading the human resources functions across EFH corporate and its subsidiaries, Luminant and TXU Energy. She was previously Vice President of Human Resources at TXU Energy, where she was originally recruited in 2006 as a Human Resources Director to support the power generation business in its construction and expansion efforts. Prior to joining TXU Energy, Ms. Kirby was Director of Human Resources at Delinea Corporation, a software services company targeting the energy industry. Before that, she was Director of Human Resources for Netrake, a startup voice-over IP hardware development company. She began her career in the executive search business as a consultant for Ray & Berndtson, supporting the technology practice. In addition to her service at Vistra Energy, Ms. Kirby chairs the board of the Teaching Trust, an education policy and leadership development organization focused on developing urban school leaders. Ms. Kirby is also a member of the Patient Advocacy Committee for Presbyterian Hospital of Dallas and sits on the executive committee of the Women’s Business Council Southwest.

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Stephanie Zapata Moore, Executive Vice President and General Counsel, has served as the Executive Vice President and General Counsel of Vistra Energy since October 3, 2016. Prior to joining Vistra Energy, Ms. Moore served as Vice President and General Counsel of Luminant, since April 2012. Previously, Ms. Moore was Senior Counsel of Luminant from March 2007 to April 2012 and Counsel of a predecessor to Luminant from November 2005 to March 2007. Prior to joining Luminant, Ms. Moore was an associate at Gardere Wynne Sewell LLP where she engaged in a corporate practice.

Stephen J. “Steve” Muscato, Senior Vice President and Chief Commercial Officer, has served as Senior Vice President of Vistra Corporate Services Company since October 3, 2016, and Chief Commercial Officer since January 2018. Prior to joining Vistra Energy, he served as Senior Vice President and Chief Commercial Officer of Luminant since 2013. Previously, Mr. Muscato held other senior leadership positions with Luminant.

Directors

Listed below is biographical information for each person who is currently a member of the Board, except for Mr. Morgan, whose information is listed above.

Scott Helm, Chairman of the Board, has served as a director since July 2017 and as chairman of the Vistra Energy Board since October 2017. He is a private investor based out of Baltimore. Previously, Mr. Helm was a founding partner of Energy Capital Partners, a private equity firm focused on investing in North American energy infrastructure. Prior to joining Energy Capital Partners, he worked as a consultant to the private equity consortium leading the acquisition at Texas Genco. Before that, he served as executive vice president and chief financial officer at Orion Power Holdings, Inc., a publicly listed company that owned and operated power plants. Mr. Helm began his career at Goldman Sachs & Co., first working in the fixed income division then moving to the investment banking division. He received a bachelor’s degree in business administration from Washington University.

Gavin R. Baiera has served as a director since October 3, 2016. Mr. Baiera was a managing director at Angelo, Gordon & Co. (“Angelo”) where he was the global head of the firm’s corporate credit activities and portfolio manager for its distressed funds. Mr. Baiera was also a managing director and member of the firm’s executive committee. Prior to joining Angelo in 2008, Mr. Baiera was the co-head of the strategic finance group at Morgan Stanley, which was responsible for all origination, underwriting, and distribution of restructuring transactions. Prior to that, Mr. Baiera worked at General Electric Capital Corporation concentrating on underwriting and investing in restructuring transactions. Mr. Baiera began his career at GE Capital in its financial management program. Mr. Baiera has served on numerous boards of directors including, most recently, MACH Gen, Orbitz Worldwide, and Travelport Worldwide.

Jennifer Box has served as a director since October 3, 2016. Ms. Box is a managing director at Oaktree Capital Management where she is focused on investments in the shipping, power, energy, media and technology sectors. Prior to joining Oaktree in 2009, Ms. Box spent three and a half years as an investment analyst in the Distressed Debt Group at The Blackstone Group. Prior to Blackstone, she was an associate consultant at the Boston Consulting Group. Ms. Box graduated summa cum laude with a B.S. degree in economics and a minor in mathematics from Duke University, where she was elected to Phi Beta Kappa. She is a CFA charterholder.

Brian K. Ferraioli has served as a director since May 2017. He most recently served as executive vice president and chief financial officer of KBR, Inc., a global engineering, construction, and services company supporting the energy, petrochemicals, government services, and civil infrastructure sectors. Prior to KBR, Mr. Ferraioli was executive vice president and chief financial officer at The Shaw Group, Inc., an engineering, construction, and fabrication company serving the electric power generation and government services industries. Prior to that, Mr. Ferraioli worked 28 years in various finance and accounting functions with Foster Wheeler AG, a Swiss global conglomerate that provides design, engineering, construction, manufacturing, development, and plant operations. In addition to Vistra Energy, Mr. Ferraioli serves on the board of Babcock & Wilcox Enterprises and previously served on the boards of

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B&W’s predecessor company, Babcock & Wilcox, Inc., and Adolfson & Peterson, a private construction company. Mr. Ferraioli graduated with a bachelor’s degree in accounting from Seton Hall University and received a master of business administration from Columbia University. Mr. Ferraioli is also a National Association of Corporate Directors Governance Fellow.

Jeff D. Hunter has served as a director since October 3, 2016. Mr. Hunter is currently Senior Managing Director of Quinbrook Infrastructure Partners and a member of the Quinbrook Investment Committee, where he is responsible for deal origination and asset management in North America. Between 2013 and 2016, he was a managing partner of Power Capital Partners, an energy focused investment firm. Prior to this, he was executive vice president and chief financial officer of U.S. Power Generating Company. Mr. Hunter has also held leadership positions at PA Consulting Group and El Paso Merchant Energy and was a consultant for MRP Generating Company, LLC. Mr. Hunter currently serves as the non-executive director on the board of directors of Texas Transmission Holdings.

Cyrus Madon has served as a director since October 3, 2016. Mr. Madon is a senior managing partner and head of Brookfield’s private equity group and chief executive officer of Brookfield Business Partners. Mr. Madon joined Brookfield in 1998 as chief financial officer of Brookfield’s real estate brokerage business. During his tenure, he has held a number of senior roles across the organization, including head of Brookfield’s corporate lending business. Mr. Madon began his career at PricewaterhouseCoopers where he worked in corporate finance and recovery, both in Canada and the United Kingdom. Mr. Madon is on the board of the Junior Achievement of Canada Foundation.

Geoffrey D. Strong has served as a director since October 3, 2016. Mr. Strong is a Senior Partner of Apollo Management, where he focuses on investments in the energy sector for the firm’s private equity funds. Prior to Apollo, Mr. Strong was an investor in the private equity group at Blackstone, where he also focused primarily on the energy sector. Before joining Blackstone, Mr. Strong was a vice president of Morgan Stanley Capital Partners, the private equity business within Morgan Stanley. In addition to Vistra Energy, Mr. Strong serves on the boards of directors of Apex Energy, Caelus Energy, Chisolm Oil and Gas, Double Eagle Energy I, Double Eagle Energy II, and Double Eagle Energy III.

Board Composition and Director Independence

Our certificate of incorporation (our “Charter”) provides for three classes of directors, each of which is to be elected on a staggered basis for a term of three years. Our bylaws (our “Bylaws”) provide that the Board shall consist of such number of directors as is determined from time to time by the vote of a majority of the total number of directors then authorized. Please see “Description of Capital Stock — Anti-takeover Effects of Provisions In Our Charter and Bylaws” for a more detailed description of our Charter and Bylaws.

The three largest groups of stockholders of Vistra Energy Corp. are (1) affiliates of Apollo Management Holdings L.P. (collectively, the “Apollo Entities”), (2) affiliates of Brookfield Asset Management Private Institutional Capital Adviser (Canada), L.P. (collectively, the “Brookfield Entities”), and (3) affiliates of Oaktree Capital Management, L.P. (collectively, the “Oaktree Entities”, and, together with the Apollo Entities and the Brookfield Entities, the “Principal Stockholders”). Pursuant to our plan of reorganization, approved in connection with our emergence from bankruptcy on October 3, 2016, we entered into stockholder’s agreements (the “Stockholder’s Agreements”) with each of the Principal Stockholders. Pursuant to each Stockholder’s Agreement, subject to the proper exercise of fiduciary duties of the Board, each Principal Stockholder is entitled to designate one director for nomination for election to 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 that it owned on the date of its respective Stockholder’s Agreement. See “Certain Relationships and Related Party Transactions — Stockholder’s Agreements.” The initial designees of each of the Apollo Entities, Brookfield Entities and Oaktree Entities are Geoffrey Strong, Cyrus Madon and Jennifer Box, respectively.

The Board consists of a majority of directors who are not employees or officers of Vistra Energy and satisfy the independence requirements of the Commission and the NYSE. The following are the independent directors of the Board: Gavin R. Baiera, Jennifer Box, Brian K. Ferraioli, Scott B. Helm, Jeff D. Hunter, Cyrus Madon and Geoffrey Strong.

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Directors and Management Following Consummation of the Merger

The board of directors of the combined company will be expanded to consist of eleven members, including: (i) eight of the directors of Vistra Energy and (ii) three of the directors of Dynegy immediately prior to the Merger (provided such directors are willing to serve on the board of the combined company). The individuals listed on the table below will serve as the combined company’s directors and executive officers:

Name	Age	Position
Curtis A. Morgan	57	President, Chief Executive Officer and Director
Gavin R. Baiera	42	Director
Jennifer Box	36	Director
Brian K. Ferraioli	62	Director
Scott B. Helm	53	Director, Chairman of the Board
Jeff D. Hunter	52	Director
Cyrus Madon	52	Director
Geoffrey D. Strong	43	Director
Hilary E. Ackermann	62	Director
Paul M. Barbas	61	Director
John R. Sult	58	Director
James A. Burke	49	Executive Vice President and Chief Operating Officer
J. William Holden	57	Executive Vice President and Chief Financial Officer
Carrie Lee Kirby	50	Executive Vice President and Chief Administrative Officer
Stephanie Zapata Moore	44	Executive Vice President and General Counsel
Sara Graziano	35	Senior Vice President of Corporate Development and Strategy
Scott A. Hudson	54	Senior Vice President and President of Retail
Stephen J. Muscato	47	Senior Vice President and Chief Commercial Officer

Biographical Summaries of Additional Directors Following Consummation of the Merger

Listed below is biographical information for the three Dynegy directors who are expected to join the board of directors of the combined company upon consummation of the Merger. Biographical information for those directors of the combined company who are currently members of the Board is listed above.

Hilary E. Ackermann served as a director of Dynegy since October 1, 2012 and is anticipated to be appointed to the Vistra Energy Board at the consummation of the Merger. Ms. Ackermann was Chief Risk Officer with Goldman Sachs Bank USA from October 2008 to 2011. In this role, she managed Credit, Market and Operational Risk for Goldman Sach’s commercial bank; developed the bank’s risk management infrastructure including policies and procedures and processes; maintained ongoing relationship with bank regulators including New York Fed, NY State Banking Department and the FDIC; chaired Operational risk, Credit risk and Middle Market Loan Committees; served as Vice Chair of Bank Risk Committee; was a member of Community Investment, Business Standards and New Activities Committees; was a member of GS Group level Credit Policy and Capital Committees; and chaired GS Group level Operational Risk Committee. Ms. Ackermann served as Managing Director, Credit Department of Goldman, Sachs & Co. from January 2002 until October 2008, as VP, Credit Department from 1989 to 2001, and as an Associate in the Credit Department from 1985 to 1988. Prior to joining Goldman, Sachs, Ms. Ackermann served as Assistant Department Head of Swiss Bank Corporation from 1981 until 1985. Ms. Ackermann currently serves on the private board of directors of Credit Suisse Holdings (USA), Inc. and each of Hartford Series Fund, Inc., Hartford HLS Series Fund II, Inc., The Hartford Mutual Funds, Inc. and The Hartford Mutual Funds II, Inc. and previously served on the public board of directors of Apollo Investment Corporation.

Paul M. Barbas served as a director of Dynegy since October 1, 2012 and is anticipated to be appointed to the Vistra Energy Board at the consummation of the Merger. Mr. Barbas was President and Chief Executive Officer of DPL Inc. and its principal subsidiary, The Dayton Power and Light Company (DP&L), from October 2006 until December 2011. He also served on the board of directors of DPL Inc. and DP&L. He previously served as Executive

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Vice President and Chief Operating Officer of Chesapeake Utilities Corporation, a diversified utility company engaged in natural gas distribution, transmission and marketing, propane gas distribution and wholesale marketing and other related services from 2005 until October 2006, as Executive Vice President from 2004 until 2005, and as President of Chesapeake Service Company and Vice President of Chesapeake Utilities Corporation, from 2003 until 2004. From 2001 until 2003, he was Executive Vice President of Allegheny Power, responsible for the operational and strategic functions of a $2.7 billion company serving 1.6 million customers with 3,200 employees. He joined Allegheny Energy in 1999 as President of its Ventures unit. Mr. Barbas serves on the board of El Paso Electric Co. and also formerly served on the public board of Pepco Holdings, Inc.

John R. Sult served as a director of Dynegy since October 1, 2012 and is anticipated to be appointed to the Vistra Energy Board at the consummation of the Merger. Mr. Sult served as Executive Vice President and Chief Financial Officer of Marathon Oil Corporation from September 2013 to August 2016. He was Executive Vice President and Chief Financial Officer of El Paso Corporation from March 2010 until May 2012. He previously served as Senior Vice President and Chief Financial Officer from November 2009 until March 2010, and as Senior Vice President and Controller from November 2005 until November 2009. Mr. Sult served as Executive Vice President, Chief Financial Officer and director of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P., from July 2010 until May 2012, as Senior Vice President and Chief Financial Officer from November 2009 until July 2010, and as Senior Vice President, Chief Financial Officer and Controller from August 2007 until November 2009. Mr. Sult also served as Chief Accounting Officer of El Paso Corporation and as Senior Vice President, Chief Financial Officer and Controller of El Paso’s Pipeline Group from November 2005 to November 2009. Prior to joining El Paso, Mr. Sult served as Vice President and Controller of Halliburton Energy Services from August 2004 until October 2005. Prior to joining Halliburton, Mr. Sult managed an independent consulting practice that provided a broad range of finance and accounting advisory services and assistance to public companies in the energy industry. Prior to private practice, Mr. Sult was an audit partner with Arthur Andersen LLP. Mr. Sult currently serves on the board of directors and chair of the audit committee of Jagged Peak Energy, Inc.

Biographical Summaries of Executive Officers

Biographical information for the individuals that will serve as executive officers of the combined company is listed above.

Committees of the Board of Directors

The standing committees of the Board consist of an audit committee, a compensation committee and a nominating and corporate governance committee.

Audit Committee

The Audit Committee is a separately-designated standing audit committee as required by Commission regulations and NYSE rules. Messrs. Ferraioli, Helm and Hunter serve on the Audit Committee, and Mr. Ferraioli serves as the Chair of the Audit Committee. The Board has determined that Messrs. Ferraioli, Helm and Hunter are independent as such term is defined in the NYSE rules and as required by Rule 10A-3 of the Securities and Exchange Act of 1934 (the “Exchange Act”). The Board has determined that each member of the Audit Committee possesses the necessary level of financial literacy required to enable him to serve effectively as an Audit Committee member. The Board has also determined that Messrs. Ferraioli, Helm and Hunter qualify as Audit Committee Financial Experts. No Audit Committee member serves on more than three audit committees of public companies, including the Audit Committee. The Audit Committee oversees (i) the quality and integrity of the financial statements of the Company; (ii) the Company’s financial reporting processes and financial statement audits; (iii) the independent registered public accountant’s qualifications and independence; (iv) the performance of the Company’s internal audit function and independent registered public accountant; (v) the systems of disclosure controls and procedures; and (vi) the Company’s system of internal controls over financial reporting, accounting, legal compliance and ethics, including the effectiveness of disclosure controls and controls over processes that could have a significant impact on the Company’s financial statements. The Audit Committee held nine meetings in 2017.

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The Board has adopted a written charter for the Audit Committee that is available on our website.

Nominating and Governance Committee

Mr. Madon and Mr. Strong serve on the Nominating and Governance Committee. The Board has determined that Messrs. Madon and Strong are independent as such term is defined in the NYSE rules. The Nominating and Governance Committee (i) identifies individuals qualified to become directors and recommends to the Board the nominees to stand for election as directors; (ii) oversees, and assumes a leadership role in, the governance of the Company including recommending Corporate Governance Guidelines for the Board’s consideration; (iii) leads the Board in its annual evaluation of its performance; and (iv) recommends to the Board nominees for each committee of the Board. The Nominating and Governance Committee held six meetings in 2017.

The Board has adopted a written charter for the nominating and governance committee that is available on our website.

Compensation Committee

Mr. Baiera and Ms. Box serve on the compensation committee of the Board (the “Compensation Committee”), and Mr. Baiera serves as the Chair of the Compensation Committee. The Board has determined that each of Mr. Baiera and Ms. Box are independent as such term is defined in the NYSE rules. The Compensation Committee (i) reviews and approves corporate goals and objectives relevant to the compensation of the Chief Executive Officer (“CEO”), evaluates the CEO’s performance in light of those goals and objectives, and determines and recommends to the Board the CEO’s compensation based on this evaluation; (ii) oversees the evaluation of executive officers (and other senior officers and key employees) other than the CEO and reviews, determines and approves their compensation levels, (iii) oversees and makes recommendations to the Board with respect to the adoption, amendment or termination of incentive compensation, equity-based and other executive compensation and benefits plans, policies and practices; (iv) reviews and discusses with the Board executive management succession planning; (v) makes recommendations to the Board with respect to the compensation of the Company’s outside directors; and (vi) produces the Compensation Committee’s report on executive compensation as required by the SEC to be included in the Company’s annual proxy statement. The Compensation Committee held six meetings in 2017.

The Board has adopted a written charter for the Compensation Committee that is available on our website.

Compensation Committee Interlocks and Insider Participation

None of the Company’s directors who currently serve, or during the past year have served, as members of the Compensation Committee is, or has, at any time, been one of the Company’s officers or employees. None of the Company’s executive officers currently serves, or has served during the last completed fiscal year, as a member of the board of directors or compensation committee of any entity that has one or more executive officers serving as a member of the Board or the Company’s Compensation Committee.

Code of Conduct

The Board has adopted a code of conduct applicable to our directors, officers and employees, including our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and other senior officers, in accordance with applicable rules and regulations of the Commission and the NYSE. Our code of conduct is available on our website.

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Executive Compensation

Before making an investment decision, you should read the compensation discussion and analysis included in Exhibit 99.1 to the Current Report on Form 8-K filed by Vistra Energy with the Commission on February 28, 2018, which is incorporated herein by reference.

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Principal and Selling Stockholders

The following table contains information about the estimated beneficial ownership of our common stock for:

• each stockholder known by us to own beneficially 5% or more of our common stock;

• each of our directors;

• each of our Named Executive Officers;

• all directors and executive officers as a group; and

• each of the selling stockholders.

The number of shares and percentage of ownership indicated in the following table is based on the 428,398,802 shares of Vistra Energy Corp. common stock outstanding as of February 28, 2018. Unless set forth in this section or under “Certain Relationships and Related Party Transactions” in the prospectus included in the registration statement on Form S-1 (File No. 333-215288) filed by the Company with the Commission on May 1, 2017, to our knowledge, none of the selling stockholders have, or within the past three years have had, any material relationship with us or with any of our predecessors or affiliates.

Information with respect to beneficial ownership has been furnished by each director, officer, beneficial owner of more than 5% of our common stock and selling stockholder. Beneficial ownership is determined in accordance with the rules of the Commission. Except as indicated by footnote and subject to community property laws where applicable, to our knowledge, the persons named in the table below will have sole voting and investment power with respect to all shares of common stock shown as beneficially owned by them.

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			Maximum Number of Shares of Common Stock That May Be		Percentage of Shares of Common Stock Beneficially Owned
Name and Address	Number of Shares of Common Stock Beneficially Owned		Offered for Resale by this Prospectus		Before Any Offering			If Maximum Number of Shares Offered are Sold
5% Stockholders
Selling Stockholders
Apollo Funds(1)		52,876,115		52,876,115		12.34	%		0	%
Brookfield Asset Management Inc. Managed Entities(2)		66,370,568		66,370,568		15.49	%		0	%
Opps VIIb TCEH Holdings, LLC(3)		50,269,525		49,485,715		11.73	%		*
Seismic Holding LLC(4)		22,880,381		22,880,381		5.34	%		0	%
Non-Selling 5% Stockholders
The Vanguard Group, Inc.(5)		22,197,359		0		5.18	%		5.18	%
Directors and Executive Officers
Gavin R. Baiera(6)		0		0		0	%		0	%
Jennifer Box(7)		0		0		0	%		0	%
Brian K. Ferraioli		5,750		0		*			*
Scott B. Helm(8)		7,200		0		*			*
Jeff Hunter(9)		17,169		0		*			*
Cyrus Madon(10)		66,370,568		66,370,568		15.49	%		0	%
Curtis A. Morgan(11)		251,103		0		*			*
Geoffrey D. Strong(12)		0		0		0	%		0	%
James A. Burke(13)		136,723		0		*			*
Sara Graziano(14)		38,278		0		*			*
J. William Holden(15)		87,981		0		*			*
Scott A. Hudson(16)		31,899		0		*			*
Carrie Lee Kirby(17)		51,040		0		*			*
Stephanie Zapata Moore(18)		38,278		0		*			*
Stephen J. Muscato(19)		31,899		0		*			*
Christy Dobry (20)		5,756		0		*			*
All directors and current executive officers as a group (16 persons)		67,073,644		66,370,568		15.66	%		*

* Represents less than 1%

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(1) Represents shares of common stock held of record by various entities (collectively, the Apollo Funds) for which affiliates of Apollo Principal Holdings III, L.P. (Principal Holdings III), APH Holdings, L.P. (APH Holdings) and APH Holdings (DC), L.P. (APH Holdings (DC)), respectively, serve as investment advisors, and in some cases as general partners, of certain of the Apollo Funds. Apollo Principal Holdings III GP, Ltd. (Principal Holdings III GP) is the general partner of Principal Holdings III and APH Holdings, and Apollo Principal Holdings IV GP, Ltd. (Principal Holdings IV GP) is the general partner of APH Holdings (DC). Also includes shares of common stock held of record by certain of the Apollo Funds for which affiliates of Apollo Management Holdings, L.P. (Management Holdings) serve as investment managers or portfolio managers. The general partner of Management Holdings is Apollo Management Holdings GP, LLC (Management Holdings GP). Leon Black, Joshua Harris and Marc Rowan are the directors of Principal Holdings III GP and Principal Holdings IV GP, and the managers, as well as executive officers, of Management Holdings GP, and as such may be deemed to have voting and dispositive control over the shares of common stock held by the Apollo Funds. The address of each of APH Holdings, APH Holdings (DC) and Principal Holdings IV GP is One Manhattanville Road, Suite 201, Purchase, New York 10577. The address of each of Principal Holdings III and Principal Holdings III GP is c/o Walkers Corporate Limited, Cayman Corporate Centre, 27 Hospital Road, George Town, Grand Cayman KY1-9008, Cayman Islands. The address of each of Management Holdings and Management Holdings GP, and Messrs. Black, Harris and Rowan, is 9 West 57th Street, 43rd Floor, New York, New York 10019.

(2) Reflects shares of common stock held by entities affiliated with and/or with accounts managed by affiliates of Brookfield Asset Management Inc. The registered holders of shares include BCP Titan Aggregator, L.P., BCP Titan Sub Aggregator, L.P., Brookfield Titan Holdings LP, 11 co-investment limited partnership vehicles of which Titan Co-Investment GP, LLC is the general partner, Longhorn Capital GS LP and Seismic Holding LLC (collectively, the investment vehicles).

The following Brookfield entities, which do not themselves hold any shares of common stock but which are controlling entities of certain of the investment vehicles, may be deemed to constitute a “group” with the investment vehicles within the meaning of Section 13(d)(3) under the Exchange Act and Rule 13d-5(b)(1) thereunder and each member of the “group” may be deemed to beneficially own all shares of common stock held by all members of the “group” set forth in the table above: Brookfield Asset Management Inc., Partners Limited, Brookfield Private Equity Inc., Brookfield US Corporation, Brookfield Private Equity Holdings LLC, Brookfield Private Equity Direct Investments Holdings LP, Titan Co-Investment GP, LLC, Brookfield Private Equity Group Holdings LP, Brookfield Capital Partners Ltd., Brookfield Holdings Canada Inc., Brookfield Private Funds Holdings Inc., Brookfield Canada Adviser and Brookfield Asset Management Private Institutional Capital Adviser (Canada), L.P. (BAMPIC).

The total number of reported shares includes the shares beneficially owned by Seismic Holding LLC. By virtue of various agreements and arrangements with Seismic Holding LLC, Brookfield Asset Management Inc. and certain of the investment vehicles share beneficial ownership of shares beneficially owned by Seismic Holding LLC. See footnote (4) to this table.

Each of the investment vehicles expressly disclaims, to the extent permitted by applicable law, beneficial ownership of any shares of common stock held by each of the other investment vehicles and the existence of a “group” involving the other investment vehicles or other Brookfield affiliates set forth in this footnote.

The numbers above include certain shares held in reserve by Vistra Energy’s transfer agent upon Emergence, pending release following the resolution of intercreditor arrangements in connection with the Plan.

The address of each Brookfield-managed entity (other than Seismic Holding LLC) is c/o BAMPIC, 250 Vesey Street, 15th Floor, New York, New York 10281.

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(3) The managing member of Opps VIIb TCEH Holdings, LLC is OCM Opportunities Fund VIIb Delaware, L.P. The general partner of OCM Opportunities Fund VIIb Delaware, L.P. is Oaktree Fund GP, LLC. The managing member of Oaktree Fund GP, LLC is Oaktree Fund GP I, L.P. The general partner of Oaktree Fund GP I, L.P. is Oaktree Capital I, L.P. The general partner of Oaktree Capital I, L.P. is OCM Holdings I, LLC. The managing member of OCM Holdings I, LLC is Oaktree Holdings, LLC.

Includes 34,719,812 common shares of the Issuer directly held by certain funds, accounts and special purpose entities managed by Oaktree Capital Management, L.P. or its affiliates. The general partner of Oaktree Capital Management, L.P. is Oaktree Holdings, Inc. The sole shareholder of Oaktree Holdings, Inc. and the managing member of Oaktree Holdings, LLC is Oaktree Capital Group, LLC. The duly elected manager of Oaktree Capital Group, LLC is Oaktree Capital Group Holdings GP, LLC (OCGH GP). OCGH GP is managed by an executive committee consisting of Howard S. Marks, Bruce A. Karsh, Jay S. Wintrob, John B. Frank, David M. Kirchheimer and Sheldon M. Stone. The address for all of the entities and individuals identified above is 333 S. Grand Avenue, 28th Floor, Los Angeles, CA 90071.

(4) Seismic Holding LLC holds 15,900,080 shares (including 107,025 shares held in reserve by Vistra Energy’s transfer agent upon Emergence, pending release following the resolution of intercreditor arrangements in connection with the Plan).

In addition, Seismic Holding may be deemed to have beneficial ownership of all the shares held by entities affiliated with Brookfield Asset Management Inc. set forth in footnote (2) to this table, by virtue of various agreements and arrangements that may be deemed to grant Seismic Holding LLC voting power and/or investment power with respect to the shares held by such entities, including the shares held by Longhorn Capital GS LP, of which Seismic Holding LLC is a limited partner with powers that may be deemed to constitute voting power and/or investment power with respect to the shares held by the limited partnership.

The total number of reported shares is included in the total described in footnote (2) to this table.

Each of Seismic Holding LLC and its controlling persons expressly disclaims, to the extent permitted by applicable law, the existence of a “group” (within the meaning of Section 13(d)(3) under the Exchange Act and Rule 13d-5(b)(1) thereunder) involving such Brookfield entities and beneficial ownership of any shares of common stock held by any of the Brookfield entities (including Longhorn Capital GS LP), with the exception of the 6,980,301 shares held by Longhorn Capital GS LP in which Seismic Holding LLC has an interest. Seismic Holding LLC is 100% indirectly owned by Qatar Investment Authority. The address of Seismic Holding LLC is Ooredoo Tower, Diplomatic Area Street, West Bay, P.O. Box 23224, Doha, State of Qatar.

(5) Reflects shares of Vistra Energy Common Stock held as of December 31, 2017.

(6) The shares reported exclude 18,320,311 shares owned by funds and accounts managed by Angelo, Gordon & Co. that were previously disclosed and may have been deemed to be beneficially owned by Mr. Baiera as managing director thereof due to the fact that Mr. Baiera is no longer associated with Angelo, Gordon & Co.

(7) Excludes 49,485,715 shares held directly by Opps VIIb TCEH Holdings, LLC, an affiliate of Oaktree Capital Management, L.P.

(8) All of the shares reported are common shares owned directly by Mr. Helm.

(9) All of the shares reported are common shares owned directly by Mr. Hunter and 10,000 of these shares have been pledged as security.

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(10) All of the shares reported are beneficially owned by the Brookfield Asset Management Inc. Managed Entities as disclosed in footnote (2) to this table and may be deemed to be beneficially owned by Mr. Madon as the senior managing partner of Brookfield Asset Management Inc. To the extent Mr. Madon is deemed to be the beneficial owner of any such shares beneficially owned by the Brookfield Asset Management Inc. Managed Entities, Mr. Madon expressly disclaims beneficial ownership thereof.

(11) 119,525 of the shares reported are common shares owned directly by Mr. Morgan; and 131,578 of the shares are vested stock options.

(12) Mr. Strong is associated with Apollo Management, L.P. (Apollo Management) and its affiliate, Apollo Management Holdings, L.P. (Management Holdings). Affiliates of Apollo Management and Management Holdings directly or indirectly serve as investment managers, portfolio managers, investment advisors, and in some cases serve as general partners of, the Apollo Funds. As such, Management Holdings, Apollo Management and its affiliated investment managers or investment advisors may be deemed to beneficially own the shares of common stock held by certain of the Apollo Funds. Mr. Strong disclaims beneficial ownership of all of the shares of common stock that may be deemed to be beneficially owned by the Apollo Funds, Apollo Management, Management Holdings or any of their affiliated investment managers or advisors. The address of Mr. Strong is c/o Apollo Management, L.P., 9 West 57th Street, 43rd Floor, New York, New York 10019.

(13) 31,460 of the shares reported are common shares owned directly by Mr. Burke; and 105,263 of the shares are vested stock options.

(14) 6,700 of the shares reported are common shares owned directly by Ms. Graziano; and 31,578 of the shares are vested stock options.

(15) 17,598 of the shares reported are common shares owned directly by Mr. Holden; and 70,383 of the shares are vested stock options.

(16) 5,584 of the shares are common shares owned directly by Mr. Hudson; and 26,315 of the shares are vested stock options.

(17) 8,935 of the shares reported are common shares owned directly by Ms. Kirby; and 42,105 of the shares are vested stock options.

(18) 6,700 of the shares reported are common shares owned directly by Ms. Moore; and 31,578 of the shares are vested stock options.

(19) 5,584 of the shares are common shares owned directly by Mr. Muscato; and 26,315 of the shares are vested stock options.

(20) 1,756 of the shares reported are common shares owned directly by Ms. Dobry; and 4,000 of the shares are vested stock options.

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Certain Relationships and Related Party Transactions

In connection with the Third Amended Joint Plan of Reorganization of the Debtors (the “Plan”), confirmed in connection with our emergence from bankruptcy on October 3, 2016 (the “Effective Date”), we entered into agreements with certain of our affiliates and with parties who received shares of our common stock and certain rights (the “TRA Rights”) to receive payments from Vistra Energy of certain tax benefits, in each case, in exchange for their claims. We have filed copies of the agreements described in this section as exhibits to the registration statement of which this prospectus is a part. The actual terms of the agreements summarized below are more detailed than the general summary information provided below. Therefore, please carefully consider the actual provisions of these agreements in connection with your decision to invest in our common stock.

Registration Rights Agreement

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

The registration statement of which this prospectus forms a part was filed pursuant to the Registration Rights Agreement. Among other things, under the terms of the Registration Rights Agreement:

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

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

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

All expenses of registration under the Registration Rights Agreement, including the legal fees of one counsel retained by or on behalf of the selling stockholders, will be paid by us.

In addition to the foregoing rights regarding the registration of Vistra Energy Corp. common stock, the Registration Rights Agreement provides certain rights to the holders of the TRA Rights under the Tax Receivable Agreement described below regarding the registration of such TRA Rights. The TRA Rights are not being registered by the registration statement of which this prospectus forms a part, but the TRA Rights may be registered at the option of certain holders.

The registration rights granted in the Registration Rights Agreement are subject to customary restrictions such as minimums, blackout periods and, if a registration is underwritten, any limitations on the number of shares to be included in the underwritten offering imposed by the managing underwriter. The Registration Rights Agreement also contains customary indemnification and contribution provisions. The Registration Rights Agreement is governed by New York law.

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Further details concerning the terms of the Registration Rights Agreement may be obtained by reviewing the Registration Rights Agreement, which is filed as an exhibit to the registration statement of which this prospectus is a part.

Stockholder’s Agreements

Pursuant to the Plan, on the Effective Date, we entered into three separate Stockholder’s Agreements with affiliates of each of the Principal Stockholders. Pursuant to each Stockholder’s Agreement, subject to the proper exercise of fiduciary duties of the Board, the applicable stockholder will, until the occurrence of a Termination Event (as defined below), be entitled to designate one person for nomination for election to the Board as a Class III director at (a) any meeting of our stockholders at which Class III directors are elected or (b) if our Charter no longer provides for the division of directors into three classes, any meeting of our stockholders at which directors are to be elected. Prior to the occurrence of a Termination Event, if a vacancy occurs because of the death, disability, disqualification, resignation or removal of the director nominee of an applicable stockholder, subject to the proper exercise of the fiduciary duties of the Board, the applicable stockholder will be entitled to designate such person’s successor.

For purposes of this section, a Termination Event means that such stockholder, together with its affiliates and investment funds, funds or accounts that are advised, managed or controlled by such stockholder or its affiliates (other than the Company or any entity that is controlled by the Company), ceases to beneficially own, in the aggregate, for a period of 20 consecutive trading days, at least 22,500,000 shares of common stock of Vistra Energy Corp. that were owned by such stockholder on the date of the applicable Stockholder’s Agreement. The rights of each stockholder under its applicable Stockholder’s Agreement will terminate automatically upon a Termination Event.

Further details concerning the terms of the Stockholder’s Agreements may be obtained by reviewing the Stockholder’s Agreements, each of which is filed as an exhibit to the registration statement of which this prospectus is a part.

Tax Receivable Agreement

On the Effective Date, we entered into a tax receivable agreement (“Tax Receivable Agreement”) with a transfer agent on behalf of certain former first lien creditors of TCEH. The Tax Receivable Agreement generally provides for the payment by us to 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 realize in periods after Emergence as a result of (a) certain transactions consummated pursuant to the Plan (including any step-up in tax basis in our assets resulting from the contribution by a subsidiary of TEX Energy LLC of certain assets of Texas Competitive Electric Holdings Company LLC and its direct and indirect subsidiaries (“Predecessor”) to Vistra Preferred Inc. (“PrefCo”) in exchange for all of PrefCo’s authorized preferred stock (the “PrefCo Preferred Stock Sale”)), (b) the tax basis of all assets acquired in connection with the Lamar and Forney Acquisition in April 2016 and (c) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the Tax Receivable Agreement, plus interest accruing from the due date of the applicable tax return.

Pursuant to the Tax Receivable Agreement, we issued the TRA Rights to our Predecessor to be held in escrow for the benefit of the first lien secured creditors of our Predecessor entitled to receive such TRA Rights under the Plan. Such TRA Rights are subject to various transfer restrictions described in the Tax Receivable Agreement and are entitled to certain registration rights more fully described in the Registration Rights Agreement. The TRA Rights are not being registered by the registration statement of which this prospectus forms a part.

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Further details concerning the terms of the Tax Receivable Agreement may be obtained by reviewing the Tax Receivable Agreement, which is filed as an exhibit to the registration statement of which this prospectus is a part.

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.

The payments we will be required to make under the Tax Receivable Agreement could be substantial. Future transactions or events could change the timing and/or amount of the actual tax benefits realized and the corresponding Tax Receivable Agreement payments from these tax attributes.

In addition, 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.

In addition, 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. Vistra Energy’s future debt agreements may restrict the ability of its subsidiaries to make distributions to it, which could affect its ability to make payments under the Tax Receivable Agreement. To the extent that Vistra Energy Corp. is unable to make payments under the Tax Receivable Agreement because of restriction under its debt agreements, 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.

Finally, 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 holder 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 assumptions. As a result, upon such a breach or change of control, Vistra Energy Corp. could be required to make a lump-sum payment under the Tax Receivable Agreement that is greater than the specified percentage of its actual cash tax savings and could have a substantial negative impact on our liquidity.

Tax Matters Agreement

On the Effective Date, we entered into a Tax Matters Agreement (“Tax Matters Agreement”), with Energy Future Holdings Corp. (“EFH Corp.”), Energy Future Intermediate Holding Company LLC (“EFIH”), EFIH Finance Inc. and EFH Merger Co. LLC, whereby the parties have agreed to take certain actions and refrain from taking certain actions in order to preserve the intended tax treatment of the distribution of Vistra Energy’s common stock as part of a tax-free spin-off from EFH Corp. (the “Spin-Off’) and to indemnify the other parties to the extent a breach of such agreement results in additional taxes to the other parties.

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

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We are also required to indemnify EFH Corp. against taxes, under certain circumstance, if the Internal Revenue Service (the “IRS”) or another taxing authority successfully challenges the amount of gain relating to the PrefCo Preferred Stock Sale or the amount or allowance of EFH Corp.’s net operating loss deductions.

Subject to certain exceptions, the Tax Matters Agreement prohibits us from taking certain actions that could reasonably be expected to undermine the intended tax treatment of the Spin-Off or to jeopardize the conclusions of the private letter ruling we obtained from the IRS or opinions of counsel received by us or EFH Corp., in each case, in connection with the Spin-Off. Certain of these restrictions apply for two years after the Spin-Off.

Under the Tax Matters Agreement, we may engage in an otherwise restricted action 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.

Further details concerning the terms of the Tax Matters Agreement may be obtained by reviewing the Tax Matters Agreement, which is filed as an exhibit to the registration statement of which this prospectus is a part.

Separation Agreement

Pursuant to the Plan, on the Effective Date, EFH Corp., Vistra Energy Corp. and Vistra Operations Company LLC (“Vistra Operations”) entered into a Separation Agreement (the “Separation Agreement”). Under the key terms of the Separation Agreement, on the Effective Date, EFH Corp. and certain of its subsidiaries (including Energy Future Competitive Holdings Company LLC (“EFCH”) and our Predecessor) transferred to Vistra Energy Corp. certain assets and liabilities related to the operations of EFCH, our Predecessor and certain subsidiaries of our Predecessor, including certain employee benefit plans specifically identified in the Separation Agreement, which Vistra Energy Corp., in turn, transferred to Vistra Operations. Pursuant to the Separation Agreement, Vistra Operations accepted, assumed and agreed to faithfully perform, discharge and fulfill certain assumed liabilities. The Contribution was effected pursuant to the side-by-side operation of the Separation Agreement and the Plan. For additional information regarding the contribution, see “The Reorganization and Emergence.”

Further details concerning the terms of the Separation Agreement may be obtained by reviewing the Separation Agreement, which is filed as an exhibit to the registration statement of which this prospectus is a part.

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Split Participant Agreement

On the Effective Date, pursuant to the Plan, and following the effectiveness of the Separation Agreement, Vistra Operations and Oncor Electric Holdings Company LLC (“Oncor”) entered into an Amended and Restated Split Participant Agreement (the “Split Participant Agreement”). Pursuant to the Split Participant Agreement, among other things, Oncor agreed to provide certain post-retirement welfare and life insurance benefits, and Vistra Operations agreed to provide certain pension benefits (as identified on Schedules I, II and III, as applicable, to the Split Participant Agreement) to certain current and future retirees of EFH Corp., Vistra Operations and Oncor (or one of their direct or indirect subsidiaries) whose employment included service that has been allocated to both (a) Oncor (or one of its predecessor regulated electric transmission and distribution utility businesses) and (b) EFH Corp. (or one of its direct or indirect subsidiaries that is not a regulated electric transmission and distribution utility).

Further details concerning the terms of the Split Participant Agreement may be obtained by reviewing the Split Participant Agreement, which is filed as an exhibit to the registration statement of which this prospectus is a part.

Review and Approval of Related Party Transactions

The Audit Committee will review and approve transactions with our directors, officers, holders of more than 5% of our voting securities or affiliates of any of the foregoing. Prior to approving any transaction with any such related party, the Audit Committee will consider the material facts as to the related party’s relationship with us and interest in the transaction. Related party transactions will not be approved unless the Audit Committee or the disinterested members of the Board as a whole has approved the transaction. We did not have a formal review and approval policy for related party transactions at the time of any transaction described above.

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Description of Capital Stock

The following description of the material terms of the capital stock of Vistra Energy Corp. includes a summary of specified provisions included in the Charter and Bylaws. This description also summarizes relevant provisions of the Delaware General Corporation Law (“DGCL”). The terms of our Charter and Bylaws will be, and the terms of the DGCL are, more detailed than the general information provided below. Accordingly, the more general information provided below is subject to, and qualified in its entirety by reference to, the actual provisions of these documents and the DGCL.

Authorized Capital Stock

We have the authority to issue a total of 1,900,000,000 shares of capital stock, consisting of:

• 1,800,000,000 shares of our common stock, par value $.01 per share; and

• 100,000,000 shares of our preferred stock, par value $.01 per share.

Outstanding Capital Stock

As of February 28, 2018, 428,454,256 shares of our common stock were issued and outstanding and owned by 111 holders of record, and no shares of our preferred stock were issued and outstanding.

Options

The Board adopted the 2016 Omnibus Incentive Plan (the “2016 Incentive Plan”), effective as of the Effective Date, under which an aggregate of 22,500,000 shares of our common stock were reserved for issuance as equity based awards to our non-employee directors, employees and certain other persons. The types of awards that may be granted under the 2016 Incentive Plan include stock options, restricted stock units (“RSUs”), restricted stock, performance awards and other forms of awards granted or denominated in shares of our common stock, among others.

Pursuant to the 2016 Incentive Plan, in accordance with certain employment agreements with certain of our executive officers, we have issued to eight of our executive officers equity awards with an aggregate grant date fair value of $30,450,000, consisting of an aggregate of 761,355 RSUs, 297,747 performance share units and 2,394,717 employee stock options at a weighted average exercise price of $14.89 per share after adjusting the exercise price downward to account for the 2016 Special Dividend.

Rights and Preferences of Vistra Energy Corp. Capital Stock

Common Stock

Voting Rights

All shares of our common stock have identical rights and privileges. The holders of shares of our common stock are entitled to vote on all matters submitted to a vote of our stockholders, including the election of directors. On all matters to be voted on by holders of shares of our common stock, the holders will be entitled to one vote for each share of our common stock held of record, and will have no cumulative voting rights.

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Dividend Rights

Subject to limitations under applicable Delaware law, preferences that may apply to any outstanding shares of our preferred stock and contractual restrictions, holders of our common stock are entitled to receive dividends or other distributions ratably, when, as and if declared by the Board. The ability of the Board to declare dividends with respect to our common stock, however, will be subject such limitations, preferences and restrictions and the availability of sufficient funds under the DGCL to pay such dividends.

Rights upon Liquidation

In the event of a liquidation, dissolution or winding up of Vistra Energy Corp., after the payment in full of all amounts owed to our creditors and holders of any outstanding shares of our preferred stock, the remaining assets of Vistra Energy Corp. will be distributed ratably to the holders of shares of our common stock. The rights, preferences and privileges of holders of shares of our common stock are subject to, and may be adversely affected by, the rights of the holders of shares of any class or series of preferred stock which the Board may designate and issue in the future without stockholder approval.

Other Rights

Holders of shares of our common stock do not have pre-emptive, subscription, redemption or conversion rights.

Blank Check Preferred Stock

Subject to limitations under applicable Delaware law, the Board is authorized to issue, from time to time and without stockholder approval, up to an aggregate of 100,000,000 shares of preferred stock in one or more classes or series and to fix the designations, powers, preferences, and relative, participating, optional or other rights, if any, and the qualifications, limitations or restrictions, if any, of the shares of each such class or series, including the dividend rights, conversion rights, voting rights, redemption rights (including sinking fund provisions), liquidation preferences and the number of shares constituting any class or series. The issuance of preferred stock with voting and conversion rights would also adversely affect the voting power of the holders of shares of our common stock, including the potential loss of voting control to others.

Stockholder Meetings

Our Charter and Bylaws provide that annual stockholder meetings will be held at a date, time and place, if any, as exclusively selected by the Board. Our Charter and Bylaws provide that, except as otherwise required by applicable law or the terms of any class or series of preferred stock issued in the future, special meetings of the stockholders may be called by (a) the Board at any time or (b) by the Chairman of the Board or the Secretary of Vistra Energy Corp. upon the written request or requests of one or more stockholders of record holding a majority of the voting power of the then-outstanding shares of our capital stock entitled to vote on the matter or matters to be brought before the proposed special meeting and complying with the notice procedures set forth in our Bylaws. Unless otherwise provided by the terms of any class or series of preferred stock issued in the future, our stockholders have no authority to act by written consent. To the extent permitted under the DGCL, we may conduct stockholder meetings by remote communications.

Stockholder Right to Designate Directors

Pursuant to each Stockholder’s Agreement, subject to the proper exercise of fiduciary duties of the Board, the applicable stockholder will, until the occurrence of a Termination Event (as defined in “Certain Relationships and Related Party Transactions”), be entitled to designate one person for nomination for election to the Board as a Class III director at (i) any meeting of our stockholders at which Class III directors are elected or (ii) if our Charter no longer provides for the division of directors into three classes, any meeting of our stockholders at which directors are to be elected. Prior to the occurrence of a Termination Event, if a vacancy occurs because of the death, disability, disqualification, resignation or removal of the director nominee of an applicable stockholder, subject to the proper exercise of the fiduciary duties of the Board, the applicable stockholder will be entitled to designate such person’s successor.

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Anti-takeover Effects of Provisions In Our Charter and Bylaws

Our Charter and Bylaws contain a number of provisions which may have the effect of discouraging transactions that involve an actual or threatened change of control of Vistra Energy Corp. In addition, provisions of our Charter and Bylaws may be deemed to have anti-takeover effects and may delay, defer or prevent a tender offer or takeover attempt that a stockholder might consider in his, her or its best interest, including those attempts that might result in a premium over the market price of the shares of our common stock held by our stockholders.

Staggered Board

Our Charter provides for three classes of directors, each of which is to be elected on a staggered basis for a term of three years. Our Charter and Bylaws provide that the Board consists of such number of directors as is determined from time to time by the vote of a majority of the total number of directors then authorized. Please see “Management — Current Composition” for a more detailed description of the composition of our Board as of the date of this prospectus.

No Written Consent of Stockholders

Any action to be taken by our stockholders must be effected at a duly called annual or special meeting and may not be effected by written consent.

Special Meetings of Stockholders

Except as required by the DGCL or the terms of any class or series of preferred stock issued in the future, special meetings of our stockholders may be called only by (a) the Board at any time or (b) the Chairman of the Board or the Secretary of Vistra Energy Corp. upon written request of one or more stockholders of record holding a majority of the voting power of the then-outstanding shares of our capital stock entitled to vote on the matter or matters to be brought before the proposed special meeting and complying with the notice procedures set forth in our Bylaws.

Advance Notice Requirement

Stockholders must provide timely notice when seeking to:

• bring business before an annual meeting of stockholders;

• bring business before a special meeting of stockholders (if contemplated and permitted by the notice of a special meeting); or

• nominate candidates for election to the Board at an annual meeting of stockholders or at a special meeting of stockholders called for the purpose of electing one or more directors to the Board.

To be timely, a stockholders notice generally must be received by the Secretary of Vistra Energy Corp. at our principal executive offices:

• in the case of an annual meeting:

• not later than the close of business on the 90th day nor earlier than the close of business on the 120th day prior to the first anniversary of the date of the immediately preceding year’s annual meeting, or

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• if the annual meeting is called for a date that is more than 30 days before or more than 60 days after the first anniversary of the date of the preceding year’s annual meeting, or if no annual meeting was held in the preceding year, not earlier than the close of business on the 120th day prior to such annual meeting and not later than the close of business on the later of the 90th day prior to the annual meeting and the 10th day following the day on which the first public announcement of the date of the annual meeting is made by Vistra Energy Corp; or

• in the case of a special meeting, not earlier than the close of business on the 120th day and not later than the close of business on the later of the 90th day prior to the special meeting and the 10th day following the day on which public announcement is first made of the date of the special meeting and the nominees proposed by the Board.

Our Charter and Bylaws also specify requirements as to the form and content of the stockholder’s notice. These provisions may preclude stockholders from bringing matters before or proposing director nominees to an annual meeting or a special meeting of stockholders.

Issuance of Blank Check preferred stock

The Board is authorized to issue, without further action by the stockholders, up to 100,000,000 shares of preferred stock with rights and preferences designated from time to time by the Board as described above under “—Rights and Preferences of Vistra Energy Corp. Capital Stock — Blank Check Preferred Stock.” The existence of authorized but unissued shares of preferred stock may enable the Board to render more difficult or discourage an attempt to obtain control of Vistra Energy Corp. by means of a merger, tender offer, proxy contest or otherwise.

Removal of Directors

Our Charter and Bylaws provide that directors may only be removed for cause and only upon the affirmative vote of a majority of the voting power of the capital stock outstanding and entitled to vote thereon.

Section 203 of the DGCL

In our Charter, we have elected not to be governed by Section 203 of the DGCL, as permitted under and pursuant to subsection (b)(3) of Section 203. Section 203 prohibits a publicly held Delaware corporation from engaging in a business combination, such as a merger, with a person or group owning 15% or more of the corporation’s outstanding voting stock for a period of three years following the date the person became an interested stockholder, unless (with certain exceptions) the business combination or the transaction in which the person became an interested stockholder is approved in a prescribed manner. Accordingly, we are currently not subject to any anti-takeover effects of Section 203, although no assurance can be given that we will not elect to be governed by Section 203 of the DGCL in the future.

Amendment of Bylaws and Charter

The approval of a 66 2/3% super-majority of the voting power of the then outstanding shares of our capital stock entitled to vote will be required to amend certain provisions of our Bylaws or to amend certain provisions of our Charter, including provisions relating to indemnification and exculpation of directors and officers and provisions relating to amendment of our Bylaws and Charter by the Board. In addition, the Charter provides certain rights to the Principal Stockholders, relating to business opportunities, which are more fully described under “— Business Opportunities” below. Until the last to occur of (a) each Principal Stockholder and its respective Affiliates ceases to own at least 5% of our outstanding common stock or (b) no director is serving on the Board pursuant to the rights of the Principal Stockholders to nominate such directors in accordance with the Bylaws and each such Principal Stockholder’s Stockholder Agreement, the approval of an 80% super-majority of the voting power of the then outstanding shares of our capital stock entitled to vote will be required to amend the Charter in any manner inconsistent with these rights.

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Business Opportunities

Our Charter provides that each of Apollo Management Holdings L.P., Brookfield Asset Management Private Institutional Capital Adviser (Canada), L.P. and Oaktree Capital Management, L.P. and their respective affiliates, to the fullest extent permitted by law, have no duty to refrain from engaging in the same or similar business activities or lines of business in which Vistra Energy Corp. or any of our affiliates now engage or propose to engage or otherwise competing with Vistra Energy Corp. or any of our affiliates. To the fullest extent permitted by applicable law, we have renounced any interest or expectancy in, or the right to be offered an opportunity to participate in, any business opportunity which may be a business opportunity of one of such stockholders. We have not, however, renounced any interest in any business opportunity offered to any director or officer of Vistra Energy Corp. if such opportunity is expressly offered to such person solely in his or her capacity as a director or officer of Vistra Energy Corp.

Authorized but Unissued Shares

Delaware law does not require stockholder approval for any issuance of authorized shares. However, the listing requirements of the NYSE, which will apply so long as our common stock remains listed on the NYSE, require stockholder approval of certain issuances equal to or exceeding 20% of the then outstanding voting power or then outstanding number of shares of common stock. These additional shares may be utilized for a variety of corporate purposes, including future public or private offerings to raise additional capital and for corporate acquisitions.

Dissenters’ Rights of Appraisal and Payment

Under the DGCL, with certain exceptions, our stockholders have appraisal rights in connection with a merger or consolidation of Vistra Energy Corp. Pursuant to the DGCL, stockholders who properly request and perfect appraisal rights in connection with such merger or consolidation have the right to receive payment of the fair value of their shares as determined by the Delaware Court of Chancery.

Stockholders’ Derivative Actions

Under the DGCL, any of our stockholders may bring an action in our name to procure a judgment in our favor, also known as a derivative action, provided that the stockholder bringing the action is a holder of shares of our capital stock at the time of the transaction to which the action relates or such stockholder’s stock thereafter devolved by operation of law.

Exclusive Forum

Our Charter provides that unless Vistra Energy Corp. consents in writing to the selection of an alternative forum, to the fullest extent permitted by law, and subject to applicable jurisdictional requirements, any state court located in the State of Delaware (or, if no state court located within the State of Delaware has jurisdiction, the federal district court for the District of Delaware) is the sole and exclusive forum for any stockholder (including any beneficial owner) to bring any claim (a) based upon a violation of a duty by a current or former director, officer, employee or stockholder in such capacity or (b) as to which the DGCL confers jurisdiction on the Court of Chancery. Any person or entity purchasing or otherwise acquiring or holding any interest in shares of our capital stock shall be deemed to have notice of, and consented to the forum provisions in, our Charter. The enforceability of similar forum provisions in other companies’ certificates of incorporation, however, has been challenged in legal proceedings, and it is possible that a court could find these types of provisions to be inapplicable or unenforceable.

Limitations on Liability and Indemnification of Directors and Officers

The DGCL authorizes corporations to limit or eliminate the personal liability of our directors to corporations and their stockholders for monetary damages for breaches of directors’ fiduciary duties, subject to certain exceptions and conditions. Our Charter limits the liability of directors to the fullest extent permitted by the

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DGCL. Such section eliminates the personal liability of a director to Vistra Energy for monetary damages for breach of fiduciary duty as a director, except for liability (i) for any breach of the director’s duty of loyalty to Vistra energy or our stockholders, (ii) for acts or omission not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) under Section 174 of the DGCL, or (iv) for any transaction from which the director derived an improper personal benefit. In addition, our Bylaws and separate indemnification agreements provide that we must indemnify our directors and officers to the fullest extent permitted by the DGCL. Under our Bylaws, Vistra Energy Corp. agrees that it is the indemnitor of first resort to provide advancement of expenses or indemnification to directors and officers.

The limitation of liability and indemnification provisions included in our Charter and Bylaws and separate indemnification agreements may discourage stockholders from bringing a lawsuit against directors for breach of their fiduciary duty. These provisions may also have the effect of reducing the likelihood of derivative litigation against directors and officers, even though such an action, if successful, might otherwise benefit us and our stockholders. In addition, your investment may be adversely affected to the extent we pay the costs of settlement and damage awards against directors and officers pursuant to these indemnification provisions.

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is American Stock Transfer & Trust Company.

Listing

Our common stock is listed on the NYSE under the symbol “VST.”

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

The following is a general discussion of the material U.S. federal income tax consequences of the acquisition, ownership and disposition of our common stock purchased pursuant to this offering by a non-U.S. holder. For the purpose of this discussion, a non-U.S. holder is any beneficial owner of our common stock that is an individual, corporation, estate or trust and that is not for U.S. federal income tax purposes any of the following:

• an individual citizen or resident of the U.S.;

• a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in the U.S. or under the laws of the United States or any state or the District of Columbia;

• a partnership (or other entity or arrangement treated as a partnership or other pass-through entity for U.S. federal income tax purposes);

• an estate whose income is subject to U.S. federal income tax regardless of its source; or

• a trust (x) whose administration is subject to the primary supervision of a court within the United States and which has one or more U.S. persons (as defined for U.S. federal income tax purposes) who have the authority to control all substantial decisions of the trust or (y) which has made a valid election under applicable U.S. Treasury Regulations to be treated as a U.S. person.

An individual who is not a citizen of the United States may, subject to certain restrictions and limitations contained in any applicable income tax treaties, be deemed to be a resident of the United States by reason of being present in the United States for at least 31 days in the calendar year and an aggregate of at least 183 days during a three year period ending in the current calendar year (counting for such purposes all of the days present in the current year, one-third of the days present in the immediate preceding calendar year and one sixth of the days present in the second preceding calendar year). U.S. residents are generally taxed for U.S. federal income tax purposes in the same manner as U.S. citizens.

If a partnership (or an entity treated as a partnership for U.S. federal income tax purposes) holds our common stock, the tax treatment of a partner in the partnership will generally depend on the status of the partner and upon the activities of the partnership. Accordingly, if you are treated as a partner of a partnership that holds our common stock you should consult your own tax advisor as to the particular U.S. federal income tax consequences applicable to you.

This discussion assumes that a non-U.S. holder will hold our common stock that may be resold pursuant to this prospectus as a capital asset (generally, property held for investment) within the meaning of Section 1221 of the Code. This discussion does not address all aspects of U.S. federal taxation (including alternative minimum, gift and estate tax) or any other U.S. federal tax laws, including Medicare taxes imposed on net investment income or any aspects of state, local or non-U.S. taxation. It does not consider any U.S. federal income tax considerations that may be relevant to non-U.S. holders that may be subject to special treatment under U.S. federal income tax laws, including, without limitation, U.S. expatriates, life insurance companies, tax-exempt or governmental organizations, dealers in securities or currency, banks or other financial institutions, investors whose functional currency is other than the U.S. dollar, “passive foreign investment companies,” “controlled foreign corporations,” except as otherwise provided below, persons who at any time hold more than 5% of the fair market value of any class of our stock and investors that hold our common stock as part of a hedge, straddle or conversion transaction. Furthermore, the following discussion is based on current provisions of the Code, Treasury Regulations and administrative and judicial interpretations thereof, all as in effect on the date hereof, and all of which are subject to change, possibly with retroactive effect. We have not sought, and will not seek, any ruling from the IRS or any opinion of counsel with respect to the tax consequences discussed herein, and there can be no assurance that the IRS will not take a position contrary to the tax consequences discussed below or that any position taken by the IRS would not be sustained.

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We urge each prospective investor to consult a tax advisor regarding the U.S. federal, state, local and non-U.S. income and other tax consequences of acquiring, holding and disposing of shares of our common stock.

Distributions

We do not plan to make any distributions for the foreseeable future. However, if we do make distributions on our common stock, those payments will constitute dividends to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will first reduce a non-U.S. holder’s adjusted tax basis in the common stock (determined on a share by share basis), but not below zero, and then will be treated as gain from the sale of the common stock (subject to the rules discussed below under “— Gain on Disposition of Common Stock”). Any such distributions will also be subject to the discussion below under the section entitled “—Additional Withholding Tax Relating to Foreign Accounts.” We expect to have significant amounts of earnings and profits as of the date of this prospectus.

Any dividends (out of earnings and profits) paid to a non-U.S. holder of our common stock that are not effectively connected with a U.S. trade or business conducted by the non-U.S. holder generally will be subject to U.S. withholding tax either at a rate of 30% of the gross amount of the dividend or such lower rate as may be specified by an applicable tax treaty. Non-U.S. holders should consult their tax advisors regarding their entitlement to benefits under an applicable income tax treaty and the requirements for and manner of claiming the benefits of such treaty (including, without limitation, the need to obtain a U.S. taxpayer identification number). To receive the benefit of a reduced treaty rate, a non-U.S. holder must generally provide us or our paying agent with a valid IRS Form W-8BEN-E, W-8BEN or other appropriate version of IRS Form W-8 certifying qualification for the reduced rate and otherwise comply with all other applicable legal requirements (including periodically updating such forms).

Dividends received by a non-U.S. holder that are effectively connected with a U.S. trade or business conducted by the non-U.S. holder (and, if provided by an applicable treaty, that are attributable to a U.S. permanent establishment of such non-U.S. holder) are exempt from such U.S. withholding tax (provided that the non-U.S. holder complies with certain certification and disclosure requirements). Non-U.S. holders should consult their tax advisors regarding their entitlement to the exemption from withholding on dividends effectively connected with such holder’s U.S. trade or business and the requirements for and manner of claiming the benefits of such exemption. To obtain this exemption, the non-U.S. holder must generally provide us or our paying agent with a valid IRS Form W-8ECI properly certifying such exemption and otherwise comply with all other applicable legal requirements (including, without limitation, periodically updating such form). Such effectively connected dividends, although not subject to withholding tax, will be subject to U.S. federal income tax on a net income basis at the same graduated rates generally applicable to U.S. persons, subject to any applicable tax treaty providing otherwise. In addition to the income tax described above, dividends received by corporate non-U.S. holders that are effectively connected with a U.S. trade or business of the corporate non-U.S. holder may be subject to a branch profits tax at a rate of 30% (or such lower rate as may be specified by an applicable tax treaty).

A non-U.S. holder of our common stock may obtain a refund of any excess amounts withheld if the non-U.S. holder is eligible for a reduced rate of U.S. withholding tax and an appropriate claim for refund is timely filed with the IRS.

A non-U.S. holder that is a foreign trust is urged to consult its own tax advisor regarding its status under U.S. tax law and the certification requirements applicable to it.

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Gain on Disposition of Common Stock

Subject to the discussion of backup withholding and of FATCA, below, a non-U.S. holder generally will not be subject to U.S. federal income tax on any gain realized upon the sale or other disposition of our common stock unless:

• the gain is effectively connected with a U.S. trade or business of the non-U.S. holder and, if required by an applicable tax treaty, is attributable to a U.S. permanent establishment maintained by such non-U.S. holder;

• the non-U.S. holder is an individual who is present in the United States for a period or periods aggregating 183 days or more during the calendar year in which the sale or disposition occurs and certain other conditions are met; or

• our common stock constitutes a “U.S. real property interest” by reason of our status as a U.S. real property holding corporation (a “USRPHC”) within the meaning of Section 897(c)(2) of the Code at any time within the shorter of the five-year period preceding the disposition or the non-U.S. holder’s holding period for our common stock.

Unless an applicable tax treaty provides otherwise, gain described in the first bullet point above will be recognized in an amount equal to the excess of the amount of cash and the fair market value of any other property received for the common stock over the non-U.S. holder’s basis in the common stock. Such gain or loss will be generally subject to U.S. federal income tax on a net income basis at the same graduated rates generally applicable to U.S. persons. In the case of a non-U.S. holder that is a foreign corporation, such gain may also be subject to a branch profits tax at a rate of 30% (or such lower rate as may be specified by an applicable tax treaty).

Gain described in the second bullet point above (which may be offset by U.S. source capital losses, provided that the non-U.S. holder has timely filed U.S. federal income tax returns with respect to such losses) will be subject to a flat 30% U.S. federal income tax (or such lower rate as may be specified by an applicable tax treaty).

With respect to the third bullet point above, we believe we are not, and will not become for the foreseeable future, a USRPHC. If we are so classified, gain arising from the sale or other taxable disposition by a non-U.S. holder of our common stock will not be subject to tax if such class of stock is regularly traded on an established securities market, as defined by applicable Treasury Regulations, and such non-U.S. holder does not own, actually or constructively, more than 5% of such class of our stock at any time during the shorter of the five-year period ending on the date of the sale or exchange or the non-U.S. holder’s holding period for our common stock. We expect our common stock to be regularly traded on an established securities market. If gain on the sale or other taxable disposition of our stock were subject to taxation under the third bullet point above, the non-U.S. holder would be subject to regular U.S. federal income tax with respect to such gain in generally the same manner as a U.S. person and would have to file a U.S. income tax return reporting such gain or loss (and a purchaser of such non-U.S. holder’s stock may be required to withhold from the proceeds payable to a non-U.S. holder from a sale or other taxable disposition of our stock).

Non-U.S. holders should consult a tax advisor regarding potentially applicable income tax treaties that may provide for different rules.

Backup Withholding and Information Reporting

Generally, we must report annually to the IRS the amount of dividends paid to each non-U.S. holder, the name and address of the recipient, and the amount, if any, of tax withheld with respect to those dividends. These information reporting requirements apply even if withholding was not required or was otherwise reduced or eliminated. This information also may be made available under a specific treaty or agreement with the tax authorities of the country in which the non-U.S. holder resides or is established. Payment of the proceeds of a sale of our common stock within the United States or through certain U.S. financial intermediaries is also subject to information reporting, and depending on the circumstances may be subject to backup withholding unless the non-U.S. holder, certifies that it is a non-U.S. holder or furnishes an IRS Form W-8.

Payments of dividends to a non-U.S. holder may be subject to backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption, for example, by properly certifying its non-U.S. status on an IRS Form W-8BEN-E or another appropriate version of IRS Form W-8. Notwithstanding the foregoing, backup withholding may apply if either we or our paying agent has actual knowledge, or reason to know, that the beneficial owner is a U.S. person that is not an exempt recipient.

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U.S. information reporting and backup withholding generally will not apply to a payment of proceeds from a disposition of common stock where the transaction is effected outside the United States through a non-U.S. office of a non-U.S. broker. However, information reporting requirements, but generally not backup withholding, generally will apply to such a payment if the broker is (i) a U.S. person; (ii) a foreign person that derives 50% or more of its gross income for certain periods from the conduct of a trade or business in the United States; (iii) a controlled foreign corporation as defined in the Code; (iv) a foreign partnership with certain U.S. connections; or (v) a U.S. branch of a foreign bank or foreign insurance company or a “territory financial institution” (as specially defined) in each case meeting certain requirements, unless the broker has documentary evidence in its records that the holder is a non-U.S. holder and certain conditions are met or the holder otherwise establishes an exemption.

Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be claimed as a refund or a credit against a non-U.S. holder’s U.S. federal income tax liability, provided that the required information is timely furnished to the IRS. Non-U.S. holders should consult their own tax advisors regarding the application of backup withholding in their particular circumstances and the availability of, and procedures for, obtaining an exemption from backup withholding.

Additional Withholding Tax Relating to Foreign Accounts

Withholding taxes may be imposed under Sections 1471 to 1474 of the Code, the Treasury Regulations promulgated thereunder and other official guidance (commonly referred to as FATCA) on certain types of payments made to non-U.S. financial institutions and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on dividends on, or gross proceeds from the sale or other disposition of, our common stock paid to a “foreign financial institution” or a “non-financial foreign entity” (each as defined in the Code), unless those entities comply with certain requirements under the Code and applicable U.S. Treasury regulations, which requirements may be modified by an “intergovernmental agreement” entered into between the United States and an applicable foreign country. Future Treasury Regulations or other official guidance may modify these requirements.

Under the applicable Treasury Regulations, withholding under FATCA generally applies to payments of dividends on our common stock and the IRS has announced that withholding will apply to payments of gross proceeds from the sale or other disposition of such stock on or after January 1, 2019. The FATCA withholding tax will apply to all withholdable payments without regard to whether the beneficial owner of the payment would otherwise be entitled to an exemption from imposition of withholding tax pursuant to an applicable tax treaty with the United States or U.S. domestic law.

Prospective investors should consult their tax advisors regarding the potential application of withholding under FATCA to their investment in our common stock.

The foregoing discussion is only a summary of certain material U.S. federal income tax consequences of the acquisition, ownership and disposition of our common stock by non-U.S. holders. You are urged to consult your own tax advisor with respect to the particular tax consequences to you of the acquisition, ownership and disposition of our common stock, including the effect of any U.S., state, local, non-U.S. or other tax laws and any applicable income tax treaty.

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Shares Eligible for Future Sales

Future issuances or sales of substantial amounts of our common stock in the public market, or the perception that such issuances or resales may occur, could adversely affect the prevailing market price of our common stock. No prediction can be made as to the effect, if any, future issuances or resales of shares, or the availability of shares for future sales, will have on the market price of our common stock prevailing from time to time. See “Risk Factors” above.

As of February 28, 2018, we have a total of 428,454,256 shares of common stock issued and outstanding. The shares that may be resold pursuant to this prospectus will be freely tradable without restriction or further registration under the Securities Act, except that any shares held by our affiliates, as that term is defined under Rule 144 of the Securities Act, may be sold only in compliance with the limitations described below. The remaining outstanding shares from time to time will be deemed restricted securities under the meaning of Rule 144. Restricted securities may be sold in the public market only if registered or if they qualify for an exemption from registration, including the exemptions pursuant to Rule 144, which is summarized below.

On August 4, 2017, we filed a registration statement on Form S-8 (File No. 333-219687) under the Securities Act to register shares of our common stock or securities convertible into or exchangeable for shares of common stock issued pursuant to our 2016 Incentive Plan. Such Form S-8 registration statement automatically became effective upon filing. Accordingly, subject to applicable vesting restrictions or lock-up restrictions and except for shares held by affiliates, shares registered thereunder are available for sale in the open market.

Issuance and Resales of Securities

We relied on Section 1145(a)(1) and (2) to exempt from the registration requirements of the Securities Act any future offer and resale of our common stock issued pursuant to the Plan. Section 1145(a)(1) exempts the offer and sale of securities under the Plan from registration under Section 5 of the Securities Act and state laws if certain requirements are satisfied. The shares of our common stock issued pursuant to the Plan may be resold without registration unless the seller is an “underwriter” with respect to those shares. Section 1145(b)(1) defines an “underwriter” as any person who: purchases a claim against, an interest in, or a claim for an administrative expense against the debtor, if that purchase is with a view to distributing any security received in exchange for such a claim or interest; offers to sell securities offered under the Plan for the holders of those securities; offers to buy those securities from the holders of the securities, if the offer to buy is (i) with a view to distributing those securities; and (ii) under an agreement made in connection with the Plan, the completion of the Plan, or with the offer or sale of securities under the Plan; or is an “affiliate” of the issuer. To the extent a person is deemed to be an “underwriter,” resales by such person would not be exempted by Section 1145 from registration under the Securities Act or other applicable law. Those persons would, however, be permitted to resell shares of our common stock without registration if they are able to comply with the provisions of Rule 144, as described further below.

Rule 144

In general, under Rule 144, as currently in effect, a person who is not deemed to be our affiliate for purposes of Rule 144 or to have been one of our affiliates at any time during the three months preceding a resale and who has beneficially owned the shares of common stock proposed to be resold for at least six months, including the holding period of any prior owner other than our affiliates, is entitled to resell those shares of common stock without complying with the manner of sale, volume limitation or notice provisions of Rule 144, subject to compliance with the current public information requirements of Rule 144. If such a person has beneficially owned the shares of common stock proposed to be resold for at least one year, including the holding period of any prior owner other than our affiliates, then that person is entitled to resell those shares of common stock without complying with any of the requirements of Rule 144. In general, after acquiring beneficial ownership, under Rule 144, as currently in effect, our affiliates or persons reselling shares of our common stock on behalf of our affiliates are entitled to sell, within any three-month period, a number of shares of our common stock that does not exceed the greater of (a) 1% of the number of shares of our common stock then outstanding and (b) the average weekly trading volume of the shares of common stock during the four calendar weeks preceding the filing of a notice on Form 144 with respect to that resale. Resales under Rule 144 by our affiliates or persons reselling shares of our common stock on behalf of our affiliates are also subject to certain manner of sale provisions and notice requirements and to the availability of current public information about us.

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Plan of Distribution

We are registering the resale of shares of our common stock covered by this prospectus by the selling stockholders from time to time after the date of this prospectus. We will not receive any of the proceeds of any such resale of shares of our common stock. The aggregate proceeds to the selling stockholders from the resales of shares or our common stock will be the purchase price of the shares less any discounts and commissions.

The selling stockholders or their pledgees, donees, transferees, or any of their successors in interest selling shares received from a named selling stockholder as a gift, partnership distribution or other non-sale-related transfer after the date of this prospectus (some or all of whom may be selling stockholders), may sell some or all of the shares of common stock covered by this prospectus from time to time on any stock exchange or automated interdealer quotation system on which the securities are listed or quoted, in the over-the-counter market, in privately negotiated transactions or otherwise, at fixed prices that may be changed, at market prices prevailing at the time of sale, at prices related to prevailing market prices, at prices determined at the time of sale, or at prices otherwise negotiated. The selling stockholders may sell the shares by one or more of the following methods, without limitation:

• one or more underwritten offerings on a firm commitment or best efforts basis;

• block trades in which the broker or dealer so engaged will attempt to sell the shares as agent but may position and resell a portion of the block as principal to facilitate the transaction;

• crosses in which the same broker or dealer acts as an agent on both sides of the trades;

• purchases by a broker or dealer as principal and resale by the broker or dealer for its own account pursuant to this prospectus;

• an exchange distribution in accordance with the rules of any stock exchange on which the shares are listed;

• ordinary brokerage transactions and transactions in which the broker solicits purchases;

• privately negotiated transactions;

• short sales, either directly or with a broker-dealer or affiliate thereof;

• through the writing of options on the shares (including the issuance by the selling stockholder of derivative securities), whether or not the options are listed on an options exchange or otherwise;

• through loans or pledges of the shares to a broker-dealer or an affiliate thereof;

• by entering into transactions with third parties who may (or may cause others to) issue securities convertible or exchangeable into, or the return of which is derived in whole or in part from the value of, our common stock;

• through the distribution of the shares by any selling stockholder to its partners, members or stockholders;

• “at the market” to or through market makers or into an existing market for the securities;

• by pledge to secure debts and other obligations (including obligations associated with derivatives transactions);

• in other ways not involving market makers or established trading markets, including direct sales to purchasers or sales effected through agents;

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• any combination of any of these methods of sale; and

• any other method permitted pursuant to applicable law.

We do not know of any arrangements by the selling stockholders for the sale of any of these shares. Upon our notification by a selling stockholder that any material arrangement has been entered into with an underwriter or broker-dealer for the sale of shares through a block trade, special offering, exchange distribution, secondary distribution or a purchase by an underwriter, dealer or agent, we will file a supplement to this prospectus, if required, pursuant to Rule 424(b) under the Securities Act, disclosing certain material information, including the number of shares being offered, the name or names of any underwriters, dealers or agents, any public offering price, any underwriting discounts and other items constituting compensation to underwriters, dealers or agents.

For example, the selling stockholders may engage brokers and dealers, and any brokers or dealers may arrange for other brokers or dealers to participate in effecting sales of the shares. These brokers, dealers or underwriters may act as principals or as agents of a selling stockholder. Broker-dealers may agree with a selling stockholder to sell a specified number of the shares at a stipulated price per security. If the broker-dealer is unable to sell shares acting as agent for a selling stockholder, it may purchase as principal any unsold shares at the stipulated price. Broker-dealers who acquire shares as principals may thereafter resell the shares from time to time in transactions on any stock exchange or automated interdealer quotation system on which the shares are then listed, at prices and on terms then prevailing at the time of sale, at prices related to the then-current market price, at prices determined at the time of sale, or at prices otherwise negotiated. Broker-dealers may use block transactions and sales to and through broker-dealers, including crosses and other transactions of the nature described above.

From time to time, one or more of the selling stockholders may pledge, hypothecate or grant a security interest in some or all of the shares owned by them. The pledgees, secured parties or persons to whom the shares have been hypothecated will, upon foreclosure in the event of default, be deemed to be selling stockholders. As and when a selling stockholder takes such actions, the number of shares offered under this prospectus on behalf of such selling stockholder will decrease. The plan of distribution for such selling stockholder’s shares will otherwise remain unchanged.

A selling stockholder may, from time to time, sell the shares short, and, in those instances, this prospectus may be delivered in connection with the short sales and the shares offered under this prospectus may be used to cover short sales. A selling stockholder may enter into hedging transactions with broker-dealers and the broker-dealers may engage in short sales of the shares in the course of hedging the positions they assume with that selling stockholder, including, without limitation, in connection with distributions of the shares by those broker-dealers. A selling stockholder may enter into options or other transactions with broker-dealers that involve the delivery of the shares offered hereby to the broker-dealers, who may then resell or otherwise transfer those shares. A selling stockholder may also loan the shares offered hereby to a broker-dealer and the broker-dealer may sell the loaned shares pursuant to this prospectus.

A selling stockholder may enter into derivative transactions with third parties, or sell shares not covered by this prospectus to third parties in privately negotiated transactions. If the applicable prospectus supplement indicates, in connection with those derivatives, the third parties may sell shares covered by this prospectus and the applicable prospectus supplement, including in short sale transactions. If so, the third-party may use shares pledged by the selling stockholder or borrowed from the selling stockholder or others to settle those sales or to close out any related open borrowings of stock, and may use shares received from the selling stockholder in settlement of those derivatives to close out any related open borrowings of stock. The third-party in such sale transactions will be an underwriter and, if not identified in this prospectus, will be identified in the applicable prospectus supplement (or a post-effective amendment to the registration statement of which this prospectus forms a part).

To the extent required under the Securities Act, the names of the selling stockholders, aggregate amount of selling stockholders’ shares being offered and the terms of the offering, the names of any agents, dealers or underwriters and any applicable compensation with respect to a particular offer will be set forth in an accompanying prospectus supplement. Any underwriters, dealers or agents participating in the distribution of the shares may

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receive compensation in the form of underwriting discounts, concessions, commissions or fees from a selling stockholder and/or purchasers of selling stockholders’ shares for whom they may act (which compensation as to a particular broker-dealer might be in excess of customary commissions). Pursuant to a FINRA requirement, the maximum commission or discount to be received by any FINRA member or independent broker-dealer may not be greater than 8% of the gross proceeds received by the selling stockholders for the sale of any shares of common stock being offered by this prospectus and any applicable prospectus supplement.

The selling stockholders and any underwriters, dealers or agents that participate in the distribution of the shares may be deemed to be “underwriters” within the meaning of the Securities Act, and any discounts, concessions, commissions or fees received by them and any profit on the resale of the shares sold by them may be deemed to be underwriting discounts and commissions.

The selling stockholders and other persons participating in the sale or distribution of the shares will be subject to applicable provisions of the Exchange Act and the rules and regulations thereunder, including Regulation M. This regulation may limit the timing of purchases and sales of any of the shares by the selling stockholders any other person. The anti-manipulation rules under the Exchange Act may apply to sales of shares in the market and to the activities of the selling stockholders and their respective affiliates. Furthermore, Regulation M may restrict the ability of any person engaged in the distribution of the shares to engage in market-making activities with respect to the particular shares being distributed for a period of up to five business days before the distribution. These restrictions may affect the marketability of the shares and the ability of any person or entity to engage in market-making activities with respect to the shares.

The shares offered hereby were originally issued to the selling stockholders pursuant to an exemption from the registration requirements of the Securities Act. We agreed to register resales of such shares under the Securities Act and to keep the registration statement of which this prospectus is a part effective for a specified period of time. We have agreed to pay certain expenses in connection with certain resales of the shares registered pursuant to the registration statement of which this prospectus is a part, including the fees and expenses of one counsel retained by the selling stockholders. In addition, we have agreed to indemnify in certain circumstances certain of the selling stockholders against certain liabilities, including liabilities under the Securities Act. Certain of the selling stockholders have agreed to indemnify us in certain circumstances against certain liabilities, including liabilities under the Securities Act. We have also agreed to pay substantially all of the expenses incidental to the registration of resales of shares of our common stock, including the payment of federal securities law and state “blue sky” registration fees but excluding underwriting discounts and commissions relating to the sale of common stock. See “Certain Relationships and Related Party Transactions — Registration Rights Agreement.”

We will not receive any proceeds from resales of any shares of our common stock under this prospectus by the selling stockholders.

We cannot assure you that the selling stockholders will sell all or any portion of the shares offered hereby. Further, we cannot assure you that any such selling stockholder will not transfer, devise or gift the common stock by other means not described in this prospectus. In addition, any common stock covered by this prospectus that qualifies for sale under Rule 144 or Regulation D of the Securities Act may be sold under Rule 144 or Regulation D, as applicable, rather than under this prospectus. The common stock covered by this prospectus may also be sold to non-U.S. persons outside the United States in accordance with Regulation S under the Securities Act rather than under this prospectus. The common stock may be resold in some states only through registered or licensed brokers or dealers. In addition, in some states the common stock may not be resold unless it has been registered or qualified for resale or an exemption from registration or qualification is available and complied with.

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Incorporation by Reference of Certain Documents

The Commission allows us to “incorporate by reference” in this prospectus information that we file with it, which means that we are disclosing important business and financial information to you by referring you to those documents. The information incorporated by reference is considered to be part of this prospectus. This prospectus incorporates by reference the documents filed by Vistra Energy listed below:

• Vistra Energy’s Annual Report on Form 10-K for the year ended December 31, 2017 filed with the Commission on February 26, 2018; and

• Vistra Energy’s Current Reports on Form 8-K filed with the Commission on January 29, 2018, February 22, 2018, February 28, 2018 and March  2, 2018.

Legal Matters

The validity of the shares of common stock offered by this prospectus will be passed upon for us by Sidley Austin LLP, Dallas, Texas.

Experts

The consolidated financial statements of (a) Vistra Energy Corp. and its subsidiaries as of December 31, 2017 and 2016 and for the year ended December 31, 2017 and for the period October 3, 2016 through December 31, 2016, and (b) its Predecessor Company for the period January 1, 2016 through October 2, 2016 and for the year ended December 31, 2015, and the related financial statement schedule incorporated in this Prospectus by reference from the Company’s Annual Report on Form 10-K for the year ended December 31, 2017, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report (which report expresses an unqualified opinion and includes an explanatory paragraph regarding emergence from bankruptcy and the non-comparability of Vistra Energy Corp. and its subsidiaries to its Predecessor Company), which is incorporated herein by reference. Such consolidated financial statements and financial statement schedule have been so incorporated in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The consolidated financial statements of Dynegy Inc. at December 31, 2017 and 2016, and for each of the three years in the period ended December 31, 2017, and the effectiveness of Dynegy’s internal control over financial reporting as of December 31, 2017 appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their reports thereon appearing elsewhere herein, and are included in reliance upon such reports given on the authority of such firm as experts in accounting and auditing.

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Where You Can Find More Information

We have filed with the Commission a registration statement on Form S-1 under the Securities Act with respect to resales of the shares of our common stock offered by this prospectus. This prospectus, which is a part of the registration statement, does not contain all of the information set forth in the registration statement or the exhibits and schedules filed therewith. For further information with respect to us and the common stock that may be offered under this prospectus, please see the registration statement and the exhibits and schedules filed with the registration statement. Statements contained in this prospectus regarding the contents of any contract or any other document that is filed as an exhibit to the registration statement are not necessarily complete, and each such statement is subject to, and qualified in all respects by reference to, the full text of such contract or other document filed as an exhibit to the registration statement. A copy of the registration statement and the exhibits and schedules filed with the registration statement may be inspected without charge at the public reference room maintained by the Commission, located at 100 F Street, N.E., Washington, D.C. 20549, and copies of all or any part of the registration statement may be obtained upon the payment of the fees prescribed by the Commission. Please call the Commission at 1-800-SEC-0330 for further information about the public reference room. The Commission also maintains an Internet website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the Commission. The address of the website is www.sec.gov.

We are subject to the information and periodic reporting requirements of the Securities Exchange Act of 1934, as amended, and, in accordance therewith, we file periodic reports, proxy statements and other information with the Commission.

We maintain a website at www.vistraenergy.com. You may access our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act with the Commission free of charge at our website as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Commission. However, the reference to our web address does not constitute incorporation by reference of the information contained at such site.

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Information About The Merger and Dynegy

The following is a summary of the material facts about the Merger and Dynegy. This summary does not purport to be complete and may not contain all of the information about the Merger that is important to you. This summary is qualified in its entirety by the Merger Agreement, which is filed as Exhibit 2.2 hereto. For a more complete understanding of the Merger, you are urged to read the Merger Agreement, the Vistra 2017 Form 10-K (which is incorporated by reference herein) and the registration statement on Form S-4 (Registration No. 333-222049) filed with the SEC by Vistra Energy Corp. on January 23, 2018 (the “Merger Form S-4”), carefully and in their entirety.

General

On October 29, 2017, the Company and Dynegy entered into the Merger Agreement. Upon the terms and subject to the conditions set forth in the Merger Agreement, which has been approved by the board of directors of Vistra Energy (the “Vistra Energy Board”) and the board of directors of Dynegy, Dynegy will merge with and into the Company, with the Company continuing as the surviving corporation. The Merger is intended to qualify as a tax-free reorganization under the Internal Revenue Code of 1986, as amended (the “Code”), so that none of the Company, Dynegy or any of the Dynegy stockholders generally will recognize any gain or loss in the transaction, except that Dynegy stockholders will recognize gain with respect to cash received in lieu of fractional shares of the Company’s common stock. We expect that the Company will be the acquirer for both federal tax and accounting purposes.

Upon the closing of the Merger, each issued and outstanding share of Dynegy common stock, par value $0.01 per share, other than shares owned by the Company or its subsidiaries, held in treasury by Dynegy or held by a subsidiary of Dynegy, will automatically be converted into the right to receive 0.652 shares of common stock, par value $0.01 per share, of the Company (the “Exchange Ratio”), except that cash will be paid in lieu of fractional shares, which we expect will result in Company stockholders and Dynegy stockholders owning approximately 79% and 21%, respectively, of the combined company. Dynegy stock options and equity-based awards outstanding immediately prior to the effective time of the Merger will generally automatically convert upon completion of the Merger into stock options and equity-based awards, respectively, with respect to the Company’s common stock, after giving effect to the Exchange Ratio.

The Merger Agreement also provides that, upon the closing of the Merger, the board of directors of the combined company will be comprised of 11 members, consisting of (a) the eight current directors of the Company and (b) three of Dynegy’s current directors, of whom one will be a Class I director, one will be a Class II director and one will be a Class III director, unless the closing of the Merger occurs after the date of the Company’s 2018 Annual Meeting of Stockholders, in which case, one will be a Class I director and two will be Class II directors. The members of the board of directors and certain executives of the combined company are identified, and certain biographical information is provided with respect to such individuals, below under “—Information about the Company Following the Merger—Directors and Management Following the Merger.” In particular, upon completion of the Merger, each of Curtis A. Morgan, currently a director and the President and Chief Executive Officer of the Company, Jim Burke, currently Chief Operating Officer of the Company, and J. William Holden, currently Chief Financial Officer of the Company, will continue in those roles at the combined company.

Completion of the Merger is subject to various customary conditions, including, among others, (a) receipt of all requisite regulatory approvals, which includes approvals of the Federal Energy Regulatory Commission, the Public Utility Commission of Texas and the New York Public Service Commission, and the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the “HSR Act”), and (b) effectiveness of the registration statement for the shares of the Company’s common stock to be issued in the Merger, and the approval of the listing of such shares on the New York Stock Exchange. Each party’s obligation to consummate the Merger is also subject to certain additional customary conditions, including (i) subject to certain exceptions, the accuracy of the representations and warranties of the other party, (ii) performance in all material respects by the other party of its obligations under the Merger Agreement and (iii) the receipt by such party of an opinion from its counsel to the effect that the Merger will qualify as a tax-free reorganization within the meaning of the Code.

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The Merger Agreement contains certain termination rights for both the Company and Dynegy, including in specified circumstances in connection with an alternative acquisition proposal that has been determined to be a superior offer. Upon termination of the Merger Agreement, under specified circumstances (a) for a failure by the Company to obtain certain requisite regulatory approvals, the Company may be required to pay Dynegy a termination fee of $100 million, (b) in connection with a superior offer, acquisition proposal or unforeseeable material intervening event, the Company may be required to pay a termination fee to Dynegy of $100 million, and (c) in connection with a superior offer, acquisition proposal or an unforeseeable material intervening event, Dynegy may be required to pay to the Company a termination fee of $87 million. In addition, if the Merger Agreement is terminated (i) because the Company’s stockholders do not approve the issuance of the Company’s common stock in the Merger or do not adopt the Merger Agreement, then the Company will be obligated to reimburse Dynegy for its reasonable out-of-pocket fees and expenses incurred in connection with the Merger Agreement, or (ii) because Dynegy’s stockholders do not adopt the Merger Agreement, then Dynegy will reimburse the Company for its reasonable out-of-pocket fees and expenses incurred in connection with the Merger Agreement, each of which is subject to a cap of $22 million. Such expense reimbursement may be deducted from the abovementioned termination fees, if ultimately payable.

Specifically, the following events relating to conditions necessary for the completion of the Merger have already occurred as of the date of this prospectus: (a) the waiting period under the HSR Act has expired, (b) the Merger Form S-4, which relates to the shares of the Company’s common stock to be issued in the Merger, has been declared effective by the Commission and (c) the stockholders of each of the Company and Dynegy have approved the Merger. The Company expects that the Merger will close in the second quarter of 2018.

Unaudited Pro Forma Condensed Combined Consolidated Financial Information

The following unaudited pro forma condensed combined consolidated financial information is presented to illustrate the estimated effects of the pending business combination of Vistra Energy and Dynegy based on the historical financial position and results of operations of Vistra Energy and Dynegy. In the Merger, each issued and outstanding share of Dynegy common stock, other than shares held by Vistra Energy or any of its subsidiaries, held in treasury by Dynegy or held by a subsidiary of Dynegy will automatically be converted into the right to receive 0.652 shares of Vistra Energy common stock.

The following unaudited pro forma condensed combined consolidated balance sheet as of December 31, 2017 and the unaudited pro forma condensed combined consolidated statement of income (loss) for the year ended December 31, 2017 (collectively the “Unaudited Pro Forma Condensed Combined Consolidated Financial Statements”) are based on the historical financial statements of Vistra Energy (included in the Vistra 2017 Form 10-K, which is incorporated herein by reference) for the year ended December 31, 2017 and the pro forma financial statements of Dynegy for the year ended December 31, 2017, after giving effect to the Merger and the assumptions and adjustments described in the accompanying notes to these Unaudited Pro Forma Condensed Combined Consolidated Financial Statements.

The Unaudited Pro Forma Condensed Combined Consolidated Statement of Income (Loss) (the pro forma statement of income (loss)) for the year ended December 31, 2017 gives effect to the Merger as if it were completed on January 1, 2017. As such, the impact from Merger-related expenses is not included in the accompanying pro forma statement of income (loss). The Unaudited Pro Forma Condensed Combined Consolidated Balance Sheet (the pro forma balance sheet) gives effect to the Merger as if it were completed on December 31, 2017. Therefore, the impact of estimated future Merger-related expenses is reflected in the pro forma balance sheet as an increase to other current liabilities and a decrease to retained earnings.

The pro forma financial statements do not reflect any cost savings (or associated costs to achieve such savings) or margin enhancements from operating efficiencies, synergies or other restructuring that could result from the Merger. Further, the pro forma financial statements do not reflect the effect of any regulatory actions that may impact the pro forma financial statements when the Merger is completed. Transactions between Vistra Energy and Dynegy during the periods presented in the pro forma financial statements have been eliminated as if Vistra Energy and Dynegy were consolidated affiliates during the periods presented.

45

The Merger will be accounted for under the acquisition method of accounting for business combinations pursuant to the provisions of Accounting Standards Codification (ASC) 805, Business Combinations. Because current shareholders of Vistra Energy will own 79% of the shares of Vistra Energy common stock on a fully diluted basis immediately following the closing of the Merger and the directors and management of Vistra Energy will retain a majority of the board, Vistra Energy is considered to be the acquiring company for accounting purposes. The purchase price will ultimately be determined on the acquisition date based upon the fair value of the shares of Vistra Energy common stock issued in the Merger. The purchase price for the purposes of these pro forma financial statements is based on the closing price of Vistra Energy common stock on March 5, 2018 of $19.91 and the exchange of Dynegy’s outstanding shares of common stock for the right to receive 0.652 of a share of Vistra Energy common stock.

Assumptions and estimates underlying the pro forma adjustments are described in the accompanying notes, which should be read in connection with the Unaudited Pro Forma Condensed Combined Consolidated Financial Statements. Since the Unaudited Pro Forma Condensed Combined Consolidated Financial Statements have been prepared based on preliminary estimates, the final amounts recorded at the date of the Merger may differ materially from the information presented. These estimates are subject to change pending further review of the assets acquired and liabilities assumed and the final purchase price. Additionally, further changes to values of assets and liabilities will likely occur between the date of these pro forma financial statements and the date on which the Merger is consummated due to changes in valuation inputs including forecasted market prices of electricity, natural gas, coal, capacity revenues, interest rates, changes to expected operating plans for certain assets, changes to regulatory requirements and other factors.

The Unaudited Pro Forma Condensed Combined Consolidated Financial Statements have been presented for illustrative purposes only and are not necessarily indicative of results of operations and financial position that would have been achieved had the pro forma events taken place on the dates indicated, or the future consolidated results of operations or financial position of the combined company.

The Unaudited Pro Forma Condensed Combined Consolidated Financial Statements should be read in conjunction with:

• the accompanying notes to the Unaudited Pro Forma Condensed Combined Consolidated Financial Statements;

• the historical audited consolidated financial statements and related notes of Vistra Energy as of and for the year ended December 31, 2017, which are included in the Vistra 2017 Form 10-K, which is incorporated by reference herein;

• the historical audited consolidated financial statements and related notes of Dynegy as of and for the year ended December 31, 2017, which are included herein beginning on page F-1 below;

• the Merger Form S-4; and

• other information contained in or incorporated by reference into this document.

46

VISTRA ENERGY

UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED STATEMENT OF INCOME (LOSS)

For the Year Ended December 31, 2017

	Historical Vistra Energy			Historical Dynegy, As Adjusted (A)			Pro Forma Adjustments			Pro Forma Combined
	(in millions, except per share amounts)
Operating revenues	$	5,430		$	4,842		$	241	(B)(C)(D)(E)	$	10,513
Fuel, purchased power and delivery fees		(2,935	)		(2,932	)		(213	)(C)(E)		(6,080	)
Operating costs		(973	)		(995	)		(12	)(D)(F)		(1,980	)
Depreciation and amortization		(699	)		(811	)		(11	)(G)		(1,521	)
Impairments		(25	)		(148	)		—	(H)		(173	)
Gain (loss) on sale of assets, net		—			(122	)		—	(H)		(122	)
Selling, general and administrative expenses		(600	)		(246	)		26	(I)		(820	)
Operating income (loss)		198			(412	)		31			(183	)
Other income and deductions, net		32			75			—	(H)		107
Reorganization items		—			494			—	(H)		494
Interest expense and related charges		(193	)		(695	)		80	(J)		(808	)
Impacts of Tax Receivable Agreement		213			—			29	(K)		242
Income (loss) before income taxes		250			(538	)		140			(148	)
Income tax (expense) benefit		(504	)		610			(593	)(L)		(487	)
Net income (loss)		(254	)		72			(453	)		(635	)
Less: Net loss attributable to noncontrolling interest		—			(4	)		—			(4	)
Net income (loss) attributable to Vistra Energy		(254	)		76			(453	)		(631	)
Less: Dividends on preferred stock		—			18			—			18
Net income (loss) attributable to common stockholders	$	(254	)	$	58		$	(453	)	$	(649	)
Weighted average shares of common stock outstanding:
Basic		428			155			(46	)(M)		537
Diluted		428			162			(53	)(M)		537
Net income (loss) per weighted average share of common stock outstanding:
Basic	$	(0.59	)	$	0.37					$	(1.21	)
Diluted	$	(0.59	)	$	0.36					$	(1.21	)

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VISTRA ENERGY AND DYNEGY

UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED BALANCE SHEET

As of December 31, 2017

	Historical Vistra Energy		Historical Dynegy, As Adjusted (N)			Pro Forma Adjustments			Pro Forma Combined
	(in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	1,487	$	365		$	—		$	1,852
Restricted cash		59		—			—			59
Trade accounts receivable — net		582		513			—			1,095
Inventories		253		431			(54	)(O)		630
Commodity and other derivative contractual assets		190		32			121	(P)		343
Prepaid expense and other current assets		102		144			47	(P)		293
Total current assets		2,673		1,485			114			4,272
Restricted cash		500		—			—			500
Investments		1,240		123			—			1,363
Property, plant and equipment — net		4,820		8,884			353	(Q)(R)		14,057
Goodwill		1,907		772			18	(S)		2,697
Identifiable intangible assets — net		2,530		78			107	(Q)(T)		2,715
Commodity and other derivative contractual assets		58		26			11	(P)		95
Accumulated deferred income taxes		710		(7	)		495	(U)		1,198
Other noncurrent assets		162		403			—			565
Total assets	$	14,600	$	11,764		$	1,098		$	27,462
LIABILITIES AND EQUITY
Current liabilities:
Long-term debt due currently	$	44	$	105		$	(4	)(V)	$	145
Trade accounts payable		473		367			—			840
Commodity and other derivative contractual liabilities		224		229			124	(P)		577
Accrued taxes		194		64			—			258
Accrued interest		16		115			—			131
Asset retirement obligations		99		46			9	(W)		154
Other current liabilities		301		109			55	(X)		465
Total current liabilities		1,351		1,035			184			2,570
Long-term debt, less amounts due currently		4,379		8,328			500	(V)		13,207
Commodity and other derivative contractual liabilities		102		31			6	(P)		139
Tax Receivable Agreement obligation		333		—			(29	)(Y)		304
Asset retirement obligations		1,837		283			30	(W)		2,150

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VISTRA ENERGY AND DYNEGY

UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED BALANCE SHEET

As of December 31, 2017

	Historical Vistra Energy			Historical Dynegy, As Adjusted (N)			Pro Forma Adjustments			Pro Forma Combined
	(in millions)
Other noncurrent liabilities and deferred credits		256			194			65	(T)		515
Total liabilities		8,258			9,871			756			18,885
Equity:
Common stock		4			1			—	(Z)		5
Additional paid-in-capital		7,765			3,719			(1,433	)(Z)		10,051
Retained deficit		(1,410	)		(1,851	)		1,807	(Z)		(1,454	)
Accumulated other comprehensive income (loss)		(17	)		32			(32	)(Z)		(17	)
		6,342			1,901			342			8,585
Noncontrolling interest		—			(8	)		—			(8	)
Total equity		6,342			1,893			342			8,577
Total liabilities and equity	$	14,600		$	11,764		$	1,098		$	27,462

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

A. Financial information presented in the “Historical Dynegy, As Adjusted” column in the “Unaudited Pro Forma Condensed Combined Consolidated Statements of Income (Loss)” represents the historical consolidated statements of operations of Dynegy for the year ended December 31, 2017. Such financial information has been reclassified to conform to the historical presentation in Vistra Energy’s consolidated statement of income (loss) as set forth below. Unless otherwise indicated, defined line items included in the footnotes have the meanings given to them in the historical financial statements of Dynegy.

Year Ended December 31, 2017
	Before Reclassification			Reclassification Amount			After Reclassification
	(in millions)
Reclassification and classification of the unaudited pro forma condensed combined consolidated statements of income:
Acquisition and integration costs		(57	)		57	(a)		—
Selling, general and administrative expenses		(189	)		(57	)(a)		(246	)
Earnings from unconsolidated investment		8			(8	)(b)		—
Other income and deductions, net		67			8	(b)		75
Loss on early extinguishment of debt		(79	)		79	(c)		—
Interest expense		(616	)		(79	)(c)		(695	)

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(a) Represents reclassification of $(57) million from acquisition and integration costs to selling, general and administrative expenses.

(b) Represents reclassification of $8 million from earnings from unconsolidated investments to other income and deductions, net.

(c) Represents reclassification of $(79) million from loss on early extinguishment of debt to interest expense.

B. During the year ended December 31, 2017, $4 million of transactions between the entities were recorded as operating revenue by Dynegy and as a contra-revenue in operating revenue by Vistra Energy. As the amount is recorded within operating revenue for both entities, the transaction eliminates upon combination and no further adjustment is required.

C. Reflects adjustments for differences in accounting policy to:

a. Reclassify gains and losses from commodity derivative instruments, which increases revenue and expense by $99 million for the year ended December 31, 2017;

b. Reclassify transmission and distribution delivery fees to conform with Vistra Energy’s historical presentation, which increases revenue and expense by $89 million for the year ended December 31, 2017;

c. Reclassify capacity costs to conform to Vistra Energy’s historical presentation, which increases revenue and expense by $31 million for the year ended December 31, 2017;

d. Adjustment related to commodity derivative transactions to conform to Vistra Energy’s accounting policies, which increases revenue and expense by $9 million and $2 million, respectively, for the year ended December 31, 2017.

In the historical and pro forma Dynegy consolidated statements of income these amounts were presented net in operating revenues, whereas Vistra Energy presents similar amounts as fuel, purchased power costs and delivery fees.

D. Reflects an adjustment for differences in accounting policy to reclassify commission or broker fees for retail customer acquisitions. In the historical Dynegy consolidated statement of income these amounts were presented net in operating revenues, whereas Vistra Energy presents similar amounts as operating costs. The adjustment increases operating revenue and operating costs by $23 million for the year ended December 31, 2017.

E. Reflects an adjustment to decrease revenue and expense by $10 million and $8 million, respectively, for the year ended December 31, 2017 related to the amortization of acquired intangible contract assets and liabilities.

F. Reflects an adjustment to conform accounting policies of Dynegy to Vistra Energy related to recognition method for major maintenance expenses for power generation assets. Adjustment requires a decrease to operating costs of $11 million for the year ended December 31, 2017.

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G. Reflects an adjustment to increase depreciation expense by $11 million for the year ended December 31, 2017 due to the fair value measurement of long-lived assets performed in connection with the Merger. The remaining depreciable lives of the acquired long-lived assets range from 1 to 30 years.

H. In accordance with the requirements for reporting on combined pro forma financial information, Vistra Energy did not remove certain material, nonrecurring items from Dynegy’s as adjusted pro forma consolidated statements of income. These items include:

a. Impairment charges of $148 million on certain power generation assets and equity method investments for the year ended December 31, 2017;

b. Gain of $494 million for the year ended December 31, 2017 of reorganization items related to the Genco Chapter 11 bankruptcy and emergence;

c. Loss on the sale of assets of $122 million for the year ended December 31, 2017 primarily due to the sale of the Lee, Dighton, and Milford, MA facilities;

d. Loss on the extinguishment of debt of $79 million for the year ended December 31, 2017. This amount was reclassified to interest expense to conform to Vistra Energy’s financial statement presentation.

I. Reflects an adjustment to remove $17 million of costs incurred by Dynegy and $9 million of costs incurred by Vistra Energy related to the Merger for the year ended December 31, 2017.

J. Historical interest expense for Dynegy was reduced $80 million for the year ended December 31, 2017 due to the removal of historical interest expense and recalculation of interest expense after the acquired debt was recorded at fair value as a result of allocating the purchase price of the acquisition. For purposes of estimating the pro forma interest expense related to the (1) Tranche C-1 Term Loan and the (2) Revolving Facility, Vistra Energy used interest rates of 4.29% and 3.57%, respectively, per annum for its variable interest rates. The Tranche C-1 Term Loan interest rate is based on LIBOR plus a 275 basis point fixed margin. The Revolving Facilities’ rate is based on LIBOR plus a 250 basis point leveraged margin.

K. Reflects adjustments to the accretion expense related to the Tax Receivable Agreement obligation by including Dynegy’s tax attributes and forecasted taxable income of the combined entity, which results in changes to the forecasted payments under the Tax Receivable Agreement obligation. The adjusted accretion expense was based off of the change in estimate as of December 31, 2017 (see Note Y below). The adjustment resulted in an increase of $29 million to impacts of Tax Receivable Agreement for the year ended December 31, 2017.

L. Reflects the tax impact of the pro forma adjustments. Previously, Dynegy had not recognized a benefit for current period losses in its historical financial statements due to its recognition of a valuation allowance against its deferred tax assets. As more fully described in Note U below, on a pro forma combined basis the valuation allowance has been significantly reduced and now only relates to a portion of the historical NOL carryforward. Therefore, income tax expense is reflected on the pro forma pre-tax loss for the year ended December 31, 2017. 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 primarily to the reduction of deferred tax assets related to the tax rate reduction in the TCJA, offset by nondeductible Tax Receivable Agreement accretion and state income tax expense, reflective of the change in the timing and amount of the Tax Receivable Agreement payments due under the Tax Receivables Agreement after contemplating the effects of the Merger.

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M. Reflects an adjustment for the replacement of the common stock, restricted stock units (“RSUs”), performance-based restricted stock units (“PSUs”), stock options, Warrants and Tangible Equity Units of Dynegy with shares of common stock, RSUs, PSUs, stock options, Warrants and Tangible Equity Units of Vistra Energy to complete the Merger, at the Exchange Ratio of 0.652 shares of Vistra Energy per share of Dynegy.

	Historical Dynegy		Vistra Shares Issued
	(in millions)
Basic shares:
Common shares outstanding		144.4		94.1
Tangible Equity Units		23.1		15.1
Total basic shares outstanding		167.5		109.2
Dilutive shares:
Stock Options		—		—
Restricted Stock Units		1.0		0.7
Performance Share Units		0.9		0.6
Tangible Equity Units		5.4		3.5
Total dilutive shares		7.3		4.8
Total diluted shares outstanding		174.8		114.0

N. Financial information presented in the “Historical Dynegy, As Adjusted” column in the unaudited pro forma condensed combined consolidated balance sheet represents the historical consolidated balance sheet of Dynegy as of December 31, 2017. Such financial information has been reclassified or classified to conform to the historical presentation in Vistra Energy’s consolidated financial statements as set forth below. Unless otherwise indicated, defined line items included in the footnotes have the meanings given to them in the historical financial statements of Dynegy.

As of December 31, 2017
	Before Reclassification		Reclassification Amount			After Reclassification
	(in millions)
Reclassification and classification of the unaudited pro forma condensed combined consolidated balance sheet:
Inventories	$	445	$	(14	)(a)	$	431
Intangible assets — current		25		(25	)(a)		—
Identifiable intangible assets — net		39		39	(a)		78
Accrued liabilities and other current liabilities		109		(109	)(b)		—
Other current liabilities		—		109	(b)		109
Intangible liabilities — current		14		(14	)(c)		—
Intangible liabilities — noncurrent		34		(34	)(c)		—
Other noncurrent liabilities and deferred credits		146		48	(c)		194
Deferred income taxes		7		(7	)(d)		—
Accumulated deferred income taxes		—		(7	)(d)		(7	)

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(a) Represents reclassification of $14 million and $25 million from inventories and intangible assets — current, respectively, to identifiable intangible assets — net.

(b) Represents reclassification of $109 million from accrued liabilities and other current liabilities to other current liabilities.

(c) Represents reclassification of $14 million and $34 million from intangible liabilities — current and intangible liabilities— noncurrent, respectively, to other noncurrent liabilities and deferred credits.

(d) Represents reclassification of $7 million from deferred income tax liability to net accumulated deferred income tax assets.

O. Reflects an adjustment of $54 million to measure inventory at fair value as part of the allocation of the purchase price.

P. Reflects increases to Dynegy’s consolidated balance sheet presentation of derivative assets and liabilities, current and noncurrent and prepaid expense, respectively, as a result of conforming the consolidated balance sheet presentation for derivative assets and liabilities. The adjustment converts these derivative assets and liabilities from a net presentation currently elected by Dynegy, to a gross basis elected by Vistra Energy, as well as adjusts for differences in accounting policy related to derivatives, for a net balance sheet impact of $49 million for the year ended December 31, 2017.

	Historical Net			Adjustments		Total
	(in millions)
Assets:
Commodity and other derivative contractual assets — current	$	32		$	121	$	153
Other current assets (a)		144			47		191
Commodity and other derivative contractual assets — noncurrent		26			11		37
Total assets		202			179		381
Liabilities:
Commodity and other derivative contractual liabilities — current		229			124		353
Commodity and other derivative contractual liabilities — noncurrent		31			6		37
Total liabilities	$	260		$	130	$	390
Total net assets	$	(58	)	$	49	$	(9	)

(a) Of the other current assets, $45 million represents margin deposits related to commodity contracts.

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Q. Reflects an adjustment to align accounting policies between Dynegy and Vistra Energy which results in the reclassification of $17 million of software and other intangibles from Property Plant and Equipment, net to Identifiable Intangible Assets, net for the year ended December 31, 2017.

R. Reflects an increase of $370 million to record Dynegy’s property, plant and equipment, at their respective estimated fair values. The fair value of Dynegy’s property, plant and equipment related to its power generation assets was estimated using a discounted cash flow method which was based on a number of factors including forecasted power prices, fuel prices, capacity revenues, operating parameters, operating and maintenance costs and other variables. The cash flows for each respective generation asset were discounted using rates between 7% and 9%, depending on the related technology and market that each respective asset operates in. Under this method, fair value of Dynegy’s property, plant and equipment is estimated to be approximately $9.2 billion. The estimate is preliminary, subject to change and could vary materially from the actual adjustment.

S. Estimated equity consideration

Upon the closing of the Merger, each issued and outstanding share of Dynegy common stock, par value $0.01 per share, other than shares held in treasury by Dynegy or held by a subsidiary of Dynegy, will automatically be converted into the right to receive 0.652 shares of common stock, par value $0.01 per share, of Vistra Energy (the “Exchange Ratio”), except that cash will be paid in lieu of fractional shares, which Vistra Energy expects will result in Vistra Energy’s stockholders and Dynegy’s stockholders owning approximately 79% and 21%, respectively, of the combined company. Dynegy Warrants, stock options, equity-based awards and Tangible Equity Units outstanding immediately prior to the Effective Time will generally automatically convert upon completion of the Merger into stock options, equity-based awards (RSUs, PSUs) and Tangible Equity Units, respectively, with respect to Vistra Energy’s common stock, after giving effect to the Exchange Ratio. The estimated preliminary equity consideration, which represents a portion of the consideration deemed transferred to the Dynegy stockholders in the Merger, is calculated based on the number of shares of the combined company that Dynegy stockholders will own as of the closing of the Merger.

The fair value of the purchase consideration expected to be transferred on the closing date includes the value of the estimated equity consideration (including the value attributable to the consideration transferred of replacement RSUs, PSUs, stock options, Warrants and Tangible Equity Units). The fair value per share of Vistra Energy common stock was assumed for pro forma purposes to be $19.91 per share, which was the closing price of Vistra Energy’s common stock on March 5, 2018, and may change significantly between these pro forma financial statements and the closing of the Merger. The accompanying unaudited pro forma condensed combined consolidated financial statements reflect an estimated preliminary purchase price of approximately $2.3 billion.

Calculation of Preliminary Purchase Price

Dynegy shares outstanding as of March 5, 2018 (in millions)		173
Exchange Ratio		0.652
Vistra Energy shares to be issued for Dynegy shares outstanding (in millions)		113
Closing price of Vistra Energy common stock on March 5, 2018	$	19.91
Purchase price for common stock (in millions)	$	2,246
Fair value of outstanding stock compensation awards attributable to pre-combination service (in millions)	$	39
Fair value of outstanding Warrants (in millions)	$	2
Total estimated purchase price (in millions)	$	2,287

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Preliminary Purchase Price Allocation

Under the acquisition method of accounting, the identifiable assets acquired and liabilities assumed of Dynegy, the accounting acquiree, are recorded at fair value on the Merger date and added to those of Vistra Energy, the accounting acquirer. The pro forma adjustments included herein are preliminary and based on estimates of the fair value and useful lives of the assets acquired and liabilities assumed and have been prepared to illustrate the estimated effect of the Merger between Vistra Energy and Dynegy. The final purchase price allocation is dependent upon certain valuation and other studies that have not yet been completed. The final determination of the purchase price allocation, upon the consummation of the Merger, will be based on the net assets acquired as of that date and will depend on a number of factors, which cannot be predicted with any certainty at this time. The purchase price allocation may change materially based on the receipt of more detailed information. Accordingly, the pro forma purchase price allocation is preliminary and is subject to further adjustment as additional information becomes available and as additional analyses and final valuations are completed. There can be no assurance that these additional analyses and final valuations will not result in significant changes to the estimates of fair value set forth below.

The following table provides a summary of the preliminary allocation of the estimated purchase price to the identifiable tangible and intangible assets acquired and liabilities assumed of Dynegy, based on Dynegy’s consolidated balance sheet as of December 31, 2017, with all excess value over consideration paid recorded as goodwill.

Preliminary Purchase Price Allocation

	(in millions)
Current assets (excluding risk management)	$	1,446
Property, plant and equipment		9,237
Goodwill		790
Deferred tax asset		488
Investments		123
Intangible assets		185
Other long-term assets, excluding goodwill		403
Commodity and other derivatives, net		(200	)
Current liabilities (excluding long-term debt due currently and risk management)		(710	)
Intangible liabilities		(113	)
Long-term debt, including amounts due currently		(8,929	)
Other long-term liabilities		(441	)
Noncontrolling interests		8
Total estimated purchase price		2,287

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T. Reflects adjustments to recognize or adjust intangible assets and liabilities as detailed below:

As of December 31, 2017
	Net Carrying Amount			Pro Forma Adjustment			Adjusted Balance
	(in millions)
Intangible assets:
Electricity contracts	$	47		$	32		$	79
Trade names		—			35			35
Fuel and transportation contracts		17			23			40
Emissions allowance		14			—			14
Computer software and other intangibles		17			—			17
Total intangible assets	$	95		$	90		$	185
Intangible liabilities:
Electricity contracts	$	(4	)	$	—		$	(4	)
Fuel and transportation contracts		(44	)		(65	)		(109	)
Total intangible liabilities	$	(48	)	$	(65	)	$	(113	)

U. Reflects an adjustment for the combined deferred tax assets resulting from the Merger. The estimated increase in deferred tax asset of $495 million stems primarily from the addition of Dynegy’s net operating loss carryforward (which is approximately $2.3 billion (federal)) and the related fair value adjustments resulting from the purchase price allocation. The deferred tax asset is preliminary and subject to change based on the final determination of the fair value of assets acquired and liabilities assumed. The Historical Dynegy balance sheet does not reflect this net operating loss carryforward deferred tax asset as a valuation allowance was required; however, based on the expected future taxable income of the combined entity, a valuation allowance is not expected to be required on the federal NOL. Note that a valuation allowance (approximately $57 million) remains on a portion of the state NOL carryforward. The tax rate of 21% was utilized in determining the value of the combined deferred tax asset to give effect to the impact of the TCJA.

V. Reflects an adjustment to record Dynegy’s long-term debt at its respective fair value (including current maturities of long-term debt), which is approximated to be $8.9 billion. Estimated fair value was calculated using market quotes available at February 26, 2018 for the Tranche C-1 Term Loan, due 2014, all outstanding Senior Notes and the 7% Amortizing Notes. Remaining debt, including the Revolving Facility, Forward Capacity Agreements, Equipment Financing Agreements and Inventory Financing Agreements, were valued at December 31, 2017 utilizing the carrying value as an approximation of fair value.

The carrying amount of Dynegy’s long-term debt (including current maturities of long-term debt) was $8.4 billion as of December 31, 2017, and the resulting fair value measurement increased long-term debt excluding amounts currently due by $500 million and decreased long-term debt currently due by $4 million.

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Adjustments to debt were determined as follows:

Facility	Historical Carrying Value as of December 31, 2017		Pro Forma Adjustment			Fair Value as of February 26, 2018
	(in millions)
Senior Notes	$	6,078	$	418		$	6,496
Tranche C-1 Term Loan, due 2024		1,944		87			2,031
7.00% Amortizing Notes, due 2019		51		(9	)		42
Forward Capacity Agreements		215		—			215
Inventory Financing Agreements		48		—			48
Equipment Financing Agreements		97		—			97
Total	$	8,433	$	496		$	8,929

W. Reflects $9 million and $30 million increase in Dynegy’s short-term and long-term asset retirement obligations, respectively, as a result of the fair value adjustment for those obligations, primarily due to estimating the fair value of Dynegy’s asset retirement obligations using the relevant discount rates as of the pro forma balance sheet date.

X. Reflects the addition of $55 million of advisor fees to be paid upon the closing of the Merger for advisors of Dynegy and Vistra Energy. There are no other factually supportable transaction costs related to the Merger that can be reflected in the pro forma financial statements at this time.

Y. Reflects the decrease of $29 million related to the non-current portion of the Tax Receivable Agreement, resulting from the impacts of the Merger on the forecasted payments under the Tax Receivable Agreement obligation. The adjustments to the Tax Receivable Agreement obligation are caused by the addition of Dynegy’s tax attributes and the forecasted taxable income of the combined entity, which results in changes to the forecasted payments under the tax receivable agreement obligation. The adjusted forecasted payments were used to determine the obligation based on Vistra Energy’s accounting policy related to changes in estimates for the obligation. The estimated obligation is based on certain assumptions which are subject to significant uncertainty, are not yet final and are subject to change.

Z. Reflects preliminary adjustments to remove Historical Dynegy retained deficit of $1.9 billion and accumulated other comprehensive income of $32 million.

Additional paid-in-capital was reduced by $1.4 billion, which represents the issuance of shares of Vistra Energy common stock to Dynegy shareholders with an estimated value of $2.3 billion, less the elimination of Dynegy historical equity of $3.7 billion.

Information about Dynegy

Business

Dynegy began operations in 1984 and became incorporated in the State of Delaware in 2007. It is a holding company and conducts substantially all of its business operations through its subsidiaries. Dynegy’s primary business is the production and sale of electric energy, capacity and ancillary services from its fleet of 43 power plants in 12 states totaling approximately 28,000 MW of generating capacity.

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Dynegy sells electric energy, capacity and ancillary services primarily on a wholesale basis from Dynegy’s power generation facilities. Dynegy also serves residential, municipal, commercial and industrial customers through its Homefield Energy and Dynegy Energy Services businesses, through which it provides retail electricity to approximately 1,141,000 residential customers and approximately 88,000 commercial, industrial and municipal customers in Illinois, Massachusetts, Ohio and Pennsylvania. Wholesale electricity customers will primarily contract for rights to capacity from generating units for reliability reasons and to meet regulatory requirements. Ancillary services support the transmission grid operation, follow real time changes in load and provide emergency reserves for major changes to the balance of generation and load. Retail electricity customers purchase energy and these related services in the deregulated retail energy market. Dynegy sells these products individually or in combination to its customers for various lengths of time from hourly to multiyear transactions.

Dynegy does business with a wide range of customers, including regional transmission organizations and independent system operators, integrated utilities, municipalities, electric cooperatives, transmission and distribution utilities, power marketers, financial participants such as banks and hedge funds, and residential, commercial, and industrial end-users. Some of Dynegy’s customers, such as municipalities or integrated utilities, purchase its products for resale in order to serve their retail, commercial and industrial customers. Other customers, such as some power marketers, may buy from Dynegy to serve their own wholesale or retail customers or as a hedge against power sales they have made.

Dynegy reports the results of its operations in the following five segments based upon the market areas in which its plants operate: (i) PJM Interconnection, LLC (“PJM”), (ii) Independent System Operator New England/New York Independent System Operator (“NY/NE”), (iii) ERCOT, (iv) Midcontinent Independent System Operator, Inc. (“MISO”), (v) California Independent System Operator (“CAISO”). Dynegy’s consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense and income tax benefit (expense). In the fourth quarter of 2017, Dynegy combined its previous MISO and IPH, LLC (“IPH”) segments into a single MISO segment to better align its IPH assets, which reside within the MISO market area. Accordingly, Dynegy has recast data from prior periods to conform to the current year segment presentation.

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Portfolio

Dynegy’s generating facilities are as follows:

Facility	Total Net Generating Capacity(MW) (1)		Primary Fuel Type		Technology Type		Location	Region
Calumet		380		Gas		CT	Chicago, IL		PJM
Dicks Creek		155		Gas		CT	Monroe, OH		PJM
Fayette		726		Gas		CCGT	Masontown, PA		PJM
Hanging Rock		1,430		Gas		CCGT	Ironton, OH		PJM
Hopewell		370		Gas		CCGT	Hopewell, VA		PJM
Kendall		1,288		Gas		CCGT	Minooka, IL		PJM
Killen (2)(3)		204		Coal		ST	Manchester, OH		PJM
Kincaid		1,108		Coal		ST	Kincaid, IL		PJM
Liberty		607		Gas		CCGT	Eddystone, PA		PJM
Miami Fort		1,020		Coal		ST	North Bend, OH		PJM
Miami Fort		77		Oil		CT	North Bend, OH		PJM
Northeastern		52		Waste Coal		ST	McAdoo, PA		PJM
Ontelaunee		600		Gas		CCGT	Reading, PA		PJM
Pleasants		388		Gas		CT	Saint Marys, WV		PJM
Richland		423		Gas		CT	Defiance, OH		PJM
Sayreville (2)(3)		170		Gas		CCGT	Sayreville, NJ		PJM
Stryker		16		Oil		CT	Stryker, OH		PJM
Stuart (2)(3)		679		Coal		ST	Aberdeen, OH		PJM
Washington		711		Gas		CCGT	Beverly, OH		PJM
Zimmer		1,300		Coal		ST	Moscow, OH		PJM
Total PJM Segment		11,704
Bellingham		566		Gas		CCGT	Bellingham, MA		ISO-NE
Bellingham NEA (2)(3)		157		Gas		CCGT	Bellingham, MA		ISO-NE
Blackstone		544		Gas		CCGT	Blackstone, MA		ISO-NE
Casco Bay		543		Gas		CCGT	Veazie, ME		ISO-NE
Independence		1,212		Gas		CCGT	Oswego, NY		NYISO
Lake Road		827		Gas		CCGT	Dayville, CT		ISO-NE
MASSPOWER		281		Gas		CCGT	Indian Orchard, MA		ISO-NE
Milford—Connecticut		600		Gas		CCGT	Milford, CT		ISO-NE
Total NY/NE Segment		4,730
Coleto Creek		650		Coal		ST	Goliad, TX		ERCOT
Ennis		366		Gas		CCGT	Ennis, TX		ERCOT
Hays		1,047		Gas		CCGT	San Marcos, TX		ERCOT
Midlothian		1,596		Gas		CCGT	Midlothian, TX		ERCOT
Wharton		83		Gas		CT	Boling, TX		ERCOT
Wise		787		Gas		CCGT	Poolville, TX		ERCOT
Total ERCOT Segment		4,529
Baldwin		1,185		Coal		ST	Baldwin, IL		MISO
Coffeen		915		Coal		ST	Coffeen, IL		MISO
Duck Creek		425		Coal		ST	Canton, IL		MISO
Edwards		585		Coal		ST	Bartonville, IL		MISO
Havana		434		Coal		ST	Havana, IL		MISO
Hennepin		294		Coal		ST	Hennepin, IL		MISO
Joppa/EEI (2)		802		Coal		ST	Joppa, IL		MISO
Joppa units 1-3		165		Gas		CT	Joppa, IL		MISO
Joppa units 4-5 (2)		56		Gas		CT	Joppa, IL		MISO
Newton		615		Coal		ST	Newton, IL		MISO
Total MISO Segment (4)		5,476
Moss Landing		1,020		Gas		CCGT	Moss Landing, CA		CAISO
Oakland		165		Oil		CT	Oakland, CA		CAISO
Total CAISO Segment		1,185
Total Capacity		27,624

(1) Unit capabilities are based on winter capacity and are reflected at Dynegy’s net ownership interest. Does not include units that have been retired or are out of operation.

(2) Co-owned with other generation companies.

(3) Facilities not operated by Dynegy.

(4) Dynegy has transmission rights into PJM for certain of its MISO plants and currently offers power and capacity into PJM.

For additional information on Dynegy’s business and operations, see the documents filed by Dynegy with the Commission.

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Risk Factors Related to Dynegy

Risks Related to the Operation of Dynegy’s Business

Wholesale and retail power prices are subject to significant volatility and because many of Dynegy’s power generation facilities operate without long-term power sales agreements, Dynegy’s revenues and profitability are subject to wide fluctuations.

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

• addition of new supplies of power from existing competitors or new market entrants as a result of the development of new generation plants, expansion of existing plants or additional transmission capacity;

• uneconomic generation kept on line by utilities, aided by state-based subsidies;

• environmental regulations and legislation;

• weather conditions, including extreme weather conditions and seasonal fluctuations;

• electric supply disruptions including plant outages;

• basis risk from transmission losses and congestion and changes in power transmission infrastructure;

• development of new technologies for the production of natural gas;

• natural gas and coal supply disruptions;

• fuel price volatility;

• economic conditions;

• capacity performance, or similar construct, requirements and penalties;

• increased competition or price pressure driven by generation from renewable sources and other subsidized generation;

• regulatory constraints on pricing (current or future), including RTO and ISO rules, policies and actions, or the functioning of the energy trading markets and energy trading generally;

• the existence and effectiveness of demand-side management; and

• conservation efforts and energy efficiency rules and the extent to which they impact electricity demand.

Dynegy’s commercial strategies for its wholesale and retail businesses may not be executed as planned, may result in lost opportunities or adversely affect financial performance.

Dynegy seeks to commercialize its assets through sales arrangements of various types. In doing so, Dynegy attempts to balance a desire for greater predictability of earnings and cash flows in the short- and medium-terms with its expectation that commodity prices will rise over the longer term, creating upside opportunities for those with unhedged generation volumes. Dynegy’s ability to successfully execute this strategy is dependent on a number of factors, many of which are outside its control, including market liquidity and design, correlation risk, commodity price cycles, the availability of counterparties willing to transact with Dynegy or to transact with Dynegy at prices it thinks are commercially acceptable, the availability of liquidity to post collateral in support of its derivative instruments and the reliability of the systems and models comprising its commercial operations function. The availability of market liquidity and willing counterparties could be negatively impacted by poor economic and financial market conditions, including impacts on financial institutions and other current and potential counterparties as well as counterparties’ views of Dynegy’s creditworthiness. If Dynegy is unable to transact in the short- and medium-terms, Dynegy’s financial condition, results of operations and cash flows will be subject to significant uncertainty and volatility. Alternatively, significant power sales for any such period may precede a run-up in commodity prices, resulting in lost up-side opportunities.

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Further, financial performance may be adversely affected if Dynegy is unable to effectively manage its power portfolio. A portion of the generation power portfolio is used to provide power to wholesale and retail customers. To the extent portions of the power portfolio are not needed for that purpose, generation output is sold in the wholesale market. To the extent Dynegy’s power portfolio is not sufficient to meet the requirements of its customers, it must purchase power in the wholesale power markets. Its financial results may be negatively affected if it is unable to manage the power portfolio and cost-effectively meet the requirements of its customers.

A decline in market liquidity and Dynegy’s ability to manage its counterparty credit risk could adversely affect Dynegy.

Dynegy’s counterparties may experience deteriorating credit. These conditions could cause counterparties in the natural gas, coal and power markets, particularly in the energy commodity derivative markets that Dynegy relies on for its hedging activities, to withdraw from participation in those markets. If multiple parties withdraw from those markets, market liquidity may be threatened, which in turn could adversely impact Dynegy’s business. Additionally, these conditions may cause Dynegy’s counterparties to seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of title 11 of the United States Code (the “Bankruptcy Code”). Dynegy’s credit risk may be exacerbated to the extent collateral held by Dynegy cannot be realized or is liquidated at prices not sufficient to recover the full amount due to Dynegy. There can be no assurance that any such losses or impairments to the carrying value of Dynegy’s financial assets would not materially and adversely affect its financial condition, results of operations and cash flows. In addition, retail sales subject Dynegy to credit risk through competitive electricity supply activities to serve commercial and industrial companies and governmental entities. This risk represents the loss that may be incurred due to the nonpayment of a customer’s account balance, as well as the loss from the resale of energy previously committed to serve that customer, which could have a material adverse effect on Dynegy’s financial condition, results of operations and cash flows.

Dynegy is exposed to the risk of fuel and fuel transportation cost increases and interruptions in fuel supplies.

Dynegy purchases the fuel requirements for many of its power generation facilities, primarily those that are natural gas-fired, under short-term contracts or on the spot market. As a result, Dynegy faces the risks of supply interruptions and fuel price volatility, as fuel deliveries may not exactly match those required for energy sales.

Further, any changes in the costs of coal, fuel oil, natural gas or transportation rates and changes in the relationship between such costs and the market prices of power will affect Dynegy’s financial results. If Dynegy is unable to procure fuel for physical delivery at prices it considers favorable, its financial condition, results of operations and cash flows could be materially adversely affected.

Operation of power generation facilities involves significant risks customary to the power industry that could have a material adverse effect on Dynegy’s financial condition, results of operations and cash flows.

The ongoing operation of Dynegy’s facilities involves risks customary to the power industry that include the breakdown or failure of equipment or processes, operational and safety performance below expected levels and the inability to transport Dynegy’s product to customers in an efficient manner due to a lack of transmission capacity. Unplanned outages of generating units, including extensions of scheduled outages due to mechanical failures or other problems, occur from time to time and are an inherent risk of Dynegy’s business. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures, could result in reduced profitability, or with respect to capacity performance, performance incentive or similar construct, significant penalties or exceptionally high real-time Locational Marginal Pricing (“LMP”). Unplanned outages typically increase Dynegy’s operation and maintenance expenses and may reduce its revenues as a result of selling fewer MW or require Dynegy to incur significant costs as a result of running one of its higher cost units or obtaining replacement power from third parties in the open market to satisfy its forward power sales obligations. If Dynegy is unsuccessful in operating its facilities efficiently, such inefficiency could have a material adverse effect on Dynegy’s financial condition, results of operations and cash flows.

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Certain of Dynegy’s competitors may receive state-based subsidies that could materially adversely affect its financial condition, results of operations and cash flows.

A number of states in which Dynegy operates have either enacted or are considering regulations or legislation to subsidize otherwise uneconomic nuclear plants, and attempt to incent the development of new renewable resources as well as increase energy efficiency investments. In addition, in December 2015, federal renewable energy tax credits, including the wind power production tax credit and solar investment tax credits, were extended as part of the Consolidated Appropriations Act of 2016. Dynegy has actively challenged these types of programs and will continue to do so, including initiating legal challenges where appropriate. At this time, the direct impact on the organized power markets is a change in the generation supply stack created by the continued operation of subsidized resources that would retire absent the subsidies. The net combined impact of existing subsidy programs on Dynegy is uncertain at this time. Continued growth of energy subsidies could have a material adverse effect on Dynegy’s financial condition, results of operations and cash flows.

Dynegy’s costs of compliance with existing environmental requirements are significant, and costs of compliance with new environmental requirements or factors could materially adversely affect its financial condition, results of operations and cash flows.

Dynegy’s business is subject to extensive and frequently changing environmental regulation by federal, state and local authorities. Such environmental regulation imposes, among other things, capital and operating expenditures, restrictions, liabilities and obligations in connection with the generation, handling, use, transportation, treatment, storage and disposal of certain substances and wastes, including Coal Combustion Residuals (“CCR”), and in connection with spills, releases and emissions of various substances (including carbon emissions) into the environment, as well as environmental impacts associated with cooling water intake structures. Existing environmental laws and regulations may be revised or reinterpreted, new laws and regulations may be adopted or may become applicable to Dynegy or its facilities, and litigation or enforcement proceedings could be commenced against Dynegy. Proposals being considered by federal and state authorities (including proposals regarding cooling water intake structures and carbon) could, if and when adopted or enacted, require Dynegy to make substantial capital and operating expenditures, impair assets, or limit or terminate operation of certain of Dynegy’s facilities. If any of these events occur, Dynegy’s financial condition, results of operations and cash flows could be materially adversely affected.

Many environmental laws require approvals or permits from governmental authorities before construction, modification or operation of a power generation facility may commence. Certain environmental permits must be renewed periodically in order for Dynegy to continue operating its facilities. The process of obtaining and renewing necessary permits can be lengthy and complex and can sometimes result in the establishment of permit conditions that make the project or activity for which the permit was sought unprofitable or otherwise unattractive. Even where permits are not required, compliance with environmental laws and regulations can require significant capital and operating expenditures. Dynegy is required to comply with numerous environmental laws and regulations, and to obtain numerous governmental permits when it modifies and operates its facilities. If there is a delay in obtaining any required environmental regulatory approvals or permits, if Dynegy fails to obtain any required approval or permit, or if Dynegy is unable to comply with the terms of such approvals or permits, the operation of its facilities may be interrupted or become subject to additional costs and/or legal challenges. Further, changed interpretations of existing regulations may subject historical maintenance, repair and replacement activities at Dynegy’s facilities to claims of noncompliance. With the trend toward stricter environmental standards and more extensive regulatory and permitting requirements, Dynegy’s capital and operating environmental expenditures are likely to be substantial and may significantly increase in the future. As a result, Dynegy’s financial condition, results of operations and cash flows could be materially adversely affected.

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Dynegy’s business is subject to complex government regulation. Changes in these regulations or in their implementation may affect costs of operating Dynegy’s facilities or its ability to operate its facilities, or increase competition, any of which would negatively impact its results of operations.

Dynegy is subject to extensive federal, state and local laws and regulations governing the generation and sale of energy commodities in each of the jurisdictions in which it has operations. Compliance with these ever-changing laws and regulations requires expenses (including legal representation) and monitoring, capital and operating expenditures. Potential changes in laws and regulations that could have a material impact on Dynegy’s business include: the introduction, or reintroduction, of rate caps or pricing constraints; inability to pass on costs to customers; state regulatory initiatives, including subsidized generation; increased credit standards, collateral costs or margin requirements, as well as reduced market liquidity, as a result of potential OTC market regulation; or a variation of these. Furthermore, these and other market-based rules and regulations are subject to change at any time, and Dynegy cannot predict what changes may occur in the future or how such changes might affect any facet of its business.

The costs and burdens associated with complying with the increased number of regulations may have a material adverse effect on Dynegy if it fails to comply with the laws and regulations governing its business or if it fails to maintain or obtain advantageous regulatory authorizations and exemptions. Failure to comply with such requirements could result in the shutdown of any noncompliant facility, the imposition of liens or fines, or civil or criminal liability. Moreover, increased competition within the sector resulting from potential legislative changes, regulatory changes or other factors may create greater risks to the stability of Dynegy’s power generation earnings and cash flows.

Regulators, politicians, non-governmental organizations and other private parties have expressed concern about GHG emissions and the potential risks associated with climate change and are taking actions which could materially adversely affect Dynegy’s financial condition, results of operations and cash flows.

For the last several years, there has been a robust public debate about climate change and the potential for regulations requiring lower emissions of GHG, primarily CO2 and methane. At the federal and state levels, rules are in effect and policies are under development to regulate GHG emissions, thereby effectively putting a cost on such emissions in order to create financial incentives to reduce them. Power generating facilities are a major source of GHG emissions. Dynegy cannot confidently predict the final outcome of the current debate on climate change nor can Dynegy predict with confidence the ultimate requirements of proposed, anticipated or existing federal and state legislation and regulations intended to address climate change. These activities, and the highly politicized nature of climate change, suggest a trend toward increased regulation of GHG that could result in a material adverse effect on Dynegy’s financial condition, results of operations and cash flows. Existing and anticipated federal and state regulations intended to address climate change may significantly increase the cost of providing electric power, resulting in far-reaching and significant impacts on us and others in the power generation industry over time. It is possible that federal and state actions intended to address climate change could result in costs assigned to GHG emissions that Dynegy would not be able to fully recover through market pricing or otherwise. If capital and/or operating costs related to compliance with regulations intended to address climate change become great enough to render the operations of certain plants uneconomical, Dynegy could, at its option and subject to any applicable financing agreements or other obligations, reduce operations or cease to operate such plants and forego such capital and/or operating costs. Though Dynegy considers its largest risk related to climate change to be legislative and regulatory changes, it is subject to physical risks inherent in industrial operations including severe weather events such as hurricanes and tornadoes. To the extent that changes in climate affect changes in weather patterns (such as more severe weather events), Dynegy could be adversely affected.

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Availability and cost of emission allowances could materially impact Dynegy’s costs of operations.

Dynegy is required to maintain, either through allocation or purchase, sufficient emission allowances to support its operations in the ordinary course of operating its power generation facilities. These allowances are used to meet Dynegy’s obligations imposed by various applicable environmental laws, and the trend toward more stringent regulations (including regulations regarding GHG emissions) will likely require Dynegy to obtain new or additional emission allowances. If Dynegy’s operational needs require more than its allocated quantity of emission allowances, Dynegy may be forced to purchase such allowances on the open market, which could be costly. If Dynegy is unable to maintain sufficient emission allowances to match its operational needs, it may have to curtail its operations so as not to exceed its available emission allowances, or install costly new emissions controls. As Dynegy uses the emissions allowances that it has purchased on the open market, costs associated with such purchases will be recognized as an operating expense. If such allowances are available for purchase, but only at significantly higher prices, their purchase could materially increase Dynegy’s costs of operations in the affected markets and materially adversely affect Dynegy’s financial condition, results of operations and cash flows.

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

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

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

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

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

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Generally, Dynegy does not own or control transmission facilities required to sell wholesale power from its generation facilities. If transmission services are inadequate, Dynegy’s ability to sell and deliver wholesale power may be materially adversely affected. Furthermore, RTOs and ISOs administer the transmission infrastructure and market, which are subject to changes in structure and operation and impose various pricing limitations. These changes and pricing limitations may affect Dynegy’s ability to deliver power to the market that would, in turn, adversely affect the profitability of Dynegy’s generation facilities.

With the exception of EEI, which owns and controls transmission lines interconnecting the Joppa facility in EEI’s control area to MISO, Tennessee Valley Authority and Louisville Gas and Electric Company, Dynegy does not own or control the transmission facilities required to deliver the power from its generation facilities to the market. If transmission services from these facilities are unavailable or disrupted, or if the transmission capacity infrastructure is inadequate, Dynegy’s ability to sell and deliver wholesale power may be materially adversely affected, which could result in reduced profitability, or with respect to capacity performance in PJM and performance incentives in ISO-NE, significant penalties. RTOs and ISOs provide transmission services, administer transparent and competitive power markets and maintain system reliability. Many of these RTOs and ISOs operate in the real-time and day-ahead markets in which Dynegy sells energy. The RTOs and ISOs that oversee most of the wholesale power markets impose price limitations, offer caps, capacity performance requirements, penalties, and other mechanisms to guard against the potential exercise of market power in these markets. Price limitations and other regulatory mechanisms may adversely affect the profitability of Dynegy’s generation facilities that sell energy and capacity into the wholesale power markets. Problems or delays that may arise in the formation and operation of maturing RTOs and similar market structures, or changes in geographic scope, rules or market operations of existing RTOs, may also affect Dynegy’s ability to sell, the prices Dynegy receives or the cost to transmit power produced by Dynegy’s generating facilities. Market design as well as rules governing the various regional power markets may also change from time to time, which could materially adversely affect Dynegy’s financial condition, results of operations and cash flows.

Dynegy’s Retail business is subject to the risk that sensitive customer data may be compromised, which could result in an adverse impact to its reputation and/or the results of operations of the Retail business.

The 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 and bank account information. The 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 occurred, Dynegy’s reputation may be adversely affected, customer confidence may be diminished or Dynegy may be subject to legal claims, any of which may contribute to the loss of customers and have a negative impact on its business and/or financial condition, results of operations and cash flows.

Unauthorized hedging and related activities by Dynegy’s employees could result in significant losses.

Dynegy intends to continue its commercial strategy, which emphasizes forward power sales opportunities intended to reduce the market price exposure of the Company to power price declines. Dynegy has various internal policies and procedures designed to monitor hedging activities and positions. These policies and procedures are designed, in part, to prevent unauthorized purchases or sales of products by Dynegy’s employees. Dynegy cannot assure, however, that these steps will detect and prevent inaccurate reporting and all other violations of its risk management policies and procedures, particularly if deception or other intentional misconduct is involved. A significant policy violation that is not detected could result in a substantial financial loss.

Dynegy’s risk management policies cannot fully eliminate the risk associated with its commodity hedging activities.

Dynegy’s asset-based power position as well as its power marketing, fuel procurement and other commodity hedging activities expose it to risks of commodity price movements. Dynegy attempts to manage this exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when Dynegy’s policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations may be diminished if the judgments and assumptions

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underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, Dynegy cannot fully predict the impact that its commodity hedging activities and risk management decisions may have on its business and/or financial condition, results of operations and cash flows.

Strikes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms could have a material adverse effect on Dynegy’s financial condition, results of operations and cash flows.

A majority of the employees at Dynegy’s facilities are subject to collective bargaining agreements with various unions. Additionally, unionization activities, including votes for union certification, could occur at the non-union generating facilities in Dynegy’s fleet. If union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strike or disruption, Dynegy could experience reduced power generation or outages if replacement labor is not procured. The ability to procure such replacement labor is uncertain. Strikes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms could have a material adverse effect on Dynegy’s financial condition, results of operations and cash flows.

Terrorist attacks and/or cyber-attacks may result in Dynegy’s inability to operate and fulfill its obligations, and could result in material repair costs.

As a power generator, Dynegy faces heightened risk of terrorism, including cyber terrorism, either by a direct act against one or more of its generating facilities or an act against the transmission and distribution infrastructure that is used to transport its power. Dynegy relies on information technology networks and systems, including third party cloud systems, to operate its generating facilities, engage in asset management activities, and process, transmit and store electronic information. Security breaches of this information technology infrastructure, including cyber-attacks and cyber terrorism, could lead to system disruptions, generating facility shutdowns or unauthorized disclosure of confidential information related to Dynegy’s employees, vendors and counterparties, including retail counterparties.

Systemic damage to one or more of Dynegy’s generating facilities and/or to the transmission and distribution infrastructure could result in Dynegy’s inability to operate in one or all of the markets it serves for an extended period of time. If Dynegy’s generating facilities are shut down, Dynegy would be unable to respond to the ISOs and RTOs or fulfill its obligations under various energy and/or capacity arrangements, resulting in lost revenues and potential fines, penalties and other liabilities. Pervasive cyber-attacks across Dynegy’s industry could affect the ability of ISOs and RTOs to function in some regions. The cost to restore Dynegy’s generating facilities after such an occurrence could be material.

Risks Related to Dynegy’s Financial Structure

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

As of December 31, 2017, Dynegy had approximately $8.6 billion of total indebtedness and approximately $8.3 billion of indebtedness net of cash. Dynegy’s debt could have negative consequences for its financial condition including:

• increasing its vulnerability to general economic and industry conditions;

• requiring a substantial portion of its cash flow from operations to be dedicated to the payment of principal and interest on its indebtedness, therefore reducing its ability to use its cash flow to fund its operations, capital expenditures and future business opportunities;

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• limiting its ability to enter into long-term power sales or fuel purchases which require credit support;

• limiting its ability to fund operations or future acquisitions;

• restricting its ability to make certain distributions with respect to its capital stock and the ability of its subsidiaries to make certain distributions to it, in light of restricted payment and other financial covenants in its credit facilities and other financing agreements;

• inhibiting the growth of its stock price;

• exposing it to the risk of increased interest rates because certain of its borrowings, including borrowings under its revolving credit facility, are at variable rates of interest;

• limiting its ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; and

• limiting its ability to adjust to changing market conditions and placing it at a competitive disadvantage compared to its competitors who may have less debt.

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

Dynegy’s existing credit facilities contain, and agreements Dynegy enters into in the future may contain, covenants that could restrict its financial flexibility.

Dynegy’s existing credit facilities contain covenants imposing certain requirements on its business. These requirements may limit Dynegy’s ability to take advantage of potential business opportunities as they arise and may adversely affect the conduct of Dynegy’s current business, including restricting its ability to finance future operations and capital needs and limiting its ability to engage in other business activities. These covenants could place restrictions on Dynegy’s ability and the ability of its operating subsidiaries to, among other things:

• declare or pay dividends, repurchase or redeem stock or make other distributions to stockholders;

• incur additional debt or issue some types of preferred shares;

• create liens;

• make certain restricted investments;

• enter into transactions with affiliates;

• enter into any agreements which limit the ability of certain subsidiaries to make dividends or otherwise transfer cash or assets to Dynegy or certain other subsidiaries;

• sell or transfer assets; and

• consolidate or merge.

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Agreements Dynegy enters into in the future may also have similar or more restrictive covenants. A breach of any covenant in the existing credit facilities or the agreements governing Dynegy’s other indebtedness would result in a default. A default, if not waived, could result in acceleration of the debt outstanding under any such agreement and in a default with respect to, and acceleration of, the debt outstanding under any other debt agreements. The accelerated debt would become due and payable immediately. If that should occur, Dynegy may not be able to make all of the required payments or borrow sufficient funds to refinance its debt obligations. Even if new financing were then available, it may not be on terms that are acceptable to Dynegy.

Dynegy’s sub-investment grade status may adversely impact its commercial operations, increase its liquidity requirements and increase the cost of refinancing opportunities. Dynegy may not have adequate liquidity to post required amounts of additional collateral.

Dynegy’s corporate family credit rating is currently below investment grade and Dynegy cannot assure that its credit ratings will improve, or that they will not decline, in the future. Dynegy’s credit ratings may affect the evaluation of its creditworthiness by trading counterparties and lenders, which could put it at a disadvantage to competitors with higher or investment grade ratings. Dynegy uses a portion of its capital resources, in the form of cash, short-term investments, lien capacity and letters of credit, to satisfy these counterparty collateral demands. Dynegy’s commodity agreements are tied to market pricing and may require it to post additional collateral under certain circumstances. If it is unable to reliably forecast or anticipate collateral calls or if market conditions change such that counterparties are entitled to additional collateral, its liquidity could be strained and may have a material adverse effect on its financial condition, results of operations and cash flows. Factors that could trigger increased demands for collateral include changes in Dynegy’s credit rating or liquidity and changes in commodity prices for power and fuel, among others. Should Dynegy’s ratings continue at their current levels, or should its ratings be further downgraded, it would expect these negative effects to continue and, in the case of a downgrade, become more pronounced.

If Dynegy’s goodwill, amortizable intangible assets, or long-lived assets become impaired, Dynegy may be required to record a significant charge to earnings.

Dynegy has significant goodwill, amortizable intangible assets and long-lived assets recorded on its balance sheet. In accordance with GAAP, goodwill is required to be tested for impairment at least annually. Additionally, Dynegy reviews goodwill, its amortizable intangible assets and long-lived assets for impairment when events or changes in circumstances indicate the carrying value of the asset may not be recoverable. Factors that may be considered include a decline in future cash flows, slower growth rates in the energy industry, and a sustained decrease in the price of Dynegy’s common stock.

Dynegy has performed its annual goodwill assessment and determined that no impairment was required. However, further goodwill impairment testing will be performed in future periods and may result in an impairment loss, which could be material. In 2017, in connection with Dynegy’s asset sales, it wrote off approximately $27 million of goodwill. Dynegy performed certain asset impairment analyses in 2017 and, as a result, recorded impairment charges of $148 million. Please read Note 8 to Dynegy’s Consolidated Financial Statements—Property, Plant and Equipment-Impairments for further discussion.

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

If an “ownership change,” as defined in Section 382 of the IRC (“IRC §382”) occurs, the amount of NOLs and AMT credits that could be used in any one year following such ownership change could be substantially limited. In general, an “ownership change” would occur when there is a greater than 50 percentage point increase in ownership of a company’s stock by stockholders, each of which owns (or is deemed to own under IRC §382) 5 percent or more of such company’s stock. Given IRC §382’s broad definition, an ownership change could be the unintended consequence of otherwise normal market trading in Dynegy stock that is outside its control. Dynegy has already experienced two “ownership changes” under IRC §382 that limit the use of its NOLs and AMT credits that existed at the time and prior to Dynegy’s emergence from bankruptcy. NOLs that have been generated subsequent to Dynegy’s emergence from bankruptcy are not currently subject to the limitations imposed by IRC §382. If, however, there is another “ownership change,” the utilization of all NOLs and AMT credits existing at that time would be subject to additional annual limitations based upon a formula provided under IRC §382 that is based on the fair market value of Dynegy and prevailing interest rates at the time of the ownership change.

The effects of the TCJA on Dynegy’s business have not yet been fully analyzed and could have an adverse effect on its financial statements.

The TCJA, enacted on December 22, 2017, reduces the U.S. federal corporate tax rate from 35 percent to 21 percent. This resulted in a reduction to Dynegy’s net deferred tax assets with a corresponding reduction to its valuation allowance. The TCJA also repealed the corporate AMT, which resulted in a $223 million tax benefit for Dynegy related to the expected refund of its excess AMT credits.

The amounts discussed above are considered to be provisional as Dynegy continues to assess available tax methods and elections and refine its computations. Additionally, further regulatory guidance related to the TCJA may be issued in 2018 which could result in changes to Dynegy’s assessment and current estimates. Dynegy continues to analyze the TCJA and its possible effects on Dynegy. Any changes or clarifications to the TCJA may change Dynegy’s expectation on the amount of its net deferred tax assets and its expectation on the amount or timing of the AMT credit refunds.

Dynegy Selected Historical Consolidated Financial Information

The selected financial information presented below was derived from, and is qualified by reference to, Dynegy’s Consolidated Financial Statements, including the notes thereto, contained elsewhere herein. The selected financial information should be read in conjunction with Dynegy’s Consolidated Financial Statements and related notes and the information set forth below under “—Information about Dynegy—Dynegy Management’s Discussion and Analysis of Financial Condition and Results of Operation.”

	Year Ended December 31,
(in millions, except per share data)	2017			2016			2015			2014			2013
Statements of Operations Data:
Revenues	$	4,842		$	4,318		$	3,870		$	2,497		$	1,466
Impairments	$	(148	)	$	(858	)	$	(99	)	$	—		$	—
General and administrative expense	$	(189	)	$	(161	)	$	(128	)	$	(114	)	$	(97	)
Operating income (loss)	$	(412	)	$	(640	)	$	64		$	(19	)	$	(318	)
Bankruptcy reorganization items, net	$	494		$	(96	)	$	—		$	3		$	(1	)
Interest expense and debt extinguishment costs	$	(695	)	$	(625	)	$	(546	)	$	(223	)	$	(108	)
Income tax benefit	$	610		$	45		$	474		$	1		$	58
Income (loss) from continuing operations	$	72		$	(1,244	)	$	47		$	(267	)	$	(359	)
Net income (loss) attributable to Dynegy Inc.	$	76		$	(1,240	)	$	50		$	(273	)	$	(356	)
Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders	$	0.37		$	(9.78	)	$	0.22		$	(2.65	)	$	(3.56	)
Cash Flow Data:
Net cash provided by operating activities	$	585		$	645		$	94		$	221		$	173
Net cash provided by (used in) investing activities	$	(2,759	)	$	(93	)	$	(6,368	)	$	(107	)	$	141
Net cash provided by (used in) financing activities	$	(1,299	)	$	2,742		$	(265	)	$	6,126		$	(154	)
Capital expenditures and acquisitions	$	(3,543	)	$	(293	)	$	(6,379	)	$	(125	)	$	138
Interest paid	$	557		$	558		$	503		$	129		$	94

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	December 31,
(amounts in millions)	2017		2016		2015		2014		2013
Balance Sheet Data:
Current assets	$	1,524	$	2,987	$	1,932	$	2,664	$	1,682
Current liabilities	$	1,049	$	916	$	809	$	678	$	718
Property, plant and equipment, net	$	8,884	$	7,121	$	8,347	$	3,255	$	3,315
Total assets	$	11,771	$	13,053	$	11,459	$	11,154	$	5,264
Long-term debt (including current portion) (1)	$	8,433	$	8,979	$	7,209	$	7,028	$	1,965
Total equity	$	1,893	$	2,039	$	2,919	$	3,023	$	2,207

(1) The year ended December 31, 2016 includes a $2 billion seven-year Term Loan related to Dynegy’s acquisition on February 7, 2017 (the “ENGIE Acquisition Closing Date”) of approximately 9,017 MW of generation, including (a) 15 natural gas-fired facilities located in Illinois, Massachusetts, New Jersey, Ohio, Pennsylvania, Texas, Virginia, and West Virginia, (b) one coal-fired facility in Texas, and (c) one waste coal-fired facility in Pennsylvania for a base purchase price of approximately $3.3 billion in cash, subject to certain adjustments (the “ENGIE Acquisition”). The year ended December 31, 2014 includes $5.1 billion related to Dynegy’s notes issued on October 27, 2014 related to (i) Dynegy’s acquisition of approximately 6,200 MW of generation in (A) three combined-cycle natural gas-fired facilities located in Ohio and Pennsylvania, (B) two natural gas-fired peaking facilities located in Ohio and Illinois, (C) one oil-fired peaking facility located in Ohio, (D) partial interests in five coal-fired facilities located in Ohio, and (E) one retail energy business for a base purchase price of $2.8 billion in cash on April 2, 2015 (the “Duke Midwest Acquisition”) and (ii) Dynegy’s acquisition of (A) five combined-cycle natural gas-fired facilities in Connecticut, Massachusetts and Pennsylvania, (B) a partial interest in one natural gas-fired peaking facility in Illinois, (C) two gas- and oil-fired peaking facilities in Ohio, (D) one coal-fired facility in Illinois and (E) one coal-fired facility in Massachusetts for a base purchase price of approximately $3.35 billion in cash plus approximately $105 million in common stock of Dynegy on April 1, 2015 (the “EquiPower Acquisition”). Please read Note 13 to Dynegy’s Consolidated Financial Statements—Debt for further discussion.

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Dynegy Management’s Discussion and Analysis of Financial Condition and Results of Operation

The following discussion should be read together with Dynegy’s consolidated financial statements and the notes thereto included elsewhere in this prospectus.

OVERVIEW

Dynegy is a holding company and conducts substantially all of its business operations through its subsidiaries. Its current business operations are focused primarily on the power generation sector of the energy industry. Dynegy currently owns approximately 28,000 MW of generating capacity in twelve states and also provides retail electricity to approximately 1,141,000 residential customers and 88,000 commercial, industrial, and municipal customers in Illinois, Massachusetts, Ohio, and Pennsylvania. Dynegy reports the results of its operations in the following five segments based upon the market areas in which its plants operate: (i) PJM, (ii) NY/NE, (iii) ERCOT, (iv) MISO and (v) CAISO. In the fourth quarter of 2017, Dynegy combined its previous MISO and IPH segments into a single MISO segment to better align its IPH assets, which reside within the MISO market area. Dynegy has recast data from prior periods to conform to the current year segment presentation.

Business Discussion

Dynegy generates earnings and cash flows in the five segments of its power generation business through sales of electric energy, capacity, and ancillary services. Primary factors affecting Dynegy’s earnings and cash flows include:

• prices for power, natural gas, coal and fuel oil, and related transportation, which in turn are largely driven by supply and demand. Demand for power can vary due to weather and general economic conditions, among other things. Power supplies similarly vary by region and are impacted significantly by available generating capacity, transmission capacity, and federal and state regulation;

• the relationship between electricity prices and prices for natural gas and coal, commonly referred to as the “spark spread” and “dark spread,” respectively, which impacts the margin Dynegy earns on the electricity it generates; and

• Dynegy’s ability to enter into commercial transactions to mitigate short- and medium-term earnings volatility and its ability to manage its liquidity requirements resulting from potential changes in collateral requirements as prices move.

Other factors that have affected, and are expected to continue to affect, earnings and cash flows for the power generation business include:

• transmission constraints, congestion, and other factors that can affect the price differential between the locations where Dynegy delivers generated power and the liquid market hub;

• Dynegy’s ability to control capital expenditures, which primarily include maintenance, safety, environmental and reliability projects, and to control operating expenses through disciplined management;

• Dynegy’s ability to optimize its assets by maintaining a high in-market availability, reliable run-time and safe, low-cost operations;

• Dynegy’s ability to optimize its assets through targeted investment in cost effective technology enhancements, such as turbine uprates, or efficiency improvements;

• Dynegy’s ability to operate and market production from its facilities during periods of planned/unplanned electric transmission outages;

• Dynegy’s ability to post the collateral necessary to execute its commercial strategy;

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• the cost of compliance with existing and future environmental requirements that are likely to be more stringent and more comprehensive;

• market supply conditions resulting from federal and regional renewable power mandates and initiatives or other state-led initiatives;

• Dynegy’s ability to maintain coal inventory levels during critical winter and summer peak periods, which is dependent upon the reliable performance of the mines, railroads, and river transporters;

• costs of transportation related to coal deliveries;

• regional renewable energy mandates and initiatives that may alter supply conditions within an independent system operator (“ISO”) and Dynegy’s generating units’ positions in the aggregate supply stack;

• changes in market design or associated rules in the markets in which Dynegy operates, including the resulting effect on future capacity revenues from changes in the existing bilateral MISO capacity markets and the existing bilateral CAISO resource adequacy markets;

• Dynegy’s ability to maintain and operate its plants in a manner that ensures it receives full capacity payments under its various tolling agreements;

• Dynegy’s ability to mitigate forced outage risk, including managing risk associated with capacity performance in PJM and performance incentives in ISO-NE;

• Dynegy’s ability to mitigate impacts associated with expiring RMR and/or capacity contracts;

• access to capital markets on reasonable terms, interest rates and other costs of liquidity;

• benefits from Dynegy’s Producing Results through Innovation by Dynegy Employees (“PRIDE”) and Earnings & Cost Improvement (“ECI”) initiatives;

• interest expense; and

• income taxes, which will be impacted by Dynegy’s ability to realize value from its Net Operating Losses (“NOLs”) and Alternative Minimum Tax (“AMT”) credits.

Please read the section below entitled “—Risks Related to the Operation of Dynegy’s Business.” for additional factors that could affect Dynegy’s future operating results, financial condition and cash flows.

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LIQUIDITY AND CAPITAL RESOURCES

Overview

Dynegy maintains a strong focus on liquidity. Dynegy believes that it has adequate resources from a combination of its current liquidity position and cash expected to be generated from future operations to fund its liquidity and capital requirements as they become due. Dynegy’s liquidity and capital requirements are primarily a function of its debt maturities and debt service requirements, contractual obligations, capital expenditures (including required environmental expenditures) and working capital needs. Examples of working capital needs include purchases and sales of commodities and associated collateral requirements, facility maintenance costs, and other costs such as payroll.

Since 2013, Dynegy has increased scale and shifted its portfolio mix, which was predominately coal-based, to a predominately gas-based portfolio, through four major acquisitions. Dynegy used a significant portion of its balance sheet capacity to finance these acquisitions. Dynegy is now focused on strengthening its balance sheet, managing debt maturities and improving its leverage profile through debt reduction primarily from operating cash flows, as well as its PRIDE and ECI initiatives.

Liquidity.

The following table summarizes Dynegy’s liquidity position at December 31, 2017 (amounts in millions):

Revolving facilities and LC capacity (1)	$	1,650
Less:
Outstanding revolver draws		—
Outstanding LCs		(438	)
Revolving facilities and LC availability		1,212
Cash and cash equivalents		365
Total available liquidity	$	1,577

(1) Includes $1.545 billion in senior secured revolving credit facilities and $105 million related to letter of credit facilities (“LCs”). Please read Note 13 to Dynegy’s Consolidated Financial Statements—Debt for further discussion.

Liquidity Highlights

• Effective on the ENGIE Acquisition Closing Date, amended the credit agreement consisting of a term loan facility (the “Term Loan”) and a revolving credit facility (the “Revolving Facility” and, collectively with the Term Loan, the “Credit Agreement”) to (i) increase the revolver capacity by $120 million, (ii) extend the maturity date on $450 million in revolver capacity to 2021, (iii) reduce the interest rate applicable to the Term Loan by 75 basis points and exchanged the previous Term Loan for a new Term Loan.

• Closed the ENGIE Acquisition for a base purchase price of $3.3 billion, paid the Energy Capital Partners (“ECP”) Buyout Price of $375 million and issued 13,711,152 common shares to Terawatt Holdings, LLC (“Terawatt”) for $150 million.

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• Illinois Power Generating Company (“Genco”) emerged from bankruptcy and, as a result, Dynegy eliminated $825 million of Genco senior notes in exchange for approximately $122 million cash, $188 million in Dynegy senior notes and 9 million 2017 Warrants with a fair value of $17 million.

• Extended payment obligations of previously monetized capacity transactions (Forward Capacity Sales Agreement) by 24 months.

• Received approximately $773 million in proceeds from assets sales. Troy and Armstrong facilities ($472 million); Lee facility ($176 million); and Dighton and Milford-MA facilities ($125 million).

• Issued $850 million of 2026 Senior Notes. Dynegy used these proceeds, together with proceeds from asset sales and cash-on-hand to repurchase $1.25 billion of its 6.75 percent senior notes due 2019 and repay $200 million of the Term Loan.

• Amended the Credit Agreement to reduce the interest rate applicable to the Term Loan by 50 basis points through an exchange. This amendment is expected to save Dynegy approximately $63 million in interest costs over the next six years. Further interest rate reductions are available to Dynegy to the extent its credit ratings increase.

Cash Flows

The following table presents net cash from operating, investing and financing activities for the years ended December 31, 2017, 2016 and 2015:

	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Net cash provided by operating activities	$	585		$	645		$	94
Net cash used in investing activities	$	(2,759	)	$	(93	)	$	(6,368	)
Net cash provided by (used in) financing activities	$	(1,299	)	$	2,742		$	(265	)

Operating Activities

Changes in net cash provided by operating activities for the year ended December 31, 2017 compared to December 31, 2016 were primarily due to:

	(in millions)
Increase in cash provided by Dynegy’s power generation facilities and retail operations	$	237
Increase in interest payments on Dynegy’s various debt agreements		(2	)
Increase in payments for acquisition-related costs		(36	)
Decrease in cash provided by changes in working capital and other		(259	)
	$	(60	)

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Changes in net cash provided by operating activities for the year ended December 31, 2016 compared to December 31, 2015 were primarily due to:

	(in millions)
Increase in cash provided by Dynegy’s power generation facilities and retail operations	$	129
Increase in interest payments on Dynegy’s various debt agreements		(48	)
Decrease in payments for acquisition-related costs		96
Increase in cash provided by changes in working capital and other		391
Decrease in legal settlement received in 2015		(17	)
	$	551

Future Operating Cash Flows. Dynegy’s future operating cash flows will vary based on a number of factors, many of which are beyond its control, including the price of power, the prices of natural gas, coal, and fuel oil and their correlation to power prices, collateral requirements, the value of capacity and ancillary services, the run-time of its generating facilities, the effectiveness of its commercial strategy, legal, environmental and regulatory requirements, and its ability to achieve the cost savings contemplated in its PRIDE and ECI initiatives. Additionally, Dynegy’s future operating cash flows will benefit from the collection of the AMT refund associated with the Tax Cuts and Jobs Act (the “TCJA”).

Collateral Postings. Dynegy uses a portion of its capital resources in the form of cash and letters of credit to satisfy counterparty collateral demands. The following table summarizes Dynegy’s collateral postings to third parties at December 31, 2017 and 2016:

(amounts in millions)	December 31, 2017		December 31, 2016
Cash (1)	$	92	$	124
LCs		438		382
Total	$	530	$	506

(1) Includes broker margin as well as other collateral postings included in Prepayments and other current assets in Dynegy’s consolidated balance sheets. As of December 31, 2017 and 2016, $47 million and $54 million, respectively, of cash posted as collateral were netted against Liabilities from risk management activities in Dynegy’s consolidated balance sheets.

Collateral postings increased from December 31, 2016 to December 31, 2017 primarily due to an increase in LCs as a result of the ENGIE Acquisition and a fourth quarter 2017 movement in commodity prices. The fair value of Dynegy’s derivatives collateralized by first priority liens included liabilities of $243 million and $136 million at December 31, 2017 and 2016, respectively.

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Investing Activities

Historical Investing Cash Flows. Changes in net cash used in investing activities for the year ended December 31, 2017 compared to December 31, 2016 were primarily due to:

	(in millions)
Cash paid, net of cash acquired for the ENGIE Acquisition	$	(3,249	)
Increase in proceeds from asset sales, net		596
Purchase of Miami Fort and Zimmer from AES Ohio Generation, LLC and The Dayton Power and Light Company (collectively, “AES”)		(70	)
Decrease in capital expenditures		69
Decrease in distributions received from Dynegy’s unconsolidated investments and other investing activity		(12	)
	$	(2,666	)

Changes in net cash used in investing activities for the year ended December 31, 2016 compared to December 31, 2015 were primarily due to:

	(in millions)
Decrease in cash paid for the Duke Midwest Acquisition and the EquiPower Acquisition in 2015	$	6,078
Increase in proceeds from asset sales, primarily related to the sale of Dynegy’s unconsolidated investment in Elwood		176
Decrease in capital expenditures		8
Increase in distributions received from Dynegy’s unconsolidated investment in Elwood and other investing activity		13
	$	6,275

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Capital Expenditures. Dynegy’s capital spending by reportable segment is as follows:

	Year Ended December 31,									Estimated
(amounts in millions)	2017			2016			2015			2018
PJM	$	87		$	158		$	142		$	69
NY/NE		86			105			44			37
ERCOT		33			—			—			69
MISO		29			47			122			55
CAISO		36			5			9			7
Other		7			9			13			9
Total capital expenditures incurred (1)	$	278		$	324		$	330		$	246
Non-cash investing activities (2)		(31	)		2			(55	)		N/A
Capital work performed under prepaid long-term service agreement		(60	)		(121	)		(18	)		N/A
Prepaid cash for long-term service agreements (3)		37			88			44			N/A
Capital Expenditures - Statement of Cash Flows	$	224		$	293		$	301			N/A

(1) Includes capitalized interest of $2 million, $10 million, and $12 million for the years ended December 31, 2017, 2016 and 2015, respectively.

(2) Please read Note 6 to Dynegy’s Consolidated Financial Statements—Cash Flow Information for further details.

(3) Prepaid cash reclassified into Investing Activities on the consolidated statements of cash flows.

Capital spending in Dynegy’s PJM and MISO segments primarily consisted of environmental and maintenance capital projects. Capital spending in Dynegy’s NY/NE, ERCOT, and CAISO segments primarily consisted of only maintenance capital projects.

Future Investing Cash Flows. Capital expenditures for 2018 are noted above. The capital budget is subject to revision as opportunities arise or circumstances change.

Financing Activities

Historical Financing Cash Flows. Changes in net cash provided by financing activities for the year ended December 31, 2017 compared to cash used in financing activities for the year ended December 31, 2016 were primarily due to:

	(in millions)
Decrease in proceeds from long-term borrowings, net of issuance costs	$	(1,271	)
Increase in repayment of borrowings		(2,000	)
Decrease in proceeds from issuance of equity, net of issuance costs		(209	)
Cash paid for debt extinguishment costs in 2017		(50	)
Cash paid related to the ECP Buyout in 2017		(375	)
Cash paid related to the Genco Bankruptcy in 2017		(133	)
Other financing activity		(3	)
	$	(4,041	)

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Changes in net cash provided by financing activities for the year ended December 31, 2016 compared to cash provided by financing activities for the year ended December 31, 2015 were primarily due to:

	(in millions)
Increase in proceeds from long-term borrowings, net of issuance costs	$	2,948
Increase in repayment of borrowings, primarily due to the early paydown of the Term Loan in 2016		(558	)
Increase in proceeds from issuance of equity, net of issuance costs primarily related to tangible equity units (“TEUs”)		365
Repurchases of common stock related to Dynegy’s share repurchase program in 2015		250
Other financing activity		2
	$	3,007

Summarized Debt and Other Obligations. The following table depicts Dynegy’s third-party debt obligations, and the extent to which they are secured as of December 31, 2017 and 2016:

(amounts in millions)	December 31, 2017			December 31, 2016
Secured obligations:
Term loan	$	2,018		$	2,224
Revolving Facility		—			—
Forward Capacity Agreement		241			219
Inventory Financing Agreements		48			129
Unsecured obligations (Amortizing Notes, Senior Notes, and Equipment Financing)		6,323			6,527
Unamortized discounts and issuance costs		(197	)		(120	)
Total long-term debt	$	8,433		$	8,979

Future Financing Cash Flows. Dynegy’s future cash flows from financing activities include principal payments on its debt instruments and periodic payments to settle certain of its interest rate swap agreements.

Financing Trigger Events. Dynegy’s debt instruments and certain of its other financial obligations include provisions which, if not met, could require early payment, additional collateral support or similar actions. The trigger events include the violation of covenants (including, in the case of the Credit Agreement under certain circumstances, the senior secured leverage ratio covenant discussed below), defaults on scheduled principal

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or interest payments, including any indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions, insolvency events, acceleration of other financial obligations and, in the case of the Credit Agreement, change of control provisions. Dynegy does not have any trigger events tied to specified credit ratings or stock price in its debt instruments and is not party to any contracts that require Dynegy to issue equity based on credit ratings or other trigger events. Please read Note 13 to Dynegy’s Consolidated Financial Statements—Debt for further discussion.

Financial Covenants

Credit Agreement. The Credit Agreement contains customary events of default and affirmative and negative covenants, subject to certain specified exceptions, including a financial covenant specifying required thresholds for Dynegy’s senior secured leverage ratio calculated on a rolling four quarters basis. To the extent Dynegy uses 25 percent or more of its Revolving Facility, the Fourth Amendment of the Credit Agreement requires that Dynegy must be in compliance with the Consolidated Senior Secured Net Debt to Consolidated Adjusted EBITDA ratio (as defined in the Credit Agreement). Balances under Dynegy’s Forward Capacity Agreement relating to its PJM capacity for Planning Years 2018-2019, 2019-2020 and 2020-2021 (the “Forward Capacity Agreement”), the inventory financing agreement assumed by Dynegy in connection with the Equipower Acquisition (the “Inventory Financing Agreement”), and various equipment financing agreements (the “Equipment Financing Agreements”) are excluded from Net Debt. Consolidated Senior Secured Net Debt to Consolidated Adjusted EBITDA ratio is 4.00:1.00. Dynegy was in compliance with these covenants as of and for the three-year period ended December 31, 2017.

Please read Note 13 to Dynegy’s Consolidated Financial Statements—Debt for further discussion.

Dividends. Dynegy has paid no cash dividends on its common stock and has no current intention of doing so. Any future determinations to pay cash dividends will be at the discretion of its Board of Directors, subject to applicable limitations under Delaware law, and will be dependent upon its results of operations, financial condition, contractual restrictions and other factors deemed relevant by the board of directors of Dynegy (the “Dynegy Board of Directors”).

Dynegy paid quarterly dividends on its mandatory convertible preferred stock on February 1, May 1, August 1, and November 1 of each year, if declared by the Dynegy Board of Directors. Dynegy dividends paid for 2017 and 2016 are as follows:

Dividend Payment Dates and Amounts Paid
(amounts in millions)	2017		2016
February 1	$	5.4	$	5.4
May 1	$	5.4	$	5.4
August 1	$	5.4	$	5.4
November 1	$	5.4	$	5.4

Dynegy’s 4 million shares of Series A Mandatory Convertible Preferred Stock converted on November 1, 2017 into approximately 12.9 million shares of Dynegy’s common stock. Please see Note 15 to Dynegy’s Consolidated Financial Statements—Stockholders’ Equity for further discussion.

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Credit Ratings

Dynegy’s credit rating status is currently “non-investment grade” and its current ratings are as follows:

	Moody’s		S&P
Corporate Family Rating		B2		B+
Senior Secured		Ba3		BB
Senior Unsecured		B3		B+

Disclosure of Contractual Obligations and Other Environmental Obligations

Dynegy has incurred various contractual obligations, financial commitments, and other environmental obligations in the normal course of business. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. Dynegy’s other environmental obligations consist of Effluent Limitation Guidelines (“ELG”) expenditures and Asset Retirement Obligations (“AROs”).

The following table summarizes the contractual obligations and other environmental obligations of Dynegy and its consolidated subsidiaries as of December 31, 2017. Cash obligations reflected are not discounted and do not include accretion or dividends.

	Expiration by Period
(amounts in millions)	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		More than 5 Years
Long-term debt (including current portion) (1)	$	8,498	$	83	$	1,063	$	1,795	$	5,557
Interest payments on debt		3,316		566		1,050		979		721
Coal purchase commitments		802		402		400		—		—
Coal transportation		837		148		181		188		320
Contractual service agreements		788		118		283		347		40
Gas purchase commitments		212		212		—		—		—
Gas transportation		183		48		73		28		34
Pension funding obligations		220		13		5		50		152
Operating leases		33		6		10		9		8
Other obligations		88		35		16		12		25
Total contractual obligations		14,977		1,631		3,081		3,408		6,857
Total ELG expenditures		274		—		199		38		37
Total AROs		586		36		69		123		358
Total contractual and other environmental obligations	$	15,837	$	1,667	$	3,349	$	3,569	$	7,252

(1) Excludes $132 million of Equipment Financing Agreements which are included in Contractual service agreements.

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Long-Term Debt (including Current Portion). Long-term debt includes amounts related to the Dynegy senior notes, the Credit Agreement, the Revolving Facility, the Inventory Financing Agreements, the Forward Capacity Agreement, and the Amortizing Notes. Amounts do not include debt to finance parts, equipment and services or unamortized discounts. Please read Note 13 to Dynegy’s Consolidated Financial Statements—Debt for further discussion.

Interest Payments on Debt. Interest payments on debt represent estimated periodic interest payment obligations associated with the Dynegy senior notes, the Revolving Facility, the Credit Agreement, the Inventory Financing Agreements, and the Amortizing Notes. Amounts include the impact of interest rate swap agreements. Please read Note 13 to Dynegy’s Consolidated Financial Statements—Debt for further discussion.

Coal Purchase Commitments. At December 31, 2017, Dynegy’s subsidiaries had contracts in place to purchase coal for various generation facilities. The amounts in the table reflect Dynegy’s minimum purchase obligations. To the extent forecasted volumes have not been priced but are subject to a price collar structure, the obligations have been calculated using the minimum purchase price of the collar.

Coal Transportation. At December 31, 2017, Dynegy had long-term coal transportation contracts in place. Dynegy also had long-term rail car leases in place. The amounts included in Coal transportation reflect Dynegy’s minimum purchase obligations based on the terms of the contracts.

Contractual Service Agreements. Contractual service agreements represent obligations with respect to long-term plant maintenance agreements. In prior periods, Dynegy has undertaken several measures to restructure some of its existing maintenance service agreements with its turbine service providers. The table above includes its current estimate of payments under the contracts through 2048 based on anticipated timing of outages and are subject to change as outage dates move. As of December 31, 2017, Dynegy’s obligation with respect to these restructured agreements is limited to the termination payments, which are approximately $707 million in the event all contracts are terminated by Dynegy. In addition, Dynegy has committed to securing capital spares and turbine uprates for its gas-fueled generation fleet to help minimize production disturbances, improve efficiency, and increase generation. As of December 31, 2017, Dynegy has obligations to purchase spare parts and turbine uprates of $112 million with payments made through 2026, of which $103 million reflects spare parts received and upgrades completed. Please read Note 16 to Dynegy’s Consolidated Financial Statements—Commitments and Contingencies—Other Commitments for further discussion.

Gas Purchase Commitments. At December 31, 2017, Dynegy’s subsidiaries had contracts in place to purchase gas for various generation facilities. The amounts in the table reflect Dynegy’s minimum purchase obligations.

Gas Transportation. Gas transportation includes fixed transport capacity obligations associated with fuel procurement for Dynegy’s gas plants.

Pension Funding Obligations. Amounts include Dynegy’s minimum required contributions to Dynegy’s defined benefit pension plans through 2027 as determined by Dynegy’s actuary and are subject to change based on actual results of the plan. Dynegy may elect to make voluntary contributions in 2018 which would decrease future funding obligations. Please read Note 17 to Dynegy’s Consolidated Financial Statements—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

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Operating Leases. Operating leases include minimum lease payment obligations associated with office space, office equipment, and land leases.

Other Obligations. Other obligations primarily include the following:

• $25 million related to limestone and ash purchase commitments;

• $17 million related to interconnection services;

• $23 million related to water services; and

• $23 million related to other miscellaneous items which are individually insignificant.

Commitments and Contingencies

Please read Note 16 to Dynegy’s Consolidated Financial Statements—Commitments and Contingencies, which is incorporated herein by reference, for further discussion of Dynegy’s material commitments and contingencies.

Off-Balance Sheet Arrangements

Dynegy had no off-balance sheet arrangements at December 31, 2017.

RESULTS OF OPERATIONS

Overview and Discussion of Comparability of Results. This section includes a discussion of Dynegy’s results of operations, both on a consolidated basis and, where appropriate, by segment, for the years ended December 31, 2017, 2016 and 2015. At the end of this section is included Dynegy’s business outlook for each segment.

Dynegy reports the results of its power generation business primarily as five separate segments in its consolidated financial statements: (i) PJM, (ii) NY/NE, (iii) ERCOT, (iv) MISO and (v) CAISO. Dynegy’s consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense and income tax benefit (expense). All references to hedging within this discussion relate to economic hedging activities as Dynegy does not elect hedge accounting.    

Non-GAAP Measures. In analyzing and planning for Dynegy’s business, Dynegy supplements its use of GAAP financial measures with non-GAAP financial measures, including EBITDA and Adjusted EBITDA as performance measures, and Adjusted Free Cash Flow (“FCF”) as a liquidity measure. These non-GAAP financial measures reflect an additional way of viewing aspects of Dynegy’s business that, when viewed with Dynegy’s GAAP results and the accompanying reconciliations to corresponding GAAP financial measures included in the tables below, may provide a more complete understanding of factors and trends affecting Dynegy’s business. These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are by definition an incomplete understanding of Dynegy and must be considered in conjunction with GAAP measures.

Dynegy believes that the non-GAAP measures disclosed in its filings are only useful as an additional tool to help management and investors make informed decisions about its financial and operating performance. By definition, non-GAAP measures do not give a full understanding of Dynegy; therefore, to be truly valuable, they must be used in conjunction with the comparable GAAP measures. In addition, non-GAAP financial measures are not standardized; therefore, it may not be possible to compare these financial measures with other companies’ non-GAAP financial measures having the same or similar names. Dynegy strongly encourages investors to review its consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

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EBITDA and Adjusted EBITDA. Dynegy defines EBITDA as earnings (loss) before interest expense, income tax expense (benefit) and depreciation and amortization expense. Dynegy defines Adjusted EBITDA as EBITDA adjusted to exclude (i) gains or losses on the sale of certain assets, (ii) the impacts of mark-to-market changes on derivatives related to our generation portfolio, as well as warrants, (iii) the impact of impairment charges, (iv) certain amounts such as those associated with acquisitions, dispositions or restructurings, (v) non-cash compensation expense, (vi) gains or losses related to modification or extinguishment of debt, and (vii) other material or unusual items.

Dynegy believes EBITDA and Adjusted EBITDA provide meaningful representations of its operating performance. Dynegy considers EBITDA as another way to measure financial performance on an ongoing basis. Adjusted EBITDA is meant to reflect the operating performance of its entire power generation fleet for the period presented; consequently, it excludes the impact of (i) mark-to-market accounting, (ii) impairment charges and (iii) other items that could be considered “non-operating” or “non-core” in nature. Because EBITDA and Adjusted EBITDA are financial measures that Dynegy management uses to allocate resources, determine its ability to fund capital expenditures, assess performance against its peers, and evaluate overall financial performance, Dynegy believes they provide useful information for Dynegy investors. In addition, many analysts, fund managers and other stakeholders who communicate with Dynegy typically request its financial results in an EBITDA and Adjusted EBITDA format.

As prescribed by the Commission, when EBITDA or Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss). Dynegy management does not analyze interest expense and income taxes on a segment level; therefore, the most directly comparable GAAP financial measure to EBITDA or Adjusted EBITDA when performance is discussed on a segment level is Operating income (loss).

Adjusted Free Cash Flow. Dynegy defines Adjusted FCF as cash flow from operating activities adjusted for (i) non-discretionary maintenance and environmental capital expenditures, (ii) the cash impact of acquisition and integration-related costs, (iii) receipts or payments related to interest rate swaps reported as financing activities in its consolidated statements of cash flows, and (iv) excludes the impact of changes in collateral, working capital and other receipts and payments. The most directly comparable GAAP financial measure is cash flows from operating activities.

Adjusted FCF may not be representative of the amount of residual cash flow that is available to Dynegy for discretionary expenditures, since it may not include deductions for mandatory debt service requirements and other non-discretionary expenditures. Dynegy management believes, however, that Adjusted FCF is useful to investors and Dynegy because it measures the cash generating ability of Dynegy’s assets. Dynegy measures Adjusted FCF on a consolidated basis.

The following table presents Adjusted FCF from operations for the years ended December 31, 2017, 2016 and 2015:

	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Net cash provided by operating activities	$	585		$	645		$	94
Capital expenditures		(249	)		(228	)		(251	)
Acquisition & integration related payments		55			73			272
Adjustment related to acquired derivatives		42			47			60
Interest rate swap settlement payments		(20	)		(17	)		(17	)
Collateral, working capital and other		(39	)		(257	)		28
Adjusted Free Cash Flow	$	374		$	263		$	186

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Consolidated Summary Financial Information—Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

Dynegy completed the ENGIE Acquisition on February 7, 2017; therefore, the results of its newly acquired plants within its PJM, NY/NE and ERCOT segments are included in its consolidated results since the acquisition date. Please read Note 3 to Dynegy’s Consolidated Financial Statements—Acquisitions and Divestitures—ENGIE Acquisition for further discussion. The following table provides summary financial data regarding Dynegy’s consolidated results of operations for the years ended December 31, 2017 and 2016, respectively:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(amounts in millions)	2017			2016
Revenues
Energy	$	4,000		$	3,366		$	634
Capacity		978			769			209
Mark-to-market income (loss), net		(243	)		136			(379	)
Contract amortization		(33	)		(80	)		47
Other		140			127			13
Total revenues		4,842			4,318			524
Cost of sales, excluding depreciation expense		(2,932	)		(2,281	)		(651	)
Gross margin		1,910			2,037			(127	)
Operating and maintenance expense		(995	)		(940	)		(55	)
Depreciation expense		(811	)		(689	)		(122	)
Impairments		(148	)		(858	)		710
Loss on sale of assets, net		(122	)		(1	)		(121	)
General and administrative expense		(189	)		(161	)		(28	)
Acquisition and integration costs		(57	)		(11	)		(46	)
Other		—			(17	)		17
Operating loss		(412	)		(640	)		228
Bankruptcy reorganization items		494			(96	)		590
Earnings from unconsolidated investments		8			7			1
Interest expense		(616	)		(625	)		9
Loss on early extinguishment of debt		(79	)		—			(79	)
Other income and expense, net		67			65			2
Loss before income taxes		(538	)		(1,289	)		751
Income tax benefit		610			45			565
Net income (loss)		72			(1,244	)		1,316
Less: Net loss attributable to noncontrolling interest		(4	)		(4	)		—
Net income (loss) attributable to Dynegy Inc.	$	76		$	(1,240	)	$	1,316

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The following tables provides summary financial data regarding Dynegy’s operating income (loss) by segment for the years ended December 31, 2017 and 2016, respectively:

	Year Ended December 31, 2017
(amounts in millions)	PJM			NY/NE			ERCOT			MISO			CAISO			Other			Total
Revenues	$	2,262		$	1,029		$	277		$	1,152		$	122		$	—		$	4,842
Cost of sales, excluding depreciation expense		(1,217	)		(658	)		(256	)		(723	)		(78	)		—			(2,932	)
Gross margin		1,045			371			21			429			44			—			1,910
Operating and maintenance expense		(389	)		(170	)		(95	)		(300	)		(39	)		(2	)		(995	)
Depreciation expense		(379	)		(224	)		(73	)		(75	)		(53	)		(7	)		(811	)
Impairments		(49	)		—			—			(99	)		—			—			(148	)
Gain (loss) on sale of assets, net		(36	)		(90	)		—			1			3			—			(122	)
General and administrative expense		—			—			—			—			—			(189	)		(189	)
Acquisition and integration costs		—			—			—			—			—			(57	)		(57	)
Operating income (loss)	$	192		$	(113	)	$	(147	)	$	(44	)	$	(45	)	$	(255	)	$	(412	)

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	Year Ended December 31, 2016
(amounts in millions)	PJM			NY/NE			MISO			CAISO			Other			Total
Revenues	$	2,202		$	837		$	1,137		$	142		$	—		$	4,318
Cost of sales, excluding depreciation expense		(985	)		(486	)		(741	)		(69	)		—			(2,281	)
Gross margin		1,217			351			396			73			—			2,037
Operating and maintenance expense		(391	)		(165	)		(347	)		(36	)		(1	)		(940	)
Depreciation expense		(346	)		(215	)		(81	)		(42	)		(5	)		(689	)
Impairments		(65	)		—			(793	)		—			—			(858	)
Gain (loss) on sale of assets, net		—			—			1			—			(2	)		(1	)
General and administrative expense		—			—			—			—			(161	)		(161	)
Acquisition and integration costs		—			—			8			—			(19	)		(11	)
Other		(1	)		—			(16	)		—			—			(17	)
Operating income (loss)	$	414		$	(29	)	$	(832	)	$	(5	)	$	(188	)	$	(640	)

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Discussion of Consolidated Results of Operations

Revenues. The following table summarizes the change in revenues by segment:

(amounts in millions)	PJM			NY/NE			ERCOT		MISO			CAISO			Total
Revenues, attributable to newly acquired ENGIE plants	$	203		$	227		$	277	$	—		$	—		$	707
Higher (lower) realized power prices, net of hedges		29			108			—		(47	)		27			117
Lower generation volumes (1)		(23	)		(51	)		—		(57	)		(8	)		(139	)
Higher (lower) capacity revenues		26			25			—		47			(22	)		76
Change in MTM value of derivative transactions		(200	)		(128	)		—		68			(7	)		(267	)
Lower contract amortization		24			4			—		7			10			45
Other (2)		1			7			—		(3	)		(20	)		(15	)
Total change in revenues	$	60		$	192		$	277	$	15		$	(20	)	$	524

(1) Decrease due to mild winter weather which decreased demand across Dynegy’s key markets as well as planned outages and shutdowns.

(2) Other primarily consists of ancillary, tolling, transmission and gas revenues.

Cost of Sales. The following table summarizes the change in cost of sales by segment:

(amounts in millions)	PJM			NY/NE			ERCOT		MISO			CAISO			Total
Cost of sales attributable to newly acquired ENGIE plants	$	91		$	119		$	256	$	—		$	—		$	466
Higher (lower) delivered fuel cost, primarily due to higher gas costs		117			142			—		(1	)		15			273
Lower burn volumes (1)		(39	)		(76	)		—		(12	)		(6	)		(133	)
Lower (higher) contract amortization		42			(18	)		—		13			—			37
Other (2)		21			5			—		(18	)		—			8
Total change in cost of sales	$	232		$	172		$	256	$	(18	)	$	9		$	651

(1) Lower burn volumes primarily due to milder weather at Dynegy’s PJM, NY/NE, and MISO segments, unit shutdowns primarily at its MISO segment, and a plant retirement at its NY/NE segment.

(2) Other primarily consists of transmission expenses and various non-recurring expenses.

Operating and Maintenance Expense. Operating and maintenance expense increased by $55 million primarily due to the newly acquired ENGIE plants, partially offset by lower costs from long-term service agreements at Dynegy’s PJM, NY/NE and CAISO segments, plant shutdowns at its MISO segment, and the Brayton Point plant retirement at its NY/NE segment.

87

Depreciation Expense. Depreciation expense increased by $122 million primarily due to increases from the newly acquired ENGIE plants partially offset by the Brayton Point plant retirement at its NY/NE segment.

Impairments. Impairments decreased by $710 million due to the following (amounts in millions):

	Year Ended December 31,
Description	2017		2016
Inventory	$	14	$	—
Property, plant and equipment		119		849
Equity investment		—		9
Assets held-for-sale, including $9 of allocated goodwill		15		—
Total	$	148	$	858

Please read Note 7 to Dynegy’s Consolidated Financial Statements—Inventory, Note 8 to Dynegy’s Consolidated Financial Statements—Property, Plant and Equipment, Note 10 to Dynegy’s Consolidated Financial Statements—Unconsolidated Investments, and Note 3 to Dynegy’s Consolidated Financial Statements—Acquisitions and Divestitures for further discussion.

Loss on Sale of Assets, net. Loss on sale of assets, net increased by $121 million primarily due to the Conesville and Zimmer ownership interest exchange, and the sale of Dynegy’s Lee, Dighton and Milford-MA facilities. Please read Note 9 to Dynegy’s Consolidated Financial Statements—Joint Ownership of Generating Facilities and Note 3 to Dynegy’s Consolidated Financial Statements—Acquisitions and Divestitures for further discussion.

General and Administrative Expense. General and administrative expense increased by $28 million primarily due to higher overhead associated with the ENGIE Acquisition and higher professional fees of $17 million related to the Merger.

Acquisition and Integration Costs. Acquisition and integration costs increased by $46 million primarily due to $36 million higher advisory and consulting fees and $10 million higher severance, retention, and payroll costs primarily related to the ENGIE Acquisition in 2017.

Other. Other decreased by $17 million primarily due to a charge in 2016 associated with the termination of an above market coal supply contract at Dynegy’s MISO segment.

Bankruptcy Reorganization Items. Bankruptcy reorganization items increased by $590 million primarily due to the gain on extinguishment of debt and legal costs associated with the Genco bankruptcy reorganization. Please read Note 20 to Dynegy’s Consolidated Financial Statements—Genco Chapter 11 Bankruptcy for further discussion.

Interest Expense. Interest expense decreased by $9 million primarily due to the elimination of the Genco senior notes partially offset by the interest on the Term Loan and the senior notes. Please read Note 13 to Dynegy’s Consolidated Financial Statements—Debt for further discussion.

Loss on Early Extinguishment of Debt. Loss on early extinguishment of debt was $79 million due to the repurchase of a portion of Dynegy’s senior notes, and the partial repayment and repricing of the Term Loan. Please read Note 13 to Dynegy’s Consolidated Financial Statements—Debt for further discussion.

88

Income Tax Benefit. The net favorable change of $565 million was primarily due to a partial release of Dynegy’s valuation allowance as a result of the ENGIE Acquisition of $354 million and recognition of the benefit of AMT credits of $223 million that had previously been subject to a valuation allowance as a result of the TCJA.

Net Income (Loss) Attributable to Dynegy Inc. The $1.316 billion increase was primarily due to (i) a $228 million lower operating loss primarily attributable to lower impairments, (ii) a $590 million gain primarily due to extinguishment of debt associated with the Genco bankruptcy, and (iii) a $565 million increase in tax benefit as discussed above, partially offset by a $79 million loss on early extinguishment of debt.

Adjusted EBITDA — Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

The following table provides summary financial data regarding Dynegy’s Adjusted EBITDA by segment for the year ended December 31, 2017:

	Year Ended December 31, 2017
(amounts in millions)	PJM		NY/NE			ERCOT			MISO			CAISO			Other			Total
Net income																		$	72
Income tax benefit																			(610	)
Other income and expense, net																			(67	)
Loss on early extinguishment of debt																			79
Interest expense																			616
Earnings from unconsolidated investments																			(8	)
Bankruptcy reorganization items																			(494	)
Operating income (loss)	$	192	$	(113	)	$	(147	)	$	(44	)	$	(45	)	$	(255	)	$	(412	)
Depreciation and amortization expense		390		232			74			91			57			7			851
Bankruptcy reorganization items		—		—			—			494			—			—			494
Earnings from unconsolidated investments		3		5			—			—			—			—			8
Loss on early extinguishment of debt		—		—			—			—			—			(79	)		(79	)
Other income and expense, net		16		—			—			26			—			25			67
EBITDA		601		124			(73	)		567			12			(302	)		929
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude noncontrolling interest		5		2			—			2			—			—			9
Acquisition, integration and restructuring costs		—		—			—			—			—			74			74
Bankruptcy reorganization items		—		—			—			(494	)		—			—			(494	)
Mark-to-market adjustments, including warrants		125		75			99			(21	)		7			(16	)		269
Impairments		49		—			—			99			—			—			148
Loss (gain) on sale of assets, net		36		90			—			(1	)		—			—			125
Loss on early extinguishment of debt		—		—			—			—			—			79			79
Non-cash compensation expense		—		—			—			1			—			20			21
Other		2		2			—			(1	)		—			(3	)		—
Adjusted EBITDA	$	818	$	293		$	26		$	152		$	19		$	(148	)	$	1,160

89

The following table provides summary financial data regarding Dynegy’s Adjusted EBITDA by segment for the year ended December 31, 2016:

	Year Ended December 31, 2016
(amounts in millions)	PJM			NY/NE			MISO			CAISO			Other			Total
Net loss																$	(1,244	)
Income tax benefit																	(45	)
Other income and expense, net																	(65	)
Interest expense																	625
Earnings from unconsolidated investments																	(7	)
Bankruptcy reorganization items																	96
Operating income (loss)	$	414		$	(29	)	$	(832	)	$	(5	)	$	(188	)	$	(640	)
Depreciation and amortization expense		349			243			87			53			5			737
Bankruptcy reorganization items		—			—			(96	)		—			—			(96	)
Earnings from unconsolidated investments		7			—			—			—			—			7
Other income and expense, net		9			1			15			12			28			65
EBITDA		779			215			(826	)		60			(155	)		73
Adjustments to reflect Adjusted EBITDA from unconsolidated investment and exclude noncontrolling interest		—			—			2			—			—			2
Acquisition, integration and restructuring costs		—			—			(8	)		—			29			21
Bankruptcy reorganization items		—			—			96			—			—			96
Mark-to-market adjustments, including warrants		(92	)		(44	)		47			—			(6	)		(95	)
Impairments		65			—			793			—			—			858
Loss (gain) on sale of assets, net		—			—			(1	)		—			2			1
Non-cash compensation expense		—			—			6			—			22			28
Other (1)		5			—			20			(1	)		(1	)		23
Adjusted EBITDA	$	757		$	171		$	129		$	59		$	(109	)	$	1,007

(1) Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $23 million.

90

Adjusted EBITDA increased by $153 million. The newly acquired ENGIE plants contributed $216 million in 2017. The offsetting $63 million decrease was primarily driven by lower energy margin, net of hedges, as a result of lower generation volumes driven by milder weather and decreased spark spreads driven by higher gas costs and milder weather at the PJM and NY/NE segments, and decreased dark spreads at the MISO segment and lower retail contribution at the PJM and MISO segments, all driven by milder weather. Please read Discussion of Segment Adjusted EBITDA for further information.

Discussion of Segment Adjusted EBITDA — Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

PJM Segment

The following table provides summary financial data regarding Dynegy’s PJM segment results of operations for the years ended December 31, 2017 and 2016, respectively:

	Year Ended December 31,						Favorable (Unfavorable)
(dollars in millions, except for price information)	2017 (1)			2016			$ Change
Operating Revenues
Energy	$	1,793		$	1,681		$	112
Capacity		493			398			95
Mark-to-market income (loss), net		(83	)		118			(201	)
Contract amortization		(18	)		(47	)		29
Other		77			52			25
Total operating revenues		2,262			2,202			60
Operating Costs
Cost of sales		(1,228	)		(1,033	)		(195	)
Contract amortization		11			48			(37	)
Total operating costs		(1,217	)		(985	)		(232	)
Gross margin		1,045			1,217			(172	)
Operating and maintenance expense		(389	)		(391	)		2
Depreciation expense		(379	)		(346	)		(33	)
Impairments		(49	)		(65	)		16
Loss on sale of assets, net		(36	)		—			(36	)
Other		—			(1	)		1
Operating income		192			414			(222	)
Depreciation and amortization expense		390			349			41
Earnings from unconsolidated investments		3			7			(4	)
Other income and expense, net		16			9			7
EBITDA		601			779			(178	)
Adjustment to reflect Adjusted EBITDA from unconsolidated investment		5			—			5
Mark-to-market adjustments		125			(92	)		217
Impairments		49			65			(16	)
Loss on sale of assets, net		36			—			36
Other		2			5			(3	)
Adjusted EBITDA	$	818		$	757		$	61
Million Megawatt Hours Generated (1)		52.8			52.8			—
IMA (1)(2):
Combined-Cycle Facilities		95	%		97	%
Coal-Fired Facilities		75	%		80	%
Average Capacity Factor (1)(3):
Combined-Cycle Facilities		64	%		74	%
Coal-Fired Facilities		56	%		53	%
CDDs (4)		1,143			1,417			(274	)
HDDs (4)		4,403			4,719			(316	)
Average Market On-Peak Spark Spreads ($/MWh) (5):
PJM West	$	16.90		$	22.62		$	(5.72	)
AD Hub	$	19.22		$	22.52		$	(3.30	)
Average Market On-Peak Power Prices ($/MWh) (6):
PJM West	$	34.38		$	34.65		$	(0.27	)
AD Hub	$	34.00		$	32.93		$	1.07
Average natural gas price—TetcoM3 ($/MMBtu) (7)	$	2.50		$	1.72		$	0.78

91

(1) Includes the activity of the assets acquired in the ENGIE Acquisition for Dynegy’s period of ownership. Million Megawatt Hours Generated and Average Capacity Factor include such activity for the full month of February. IMA excludes such activity for Dynegy’s period of ownership in February.

(2) IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of Dynegy management control such as weather-related issues. The calculation excludes combustion turbines (“CTs”).

(3) Reflects actual production as a percentage of available capacity. The calculation excludes CTs.

(4) Reflects Cooling Degree Days (“CDDs”) or Heating Degree Days (“HDDs”) for the PJM Region based on National Oceanic and Atmospheric Association (“NOAA”) data.

(5) Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to Dynegy.

(6) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices Dynegy realized.

(7) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by Dynegy.

Operating income decreased by $222 million primarily due to the following:

	(in millions)
Income attributable to newly acquired plants in 2017	$	59
Lower energy margin, net of hedges, due to the following:
Lower spark spreads as a result of higher gas costs and milder weather	$	(49	)
Lower generation volumes due to milder weather	$	(23	)
Lower retail contribution as a result of higher supply costs and milder weather	$	(30	)
Higher capacity revenues as a result of higher 2017 pricing and performance penalties in 2016	$	26
Lower O&M costs associated with outages in 2016 and lower costs from long-term service agreements	$	26
Change in MTM value of derivative transactions	$	(200	)
Lower impairment charges	$	16
Loss on sale of assets due to the sale of Lee and the Conesville and Zimmer ownership interest exchange	$	(36	)

Adjusted EBITDA increased by $61 million primarily due to the following:

	(in millions)
Contribution from newly acquired plants in 2017	$	85
Lower energy margin, net of hedges, due to the following:
Lower spark spreads as a result of higher gas costs and milder weather	$	(23	)
Lower generation volumes due to milder weather	$	(37	)
Lower retail contribution as a result of higher supply costs and milder weather	$	(30	)
Higher capacity revenues as a result of higher 2017 pricing and performance penalties in 2016	$	26
Lower O&M costs associated with outages in 2016 and lower costs from long-term service agreements	$	24
Net casualty loss insurance reimbursement	$	7

92

NY/NE Segment

The following table provides summary financial data regarding Dynegy’s NY/NE segment results of operations for the years ended December 31, 2017 and 2016, respectively:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2017 (1)			2016
Operating Revenues
Energy	$	813		$	570		$	243
Capacity		257			168			89
Mark-to-market income (loss), net		(75	)		65			(140	)
Contract amortization		(9	)		(10	)		1
Other		43			44			(1	)
Total operating revenues		1,029			837			192
Operating Costs
Cost of sales		(660	)		(469	)		(191	)
Contract amortization		2			(17	)		19
Total operating costs		(658	)		(486	)		(172	)
Gross margin		371			351			20
Operating and maintenance expense		(170	)		(165	)		(5	)
Depreciation expense		(224	)		(215	)		(9	)
Loss on sale of assets, net		(90	)		—			(90	)
Operating loss		(113	)		(29	)		(84	)
Depreciation and amortization expense		232			243			(11	)
Earnings from unconsolidated investments		5			—			5
Other income and expense, net		—			1			(1	)
EBITDA		124			215			(91	)
Adjustments to reflect Adjusted EBITDA from unconsolidated investment		2			—			2
Mark-to-market adjustments		75			(44	)		119
Loss on sale of assets, net		90			—			90
Other		2			—			2
Adjusted EBITDA	$	293		$	171		$	122
Million Megawatt Hours Generated (1)		19.2			16.9			2.3
IMA for Combined-Cycle Facilities (1)(2)		96	%		96	%
Average Capacity Factor for Combined-Cycle Facilities (1)(3)		43	%		48	%
CDDs (4)		721			884			(163	)
HDDs (4)		5,495			5,593			(98	)
Average Market On-Peak Spark Spreads ($/MWh) (5):
New York—Zone C	$	14.78		$	16.46		$	(1.68	)
Mass Hub	$	12.09		$	13.80		$	(1.71	)
Average Market On-Peak Power Prices ($/MWh) (6):
New York—Zone C	$	29.56		$	26.88		$	2.68
Mass Hub	$	37.83		$	35.52		$	2.31
Average natural gas price—Algonquin Citygates ($/MMBtu) (7)	$	3.68		$	3.10		$	0.58

93

(1) Includes the activity of the assets acquired in the ENGIE Acquisition for Dynegy’s period of ownership. Million Megawatt Hours Generated and Average Capacity Factor include such activity for the full month of February. IMA excludes such activity for our period of ownership in February.

(2) IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of Dynegy management control such as weather-related issues. The calculation excludes Dynegy’s Brayton Point facility.

(3) Reflects actual production as a percentage of available capacity. The calculation excludes Dynegy’s Brayton Point facility.

(4) Reflects CDDs or HDDs for the ISO-NE Region based on NOAA data.

(5) Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to Dynegy.

(6) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices Dynegy realized.

(7) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by Dynegy.

Operating loss increased by $84 million primarily due to the following:

	(in millions)
Income attributable to newly acquired plants in 2017	$	26
Lower energy margin, net of hedges, due to lower generation volumes as a result of milder weather and the retirement of Dynegy’s Brayton Point facility	$	(8	)
Higher capacity revenues as a result of higher 2017 pricing, offset by capacity lost due to the retirement of Dynegy’s Brayton Point facility	$	25
Change in MTM value of derivative transactions	$	(128	)
Lower contract amortization	$	22
Lower O&M costs associated with planned major maintenance outages and as a result of the retirement of Dynegy’s Brayton Point facility	$	20
Lower depreciation primarily due to the retirement of Dynegy’s Brayton Point facility	$	48
Loss on sale of Dynegy’s Dighton and Milford-MA facilities	$	(90	)

Adjusted EBITDA increased by $122 million primarily due to the following:

	(in millions)
Contribution from newly acquired plants in 2017	$	105
Lower energy margin, net of hedges, due to the following:
Lower spark spreads, net of hedges as a result of higher gas costs and milder weather	$	(22	)
Lower generation volumes as a result of milder weather and the retirement of Dynegy’s Brayton Point facility	$	(10	)
Higher capacity revenues as a result of higher 2017 pricing, offset by capacity lost due to the retirement of Dynegy’s Brayton Point facility	$	25
Lower O&M costs associated with planned major maintenance outages and as a result of the retirement of Dynegy’s Brayton Point facility	$	20

94

ERCOT Segment

The ERCOT segment includes the results of operations since the ENGIE Acquisition Closing Date. The following table provides summary financial data regarding Dynegy’s ERCOT segment for the year ended December 31, 2017:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2017			2016
Operating revenues
Energy	$	366		$	—			N/A
Mark-to-market loss, net		(99	)		—			N/A
Other		10			—			N/A
Total operating revenues		277			—			N/A
Operating costs
Cost of sales		(256	)		—			N/A
Total operating costs		(256	)		—			N/A
Gross margin		21			—			N/A
Operating and maintenance expense		(95	)		—			N/A
Depreciation expense		(73	)		—			N/A
Operating loss		(147	)		—			N/A
Depreciation and amortization expense		74			—			N/A
EBITDA		(73	)		—			N/A
Mark-to-market adjustments		99			—			N/A
Adjusted EBITDA	$	26		$	—			N/A
Million Megawatt Hours Generated (1)		11.0			—			N/A
IMA (1)(2):
Combined-Cycle Facilities		94	%		—	%
Coal-Fired Facility		96	%		—	%
Average Capacity Factor (1)(3):
Combined-Cycle Facilities		25	%		—	%
Coal-Fired Facility		67	%		—	%
CDDs (4)		3,390			3,355			35
HDDs (4)		1,090			1,222			(132	)
Average Market On-Peak Spark Spreads ($/MWh) (5):
ERCOT North	$	7.79		$	9.79		$	(2.00	)
Average Market On-Peak Power Prices ($/MWh) (6):
ERCOT North	$	26.45		$	26.02		$	0.43
Average natural gas price—Waha Hub ($/MMBtu) (7)	$	2.67		$	2.32		$	0.35

95

(1) Million Megawatt Hours Generated and Average Capacity Factor include such activity for the full month of February. IMA excludes such activity for Dynegy’s period of ownership in February.

(2) IMA is an internal measurement calculation that reflects the percentage of generation available when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of Dynegy management control such as weather-related issues. The calculation excludes CTs.

(3) Reflects actual production as a percentage of available capacity. The calculation excludes CTs.

(4) Reflects CDDs or HDDs for the ERCOT Region based on NOAA data.

(5) Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to Dynegy.

(6) Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices Dynegy realized.

(7) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by Dynegy.

Operating loss of $147 million primarily consisted of the following:

	(in millions)
Energy margin, net of hedges	$	110
MTM loss	$	(99	)
Ancillary sales	$	8
O&M costs	$	(95	)
Depreciation expense	$	(73	)

Adjusted EBITDA was $26 million primarily related to the following:

	(in millions)
Energy margin, net of hedges	$	110
Ancillary sales	$	8
O&M costs	$	(94	)

96

MISO Segment

The following table provides summary financial data regarding Dynegy’s MISO segment results of operations for the years ended December 31, 2017 and 2016, respectively:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2017			2016
Operating Revenues
Energy	$	920		$	1,027		$	(107	)
Capacity		210			163			47
Mark-to-market income (loss), net		21			(47	)		68
Contract amortization		(6	)		(13	)		7
Other		7			7			—
Total operating revenues		1,152			1,137			15
Operating Costs
Cost of sales		(731	)		(762	)		31
Contract amortization		8			21			(13	)
Total operating costs		(723	)		(741	)		18
Gross margin		429			396			33
Operating and maintenance expense		(300	)		(347	)		47
Depreciation expense		(75	)		(81	)		6
Impairments		(99	)		(793	)		694
Gain on sale of assets, net		1			1			—
Acquisition and integration costs		—			8			(8	)
Other		—			(16	)		16
Operating loss		(44	)		(832	)		788
Depreciation and amortization expense		91			87			4
Bankruptcy reorganization items		494			(96	)		590
Other income and expense, net		26			15			11
EBITDA		567			(826	)		1,393
Adjustments to reflect Adjusted EBITDA from noncontrolling interest		2			2			—
Acquisition, integration, restructuring and bankruptcy reorganization costs		—			(8	)		8
Bankruptcy reorganization items		(494	)		96			(590	)
Mark-to-market adjustments		(21	)		47			(68	)
Impairments		99			793			(694	)
Gain on sale of assets, net		(1	)		(1	)		—
Non-cash compensation expense		1			6			(5	)
Other (1)		(1	)		20			(21	)
Adjusted EBITDA	$	152		$	129		$	23
Million Megawatt Hours Generated		29.1			29.8			(0.7	)
IMA for Coal-Fired Facilities (2)		89	%		89	%
Average Capacity Factor for Coal-Fired Facilities (3)		63	%		53	%
CDDs (4)		1,272			1,652			(380	)
HDDs (4)		4,534			4,662			(128	)
Average Market On-Peak Power Prices ($/MWh) (5):
Indiana (Indy Hub)	$	34.36		$	33.71		$	0.65
Commonwealth Edison (NI Hub)	$	32.28		$	31.98		$	0.30

97

(1) Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $23 million for the year ended December 31, 2016. Adjusted EBITDA did not include this adjustment for the year ended December 31, 2017.

(2) IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of Dynegy management control such as weather-related issues.

(3) Reflects actual production as a percentage of available capacity.

(4) Reflects CDDs or HDDs for the MISO Region based on NOAA data.

(5) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

Operating loss decreased by $788 million primarily due to the following:

	(in millions)
Lower energy margin due to the following:
Lower dark spreads, net of hedges, as a result of milder weather, and higher fuel and transportation costs	$	(47	)
Lower generation volumes as a result of shutdowns in 2016	$	(4	)
Lower retail contribution as a result of milder weather	$	(43	)
Change in fuel and transportation costs related to Wood River	$	14
Change in fuel costs as a result of a coal inventory adjustment in 2016	$	7
Higher capacity revenues due to higher pricing and volumes, including revenues related to PJM pseudo-ties	$	47
Change in MTM value of derivative transactions	$	68
Termination of an above market coal supply contract in 2016	$	15
Lower O&M costs primarily due to shutdowns in 2016, ARO accretion, property taxes, and fewer outages	$	47
Absence of impairment charges primarily due to Dynegy’s Baldwin and Newton facilities in 2016	$	694

Adjusted EBITDA increased by $23 million primarily due to the following:

	(in millions)
Lower energy margin, net of hedges, due to the following:
Lower dark spreads, net of hedges, as a result of milder weather, and higher fuel and transportation costs	$	(48	)
Lower retail contribution as a result of milder weather	$	(43	)
Change in fuel costs as a result of a coal inventory adjustment in 2016	$	6
Higher capacity revenues due to higher pricing and volumes, including revenues related to PJM pseudo-ties	$	47
AER proceeds	$	25
Lower O&M costs primarily due to shutdowns in 2016, property taxes, and fewer outages	$	31

98

CAISO Segment

The following table provides summary financial data regarding Dynegy’s CAISO segment results of operations for the years ended December 31, 2017 and 2016, respectively:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2017			2016
Operating Revenues
Energy	$	108		$	88		$	20
Capacity		18			40			(22	)
Mark-to-market loss, net		(7	)		—			(7	)
Contract amortization		—			(10	)		10
Other		3			24			(21	)
Total operating revenues		122			142			(20	)
Operating Costs
Cost of sales		(78	)		(69	)		(9	)
Total operating costs		(78	)		(69	)		(9	)
Gross margin		44			73			(29	)
Operating and maintenance expense		(39	)		(36	)		(3	)
Depreciation expense		(53	)		(42	)		(11	)
Gain on sale of assets, net		3			—			3
Operating loss		(45	)		(5	)		(40	)
Depreciation and amortization expense		57			53			4
Other income and expense, net		—			12			(12	)
EBITDA		12			60			(48	)
Mark-to-market adjustments		7			—			7
Other		—			(1	)		1
Adjusted EBITDA	$	19		$	59		$	(40	)
Million Megawatt Hours Generated		2.3			2.6			(0.3	)
IMA for Combined-Cycle Facilities (1)		92	%		96	%
Average Capacity Factor for Combined-Cycle Facilities (2)		26	%		27	%
CDDs (3)		1,337			1,211			126
HDDs (3)		1,233			1,218			15
Average Market On-Peak Spark Spreads ($/MWh) (4):
North of Path 15 (NP 15)	$	15.38		$	12.67		$	2.71
Average Market On-Peak Power Prices ($/MWh) (5):
North of Path 15 (NP 15)	$	38.02		$	31.60		$	6.42
Average natural gas price—PG&E Citygate ($/MMBtu) (6)	$	3.23		$	2.70		$	0.53

99

(1) IMA is an internal measurement calculation that reflects the percentage of generation available when market prices are such that these units could be profitably dispatched. This calculation excludes certain events outside of Dynegy’s management control such as weather-related issues. The calculation excludes CTs.

(2) Reflects actual production as a percentage of available capacity. The calculation excludes CTs.

(3) Reflects CDDs or HDDs for the ISO-NE Region based on NOAA data.

(4) Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to Dynegy.

(5) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices Dynegy realized.

(6) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by Dynegy.

Operating loss increased by $40 million primarily due to the following:

	(in millions)
Higher energy margin, net of hedges, due to higher spark spreads as a result of warmer weather	$	12
Lower capacity revenues due to lower volumes and prices	$	(22	)
Lower tolling revenue due to expiration of tolling agreement	$	(19	)
Change in MTM value of derivative transactions	$	(7	)
Higher O&M costs due to higher ARO accretion	$	(3	)
Higher depreciation and amortization	$	(2	)

100

Adjusted EBITDA decreased by $40 million primarily due to the following:

	(in millions)
Higher energy margin, net of hedges, due to higher spark spreads as a result of warmer weather	$	12
Lower capacity revenues due to lower volumes and prices	$	(22	)
Lower tolling revenue due to expiration of tolling agreement in 2016	$	(19	)
Supplier settlement in 2016	$	(12	)

Consolidated Summary Financial Information—Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Dynegy completed the EquiPower Acquisition and Duke Midwest Acquisition on April 1, 2015 and April 2, 2015, respectively; therefore, the results of these plants within Dynegy’s PJM and NY/NE segments are only included in Dynegy’s consolidated results from their respective acquisition dates. Please read Note 3 to Dynegy’s Consolidated Financial Statements—Acquisitions and Divestitures—EquiPower Acquisition and Duke Midwest Acquisition for further discussion. The following table provides summary financial data regarding Dynegy’s consolidated results of operations for the years ended December 31, 2016 and 2015, respectively:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(amounts in millions)	2016			2015
Revenues
Energy	$	3,366		$	3,083		$	283
Capacity		769			626			143
Mark-to-market income, net		136			127			9
Contract amortization		(80	)		(83	)		3
Other		127			117			10
Total revenues		4,318			3,870			448
Cost of sales, excluding depreciation expense		(2,281	)		(2,028	)		(253	)
Gross margin		2,037			1,842			195
Operating and maintenance expense		(940	)		(839	)		(101	)
Depreciation expense		(689	)		(587	)		(102	)
Impairments		(858	)		(99	)		(759	)
Loss on sale of assets, net		(1	)		(1	)		—
General and administrative expense		(161	)		(128	)		(33	)
Acquisition and integration costs		(11	)		(124	)		113
Other		(17	)		—			(17	)
Operating income (loss)		(640	)		64			(704	)
Bankruptcy reorganization items		(96	)		—			(96	)
Earnings from unconsolidated investments		7			1			6
Interest expense		(625	)		(546	)		(79	)
Other income and expense, net		65			54			11
Loss before income taxes		(1,289	)		(427	)		(862	)
Income tax benefit		45			474			(429	)
Net income (loss)		(1,244	)		47			(1,291	)
Less: Net loss attributable to noncontrolling interest		(4	)		(3	)		(1	)
Net income (loss) attributable to Dynegy Inc.	$	(1,240	)	$	50		$	(1,290	)

101

The following tables provide summary financial data regarding Dynegy’s operating income (loss) by segment for the years ended December 31, 2016 and 2015, respectively:

	Year Ended December 31, 2016
(amounts in millions)	PJM			NY/NE			MISO			CAISO			Other			Total
Revenues	$	2,202		$	837		$	1,137		$	142		$	—		$	4,318
Cost of sales, excluding depreciation expense		(985	)		(486	)		(741	)		(69	)		—			(2,281	)
Gross margin		1,217			351			396			73			—			2,037
Operating and maintenance expense		(391	)		(165	)		(347	)		(36	)		(1	)		(940	)
Depreciation expense		(346	)		(215	)		(81	)		(42	)		(5	)		(689	)
Impairments		(65	)		—			(793	)		—			—			(858	)
Gain (loss) on sale of assets, net		—			—			1			—			(2	)		(1	)
General and administrative expense		—			—			—			—			(161	)		(161	)
Acquisition and integration costs		—			—			8			—			(19	)		(11	)
Other		(1	)		—			(16	)		—			—			(17	)
Operating income (loss)	$	414		$	(29	)	$	(832	)	$	(5	)	$	(188	)	$	(640	)

102

	Year Ended December 31, 2015
(amounts in millions)	PJM			NY/NE			MISO			CAISO			Other			Total
Revenues	$	1,716		$	695		$	1,281		$	178		$	—		$	3,870
Cost of sales, excluding depreciation expense		(716	)		(414	)		(793	)		(105	)		—			(2,028	)
Gross margin		1,000			281			488			73			—			1,842
Operating and maintenance expense		(296	)		(126	)		(389	)		(32	)		4			(839	)
Depreciation expense		(281	)		(186	)		(68	)		(48	)		(4	)		(587	)
Impairments		—			(25	)		(74	)		—			—			(99	)
Loss on sale of assets, net		—			—			—			(1	)		—			(1	)
General and administrative expense		—			—			—			—			(128	)		(128	)
Acquisition and integration costs		—			—			—			—			(124	)		(124	)
Operating income (loss)	$	423		$	(56	)	$	(43	)	$	(8	)	$	(252	)	$	64

Discussion of Consolidated Results of Operations

Revenues. The following table summarizes the change in revenues by segment:

(amounts in millions)	PJM			NY/NE			MISO			CAISO			Total
Revenues, net of hedges, attributable to Duke Midwest and EquiPower plants for the first quarter of 2016	$	467		$	194		$	—		$	—		$	661
Lower power prices and spark spreads		(66	)		(26	)		(13	)		—			(105	)
Higher (lower) generation volumes (1)		122			(64	)		(139	)		(39	)		(120	)
Higher (lower) capacity revenues		(36	)		(17	)		67			9			23
Change in MTM value of derivative transactions		(61	)		41			(63	)		(4	)		(87	)
Lower (higher) contract amortization		9			(4	)		12			(3	)		14
Other (2)		51			18			(8	)		1			62
Total change in revenues	$	486		$	142		$	(144	)	$	(36	)	$	448

(1) Decrease due to mild winter weather which decreased demand across Dynegy’s key markets as well as planned outages and shutdowns; PJM segment increased due to higher demand for gas-fired generation as a result of lower gas prices.

(2) Other primarily consists of ancillary, tolling, transmission and gas revenues.

103

Cost of Sales. The following table summarizes the change in cost of sales by segment:

(amounts in millions)	PJM			NY/NE			MISO			CAISO			Total
Cost of sales attributable to Duke Midwest and EquiPower plants for the first quarter of 2016	$	157		$	128		$	—		$	—		$	285
Higher (lower) prices		(95	)		(13	)		23			(7	)		(92	)
Higher (lower) burn volumes (1)		133			(23	)		(101	)		(19	)		(10	)
Higher (lower) transportation costs (2)		3			(16	)		—			(1	)		(14	)
Lower (higher) contract amortization		20			(3	)		16			—			33
Other (3)		51			(1	)		10			(9	)		51
Total change in cost of sales	$	269		$	72		$	(52	)	$	(36	)	$	253

(1) Lower burn volumes primarily due to mild winter weather which decreased demand across Dynegy’s key markets as well as planned outages and shutdowns; PJM segment increased as a result of higher plant availability and demand.

(2) Lower transportation costs primarily at Dynegy’s NY/NE segment due to reduced demand charge payment at Independence.

(3) Other primarily consists of transmission expenses, gas purchases, and various non-recurring expenses.

Operating and Maintenance Expense. Operating and maintenance expense increased by $101 million primarily due to the Duke Midwest and EquiPower plants for the first quarter of 2016 and planned major maintenance outages at Dynegy’s PJM and NY/NE segments, partially offset by a decrease primarily due to plant shutdowns at Dynegy’s MISO segment.

Depreciation Expense. Depreciation expense increased by $102 million primarily due to Duke Midwest and EquiPower plants for the first quarter of 2016, offset by a decrease due to a lower depreciable base of certain generation facilities as a result of impairments at Dynegy’s MISO and NY/NE segments.

Impairments. Impairments increased by $759 million due to the following (amounts in millions):

	Year Ended December 31,
Description	2016		2015
Property, plant and equipment	$	849	$	99
Equity investment		9		—
Total	$	858	$	99

104

Please read Note 8 to Dynegy’s Consolidated Financial Statements—Property, Plant and Equipment and Note 10 to Dynegy’s Consolidated Financial Statements—Unconsolidated Investments for further discussion.

General and Administrative Expense. General and administrative expense increased by $33 million primarily due to higher overhead associated with the Duke Midwest and EquiPower acquisitions and higher legal fees primarily related to costs associated with the Genco reorganization that were incurred prior to Genco’s filing of the Bankruptcy Petition. Please read Note 20 to Dynegy’s Consolidated Financial Statements—Genco Chapter 11 Bankruptcy for further discussion.

Acquisition and Integration Costs. Acquisition and integration costs decreased by $113 million due to $53 million in lower advisory and consulting fees, $12 million in severance, retention, and payroll costs, and $48 million in Bridge Loan financing fees related to the Duke Midwest Acquisition and EquiPower Acquisition in 2015.

Other. Other of $17 million for the year ended December 31, 2016 is primarily due to a charge associated with the termination of an above market coal supply contract.

Bankruptcy Reorganization Items. Bankruptcy reorganization items increased by $96 million primarily due to the write-off of the remaining unamortized discount related to the Genco senior notes and legal costs associated with the Genco reorganization that were incurred after Genco’s filing of its petition under title 11 of the United States Code (the “Bankruptcy Petition”). Please read Note 20 to Dynegy’s Consolidated Financial Statements—Genco Chapter 11 Bankruptcy for further discussion.

Interest Expense. Interest expense increased by $79 million primarily due to interest on the Term Loan, newly issued senior notes, and Amortizing Notes. Please read Note 13 to Dynegy’s Consolidated Financial Statements—Debt for further discussion.

Other Income and Expense, Net. Other income and expense, net increased by $11 million primarily due to:

	(in millions)
Gain related to the Ponderosa Pine Energy, LLC settlement	$	20
Previously contingent proceeds received related to the AER Acquisition	$	14
Supplier settlement	$	12
Casualty loss insurance reimbursement, net	$	11
Change in fair value of Dynegy’s common stock warrants	$	(48	)

Income Tax Benefit. Income tax benefit decreased by $429 million as a result of a $459 million benefit due to a release of the valuation allowance that occurred during the year ended December 31, 2015. The remaining $30 million favorable change was for discrete items including a 2016 change in Dynegy’s corporate tax structure, a 2015 state law change in Connecticut, the benefit from accelerating the minimum tax credit and the application of Dynegy’s effective state tax rates for jurisdictions for which Dynegy does not record a valuation allowance.

As of December 31, 2016, Dynegy continued to maintain a valuation allowance against its net deferred tax assets in each jurisdiction as they arise as there was not sufficient evidence to overcome Dynegy’s historical cumulative losses to conclude that it is more likely than not that Dynegy’s net deferred tax assets can be realized in the future. Please read Note 14 to Dynegy’s Consolidated Financial Statements—Income Taxes for further discussion.

105

Net Income (Loss) Attributable to Dynegy Inc. The $1.290 billion decrease was primarily due to (i) $759 million in higher impairment charges recorded in 2016 compared to 2015, and (ii) income from a $459 million deferred tax valuation allowance release in 2015, which did not reoccur in 2016, partially offset by a $156 million contribution from Duke Midwest and EquiPower plants in the first quarter of 2016.

Adjusted EBITDA — Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

The following table provides summary financial data regarding Dynegy’s Adjusted EBITDA by segment for the year ended December 31, 2016:

	Year Ended December 31, 2016
(amounts in millions)	PJM			NY/NE			MISO			CAISO			Other			Total
Net loss																$	(1,244	)
Income tax benefit																	(45	)
Other income and expense, net																	(65	)
Interest expense																	625
Earnings from unconsolidated investments																	(7	)
Bankruptcy reorganization items																	96
Operating income (loss)	$	414		$	(29	)	$	(832	)	$	(5	)	$	(188	)	$	(640	)
Depreciation and amortization expense		349			243			87			53			5			737
Bankruptcy reorganization items		—			—			(96	)		—			—			(96	)
Earnings from unconsolidated investments		7			—			—			—			—			7
Other income and expense, net		9			1			15			12			28			65
EBITDA		779			215			(826	)		60			(155	)		73
Adjustments to reflect Adjusted EBITDA from unconsolidated investment and exclude noncontrolling interest		—			—			2			—			—			2
Acquisition and integration costs		—			—			(8	)		—			29			21
Bankruptcy reorganization items		—			—			96			—			—			96
Mark-to-market adjustments, including warrants		(92	)		(44	)		47			—			(6	)		(95	)
Impairments		65			—			793			—			—			858
Loss (gain) on sale of assets, net		—			—			(1	)		—			2			1
Non-cash compensation expense		—			—			6			—			22			28
Other (1)		5			—			20			(1	)		(1	)		23
Adjusted EBITDA	$	757		$	171		$	129		$	59		$	(109	)	$	1,007

(1) Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $23 million.    

106

The following table provides summary financial data regarding Dynegy’s Adjusted EBITDA by segment for the year ended December 31, 2015:

	Year Ended December 31, 2015
(amounts in millions)	PJM			NY/NE			MISO			CAISO			Other			Total
Net income																$	47
Income tax benefit																	(474	)
Other income and expense, net																	(54	)
Interest expense																	546
Earnings from unconsolidated investments																	(1	)
Operating income (loss)	$	423		$	(56	)	$	(43	)	$	(8	)	$	(252	)	$	64
Depreciation and amortization expense		275			195			73			55			4			602
Earnings from unconsolidated investments		1			—			—			—			—			1
Other income and expense, net		(2	)		—			1			—			55			54
EBITDA		697			139			31			47			(193	)		721
Adjustments to reflect Adjusted EBITDA from unconsolidated investment and exclude noncontrolling interest		12			—			3			—			—			15
Acquisition and integration costs		—			—			—			—			124			124
Mark-to-market adjustments, including warrants		(58	)		11			(16	)		(4	)		(54	)		(121	)
Impairments		—			25			74			—			—			99
Loss on sale of assets, net		—			—			—			1			—			1
Other (1)		(2	)		—			12			—			1			11
Adjusted EBITDA (2)	$	649		$	175		$	104		$	44		$	(122	)	$	850

(1) Other includes an adjustment to exclude costs related to the Baldwin transformer project of $7 million.

(2) Not adjusted for the following items which are excluded in 2016: (i) non-cash compensation expense of $27 million, and (ii) Wood River’s energy margin and O&M costs of $13 million.

107

Adjusted EBITDA increased by $157 million primarily due to a $209 million contribution from Duke Midwest and EquiPower plants in the first quarter of 2016. The offsetting $52 million decrease was driven by (i) lower energy margin, net of hedges, at the NY/NE and CAISO segments as a result of mild winter weather which decreased demand across Dynegy’s key markets and lowered power prices and spark spreads, (ii) lower energy margin, net of hedges, at the MISO segment due to higher fuel costs as a result of the 2015 coal inventory management efforts and an inventory flyover adjustment, and (iii) lower capacity revenues as a result of performance penalties and lower pricing at the PJM segment and lower pricing at the NY/NE segment. Please read Discussion of Segment Adjusted EBITDA for further information.

Discussion of Segment Adjusted EBITDA — Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

PJM Segment

The following table provides summary financial data regarding Dynegy’s PJM segment results of operations for the years ended December 31, 2016 and 2015, respectively:

	Year Ended December 31,						Favorable (Unfavorable)
(dollars in millions, except for price information)	2016			2015			$ Change
Operating Revenues
Energy	$	1,681		$	1,257		$	424
Capacity		398			345			53
Mark-to-market income, net		118			105			13
Contract amortization		(47	)		(47	)		—
Other		52			56			(4	)
Total operating revenues		2,202			1,716			486
Operating Costs
Cost of sales		(1,033	)		(771	)		(262	)
Contract amortization		48			55			(7	)
Total operating costs		(985	)		(716	)		(269	)
Gross margin		1,217			1,000			217
Operating and maintenance expense		(391	)		(296	)		(95	)
Depreciation expense		(346	)		(281	)		(65	)
Impairments		(65	)		—			(65	)
Other		(1	)		—			(1	)
Operating income		414			423			(9	)
Depreciation and amortization expense		349			275			74
Earnings from unconsolidated investments		7			1			6
Other income and expense, net		9			(2	)		11
EBITDA		779			697			82
Adjustment to reflect Adjusted EBITDA from unconsolidated investment		—			12			(12	)
Mark-to-market adjustments		(92	)		(58	)		(34	)
Impairments		65			—			65
Other		5			(2	)		7
Adjusted EBITDA	$	757		$	649		$	108
Million Megawatt Hours Generated (1)		52.8			40.4			12.4
IMA (1)(2):
Combined-Cycle Facilities		97	%		99	%
Coal-Fired Facilities		80	%		74	%
Average Capacity Factor (1)(3):
Combined-Cycle Facilities		74	%		75	%
Coal-Fired Facilities		53	%		51	%
CDDs (4)		1,417			1,218			199
HDDs (4)		4,719			4,992			(273	)
Average Market On-Peak Spark Spreads ($/MWh) (5):
PJM West	$	22.62		$	25.24		$	(2.62	)
AD Hub	$	22.52		$	28.22		$	(5.70	)
Average Market On-Peak Power Prices ($/MWh) (6):
PJM West	$	34.65		$	43.21		$	(8.56	)
AD Hub	$	32.93		$	37.52		$	(4.59	)
Average natural gas price—TetcoM3 ($/MMBtu) (7)	$	1.72		$	2.57		$	(0.85	)

108

(1) Reflects the activity for the period in which the EquiPower and Duke Midwest acquisitions were included in Dynegy’s consolidated results.

(2) IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of Dynegy management control such as weather-related issues. The calculation excludes CTs.

(3) Reflects actual production as a percentage of available capacity. The calculation excludes CTs.

(4) Reflects CDDs or HDDs for the PJM Region based on NOAA data.

(5) Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to Dynegy.

(6) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices Dynegy realized.

(7) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by Dynegy.

Operating income decreased $9 million primarily due to the following:

	(in millions)
Contribution from Duke Midwest and EquiPower plants in the first quarter of 2016	$	174
Lower capacity revenues as a result of lower pricing and performance penalties	$	(36	)
Change in MTM value of derivative transactions	$	(61	)
Higher O&M costs associated with planned major maintenance outages	$	(25	)
Impairment charges incurred in 2016	$	(65	)

Adjusted EBITDA increased by $108 million primarily due to the following:

	(in millions)
Contribution from Duke Midwest and EquiPower plants in the first quarter of 2016	$	170
Higher energy margin, net of hedges, due to the following:
Higher generation volumes as a result of higher plant availability	$	21
Lower power prices and spark spreads as a result of mild weather	$	(10	)
Lower capacity revenues as a result of lower pricing and performance penalties	$	(36	)
Higher O&M costs associated with planned major maintenance outages	$	(23	)

109

NY/NE Segment

The following table provides summary financial data regarding Dynegy’s NY/NE segment results of operations for the years ended December 31, 2016 and 2015, respectively:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2016			2015
Operating Revenues
Energy	$	570		$	524		$	46
Capacity		168			154			14
Mark-to-market income, net		65			2			63
Contract amortization		(10	)		(4	)		(6	)
Other		44			19			25
Total operating revenues		837			695			142
Operating Costs
Cost of sales		(469	)		(410	)		(59	)
Contract amortization		(17	)		(4	)		(13	)
Total operating costs		(486	)		(414	)		(72	)
Gross margin		351			281			70
Operating and maintenance expense		(165	)		(126	)		(39	)
Depreciation expense		(215	)		(186	)		(29	)
Impairments		—			(25	)		25
Operating loss		(29	)		(56	)		27
Depreciation and amortization expense		243			195			48
Other income and expense, net		1			—			1
EBITDA		215			139			76
Mark-to-market adjustments		(44	)		11			(55	)
Impairments		—			25			(25	)
Adjusted EBITDA	$	171		$	175		$	(4	)
Million Megawatt Hours Generated (1)		16.9			15.7			1.2
IMA for Combined-Cycle Facilities (1)(2)		96	%		98	%
Average Capacity Factor for Combined-Cycle Facilities (1)(3)		48	%		56	%
CDDs (4)		884			820			64
HDDs (4)		5,593			6,056			(463	)
Average Market On-Peak Spark Spreads ($/MWh) (5):
New York—Zone C	$	16.46		$	24.76		$	(8.30	)
Mass Hub	$	13.80		$	15.23		$	(1.43	)
Average Market On-Peak Power Prices ($/MWh) (6):
New York—Zone C	$	26.88		$	35.05		$	(8.17	)
Mass Hub	$	35.52		$	48.96		$	(13.44	)
Average natural gas price—Algonquin Citygates ($/MMBtu) (7)	$	3.10		$	4.82		$	(1.72	)

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(1) Reflects the activity for the period in which the EquiPower and Duke Midwest acquisitions were included in Dynegy’s consolidated results.

(2) IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of Dynegy management control such as weather-related issues. The calculation excludes Dynegy’s Brayton Point facility.

(3) Reflects actual production as a percentage of available capacity. The calculation excludes Dynegy’s Brayton Point facility.

(4) Reflects CDDs or HDDs for the ISO-NE Region based on NOAA data.

(5) Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to Dynegy.

(6) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices Dynegy realized.

(7) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by Dynegy.

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Operating loss decreased $27 million primarily due to the following:

	(in millions)
Loss attributable to Duke Midwest and EquiPower plants in the first quarter of 2016	$	(16	)
Lower energy margin, net of hedges, due to lower spark spreads and lower generation volumes	$	(39	)
Higher O&M costs associated with planned major maintenance outages	$	(8	)
Change in MTM value of derivative transactions	$	41
Impairment charges incurred in 2015	$	25
Lower depreciation due to a fourth quarter 2015 impairment of Dynegy’s Brayton Point facility	$	22

Adjusted EBITDA decreased by $4 million primarily due to the following:

	(in millions)
Contribution from Duke Midwest and EquiPower plants in the first quarter of 2016	$	39
Lower energy margin, net of hedges, due to the following:
Lower spark spreads as a result of mild winter weather	$	(14	)
Lower generation volumes as a result of more planned outages	$	(25	)
Lower capacity revenues as a result of lower pricing	$	(17	)
Higher tolling revenues as a result of a 2016 tolling contract	$	12
Higher O&M costs associated with planned major maintenance outages	$	(5	)

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MISO Segment

The following table provides summary financial data regarding Dynegy’s MISO segment results of operations for the years ended December 31, 2016 and 2015, respectively:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2016			2015
Operating Revenues
Energy	$	1,027		$	1,177		$	(150	)
Capacity		163			96			67
Mark-to-market income (loss), net		(47	)		16			(63	)
Contract amortization		(13	)		(25	)		12
Other		7			17			(10	)
Total operating revenues		1,137			1,281			(144	)
Operating Costs
Cost of sales		(762	)		(830	)		68
Contract amortization		21			37			(16	)
Total operating costs		(741	)		(793	)		52
Gross margin		396			488			(92	)
Operating and maintenance expense		(347	)		(389	)		42
Depreciation expense		(81	)		(68	)		(13	)
Impairments		(793	)		(74	)		(719	)
Gain on sale of assets, net		1			—			1
Acquisition and integration costs		8			—			8
Other		(16	)		—			(16	)
Operating loss		(832	)		(43	)		(789	)
Depreciation and amortization expense		87			73			14
Bankruptcy reorganization items		(96	)		—			(96	)
Other income and expense, net		15			1			14
EBITDA		(826	)		31			(857	)
Adjustments to reflect Adjusted EBITDA from noncontrolling interest		2			3			(1	)
Acquisition, integration and restructuring costs		(8	)		—			(8	)
Bankruptcy reorganization items		96			—			96
Mark-to-market adjustments		47			(16	)		63
Impairments		793			74			719
Gain on sale of assets, net		(1	)		—			(1	)
Non-cash compensation expense		6			—			6
Other (1)		20			12			8
Adjusted EBITDA	$	129		$	104		$	25
Million Megawatt Hours Generated		29.8			34.4			(4.6	)
IMA for Coal-Fired Facilities (2)		89	%		88	%
Average Capacity Factor for Coal-Fired Facilities (3)		53	%		56	%
CDDs (4)		1,652			1,425			227
HDDs (4)		4,662			5,061			(399	)
Average Market On-Peak Power Prices ($/MWh) (5):
Indiana (Indy Hub)	$	33.71		$	33.50		$	0.21
Commonwealth Edison (NI Hub)	$	31.98		$	33.98		$	(2.00	)

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(1) Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $23 million for the year ended December 31, 2016. Adjusted EBITDA did not include this adjustment for the year ended December 31, 2015.

(2) IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of Dynegy management control such as weather-related issues.

(3) Reflects actual production as a percentage of available capacity.

(4) Reflects CDDs or HDDs for the MISO Region based on NOAA data.

(5) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices Dynegy realized.

Operating loss increased by $789 million primarily due to the following:

	(in millions)
Lower energy margin due to the following:
Lower dark spreads, net of hedges as a result of mild winter weather	$	(33	)
Lower generation volumes as a result of mild winter weather and shutdowns in 2016	$	(28	)
Lower retail contribution as a result of milder weather	$	(4	)
Coal inventory adjustments at Baldwin & Wood River	$	(7	)
Fuel and transportation costs related to Wood River shutdown	$	(14	)
Higher capacity revenues as a result of higher pricing and volumes	$	67
Change in MTM value of derivative transactions	$	(63	)
Termination of an above market coal supply contract in 2016	$	(15	)
Lower O&M costs due to shutdowns in 2016 and fewer outages	$	42
Higher depreciation and amortization	$	(17	)
Higher impairment charges primarily due to Dynegy’s Baldwin and Newton facilities in 2016	$	(719	)

Adjusted EBITDA increased by $25 million primarily due to the following:

	(in millions)
Lower energy margin due to the following:
Lower dark spreads, net of hedges as a result of mild winter weather	$	(25	)
Lower generation volumes as a result of mild winter weather and shutdowns in 2016	$	(28	)
Lower retail contribution as a result of milder weather	$	(4	)
Higher fuel costs incurred in 2016 as a result of 2015 coal inventory management efforts and a coal inventory adjustment	$	(13	)
Higher capacity revenues as a result of higher pricing and volumes	$	67
Lower O&M costs due to fewer outages	$	27

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CAISO Segment

The following table provides summary financial data regarding Dynegy’s CAISO segment results of operations for the years ended December 31, 2016 and 2015, respectively:

	Year Ended December 31,						Favorable (Unfavorable) $ Change
(dollars in millions, except for price information)	2016			2015
Operating Revenues
Energy	$	88		$	125		$	(37	)
Capacity		40			31			9
Mark-to-market income, net		—			4			(4	)
Contract amortization		(10	)		(7	)		(3	)
Other		24			25			(1	)
Total operating revenues		142			178			(36	)
Operating Costs
Cost of sales		(69	)		(105	)		36
Total operating costs		(69	)		(105	)		36
Gross margin		73			73			—
Operating and maintenance expense		(36	)		(32	)		(4	)
Depreciation expense		(42	)		(48	)		6
Loss on sale of assets, net		—			(1	)		1
Operating loss		(5	)		(8	)		3
Depreciation and amortization expense		53			55			(2	)
Other income and expense, net		12			—			12
EBITDA		60			47			13
Mark-to-market adjustments		—			(4	)		4
Loss on sale of assets, net		—			1			(1	)
Other		(1	)		—			(1	)
Adjusted EBITDA	$	59		$	44		$	15
Million Megawatt Hours Generated		2.6			4.0			(1.4	)
IMA for Combined-Cycle Facilities (1)		96	%		96	%
Average Capacity Factor for Combined-Cycle Facilities (2)		27	%		38	%
CDDs (3)	$	1,211		$	1,480		$	(269	)
HDDs (3)	$	1,218		$	1,237		$	(19	)
Average Market On-Peak Spark Spreads ($/MWh) (4):
North of Path 15 (NP 15)	$	12.67		$	14.32		$	(1.65	)
Average Market On-Peak Power Prices ($/MWh) (5):
North of Path 15 (NP 15)	$	31.60		$	35.23		$	(3.63	)
Average natural gas price—PG&E Citygate ($/MMBtu) (6)	$	2.70		$	2.99		$	(0.29	)

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(1) IMA is an internal measurement calculation that reflects the percentage of generation available when market prices are such that these units could be profitably dispatched. This calculation excludes certain events outside of Dynegy management control such as weather-related issues. The calculation excludes CTs.

(2) Reflects actual production as a percentage of available capacity. The calculation excludes CTs.

(3) Reflects CDDs or HDDs for the ISO-NE Region based on NOAA data.

(4) Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to Dynegy.

(5) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices Dynegy realized.

(6) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by Dynegy.

Operating loss decreased by $3 million primarily due to the following:

	(in millions)
Lower energy margin, net of hedges, primarily due to lower generation volumes as a result of higher fuel costs	$	(7	)
Higher capacity revenues due to higher contracted volumes	$	9

Adjusted EBITDA increased by $15 million primarily due to the following:

Lower energy margin, net of hedges, primarily due to lower generation volumes as a result of higher fuel costs	$	(7	)
Higher capacity revenues due to higher contracted volumes	$	9
Supplier settlement	$	12

Outlook

Since 2013, Dynegy has increased scale and shifted its portfolio mix, which was predominately coal-based, to a predominately gas-based portfolio, through four major acquisitions. Dynegy used a significant portion of its balance sheet capacity to finance these acquisitions. Dynegy is now focused on strengthening its balance sheet, managing debt maturities and improving its leverage profile through debt reduction primarily from operating cash flows, as well as its PRIDE and ECI initiatives.

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On October 29, 2017, Dynegy and Vistra Energy entered into the Merger Agreement. We expect the transaction to close in the second quarter of 2018 after meeting the remaining customary conditions, including regulatory approvals including FERC, the Public Utility Commission of Texas and the New York Public Service Commission.    

Dynegy expects that its future financial results will continue to be impacted by market structure and prices for electric energy, capacity, and ancillary services, including pricing at its plant locations relative to pricing at their respective trading hubs, the volatility of fuel and electricity prices, transportation and transmission logistics, weather conditions, and the availability of its plants. Further, there has been a historical trend toward greater environmental regulation of all aspects of its business. To the extent this trend continues, it is possible that Dynegy will experience additional costs related to water, air, and coal ash regulations.

Certain states (Illinois, New York and Connecticut) in Dynegy’s markets have passed legislation or orders whereby those states will subsidize or could subsidize certain nuclear energy producers. Dynegy believes these subsidies have and will continue to adversely affect the energy and capacity markets by artificially suppressing prices. As a result, Dynegy is currently a party to lawsuits in Illinois and New York challenging these subsidy programs. Other states including New Jersey, Pennsylvania, and Ohio are also considering similar nuclear subsidy programs.

The portions of Dynegy’s generation volumes sold, coal requirements contracted, coal requirements priced, and coal transportation requirements contracted, by segment, are discussed below. Dynegy looks to procure and price additional coal and coal transportation opportunistically. For Dynegy’s gas-fired fleet, Dynegy hedges price risk by selling forward spark spreads which involves purchasing the required amount of natural gas at the same time as Dynegy sells power. Dynegy expects to continue its hedging program for energy over a one- to three-year period using various instruments, including retail sales in Dynegy’s PJM, NY/NE, and MISO segments, and in accordance with its risk management policy.

Dynegy’s Operating Segments

PJM Segment. The PJM segment is comprised of 19 power generation facilities located within the PJM region, with a total generating capacity of 11,704 MW. Dynegy has recently announced the planned retirements of its jointly owned Stuart (679 MW related to Dynegy’s ownership) and Killen (204 MW related to Dynegy’s ownership) facilities by mid-2018.

In PJM, Dynegy has installed 325 MW of uprates since 2014, primarily through upgrades to the hot gas path components of its combined-cycle gas turbines. Dynegy is installing an additional 18 MW of uprates in the spring of 2018 at its Pleasants peaking facility.

PJM introduced its new Capacity Performance (“CP”) product beginning with the Planning Year 2016-2017 capacity auction. CP resources must be capable of sustainable, predictable operation that allows them to be available to provide energy and reserves during performance assessment hours throughout the Delivery Year. Beginning in Planning Year 2018-2019, PJM introduced Base Capacity (“Base”) product, which, alongside CP, replaced the legacy capacity product. Base capacity resources are those capacity resources that are not capable of sustained, predictable operation throughout the entire delivery year, but are capable of providing energy and reserves during hot weather operations. They are subject to non-performance charges assessed during emergency conditions, from June through September.

Dynegy uses its retail business to hedge a portion of the energy output from its facilities. Its portfolio beyond 2019 is primarily open to benefit from possible future power market pricing improvements.

The following table reflects Dynegy’s hedging activities as of February 8, 2018:

	2018			2019			2020 to 2022
Generation volumes hedged		78	%		40	%		5	%
Coal requirements contracted (1)		99	%		100	%		33	%
Coal requirements priced (1)		99	%		58	%		6	%
Coal transportation requirements contracted (1)		100	%		100	%		100	%

(1) Excludes non-operated jointly-owned generating units.

117

PJM Capacity Market. The most recent RPM auction results, for the zones in which Dynegy’s assets are located, are as follows for each Planning Year:

	2017-2018				2018-2019				2019-2020				2020-2021
(price per MW-day)	Legacy Capacity		CP		Base		CP		Base		CP		CP
RTO zone (1)	$	120.00	$	151.50	$	149.98	$	164.77	$	80.00	$	100.00	$	88.32
MAAC zone	$	120.00	$	151.50	$	149.98	$	164.77	$	80.00	$	100.00	$	86.04
EMAAC zone	$	120.00	$	151.50	$	210.63	$	225.42	$	99.77	$	119.77	$	187.87
COMED zone	$	120.00	$	151.50	$	200.21	$	215.00	$	182.77	$	202.77	$	188.12
ATSI zone	$	120.00	$	151.50	$	149.98	$	164.77	$	80.00	$	100.00	$	76.53
PPL zone	$	120.00	$	151.50	$	75.00	$	164.77	$	80.00	$	100.00	$	86.04

(1) Planning Year 2020-2021 includes DEOK zone which broke out from RTO zone at $130.00 per MW-day.

Dynegy’s capacity sales, net of purchases, aggregated by Planning Year and capacity type through Planning Year 2020-2021, are as follows:

	2017-2018		2018-2019		2019-2020		2020-2021
Legacy/Base auction capacity sold, net (MW)		2,920		1,910		1,413		—
CP auction capacity sold, net (MW)		7,276		7,804		8,159		8,558
Bilateral capacity sold, net (MW)		2		270		200		200
Total segment capacity sold, net (MW)		10,198		9,984		9,772		8,758
Average price per MW-day	$	143.99	$	180.72	$	128.72	$	130.13

NY/NE Segment. The NY/NE segment is comprised of seven power generation facilities located within the ISO-NE region (3,518 MW) and one power generation facility located within the NYISO region (1,212 MW), totaling 4,730 MW of electric generating capacity. Dynegy began retail activities in Massachusetts in 2017, providing additional channels to market for its ISO-NE plants.

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In New England, at Dynegy’s Lake Road and Milford-Connecticut facilities, Dynegy cleared 70 MW of new uprates in FCA-10, at a capacity rate of $7.03 per kW-month for seven years beginning with Planning Year 2019-2020 and extending through Planning Year 2025-2026. For FCA-11, Dynegy cleared a total of 34 MW of uprates at Lake Road and Casco Bay that did not qualify for a seven-year rate lock. Dynegy has been awarded six municipal load contracts encompassing 76,100 accounts in the state of MA.

The following table reflects Dynegy’s hedging activities as of February 8, 2018:

	2018			2019			2020 to 2022
Generation volumes hedged (1)		64	%		19	%		3	%

(1) Excludes volumes subject to tolling agreements.

NYISO Capacity Market. The most recent seasonal auction results for NYISO’s Rest-of-State zones, in which the capacity for Dynegy’s Independence plant clears, are as follows for each planning period:

	Summer 2017		Winter 2017-2018
Price per kW-month	$	3.00	$	0.37

Due to the short-term, seasonal nature of the NYISO capacity auctions, Dynegy monetizes the majority of its capacity through bilateral trades. Dynegy’s capacity sales, aggregated by season through Summer 2020, are as follows:

	Winter 2017- 2018		Summer 2018		Winter 2018- 2019		Summer 2019		Winter 2019- 2020		Summer 2020
Auction capacity sold (MW)		122		—		—		—		—		—
Bilateral capacity sold (MW)		1,088		855		605		305		210		75
Total capacity sold (MW)		1,210		855		605		305		210		75
Average price per kW-month	$	1.79	$	3.12	$	2.19	$	3.06	$	2.57	$	3.15

ISO-NE Capacity Market. The most recent FCA results for ISO-NE Rest-of-Pool, in which most of Dynegy’s assets are located, are as follows for each Planning Year:

	2017-2018		2018-2019		2019-2020		2020-2021		2021-2022
Price per kW-month	$	7.03	$	9.55	$	7.03	$	5.30	$	4.63

Performance incentive rules will go into effect for Planning Year 2018-2019, having the potential to increase capacity payments for those resources that are providing excess energy or reserves during a shortage event, while penalizing those that produce less than the required level. Dynegy continues to market and pursue longer term multi-year capacity transactions that extend past Planning Year 2021-2022.

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Dynegy’s capacity sales, aggregated by Planning Year through Planning Year 2021-2022, are as follows:

	2017-2018		2018-2019		2019-2020		2020-2021		2021-2022
Auction capacity sold (MW)		3,155		3,168		3,203		3,229		2,762
Bilateral capacity sold (MW)		148		86		30		—		—
Total capacity sold (MW)		3,303		3,254		3,233		3,229		2,762
Average price per kW-month	$	6.92	$	9.98	$	7.02	$	5.39	$	4.79

ERCOT Segment. The ERCOT segment is comprised of six power generation facilities located within the ERCOT region, with a total generating capacity of 4,529 MW.

The following table reflects Dynegy’s hedging activities as of February 8, 2018:

	2018			2019			2020 to 2022
Generation volumes hedged		74	%		26	%		—	%
Coal requirements contracted		100	%		—	%		—	%
Coal requirements priced		100	%		—	%		—	%
Coal transportation requirements contracted		100	%		—	%		—	%

ERCOT Market. In addition to the energy and fuel hedges summarized in the table above Dynegy also hedges using the forward sale of ancillary services.

MISO Segment. Dynegy’s MISO segment is comprised of eight power generation facilities located in Illinois, totaling 5,476 MW of electric generating capacity. Joppa, which is within the EEI control area, is interconnected to Tennessee Valley Authority and Louisville Gas and Electric Company, but primarily sells its capacity and energy to MISO. Dynegy currently offers a portion of its MISO segment generating capacity and energy into PJM. As of June 1, 2016, Dynegy’s Coffeen, Duck Creek, E.D. Edwards and Newton facilities have 937 MW, or 17 percent of MISO’s current capacity and energy, electrically tied into PJM through pseudo-tie arrangements. As of June 1, 2017, Hennepin began offering 260 MW of the facility’s energy and capacity into PJM as a block schedule and will begin dispatching as a pseudo-tie unit for Planning Year 2018-2019.

Dynegy’s portfolio beyond 2018 is primarily open to benefit from possible future power market pricing improvements. MISO will continue to use Dynegy’s retail business to hedge a portion of the output from its MISO facilities. The retail hedges are well correlated to Dynegy’s facilities due to the close proximity of the hedge and through participation in FTR markets. The following table reflects Dynegy’s hedging activities as of February 8, 2018:

	2018			2019			2020 to 2022
Generation volumes hedged		75	%		39	%		17	%
Coal requirements contracted		91	%		74	%		43	%
Coal requirements priced		90	%		6	%		5	%
Coal transportation requirements contracted		100	%		100	%		99	%

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MISO Capacity Market. The capacity auction results for MISO Local Resource Zone 4, in which Dynegy’s assets are located, are as follows for each Planning Year:

	2017-2018
Price per MW-day	$	1.50

Dynegy’s MISO segment cleared no incremental volumes, in excess of its retail load obligations, in the MISO Planning Year 2017-2018 capacity auction. MISO capacity sales through Planning Year 2020-2021 are as follows:

	2017-2018		2018-2019		2019-2020		2020-2021
Bilateral capacity sold in MISO (MW)		3,506		2,269		1,978		1,520
Legacy/Base auction capacity sold in PJM (MW)		572		—		260		—
CP auction capacity sold in PJM (MW)		472		835		356		444
Total MISO segment capacity sold (MW)		4,550		3,104		2,594		1,964
Average price per kW-month	$	4.01	$	4.37	$	3.72	$	3.80

The results of the most recent MISO capacity auction continue to validate Dynegy’s strategy of right-sizing its MISO wholesale generation business to more closely match its retail business or to export capacity to PJM. Despite continuing low auction clearing prices, Dynegy has been able to effectively monetize much of its available MISO capacity at attractive prices.

CAISO Segment. The CAISO segment is comprised of two power generation facilities located within the CAISO region, with a total generating capacity of 1,185 MW.

The following table reflects Dynegy’s hedging activities as of February 8, 2018:

	2018			2019			2020 to 2022
Generation volumes hedged		56	%		24	%		—	%

CAISO Capacity Market. The CAISO capacity market is a bilateral market in which Load Serving entities are required to procure sufficient resources to meet their peak load plus a 15 percent reserve margin. Dynegy transacts with investor owned utilities, municipalities, community choice aggregators, retail providers, and other marketers through Request for Offers solicitations, broker markets, and directly with bilateral transactions for both Generic and Flexible Resource Adequacy (“RA”) capacity. On December 22, 2017, the CAISO issued a Capacity Procurement Mechanism designation on Moss Landing Unit 1 for 510 MW for 2018, which is reflected in Dynegy’s capacity sales table below.

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Dynegy’s capacity sales, aggregated by calendar year for 2018 through 2020 for Moss Landing, are as follows:

	2018		2019		2020
Bilateral capacity sold (Avg MW)		966		850		—

Dynegy has also sold seasonal capacity for Moss Landing opportunistically. Dynegy’s Oakland facility operated under an RMR contract with the CAISO for 2017 and was given notice of extension for 2018.

SEASONALITY

Dynegy’s revenues and operating income are subject to fluctuations during the year, primarily due to the impact seasonal factors have on sales volumes and the prices of power and natural gas. Power marketing operations and generating facilities typically have higher volatility and demand in the summer cooling months and winter heating season.

CRITICAL ACCOUNTING POLICIES

Dynegy’s Accounting Department is responsible for the development and application of accounting policy and control procedures. This department conducts these activities independent of any active management of Dynegy’s risk exposures, is independent of Dynegy’s business segments, and reports to Dynegy’s Chief Financial Officer (“CFO”).

The process of preparing financial statements in accordance with GAAP requires Dynegy’s management to make estimates and judgments. It is possible that materially different amounts could be recorded if these estimates and judgments change or if actual results differ from these estimates and judgments. Dynegy has identified the following critical accounting policies that require a significant amount of estimation and judgment and are considered important to the portrayal of Dynegy’s financial position and results of operations:

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Description	Judgments and Uncertainties	Effect if Actual Results Differ From Assumptions
Derivative Instruments
Commodity contracts that meet the definition of a derivative are often entered into to mitigate or eliminate market and financial risks associated with Dynegy’s generation business. These contracts include forward contracts, which commit Dynegy to sell commodities in the future; futures contracts, which are generally broker-cleared standard commitments to purchase or sell a commodity; option contracts, which convey the right to buy or sell a commodity; and swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined quantity. There are two different ways to account for these types of commodity contracts, as Dynegy does not elect hedge accounting for any of its derivative instruments: (i) as an accrual contract, if the criteria for the “normal purchase, normal sale” exception are met, documented, and elected; or (ii) as a mark-to-market contract with changes in fair value recognized in current period earnings. Comparability of Dynegy’s financial statements to its peers for similar contracts may not be possible due to differences in electing the “normal purchase, normal sale” exception or electing hedge accounting. Dynegy is exposed to changes in interest rate risk through its variable rate debt and enters into interest rate swaps to manage its interest rate risk with the changes in fair value recorded currently to interest expense. Dynegy’s interest-based derivative instruments are not designated as hedges of its variable debt.	Dynegy utilizes market data or assumptions, including assumptions about risk and the risks inherent in the inputs to the valuation technique, primarily forward price curves, pricing risk, and credit risk. Dynegy primarily applies the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, Dynegy utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs are classified into three levels of fair value hierarchy under GAAP and described as actively quoted market prices (Level 1), directly or indirectly observable (Level 2), or generally unobservable (Level 3). Those inputs include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of Dynegy’s nonperformance risk on its liabilities. Valuation adjustments are generally based on capital market implied ratings when assessing the credit standing of Dynegy’s counterparties, and when applicable, adjusted based on management’s estimates of assumptions market participants would use in determining fair value.	Changes to Dynegy’s assumptions for the fair value of Dynegy’s derivative instruments could result in a material change to the fair value of Dynegy’s risk management assets and liabilities recorded to its consolidated balance sheets and corresponding changes in fair value recorded to its consolidated statements of operations. Please read Note 5 to Dynegy’s Consolidated Financial Statements-Fair Value Measurements for further discussion of Dynegy’s assumptions.
Dynegy elects to offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement and Dynegy elects to offset the fair value of amounts recognized for the cash collateral paid or received against the fair value of amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ From Assumptions
Accounting for Income Taxes
Dynegy files a consolidated U.S. federal income tax return. Dynegy uses the asset and liability method of accounting for deferred income taxes and provides deferred income taxes for all significant differences. Dynegy also accounts for changes in the tax code when enacted. Because Dynegy operates and sells power in many different states, its effective annual state income tax rate may vary from period to period due to changes in its sales profile by state, as well as jurisdictional and legislative changes by state. As a result, changes in its estimated effective annual state income tax rate can have a significant impact on its measurement of temporary differences. Dynegy conducts a valuation assessment on its deferred tax assets, which involves an extensive analysis of positive and negative evidence, to determine if it is more likely than not that they will not be realized.	As part of the process of preparing its consolidated financial statements, Dynegy is required to estimate its income taxes in each of the jurisdictions in which it operates. This process involves estimating its actual current tax payable and related tax expense together with assessing temporary differences resulting from differing tax and accounting treatment of certain items, such as depreciation, for tax and accounting purposes. Dynegy projects the rates at which state tax temporary differences will reverse based upon estimates of revenues and operations in the respective jurisdictions in which it conducts business. The guidance related to accounting for income taxes also require that a valuation allowance be established when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income of the appropriate character during the periods in which those temporary differences are deductible. In making this determination, management considers all available positive and negative evidence affecting specific deferred tax assets, including Dynegy’s past and anticipated future performance, the reversal of deferred tax liabilities and the implementation of tax planning strategies.	Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A change in the future taxable income assumptions used to determine Dynegy’s need for a valuation allowance can result in more or less deferred tax assets being recognized in its financial statements. The ultimate tax outcome is uncertain and the assumptions used on the utilization of tax benefits in the future can change primarily as a consequence of newly enacted tax laws and management’s view of future taxable income. These changes can materially affect Dynegy’s overall financial results.
Accounting for uncertainty in income taxes requires that Dynegy determine whether it is more likely than not that a tax position Dynegy has taken will be sustained upon examination. If Dynegy determines that it is more likely than not that the position will be sustained, Dynegy recognizes the largest amount of the benefit that is greater than 50 percent likely of being realized upon settlement.	There is a significant amount of judgment involved in assessing the likelihood that a tax position will be sustained upon examination and in determining the amount of the benefit that will ultimately be realized.	A change in Dynegy’s assumptions assessing the likelihood that a tax position will be sustained upon examination may change the amount of tax benefit that is recognized in its financial statements. Please read Note 14 to Dynegy’s Consolidated Financial Statements-Income Taxes for further discussion of Dynegy’s accounting for income taxes, uncertain tax positions, and changes in Dynegy’s valuation allowance.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ From Assumptions
Business Combinations
Accounting Standards Codification (“ASC”) 815, Business Combinations requires that the purchase price for a business combination be assigned and allocated to the identifiable assets acquired and liabilities assumed based upon their fair value. Generally, the amount recorded in the financial statements for an acquisition’s assets and liabilities is equal to the purchase price (the fair value of the consideration paid); however, a purchase price that exceeds the fair value of the net assets acquired will result in the recognition of goodwill. Conversely, a purchase price that is below the fair value of the net assets acquired will result in the recognition of a bargain purchase in the income statement. In addition to the potential for the recognition of goodwill or a bargain purchase, differing fair values will impact the allocation of the purchase price to the individual assets and liabilities and can impact the gross amount and classification of assets and liabilities recorded in Dynegy’s consolidated balance sheets, which can impact the timing and amount of depreciation and amortization expense recorded in any given period.	In estimating fair value, Dynegy uses discounted cash flow (“DCF”) projections, recent comparable market transactions, if available, or quoted prices. Dynegy considers assumptions that third parties would make in estimating fair value, including, but not limited to, the highest and best use of the asset. There is a significant amount of judgment involved in cash-flow estimates, including assumptions regarding market convergence, discount rates, commodity prices, useful lives and growth factors. The assumptions used by another party could differ significantly from Dynegy’s assumptions. Dynegy utilizes its best effort to make its determinations and review all information available, including estimated future cash flows and prices of similar assets when making its best estimate. Dynegy also may hire independent appraisers or valuation specialists to help it make this determination as it deems appropriate under the circumstances. Refer to Note 3 to Dynegy’s Consolidated Financial Statements—Acquisitions and Divestitures for further discussion of assumptions used in acquisitions.	There is a significant amount of judgment in determining the fair value of acquisitions and in allocating the purchase price to individual assets and liabilities. Had different assumptions been used, the fair value of the assets acquired and liabilities assumed could have been significantly higher or lower with a corresponding increase or reduction in recognized goodwill, or could have required recognition of a bargain purchase.

125

Description	Judgments and Uncertainties	Effect if Actual Results Differ From Assumptions
Impairment of Long-Lived Assets
ASC 360, Property, Plant and Equipment (“PP&E”) requires for an entity to assess whether the recorded values of PP&E and finite-lived intangible assets have become impaired when certain indicators of impairment exist. Examples of these indicators include, but are not limited to: •      a significant decrease in the market price of a long-lived asset (asset group); •      a significant adverse change in the extent or manner in which a long-lived asset (asset group) is being used, or in its physical condition; •      a significant adverse change in legal factors or in the business climate that could affect the value of a long-lived asset (asset group), including an adverse action or assessment by a regulator; •      an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset (asset group); •      a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset (asset group); and	Determining whether an impairment trigger exists involves significant judgment by management which may result in a different answer if Dynegy’s peers were to consider the same facts and circumstances. If it is determined that the asset’s value is not recoverable, then Dynegy will perform step two of the impairment analysis and fair value the asset using a DCF model and record an impairment charge to reduce the value of the asset to its fair value. The assumptions and estimates used by management to assess whether the asset may have become impaired, whether the asset’s value is recoverable, and to determine the fair value of the estimate are significant and may vary materially from the assumptions used by Dynegy’s peers. Examples of the assumptions and estimates used by management include: •      determination of increases/decreases in the market price of an asset being a short-term or long-term, fundamental change; •      the highest and best use of the asset; •      forecasted environmental changes; •      forecasted regulatory changes; •      management’s fundamental view of the long-term pricing environment for energy and capacity; •      management’s forecast of gross margin, capital expenditures, and operations and maintenance costs; •      remaining useful life of Dynegy’s assets; •      salvage value; •      discount rates; and •      inflation rates. The assumptions used in impairment analyses often include unobservable inputs that are based on management’s long-term view of Dynegy’s assets remaining useful lives, operating margin and capital requirements.	Changes in market economics and environmental requirements can alter previous assumptions and trigger impairment charges that can materially differ from the results Dynegy has reported.
•      a current expectation that it is more likely than not a long-lived asset (asset group) will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

126

Description	Judgments and Uncertainties	Effect if Actual Results Differ From Assumptions
Goodwill Impairment
Dynegy records goodwill when the purchase price for an acquisition classified as a business combination exceeds the estimated net fair value of the identifiable tangible and intangible assets acquired. The amount of goodwill which can be recognized as part of an acquisition can change materially based upon the assumptions used when determining the net fair value of those assets. Dynegy allocates goodwill to reporting units based on the relative fair value of the purchased operating assets assigned to those reporting units. ASC 350, Intangibles-Goodwill and Other requires an entity to assess whether goodwill has become impaired at least annually, or when certain indicators of impairment exist on an interim basis. Dynegy has elected October 1 for its annual assessment. Examples of the indicators of impairment include, but are not limited to: •      a deterioration of general economic conditions, limitation on accessing capital, or other developments in equity and credit markets; •      increases in costs which have a negative effect on earnings and cash flows; •      overall financial performance such as negative or declining cash flows or a decline in actual or planned revenue or earnings; •      other relevant entity-specific events such as changes in management, key personnel, strategy, or customers, contemplation of bankruptcy, or litigation; •      a more likely than not expectation of selling or disposing all, or a portion, of a reporting unit; and,	Determining whether a goodwill impairment trigger exists involves significant judgment by management, which may result in a different answer if Dynegy’s peers were to consider the same facts and circumstances. The assumptions and estimates used by management to determine the fair value of Dynegy’s reporting units and goodwill for step one, and the fair value of Dynegy’s equity to reconcile to its market capitalization, are significant and require management judgment. Some examples of the assumptions and estimates used include: •      the highest and best use of the reporting units assets; •      recent comparable market transactions, if available, or quoted prices; •      management’s forecast of gross margin, capital expenditures, and operations and maintenance costs; •      forecasted environmental and regulatory changes; •      management’s fundamental view of the long-term pricing environment for energy and capacity; •      remaining useful life of Dynegy’s assets; •      salvage value; •      discount rates; and •      inflation rates.	Changes in management’s assumptions and estimates regarding the fair value of these reporting units could result in a materially different result. The assumptions used in goodwill impairment analyses often include unobservable inputs that are based on management’s long-term view of the reporting unit asset’s remaining useful lives, operating margin and capital requirements. Changes in the reporting unit’s economics can alter previous assumptions and trigger impairment charges that can materially affect Dynegy’s financial results.
•      recognition of a goodwill impairment loss in the financial statements of a subsidiary that is a component of a reporting unit.
In the event management determines an impairment indicator exists or is performing the annual assessment, ASC 350 allows an entity to elect to qualitatively assess whether it is more likely than not (a likelihood of more than 50 percent) that an impairment has occurred. If Dynegy determines that it is more likely than not that goodwill has become impaired, it will impair goodwill by the amount by which the carrying value of the reporting unit, including goodwill, exceeds its fair value that will be retained. When Dynegy disposes of a reporting unit or a portion of a reporting unit that constitutes a business, Dynegy includes goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on sale. The amount of goodwill to be included in that carrying amount is based on the relative fair value of the business to be disposed of as compared to the portion of the reporting unit that will be retained.

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RECENT ACCOUNTING PRONOUNCEMENTS

Please read Note 2 to Dynegy’s Consolidated Financial Statements—Summary of Significant Accounting Policies for further discussion of accounting principles adopted and accounting principles not yet adopted.

RISK MANAGEMENT DISCLOSURES

The following table provides a reconciliation of the risk management data contained within Dynegy’s consolidated balance sheets on a net basis:

(amounts in millions)	As of and for the Year Ended December 31, 2017
Fair value of portfolio at December 31, 2016	$	6
Risk management losses recognized through the statement of operations in the period, net		(223	)
Contracts realized or otherwise settled during the period		16
Cash received related to option premiums		(3	)
Acquired derivatives		9
Change in collateral/margin netting		(7	)
Fair value of portfolio at December 31, 2017	$	(202	)

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The net risk management liability of $202 million is the aggregate of the following line items in Dynegy’s consolidated balance sheets: Current Assets—Assets from risk management activities, Other Assets—Assets from risk management activities, Current Liabilities—Liabilities from risk management activities, and Other Liabilities—Liabilities from risk management activities.

Risk Management Asset and Liability Disclosures. The following table provides an assessment of net contract values by year as of December 31, 2017, based on Dynegy’s valuation methodology:

Net Fair Value of Risk Management Portfolio

(amounts in millions)	Total			2018			2019			2020		2021		2022		Thereafter
Market quotations (1)(2)	$	(224	)	$	(219	)	$	(21	)	$	3	$	4	$	4	$	5
Prices based on models (2)		(25	)		(25	)		—			—		—		—		—
Total (3)	$	(249	)	$	(244	)	$	(21	)	$	3	$	4	$	4	$	5

(1) Prices obtained from actively traded, liquid markets for commodities.

(2) The market quotations category represents Dynegy’s transactions classified as Level 1 and Level 2. The prices based on models category represents transactions classified as Level 3. Please read Note 5—Fair Value Measurements for further discussion.

(3) Excludes $47 million of broker margin that has been netted against Risk management liabilities in Dynegy’s consolidated balance sheets. Please read Note 4 to Dynegy’s Consolidated Financial Statements—Risk Management Activities, Derivatives and Financial Instruments for further discussion.

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DYNEGY INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Consolidated Financial Statements
Reports of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets:
December 31, 2017 and 2016		F-5
Consolidated Statements of Operations:
For the years ended December 31, 2017, 2016 and 2015		F-7
Consolidated Statements of Comprehensive Income (Loss):
For the years ended December 31, 2017, 2016 and 2015		F-8
Consolidated Statements of Cash Flows:
For the years ended December 31, 2017, 2016 and 2015		F-9
Consolidated Statements of Changes in Equity:
For the years ended December 31, 2017, 2016 and 2015		F-10
Notes to Consolidated Financial Statements		F-11

F-1

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of Dynegy Inc.:

Opinion on Internal Control over Financial Reporting

We have audited Dynegy Inc.’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Dynegy Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of Dynegy Inc. as of December 31, 2017 and 2016, and the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “consolidated financial statements”), and our report dated February 22, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

F-2

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Houston, Texas

February 22, 2018

F-3

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of Dynegy Inc.:

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Dynegy Inc. (the Company) as of December 31, 2017 and 2016, and the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 22, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2007

Houston, Texas

February 22, 2018

F-4

Item 1—FINANCIAL STATEMENTS

DYNEGY INC.

CONSOLIDATED BALANCE SHEETS

(in millions, except share data)

	December 31, 2017		December 31, 2016
ASSETS
Current Assets
Cash and cash equivalents	$	365	$	1,776
Restricted cash		—		62
Accounts receivable, net of allowance for doubtful accounts of $1 and $1, respectively		513		386
Inventory		445		445
Assets from risk management activities		32		130
Intangible assets		25		38
Prepayments and other current assets		144		150
Total Current Assets		1,524		2,987
Property, plant and equipment, net		8,884		7,121
Investment in unconsolidated affiliate		123		—
Restricted cash		—		2,000
Assets from risk management activities		26		16
Goodwill		772		799
Intangible assets		39		23
Other long-term assets		403		107
Total Assets	$	11,771	$	13,053

See the notes to consolidated financial statements.

F-5

DYNEGY INC.

CONSOLIDATED BALANCE SHEETS

(in millions, except share data)

	December 31, 2017			December 31, 2016
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	367		$	332
Accrued interest		115			81
Intangible liabilities		14			21
Accrued taxes		64			45
Accrued liabilities and other current liabilities		109			88
Liabilities from risk management activities		229			97
Asset retirement obligations		46			51
Debt, current portion, net		105			201
Total Current Liabilities		1,049			916
Liabilities subject to compromise (Note 20)		—			832
Debt, long-term portion, net		8,328			8,778
Other Liabilities
Liabilities from risk management activities		31			43
Asset retirement obligations		283			236
Deferred income taxes		7			5
Intangible liabilities		34			34
Other long-term liabilities		146			170
Total Liabilities		9,878			11,014
Commitments and Contingencies (Note 16)
Stockholders’ Equity
Preferred Stock, $0.01 par value, 20,000,000 shares authorized:
Series A 5.375% mandatory convertible preferred stock, $0.01 par value; 4,000,000 shares issued and outstanding at December 31, 2016		—			400
Common stock, $0.01 par value, 420,000,000 shares authorized; 155,710,613 shares issued and 144,384,491 shares outstanding at December 31, 2017; 128,626,740 shares issued and 117,300,618 outstanding at December 31, 2016		1			1
Additional paid-in capital		3,719			3,547
Accumulated other comprehensive income, net of tax		32			21
Accumulated deficit		(1,851	)		(1,927	)
Total Dynegy Stockholders’ Equity		1,901			2,042
Noncontrolling interest		(8	)		(3	)
Total Equity		1,893			2,039
Total Liabilities and Equity	$	11,771		$	13,053

See the notes to consolidated financial statements.

F-6

DYNEGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)

	Year Ended December 31,
	2017			2016			2015
Revenues	$	4,842		$	4,318		$	3,870
Cost of sales, excluding depreciation expense		(2,932	)		(2,281	)		(2,028	)
Gross margin		1,910			2,037			1,842
Operating and maintenance expense		(995	)		(940	)		(839	)
Depreciation expense		(811	)		(689	)		(587	)
Impairments		(148	)		(858	)		(99	)
Loss on sale of assets, net		(122	)		(1	)		(1	)
General and administrative expense		(189	)		(161	)		(128	)
Acquisition and integration costs		(57	)		(11	)		(124	)
Other		—			(17	)		—
Operating income (loss)		(412	)		(640	)		64
Bankruptcy reorganization items (Note 20)		494			(96	)		—
Earnings from unconsolidated investments		8			7			1
Interest expense		(616	)		(625	)		(546	)
Loss on early extinguishment of debt (Note 13)		(79	)		—			—
Other income and expense, net		67			65			54
Loss before income taxes		(538	)		(1,289	)		(427	)
Income tax benefit (Note 14)		610			45			474
Net income (loss)		72			(1,244	)		47
Less: Net loss attributable to noncontrolling interest		(4	)		(4	)		(3	)
Net income (loss) attributable to Dynegy Inc.		76			(1,240	)		50
Less: Dividends on preferred stock		18			22			22
Net income (loss) attributable to Dynegy Inc. common stockholders	$	58		$	(1,262	)	$	28
Earnings (Loss) Per Share (Note 15):
Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders	$	0.37		$	(9.78	)	$	0.22
Diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders	$	0.36		$	(9.78	)	$	0.22
Basic shares outstanding		155			129			125
Diluted shares outstanding		162			129			126

See the notes to consolidated financial statements.

F-7

DYNEGY INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in millions)

	Year Ended December 31,
	2017			2016			2015
Net income (loss)	$	72		$	(1,244	)	$	47
Other comprehensive income before reclassifications:
Actuarial gain and plan amendments (net of tax of $5, $3, and zero, respectively)		19			3			4
Amounts reclassified from accumulated other comprehensive income:
Settlement cost (net of tax of zero)		—			6			—
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero, zero, and zero, respectively)		(8	)		(5	)		(4	)
Other comprehensive income, net of tax		11			4			—
Comprehensive income (loss)		83			(1,240	)		47
Less: Comprehensive loss attributable to noncontrolling interest		(4	)		(2	)		(2	)
Total comprehensive income (loss) attributable to Dynegy Inc.	$	87		$	(1,238	)	$	49

See the notes to consolidated financial statements.

F-8

DYNEGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year Ended December 31,
	2017			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	72		$	(1,244	)	$	47
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation expense		811			689			587
Loss on early extinguishment of debt		79			—			—
Non-cash interest expense		44			56			38
Amortization of intangibles		12			21			(11	)
Bankruptcy reorganization items		(494	)		96			—
Impairments		148			858			99
Risk management activities		207			(148	)		(130	)
Loss on sale of assets, net		122			1			1
Earnings from unconsolidated investments		(8	)		(7	)		(1	)
Deferred income taxes		(610	)		(45	)		(477	)
Change in value of common stock warrants		(16	)		(6	)		(54	)
Other		81			14			51
Changes in working capital:
Accounts receivable, net		(47	)		42			(64	)
Inventory		110			154			(119	)
Prepayments and other current assets		26			94			94
Accounts payable and accrued liabilities		46			84			25
Distributions from unconsolidated investments		5			1			3
Changes in non-current assets		(12	)		(43	)		—
Changes in non-current liabilities		9			28			5
Net cash provided by operating activities		585			645			94
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(224	)		(293	)		(301	)
Acquisitions, net of cash acquired		(3,319	)		—			(6,078	)
Distributions from unconsolidated investments		12			14			8
Proceeds from asset sales, net		772			176			—
Other investing		—			10			3
Net cash used in investing activities		(2,759	)		(93	)		(6,368	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs		1,743			3,014			66
Repayments of borrowings		(2,589	)		(589	)		(31	)
Proceeds from issuance of equity, net of issuance costs		150			359			(6	)
Payments of debt extinguishment costs		(50	)		—			—
Preferred stock dividends paid		(22	)		(22	)		(23	)
Interest rate swap settlement payments		(20	)		(17	)		(17	)
Acquisition of noncontrolling interest		(375	)		—			—
Payments related to bankruptcy settlement		(133	)		—			—
Repurchase of common stock		—			—			(250	)
Other financing		(3	)		(3	)		(4	)
Net cash provided by (used in) financing activities		(1,299	)		2,742			(265	)
Net increase (decrease) in cash, cash equivalents and restricted cash		(3,473	)		3,294			(6,539	)
Cash, cash equivalents and restricted cash, beginning of period		3,838			544			7,083
Cash, cash equivalents and restricted cash, end of period	$	365		$	3,838		$	544

See the notes to consolidated financial statements.

F-9

DYNEGY INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(in millions)

	Preferred Stock			Common Stock		Additional Paid-In Capital			AOCI			Accumulated Deficit			Total Controlling Interests			Noncontrolling Interest			Total
December 31, 2014	$	400		$	1	$	3,338		$	20		$	(736	)	$	3,023		$	—		$	3,023
Net income (loss)		—			—		—			—			50			50			(3	)		47
Equity issuance for acquisition, net (Note 15)		—			—		99			—			—			99			—			99
Other comprehensive income (loss), net of tax		—			—		—			(1	)		—			(1	)		1			—
Share-based compensation expense, net of tax		—			—		22			—			—			22			—			22
Options exercised		—			—		1			—			—			1			—			1
Dividends Paid		—			—		(23	)		—			—			(23	)		—			(23	)
Repurchases of common stock (Note 15)		—			—		(250	)		—			—			(250	)		—			(250	)
December 31, 2015		400			1		3,187			19			(686	)		2,921			(2	)		2,919
Net loss		—			—		—			—			(1,240	)		(1,240	)		(4	)		(1,244	)
TEUs (Note 12)		—			—		359			—			—			359			—			359
Other comprehensive income, net of tax		—			—		—			2			—			2			2			4
Share-based compensation expense, net of tax		—			—		22			—			—			22			—			22
Dividends paid		—			—		(22	)		—			—			(22	)		—			(22	)
Other		—			—		1			—			(1	)		—			1			1
December 31, 2016		400			1		3,547			21			(1,927	)		2,042			(3	)		2,039
Net income (loss)		—			—		—			—			76			76			(4	)		72
Equity issuance for acquisition, net (Note 15)		—			—		150			—			—			150			—			150
Preferred stock conversion		(400	)		—		400			—			—			—			—			—
Other comprehensive income, net of tax		—			—		—			11			—			11			—			11
Share-based compensation expense, net of tax		—			—		19			—			—			19			—			19
Acquisition of non-controlling interest		—			—		(375	)		—			—			(375	)		—			(375	)
Dividends paid		—			—		(22	)		—			—			(22	)		—			(22	)
Other		—			—		—			—			—			—			(1	)		(1	)
December 31, 2017	$	—		$	1	$	3,719		$	32		$	(1,851	)	$	1,901		$	(8	)	$	1,893

See the notes to consolidated financial statements.

F-10

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Operations

We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily on the power generation sector of the energy industry. Unless the context indicates otherwise, throughout this report, the terms “Dynegy,” “the Company,” “we,” “us,” “our” and “ours” are used to refer to Dynegy Inc. and its direct and indirect subsidiaries. We report the results of our power generation business as five segments in our consolidated financial statements: (i) PJM, (ii) NY/NE, (iii) ERCOT, (iv) MISO and (v) CAISO. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense, and income tax benefit (expense). In the fourth quarter of 2017, we combined our previous MISO and IPH segments into a single MISO segment to better align our IPH assets, which reside within the MISO market area, and changed our organizational structure to manage our assets, make financial decisions, and allocate resources based upon the market areas in which our plants operate. Accordingly, the Company has recast data from prior periods to conform to the current year segment presentation. All significant intercompany transactions have been eliminated. Please read Note 21—Segment Information for further discussion.

On February 2, 2017, Illinois Power Generating Company (“Genco”) emerged from bankruptcy. Please read Note 20—Genco Chapter 11 Bankruptcy for further discussion.

On February 7, 2017, (“the ENGIE Acquisition Closing Date”), Dynegy acquired approximately 9,017 MW of generation, including (i) 15 natural gas-fired facilities located in Illinois, Massachusetts, New Jersey, Ohio, Pennsylvania, Texas, Virginia, and West Virginia, (ii) one coal-fired facility in Texas, and (iii) one waste coal-fired facility in Pennsylvania for a base purchase price of approximately $3.3 billion in cash, subject to certain adjustments (the “ENGIE Acquisition”). Please read Note 3—Acquisitions and Divestitures for further discussion.

On October 29, 2017, Dynegy and Vistra Energy Corp., a Delaware corporation (“Vistra Energy”), entered into an Agreement and Plan of Merger (the “Merger Agreement”). Under the Merger Agreement, which has been approved by the boards of directors of both companies, Dynegy will merge with and into Vistra Energy in a tax-free, all-stock transaction, with Vistra Energy continuing as the surviving corporation (the “Merger”). Under the terms of the agreement, Dynegy stockholders will receive 0.652 shares of Vistra Energy common stock for each share of Dynegy common stock they own, resulting in Vistra Energy stockholders and Dynegy stockholders owning approximately 79 percent and 21 percent, respectively, of the combined company. During 2017, we incurred approximately $17 million in costs related to the Merger, which are included in General and administrative expense in our consolidated statement of operations.

We expect the transaction to close in the second quarter of 2018 after meeting the remaining customary conditions, including, among others, (a) approval by Vistra Energy’s stockholders of the issuance of the Vistra Energy common stock in the Merger, scheduled for March 2, 2018, and (b) receipt of all requisite regulatory approvals including FERC, the Public Utility Commission of Texas and the New York Public Service Commission. Each party’s obligation to consummate the Merger is also subject to certain additional customary conditions. The Merger Agreement contains customary representations, warranties and covenants of Dynegy and Vistra Energy, and contains certain termination rights for both Dynegy and Vistra Energy. If the Merger Agreement is terminated because Dynegy’s Board of Directors changes its recommendation to stockholders or Dynegy enters into a definitive agreement for a superior proposal, Dynegy will be required to pay Vistra Energy a termination fee of $87 million. If the Merger Agreement is terminated for a failure to obtain certain requisite regulatory approvals or Vistra Energy’s Board of Directors changes its recommendation in favor of the Merger, Vistra Energy may be required to pay Dynegy a termination fee of $100 million.

F-11

Note 2—Summary of Significant Accounting Policies

Principles of Consolidation. The accompanying consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries for which we are the primary beneficiary. Intercompany accounts and transactions have been eliminated. Certain prior period amounts in our consolidated financial statements have been reclassified to conform to current year presentation. Accounting policies for all of our operations are in accordance with accounting principles generally accepted in the United States of America (“U.S.”).

Unconsolidated Investments. We use the equity method of accounting for investments in affiliates over which we exercise significant influence. We use the cost method of accounting where we do not exercise significant influence.

Our share of net income (loss) from these affiliates is reflected in the consolidated statements of operations as Earnings from unconsolidated investments. All investments in unconsolidated affiliates are periodically assessed for other-than-temporary declines in value, with write-downs recognized in Earnings from unconsolidated investments in the consolidated statements of operations.

Undivided Interest Accounting. We account for our undivided interests in certain of our coal-fired power generation facilities whereby our proportionate share of each facility’s assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying consolidated financial statements.

Noncontrolling Interest. Noncontrolling interest is comprised of the 20 percent of Electric Energy, Inc. (“EEI”) which we do not own. This noncontrolling interest is classified as a component of equity separate from our equity in the consolidated balance sheets.

Use of Estimates. The preparation of consolidated financial statements in conformity with Generally Accepted Accounting Principles (“GAAP”) requires management to make informed estimates and judgments that affect our reported financial position and results of operations based on currently available information. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things: (i) developing fair value assumptions, including estimates of future cash flows and discount rates related to impairment analyses and business combinations, (ii) valuation of derivative instruments, (iii) analyzing tangible and intangible assets for possible impairment, (iv) estimating the useful lives of our long-lived assets, (v) estimating the scope, costs and timing of remediation work related to Asset Retirement Obligations (“AROs”), (vi) assessing future tax exposure and the realization of deferred tax assets, (vii) determining amounts to accrue for contingencies, guarantees, and indemnifications, and (viii) estimating various factors used to value our pension assets and liabilities. Actual results could differ materially from our estimates. In the opinion of management, all adjustments considered necessary for a fair presentation have been included in our consolidated financial statements.

Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid short-term investments with original maturities of three months or less.

Restricted Cash. Restricted cash represents cash that is not readily available for general purpose cash needs. Restricted cash is classified as a current or long-term asset based on the timing and nature of when or how the cash is expected to be used or when the restrictions are expected to lapse. As of December 31, 2017, the Company had no restricted cash balances, and as of December 31, 2016, the Company had the following restricted cash balances:

F-12

(amounts in millions)
Restricted cash, current:
Cash deposits associated with certain letters of credit (1)	$	41
Pre-funded original issue discount on the Term Loan (2)		20
Interest earned on funds in escrow		1
	$	62
Restricted cash, long-term:
Restricted cash related to the issuance of the Term Loan (2)	$	2,000

(1) Upon the emergence of Genco from bankruptcy, approximately $35 million of these deposits were returned to Dynegy.

(2) Upon the close of the ENGIE Acquisition, as defined herein, the proceeds from the issuance of the Term Loan were released from escrow. Please read Note 13—Debt for further information.

Accounts Receivable and Allowance for Doubtful Accounts. We record accounts receivable at net realizable value (“NRV”) when the product or service is delivered to the customer. We establish provisions for losses on accounts receivable if it becomes probable that we will not collect all or part of outstanding balances. We review collectability and establish or adjust our allowance as necessary using the specific identification method.

Inventory. Our commodity and materials and supplies inventories are carried at the lower of weighted average cost or NRV.

Property, Plant and Equipment. Property, plant and equipment (“PP&E”), which consists principally of power generating facilities, including capitalized interest, is generally recorded at historical cost. Expenditures for major installations, replacements, and improvements or betterments are capitalized and depreciated over the expected life cycle. Expenditures for maintenance, repairs, and minor renewals to maintain the operating condition of our assets are expensed. Depreciation is recognized using the straight-line method over the estimated economic service lives of the assets, ranging from one to 40 years.

F-13

The estimated economic service lives of our asset groups are as follows:

Asset Group	Range of Years
Power generation		1 to 36
Buildings and improvements		1 to 40
Office and other equipment		1 to 28

Gains and losses on sales of assets are reflected in Gain (loss) on sale of assets, net in the consolidated statements of operations. We evaluate our PP&E for impairment when events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. If an impairment is indicated, the carrying value is first compared to the undiscounted cash flows for the asset’s remaining useful life to determine if the carrying value is recoverable. In the event the carrying value is not recoverable, an impairment is recognized for the amount of carrying value in excess of the asset’s fair value. We recorded impairments on certain of our assets in 2017. Please read Note 8—Property, Plant and Equipment for further information.

Goodwill. Goodwill represents, at the time of an acquisition, the excess of purchase price over fair value of the identifiable tangible and intangible net assets acquired. The carrying amount of our goodwill is periodically reviewed, at least annually, for impairment and when certain indicators of impairment exist on an interim basis. We have elected October 1 for our annual assessment. In accordance with Accounting Standards Codification (“ASC”) 350, Intangibles-Goodwill and Other, we can opt to perform a qualitative assessment to test goodwill for impairment to determine whether it is more likely than not (a likelihood of more than 50 percent) that an impairment has occurred or we can directly perform a quantitative assessment of our reporting units. In the absence of sufficient qualitative factors, we will compare the fair value of a reporting unit to the book value, including goodwill. If the fair value exceeds book value, the goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, an impairment charge is recognized for the excess.

There were no impairments of goodwill for the year ended December 31, 2017. We wrote off approximately $27 million of goodwill during the year ended December 31, 2017 related to divestitures of facilities located within our reporting units. Please see Note 3—Acquisitions and Divestitures for further information.

Intangible Assets and Liabilities. We initially record and measure intangible assets and liabilities (“Intangibles”) based on the fair value of those rights transferred in the transaction in which the asset was acquired. Our recognized Intangibles consist of contractual rights and obligations with finite lives, and their initial values are based on quoted market prices, if available, or measurement techniques based on the best information available such as a present value of future cash flows. We amortize our definite-lived Intangibles over the useful life of the respective contracts.

Asset Retirement Obligations. We record the present value of our legal obligations to retire tangible, long-lived assets when the liability is incurred. Please see Use of Estimates above for a description of the significant estimates used by management in determining our liability. Our AROs relate to activities such as Coal Combustion Residuals (“CCR”) surface impoundments and landfill closure, dismantlement of power generation facilities, future removal of asbestos-containing material from certain power generation facilities, closure and post-closure costs, environmental testing, remediation, monitoring, and land obligations. Accretion expense is included in Operating and maintenance expense in our consolidated statements of operations. A summary of the changes related to our AROs is as follows:

F-14

	Year Ended December 31,
(amounts in millions)	2017			2016
Balance at beginning of year	$	287		$	280
Accretion expense		20			20
Liabilities settled		(8	)		(1	)
Revision of previous estimate (1)		22			(12	)
Acquisitions		24			—
Divestitures		(16	)		—
Balance at end of year	$	329		$	287

(1) Based on management’s review and assessment of CCR compliance timing and site-specific analysis.

Contingencies, Commitments, Guarantees and Indemnifications. We are involved in numerous lawsuits, claims, and proceedings in the normal course of our operations. We record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We review our loss contingencies on an ongoing basis to ensure that we have appropriate reserves recorded in our consolidated balance sheets. These reserves are based on estimates and judgments made by management with respect to the likely outcome of these matters, including any applicable insurance coverage, and are adjusted as circumstances warrant. Liabilities for environmental contingencies are recorded when an environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Measurement of liabilities is based, in part, on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs, and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of such liability.

We enter into various guarantees and indemnifications during the ordinary course of business. When a guarantee or indemnification is entered into, an estimated fair value of the underlying guarantee or indemnification is recorded. Some guarantees and indemnifications could have significant financial impact under certain circumstances; however, management also considers the probability of such circumstances occurring when estimating the fair value.

Preferred Stock. The outstanding shares of our Preferred Stock converted to approximately 12.9 million shares of Common Stock on November 1, 2017 (the “Mandatory Conversion Date”). Our preferred shares were mandatorily convertible, were not redeemable and are classified within stockholders’ equity. We presented the gross proceeds from their issuance as a single line item within stockholders’ equity on the consolidated balance sheets. Dividends on the preferred shares were cumulative and are presented as a reduction of net income (or increase of net loss) to derive net income (loss) attributable to common shareholders on the consolidated statements of operations. Dividends are recognized in stockholders’ equity in the period in which they are declared, and are presented as a financing activity on the consolidated statements of cash flows when paid.

On October 2, 2017, our Board of Directors declared a dividend on our mandatory convertible preferred stock of $1.34 per share, or approximately $5 million in the aggregate.

F-15

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

Revenue Recognition. We earn revenue from our facilities in three primary ways: (i) the sale of energy through both physical and financial transactions to optimize the financial performance of our generating facilities; (ii) the sale of capacity; and (iii) the sale of ancillary services, which are the products of a generation facility that support the transmission grid operation, allow generation to follow real-time changes in load, and provide emergency reserves for major changes to the balance of generation and load. We recognize revenue from these transactions when the product or service is delivered to a customer, unless they meet the definition of a derivative. Please read “Derivative Instruments—Generation” for further discussion of the accounting for these types of transactions.

Derivative Instruments—Generation. We enter into commodity contracts that meet the definition of a derivative. These contracts are often entered into to mitigate or eliminate market and financial risks associated with our generation business. These contracts include forward contracts, which commit us to buy or sell commodities in the future; futures contracts, which are generally broker-cleared standard commitments to purchase or sell a commodity; option contracts, which convey the right to buy or sell a commodity; and swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined quantity. All derivative commodity contracts that do not qualify for the “normal purchase, normal sale” exception are recorded at fair value in Risk management assets and liabilities in the consolidated balance sheets. We elect not to apply hedge accounting to our derivative commodity contracts; therefore, changes in fair value are recorded currently in Revenues in our consolidated statements of operations. As a result, these mark-to-market gains and losses are not reflected in the consolidated statements of operations in the same period as the underlying activity for which the derivative instruments serve as economic hedges. Derivative instruments and related cash collateral or margin that are executed with the same counterparty under a master netting agreement are reflected on a net basis in the consolidated balance sheets.

Cash inflows and cash outflows associated with the settlement of risk management activities are recognized in net cash provided by (used in) operating activities on the consolidated statements of cash flows.

Derivative Instruments—Financing Activities. We are exposed to changes in interest rates through our variable rate debt. In order to manage our interest rate risk, we enter into interest rate swap agreements. We elect not to apply hedge accounting to our interest rate derivative contracts; therefore, changes in fair value are recorded currently in earnings through interest expense. Cash settlements related to interest rate contracts are generally classified as either inflows or outflows from operating activities on the consolidated statements of cash flows. However, due to an other-than-insignificant financing element at inception on a portion of our interest rate swaps, certain of our cash flows related to these contracts are classified as financing activities. Please read Note 13—Debt for more information.

Fair Value Measurements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Our estimate of fair value reflects the impact of credit risk. We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs are classified as readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the classification of the inputs used to calculate the fair value of a transaction. The inputs used to measure fair value have been placed in a hierarchy based on priority.

F-16

The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

• Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities, and U.S. government treasury securities.

• Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using industry-standard models or other valuation methodologies in which substantially all assumptions are observable in the marketplace throughout the full term of the instrument, and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over the counter forwards, options, and swaps.

• Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to our needs. At each balance sheet date, we perform an analysis of all instruments and include in Level 3 all of those whose fair value is based on significant unobservable inputs.

The determination of fair value incorporates various factors. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities. Valuation adjustments are generally based on capital market implied ratings evidence when assessing the credit standing of our counterparties and, when applicable, adjusted based on management’s estimates of assumptions market participants would use in determining fair value.

Income Taxes. We file a consolidated U.S. federal income tax return. We use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant timing differences as of each reporting date. We also account for changes in the tax code when enacted.

As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing tax and accounting treatment of certain items, such as depreciation. These differences can result in deferred tax assets and liabilities which are included within our consolidated balance sheets and are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Because we operate and sell power in many different states, our effective annual state income tax rate may vary from period to period because of changes in our sales profile by state, as well as jurisdictional and legislative changes by state. As a result, changes in our estimated effective annual state income tax rate can have a significant impact on our measurement of temporary differences. We project the rates at which state tax temporary differences will reverse based upon estimates of revenues and operations in the respective jurisdictions in which we conduct business.

F-17

The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. In making this determination, we consider all available positive and negative evidence affecting specific deferred tax assets, including our past and anticipated future performance, the reversal of deferred tax liabilities, and the implementation of tax planning strategies.

Accounting for uncertainty in income taxes requires that we determine whether it is more likely than not that a tax position we have taken will be sustained upon examination. If we determine that it is more likely than not that the position will be sustained, we recognize the largest amount of the benefit that is greater than 50 percent likely of being realized upon settlement.

Please read Note 14—Income Taxes for further discussion of our accounting for income taxes, uncertain tax positions, and changes in our valuation allowance.

Earnings (Loss) Per Share. Basic earnings (loss) per share represents the amount of earnings for the period available to each share of common stock outstanding during the period. Diluted earnings (loss) per share includes the effect of issuing shares of common stock, assuming (i) stock options and warrants are exercised, (ii) restricted stock units and performance stock units are fully vested under the treasury stock method, and (iii) our mandatory convertible preferred stock and the prepaid stock purchase contracts (“SPCs”) are converted into common stock under the if-converted method.

Business Combinations Accounting. The Company accounts for its business combinations in accordance with ASC 805, Business Combinations (“ASC 805”), which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also requires an acquirer to measure any goodwill acquired and determine what information to disclose to enable users of an entity’s financial statements to evaluate the nature and financial effects of the business combination. In addition, ASC 805 requires transaction costs to be expensed as incurred.

Variable Interest Entities. We evaluate our interests in variable interest entities (“VIEs”) to determine if we are considered the primary beneficiary and should therefore consolidate the VIE. The primary beneficiary of a VIE is the party that both: (i) has the power to direct the activities of a VIE that most significantly impact its economic performance and (ii) has an obligation to absorb losses or a right to receive benefits that could potentially be significant to the VIE.

Accounting Standards Adopted

Goodwill. In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-04-Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. To simplify the subsequent measure of goodwill, the amendments in this ASU eliminate step two from the goodwill impairment test. An entity will no longer be required to calculate the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if the reporting unit had been acquired in a business combination to determine the impairment of goodwill. The amendments in this ASU will now require goodwill impairment to be measured by the amount by which the carrying value of the reporting unit exceeds its fair value. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Upon adoption, an entity shall apply the guidance in this ASU prospectively with early adoption permitted for annual goodwill tests performed after January 1, 2017. We adopted this ASU on January 1, 2017 with no material impact on our consolidated financial statements.

Statement of Cash Flows. In August 2016, the FASB issued ASU 2016-15-Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. To reduce current and future diversity in practice, the amendments in this ASU provide guidance for several cash flow classification issues identified where current GAAP is either unclear or does not include specific guidance. We early adopted this ASU as of December 31, 2016 and applied the amendments on a retrospective basis. The adoption of this ASU affected the classification of prepayments for future planned outage work performed under long-term service agreements. The majority of the cash prepayments required under these agreements will now be reflected as cash outflows from investing activities

F-18

and the remainder will be classified as cash outflows from operating activities, based on whether they are anticipated to be expensed or capitalized. As a result of the retrospective application of this ASU, we reclassified approximately $(33) million, and $26 million of cash prepayments from operating activities to investing activities in our consolidated statement of cash flows for the years ended December 31, 2016 and 2015, respectively.

In November 2016, the FASB issued ASU 2016-18-Statement of Cash Flows (Topic 230): Restricted Cash. The amendments in this ASU require that a statement of cash flows explains the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. We early adopted this ASU as of December 31, 2016 and applied the amendments on a retrospective basis. As a result of the retrospective application of this ASU, we reclassified a change of approximately $2 million and $26 million of restricted cash from operating activities and $2.021 billion and $5.148 billion of restricted cash from investing activities to Net increase (decrease) in cash, cash equivalents, and restricted cash in our consolidated statement of cash flows for the years ended December 31, 2016 and 2015, respectively. Additionally, restricted cash of $39 million and $2.062 billion are now reflected in the beginning of period and end of period cash, cash equivalents and restricted cash line items, respectively, in our consolidated statement of cash flows for the year ended December 31, 2016 and $5.213 billion and $39 million are now reflected in the beginning of period and end of period cash, cash equivalents and restricted cash line items, respectively, in our consolidated statement of cash flows for the year ended December 31, 2015.

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within our consolidated balance sheets that sum to the total of the same such amounts shown in our consolidated statements of cash flows:

(amounts in millions)	December 31, 2017		December 31, 2016		December 31, 2015
Cash and cash equivalents	$	365	$	1,776	$	505
Restricted cash included in current assets (1)		—		62		39
Restricted cash included in long-term assets (2)		—		2,000		—
Total cash, cash equivalents and restricted cash	$	365	$	3,838	$	544

(1) Year ended December 31, 2016, includes $41 million related to collateral and $21 million placed in escrow for the issuance of the Term Loan ($20 million of pre-funded original issue discount and $1 million interest income earned). Year ended December 31, 2015, includes $39 million related to collateral.

(2) Relates to amounts placed into escrow for the issuance of the Term Loan.

Compensation. In March 2016, the FASB issued ASU 2016-09-Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The amendments in this ASU simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. We adopted this ASU on January 1, 2017 with no material impact on our consolidated financial statements.

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Accounting Standards Not Yet Adopted

Business Combinations. In January 2017, the FASB issued ASU 2017-01-Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments in this ASU clarify the definition of a business. The amendments affect all companies and other reporting organizations that must determine whether they have acquired or sold a business. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption will have on our consolidated financial statements.

Pensions. In March 2017, the FASB issued ASU 2017-07-Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The amendments of this ASU require an entity to report the service cost component of net benefit costs in the same line item as other compensation costs arising from services rendered by the related employees during the applicable service period. The other components of net benefit cost are required to be presented separately from the service cost component and below the subtotal of operating income. Additionally, only the service cost component of net benefit costs is eligible for capitalization. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. The adoption of this standard must be applied on a retrospective basis for the amendments concerning income statement presentation and on a prospective basis for the amendments regarding the capitalization of the service cost component. We are currently evaluating this ASU and any potential impacts the adoption will have on our consolidated financial statements.

Leases. In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842). The provisions in this ASU will require lessees to recognize lease assets and lease liabilities, for all leases, including operating leases, on the balance sheet. The lease assets recognized in the balance sheet will represent a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The lease liability recognized in the balance sheet will represent the lessee’s obligation to make lease payments arising from a lease, measured based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets or lease liabilities for leases with a term of 12 months or less. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We have established an implementation team to assess the impact the new accounting standard will have on our financial statements, as well as accounting policies, business processes and controls.

Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09-Revenue from Contracts with Customers (Topic 606). This ASU supersedes current revenue recognition requirements and industry specific guidance and develops a common revenue recognition standard whereby an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing, and uncertainty of revenues and cash flows from contracts with customers. The guidance in this ASU and its amendments are effective for interim and annual periods beginning after December 15, 2017, unless early adopted. We intend on adopting the ASU using the modified retrospective approach.

We have finalized our evaluation of the impact that the new accounting standard will have on our financial statements. As a result of our evaluation, the Company did not identify any material changes to the timing of our revenue recognition. Changes to our disclosures will primarily include a regional presentation of our revenues disaggregated by revenue type - energy, capacity, and ancillary services, as well as disclosure of future performance obligations. We have assessed our accounting policies and internal processes and controls, and identified changes which will become effective upon adoption.

F-20

Note 3—Acquisitions and Divestitures

Acquisitions

ENGIE Acquisition. On the ENGIE Acquisition Closing Date, pursuant to the terms of the stock purchase agreement, as amended and restated on June 27, 2016, (the “ENGIE Acquisition Stock Purchase Agreement”), Dynegy acquired approximately 9,017 MW of generation from GDF SUEZ Energy North America, Inc. (“GSENA”) and International Power, S.A. (the “Seller”), including (i) 15 natural gas-fired facilities located in Illinois, Massachusetts, New Jersey, Ohio, Pennsylvania, Texas, Virginia, and West Virginia, (ii) one coal-fired facility in Texas, and (iii) one waste coal-fired facility in Pennsylvania for a base purchase price of approximately $3.3 billion in cash, subject to certain adjustments (the “ENGIE Acquisition”).

Business Combination Accounting

The ENGIE Acquisition has been accounted for in accordance with ASC 805 with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the ENGIE Acquisition Closing Date. A summary of the various techniques used to fair value the identifiable assets and liabilities, as well as their classification within the fair value hierarchy are listed below.

• Working capital was valued using available market information (Level 2).

• Acquired PP&E, excluding those assets classified as held-for-sale, was valued using a discounted cash flow (“DCF”) analysis based upon a debt-free, free cash flow model (Level 3). The DCF model was created for each power generation facility based on its remaining useful life, and:

• for the years 2017 and 2018, included gross margin forecasts using quoted forward commodity market prices;

• for the years 2019 through 2026, we used gross margin forecasts based upon commodity and capacity price curves developed internally using forward New York Mercantile Exchange natural gas prices and supply and demand factors;

• for periods beyond 2026, we assumed a 2.5 percent growth rate.

We also used management’s forecasts of operations and maintenance expense, general and administrative expense, as well as capital expenditures for the years 2017 through 2021, and for years thereafter assumed a 2.5 percent growth rate. These cash flows were discounted using discount rates of approximately 9 percent to 13 percent for gas-fired, and approximately 13 percent to 14 percent for coal-fired, generation facilities, based upon the plant’s age, efficiency, region, and years until retirement.

• Acquired PP&E classified as held-for-sale was valued based upon the sale price of the assets (Level 3).

• Acquired derivatives were valued using the methods described in Note 5—Fair Value Measurements (Level 2 or Level 3).

• Contracts with terms that were not at current market prices were also valued using a DCF analysis (Level 3). The cash flows generated by the contracts were compared with their cash flows based on current market prices with the resulting difference recorded as either an intangible asset or liability.

• AROs were recorded in accordance with ASC 410, Asset Retirement and Environmental Obligations (Level 3).

F-21

The accounting for the ENGIE Acquisition is not complete because certain information and analysis that may impact our initial valuation is still being obtained or reviewed. Dynegy expects to finalize these amounts during the first quarter of 2018. The significant assets and liabilities for which provisional amounts are recognized are PP&E, deferred income taxes, and taxes other than deferred income taxes. Additionally, some taxes have not yet been finalized with the associated taxing jurisdictions, resulting in a potential change to their fair value at acquisition. These changes may also impact the fair value of the acquired PP&E or deferred tax liability. As such, the provisional amounts recognized are subject to revision until our valuation is completed, not to exceed one year from the ENGIE Acquisition Closing Date, and any material adjustments identified that existed as of the acquisition date will be recognized in the period in which they are identified.

The following table summarizes the consideration paid and the provisional fair value amounts recognized for the assets acquired and liabilities assumed related to the ENGIE Acquisition, as of the acquisition date, February 7, 2017:

(amounts in millions)
Base purchase price	$	3,300
Working capital adjustments and other		(31	)
Fair value of total consideration transferred	$	3,269
Cash	$	20
Accounts receivable		22
Inventory		95
Prepayments and other current assets		3
Assets from risk management activities (including current portion of $21 million)		25
Property, plant and equipment		2,775
Investment in unconsolidated affiliate		132
Intangible assets (including current portion of $7 million)		50
Assets held-for-sale		472
Other long-term assets		131
Total assets acquired		3,725
Accounts payable		18
Liabilities from risk management activities (including current portion of $13 million)		16
Asset retirement obligations		19
Intangible liabilities (including current portion of $16 million)		30
Deferred income taxes, net		372
Other long-term liabilities		1
Total liabilities assumed		456
Net assets acquired	$	3,269

F-22

EquiPower Acquisition. On April 1, 2015, we purchased 100 percent of the equity interests in EquiPower Resources Corp. (“ERC”) from certain affiliates of ECP thereby acquiring (i) five combined-cycle natural gas-fired facilities in Connecticut, Massachusetts, and Pennsylvania, (ii) a partial interest in one natural gas-fired peaking facility in Illinois, (iii) two gas- and oil-fired peaking facilities in Ohio, and (iv) one coal-fired facility in Illinois (the “ERC Acquisition”). In a related transaction on the same date, we purchased, through a wholly owned subsidiary, 100 percent of the equity interests in Brayton Point Holdings, LLC (“Brayton”) from certain affiliates of Energy Capital Partners (“ECP”), thereby acquiring a coal-fired facility in Massachusetts (the “Brayton Acquisition”).

The ERC Acquisition and the Brayton Acquisition (collectively, the “EquiPower Acquisition”) added approximately 6,300 MW of generation in Connecticut, Illinois, Massachusetts, Ohio, and Pennsylvania for an aggregate base purchase price of approximately $3.35 billion in cash plus approximately $105 million in common stock of Dynegy, subject to certain adjustments.

Duke Midwest Acquisition. On April 2, 2015, we purchased 100 percent of the membership interests in Duke Energy Commercial Asset Management, LLC and Duke Energy Retail Sales, LLC, from two affiliates of Duke Energy Corporation (collectively, “Duke Energy”), thereby acquiring approximately 6,200 MW of generation in (i) three combined-cycle natural gas-fired facilities located in Ohio and Pennsylvania, (ii) two natural gas-fired peaking facilities located in Ohio and Illinois, (iii) one oil-fired peaking facility located in Ohio, (iv) partial interests in five coal-fired facilities located in Ohio, and (v) one retail energy business for a base purchase price of $2.8 billion in cash (the “Duke Midwest Acquisition”), subject to certain adjustments.

The following table summarizes acquisition costs incurred related to the ENGIE Acquisition, the EquiPower Acquisition and the Duke Midwest Acquisition, which are included in Acquisition and integration costs in our consolidated statements of operations, and revenues and operating income (loss) attributable to the acquisitions, which are included in our consolidated statements of operations:

F-23

	Year Ended December 31,
(amounts in millions)	2017		2016		2015
Acquisition costs	$	38	$	5	$	86
Revenues	$	3,079	$	2,280	$	1,703
Operating income	$	86	$	235	$	230

Pro Forma Results. The unaudited pro forma financial results for the years ended December 31, 2017, 2016 and 2015 assume the February 2017 ENGIE Acquisition occurred on January 1, 2016 and the April 2015 EquiPower and Duke Midwest Acquisitions occurred on January 1, 2014. The unaudited pro forma financial results may not be indicative of the results that would have occurred had the acquisitions been completed on the above dates, nor are they indicative of future results of operations. The unaudited pro forma financial results for the three years ended December 31, 2017 include adjustments of $38 million, $5 million, and $86 million, respectively, for non-recurring acquisition costs.

	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Revenues	$	4,899		$	5,046		$	4,860
Net income (loss)	$	77		$	(1,361	)	$	308
Net loss attributable to noncontrolling interest	$	(4	)	$	(4	)	$	(3	)
Net income (loss) attributable to Dynegy Inc.	$	81		$	(1,357	)	$	311

Other. On April 12, 2017, we received approximately $25 million of cash related to the 2013 New Ameren Energy Resources, LLC (“AER”) Acquisition. As a result, we have recorded $25 million in Other income and expense, net in our consolidated statement of operations for the year ended December 31, 2017.

During the year ended December 31, 2016, we received proceeds of $14 million of cash related to the AER Acquisition. As a result, we recorded $14 million in Other income and expense, net in our consolidated statement of operations for the year ended December 31, 2016.

Divestitures

Troy and Armstrong. On July 11, 2017, Dynegy completed the sale of its equity ownership interests in two peaking facilities in PJM to LS Power (the “Troy and Armstrong Sale”) for approximately $472 million in cash, including working capital adjustments. The facilities sold were recently acquired in the ENGIE Acquisition and total 1,269 MW.

Dighton and Milford-MA. On September 22, 2017, Dynegy completed the sale of its equity ownership interests in two intermediate natural gas-fueled facilities to Starwood Energy Group for approximately $125 million in cash, including working capital adjustments. This sale has fulfilled the mitigation plan approved by FERC regarding the Company’s purchase of ENGIE’s US-based asset portfolio. For the year ended December 31, 2017, we recognized a loss on sale of assets on our Dighton and Milford-MA facilities of $90 million, which includes $18 million of allocated goodwill. Goodwill was allocated based on the relative fair values of Dighton and Milford-MA compared to the fair values of the remaining reporting unit.

F-24

Lee. On October 12, 2017, Dynegy completed the sale of its equity ownership in the Lee facility, a natural gas-fueled peaking facility in PJM, to an affiliate of Rockland Capital for $176 million in cash, including working capital adjustments.

Our Lee facility met Held-for-Sale criteria during the third quarter of 2017. As a result, we wrote down the carrying value of the assets held-for-sale to the sales price and recognized an impairment of $15 million, which includes $9 million of allocated goodwill and was recorded in Impairments in our consolidated statements of operations. Additionally, upon the closing of the sale, we recorded a $5 million loss to Loss on sale of assets, net in our consolidated statements of operations.

Note 4—Risk Management Activities, Derivatives and Financial Instruments

The nature of our business involves commodity market and financial risks. Specifically, we are exposed to commodity price variability related to our power generation business. Our commercial team manages these commodity price risks with financially and physically settled contracts consistent with our commodity risk management policy. Our treasury team manages our interest rate risk.

Our commodity risk management policy gives us the flexibility to sell energy and capacity and purchase fuel through a combination of spot market sales and near-term contractual arrangements (generally over a rolling one- to three-year time frame). Our commodity risk management goal is to protect cash flow in the near-term while keeping the ability to capture value longer-term.

Many of our contractual arrangements are derivative instruments and are accounted for at fair value as part of Revenues in our consolidated statements of operations. We have other contractual arrangements such as capacity forward sales arrangements, tolling arrangements, fixed price coal purchases and retail power sales which do not receive recurring fair value accounting treatment because these arrangements do not meet the definition of a derivative or are designated as “normal purchase, normal sale,” in accordance with ASC 815, Derivatives and Hedging. As a result, the gains and losses with respect to these arrangements are not reflected in the consolidated statements of operations until the delivery occurs.

Quantitative Disclosures Related to Financial Instruments and Derivatives

As of December 31, 2017, we had net purchases and sales of derivative contracts outstanding in the following quantities:

Contract Type	Quantity			Unit of Measure		Fair Value (1)
(dollars and quantities in millions)	Purchases (Sales)					Asset (Liability)
Commodity contracts:
Electricity derivatives (2)		(62	)		MWh	$	(150	)
Electricity basis derivatives (3)		(25	)		MWh	$	(4	)
Natural gas derivatives (2)		404			MMBtu	$	(4	)
Natural gas basis derivatives		120			MMBtu	$	(1	)
Physical heat rate derivatives (4)		177/	(17)		MMBtu/MWh	$	(95	)
Heat rate option		6/	(1)		MMBtu/MWh	$	(4	)
Emissions derivatives		8			Metric Ton	$	2
Interest rate swaps		1,961			U.S. Dollar	$	7
Common stock warrants (5)		9			Warrant	$	(2	)

(1) Includes both asset and liability risk management positions but excludes margin and collateral netting of $47 million.

(2) Mainly comprised of swaps and physical forwards.

(3) Comprised of FTRs and swaps.

(4) Comprised of swaps which settle on the relationship of power pricing to natural gas pricing.

(5) Each warrant is convertible into one share of Dynegy common stock.

F-25

Derivatives on the Balance Sheet. The following tables present the fair value and balance sheet classification of derivatives in our consolidated balance sheets as of December 31, 2017 and 2016. As of December 31, 2017 and 2016, there were no gross amounts available to be offset that were not offset in our consolidated balance sheets.

		December 31, 2017
					Gross amounts offset in the balance sheet
Contract Type	Balance Sheet Location	Gross Fair Value			Contract Netting			Collateral or Margin Received or Paid		Net Fair Value
(amounts in millions)
Derivative assets:
Commodity contracts	Assets from risk management activities	$	155		$	(112	)	$	—	$	43
Interest rate contracts	Assets from risk management activities		20			(5	)		—		15
Total derivative assets		$	175		$	(117	)	$	—	$	58
Derivative liabilities:
Commodity contracts	Liabilities from risk management activities	$	(411	)	$	112		$	47	$	(252	)
Interest rate contracts	Liabilities from risk management activities		(13	)		5			—		(8	)
Common stock warrants	Accrued liabilities and other current liabilities and other long-term liabilities		(2	)		—			—		(2	)
Total derivative liabilities		$	(426	)	$	117		$	47	$	(262	)
Total derivatives		$	(251	)	$	—		$	47	$	(204	)

F-26

		December 31, 2016
					Gross amounts offset in the balance sheet
Contract Type	Balance Sheet Location	Gross Fair Value			Contract Netting			Collateral or Margin Received or Paid		Net Fair Value
(amounts in millions)
Derivative assets:
Commodity contracts	Assets from risk management activities	$	311		$	(165	)	$	—	$	146
Total derivative assets		$	311		$	(165	)	$	—	$	146
Derivative liabilities:
Commodity contracts	Liabilities from risk management activities	$	(329	)	$	165		$	54	$	(110	)
Interest rate contracts	Liabilities from risk management activities		(30	)		—			—		(30	)
Common stock warrants	Accrued liabilities and other current liabilities		(1	)		—			—		(1	)
Total derivative liabilities		$	(360	)	$	165		$	54	$	(141	)
Total derivatives		$	(49	)	$	—		$	54	$	5

Certain of our derivative instruments have credit limits that require us to post collateral. The amount of collateral required to be posted is a function of the net liability position of the derivative as well as our established credit limit with the respective counterparty. If our credit rating were to worsen, the counterparties could require us to post additional collateral. The amount of additional collateral that would be required to be posted would vary depending on the extent of change in our credit rating as well as the requirements of the individual counterparty. As of December 31, 2017, the aggregate fair value of all commodity derivative instruments containing credit-risk-related contingent features, in a liability position and not fully collateralized, is $32 million for which we have posted no collateral. Transactions with our clearing brokers are excluded as they are fully collateralized. Our remaining derivative instruments do not have credit-related collateral contingencies as they are included within our first-lien collateral program.

The following table summarizes our cash collateral posted as of December 31, 2017 and 2016, within Prepayments and other current assets in our consolidated balance sheets, and the amount applied against short-term risk management activities:

Location on Balance Sheet	December 31, 2017		December 31, 2016
(amounts in millions)
Gross collateral posted with counterparties	$	92	$	116
Less: Collateral netted against risk management liabilities		47		54
Net collateral within Prepayments and other current assets	$	45	$	62

F-27

Impact of Derivatives on the Consolidated Statements of Operations

We elect not to designate derivatives related to our power generation business and interest rate instruments as cash flow or fair value hedges. Thus, we account for changes in the fair value of these derivatives within our consolidated statements of operations.

Our consolidated statements of operations for the years ended December 31, 2017, 2016 and 2015 include the impact of derivative financial instruments as presented below.

Derivatives Not Designated as Hedges	Location of Gain (Loss) Recognized in Income on Derivatives	Year Ended December 31,
		2017			2016			2015
(amounts in millions)
Commodity contracts	Revenues	$	(58	)	$	270		$	194
Interest rate contracts	Interest expense	$	16		$	(5	)	$	(15	)
Common stock warrants	Other income and (expense), net	$	16		$	6		$	54

Note 5—Fair Value Measurements

We apply the market approach for recurring fair value measurements, employing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We have consistently used the same valuation techniques for all periods presented. Please read Note 2—Summary of Significant Accounting Policies—Fair Value Measurements for further discussion.

The finance organization monitors commodity risk through the Commodity Risk Control Group (“CRCG”). The Executive Management Team (“EMT”) monitors interest rate risk. The EMT has delegated the responsibility for managing interest rate risk to the Chief Financial Officer (“CFO”). The CRCG is independent of our commercial operations and has direct access to the Audit Committee. The Finance and Risk Management Committee, comprised of members of management and chaired by the CFO, meets periodically and is responsible for reviewing our overall day-to-day energy commodity risk exposure, as measured against the limits established in our Commodity Risk Policy. Each quarter, as part of its internal control processes, representatives from the CRCG review the methodology and assumptions behind the pricing of the forward curves. As part of this review, liquidity periods are established based on third party market information, the basis relationship between direct and derived curves is evaluated, and changes are made to the forward power model assumptions.

The CRCG reviews changes in value on a daily basis through the use of various reports. The pricing for power, natural gas, and fuel oil curves is automatically entered into our commercial system nightly based on data received from our market data provider. The CRCG reviews the data provided by the market data provider by utilizing third party broker quotes for comparison purposes. In addition, our traders are required to review various reports to ensure accuracy on a daily basis.

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 and 2016, and are presented on a gross basis before consideration of amounts netted under master netting agreements and the application of collateral and margin paid:

F-28

	Fair Value as of December 31, 2017
(amounts in millions)	Level 1			Level 2			Level 3			Total
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—		$	71		$	6		$	77
Natural gas derivatives		—			62			10			72
Physical heat rate derivatives		—			4			—			4
Emissions derivatives		—			2			—			2
Total assets from commodity risk management activities		—			139			16			155
Assets from interest rate contracts		—			20			—			20
Total assets	$	—		$	159		$	16		$	175
Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives	$	—		$	(200	)	$	(31	)	$	(231	)
Natural gas derivatives		—			(71	)		(6	)		(77	)
Physical heat rate derivatives		—			(99	)		—			(99	)
Heat rate option		—			—			(4	)		(4	)
Total liabilities from commodity risk management activities		—			(370	)		(41	)		(411	)
Liabilities from interest rate contracts		—			(13	)		—			(13	)
Liabilities from outstanding common stock warrants		(2	)		—			—			(2	)
Total liabilities	$	(2	)	$	(383	)	$	(41	)	$	(426	)

F-29

	Fair Value as of December 31, 2016
(amounts in millions)	Level 1			Level 2			Level 3			Total
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—		$	118		$	20		$	138
Natural gas derivatives		—			169			4			173
Total assets from commodity risk management activities	$	—		$	287		$	24		$	311
Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives	$	—		$	(245	)	$	(12	)	$	(257	)
Natural gas derivatives		—			(52	)		(10	)		(62	)
Emissions derivatives		—			(10	)		—			(10	)
Total liabilities from commodity risk management activities		—			(307	)		(22	)		(329	)
Liabilities from interest rate contracts		—			(30	)		—			(30	)
Liabilities from outstanding common stock warrants		(1	)		—			—			(1	)
Total liabilities	$	(1	)	$	(337	)	$	(22	)	$	(360	)

Level 3 Valuation Methods. The electricity derivatives classified within Level 3 include financial swaps executed in illiquid trading locations or on long dated contracts, capacity contracts, heat rate derivatives, and FTRs. The curves used to generate the fair value of the financial swaps are based on basis adjustments applied to forward curves for liquid trading points, while the curves for the capacity deals are based upon auction results in the marketplace, which are infrequently executed. The forward market price of FTRs is derived using historical congestion patterns within the marketplace, heat rate derivative valuations are derived using a DCF model, which uses modeled forward natural gas and power prices, and the heat rate option is derived using a Black-Scholes spread model, which uses forward natural gas and power prices, market implied volatilities, and modeled correlation values. The natural gas derivatives classified within Level 3 include financial swaps, basis swaps, and physical purchases executed in illiquid trading locations or on long dated contracts.

F-30

Sensitivity to Changes in Significant Unobservable Inputs for Level 3 Valuations. The significant unobservable inputs used in the fair value measurement of our commodity instruments categorized within Level 3 of the fair value hierarchy include estimates of forward congestion, power price spreads, and natural gas pricing, and the difference between our plant locational prices to liquid hub prices. Power price spreads, and natural gas pricing, and the difference between our plant locational prices to liquid hub prices are generally based on observable markets where available, or derived from historical prices and forward market prices from similar observable markets when not available. Increases in the price of the spread on a buy or sell position in isolation would result in a higher/lower fair value measurement. The significant unobservable inputs used in the valuation of Dynegy’s contracts classified as Level 3 as of December 31, 2017 are as follows:

Transaction Type

Quantity

Unit of Measure

Net Fair Value

Valuation Technique

Significant Unobservable Input

Significant Unobservable Input Range

(dollars in millions)

Electricity derivatives:

Forward contracts—power (1)

(14

)

Million MWh

$

(23

)

Basis spread + liquid location

Basis spread

$4.25 - $6.25

FTRs

(22

)

Million MWh

$

(2

)

Historical congestion

Forward price

$0 - $6.00

Physical heat rate derivatives

4/0

Million MMBtu /Million MWh

$

—

Discounted Cash Flow

Forward price

$2.00 - $2.80 / $22 - $27

Heat rate option

6/1

Million MMBtu /Million MWh

$

(4

)

Option models

Power price volatility Gas/ Power price correlation

30% - 50% / 70% - 100%

Natural gas derivatives (1)

95

Million MMBtu

$

4

Illiquid location fixed price

Forward price

$2.00 - $2.45

(1) Represents forward financial and physical transactions at illiquid pricing locations and long-dated contracts.

F-31

The following tables set forth a reconciliation of changes in the fair value of financial instruments classified as Level 3 in the fair value hierarchy:

	Year Ended December 31, 2017
(amounts in millions)	Electricity Derivatives			Natural Gas Derivatives			Heat Rate Option			Total
Balance at December 31, 2016	$	8		$	(6	)	$	—		$	2
Total gains (losses) included in earnings		(30	)		5			—			(25	)
Settlements (1)		(4	)		5			—			1
Option premiums received		—			—			(4	)		(4	)
Acquired derivatives		1			—			—			1
Balance at December 31, 2017	$	(25	)	$	4		$	(4	)	$	(25	)
Unrealized gains (losses) relating to instruments held as of December 31, 2017	$	(30	)	$	5		$	—		$	(25	)
	Year Ended December 31, 2016
(amounts in millions)	Electricity Derivatives			Natural Gas Derivatives			Coal Derivatives			Total
Balance at December 31, 2015	$	(18	)	$	(32	)	$	2		$	(48	)
Total gains (losses) included in earnings		59			49			(4	)		104
Settlements (1)		(33	)		(23	)		2			(54	)
Balance at December 31, 2016	$	8		$	(6	)	$	—		$	2
Unrealized gains (losses) relating to instruments held as of December 31, 2016	$	59		$	49		$	(4	)	$	104

F-32

	Year Ended December 31, 2015
(amounts in millions)	Electricity Derivatives			Natural Gas Derivatives			Heat Rate Derivatives			Coal Derivatives			Total
Balance at December 31, 2014	$	(4	)	$	—		$	—		$	—		$	(4	)
Total gains included in earnings		39			3			—			—			42
Settlements (1)		1			28			9			(2	)		36
Acquired derivatives		(54	)		(63	)		(9	)		4			(122	)
Balance at December 31, 2015	$	(18	)	$	(32	)	$	—		$	2		$	(48	)
Unrealized gains relating to instruments held as of December 31, 2015	$	39		$	3		$	—		$	—		$	42

(1) For purposes of these tables, we define settlements as the beginning of period fair value of contracts that settled during the period.

Gains and losses recognized for Level 3 recurring items are included in Revenues in our consolidated statements of operations for commodity derivatives. We believe an analysis of commodity instruments classified as Level 3 should be undertaken with the understanding that these items generally serve as economic hedges of our power generation portfolio. We did not have any material transfers between Level 1, Level 2 and Level 3 for the years ended December 31, 2017 and 2016.

Nonfinancial Assets and Liabilities. Nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of such assets and liabilities and their placement within the fair value hierarchy.

Impairments. During the years ended December 31, 2017, 2016 and 2015, we recorded impairment charges related to certain of our facilities, materials and supplies inventory and assets held-for-sale using fair value measurements. See Note 3—Acquisitions and Divestitures, Note 7—Inventory and Note 8—Property, Plant and Equipment for further discussion. Certain impairments were determined through a DCF model using similar fair value methodologies used to value our business acquisitions.

Fair Value of Financial Instruments. The following table discloses the fair value of financial instruments which are not recognized at fair value in our consolidated balance sheets. Unless otherwise noted, the fair value of debt as reflected in the table has been calculated based on the average of certain available broker quotes as of December 31, 2017 and 2016, respectively.

F-33

			December 31, 2017						December 31, 2016
(amounts in millions)	Fair Value Hierarchy		Carrying Amount			Fair Value			Carrying Amount			Fair Value
Dynegy Inc.:
Term Loan, due 2024 (1)		Level 2	$	(1,944	)	$	(2,021	)	$	(2,213	)	$	(2,250	)
Revolving Facility (1)		Level 2	$	—		$	—		$	—		$	—
6.75% Senior Notes, due 2019 (1)		Level 2	$	(845	)	$	(873	)	$	(2,083	)	$	(2,137	)
7.375% Senior Notes, due 2022 (1)		Level 2	$	(1,734	)	$	(1,844	)	$	(1,731	)	$	(1,665	)
5.875% Senior Notes, due 2023 (1)		Level 2	$	(493	)	$	(508	)	$	(492	)	$	(431	)
7.625% Senior Notes, due 2024 (1)		Level 2	$	(1,237	)	$	(1,344	)	$	(1,237	)	$	(1,156	)
8.034% Senior Notes, due 2024 (1)		Level 2	$	(188	)	$	(198	)	$	—		$	—
8.00% Senior Notes, due 2025 (1)		Level 2	$	(739	)	$	(812	)	$	(738	)	$	(703	)
8.125% Senior Notes, due 2026 (1)		Level 2	$	(842	)	$	(933	)	$	—		$	—
7.00% Amortizing Notes, due 2019 (TEUs) (1)		Level 2	$	(51	)	$	(54	)	$	(78	)	$	(90	)
Forward capacity agreement (1)		Level 3	$	(215	)	$	(215	)	$	(205	)	$	(205	)
Inventory financing agreements		Level 3	$	(48	)	$	(48	)	$	(129	)	$	(127	)
Equipment financing agreements (1)		Level 3	$	(97	)	$	(97	)	$	(73	)	$	(73	)
Genco:
Liabilities subject to compromise (2)		Level 3	$	—		$	—		$	(825	)	$	(366	)

(1) Carrying amounts include unamortized discounts and debt issuance costs. Please read Note 13—Debt for further discussion.

(2) Carrying amounts represent the Genco senior notes that were classified as liabilities subject to compromise as of December 31, 2016. The fair value of the senior notes was equal to the Genco Plan consideration and is a Level 3 valuation due to a lack of observable inputs that make up the consideration. Please read Note 20—Genco Chapter 11 Bankruptcy for further details.

Concentration of Credit Risk. We sell our energy products and services to customers in the electric and natural gas distribution industries, financial institutions, residential customers and to entities engaged in commercial and industrial businesses. These industry concentrations have the potential to impact our overall exposure to credit risk, either positively or negatively, because the customer base may be similarly affected by changes in economic, industry, weather or other conditions.

At December 31, 2017 and 2016, our credit exposure as it relates to the mark-to-market portion of our risk management portfolio totaled $7 million and $79 million, respectively.

F-34

Our Credit Department, based on guidelines approved by the Board of Directors, establishes our counterparty credit limits. Our credit risk system provides current credit exposure to counterparties on a daily basis. Our industry typically operates under negotiated credit lines for physical delivery and financial contracts. We enter into master netting agreements in an attempt to both mitigate credit exposure and reduce collateral requirements. In general, the agreements include our risk management subsidiaries and allow the aggregation of credit exposure, margin and set-off. We attempt to further reduce credit risk with certain counterparties by obtaining third party guarantees or collateral as well as the right of termination in the event of default. As a result, we decrease a potential credit loss arising from a counterparty default.

We include cash collateral deposited with brokers and cash paid to non-broker counterparties which has not been offset against risk management liabilities in Prepayments and other current assets in our consolidated balance sheets. As of December 31, 2017 and 2016, we had $45 million and $62 million recorded to Prepayments and other current assets, respectively. We include cash collateral received from non-broker counterparties in Accrued liabilities and other current liabilities in our consolidated balance sheets. As of December 31, 2017 and 2016, we were not holding any collateral received from counterparties.

Note 6—Cash Flow Information

The supplemental disclosures of cash flow and non-cash investing and financing information are as follows:

	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Interest paid (net of amount capitalized of $2, $10, and $12, respectively)	$	555		$	548		$	491
Taxes paid (net of refunds)	$	(5	)	$	(1	)	$	2
Other non-cash investing and financing activity:
Change in capital expenditures included in accounts payable	$	7		$	(13	)	$	(8	)
Change in capital expenditures pursuant to equipment financing agreements	$	24		$	11		$	63
Issuance of 2017 Warrants	$	17		$	—		$	—
Issuance of senior notes related to the Genco restructuring	$	188		$	—		$	—
Sale of interest in Conesville facility	$	(58	)	$	—		$	—
Acquisition of interest in Zimmer facility	$	27		$	—		$	—
Non-cash consideration transferred for acquisitions	$	—		$	—		$	105

F-35

Note 7—Inventory

A summary of our inventories is as follows:

(amounts in millions)	December 31, 2017		December 31, 2016
Materials and supplies	$	242	$	182
Coal		166		238
Fuel oil		15		17
Natural gas		9		—
Emissions allowances (1)		13		8
Total	$	445	$	445

(1) At December 31, 2017 and December 31, 2016, a portion of this inventory was held as collateral by one of our counterparties as part of an inventory financing agreement. Please read Note 13—Debt—Emissions Repurchase Agreements for further discussion.

As discussed in Note 9—Joint Ownership of Generating Facilities, Stuart Unit 1 was retired early on September 30, 2017, with remaining Stuart and Killen units scheduled to be retired by mid-2018. We determined that we would not be able to recover the carrying value of our inventory at these facilities and, as a result, recognized a charge of $14 million in Impairments in our consolidated statements of operations for the year ended December 31, 2017.

Note 8—Property, Plant and Equipment

A summary of our property, plant and equipment is as follows:

(amounts in millions)	December 31, 2017			December 31, 2016
Power generation	$	9,998		$	7,537
Buildings and improvements		955			944
Office and other equipment		115			98
Property, plant and equipment		11,068			8,579
Accumulated depreciation		(2,184	)		(1,458	)
Property, plant and equipment, net	$	8,884		$	7,121

F-36

The following table summarizes total interest costs incurred and interest capitalized related to costs of construction projects in process:

	Year Ended December 31,
(amounts in millions)	2017		2016		2015
Total interest costs incurred	$	576	$	556	$	487
Capitalized interest	$	2	$	10	$	12

Impairments

During the years ended December 31, 2017, 2016 and 2015, we recognized the following impairments in our consolidated statements of operations (amounts in millions).

Facility	Fair Value		2017		2016		2015
Baldwin (1)	$	97	$	—	$	645	$	—
Stuart (2)	$	—		—		56		—
Newton FGD (3)	$	—		—		148		—
Killen (4)	$	—		20		—		—
Hennepin (1)	$	16		10		—		—
Havana (1)	$	37		89		—		—
Wood River (5)	$	—		—		—		74
Brayton Point (6)	$	86		—		—		25
Total PP&E Impairments			$	119	$	849	$	99
Inventory	$	—		14		—		—
Equity investment	$	173		—		9		—
Assets held-for-sale, including $9 of allocated goodwill	$	176		15		—		—
Total Impairments			$	148	$	858	$	99

F-37

(1) Units failed to recover their basic operating costs in the MISO capacity auctions. The impairment was measured using a DCF model. As part of our impairment analysis, we changed the remaining useful lives of certain of our facilities.

(2) We determined that the facility would experience recurring negative cash flows due to on-going required maintenance and environmental capital expenditures, combined with consistently poor reliability. The impairment was measured using a DCF model.

(3) We terminated the flue gas desulfurization (“FGD”) systems construction project at our Newton generation facility. The impairment charge was equal to the capitalized cost of the project.

(4) In first quarter 2017, Dayton Power and Light Co., the partner and operator of Killen, announced the shutdown of the Killen generation facility by June 2018. As a result, the DCF model for the facility indicated negative cash flows, resulting in an impairment charge equal to its book value.

(5) Primarily attributable to its uneconomic operation stemming from a poorly designed wholesale capacity market and increased environmental costs. The impairment was measured using a DCF model.

(6) Temperate weather had a significant impact on the facility’s remaining cash flows, as the facility retired in May 2017. The impairment was measured using a DCF model.

Brayton Point Retirement

The Brayton Point facility officially retired on June 1, 2017. During the year ended December 31, 2017, we recognized approximately $12 million of severance costs, which were classified within Operating and maintenance expense in our consolidated statement of operations.

Note 9—Joint Ownership of Generating Facilities

We hold ownership interests in certain jointly owned generating facilities. We are entitled to the proportional share of the generating capacity and the output of each unit equal to our ownership interests. We pay our share of capital expenditures, fuel inventory purchases, and operating expenses, except in certain instances where agreements have been executed to limit certain joint owners’ maximum exposure to the additional costs. Our share of revenues and operating costs of the jointly owned generating facilities is included within the corresponding financial statement line items in our consolidated statements of operations.

F-38

During 2017, in an effort to simplify structure and drive operating efficiencies, we acquired or exchanged ownership interests in certain of our jointly owned generating facilities. As a result, we now own 100 percent of Miami Fort and Zimmer and disposed of our full interest in Conesville. No ownership changes occurred related to the Stuart and Killen facilities, as they are scheduled to be retired mid-2018. The following tables present the ownership interests of the jointly owned facilities as of December 31, 2017 and 2016 included in our consolidated balance sheets. Each facility is co-owned with one or more other generation companies.

	December 31, 2017
(dollars in millions)	Ownership Interest			Property, Plant and Equipment		Accumulated Depreciation			Construction Work in Progress		Total
Stuart (1)(2)		39.0	%	$	1	$	—		$	—	$	1
Killen (1)(2)		33.0	%	$	—	$	—		$	—	$	—
	December 31, 2016
(dollars in millions)	Ownership Interest			Property, Plant and Equipment		Accumulated Depreciation			Construction Work in Progress		Total
Miami Fort		64.0	%	$	207	$	(39	)	$	4	$	172
Stuart (1)		39.0	%	$	—	$	—		$	4	$	4
Conesville (1)		40.0	%	$	61	$	(3	)	$	6	$	64
Zimmer		46.5	%	$	115	$	(25	)	$	6	$	96
Killen (1)		33.0	%	$	19	$	(2	)	$	3	$	20

(1) Facilities not operated by Dynegy.

(2) Stuart Unit 1 was retired early on September 30, 2017, with remaining Stuart and Killen units scheduled to be retired by mid-2018.

On May 9, 2017, Dynegy finalized the sale of its 40 percent ownership interest in Conesville to American Electric Power (“AEP”) in exchange for AEP’s 25.4 percent ownership interest in Zimmer. As a result, Dynegy then owned 71.9 percent of the Zimmer facility and no longer had an ownership interest in the Conesville facility. No cash was exchanged in the transaction and no additional debt was incurred by either party. AEP returned a previously issued letter of credit totaling $58 million to Dynegy. The fair value of the additional Zimmer interest is $27 million and was allocated $14 million to Property, plant and equipment, $14 million to Inventory, and $1 million to ARO liability in our consolidated balance sheets. As a result of the Conesville sale, we recognized a loss of $31 million for the twelve months ended December 31, 2017, representing the difference between the $58 million book value of our transferred interest in Conesville and the $27 million fair value of the acquired interest in Zimmer.

F-39

On December 8, 2017, Dynegy finalized the purchase of AES Ohio Generation, LLC’s and The Dayton Power and Light Company’s (collectively, “AES”) 28.1 percent interest in Zimmer and 36 percent interest in Miami Fort for $70 million in cash for PP&E, Inventory, and the assumption of certain liabilities, subject to customary adjustments. Dynegy now owns 100 percent of Zimmer and Miami Fort, which are fully consolidated as of December 31, 2017.

The transactions above were accounted for as business combinations using similar fair value methodologies as described in Note 3—Acquisitions and Divestitures.

Note 10—Unconsolidated Investments

Equity Method Investments

NELP. In connection with the ENGIE Acquisition, we acquired a 50 percent interest in Northeast Energy, LP (“NELP”), a joint venture with NextEra Energy, Inc., which indirectly owns the Bellingham NEA facility and the Sayreville facility. At December 31, 2017, our equity method investment in NELP included in our consolidated balance sheets was $123 million. Upon the acquisition, we recognized basis differences in the net assets of approximately $39 million primarily related to PP&E. These basis differences are being amortized over their respective useful lives. Our risk of loss related to our equity method investment is limited to our investment balance.

For the year ended December 31, 2017, we recorded $8 million in equity earnings related to our investment in NELP which is reflected in Earnings from unconsolidated investments in our consolidated statements of operations. For the year ended December 31, 2017, we received distributions of $17 million, of which $12 million was considered to be a return of investment using the cumulative earnings approach and reflected as Distributions from unconsolidated investments in our consolidated statements of cash flows.

Elwood. On November 21, 2016, Dynegy sold its 50 percent equity interest in Elwood Energy, LLC, a limited liability company (“Elwood Energy”) and Elwood Expansion LLC, a limited liability company (and together with Elwood Energy “Elwood”), to J-Power USA Development Co. Ltd. for approximately $173 million (the “Elwood Sale”). As a result, we recorded an impairment charge of $9 million to Impairments in our consolidated statements of operations for the year ended December 31, 2016, to write down our investment in Elwood to the sales price. For the years ended December 31, 2016 and 2015, we recorded $7 million and $1 million in equity earnings related to our investment in Elwood, which is reflected in Earnings from unconsolidated investments in our consolidated statements of operations. For the year ended December 31, 2016, we received distributions of $15 million, of which $14 million was considered to be a return of investment. For the year ended December 31, 2015, we received distributions of $11 million, of which $8 million was considered a return on investment. Both used the accumulated earnings approach and were reflected as Distributions from unconsolidated investments in our consolidated statements of cash flows.

F-40

Note 11—Intangible Assets and Liabilities

The following table summarizes the components of our intangible assets and liabilities as of December 31, 2017 and 2016:

	December 31, 2017									December 31, 2016
(amounts in millions)	Gross Carrying Amount			Accumulated Amortization			Net Carrying Amount			Gross Carrying Amount			Accumulated Amortization			Net Carrying Amount
Intangible Assets:
Electricity contracts	$	178		$	(131	)	$	47		$	260		$	(206	)	$	54
Gas transport contracts		30			(13	)		17			13			(6	)		7
Total intangible assets	$	208		$	(144	)	$	64		$	273		$	(212	)	$	61
Intangible Liabilities:
Electricity contracts	$	(11	)	$	7		$	(4	)	$	(28	)	$	26		$	(2	)
Coal contracts		—			—			—			(49	)		42			(7	)
Coal transport contracts		(48	)		44			(4	)		(86	)		73			(13	)
Gas transport contracts		(58	)		19			(39	)		(41	)		8			(33	)
Gas storage contracts		(2	)		1			(1	)		—			—			—
Total intangible liabilities	$	(119	)	$	71		$	(48	)	$	(204	)	$	149		$	(55	)
Intangible assets and liabilities, net	$	89		$	(73	)	$	16		$	69		$	(63	)	$	6

The following table presents our amortization expense (revenue) of intangible assets and liabilities for the years ended December 31, 2017, 2016 and 2015:

F-41

	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Electricity contracts, net (1)	$	32		$	70		$	75
Coal contracts, net (2)		(5	)		(41	)		(60	)
Coal transport contracts, net (2)		(9	)		(27	)		(32	)
Gas transport contracts, net (2)		(5	)		19			6
Gas storage contracts, net (2)		(1	)		—			—
Total	$	12		$	21		$	(11	)

(1) The amortization of these contracts is recognized in Revenues or Cost of sales in our consolidated statements of operations.

(2) The amortization of these contracts is recognized in Cost of sales in our consolidated statements of operations.

Amortization expense (revenue), net for the next five years as of December 31, 2017 is as follows: 2018—$11 million, 2019—$17 million, 2020—$2 million, 2021—($3) million, and 2022—($4) million.

The following table summarizes the components of our contract based intangible assets and liabilities recorded in connection with the ENGIE Acquisition in February 2017:

(amounts in millions)	Gross Carrying Amount			Weighted-Average Amortization Period (months)
Intangible Assets:
Electricity contracts	$	34			39
Gas transport contracts		16			47
Total intangible assets	$	50			41
Intangible Liabilities:
Electricity contracts	$	(11	)		32
Gas contracts		—			1
Gas transport contracts		(17	)		35
Gas storage contracts		(2	)		13
Total intangible liabilities	$	(30	)		33
Total intangible assets and liabilities, net	$	20

F-42

Note 12—Tangible Equity Units

In 2016, we issued 4.6 million, 7 percent tangible equity units (“TEUs”) at $100 per unit and received proceeds of $443 million, net of issuance costs of $17 million.

Each TEU is comprised of: (i) a prepaid SPC issued by Dynegy, and (ii) an amortizing note (“Amortizing Note”), with an initial principal amount of $18.95 that pays an equal quarterly cash installment of $1.75 per Amortizing Note on January 1, April 1, July 1, and October 1 of each year, with the exception of the first installment payment of $1.94 which was due on October 1, 2016. In the aggregate, the annual quarterly cash installments are equivalent to a 7 percent cash payment per year. Each installment cash payment constitutes a payment of interest and a partial repayment of principal. Each TEU may be separated by a holder into its constituent SPC and Amortizing Note after the initial issuance date of the TEUs, and the separate components may be combined to create a TEU after the initial issuance date, in accordance with the terms of the SPC. The TEUs are listed on the New York Stock Exchange under the symbol “DYNC”.

In 2016, we allocated the proceeds from the issuance of the TEUs, including other fees and expenses, to equity and debt based on the relative fair value of the respective components of each TEU as follows:

(in millions, except price per TEU)	SPC			Amortizing Note			Total
Price per TEU	$	81		$	19		$	100
Gross proceeds	$	373		$	87		$	460
Less: Issuance costs		(14	)		(3	)		(17	)
Net proceeds	$	359		$	84		$	443

The fair value of the SPCs was recorded as additional paid in capital, net of issuance costs. The fair value of the Amortizing Notes was recorded as debt, with deferred financing costs recorded as a reduction of the carrying amount of the debt in our consolidated balance sheet. Deferred financing costs related to the Amortizing Notes will be amortized through the maturity date using the effective interest rate method.

Unless settled early at the holder’s or Dynegy’s election or redeemed by Dynegy in connection with an acquisition termination redemption, on July 1, 2019, Dynegy will deliver to the SPC holders a number of shares of common stock based on the 20 day volume-weighted average price (“VWAP”) of our common stock, at a conversion price ranging from 5.0201 shares to 6.1996 shares.

F-43

In addition, on any business day during the period beginning on, and including, the business day immediately following the date of initial issuance of the TEUs to, but excluding, the third business day immediately preceding the mandatory settlement date, any holder of an SPC may settle any or all of its SPCs early, and Dynegy will deliver a number of shares of Common Stock equal to the minimum settlement rate. Additionally, the SPCs may be redeemed in the event of a fundamental change or under an acquisition termination event, both as defined in the SPC.

Note 13—Debt

A summary of our long-term debt is as follows:

(amounts in millions)	December 31, 2017			December 31, 2016
Secured Obligations:
Term Loan, due 2024	$	2,018		$	2,224
Revolving Facility		—			—
Forward Capacity Agreement		241			219
Inventory Financing Agreements		48			129
Subtotal secured obligations		2,307			2,572
Unsecured Obligations:
7.00% Amortizing Notes, due 2019 (TEUs)		53			80
6.75% Senior Notes, due 2019		850			2,100
7.375% Senior Notes, due 2022		1,750			1,750
5.875% Senior Notes, due 2023		500			500
7.625% Senior Notes, due 2024		1,250			1,250
8.034% Senior Notes, due 2024		188			—
8.00% Senior Notes, due 2025		750			750
8.125% Senior Notes, due 2026		850			—
Equipment Financing Agreements		132			97
Subtotal unsecured obligations		6,323			6,527
Total debt obligations		8,630			9,099
Unamortized debt discounts and issuance costs		(197	)		(120	)
		8,433			8,979
Less: Current maturities, including unamortized debt discounts and issuance costs, net		105			201
Total long-term debt	$	8,328		$	8,778

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Certain of our debt instruments contain change of control provisions, which will not be triggered with the Merger with Vistra Energy. For further discussion of the Merger, see Note 1—Organization and Operations.

Aggregate maturities of the principal amounts of all indebtedness, excluding unamortized discounts, as of December 31, 2017 are as follows:

	(in millions)
2018	$	115
2019		971
2020		136
2021		59
2022		1,760
Thereafter		5,589
Total	$	8,630

Credit Agreement

As of December 31, 2017, we had a $3.563 billion credit agreement, as amended, that consisted of (i) a $2.018 billion seven-year senior secured term loan facility (the “Term Loan”) and (ii) $1.545 billion in senior secured revolving credit facilities (the “Revolving Facility,” and collectively with the Term Loan, the “Credit Agreement”). During the year ended December 31, 2017, we made the following changes to the Credit Agreement:

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• During 2017, we amended the Credit Agreement to increase the revolver capacity by $120 million and to extend the maturity date on $450 million in revolver capacity to 2021, which was effective upon the ENGIE Acquisition Closing Date.

• On the ENGIE Acquisition Closing Date, we amended the Credit Agreement to (i) reduce the interest rate applicable to the Term Loan by 75 basis points and (ii) exchange our previous Term Loan for the current Term Loan. As a result of this exchange, we recorded a loss on early extinguishment of debt of approximately $7 million in our consolidated statements of operations in the first quarter of 2017, of which approximately $5 million was related to the write-off of unamortized deferred financing costs and approximately$2 million was related to the write-off of unamortized debt discount.

• On August 22, 2017, we repaid $200 million of our Term Loan. As a result of this transaction, we recorded a loss on early extinguishment of debt of approximately $8 million in our consolidated statements of operations for the year ended December 31, 2017, of which $6 million was related to the write-off of unamortized deferred financing costs and $2 million was related to the write-off of unamortized debt discount.

• On December 20, 2017, we amended the Credit Agreement to reduce interest rate margins applicable to the Term Loan from 2.25 percent to 1.75 percent with respect to base rate borrowings and from 3.25 percent to 2.75 percent with respect to LIBOR borrowings through an exchange. Additional reductions from 2.25 percent to 1.50 percent with respect to base rate borrowings and from 2.75 percent to 2.50 percent with respect to LIBOR borrowings are available to the Company based on certain corporate ratings or corporate family ratings from Moody’s and S&P. As a result of this exchange, we recorded a loss on early extinguishment of debt of approximately $6 million in our consolidated statements of operations in the fourth quarter of 2017, of which approximately $4 million was related to the write-off of unamortized deferred financing costs, approximately $1 million was related to the write-off of unamortized debt discount, and approximately $1 million related to fees.

At December 31, 2017, there were no amounts drawn on the Revolving Facility; however, we had outstanding letters of credit (“LCs”) of approximately $353 million, which reduce the amount available under the Revolving Facility. In the first quarter of 2017 there was $300 million drawn on the Revolving Facility, and subsequently fully repaid in the fourth quarter of 2017. The Credit Agreement contains customary events of default and affirmative and negative covenants, subject to certain specified exceptions, including a Senior Secured Leverage Ratio (as defined in the Credit Agreement) calculated on a rolling four quarters basis. Under the Credit Agreement, if Dynegy utilizes 25 percent or more of its Revolving Facility, Dynegy must be in compliance with the Consolidated Senior Secured Net Debt to Consolidated Adjusted EBITDA ratio of 4.00:1.00. Based on the calculation outlined in the Credit Agreement, we were in compliance with these covenants as of December 31, 2017.

Under the terms of the Credit Agreement, existing balances under our Forward Capacity Agreement, Inventory Financing Agreements, and Equipment Financing Agreements are excluded from Consolidated Senior Secured Net Debt, as defined in the Credit Agreement.

Interest Rate Swaps. In March 2017, we amended our existing interest rate swaps to more closely match the terms of our Term Loan. The swaps have an aggregate notional value of approximately $761 million at an average fixed rate of 3.03 percent and expire between the second quarter of 2018 and the second quarter of 2020. In a previous extension to the existing interest rate swaps, in lieu of paying the breakage fees related to terminating the old swaps and issuing the new swaps, the costs were incorporated into the terms of the new swaps. As a result, any cash flows related to the settlement of the swaps are reflected as a financing activity in our consolidated statements of cash flows.

Additionally, in May 2017, we entered into new interest rate swap agreements. The swaps have an aggregate notional value of approximately $1.2 billion at an average fixed rate of 1.97 percent and expire in the first quarter of 2024. Any cash flows related to the settlement of these swaps are reflected as an operating activity in our consolidated statements of cash flows.

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Senior Notes

The senior notes are unsecured and unsubordinated obligations of the Company and are guaranteed by each of the Company’s current and future wholly-owned domestic subsidiaries that from time to time are a borrower or guarantor under the Credit Agreement. The senior notes indentures limit, among other things, the ability of the Company or any of the guarantors to create liens upon any principal property to secure debt for borrowed money in excess of, among other limitations, 30 percent of total assets.

As a result of Genco’s emergence from bankruptcy, we issued $188 million of new seven-year unsecured notes as partial consideration in exchange for Genco’s existing senior notes. Please read Note 20—Genco Chapter 11 Bankruptcy for further discussion.

On August 21, 2017, we issued $850 million of 8.125 percent senior notes due 2026 (the “2026 Senior Notes”) in a private placement transaction. Interest is payable semiannually in arrears on January 30 and July 30 of each year, beginning January 30, 2018. Dynegy used the proceeds of the offering, together with proceeds from the sale of certain facilities, and cash-on-hand to repurchase $1.25 billion of its 6.75 percent senior notes due 2019 and repay $200 million of its Term Loan, as noted above.

In connection with the extinguishment of a portion of our 2019 senior notes, we recorded a loss on early extinguishment of debt of approximately $58 million in our consolidated statements of operations for the year ended December 31, 2017, of which approximately $44 million related to a premium paid in excess of debt principal, approximately $8 million related to the write-off of unamortized deferred financing costs, and approximately $6 million related to fees. The Company, pursuant to a Registration Rights Agreement, has agreed to use commercially reasonable efforts to register the 2026 Senior Notes by August 16, 2018. Otherwise, the 2026 Senior Notes are generally identical in all material respects to Dynegy’s other outstanding senior notes.

Amortizing Notes

On June 21, 2016, in connection with the issuance of the TEUs, Dynegy issued the Amortizing Notes with a principal amount of approximately $87 million. The Amortizing Notes mature on July 1, 2019. Each installment payment per Amortizing Note will be paid in cash and will constitute a partial repayment of principal and a payment of interest, computed at an annual rate of 7 percent. Interest will be calculated on the basis of a 360 day year consisting of twelve 30 day months. Payments will be applied first to the interest due and payable and then to the reduction of the unpaid principal amount, allocated as set forth in the Indenture. Please read Note 12—Tangible Equity Units for further discussion.

Letter of Credit Facilities

Dynegy has a Letter of Credit Reimbursement Agreement with an issuing bank, for an LC in an amount not to exceed $55 million. In July 2017, the expiry date of the facility was extended one year, to September 19, 2018. At December 31, 2017, there was $55 million of LCs outstanding under this facility.

Following the ENGIE Acquisition Closing Date, Dynegy entered into a Letter of Credit Reimbursement Agreement with an issuing bank, pursuant to which the issuing bank agreed to provide LCs in an amount not to exceed $50 million. At December 31, 2017, there was $30 million of LCs outstanding under this facility. The facility matured February 7, 2018 and the LCs under this facility have since been transferred to under the Dynegy revolver.

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Forward Capacity Agreement

As of December 31, 2017, we have sold a portion of our PJM capacity that cleared for Planning Years 2018-2019, 2019-2020 and 2020-2021 to a financial institution. Dynegy will continue to be subject to the performance obligations as well as any associated performance penalties and bonus payments for those planning years. As a result, this transaction is accounted for as a debt issuance of $241 million with an implied interest rate of 4.9 percent. On March 29, 2017, we replaced an existing Planning Year 2017-2018 contract in the amount of $110 million, with a Planning Year 2019-2020 contract in the amount of $121 million. On July 7, 2017, we replaced $99 million of $109 million of an existing Planning Year 2018-2019 contract with a Planning Year 2020-2021 contract in the amount of $110 million.

Inventory Financing Agreements

Brayton Point Inventory Financing. In connection with the EquiPower Acquisition, we assumed an inventory financing agreement (the “Inventory Financing Agreement”) for coal and fuel oil inventories at our Brayton Point facility, consisting of a debt obligation for existing and subsequent inventories, as well as a $15 million line of credit. Balances in excess of the $15 million line of credit are cash collateralized. On May 31, 2017, the Brayton Point inventory financing agreement terminated and the remaining obligation was paid. The Brayton Point facility officially retired on June 1, 2017.

Emissions Repurchase Agreements. In August 2015, we entered into two repurchase transactions with a third party in which we sold approximately $78 million of RGGI inventory and received cash. In February 2017, we repurchased approximately $30 million of the previously sold RGGI inventory. We are obligated to repurchase the remaining inventory in February 2018 at a specified price with an annualized carry cost of approximately 3.49 percent. As of December 31, 2017, there was $48 million, in aggregate, outstanding under these agreements. In February 2018, we repaid all amounts outstanding under these agreements.

Equipment Financing Agreements

Under certain of our contractual service agreements in which we receive maintenance and capital improvements for our gas-fueled generation fleet, we have obtained parts and equipment intended to increase the output, efficiency, and availability of our generation units. We have financed these parts and equipment under agreements with maturities ranging from 2019 to 2026. The portion of future payments attributable to principal will be classified as cash outflows from financing activities, and the portion of future payments attributable to interest will be classified as cash outflows from operating activities in our consolidated statements of cash flows. The related assets were recorded at the net present value of the payments of $97 million. The $35 million discount is currently being amortized as interest expense over the life of the payments.

Note 14—Income Taxes    

We are subject to U.S. federal and state income taxes on our operations.

Tax Reform Act.

On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act (“TCJA”). Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the Internal Revenue Code of 1986, as amended (“the Code”), including amendments which significantly change the taxation of business entities. The more significant changes in the TCJA that impact Dynegy are:

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• reductions in the corporate federal income tax rate from 35 percent to 21 percent,

• repeal of the corporate Alternative Minimum Tax (“AMT”) providing for refunds of excess AMT credits,

• limiting the utilization of Net Operating Losses (“NOLs”) arising after December 31, 2017 to 80 percent of taxable income with an indefinite carryforward (existing NOLs can continue to be utilized at 100 percent of taxable income with a 20-year carryforward), and

• limiting the deduction of net business interest expense to 30 percent of adjusted taxable income as defined in the TCJA.

As a result of the reduction in the U.S. federal corporate tax rate, Dynegy has recorded a $394 million reduction to our net deferred tax assets, including the federal benefit of state deferred taxes, which was fully offset by a decrease in our valuation allowance for the year ended December 31, 2017. Additionally, we have recorded a $223 million current tax benefit and long term tax receivable in 2017 related to the expected refund of our existing AMT credits.

In accordance with Staff Accounting Bulletin 118, the amounts recorded in the fourth quarter of 2017 related to the TCJA represent reasonable estimates based on our analysis to date and are considered to be provisional and subject to revision during 2018. Provisional amounts were recorded for the re-measurement of our 2017 U.S. deferred taxes and ancillary state tax effects. These amounts are considered to be provisional as we continue to assess available tax methods and elections and refine our computations. Additionally, further regulatory guidance related to the TCJA is expected to be issued in 2018 which may result in changes to our current estimates.

Our losses from continuing operations before income taxes were $538 million, $1.289 billion and $427 million for the years ended December 31, 2017, 2016 and 2015, respectively, which were solely from domestic sources.

Our components of income tax benefit related to losses from continuing operations were as follows:

	Year Ended December 31,
(amounts in millions)	2017		2016		2015
Current tax benefit (expense)	$	233	$	15	$	(3	)
Deferred tax benefit		377		30		477
Income tax benefit	$	610	$	45	$	474

Our income tax benefit related to losses from continuing operations before income taxes for each of the years ended December 31, 2017, 2016 and 2015 were equivalent to effective rates of 113 percent, 3 percent, and 111 percent, respectively. Differences between taxes computed at the U.S. federal statutory rate and our reported income tax benefit were as follows:

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	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Expected tax benefit at U.S. statutory rate (35%)	$	189		$	451		$	149
State taxes		35			16			68
Permanent differences (1)		(21	)		(4	)		16
Non-deductible goodwill		(10	)		—			—
Valuation allowance (2)(3)		879			(404	)		271
NOL adjustments from use limitations		(13	)		(17	)		—
Adjustment to AMT credits		(17	)		—			(26	)
Change in federal tax rate as included in TCJA		(429	)		—			—
Other		(3	)		3			(4	)
Income tax benefit	$	610		$	45		$	474

(1) Permanent items for years ended December 31, 2017, 2016 and 2015 included a benefit of less than $1 million, a benefit of $2 million, and a benefit of $18 million, respectively, for the change in the fair value of warrants during the year that were not deductible for income taxes. Income tax benefit for the years ended December 31, 2017 and 2016 includes $8 million and $5 million, respectively, of income tax expense for non-deductible fees related to the Genco Plan. Please read Note 20—Genco Chapter 11 Bankruptcy for further discussion. Income tax benefit for the year ended December 31, 2017, includes $22 million for non-deductible legal fees related to the ENGIE Acquisition.

(2) The EquiPower Acquisition on April 1, 2015 caused a change in the attributes and impacted our estimate of the realizability of our deferred tax assets. As a result, we recorded a $453 million reduction to our valuation allowance in 2015 and $3 million in 2016.

(3) The ENGIE Acquisition on February 7, 2017 caused a change in the attributes and impacted our estimate of the realizability of our deferred tax assets. As a result, we recorded a $354 million reduction to our valuation allowance in 2017. We also recorded a benefit for the repeal of the corporate AMT in the amount of $223 million as included in the TCJA.

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Deferred Tax Liabilities and Assets. Our significant components of deferred tax assets and liabilities were as follows:

	Year Ended December 31,
(amounts in millions)	2017			2016
Non-current deferred tax assets:
NOL carryforwards	$	1,195		$	1,629
AMT, state, and other tax credit carryforwards		25			241
Reserves (legal, environmental and other)		4			7
Pension and other post-employment benefits		11			18
Asset retirement obligations		68			85
Deferred financing costs and intangible/other contracts		22			48
Derivative contracts		69			57
Other		29			46
Subtotal		1,423			2,131
Less: valuation allowance		(852	)		(1,704	)
Total non-current deferred tax assets	$	571		$	427
Non-current deferred tax liabilities:
Depreciation and other property differences	$	(560	)	$	(371	)
Derivative contracts		(7	)		(44	)
Other		(11	)		(17	)
Total non-current deferred tax liabilities	$	(578	)	$	(432	)
Net non-current deferred tax liabilities	$	(7	)	$	(5	)

NOL Carryforwards. As of December 31, 2017, we had approximately $4.6 billion of NOLs and $3.6 billion of state NOLs that can be used to offset future taxable income. The federal NOLs expire beginning in 2024 through 2037. Similarly, the state NOLs will expire at various dates (based on the company’s review of the application of apportionment factors and other state tax limitations). Under federal income tax law, our NOLs can be utilized to reduce future taxable income subject to certain limitations, including if we were to undergo an ownership change as defined by Internal Revenue Code (“IRC”) Section 382. If an ownership change were to occur as a result of future transactions in our stock, our ability to utilize the NOLs may be significantly limited.

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Alternative Minimum Tax Credit Carryforwards. For the years ended December 31, 2017 and 2016, the Company elected to accelerate the minimum tax credit in lieu of claiming the bonus depreciation allowance, resulting in a current Income tax benefit of $18 million and $16 million, respectively. Dynegy has recorded a $223 million tax benefit in 2017 related to the expected refund of its existing AMT Credits as provided for in the TCJA.

Change in Valuation Allowance. Realization of our deferred tax assets is dependent upon, among other things, our ability to generate taxable income of the appropriate character in the future. At December 31, 2017 and 2016, we have a valuation allowance against our net deferred assets including federal and state NOLs and AMT credit carryforwards. Additionally, at December 31, 2017 and 2016, our temporary differences were in a net deferred tax asset position. We do not believe we will produce sufficient future taxable income, nor are there tax planning strategies available, to realize the tax benefits of our net deferred tax asset associated with temporary differences. Accordingly, we have recorded a full valuation allowance against the net asset temporary differences related to federal income tax and the net asset temporary differences related to most state income tax as appropriate.

The changes in the valuation allowance were as follows:

	Year Ended December 31,
	2017			2016		2015
Beginning of period	$	1,704		$	1,276	$	1,535
Changes in valuation allowance—continuing operations:
Charged to costs and expenses		(854	)		428		(259	)
Charged to other accounts		2			—		—
End of period	$	852		$	1,704	$	1,276

Unrecognized Tax Benefits. We are complete with federal income tax audits by the Internal Revenue Service (“IRS”) through 2015 as a result of our participation in the IRS’ Compliance Assurance Process. However, any NOLs we claim in future years to reduce taxable income could be subject to additional IRS examination regardless of when the NOLs occurred. We are generally not subject to examinations for state and local taxes for tax years 2013 or earlier with few exceptions.

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A reconciliation of our beginning and ending amounts of unrecognized tax benefits were as follows:

	Year Ended December 31,
amounts in millions	2017			2016		2015
Unrecognized tax benefits, beginning of period	$	3		$	3	$	4
Increase due to ENGIE acquisition		63			—		—
Decrease due to rate changes		(26	)		—		—
Decrease due to settlements and payments		—			—		(1	)
Unrecognized tax benefits, end of period	$	40		$	3	$	3

As of December 31, 2017, approximately $3 million of unrecognized tax benefits would impact our effective tax rate if recognized.

Note 15—Stockholders’ Equity

Preferred Stock

We have authorized preferred stock consisting of 20 million shares, $0.01 par value. Our preferred stock may be issued from time to time in one or more series, the shares of each series to have such designations and powers, preferences, rights, qualifications, limitations and restrictions thereof as specified by our Board of Directors. Our 4 million shares of Series A Mandatory Convertible Preferred Stock converted on November 1, 2017, into approximately 12.9 million shares of our common stock, whereupon we reclassified the balance of Preferred Stock to Additional paid-in-capital.

Stock Purchase Agreement-Terawatt

On February 24, 2016, Dynegy entered into a Stock Purchase Agreement with Terawatt Holdings, LP (“Terawatt”), an affiliate of the investment funds of ECP, pursuant to which, at the ENGIE Acquisition Closing Date, Dynegy issued to Terawatt 13,711,152 shares of Dynegy common stock for $150 million (the “PIPE Transaction”).

ECP Buyout

Dynegy settled its payment obligation to ECP of $375 million on the ENGIE Acquisition Closing Date. This payment is recorded as a reduction in additional paid-in capital in our consolidated balance sheet and is reflected as a purchase of a noncontrolling interest in financing activities in our consolidated statement of cash flows as of December 31, 2017.

TEUs

On June 21, 2016, pursuant to a registered public offering, we issued 4.6 million, 7 percent TEUs at $100 per unit. Each TEU was comprised of a prepaid stock purchase contract and an amortizing note which were accounted for as separate instruments. Please read Note 12—Tangible Equity Units for further discussion.

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Common Stock

Upon our emergence from bankruptcy on October 1, 2012 (the “Plan Effective Date”), we authorized 420 million shares of common stock, $0.01 par value per share, of which 11,326,122 shares are currently held in treasury. The following table reflects balances and activity in our outstanding shares of common stock, for the years ended December 31, 2017, 2016 and 2015:

	Shares outstanding balance as of December 31,
(in millions)	2017		2016		2015
Shares outstanding at the beginning of the period		117		117		124
Shares issued under the PIPE Transaction		14		—		—
Shares issued as consideration for the EquiPower Acquisition		—		—		3
Shares repurchases (in treasury)		—		—		(11	)
Shares issued from conversion of preferred stock		13		—		—
Shares issued under long-term compensation plans		—		—		1
Shares outstanding at the end of period		144		117		117

Warrants. As of the Plan Effective Date, we issued to then-existing stockholders warrants to purchase up to 15.6 million shares of common stock for an exercise price of $40 per share (the “2012 Warrants”). The 2012 Warrants expired on October 2, 2017.

During 2017, we issued 9.0 million warrants (the “2017 Warrants”), each of which entitles the holder to purchase one share of Dynegy common stock, to eligible holders of Genco senior notes as a result of the Genco Chapter 11 Bankruptcy. The 2017 Warrants have an exercise price of $35 per share of common stock and a seven-year term expiring on February 2, 2024. The warrants are recorded as Other long-term liabilities in our consolidated balance sheet and are adjusted to their estimated fair value at the end of each reporting period with the change in fair value recognized in Other income (expense) in our consolidated statement of operations. Please read Note 20—Genco Chapter 11 Bankruptcy and Note 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion.

Stock Award Plans

We have one stock award plan, the Dynegy Amended and Restated 2012 Long Term Incentive Plan (the “ LTIP”), which provides for the issuance of authorized shares of our common stock. Restricted Stock Units (“RSUs”), Performance Stock Units (“PSUs”) and option grants have been issued under the LTIP. The LTIP is a broad-based plan and provides for the issuance of approximately 3.2 million authorized shares through May 2026.

All options granted under the LTIP cease vesting for employees who are terminated with cause. For severance-eligible terminations, as defined under the severance pay plan, disability, retirement or death, immediate or continued vesting and/or an extended period in which to exercise vested options may apply, dependent upon the terms of the grant agreement applying to a specific grant that was awarded. Shares of common stock are issued upon exercise of stock options from previously unissued shares. Any options granted under the LTIP will expire no later than 10 years from the date of the grant.

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All RSUs granted under the LTIP contain a service condition and cease vesting for employees or directors who are terminated with cause. For severance-eligible employee terminations, as defined under the severance pay plan, director terminations without cause, employee or director disability, retirement or death, immediate vesting of some or all of the RSUs may apply, dependent upon the terms of the grant agreement applying to a specific grant that was awarded. Shares of common stock are issued upon vesting of RSUs from previously unissued shares, with the exception of 2.5 million and 1.5 million shares of RSU’s granted in 2017 and 2016, respectively, to be settled in cash. As these awards must be settled in cash, we account for them as liabilities, with changes in the fair value of the liability recognized as expense in our consolidated statements of operations. We paid $3 million in cash for 0.4 million of the RSU’s accounted for as liabilities that vested during the year ended December 31, 2017.

All PSUs granted under the LTIP contain a performance condition and cease vesting for employees who do not remain continuously employed during the performance period under the grant agreements. For severance-eligible terminations, as defined under the severance pay plan, disability, retirement or death, immediate vesting of some or all of the PSUs may apply, dependent upon the terms of the grant agreement applying to a specific grant that was awarded. Upon a corporate change, employees receive an immediate vesting of PSUs regardless of whether the employee is terminated.

We use the fair value based method of accounting for stock-based employee compensation. We estimate forfeiture rates based on our actual forfeitures. Compensation expense related to options, RSUs and PSUs granted totaled $44 million, $31 million and $28 million for the years ended December 31, 2017, 2016 and 2015, respectively. We recognize compensation expense ratably over the vesting period of the respective awards. Tax benefits for compensation expense related to options, RSUs and PSUs granted totaled $15 million, $11 million and $10 million for the years ended December 31, 2017, 2016 and 2015, respectively. As of December 31, 2017, $31 million of total unrecognized compensation expense related to options, RSUs and PSUs granted is expected to be recognized over a weighted-average period of 1.43 years. The total fair value of options, RSUs and PSUs vested was $26 million, $27 million and $18 million for the years ended December 31, 2017, 2016 and 2015, respectively. We did not capitalize any share-based compensation in the years ended December 31, 2017, 2016 and 2015. We settled 0.1 million RSUs related to severances and retirements for $1 million in cash for the year ended December 31, 2017. We did not settle any share-based compensation for cash in the years ended December 31, 2016 and 2015.

No options were exercised for the years ended December 31, 2017 and 2016. Cash received from option exercises was $0.5 million and the tax benefit realized for the additional tax deduction from share-based payment awards totaled less than $1 million for the year ended December 31, 2015.

The following summarizes our stock option activity:

	Year Ended December 31, 2017
	Options (in thousands)			Weighted Average Exercise  Price		Weighted Average Remaining Contractual Life (in years)		Aggregate Intrinsic Value (amounts in millions)
Outstanding at beginning of period		2,805		$	18.69
Granted		1,454		$	8.02
Forfeited		(10	)	$	27.24
Expired		(42	)	$	21.79
Outstanding at end of period		4,207		$	14.95		7.65	$	6.4
Vested and unvested expected to vest		4,207		$	14.95		7.65	$	6.4
Exercisable at end of period		2,023		$	20.02		6.40	$	0.5

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During the years ended December 31, 2017, 2016 and 2015, we did not grant any options at an exercise price less than the market price on the date of grant. The weighted average exercise price of options granted during the years ended December 31, 2016 and 2015 was $11.05 and $27.43, respectively. The intrinsic value of options exercised during the years ended December 31, 2016 and 2015 was less than $1 million.

For stock options, we determine the fair value of each stock option at the grant date using a Black-Scholes model, with the following weighted-average assumptions used for grants:

	Year Ended December 31,
	2017			2016			2015
Dividend Yield	$	—		$	—		$	—
Expected volatility (1)		48.50	%		41.19	%		27.70	%
Risk-free interest rate (2)		2.07	%		1.42	%		1.64	%
Expected option life (3)		5.5 years			5.5 years			5.5 years
Weighted average grant-date fair value	$	3.71		$	4.37		$	7.93

(1) For the years ended December 31, 2017, 2016 and 2015, the expected volatility was calculated based on the historical volatilities of our stock since October 3, 2012.

(2) The risk-free interest rate was calculated based upon observed interest rates appropriate for the term of our employee stock options.

(3) Currently, we calculate the expected option life using the simplified methodology suggested by authoritative guidance issued by the SEC.

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The following summarizes our RSU activity:

	Year Ended December 31, 2017
	RSUs (in thousands)			Weighted Average Grant Date Fair Value
Outstanding at beginning of period		2,717		$	16.11
Granted		3,177		$	7.99
Vested and released		(1,241	)	$	19.04
Forfeited		(107	)	$	11.08
Outstanding at end of period		4,546		$	9.75

For RSUs, we consider the fair value to be the closing price of the stock on the grant date. The weighted average grant date fair value of RSUs granted during the years ended December 31, 2016 and 2015 was $11.20 and $28.93, respectively. We recognize the fair value of our share-based payments over the vesting periods of the awards, which is typically a three-year service period.

The following summarizes our PSU activity:

	Year Ended December 31, 2017
	PSUs (in thousands)			Weighted Average Grant Date Fair Value
Outstanding at beginning of period		1,221		$	16.48
Granted		583		$	8.02
Vested and released		(3	)	$	26.66
Forfeited		(186	)	$	23.10
Outstanding at end of period		1,615		$	12.65

The weighted average grant date fair value of PSUs granted during the years ended December 31, 2016 and 2015 was $16.48 and $27.54.

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For PSUs granted prior to 2016, the fair value is determined using total shareholder return (“TSR”), measured over a three-year period relative to a selected group of energy industry peer companies, using a Monte Carlo model. The key characteristics of the PSUs are as follows:

• Three-year performance period;

• Payout opportunity of 0-200 percent of target (100 percent), intended to be settled in shares;

• Cumulative TSR percentile ranking calculated at end of performance period and applied to the payout scale to determine the number of earned/vested PSUs; and

• If absolute TSR is negative, PSU award payouts will be capped at 100 percent of the target number of PSUs granted, regardless of relative TSR positioning.

For PSUs granted in and subsequent to 2016, the fair value is determined using TSR for one-half of the award and the other half using pre-determined adjusted free cash flow (“FCF”) thresholds based upon the three year performance period. The FCF payout opportunity is also 0-200 percent of target (100 percent) intended to be settled in shares. These PSUs have the same key characteristics as described above.

Earnings (Loss) Per Share

Basic earnings (loss) per share is based on the weighted average number of common shares outstanding during the period. Diluted earnings (loss) is based on the weighted average number of common shares used for the basic earnings (loss) per share computation, adjusted for the incremental issuance of shares of common stock assuming (i) our stock options and warrants are exercised, (ii) our restricted stock units and performance stock units are fully vested under the treasury stock method, and (iii) our mandatory convertible preferred stock and the SPCs are converted into common stock under the if converted method. Please read Note 12—Tangible Equity Units for further discussion.

The following table reflects the significant components of our weighted average shares outstanding used in the basic and diluted loss per share calculations for the years ended December 31, 2017, 2016 and 2015:

	Year Ended December 31,
(in millions, except per share amounts)	2017		2016		2015
Shares outstanding at the beginning of the period		140		117		124
Weighted-average shares during the period of:
Shares issuances		13		—		4
Shares converted from preferred stock		2		—		—
Shares repurchases		—		—		(3	)
Prepaid stock purchase contract (TEUs) (1)		—		12		—
Basic weighted-average shares		155		129		125
Dilution from potentially dilutive shares (2)		7		—		1
Diluted weighted-average shares (3)		162		129		126

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(1) The minimum settlement amount, or 23.1 million shares, are considered to be outstanding since June 21, 2016, and are included in the computation of basic earnings (loss) per share. Please read Note 12 - Tangible Equity Units for further discussion.

(2) Shares included in the computation of diluted earnings per share for the year ended December 31, 2017 consist of:

• 5.4 million additional shares upon settlement of the TEUs - which reflects the difference between the minimum settlement amount included in basic weighted-average shares outstanding and the maximum settlement amount (28.5 million shares); and

• 1.9 million additional shares attributable to restricted stock units and performance stock units.

(3) Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the year ended December 31, 2016.

For the years ended December 31, 2017, 2016 and 2015, the following potentially dilutive securities were not included in the computation of diluted per share amounts because the effect would be anti-dilutive:

	Year Ended December 31,
(in millions of shares)	2017		2016		2015
Stock options		2.8		2.8		0.5
Restricted stock units		—		1.3		—
Performance stock units		—		1.2		—
Warrants (1)		9.0		15.6		15.6
Series A 5.375% mandatory convertible preferred stock (2)		—		12.9		12.9
TEUs		—		5.4		—
Total		11.8		39.2		29.0

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(1) During 2017, we issued 9.0 million warrants to eligible holders of Genco senior notes as a result of the Genco Chapter 11 Bankruptcy. Warrants to purchase 15.6 million shares of our Common Stock expired on October 2, 2017.

(2) On November 1, 2017, our outstanding Preferred Stock was converted to approximately 12.9 million shares of Common Stock.

Accumulated Other Comprehensive Income

Changes in accumulated other comprehensive income (“AOCI”), net of tax, by component are as follows:

	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Beginning of period	$	21		$	19		$	20
Other comprehensive income before reclassifications:
Actuarial gain and plan amendments (net of tax of $5, $3, and zero, respectively)		19			2			3
Amounts reclassified from accumulated other comprehensive income:
Settlement cost (net of tax of zero) (1)		—			5			—
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero, zero, and zero, respectively) (2)		(8	)		(5	)		(4	)
Net current period other comprehensive income (loss), net of tax		11			2			(1	)
End of period	$	32		$	21		$	19

(1) Amount is related to the EEI other post-employment benefit plan settlement cost and was recorded in Operating and maintenance expense in our consolidated statements of operations. Please read Note 17—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

(2) Amounts are associated with our defined benefit pension and other post-employment benefit plans and are included in the computation of net periodic pension cost. Please read Note 17—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

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Note 16—Commitments and Contingencies

Legal Proceedings

Set forth below is a summary of our material ongoing legal proceedings. We record accruals for estimated losses from contingencies when available information indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, we disclose matters for which management believes a material loss is reasonably possible. In all instances, management has assessed the matters below based on current information and made judgments concerning their potential outcome, giving consideration to the nature of the claim, the amount, if any, the nature of damages sought, and the probability of success. Management regularly reviews all new information with respect to such contingencies and adjusts its assessments and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties including unfavorable rulings or developments, it is possible that the ultimate resolution of our legal proceedings could involve amounts that are different from our currently recorded accruals, and that such differences could be material.

In addition to the matters discussed below, we are party to other routine proceedings arising in the ordinary course of business. Any accruals or estimated losses related to these matters are not material. In management’s judgment, the ultimate resolution of these matters will not have a material effect on our financial condition, results of operations, or cash flows.

Gas Index Pricing Litigation. We, through our subsidiaries, and other energy companies are named as defendants in several lawsuits claiming damages resulting from alleged price manipulation and false reporting of natural gas prices to various index publications from 2000-2002. The cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices in three states (Kansas, Missouri, and Wisconsin) during the relevant time period. The cases are consolidated in a multi-district litigation proceeding pending in the United States District Court for Nevada. On March 30, 2017, the court denied Plaintiffs’ motion to certify a class action, which will be subject to an interlocutory appeal granted by the Ninth Circuit on June 13, 2017. At this time we cannot reasonably estimate a potential loss.

Advatech Dispute. On September 2, 2016, our Genco subsidiary terminated its Second Amended and Restated Newton FGD System Engineering, Procurement, Construction and Commissioning Services Contract dated as of December 15, 2014 with Advatech, LLC. Advatech issued Genco its final invoice on September 30, 2016 totaling $81 million. Genco contested the invoice on October 3, 2016 and believes the proper amount is less than $1 million. On October 27, 2016, Advatech initiated the dispute resolution process under the Contract and filed for arbitration on March 16, 2017. Settlement discussions required under the dispute resolution process have been unsuccessful. We believe the risk of a material loss related to this dispute to be remote. We dispute the allegations and will defend our position vigorously.

Vistra Merger Stockholder Litigation. On January 4, 2018, a putative class action complaint was filed in the United States District Court for the Southern District of Texas against Dynegy, Dynegy’s individual Board members, and Vistra Energy alleging that the December 13, 2017 S-4 Registration Statement related to the Merger “omits material information with respect to the Merger, which renders the Registration Statement false and misleading.” Two additional lawsuits have been filed in Texas and Delaware making nearly identical allegations but excluding Vistra as a defendant. We dispute the allegations and will defend our position vigorously.

Wood River Rail Dispute. On November 30, 2017, Dynegy Midwest Generation, LLC (“DMG”) received notification that BNSF Railway Company and Norfolk Southern Railway Company were initiating dispute resolution related to DMG’s suspension of its Wood River Rail Transportation Agreement with the railroads. The parties are attempting to negotiate a resolution per the mandatory terms of the dispute resolution provision of the agreement. If the parties are unable negotiate a resolution, the railroads can initiate an arbitration to resolve the dispute. At this time, we view the likelihood of material loss as remote and dispute the railroads’ allegations and, if arbitration ensues, will defend our position vigorously.

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Other Contingencies

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

On October 1, 2015, FERC issued an order of non-public, formal investigation, stating that shortly after the conclusion of the 2015-2016 PRA, FERC’s Office of Enforcement began a non-public informal investigation into whether market manipulation or other potential violations of FERC orders, rules and regulations occurred before or during the PRA (the “Order”). The Order noted that the investigation is ongoing, and that the order converting the informal, non-public investigation to a formal, non-public investigation does not indicate that FERC has determined that any entity has engaged in market manipulation or otherwise violated any FERC order, rule, or regulation. Dynegy is participating in the investigation. We believe the risk of a material loss related to the investigation to be remote.

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

New Source Review and CAA Matters.

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

In August 2012, the EPA issued a Notice of Violation (“NOV”) alleging that projects performed in 1997, 2006 and 2007 at the Newton facility violated Prevention of Significant Deterioration, Title V permitting, and other requirements. The NOV remains unresolved. We believe our defenses to the allegations described in the NOV are meritorious. A decision by the U.S. Court of Appeals for the Seventh Circuit in 2013 held that similar claims older than five years were barred by the statute of limitations. This decision may provide an additional defense to the allegations in the Newton facility NOV. In September 2016, we retired Newton Unit 2.

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

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

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

Ultimate resolution of any of these CAA matters could have a material adverse impact on our future financial condition, results of operations and cash flows. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve these matters.

Coal Combustion Residuals/ Groundwater.

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

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

In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities’ CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the CCR rule.

If remediation measures concerning groundwater are necessary at any of our coal-fired MISO Segment facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations, and cash flows. At this time we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required. CCR surface impoundment and landfill closure costs are reflected in our AROs.

Other Commitments

In conducting our operations, we routinely enter into long-term commodity purchase and sale commitments, as well as agreements that commit future cash flow to the lease or acquisition of assets used in our businesses. The following describes the significant commitments outstanding at December 31, 2017.

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Coal Purchase Commitments. At December 31, 2017, we had contracts in place to purchase coal for our generation facilities with aggregate minimum commitments of $802 million. To the extent purchased or committed volumes have not been priced but are subject to a price collar structure, the obligations have been calculated using the minimum purchase price of the collar.

Coal Transportation. At December 31, 2017, we had coal transportation contracts and rail car leases in place for our generation facilities with aggregate minimum commitments of $837 million.

Contractual Service Agreements. Contractual service agreements represent obligations with respect to long-term plant maintenance agreements. In prior periods, we have undertaken several measures to restructure some of our existing maintenance service agreements with our turbine service providers. As of December 31, 2017, our obligation with respect to these restructured agreements is limited to the termination payments, which are approximately $707 million in the event all contracts are terminated by us.

In addition, we have committed to securing capital spares and turbine uprates for our gas-fueled generation fleet to help minimize production disturbances, improve efficiency, and increase generation. As of December 31, 2017, we have obligations to purchase spare parts and turbine uprates of $112 million with payments made through 2026, of which $103 million reflects spare parts received and upgrades completed. Upon the receipt of the parts and transfer of title to Dynegy, we recognize the asset and the associated payment obligation at the NPV of those payments, which we record to PP&E and Debt in our consolidated balance sheets.

Gas Purchase Commitments. At December 31, 2017, we had contracts in place to purchase gas for our generation facilities with aggregate minimum commitments of $212 million.

Gas Transportation. At December 31, 2017, we had firm capacity payment obligations related to transportation of natural gas. Such arrangements are routinely used in the physical movement and storage of energy. The total of such obligations was $183 million.

Operating Leases.

Office Space, Equipment and Other Property. Minimum lease payment obligations, by year, associated with office space, equipment, land and other leases per year for the years 2018-2022 are as follows:

	(in millions)
2018	$	6
2019	$	5
2020	$	5
2021	$	5
2022	$	4

During the years ended December 31, 2017, 2016 and 2015, we recognized rental expense of approximately $5 million, $5 million and $5 million, respectively.

Other Obligations. We have other obligations of $25 million for contracts in place to purchase limestone and ash, $17 million for interconnection services, $23 million for water services and $23 million for other miscellaneous items which are individually insignificant.

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Indemnifications and Guarantees

In the ordinary course of business, we routinely enter into contractual agreements that contain various representations, warranties, indemnifications and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, asset sales agreements, and procurement and construction contracts. Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third party claims, in which event we will effectively be indemnifying the other party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false. While there is always the possibility of a loss related to such representations, warranties, indemnifications, and guarantees in our contractual agreements, and such loss could be significant, in most cases management considers the probability of loss to be remote. We have accrued no amounts with respect to the indemnifications as of December 31, 2017 because none were probable of occurring, nor could they be reasonably estimated.

Note 17—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans

We sponsor and administer defined benefit plans and defined contribution plans for the benefit of our employees and also provide other post-employment benefits to retirees who meet age and service requirements. During the years ended December 31, 2017, 2016 and 2015, our contributions related to these plans were approximately $63 million, $43 million and $50 million, respectively. The following summarizes these plans:

Short-Term Incentive Plan. Dynegy maintains a discretionary incentive compensation plan to provide our employees with rewards for the achievement of corporate goals and individual, professional accomplishments. Specific awards are determined by Dynegy’s Compensation and Human Resources Committee of the Board of Directors and are based on predetermined goals and objectives established at the start of each performance year.

Dynegy Inc. 401(k) Savings Plans. For the years ended December 31, 2017, 2016 and 2015, our employees participated in several 401(k) savings plans, all of which meet the requirements of IRC Section 401(k) and are defined contribution plans subject to the provisions of the Employee Retirement Income Security Act. Effective January 1, 2016, all of these plans, except for the Brayton Point Energy LLC 401k Plan for Bargaining Employees, were merged into the Dynegy 401(k) Plan and employees who participate in these plans became eligible to participate in the Dynegy 401(k) Plan. The following summarizes the plan:

• Dynegy 401(k) Plan. This plan and the related trust fund are established and maintained for the exclusive benefit of participating employees in the U.S. Generally, all employees of designated Dynegy subsidiaries are eligible to participate in this plan. Except for certain represented employees, employee pre-tax and Roth contributions to the plan are matched by the Company at 100 percent, up to a maximum of five percent of base pay (subject to IRS limitations) and vesting in company contributions is based on years of service with 50 percent vesting per full year of service. This plan also allows for a discretionary contribution to eligible employee accounts for each plan year, subject to the sole discretion of the Compensation and Human Resources Committee of the Board of Directors. No discretionary contributions were made for any of the years in the three-year period ended December 31, 2017.

During the years ended December 31, 2017, 2016 and 2015, we recognized aggregate costs related to our 401(k) Plans of $13 million, $15 million and $10 million, respectively.

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Pension and Other Post-Employment Benefits

We have various defined benefit pension plans and post-employment benefit plans. Generally, all employees participate in the pension plans (subject to plan eligibility requirements), but only some of our employees participate in the other post-employment medical and life insurance benefit plans. The pension plans are in the form of cash balance plans and more traditional career average or final average pay formula plans. Separately, our EEI employees and retirees participate in EEI’s single-employer pension and other post-employment plans. We consolidate EEI, and therefore, EEI’s plans are reflected in our pension and post-employment balances and disclosures. Dynegy and EEI both use a measurement date of December 31 for their pension and post-employment benefit plans.

In December 2017, we merged our Dynegy Inc. Retirement Plan into the Sithe Stable Pension Account Plan, which is sponsored by our wholly-owned subsidiary, Sithe Energies, Inc. The combined plan was re-named as the Dynegy Pension Plan, and the sponsorship of the combined plan was transferred from Sithe Energies, Inc. to Dynegy Inc.

In 2017, the Dynegy pension and other post-employment plans were amended as a result of negotiations with former Duke Midwest union participants, IBEW Local 1347. As part of these amendments, the participants’ previous pension plan accrued benefits were frozen as of December 31, 2017 and began accruing on January 1, 2018 with a minimum interest crediting rate of 4 percent. Other post-employment plans were amended to provide retiree medical plan benefits to only certain participants as of January 1, 2018. As a result of these amendments, we remeasured our affected plans and recorded a net-of-tax gain of approximately $15 million through accumulated other comprehensive income during 2017.

In the fourth quarter of 2016, EEI other post-employment plans were amended to change health benefits to a Health Reimbursement Account (“HRA”) for salaried employees and union employees. As a result of these amendments, we remeasured our affected plans and recorded a net-of-tax gain of approximately $17 million through accumulated other comprehensive income.

Additionally, in the fourth quarter of 2016, annuities and individual life insurance policies were purchased from the EEI other post-employment plans, relieving Dynegy of its obligation for the medical and life insurance coverage for inactive participants. As a result, we recorded a net-of-tax settlement cost of $6 million through operating and maintenance expense.

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Obligations and Funded Status. The following tables contain information about the obligations, plan assets, and funded status of all plans in which we, or one of our subsidiaries, formerly sponsored or participated in on a combined basis.

	Pension Benefits						Other Benefits
	Year Ended December 31,
(amounts in millions)	2017			2016			2017			2016
Benefit obligation, beginning of the year	$	508		$	483		$	42		$	74
Service cost		17			16			—			1
Interest cost		20			20			2			3
Actuarial loss		28			23			1			4
Benefits paid		(36	)		(32	)		(4	)		(6	)
Plan change		(10	)		(2	)		(1	)		(17	)
Settlements		—			—			—			(17	)
Acquisitions		—			—			—			—
Divestitures		—			—			—			—
Benefit obligation, end of the year	$	527		$	508		$	40		$	42
Fair value of plan assets, beginning of the year	$	415		$	410		$	49		$	67
Actual return on plan assets		65			37			4			2
Employer contributions		4			—			—			—
Benefits paid		(36	)		(32	)		(2	)		(3	)
Settlements		—			—			—			(17	)
Acquisitions		—			—			—			—
Divestitures		—			—			—			—
Transfers Out (1)		—			—			(19	)		—
Fair value of plan assets, end of the year	$	448		$	415		$	32		$	49
Funded status	$	(79	)	$	(93	)	$	(8	)	$	7

(1) As permitted by EEI’s other post-employment plan for EEI union employees, part of the overfunded portion of the plan assets was segregated in 2017 to offset the employer cost of the active EEI employees’ health and welfare benefits.

Our accumulated benefit obligation related to pension plans was $527 million and $501 million as of December 31, 2017 and 2016, respectively. Our accumulated benefit obligation related to other post-employment plans was $40 million and $42 million as of December 31, 2017 and 2016, respectively.

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Amounts recognized in the consolidated balance sheets consist of:

	Pension Benefits						Other Benefits
	Year Ended December 31,
(amounts in millions)	2017			2016			2017			2016
Non-current assets	$	—		$	7		$	33		$	32
Current liabilities		—			—			(2	)		(2	)
Non-current liabilities		(79	)		(100	)		(20	)		(23	)
Net amount recognized	$	(79	)	$	(93	)	$	11		$	7

Pre-tax amounts recognized in AOCI consist of:

	Pension Benefits						Other Benefits
	Year Ended December 31,
(amounts in millions)	2017			2016			2017			2016
Prior service credit	$	(19	)	$	(12	)	$	(43	)	$	(47	)
Actuarial loss (gain)		(8	)		2			1			1
Net gain recognized	$	(27	)	$	(10	)	$	(42	)	$	(46	)

The net actuarial loss (gain) and prior service credit that were amortized from AOCI into net periodic benefit cost during the years ended December 31, 2017, 2016 and 2015 for the defined benefit pension plans were $2 million, $1 million and $1 million, respectively. The net prior service credit that was amortized from AOCI into net periodic benefit cost during the years ended December 31, 2017, 2016 and 2015 for other post-employment benefit plans was $5 million, $4 million and $3 million, respectively.

The expected amounts that will be amortized from AOCI and recognized as components of net periodic benefit cost (gain) in 2018 are as follows:

(amounts in millions)	Pension Benefits			Other Benefits
Prior service credit	$	(3	)	$	(5	)
Actuarial gain		—			(1	)
	$	(3	)	$	(6	)

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The amortization of prior service cost is determined using a straight line amortization of the cost over the average remaining service period of employees expected to receive benefits under the plans.

Components of Net Periodic Benefit Cost (Gain). The components of net periodic benefit cost (gain) were as follows:

	Pension Benefits
	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Service cost benefits earned during period	$	17		$	16		$	14
Interest cost on projected benefit obligation		20			20			18
Expected return on plan assets		(25	)		(22	)		(23	)
Amortization of:
Prior service credit		(2	)		(1	)		(1	)
Actuarial gain		—			—			—
Net periodic benefit cost	$	10		$	13		$	8
	Other Benefits
	Year Ended December 31,
(amounts in millions)	2017			2016			2015
Service cost benefits earned during period	$	—		$	1		$	1
Interest cost on projected benefit obligation		2			3			4
Expected return on plan assets		(2	)		(4	)		(4	)
Amortization of:
Prior service credit		(5	)		(4	)		(3	)
Actuarial gain		(1	)		—			—
Net periodic benefit gain		(6	)		(4	)		(2	)
Settlement cost (1)		—			6			—
Total benefit cost (gain)	$	(6	)	$	2		$	(2	)

(1) The settlement cost for the year ended December 31, 2016 was related to EEI’s other post-employment benefit plan for EEI union employees.

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Assumptions. The following weighted average assumptions were used to determine benefit obligations:

	Pension Benefits						Other Benefits
	Year Ended December 31,
	2017			2016			2017			2016
Discount rate (1)		3.60	%		4.05	%		3.55	%		4.00	%
Rate of compensation increase (2)		3.50	%		3.50	%		3.50	%		3.50	%

(1) We utilized a yield curve approach to determine the discount. Projected benefit payments for the plans were matched against the discount rates in the yield curve.

(2) The rate of compensation increase used for other post-employment benefits is specifically related to the EEI post-employment plans.

The following weighted average assumptions were used to determine net periodic benefit cost (gain):

	Pension Benefits									Other Benefits
	Year Ended December 31,
	2017			2016			2015			2017			2016			2015
Discount rate		3.60	%		4.05	%		4.35	%		3.55	%		4.00	%		4.35	%
Dynegy - Expected return on plan assets		6.20	%		5.60	%		5.70	%		N/A			N/A			N/A
EEI - Expected return on plan assets (1)		6.40	%		5.90	%		6.00	%		5.75	%		5.40	%		5.50	%
Rate of compensation increase (2)		3.50	%		3.50	%		3.50	%		3.50	%		3.50	%		3.50	%

(1) The average expected return on EEI’s other post-employment plan assets was 5.75 percent, 5.40 percent, and 5.50 percent for the years ended December 31, 2017, 2016 and 2015, respectively. The expected return on EEI’s other post-employment plan assets was 6.90 percent, 6.30 percent, and 6.20 percent for EEI union employees for the years ended December 31, 2017, 2016 and 2015, respectively. The expected return on EEI’s other post-employment plan assets was 4.60 percent, 4.50 percent, and 4.80 percent for EEI salaried employees for the years ended December 31, 2017, 2016 and 2015, respectively.

(2) The rate of compensation increase used for other post-employment benefits for the years ended December 31, 2017, 2016 and 2015 is specifically related to the EEI post-employment plans.

F-70

Our expected long-term rate of return on Dynegy’s pension plan assets and EEI’s pension plan assets is 5.60 percent and 6.40 percent, respectively, for the year ended December 31, 2018. Our expected long-term rate of return on EEI’s other post-employment plan assets is 7.10 percent for EEI union employees and 4.50 percent for EEI salaried employees for the year ended December 31, 2018. This figure begins with a blend of asset class-level returns developed under a theoretical global capital asset pricing model methodology conducted by an outside consultant. In development of this figure, the historical relationships between equities and fixed income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long term. Current market factors such as inflation and interest rates are also incorporated in the assumptions. This figure gives consideration towards the plan’s use of active management and favorable past experience. It is also net of plan expenses.

The following summarizes our assumed health care cost trend rates:

	Year Ended December 31,
	2017			2016			2015
Health care cost trend rate assumed for next year		7.00	%		7.25	%		7.00	%
Ultimate trend rate		4.50	%		4.50	%		4.50	%
Year that the rate reaches the ultimate trend rate		2025			2025			2023

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The impact of a one percent increase/decrease in assumed health care cost trend rates is as follows:

(amounts in millions)	Increase		Decrease
Aggregate impact on service cost and interest cost	$	—	$	—
Impact on accumulated post-employment benefit obligation	$	3	$	(2	)

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Plan Assets. We employ a total return investment approach whereby a mix of equity and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. The intent of this strategy is to minimize plan expenses by outperforming plan liabilities over the long run. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks as well as growth, value, and small and large capitalizations. The Dynegy plans have adopted a glide-path approach to de-risk the portfolio as funding levels increased. The target asset mix as of December 31, 2017 was approximately 46 percent to equity investments and approximately 54 percent to fixed income investments. Dynegy plan assets are routinely monitored and rebalanced as circumstances warrant. The EEI plans have not adopted a glide-path approach. The target asset mix for EEI’s plan assets as of December 31, 2017 was approximately 60 percent to equity investments and approximately 40 percent to fixed income investments. EEI’s plan assets are routinely monitored and rebalanced as circumstances warrant.

Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying investment. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, periodic asset/liability studies and annual liability measurements.

The following tables set forth by level within the fair value hierarchy assets that were accounted for at fair value related to our pension and other post-employment plans. These assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value as of December 31, 2017
(amounts in millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	7	$	—	$	—	$	7
Equity securities:
U.S. companies (1)		14		136		—		150
Non-U.S. companies (2)		1		19		—		20
International (3)		9		62		—		71
Fixed income securities (4)		63		169		—		232
Total	$	94	$	386	$	—	$	480

F-72

	Fair Value as of December 31, 2016
(amounts in millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	4	$	2	$	—	$	6
Equity securities:
U.S. companies (1)		18		129		—		147
Non-U.S. companies (2)		1		15		—		16
International (3)		8		58		—		66
Fixed income securities (4)		70		161		—		231
Total	$	101	$	365	$	—	$	466

(1) This category comprises a domestic common collective trust not actively managed that tracks the Dow Jones total U.S. stock market.

(2) This category comprises a common collective trust not actively managed that tracks the MSCI All Country World Ex-U.S. Index.

(3) This category comprises actively managed common collective trusts that hold U.S. and foreign equities. These trusts track the MSCI World Index.

(4) This category includes a mutual fund and a trust that invest primarily in investment grade corporate bonds.

Contributions and Payments. Our required benefit contributions for our pension and other post-employment benefit plans are as follows:

(amounts in millions)	Pension Benefits		Other Benefits
2016	$	—	$	2
2017	$	4	$	2
2018	$	13	$	2

F-73

Our expected benefit payments for future services for our pension and other post-employment benefits are as follows:

(amounts in millions)	Pension Benefits		Other Benefits
2018	$	39	$	3
2019	$	38	$	3
2020	$	38	$	3
2021	$	38	$	3
2022	$	38	$	2
2023 -2027	$	190	$	11

Note 18—Quarterly Financial Information

The following is a summary of our unaudited quarterly financial information:

	Quarter Ended
(amounts in millions, except per share data)	March 31			June 30			September 30			December 31
2017
Revenues	$	1,247		$	1,164		$	1,437		$	994
Operating income (loss) (1)	$	(49	)	$	(182	)	$	58		$	(239	)
Net income (loss) (2)(3)(4)	$	596		$	(296	)	$	(133	)	$	(95	)
Net income (loss) attributable to Dynegy Inc. common stockholders (2)(3)(4)	$	592		$	(302	)	$	(137	)	$	(95	)
Net income (loss) per share attributable to Dynegy Inc. common stockholders—Basic (2)(3)(4)	$	4.00		$	(1.96	)	$	(0.89	)	$	(0.58	)
Net income (loss) per share attributable to Dynegy Inc. common stockholders—Diluted (2)(3)(4)	$	3.57		$	(1.96	)	$	(0.89	)	$	(0.58	)
2016
Revenues	$	1,123		$	904		$	1,184		$	1,107
Operating income (loss) (1)	$	145		$	(702	)	$	(117	)	$	34
Net loss	$	(10	)	$	(803	)	$	(249	)	$	(182	)
Net loss attributable to Dynegy Inc. common stockholders	$	(15	)	$	(807	)	$	(254	)	$	(186	)
Net loss per share attributable to Dynegy Inc. common stockholders—Basic	$	(0.13	)	$	(6.73	)	$	(1.81	)	$	(1.33	)
Net loss per share attributable to Dynegy Inc. common stockholders—Diluted	$	(0.13	)	$	(6.73	)	$	(1.81	)	$	(1.33	)

F-74

(1) The results for the quarters ended March 31, 2017, June 30, 2017, and September 30, 2017, include impairment charges of $20 million, $99 million, and $29 million, respectively. The results for the quarters ended June 30, 2016, September 30, 2016, and December 31, 2016, include impairment charges of $645 million, $212 million, and $1 million, respectively. See Note 8—Property, Plant and Equipment for more information.

(2) The results for the quarters ended June 30, 2017, September 30, 2017, and December 31, 2017 include losses on sale of assets of $29 million, $78 million, and $15 million, respectively. See Note 3—Acquisitions and Divestitures and Note 9—Joint Ownership of Generating Facilities for more information.

(3) The results for the quarters ended March 31, 2017, June 30, 2017, and September 30, 2017, include income (loss) from bankruptcy reorganization items of $483 million, ($1) million, and $12 million, respectively. The results for the quarter ended December 31, 2016 include loss from Bankruptcy reorganization items of $96 million. See Note 20—Genco Chapter 11 Bankruptcy for more information.

(4) The results for the quarters ended March 31, 2017 and December 31, 2017 include a $317 million and $37 million income tax benefit, respectively, from the partial release of our valuation allowance as a result of the ENGIE Acquisition. The results for the quarter ended December 31, 2017 include a $223 million tax benefit related to the expected refund of its existing AMT Credits as provided for in the TCJA. See Note 14—Income Taxes for more information.

Note 19—Condensed Consolidating Financial Information

Dynegy’s senior notes are guaranteed by certain, but not all, of our wholly owned subsidiaries. The following condensed consolidating financial statements as of and for the years ended December 31, 2017, 2016 and 2015 present the financial information of (i) Dynegy (“Parent”), which is the parent and issuer of the senior notes, on a stand-alone, unconsolidated basis, (ii) the guarantor subsidiaries of Dynegy, (iii) the non-guarantor subsidiaries of Dynegy, and (iv) the eliminations necessary to arrive at the information for Dynegy on a consolidated basis. The 100 percent owned subsidiary guarantors, jointly, severally, fully, and unconditionally, guarantee the payment obligations under the senior notes. Please read Note 13—Debt for further discussion.

These statements should be read in conjunction with the consolidated financial statements and notes thereto of Dynegy. The supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements. On February 2, 2017, upon Genco’s emergence from bankruptcy, IPH (excluding Electric Energy, Inc.) became a guarantor to the senior notes. Accordingly, condensed consolidating financial information previously reported has been retroactively adjusted to reflect the status of Dynegy’s subsidiaries as either guarantor subsidiaries or non-guarantor subsidiaries as of December 31, 2017.

F-75

For purposes of the condensed consolidating financial statements, a portion of our intercompany receivable, which we do not consider to be likely of settlement, has been classified as equity as of December 31, 2017 and December 31, 2016.

Condensed Consolidating Balance Sheet for the Year Ended December 31, 2017

(amounts in millions)

	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Current Assets
Cash and cash equivalents	$	233	$	124		$	8		$	—		$	365
Accounts receivable, net		126		4,269			14			(3,896	)		513
Inventory		—		415			30			—			445
Other current assets		8		288			2			(97	)		201
Total Current Assets		367		5,096			54			(3,993	)		1,524
Property, plant and equipment, net		—		8,585			299			—			8,884
Investment in affiliates		16,132		—			—			(16,132	)		—
Investment in unconsolidated affiliates		—		123			—			—			123
Goodwill		—		772			—			—			772
Other long-term assets		244		185			39			—			468
Intercompany note receivable		46		—			—			(46	)		—
Total Assets	$	16,789	$	14,761		$	392		$	(20,171	)	$	11,771
Current Liabilities
Accounts payable	$	3,555	$	471		$	232		$	(3,891	)	$	367
Other current liabilities		156		520			108			(102	)		682
Total Current Liabilities		3,711		991			340			(3,993	)		1,049
Debt, long-term portion, net		8,045		256			27			—			8,328
Intercompany note payable		3,042		46			—			(3,088	)		—
Other long-term liabilities		90		367			44			—			501
Total Liabilities		14,888		1,660			411			(7,081	)		9,878
Stockholders’ Equity
Dynegy Stockholders’ Equity		1,901		16,151			(19	)		(16,132	)		1,901
Intercompany note receivable		—		(3,042	)		—			3,042			—
Total Dynegy Stockholders’ Equity		1,901		13,109			(19	)		(13,090	)		1,901
Noncontrolling interest		—		(8	)		—			—			(8	)
Total Equity		1,901		13,101			(19	)		(13,090	)		1,893
Total Liabilities and Equity	$	16,789	$	14,761		$	392		$	(20,171	)	$	11,771

F-76

Condensed Consolidating Balance Sheet for the Year Ended December 31, 2016

(amounts in millions)

	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Current Assets
Cash and cash equivalents	$	1,529	$	221		$	26	$	—		$	1,776
Restricted cash		21		41			—		—			62
Accounts receivable, net		141		2,604			39		(2,398	)		386
Inventory		—		326			119		—			445
Other current assets		12		408			2		(104	)		318
Total Current Assets		1,703		3,600			186		(2,502	)		2,987
Property, plant and equipment, net		—		6,772			349		—			7,121
Investment in affiliates		12,175		—			—		(12,175	)		—
Restricted cash		2,000		—			—		—			2,000
Other long-term assets		2		109			35		—			146
Goodwill		—		799			—		—			799
Intercompany note receivable		—		8			—		(8	)		—
Total Assets	$	15,880	$	11,288		$	570	$	(14,685	)	$	13,053
Current Liabilities
Accounts payable	$	1,990	$	443		$	297	$	(2,398	)	$	332
Other current liabilities		143		377			168		(104	)		584
Total Current Liabilities		2,133		820			465		(2,502	)		916
Liabilities subject to compromise		—		832			—		—			832
Debt, long-term portion, net		8,531		216			31		—			8,778
Intercompany note payable		3,042		—			—		(3,042	)		—
Other long-term liabilities		132		313			51		(8	)		488
Total Liabilities		13,838		2,181			547		(5,552	)		11,014
Stockholders’ Equity
Dynegy Stockholders’ Equity		2,042		12,152			23		(12,175	)		2,042
Intercompany note receivable		—		(3,042	)		—		3,042			—
Total Dynegy Stockholders’ Equity		2,042		9,110			23		(9,133	)		2,042
Noncontrolling interest		—		(3	)		—		—			(3	)
Total Equity		2,042		9,107			23		(9,133	)		2,039
Total Liabilities and Equity	$	15,880	$	11,288		$	570	$	(14,685	)	$	13,053

F-77

Condensed Consolidating Statements of Operations for the Year Ended December 31, 2017

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	4,557		$	422		$	(137	)	$	4,842
Cost of sales, excluding depreciation expense		—			(2,790	)		(279	)		137			(2,932	)
Gross margin		—			1,767			143			—			1,910
Operating and maintenance expense		—			(881	)		(114	)		—			(995	)
Depreciation expense		—			(757	)		(54	)		—			(811	)
Impairments		—			(148	)		—			—			(148	)
Gain (loss) on sale of assets, net		—			(123	)		1			—			(122	)
General and administrative expense		(28	)		(155	)		(6	)		—			(189	)
Acquisition and integration costs		(54	)		(3	)		—			—			(57	)
Operating loss		(82	)		(300	)		(30	)		—			(412	)
Bankruptcy reorganization items		(18	)		512			—			—			494
Earnings from unconsolidated investments		—			8			—			—			8
Equity in losses from investments in affiliates		824			—			—			(824	)		—
Interest expense		(597	)		(20	)		(13	)		14			(616	)
Loss on early extinguishment of debt		(79	)		—			—			—			(79	)
Other income and expense, net		28			53			—			(14	)		67
Income (loss) before income taxes		76			253			(43	)		(824	)		(538	)
Income tax benefit (Note 14)		—			610			—			—			610
Net income (loss)		76			863			(43	)		(824	)		72
Less: Net loss attributable to noncontrolling interest		—			(4	)		—			—			(4	)
Net income (loss) attributable to Dynegy Inc.	$	76		$	867		$	(43	)	$	(824	)	$	76

F-78

Condensed Consolidating Statements of Operations for the Year Ended December 31, 2016

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	3,942		$	468		$	(92	)	$	4,318
Cost of sales, excluding depreciation expense		—			(2,112	)		(261	)		92			(2,281	)
Gross margin		—			1,830			207			—			2,037
Operating and maintenance expense		—			(796	)		(144	)		—			(940	)
Depreciation expense		—			(612	)		(77	)		—			(689	)
Impairments		—			(858	)		—			—			(858	)
Gain (loss) on sale of assets, net		(2	)		1			—			—			(1	)
General and administrative expense		(7	)		(148	)		(6	)		—			(161	)
Acquisition and integration costs		(10	)		(1	)		—			—			(11	)
Other		—			(9	)		(8	)		—			(17	)
Operating loss		(19	)		(593	)		(28	)		—			(640	)
Bankruptcy reorganization items		—			(96	)		—			—			(96	)
Earnings from unconsolidated investments		—			7			—			—			7
Equity in losses from investments in affiliates		(715	)		—			—			715			—
Interest expense		(538	)		(83	)		(9	)		5			(625	)
Other income and expense, net		32			38			—			(5	)		65
Loss before income taxes		(1,240	)		(727	)		(37	)		715			(1,289	)
Income tax benefit (Note 14)		—			45			—			—			45
Net loss		(1,240	)		(682	)		(37	)		715			(1,244	)
Less: Net loss attributable to noncontrolling interest		—			(4	)		—			—			(4	)
Net loss attributable to Dynegy Inc.	$	(1,240	)	$	(678	)	$	(37	)	$	715		$	(1,240	)

F-79

Condensed Consolidating Statements of Operations for the Year Ended December 31, 2015

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	3,508		$	525		$	(163	)	$	3,870
Cost of sales, excluding depreciation expense		—			(1,874	)		(317	)		163			(2,028	)
Gross margin		—			1,634			208			—			1,842
Operating and maintenance expense		—			(717	)		(122	)		—			(839	)
Depreciation expense		—			(505	)		(82	)		—			(587	)
Impairments		—			(74	)		(25	)		—			(99	)
Loss on sale of assets, net		—			(1	)		—			—			(1	)
General and administrative expense		(6	)		(116	)		(6	)		—			(128	)
Acquisition and integration costs		—			(124	)		—			—			(124	)
Operating income (loss)		(6	)		97			(27	)		—			64
Earnings from unconsolidated investments		—			1			—			—			1
Equity in earnings from investments in affiliates		476			—			—			(476	)		—
Interest expense		(475	)		(69	)		(4	)		2			(546	)
Other income and expense, net		55			1			—			(2	)		54
Income (loss) before income taxes		50			30			(31	)		(476	)		(427	)
Income tax benefit (Note 14)		—			472			2			—			474
Net income (loss)		50			502			(29	)		(476	)		47
Less: Net income attributable to noncontrolling interest		—			(3	)		—			—			(3	)
Net income (loss) attributable to Dynegy Inc.	$	50		$	505		$	(29	)	$	(476	)	$	50

F-80

Condensed Consolidating Statements of Comprehensive Income (Loss) for the Year Ended December 31, 2017

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	76		$	863		$	(43	)	$	(824	)	$	72
Other comprehensive income (loss) before reclassifications:
Actuarial gain (loss) and plan amendments, net of tax of $5		22			(3	)		—			—			19
Amounts reclassified from accumulated other comprehensive income:
Amortization of unrecognized prior service credit, net of tax of zero		(7	)		—			(1	)		—			(8	)
Other comprehensive loss from investment in affiliates		(4	)		—			—			4			—
Other comprehensive income (loss), net of tax		11			(3	)		(1	)		4			11
Comprehensive income (loss)		87			860			(44	)		(820	)		83
Less: Comprehensive loss attributable to noncontrolling interest		—			(4	)		—			—			(4	)
Total comprehensive income (loss) attributable to Dynegy Inc.	$	87		$	864		$	(44	)	$	(820	)	$	87

F-81

Condensed Consolidating Statements of Comprehensive Loss for the Year Ended December 31, 2016

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net loss	$	(1,240	)	$	(682	)	$	(37	)	$	715		$	(1,244	)
Other comprehensive income (loss) before reclassifications:
Actuarial gain (loss) and plan amendments, net of tax of $3		(4	)		1			6			—			3
Amounts reclassified from accumulated other comprehensive income:
Settlement cost, net of tax of zero		—			—			6			—			6
Amortization of unrecognized prior service credit, net of tax of zero		(4	)		—			(1	)		—			(5	)
Other comprehensive income from investment in affiliates		12			—			—			(12	)		—
Other comprehensive income, net of tax		4			1			11			(12	)		4
Comprehensive loss		(1,236	)		(681	)		(26	)		703			(1,240	)
Less: Comprehensive income (loss) attributable to noncontrolling interest		2			(2	)		—			(2	)		(2	)
Total comprehensive loss attributable to Dynegy Inc.	$	(1,238	)	$	(679	)	$	(26	)	$	705		$	(1,238	)

F-82

Condensed Consolidating Statements of Comprehensive Income (Loss) for the Year Ended December 31, 2015

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	50		$	502		$	(29	)	$	(476	)	$	47
Other comprehensive income (loss) before reclassifications:
Actuarial gain (loss) and plan amendments, net of tax of zero		(8	)		7			5			—			4
Amounts reclassified from accumulated other comprehensive income (loss):
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero		(3	)		—			(1	)		—			(4	)
Other comprehensive loss from investment in affiliates		11			—			—			(11	)		—
Other comprehensive income, net of tax		—			7			4			(11	)		—
Comprehensive income (loss)		50			509			(25	)		(487	)		47
Less: Comprehensive income (loss) attributable to noncontrolling interest		1			(2	)		—			(1	)		(2	)
Total comprehensive income (loss) attributable to Dynegy Inc.	$	49		$	511		$	(25	)	$	(486	)	$	49

F-83

Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2017

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(427	)	$	899		$	113		$	—		$	585
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		—			(208	)		(16	)		—			(224	)
Acquisitions, net of cash acquired/divestitures		(3,244	)		(75	)		—			—			(3,319	)
Distributions from unconsolidated affiliate		—			12			—			—			12
Proceeds from sales of assets, net		775			(4	)		1			—			772
Net intercompany transfers		691			—			—			(691	)		—
Net cash used in investing activities		(1,778	)		(275	)		(15	)		(691	)		(2,759	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs		1,743			—			—			—			1,743
Repayments of borrowings		(2,487	)		(46	)		(56	)		—			(2,589	)
Proceeds from issuance of equity, net of issuance costs		150			—			—			—			150
Payments of debt extinguishment costs		(50	)		—			—			—			(50	)
Preferred stock dividends paid		(22	)		—			—			—			(22	)
Interest rate swap settlement payments		(20	)		—			—			—			(20	)
Acquisition of noncontrolling interest		(375	)		—			—			—			(375	)
Payments related to bankruptcy settlement		(128	)		(5	)		—			—			(133	)
Net intercompany transfers		—			(631	)		(60	)		691			—
Intercompany borrowings, net of repayments		80			(80	)		—			—			—
Other financing		(3	)		—			—			—			(3	)
Net cash provided by (used in) financing activities		(1,112	)		(762	)		(116	)		691			(1,299	)
Net decrease in cash and cash equivalents		(3,317	)		(138	)		(18	)		—			(3,473	)
Cash, cash equivalents and restricted cash, beginning of period		3,550			262			26			—			3,838
Cash, cash equivalents and restricted cash, end of period	$	233		$	124		$	8		$	—		$	365

F-84

Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2016

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(476	)	$	1,090		$	31		$	—		$	645
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		—			(243	)		(50	)		—			(293	)
Proceeds from sales of assets, net		171			5			—			—			176
Distributions from unconsolidated affiliate		—			14			—			—			14
Net intercompany transfers		958			—			—			(958	)		—
Other investing		—			10			—			—			10
Net cash provided by (used in) investing activities		1,129			(214	)		(50	)		(958	)		(93	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs		2,816			198			—			—			3,014
Repayments of borrowings		(563	)		(15	)		(11	)		—			(589	)
Proceeds from issuance of equity, net of issuance costs		359			—			—			—			359
Preferred stock dividends paid		(22	)		—			—			—			(22	)
Interest rate swap settlement payments		(17	)		—			—			—			(17	)
Net intercompany transfers		—			(991	)		33			958			—
Other financing		(3	)		—			—			—			(3	)
Net cash provided by (used in) financing activities		2,570			(808	)		22			958			2,742
Net increase in cash and cash equivalents		3,223			68			3			—			3,294
Cash, cash equivalents and restricted cash, beginning of period		327			194			23			—			544
Cash, cash equivalents and restricted cash, end of period	$	3,550		$	262		$	26		$	—		$	3,838

F-85

Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2015

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(432	)	$	682		$	(156	)	$	—		$	94
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		—			(290	)		(11	)		—			(301	)
Acquisitions, net of cash acquired/divestitures		(6,207	)		29			100			—			(6,078	)
Distributions from unconsolidated affiliate		—			8			—			—			8
Net intercompany transfers		450			—			—			(450	)		—
Other investing		—			3			—			—			3
Net cash provided by (used in) investing activities		(5,757	)		(250	)		89			(450	)		(6,368	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs		(31	)		78			19			—			66
Repayments of borrowings		(8	)		(23	)		—			—			(31	)
Proceeds from issuance of equity, net of issuance costs		(6	)		—			—			—			(6	)
Preferred stock dividends paid		(23	)		—			—			—			(23	)
Interest rate swap settlement payments		(17	)		—			—			—			(17	)
Repurchase of common stock		(250	)		—			—			—			(250	)
Net intercompany transfers		—			(347	)		(103	)		450			—
Other financing		(4	)		—			—			—			(4	)
Net cash provided by (used in) financing activities		(339	)		(292	)		(84	)		450			(265	)
Net increase (decrease) in cash and cash equivalents		(6,528	)		140			(151	)		—			(6,539	)
Cash, cash equivalents and restricted cash, beginning of period		6,855			54			174			—			7,083
Cash, cash equivalents and restricted cash, end of period	$	327		$	194		$	23		$	—		$	544

F-86

Note 20—Genco Chapter 11 Bankruptcy

On October 14, 2016, we entered into a restructuring support agreement with Genco and an ad hoc group of Genco bondholders to restructure the Genco senior notes. As a result of filing a prepackaged plan of reorganization (the “Genco Plan”), we reclassified the Genco senior notes as Liabilities subject to compromise in our consolidated balance sheet as of December 31, 2016. The amounts represented the allowed claims to be resolved in connection with our Chapter 11 proceedings. A summary of our liabilities subject to compromise as of December 31, 2016 is as follows:

(amounts in millions)	December 31, 2016
Genco senior notes:
7.00% Senior Notes Series H, due 2018	$	300
6.30% Senior Notes Series I, due 2020		250
7.95% Senior Notes Series F, due 2032		275
Interest accrued		7
Total liabilities subject to compromise	$	832

Costs associated with the reorganization incurred prior to the Bankruptcy Petition of approximately $10 million have been recorded in General and administrative expense in our consolidated statement of operations for the year ended December 31, 2016. Costs post Genco’s Bankruptcy Petition of approximately $96 million have been recorded to Bankruptcy reorganization items in our consolidated statement of operations for the year ended December 31, 2016, and primarily include the write-off of the remaining unamortized discount related to the Genco senior notes and legal expenses incurred.

On December 9, 2016, Genco filed a petition (the “Bankruptcy Petition”) under title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). On January 25, 2017, the Bankruptcy Court confirmed the Genco Plan and Genco emerged from bankruptcy on February 2, 2017. As a result, we eliminated $825 million of Genco senior notes and $7 million of accrued interest in exchange for approximately $122 million of cash, $188 million of new seven-year unsecured notes, and 2017 Warrants to purchase up to 9 million shares of common stock with a fair value of $17 million.

The 2017 Warrants, which have an exercise price of $35 per share of common stock, have a seven-year term expiring on February 2, 2024 and are recorded as Other long-term liabilities in our consolidated balance sheet as of December 31, 2017.

F-87

The following table summarizes the Company’s gain from the termination of the Genco senior notes, which is recognized in Bankruptcy reorganization items in our consolidated statement of operations for the year ended December 31, 2017:

(amounts in millions)
Liabilities subject to compromise, which were terminated	$	832
Less:
Seven-year unsecured notes		188
Cash consideration		122
2017 Warrants, at fair value		17
Legal and consulting fees		11
Bankruptcy reorganization items	$	494

For income tax purposes, the income from cancellation of debt is excluded from taxable income in the current year and will instead reduce Genco’s tax attributes.

During 2016, upon Genco’s petition for bankruptcy under Chapter 11, we analyzed Genco as a VIE. Based on the analysis, it was determined that Dynegy was the primary beneficiary of Genco and continued to receive the benefits and controlled the significant activities of Genco. As a result, Genco was consolidated by Dynegy as a VIE as of December 31, 2016.

Note 21—Segment Information

We report the results of our operations in the following five segments based upon the market areas in which our plants operate: (i) PJM, (ii) NY/NE, (iii) ERCOT, (iv) MISO and (v) CAISO. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense and income tax benefit (expense). In the fourth quarter of 2017, we combined our previous MISO and IPH segments into a single MISO segment to better align our IPH assets, which reside within the MISO market area. Accordingly, the Company has recast data from prior periods to conform to the current year segment presentation. PJM also includes our Dynegy Energy Services retail business in Ohio and Pennsylvania. NY/NE also includes our Dynegy Energy Services retail business in Massachusetts. MISO also includes our Homefield Energy retail business in Illinois.

Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the years ended December 31, 2017, 2016 and 2015 is presented below:

F-88

Segment Data as of and for the Year Ended December 31, 2017

(amounts in millions)

	PJM			NY/NE			ERCOT			MISO			CAISO			Other and Eliminations			Total
Domestic:
Unaffiliated revenues	$	2,352		$	1,031		$	276		$	1,061		$	122		$	—		$	4,842
Intercompany and affiliate revenues		(90	)		(2	)		1			91			—			—			—
Total revenues	$	2,262		$	1,029		$	277		$	1,152		$	122		$	—		$	4,842
Depreciation expense	$	(379	)	$	(224	)	$	(73	)	$	(75	)	$	(53	)	$	(7	)	$	(811	)
Impairments		(49	)		—			—			(99	)		—			—			(148	)
Gain (loss) on sale of assets, net		(36	)		(90	)		—			1			3			—			(122	)
General and administrative expense		—			—			—			—			—			(189	)		(189	)
Acquisition and integration costs		—			—			—			—			—			(57	)		(57	)
Operating income (loss)	$	192		$	(113	)	$	(147	)	$	(44	)	$	(45	)	$	(255	)	$	(412	)
Bankruptcy reorganization items		—			—			—			494			—			—			494
Earnings from unconsolidated investments		3			5			—			—			—			—			8
Interest expense		—			—			—			—			—			(616	)		(616	)
Loss on early extinguishment of debt		—			—			—			—			—			(79	)		(79	)
Other income and expense, net		16			—			—			26			—			25			67
Loss before income taxes																				(538	)
Income tax benefit		—			—			—			—			—			610			610
Net Income																				72
Less: Net loss attributable to noncontrolling interest																				(4	)
Net Income attributable to Dynegy Inc.																			$	76
Total assets—domestic	$	4,912		$	3,374		$	1,563		$	812		$	455		$	655		$	11,771
Investment in unconsolidated affiliate	$	67		$	56		$	—		$	—		$	—		$	—		$	123
Capital expenditures	$	(103	)	$	(50	)	$	(26	)	$	(26	)	$	(12	)	$	(7	)	$	(224	)

F-89

Segment Data as of and for the Year Ended December 31, 2016

(amounts in millions)

	PJM			NY/NE			MISO			CAISO			Other and Eliminations			Total
Domestic:
Unaffiliated revenues	$	2,147		$	836		$	1,165		$	142		$	—		$	4,290
Intercompany revenues		55			1			(28	)		—			—			28
Total revenues	$	2,202		$	837		$	1,137		$	142		$	—		$	4,318
Depreciation expense	$	(346	)	$	(215	)	$	(81	)	$	(42	)	$	(5	)	$	(689	)
Impairments		(65	)		—			(793	)		—			—			(858	)
Gain (loss) on sale of assets, net		—			—			1			—			(2	)		(1	)
General and administrative expense		—			—			—			—			(161	)		(161	)
Acquisition and integration costs		—			—			8			—			(19	)		(11	)
Operating income (loss)	$	414		$	(29	)	$	(832	)	$	(5	)	$	(188	)	$	(640	)
Bankruptcy reorganization items		—			—			(96	)		—			—			(96	)
Earnings from unconsolidated investments		7			—			—			—			—			7
Interest expense		—			—			—			—			(625	)		(625	)
Other income and expense, net		9			1			15			12			28			65
Loss before income taxes																	(1,289	)
Income tax benefit		—			—			—			—			45			45
Net loss																	(1,244	)
Less: Net loss attributable to noncontrolling interest																	(4	)
Net loss attributable to Dynegy Inc.																$	(1,240	)
Total assets—domestic	$	4,939		$	2,769		$	1,065		$	485		$	3,795		$	13,053
Capital expenditures	$	(160	)	$	(64	)	$	(52	)	$	(7	)	$	(10	)	$	(293	)

F-90

Segment Data as of and for the Year Ended December 31, 2015

(amounts in millions)

	PJM			NY/NE			MISO			CAISO			Other and Eliminations			Total
Domestic:
Unaffiliated revenues	$	1,708		$	705		$	1,279		$	178		$	—		$	3,870
Intercompany revenues		8			(10	)		2			—			—			—
Total revenues	$	1,716		$	695		$	1,281		$	178		$	—		$	3,870
Depreciation expense	$	(281	)	$	(186	)	$	(68	)	$	(48	)	$	(4	)	$	(587	)
Impairments		—			(25	)		(74	)		—			—			(99	)
Loss on sale of assets, net		—			—			—			(1	)		—			(1	)
General and administrative expense		—			—			—			—			(128	)		(128	)
Acquisition and integration costs		—			—			—			—			(124	)		(124	)
Operating income (loss)	$	423		$	(56	)	$	(43	)	$	(8	)	$	(252	)	$	64
Earnings from unconsolidated investments		1			—			—			—			—			1
Interest expense		—			—			—			—			(546	)		(546	)
Other income and expense, net		(2	)		—			1			—			55			54
Loss from continuing operations before income taxes																	(427	)
Income tax benefit		—			—			—			—			474			474
Net income																	47
Less: Net loss attributable to noncontrolling interest																	(3	)
Net income attributable to Dynegy Inc.																$	50
Total assets—domestic	$	5,474		$	2,970		$	1,995		$	534		$	486		$	11,459
Investment in unconsolidated affiliate	$	190		$	—		$	—		$	—		$	—		$	190
Capital expenditures	$	(106	)	$	(52	)	$	(119	)	$	(11	)	$	(13	)	$	(301	)

F-91

Significant Customers

Our total revenues for customers who individually accounted for more than 10 percent of our consolidated revenues, and the segments impacted, for the years ended December 31, 2017, 2016 and 2015 are presented below:

(amounts in millions) Customers	Revenues
	2017		2016		2015		Segment(s)
PJM	$	1,313	$	1,366	$	1,088	PJM, MISO
MISO	$	506	$	688	$	842	MISO
ISO-NE	$	669	$	437		N/A	MISO, NY/NE

Employee Concentrations

As of December 31, 2017, approximately 40 percent of our employees are covered by a collective bargaining agreement.

F-92