Exhibit 99.2

Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read together with the consolidated financial statements and the notes thereto included in Exhibit 99.3 attached to this Current Report on Form 8-K. All references to notes to our consolidated financial statements refer to the financial statements included in Exhibit 99.3 attached to this Current Report on Form 8-K. All references to our Annual Report on Form 10-K refer to our Form 10-K for the year ended December 31, 2017 which was filed with the Securities and Exchange Commission on February 26, 2018. The following discussion has been updated subsequent to the filing of the Form 10-K to reflect a change in reporting segments in the first quarter of 2018.

As described in Note 1 to the Financial Statements, Vistra Energy is considered a new reporting entity for accounting purposes as of the Effective Date, and its financial statements reflect the application of fresh start reporting. The financial statements of Vistra Energy (the Successor) for periods subsequent to the Effective Date are not comparable to the financial statements of TCEH (the Predecessor) for periods prior to the Effective Date, as those previous periods do not give effect to any adjustments to the carrying values of assets or amounts of liabilities that resulted from the Plan of Reorganization, and the related application of fresh start reporting, which includes accounting policies implemented by Vistra Energy that may differ from the Predecessor. See Note 6 to the Financial Statements for further discussion of fresh start reporting.

The following discussion and analysis of our financial condition and results of operations for the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015 should be read in conjunction with our consolidated financial statements and the notes to those statements. Results are impacted by the effects of fresh start reporting, the Bankruptcy Filing and the application of Financial Accounting Standards Board Accounting Standards Codification (ASC) 852, Reorganizations.

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

Business

Vistra Energy is a holding company operating an integrated power business in Texas. Through our Luminant and TXU Energy subsidiaries, we are principally engaged in competitive electricity market activities including electricity generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity and related services to end users. Prior to the Effective Date, TCEH was a holding company for our subsidiaries, which were principally engaged in the same activities as they are today.

Operating Segments

Subsequent to the Effective Date, Vistra Energy has three reportable segments: (i) our Wholesale Generation segment, consisting largely of Luminant, (ii) our Retail Electricity segment, consisting largely of TXU Energy, and (iii) our Asset Closure segment, consisting of financial results of retired plants and mines. Prior to the Effective Date, there were no reportable business segments for TCEH. See Note 20 to the Financial Statements for further information concerning reportable business segments.

Significant Activities and Events and Items Influencing Future Performance

Merger Agreement — On October 29, 2017, Vistra Energy and Dynegy Inc., a Delaware corporation (Dynegy), entered into an Agreement and Plan of Merger (the Merger Agreement). Upon the terms and subject to the conditions set forth in the Merger Agreement, which has been approved by the boards of directors of Vistra Energy and Dynegy, Dynegy will merge with and into Vistra Energy (the Merger), with Vistra Energy continuing as the surviving corporation.

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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 Vistra Energy or its subsidiaries, held in treasury by Dynegy or held by a subsidiary of Dynegy, will automatically be converted into the right to receive the Exchange Ratio, except that cash will be paid in lieu of fractional shares, which we expect will result in Vistra Energy's stockholders and Dynegy's stockholders owning approximately 79% and 21%, respectively, of the combined company.

See Note 2 to the Financial Statements for a summary of the Merger Agreement and the related Merger Support Agreements. The Merger is subject to numerous uncertainties and risks more fully described in Item 1. Risk Factors of this Annual Report on Form 10-K.

Retirement of Generation Plants — In October 2017, Luminant announced plans to retire three power plants with a total installed nameplate generation capacity of approximately 4,167 MW and two lignite mines. These power plants include the Monticello, Sandow 4, Sandow 5 and Big Brown generation units. Luminant decided to retire these units given they are projected to be uneconomic based on current market conditions and given the significant environmental costs associated with operating such units. In the case of the Sandow units, the decision also reflected the execution of a Settlement Agreement discussed below.

As part of the retirement process, Luminant filed notices with ERCOT, which triggered a reliability review regarding such proposed retirements. In October and November 2017, ERCOT determined the units were not needed for reliability. The Sandow and Monticello units were retired in January 2018, and the Big Brown units were retired in February 2018.

During the year ended December 31, 2017, we recorded charges of approximately $206 million related to the retirements, including employee related severance costs, noncash charges for writing off materials inventory and a contract intangible asset associated with the Big Brown plant and the acceleration of Luminant's mining reclamation obligations (see Note 21 to the Financial Statements). In addition, we will continue the ongoing reclamation work at the plants' mines.

Termination and Settlement of Alcoa Contract — In October 2017, subsidiaries of Vistra Energy (Vistra Parties) entered into a separation and settlement agreement (Settlement Agreement) with Alcoa Corporation and Alcoa USA Corp. (collectively, the Alcoa Parties). Pursuant to the Settlement Agreement, the Vistra Parties and the Alcoa Parties agreed to early termination of a series of agreements related to industrial operations near Rockdale, Texas, thereby ending their contractual relationship with respect to the power generation unit known as Sandow Unit 4 and the mine known as Three Oaks Mine. The terminated agreements were scheduled to terminate in 2038 absent the Settlement Agreement. Among other things, the Alcoa Parties made a cash payment to the Vistra Parties in the amount of approximately $238 million and transferred certain real property and related assets to the Vistra Parties, the Vistra Parties agreed to assume and be responsible for certain liabilities and asset retirement obligations related to Sandow Unit 4 (including certain related common facilities), the related mine and other property transferred from the Alcoa Parties to the Vistra Parties, and both parties released one another from any obligations and claims under the terminated agreements. The transactions under the Settlement Agreement are effective as of October 1, 2017.

In the three months ended December 31, 2017, we recorded a gain related to the impacts of the Settlement Agreement in our consolidated financial statements totaling $11 million, which included the receipt of the cash payment, the acquisition of real property and the incurrence of certain liabilities and asset retirement obligations, along with the elimination of a related electric supply contract intangible asset on our consolidated balance sheet (see Note 7 to the Financial Statements).

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

Upton Solar Development — In May 2017, we acquired the rights to develop, construct and operate a utility scale solar photovoltaic power generation facility in Upton County, Texas. As part of this project, we entered a turnkey engineering, procurement and construction agreement to construct the approximately 180 MW facility. For the year ended December 31, 2017, we have spent approximately $190 million related to this project primarily for progress payments under the engineering, procurement and construction agreement and the acquisition of the development rights. We currently estimate that the facility will begin operations in the summer of 2018.

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Repricing of Vistra Operations Credit Facilities—In February, August and December 2017 and February 2018, certain pricing terms for the Vistra Operations Credit Facility were amended. Any amounts borrowed under the Revolving Credit Facility will bear interest based on applicable LIBOR rates plus 2.25%. Amounts borrowed under the Initial Term Loan B Facility and the Term Loan C Facility will bear interest based on applicable LIBOR rates, subject to a 0.75% floor, plus 2.50%. The Incremental Term Loan B Facility will bear interest based on applicable LIBOR rates plus 2.25%. In connection with a repricing amendment in December 2017, the Revolving Credit Facility letter of credit sub-facility was increased from $600 million to $715 million and the Term Loan C Facility was reduced from $650 million to $500 million. See Note 12 to the Financial Statements for details of the Vistra Operations Credit Facilities.

Environmental Matters — See Note 13 to Financial Statements for a discussion of greenhouse gas emissions, the Cross-State Air Pollution Rule, regional haze, state implementation plan and other recent EPA actions as well as related litigation.

Key Risks and Challenges

Following is a discussion of key risks and challenges facing management and the initiatives currently underway to manage such challenges. These matters involve risks that could have a material effect on our results of operations, liquidity or financial condition.

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Natural Gas Price and Market Heat Rate Exposure

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

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(a) Settled prices represent the average of NYMEX Henry Hub monthly settled prices of financial contracts for the year ending on the date presented. Forward prices represent the three-year average of NYMEX Henry Hub monthly forward prices at the date presented. Three-year forward prices are presented as such period is generally deemed to be a liquid period.

In contrast to our natural gas fueled generation facilities, changes in natural gas prices have no significant effect on the cost of generating power at our nuclear-, lignite- and coal-fueled facilities, which represent a substantial amount of our generation capacity. Consequently, all other factors being equal, these nuclear-, lignite- and coal-fueled generation assets increase or decrease in value as natural gas prices and market heat rates rise or fall, respectively, because of the effect on our operating margins from changes in wholesale electricity prices in ERCOT. A persistent decline in the price of natural gas, and the corresponding decline in the price of power in the ERCOT market, would likely have a material adverse effect on our results of operations, liquidity and financial condition, predominantly related to the production of power generation volumes in excess of the volumes utilized to service our retail customer load requirements.

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

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

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

• employing disciplined, liquidity-efficient hedging and risk management strategies through physical and financial energy-related contracts intended to partially hedge gross margins;

• continuing focus on cost management to better withstand gross margin volatility;

• following a retail pricing strategy that appropriately reflects the value of our product offering to customers, the magnitude and costs of commodity price, liquidity risk and retail demand variability, and

• improving retail customer service to attract and retain high-value customers.

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

Taking together forward wholesale, retail electricity sales and other retail customer considerations and all other hedging positions, at December 31, 2017, we had effectively hedged an estimated 90% and 22% of the natural gas price exposure related to our overall business for 2018 and 2019, respectively. Additionally, taking into consideration our overall heat rate exposure and related hedging positions at December 31, 2017, we had effectively hedged 83% and 42% of the heat rate exposure to our overall business for 2018 and 2019, respectively.

The following sensitivity table provides approximate estimates of the potential impact of movements in natural gas prices and market heat rates on realized pretax earnings (in millions) taking into account the hedge positions noted in the paragraph above for the periods presented. The estimates related to price sensitivity are based on our expected generation and retail positions, related hedges and forward prices as of December 31, 2017. The underlying hedge positions take into account the effects of the retirements of generation facilities discussed in Note 4 to the Financial Statements.

	Balance 2018 (a)	2019
$0.50/MMBtu increase in natural gas price (b)(c)	$ ~25	$ ~155
$0.50/MMBtu decrease in natural gas price (b)(c)	$ ~(15)	$ ~(155)
1.0/MMBtu/MWh increase in market heat rate (d)	$ ~60	$ ~110
1.0/MMBtu/MWh decrease in market heat rate (d)	$ ~(55)	$ ~(100)

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(a) Balance of 2018 is from February 1, 2018 through December 31, 2018 for natural gas price sensitivities and January 1, 2018 through December 31, 2018 for market heat rate sensitivities.

(b) Assumes conversion of generation positions based on market heat rates and an estimate of natural gas generally being on the margin 70% to 90% of the time in the ERCOT market.

(c) Based on Houston Ship Channel natural gas prices at December 31, 2017.

(d) Based on ERCOT North Hub around-the-clock heat rates at December 31, 2017.

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Competitive Retail Markets and Customer Retention

Competitive retail activity in ERCOT has resulted in retail customer churn as customers switch retail electricity providers for various reasons. Based on numbers of meters, our total retail customer counts increased slightly in 2017 and declined approximately 1% in 2016 and less than 1% in 2015. Based upon December 31, 2017 results discussed below in Results of Operations, a 1% decline in retail customers would result in a decline in annual revenues of approximately $40 million. In responding to the competitive landscape in the ERCOT market, we have attempted to reduce overall customer losses by focusing on the following key initiatives:

• Maintaining competitive pricing initiatives on residential service plans;

• Actively competing for new customers in areas open to competition within ERCOT, while continuing to strive to enhance the experience of our existing customers; we are focused on continuing to implement initiatives that deliver world-class customer service and improve the overall customer experience;

• Establishing and leveraging our TXU Energy^TM brand in the sale of electricity to residential and commercial customers, as the most innovative retailer in the ERCOT market by continuing to develop tailored product offerings to meet customer needs, and

• Focusing market initiatives largely on programs targeted at retaining the existing highest-value customers and to recapturing customers who have switched REPs, including maintaining and continuously refining a disciplined contracting and pricing approach and economic segmentation of the business market to enhance targeted sales and marketing efforts and to more effectively deploy our direct-sales force; tactical programs we have initiated include improved customer service, aided by an enhanced customer management system, new product price/service offerings and a multichannel approach for the small business market.

Exposures Related to Nuclear Asset Outages

Our nuclear assets are comprised of two generation units at the Comanche Peak facility, each with an installed nameplate generation capacity of 1,150 MW. As of February 26, 2018, these units represented approximately 17% of our total generation capacity. The nuclear generation units represent our lowest marginal cost source of electricity. Assuming both nuclear generation units experienced an outage at the same time, the unfavorable impact to pretax earnings is estimated (based upon forward electricity market prices for 2018 at December 31, 2017) to be approximately $1 million per day before consideration of any costs to repair the cause of such outages or receipt of any insurance proceeds. Also see discussion of nuclear facilities insurance in Note 13 to the Financial Statements.

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

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

Cyber/Data Security and Infrastructure Protection Risk

A breach of cyber/data security measures that impairs our information technology infrastructure could disrupt normal business operations and affect our ability to control our generation assets, access retail customer information and limit communication with third parties. Any loss of confidential or proprietary data through a breach could materially affect our reputation, including our TXU Energy^TM brand, expose the company to legal claims or impair our ability to execute on business strategies.

We participate in industry groups and with regulators to remain current on emerging threats and mitigating techniques. These groups include, but are not limited to, the U.S. Cyber Emergency Response Team, the National Electric Sector Cyber Security Organization, the NRC and NERC.

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While the company has not experienced a cyber/data event causing any material operational, reputational or financial impact, we recognize the growing threat within the general market place and our industry, and are proactively making strategic investments in our perimeter and internal defenses, cyber/data security operations center and regulatory compliance activities. We also apply the knowledge gained through industry and government organizations to continuously improve our technology, processes and services to detect, mitigate and protect our cyber and data assets.

Application of Critical Accounting Policies

Our significant accounting policies are discussed in Note 1 to the Financial Statements. We follow accounting principles generally accepted in the U.S. Application of these accounting policies in the preparation of our consolidated financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and revenues and expenses during the periods covered. The following is a summary of certain critical accounting policies that are impacted by judgments and uncertainties and under which different amounts might be reported using different assumptions or estimation methodologies.

Accounting in Reorganization and Fresh-Start Reporting

The consolidated financial statements of our Predecessor reflect the application of ASC 852. During the Chapter 11 Cases, the Debtors, including our Predecessor and its subsidiaries, operated their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. ASC 852 applies to entities that have filed a petition for bankruptcy under Chapter 11 of the Bankruptcy Code. The guidance requires that transactions and events directly associated with the reorganization be distinguished from the ongoing operations of the business. In addition, the guidance provides for changes in the accounting and presentation of liabilities. Expenses and income directly associated with the Chapter 11 Cases are reported separately in the statements of consolidated income (loss) as reorganization items. Reorganization items also include adjustments to reflect the carrying value of liabilities subject to compromise (LSTC) at their estimated allowed claim amounts, as such adjustments are determined. See Note 5 to the Financial Statements.

As of the Effective Date, Vistra Energy applied fresh-start reporting under the applicable provisions of ASC 852. Fresh-start reporting includes (1) distinguishing the consolidated financial statements of the entity that was previously in restructuring from the consolidated financial statements of the entity that emerges from restructuring, (2) assigning the reorganized value of the successor entity by measuring all assets and liabilities of the successor entity at fair value, and (3) selecting accounting policies for the successor entity. The effects from emerging from bankruptcy, including the extinguishment of liabilities, as well as the fresh start reporting adjustments are reported in the Predecessor's statement of consolidated income (loss). The consolidated financial statements of Vistra Energy for periods subsequent to the Effective Date are not comparable to the financial statements of our Predecessor for periods prior to the Effective Date, as those previous periods do not give effect to any adjustments to the carrying values of assets or amounts of liabilities, nor any differences in accounting policies that were a consequence of the Plan of Reorganization or the related application of fresh-start reporting. See Note 6 to the Financial Statements.

Derivative Instruments and Mark-to-Market Accounting

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

Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as market prices change. Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net income with an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. In computing fair value for derivatives, each forward pricing curve is separated into liquid and illiquid periods. The liquid period varies by delivery point and commodity. Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity. For illiquid periods, fair value is estimated based on forward price curves developed using modeling techniques that take into account available market information and other inputs that might not be readily observable in the market. We estimate fair value as described in Note 15 to the Financial Statements.

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Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. Normal purchases and sales are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business and are not subject to mark-to-market accounting if the normal purchase or sale election is made. Vistra Energy does not have derivative instruments with hedge accounting designations.

We report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting arrangements that we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the consolidated balance sheets, with the exception of certain margin amounts related to changes in fair value on certain CME transactions that, beginning in January 2017, are legally characterized as settlement of derivative contracts rather than collateral.

See Note 16 to the Financial Statements for further discussion regarding derivative instruments.

Accounting for Income Taxes

EFH Corp. files a United States federal income tax return that includes the results of EFCH, EFIH, Oncor Holdings and, prior to the Effective Date, TCEH. EFH Corp. is the corporate parent of the EFH Corp. consolidated group, while each of EFIH, Oncor Holdings, EFCH and, prior to the effective date, TCEH was classified as a disregarded entity for United States federal income tax purposes. Pursuant to applicable United States Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group. Subsequent to the Effective Date, the TCEH Debtor and the Contributed EFH Debtors are no longer included in the EFH Corp. consolidated group and are included in a consolidated group of which Vistra Energy is the corporate parent.

Prior to the Effective Date, EFH Corp. and certain of its subsidiaries (including EFCH, EFIH, and TCEH, but not including Oncor Holdings and Oncor) were parties to a Federal and State Income Tax Allocation Agreement, which provided, among other things, that any corporate member or disregarded entity in the EFH Corp. group was required to make payments to EFH Corp. in an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return. Pursuant to the Plan of Reorganization, the TCEH Debtors and Contributed EFH Debtors rejected this agreement on the Effective Date. See Notes 5 and 8 to the Financial Statements for a discussion of the Tax Matters Agreement that was entered on the Effective Date between EFH Corp. and Vistra Energy. Additionally, since the date of the Settlement Agreement, no further cash payments among the Debtors were made in respect of federal income taxes. EFH Corp. has elected to continue to allocate federal income taxes among the entities that are parties to the Federal and State Income Tax Allocation Agreement. The Settlement Agreement did not alter the allocation and payment for state income taxes, which continued to be settled prior to the Effective Date.

Our income tax expense and related consolidated balance sheet amounts involve significant management estimates and judgments. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve estimates and judgments of the timing and probability of recognition of income and deductions by taxing authorities. In assessing the likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future taxable income. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, our forecasted financial condition and results of operations in future periods, as well as final review of filed tax returns by taxing authorities. Income tax returns are regularly subject to examination by applicable tax authorities. In management's opinion, the liability recorded pursuant to income tax accounting guidance related to uncertain tax positions reflects future taxes that may be owed as a result of any examination.

Our deferred tax assets were significantly impacted by the TCJA, which reduced the overall federal corporate rate from 35% to 21%. This rate change decreased our overall deferred tax asset balance by approximately $451 million.

See Notes 1 and 8 to the Financial Statements for discussion of income tax matters.

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Accounting for Tax Receivable Agreement

On the Effective Date, we entered into a tax receivable agreement (the TRA) with American Stock Transfer & Trust Company, LLC, as the transfer agent. Pursuant to the TRA, we issued beneficial interests in the rights to receive payments under the TRA (the TRA Rights) to the first lien creditors of our Predecessor to be held in escrow for the benefit of the first lien creditors of our Predecessor entitled to receive such TRA Rights under the Plan. As part of Emergence, Vistra Energy reflected the obligation associated with TRA Rights at fair value in the amount of $574 million related to these future payment obligations. As of December 31, 2017, the TRA obligation has been adjusted to $357 million. During the year ended December 31, 2017, we recorded reductions to the carrying value of the TRA obligation totaling approximately $295 million. The largest driver in the reduction to the TRA obligation carrying value primarily resulted from a change in the corporate tax rate from 35% to 21% related to tax reform legislation, which reduced the total expected undiscounted payments under the TRA from $2.1 billion to $1.2 billion. The TRA obligation value is the discounted amount of estimated payments to be made each year under the TRA, based on certain assumptions, including but not limited to:

• the amount of tax basis related to (i) the Lamar and Forney acquisition and (ii) step-up resulting from the PrefCo Preferred Stock Sale (which is estimated to be approximately $5.5 billion) and the allocation of such tax basis step-up among the assets subject thereto;

• the depreciable lives of the assets subject to such tax basis step-up, which generally is expected to be 15 years for most of such assets;

• a federal corporate income tax rate in all future years of 21%;

• the Company generally expects to generate sufficient taxable income to be able to utilize the deductions arising out of (i) the tax basis step up attributable to the PrefCo Preferred Stock Sale, (ii) the entire tax basis of the assets acquired as a result of the Lamar and Forney Acquisition, and (iii) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA in the tax year in which such deductions arise; and

• a discount rate of 15%, which represents our view of the rate that a market participant would use based on the risk associated with the uncertainty in the amount and timing of the cash flows, at the time of Emergence.

We recognize accretion expense over the life of the TRA Rights liability as the present value of the liability is accreted up over the life of the liability. This noncash accretion expense is reported in the statements of consolidated income (loss) as Impacts of Tax Receivable Agreement. Further, there may be significant changes, which may be material, to the estimate of the related liability due to various reasons including changes in corporate tax law, changes in estimates of future taxable income of Vistra Energy and its subsidiaries and other items. Changes in those estimates are recognized as adjustments to the related TRA Rights liability, with offsetting impacts recorded in the statements of consolidated income (loss) as Impacts of Tax Receivable Agreement. See Note 9 to the Financial Statements.

Asset Retirement Obligations (ARO)

As part of fresh start reporting, new fair values were established for all AROs for the Successor. A liability is initially recorded at fair value for an asset retirement obligation associated with the legal obligation associated with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets in the period in which it is incurred if a fair value is reasonably estimable. Generally, changes in estimates related to ARO obligations are recorded as increases or decreases to the liability and related asset as information becomes available. Changes in estimates related to assets that have been retired or for which capitalized costs are not recoverable are reflected in income.

During the year ended December 31, 2017, we recorded additional ARO obligations totaling $112 million primarily reflecting the acceleration of ARO obligations due to the retirements of our Monticello, Sandow and Big Brown plants. In addition, we recorded additional ARO obligations totaling $62 million as part of acquiring certain real property through the Alcoa contract settlement.

See Note 21 to the Financial Statements for additional discussion of ARO obligations.

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Impairment of Goodwill and Other Long-Lived Assets

We evaluate long-lived assets (including intangible assets with finite lives) for impairment, in accordance with accounting standards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. For our generation assets, possible indications include an expectation of continuing long-term declines in natural gas prices and/or market heat rates or an expectation that "more likely than not" a generation asset will be sold or otherwise disposed of significantly before the end of its estimated useful life. The determination of the existence of these and other indications of impairment involves judgments that are subjective in nature and may require the use of estimates in forecasting future results and cash flows related to an asset or group of assets. Further, the unique nature of our property, plant and equipment, which includes a fleet of generation assets with a diverse fuel mix and individual generation units that have varying production or output rates, requires the use of significant judgments in determining the existence of impairment indications and the grouping of assets for impairment testing. We generally utilize an income approach measurement to derive fair values for our long-lived generation assets. The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity prices, market heat rates, the effects of environmental rules, generation plant performance, forecasted capital expenditures and forecasted fuel prices. Any significant change to one or more of these factors can have a material impact on the fair value measurement of our long-lived assets. As a result of the decrease in forecasted wholesale electricity prices, potential effects from environmental regulations and changes to our Predecessor's operating plans in 2015 and 2014, our Predecessor evaluated the recoverability of its generation assets. See Note 4 to the Financial Statements for a discussion of the impairment charges related to certain of those assets. Additional material impairments related to these or other of our generation facilities may occur in the future if forward wholesale electricity prices in ERCOT decline or if additional environmental regulations increase the cost of producing electricity at our generation facilities.

Goodwill and intangible assets with indefinite useful lives, such as the intangible asset related to the TXU Energy^TM brand, are required to be tested for impairment at least annually (as of the Effective Date, we have selected October 1 as our annual test date) or whenever events or changes in circumstances indicate an impairment may exist, such as the indicators used to evaluate impairments to long-lived assets discussed above or declines in values of comparable public companies in our industry. Accounting guidance requires goodwill to be allocated to our reporting units, and at December 31, 2017 all goodwill was allocated to our Retail Electricity reporting unit. Goodwill impairment testing is performed at the reporting unit level. Under this goodwill impairment analysis, if at the assessment date, a reporting unit's carrying value exceeds its estimated fair value (enterprise value), the estimated enterprise value of the reporting unit is compared to the estimated fair values of the reporting unit's assets (including identifiable intangible assets) and liabilities at the assessment date, and the resultant implied goodwill amount is then compared to the recorded goodwill amount. Any excess of the recorded goodwill amount over the implied goodwill amount is written off as an impairment charge.

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

See Note 7 to the Financial Statements for additional discussion of the Predecessor's goodwill impairment charges.

10

RESULTS OF OPERATIONS

Vistra Energy Consolidated Financial Results — Year Ended December 31, 2017

	Successor
	Year Ended December 31, 2017
	Wholesale Generation			Retail Electricity			Asset Closure			Eliminations / Corporate and Other			Vistra Energy Consolidated
Operating revenues	$	1,794		$	4,058		$	964		$	(1,386	)	$	5,430
Fuel, purchased power costs and delivery fees	(981		)	(2,733		)	(607		)	1,386			(2,935		)
Operating costs	(578		)	(14		)	(380		)	(1		)	(973		)
Depreciation and amortization (a)	(229		)	(430		)	(1		)	(39		)	(699		)
Selling, general and administrative expenses	(124		)	(420		)	(19		)	(37		)	(600		)
Impairment of long-lived assets	—			—			(25		)	—			(25		)
Operating income (loss)	(118		)	461			(68		)	(77		)	198
Other income	24			34			6			(27		)	37
Other deductions	(3		)	—			(1		)	(1		)	(5		)
Interest expense and related charges	(21		)	—			—			(172		)	(193		)
Impacts of Tax Receivable Agreement	—			—			—			213			213
Income before income taxes	$	(118	)	$	495		$	(63	)	$	(64	)	250
Income tax expense										(504		)	(504		)
Net loss										$	(568	)	$	(254	)

____________

(a) Vistra Energy consolidated depreciation and amortization expense does not include $136 million of nuclear fuel amortization, reported as fuel costs, and intangible net assets and liabilities amortization, reported in various other line items including operating revenues and fuel and purchased power costs and delivery fees.

For the year ended December 31, 2017, consolidated operating income totaled $198 million and reflected strong operating performance in our Wholesale Generation and Retail Electricity segments despite an unplanned outage at one of our nuclear generation units and mild weather in both the summer and winter seasons. In addition, several strategic actions were announced during 2017, including the retirements of our Monticello, Sandow and Big Brown plants, the settlement of the Alcoa contract and the Merger Agreement with Dynegy. Operating income was reduced by $835 million in depreciation and amortization expense, $206 million in charges related to the plant retirement announcements and $116 million in unrealized mark-to-market losses on commodity risk management activity and interest rate swaps. Segment operating results were driven by:

• Our Wholesale Generation segment had strong operating performance from our generation fleet during the peak summer operating months, which was offset by unrealized mark-to-market losses on commodity risk management activities totaling $317 million for the period (including $154 million of unrealized losses on positions with the Retail Electricity segment), resulting in an operating loss of $118 million for the period. The unrealized losses were driven by the impacts of the reversal of previously recorded unrealized gains on settled positions and an increase in forward power prices, partially offset by unrealized gains due to a decrease in forward natural gas prices during the period. Operating loss also includes $319 million in depreciation and amortization expense, including nuclear fuel amortization. Additionally, operating loss includes a $74 million unfavorable impact due to an unplanned outage at one of our nuclear generation units that began in June 2017 ($57 million of lower earnings due to lost generation and $17 million of additional operating costs). The outage required repairs to the plant's steam turbine generator, a standard component in all power stations that is unrelated to Comanche Peak's nuclear reactor, which was not impacted by the outage. The unit returned to service in August 2017. Please see the discussion of Wholesale Generation below for further details.

• Our Retail Electricity segment had operating income of $461 million for the period, which was primarily driven by favorable profit margins and $154 million of unrealized gains in purchased power costs on positions with the Wholesale Generation segment, partially offset by $476 million in depreciation and amortization expense reflecting amortization expense related to retail customer relationship and retail contracts intangible assets. Please see the discussion of Retail Electricity below for further details.

• Our Asset Closure segment had an operating loss of $68 million for the period. Please see the Asset Closure segment financial results below for further details.

11

• Net operating expense related to Eliminations and Corporate and Other activities totaled $77 million and primarily reflected amortization of software and other technology-related assets (see Note 7 to the Financial Statements) and rent expense.

Interest expense and related charges totaled $193 million and included $213 million of interest expense incurred, partially offset by $29 million of unrealized mark-to-market gains on interest rate swaps (see Note 10 to the Financial Statements).

The Impacts of the Tax Receivable Agreement were income of $213 million, which includes a $295 million gain due to changes in the estimated amount and timing of TRA payments. See Note 9 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement obligation.

Income tax expense totaled $504 million. The effective tax rate of 201.6% was higher than the U.S. Federal statutory rate of 35% primarily due to a $451 million reduction of deferred tax assets related to the decrease in the corporate tax rate in the TCJA, partially offset by $80 million of tax impacts related to nondeductible TRA accretion. See Note 8 to the Financial Statements for reconciliation of this effective rate to the U.S. federal statutory rate.

Our total net loss of $254 million reflected the tax effects of the TCJA and the TRA obligation, as well as the items impacting operating income listed above.

Vistra Energy Consolidated Financial Results — Period from October 3, 2016 through December 31, 2016

	Successor
	Period from October 3, 2016 through December 31, 2016
	Wholesale Generation			Retail Electricity			Asset Closure			Eliminations / Corporate and Other			Vistra Energy Consolidated
Operating revenues	$	212		$	912		$	238		$	(171	)	$	1,191
Fuel, purchased power costs and delivery fees	(214		)	(515		)	(162		)	171			(720		)
Operating costs	(151		)	(3		)	(54		)	—			(208		)
Depreciation and amortization (a)	(53		)	(153		)	—			(10		)	(216		)
Selling, general and administrative expenses	(65		)	(130		)	(6		)	(7		)	(208		)
Operating income (loss)	(271		)	111			16			(17		)	(161		)
Other income	2			3			1			4			10
Other deductions	—			—			—			—			—
Interest expense and related charges	1			—			—			(61		)	(60		)
Impacts of Tax Receivable Agreement	—			—			—			(22		)	(22		)
Income (loss) before income taxes	$	(268	)	$	114		$	17		(96		)	(233		)
Income tax benefit										70			70
Net loss										$	(26	)	$	(163	)

____________

(a) Vistra Energy consolidated depreciation and amortization expense does not include $69 million of nuclear fuel amortization, reported as fuel costs, and intangible net assets and liabilities amortization, reported in various other line items including operating revenues and fuel and purchased power costs and delivery fees.

12

Consolidated operating loss totaled $161 million for the period from October 3, 2016 through December 31, 2016. Results were driven by:

• Our Wholesale Generation segment had an operating loss of $271 million for the period, which was primarily driven by unrealized mark-to-market losses on commodity risk management activities totaling $273 million for the period (including $113 million of unrealized losses on positions with the Retail Electricity segment and $22 million of unrealized gains on hedging activities for fuel and purchased power costs). The unrealized losses were driven by increases in forward natural gas prices during the period. Please see the discussion of Wholesale Generation below for further details.

• Our Retail Electricity segment had an operating income of $111 million for the period, which was primarily driven by favorable profit margins, including $113 million of unrealized gains in purchased power costs on positions with the Wholesale Generation segment. Please see the discussion of Retail Electricity below for further details.

• Our Asset Closure segment had operating income of $16 million for the period. Please see the Asset Closure segment financial results below for further details.

• Net operating expense related to Eliminations and Corporate and Other activities totaled $17 million and primarily reflected $7 million in amortization of software and other technology-related assets (see Note 7 to the Financial Statements) and $4 million of post-Emergence restructuring fees.

Interest expense and related charges totaled $60 million and reflected $51 million of interest expense incurred and $11 million of unrealized mark-to-market losses on interest rate swaps (see Note 10 to the Financial Statements).

Impacts of the Tax Receivable Agreement were a loss of $22 million, which reflected accretion expense during the period. See Note 9 to the Financial Statements for discussion of the impacts of the Tax Receivable Agreement obligation.

Income tax benefit totaled $70 million. The effective tax rate was 30.0%. See Note 8 to the Financial Statements for reconciliation of this effective rate to the U.S. federal statutory rate.

Operating Income

We evaluate our segment performance using operating income as an earnings metric. We believe operating income is useful in evaluating our core business activities and is one of the metrics used by our chief operating decision maker and leadership to evaluate segment results. Operating income excludes interest income, interest expense and related charges, impacts of the Tax Receivables Agreement and income tax expense as these activities are managed at the corporate level.

13

Operating Statistics — Year Ended December 31, 2017 and Period from October 3, 2016 through December 31, 2016

	Successor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Sales volumes (GWh):
Retail electricity sales volumes:
Residential	20,536			4,485
Business markets	18,496			4,430
Total retail electricity sales volumes	39,032			8,915
Wholesale electricity sales volumes (a)	48,578			13,806
Production volumes (GWh):
Nuclear facilities	16,921			5,373
Lignite and coal facilities (Wholesale Generation segment)	26,043			6,924
Lignite and coal facilities (Asset Closure segment)	25,392			6,730
Natural gas facilities	18,522			3,138
Capacity factors:
Nuclear facilities	84.0		%	105.7		%
Lignite and coal facilities (Wholesale Generation segment)	77.2		%	81.4		%
Lignite and coal facilities (Asset Closure segment)	69.6		%	73.1		%
CCGT facilities	69.3		%	47.0		%
Market pricing:
Average ERCOT North power price ($/MWh)	$	23.26		$	26.52
Weather (North Texas average) - percent of normal (b):
Cooling degree days	99.1		%	149.2		%
Heating degree days	72.1		%	79.5		%

____________

(a) Includes net amounts related to sales and purchases of balancing energy in the ERCOT real-time market.

(b) Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the U.S. Department of Commerce). Normal is defined as the average over the 10-year period from 2006 to 2015 for the year ended December 31, 2017 and 2001 to 2010 for the period from October 3, 2016 through December 31, 2016.

Wholesale Generation Segment Financial Results — Year Ended December 31, 2017 and Period from October 3, 2016 through December 31, 2016

For the year ended December 31, 2017, wholesale electricity revenues totaled $1.794 billion and included:

• $372 million in third-party wholesale electricity revenue, which included $523 million in electricity sales to third parties, including revenues from the Odessa power generation facility acquired in August 2017 (see Note 3 to the Financial Statements), and $151 million in unrealized losses from hedging activities reflecting the reversal of previously recorded unrealized gains on settled power positions and an increase in forward power prices, partially offset by unrealized gains due to a decrease in forward natural gas prices, and

• $1.385 billion in affiliated revenue with the Retail Electricity segment, which included $1.539 billion in sales for the period and $154 million in unrealized losses on hedging activities with affiliate positions reflecting an increase in forward power prices.

14

For the period from October 3, 2016 through December 31, 2016, wholesale electricity revenues totaled $212 million and included:

• $36 million in third-party wholesale electricity revenue, which included $218 million in electricity sales to third parties, partially offset by $182 million in unrealized losses from hedging activities reflecting an increase in forward natural gas prices and by the reversal of previously recorded unrealized gains on settled power positions, and

• $171 million in affiliated revenue with the Retail Electricity segment, which included $284 million in sales for the period, partially offset by $113 million in unrealized losses on hedging activities with affiliate positions reflecting an increase in forward commodity prices.

For the year ended December 31, 2017, wholesale electricity sales and operating costs include unfavorable impacts totaling $74 million due to an unplanned outage at one of our nuclear generation units that began in June 2017.

	Successor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Wholesale electricity sales	$	523		$	218
Unrealized net (losses) on hedging activities	(151		)	(182		)
Sales to affiliates	1,539			284
Unrealized net (losses) on hedging activities with affiliates	(154		)	(113		)
Other revenues	37			5
Total wholesale electricity revenues	$	1,794		$	212

For the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016, fuel, purchased power costs and delivery fees totaled $981 million and $214 million, respectively, and primarily reflected fuel and purchased power costs and ancillary and other costs. For the year ended December 31, 2017, fuel expense for our nuclear facilities was lower due to an unplanned outage at one of our units. For the year ended December 31, 2017, fuel expense for our natural gas facilities reflected incremental costs related to the Odessa Acquisition (see Note 3 to the Financial Statements). For the year ended December 31, 2017, fuel and purchased power costs also included $12 million in unrealized losses from hedging activities reflecting reversal of previously recorded unrealized gains on settled coal and diesel positions. For the period from October 3, 2016 through December 31, 2016, fuel and purchased power costs also included $22 million in unrealized gains from hedging activities reflecting gains on coal and diesel hedges due to increases in forward prices.

Operating costs totaled $578 million and $151 million for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016, respectively, and reflected operations and maintenance expenses for power generation facilities and salaries and benefits for facilities personnel. For the year ended December 31, 2017, operating costs for our nuclear facilities were impacted by an unplanned outage at one of our units as well as refueling both units during the year, which occurs every three years. For the year ended December 31, 2017, operating costs for our natural gas facilities reflected the Odessa Acquisition.

For the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016, depreciation and amortization expenses totaled $229 million and $53 million, respectively, and primarily reflected depreciation on power generation and mining property, plant and equipment.

For the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016, SG&A totaled $124 million and $65 million, respectively, and primarily reflected functional group service costs allocated from Corporate and Other activities. SG&A costs reflect a workforce reduction in October 2016 that better aligned our cost structure, particularly as it relates to support functions within the business, to current market conditions.

Retail Electricity Segment Financial Results — Year Ended December 31, 2017 and Period from October 3, 2016 through December 31, 2016

For the year ended December 31, 2017, retail electricity revenues totaled $4.058 billion and included $3.916 billion related to 39,032 GWh in sales volumes. During the period, revenues were unfavorably impacted by mild weather in both the peak summer cooling period and the winter season at the beginning of the year as noted in the weather information included above in our Operating Statistics.

15

For the period from October 3, 2016 through December 31, 2016, retail electricity revenues totaled $912 million and included $907 million related to 8,915 GWh in sales volumes. Sales volumes for the period were evenly split between residential and business market customers.

	Successor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Retail electricity sales	$	3,916		$	907
Amortization income (expense) of identifiable intangible assets related to retail contracts (see Note 7 to the Financial Statements)	(46		)	(36		)
Other revenues	188			41
Total retail electricity revenues	$	4,058		$	912

Purchased power costs, delivery fees and other costs totaled $2.733 billion and $515 million for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016, respectively, and reflected the following:

	Successor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016
Purchases from affiliates	$	1,539		$	284
Unrealized net gains on hedging activities with affiliates	(154		)	(113		)
Delivery fees	1,345			320
Other costs	3			24
Total purchased power costs and delivery fees	$	2,733		$	515

Depreciation and amortization expenses totaled $430 million and $153 million for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016, respectively, and primarily reflected the impacts of amortization expense related to the retail customer relationship intangible asset established in fresh start reporting (see Note 7 to the Financial Statements).

SG&A totaled $420 million and $130 million for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016, respectively, and reflected employee compensation and benefit costs (including functional group costs allocated from Corporate and Other), marketing and operation expenses and bad debt expense. SG&A costs reflect a workforce reduction in October 2016 that better aligned our cost structure, particularly as it relates to support functions within the business, to current market conditions. For the year ended December 31, 2017, SG&A reflects an increase in bad debt expense as a result of the estimated impact on collectability from customers affected by Hurricane Harvey.

Asset Closure Segment Financial Results — Year Ended December 31, 2017 and Period from October 3, 2016 through December 31, 2016

Results for the Asset Closure segment include the Monticello, Sandow and Big Brown plants that were retired in January and February 2018. For the year ended December 31, 2017, operating loss totaled $68 million related to production volumes of 25,392 GWh. Operating loss in 2017 includes a charge of $206 million related to the plant retirement announcements, including (i) $170 million of operating costs related to severance accruals, write-off of material and supplies inventory and changes to estimates and timing of asset retirement obligations and (ii) $25 million of impairments of long-lived assets related to the write-off of capitalized improvements of our Sandow 4 generation facility. For the period from October 3, 2016 through December 31, 2016, operating revenues totaled $16 million related to production volumes of 6,730 GWh.

16

Predecessor Consolidated Financial Results — Period from January 1, 2016 through October 2, 2016 and the Year Ended December 31, 2015

	Predecessor
	Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
Operating revenues	$	3,973		$	5,370
Fuel, purchased power costs and delivery fees	(2,082		)	(2,692		)
Net gain from commodity hedging and trading activities	282			334
Operating costs	(664		)	(834		)
Depreciation and amortization	(459		)	(852		)
Selling, general and administrative expenses	(482		)	(676		)
Impairment of goodwill	—			(2,200		)
Impairment of long-lived assets	—			(2,541		)
Operating income (loss)	568			(4,091		)
Other income	19			18
Other deductions	(75		)	(93		)
Interest expense and related charges	(1,049		)	(1,289		)
Reorganization items	22,121			(101		)
Income (loss) before income taxes	21,584			(5,556		)
Income tax benefit	1,267			879
Net income (loss)	$	22,851		$	(4,677	)

17

Predecessor Operating Statistics — Period from January 1, 2016 through October 2, 2016 and the Year Ended December 31, 2015

	Predecessor
	Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
Operating revenues:
Retail electricity revenues	$	3,154		$	4,449
Wholesale electricity revenues and other operating revenues (a)(b)	819			921
Total operating revenues	$	3,973		$	5,370
Fuel, purchased power costs and delivery fees:
Fuel for nuclear facilities	$	92		$	146
Fuel for lignite and coal facilities	548			736
Fuel for natural gas facilities and purchased power costs (a)	310			252
Other costs	108			166
Delivery fees	1,024			1,392
Total	$	2,082		$	2,692
Sales volumes:
Retail electricity sales volumes (GWh):
Residential	16,619			21,923
Business markets	14,354			19,289
Total retail electricity	30,973			41,212
Wholesale electricity sales volumes (b)	25,563			23,533
Production volumes (GWh):
Nuclear facilities	15,005			19,954
Lignite and coal facilities (c)	31,865			41,817
Natural gas facilities	8,539			709
Capacity factors:
Nuclear facilities	99.2		%	99.0		%
Lignite and coal facilities (c)	60.5		%	59.5		%
CCGT facilities	65.2		%	N/A
Market pricing:
Average ERCOT North power price ($/MWh)	$	20.78		$	23.78
Weather (North Texas average) - percent of normal (d):
Cooling degree days	102.8		%	105.4		%
Heating degree days	81.9		%	103.8		%

____________

(a) Upon settlement, physical derivative commodity contracts that we mark-to-market in net income, such as certain electricity sales and purchase agreements and coal purchase contracts, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, rather than contract price. The offsetting differences between contract and market prices are reported in net gain from commodity hedging and trading activities.

(b) Includes net amounts related to sales and purchases of balancing energy in the ERCOT real-time market.

(c) Includes the estimated effects of economic backdown (including seasonal operations) of lignite/coal-fueled units totaling 14,420 GWh and 19,900 GWh for the period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively.

(d) Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the U.S. Department of Commerce). Normal is defined as the average over the 10-year period from 2000 to 2010.

18

Predecessor Financial Results — Period from January 1, 2016 through October 2, 2016 and the Year Ended December 31, 2015

For the period from January 1, 2016 through October 2, 2016, income before income taxes totaled $21.584 billion and included a $24.252 billion gain on reorganization adjustments and a $2.013 billion loss for the net impacts from the adoption of fresh start reporting (see Notes 5 and 6 to the Financial Statements). Results also reflected the effect of declining average electricity prices on operating revenues, $977 million in adequate protection interest expense paid/accrued on pre-petition debt and $116 million in reorganization items associated with the Chapter 11 Cases. For the year ended December 31, 2015, loss before income taxes totaled $5.556 billion and primarily reflected noncash impairments of certain long-lived assets totaling $2.541 billion and of goodwill totaling $2.2 billion.

Operating revenues totaled $3.973 billion and $5.370 billion for the period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively.

• For the period from January 1, 2016 through October 2, 2016, retail electricity revenues totaled $3.154 billion and were negatively impacted by declining average prices and reduced volumes reflecting milder than normal weather in 2016. Wholesale revenues totaled $649 million and were positively impacted by increases in generation volumes (approximately 8,048 GWh) driven by the Lamar and Forney generation assets acquired in April 2016 (see Note 3 to the Financial Statements), partially offset by lower average wholesale electricity prices.

• For the year ended December 31, 2015, retail electricity revenues totaled $4.449 billion and were favorably impacted by increased sales volumes driven by increased business volumes, partially offset by lower average retail prices primarily for business market customers. Wholesale revenues totaled $680 million and were negatively impacted by decreases in generation volumes driven by increased economic backdown (including seasonal operations) at lignite and coal generation facilities driven by a decline in wholesale electricity prices.

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

	Predecessor
	Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
Realized net gains	$	320		$	217
Unrealized net gains (losses)	(38		)	117
Total	$	282		$	334

For both periods presented, the negative impacts of declining average prices on wholesale operating revenues were partially offset by realized net gains reflecting settled gains on derivatives due to declining market prices. These gains were primarily related to natural gas positions.

For the period from January 1, 2016 through October 2, 2016, net unrealized losses were primarily impacted by reversals of previously recorded unrealized net gains on settled positions. For the year ended December 31, 2015, net unrealized gains were primarily impacted by the impact of declining natural gas prices on our Predecessor's hedging program.

Fuel, purchased power costs and delivery fees totaled $2.082 billion and $2.692 billion for the period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively. For the period from January 1, 2016 through October 2, 2016, fuel, purchased power costs and delivery fees reflected the impact of declining electricity prices on purchased power costs during 2016, partially offset by incremental natural gas fuel costs associated with the Lamar and Forney Acquisition.

Operating costs totaled $664 million and $834 million for the period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively, and primarily reflect maintenance expense for generation assets, including the scope and timing of maintenance costs at lignite/coal-fueled generation facilities. For the period from January 1, 2016 through October 2, 2016, operating costs were also impacted by incremental operation and maintenance costs associated with the Lamar and Forney Acquisition.

19

Depreciation and amortization expenses totaled $459 million and $852 million for the period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively. primarily reflected depreciation on power generation and mining property, plant and equipment and amortization of identifiable intangible assets. For the period from January 1, 2016 through October 2, 2016, depreciation and amortization expenses were also impacted by incremental depreciation expense associated with the Lamar and Forney Acquisition.

SG&A expenses totaled $482 million and $676 million for the period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively, and reflected administrative and general salaries, employee benefits, marketing costs related to retail electricity activity and other administrative costs.

For the period from January 1, 2016 through October 2, 2016, results also include $32 million of severance expense, primarily reported in fuel, purchased power costs and delivery fees and operating costs, associated with certain actions taken to reduce costs related to mining and lignite/coal generation operations.

For the period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, interest expense and related charges totaled $1.049 billion and $1.289 billion, respectively, and included adequate protection payments approved by the Bankruptcy Court for the benefit of TCEH secured creditors totaling $977 million and $1.233 billion, respectively, and interest expense on debtor-in-possession financing totaling $76 million and $63 million, respectively.

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

The table below summarizes the changes in commodity contract assets and liabilities for the periods presented. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $145 million and $166 million in unrealized net losses for the Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016, respectively, and $38 million in unrealized net losses and $117 million in unrealized net gains for the Predecessor period from January 1, 2016 through October 2, 2016 and the year ended December 31, 2015, respectively, all arising from mark-to-market accounting for positions in the commodity contract portfolio.

	Successor						Predecessor
	Year Ended December 31, 2017			Period from October 3, 2016 through December 31, 2016			Period from January 1, 2016 through October 2, 2016			Year Ended December 31, 2015
Commodity contract net asset at beginning of period	$	64		$	181		$	271		$	180
Settlements/termination of positions (a)	(207		)	(95		)	(232		)	(263		)
Changes in fair value of positions in the portfolio (b)	62			(71		)	194			380
Other activity (c)	(15		)	49			(35		)	(26		)
Commodity contract net asset (liability) at end of period	$	(96	)	$	64		$	198		$	271

____________

(a) Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). The Successor period for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016 includes reversal of $63 million and $90 million, respectively, of previously recorded unrealized gains related to Vistra Energy beginning balances. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.

(b) Represents unrealized net gains (losses) recognized, reflecting the effect of changes in fair value. The Successor period for the year ended December 31, 2017 includes a $23 million inception gain related to long-term power derivatives. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.

(c) Represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses. Amounts are generally related to certain margin deposits classified as settlement for certain transactions executed on the CME as well as premiums related to options purchased or sold and the initial fair value of the earn-out provision related to the Odessa Acquisition (see Note 3 to the Financial Statements). The Predecessor period from January 1, 2016 through October 2, 2016 includes fair value of acquired commodity contracts as of the date of the Lamar and Forney Acquisition (see Note 3 to the Financial Statements).

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Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair values at December 31, 2017, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

	Successor
	Maturity dates of unrealized commodity contract net liability at December 31, 2017
Source of fair value	Less than 1 year			1-3 years			4-5 years			Excess of 5 years		Total
Prices actively quoted	$	11		$	(9	)	$	—		$	—	$	2
Prices provided by other external sources	(12		)	(33		)	—			—		(45		)
Prices based on models	(16		)	(45		)	(1		)	9		(53		)
Total	$	(17	)	$	(87	)	$	(1	)	$	9	$	(96	)

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FINANCIAL CONDITION

Operating Cash Flows

Successor— Year Ended December 31, 2017 — Cash provided by operating activities totaled $1.386 billion in 2017 and was primarily driven by $1.168 billion of cash from operations, $238 million in proceeds from the Alcoa contract settlement and a $146 million net source of cash reflecting decreases in cash utilized in margin postings related to derivative contracts.

Period from October 3, 2016 through December 31, 2016 — Cash provided by operating activities totaled $81 million and was primarily driven by cash earnings from our business of approximately $251 million after taking into consideration depreciation and amortization and unrealized mark-to-market losses on derivatives, offset by a net use of cash of approximately $170 million in working capital primarily driven by cash utilized in margin postings related to derivative contracts.

Depreciation and Amortization — Depreciation and amortization expense reported as a reconciling adjustment in the statements of consolidated cash flows exceed the amount reported in the statements of consolidated income (loss) by $136 million and $69 million for the year ended December 31, 2017 and the period from October 3, 2016 through December 31, 2016, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the statements of consolidated income (loss) consistent with industry practice, and amortization of intangible net assets and liabilities that are reported in various other statements of consolidated income (loss) line items including operating revenues and fuel and purchased power costs and delivery fees.

Predecessor— Period from January 1, 2016 through October 2, 2016 — Cash used in operating activities totaled $238 million and was primarily driven by cash used for margin deposit postings and other working capital utilization.

Year Ended December 31, 2015 — Cash provided by operating activities totaled $237 million in 2015 and was primarily driven by cash used for margin deposit postings and other working capital utilization.

Financing Cash Flows

Successor— Year Ended December 31, 2017 — Cash used in financing activities totaled $201 million in 2017 and reflected the repayment of debt, including the repayment of $150 million in principal under the Term Loan C Facility (see Note 12 to the Financial Statements).

Period from October 3, 2016 through December 31, 2016 — Cash provided by financing activities totaled $6 million and related to the net impacts of the Incremental Term Loan B borrowings and the Special Dividend paid to shareholders.

Predecessor— Period from January 1, 2016 through October 2, 2016 — Cash provided by financing activities totaled $1.059 billion and primarily reflected $2.040 billion in net borrowings under the DIP Roll Facilities and the DIP Facility, including $870 million in net borrowings to fund the Lamar and Forney Acquisition (see Note 3 to the Financial Statements), and $69 million from the issuance of preferred stock, partially offset by $915 million in payments to extinguish claims under the Plan of Reorganization and $112 million in fees related to the issuance of the DIP Roll Facilities.

Year Ended December 31, 2015 — Cash used in financing activities totaled $30 million and reflected the repayments of certain debt principal and fees.

Investing Cash Flows

Successor— Year Ended December 31, 2017 — Cash used in investing activities totaled $727 million in 2017 and reflected payments of $355 million related to the Odessa Acquisition, Upton solar development expenditures totaling $190 million and capital expenditures (including nuclear fuel purchases) totaling $176 million. The Odessa Acquisition and the Upton solar development were funded using cash on hand.

Capital expenditures, including nuclear fuel, in the year ended December 31, 2017 totaled $176 million and consisted of:

• $74 million primarily for our generation operations;

• $14 million for environmental expenditures related to generation units;

• $62 million for nuclear fuel purchases, and

• $26 million for information technology and other corporate investments.

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Period from October 3, 2016 through December 31, 2016 — Cash used in investing activities totaled $93 million and was primarily driven by capital expenditures of $48 million and purchases of nuclear fuel of $41 million.

Capital expenditures, including nuclear fuel, in the period from October 3, 2016 through December 31, 2016 totaled $89 million and consisted of:

• $18 million primarily for our generation operations;

• $22 million for environmental expenditures related to generation units;

• $41 million for nuclear fuel purchases, and

• $8 million for information technology and other corporate investments.

Predecessor— Period from January 1, 2016 through October 2, 2016 — Cash used in investing activities totaled $1.420 billion. Cash used reflected payments of $1.343 billion related to the Lamar and Forney Acquisition net of cash acquired (see Note 3 to the Financial Statements) and capital expenditures (including nuclear fuel purchases) totaling $263 million, partially offset by a $233 million decrease in restricted cash used to backstop letters of credit.

Capital expenditures, including nuclear fuel, in the period from January 1, 2016 through October 2, 2016 totaled $263 million and consisted of:

• $171 million primarily for our generation operations;

• $40 million for environmental expenditures related to generation units;

• $33 million for nuclear fuel purchases, and

• $19 million for information technology and other corporate investments.

Year Ended December 31, 2015 — Cash used in investing activities totaled $650 million and reflected capital expenditures (including nuclear fuel purchases) totaling $460 million and a $123 million increase in restricted cash largely for supporting letters of credit issued under the DIP Facility.

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

• $230 million primarily for our generation operations;

• $82 million for environmental expenditures related to generation units;

• $123 million for nuclear fuel purchases, and

• $25 million for information technology and other corporate investments.

Debt Activity

See Note 12 to the Financial Statements for details of the Vistra Operations Credit Facilities and other long-term debt.

Available Liquidity

The following table summarizes changes in available liquidity for the year ended December 31, 2017:

	December 31, 2017		December 31, 2016		Change
Cash and cash equivalents (a)	$	1,487	$	843	$	644
Vistra Operations Credit Facilities — Revolving Credit Facility	834		860		(26		)
Vistra Operations Credit Facilities — Term Loan C Facility (b)	7		131		(124		)
Total liquidity	$	2,328	$	1,834	$	494

___________

(a) Cash and cash equivalents excludes $500 million and $650 million of restricted cash held for letter of credit support at December 31, 2017 and 2016, respectively (see Note 21 to the Financial Statements).

(b) The Term Loan C Facility is used for issuing letters of credit for general corporate purposes. Borrowings totaling $500 million and $650 million under this facility were held in collateral accounts at December 31, 2017 and 2016, respectively, and are reported as restricted cash in our consolidated balance sheets. The December 31, 2017 restricted cash balance represents borrowings under the Term Loan C Facility held in collateral accounts that support $493 million in letters of credit outstanding, leaving $7 million in available letter of credit capacity (see Note 12 to the Financial Statements).

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The increase in available liquidity of $494 million in the year ended December 31, 2017 compared to December 31, 2016 was primarily driven by increased available cash from operations, partially offset by the repayment of $150 million in principal under the Term Loan C Facility and cash utilized in the Odessa Acquisition and our development of the Upton solar facility.

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

Capital Expenditures

Estimated capital expenditures and nuclear fuel purchases for 2018 are expected to total approximately $396 million and include:

• $248 million for investments in generation and mining facilities, including approximately:

• $231 million primarily for our generation operations and

• $17 million for environmental expenditures,

• $118 million for nuclear fuel purchases, and

• $30 million for information technology and other corporate investments.

Liquidity Effects of Commodity Hedging and Trading Activities

We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. We use cash, letters of credit and other forms of credit support to satisfy such collateral posting obligations. See Note 12 to the Financial Statements for discussion of the Vistra Operations Credit Facilities.

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

At December 31, 2017, we received or posted cash and letters of credit for commodity hedging and trading activities as follows:

• $30 million in cash has been posted with counterparties as compared to $213 million posted at December 31, 2016;

• $4 million in cash has been received from counterparties as compared to $41 million received at December 31, 2016;

• $390 million in letters of credit have been posted with counterparties as compared to $363 million posted at December 31, 2016, and

• $3 million in letters of credit have been received from counterparties as compared to $10 million received at December 31, 2016.

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Income Tax Matters

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

The TCEH Debtors and the Contributed EFH Debtors emerged from the Chapter 11 Cases on the Effective Date in a tax-free spin-off from EFH Corp that was part of a series of transactions that included a taxable component, which generated a taxable gain that was offset with available net operating losses (NOLs) of EFH Corp., substantially reducing the NOLs available to EFH Corp. in the future. As a result of the use of the NOLs, the taxable portion of the transaction resulted in no regular tax liability due and approximately $14 million of alternative minimum tax, payable to the IRS by EFH Corp. Pursuant to the Tax Matters Agreement, Vistra Energy had an obligation to reimburse EFH Corp. 50% of the alternative minimum tax, and approximately $7 million was reimbursed during the three months ended June 30, 2017. In October 2017, the 2016 federal tax return that included the results of EFCH, EFIH, Oncor Holdings and TCEH was filed with the IRS and resulted in $3 million payment from EFH Corp to Vistra Energy.

Income Tax Payments — In the next 12 months, we expect to make federal income tax payments of approximately $40 million, which represents Vistra Energy's remaining estimated 2017 federal income tax liability. We also expect to make Texas margin tax payments of approximately $14 million in the next 12 months. For the year ended December 31, 2017, federal income tax payments totaled $41 million and Texas margin tax payments totaled $22 million.

Capitalization

At both December 31, 2017 and 2016, our capitalization ratios consisted of 41% borrowing under the Vistra Energy Operations Facilities and other long-term debt (less amounts due currently) and 59% shareholders' equity. Total borrowings under the Vistra Energy Operations Facilities and other long-term debt to capitalization was 41% at both December 31, 2017 and 2016.

Financial Covenants

The agreement governing the Vistra Operations Credit Facilities includes a covenant, solely with respect to the Revolving Credit Facility and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $100 million) exceed 30% of the revolving commitments), that requires the consolidated first lien net leverage ratio not exceed 4.25 to 1.00. Although the period ended December 31, 2017 was not a compliance period, we would have been in compliance with this financial covenant if it was required to be tested at such date.

See Note 12 to the Financial Statements for discussion of other covenants related to the Vistra Operations Credit Facilities.

Collateral Support Obligations

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

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The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, at December 31, 2017, Vistra Energy has posted letters of credit in the amount of $55 million with the PUCT, which is subject to adjustments.

ERCOT has rules in place to assure adequate creditworthiness of parties that participate in the day-ahead, real-time and congestion revenue rights markets operated by ERCOT. Under these rules, Vistra Energy has posted collateral support totaling $110 million in the form of letters of credit and $15 million in cash at December 31, 2017 (which is subject to daily adjustments based on settlement activity with ERCOT).

Material Cross Default/Acceleration Provisions

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

A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of $300 million may result in a cross default under the Vistra Operations Credit Facilities. Such a default would allow the lenders to accelerate the maturity of outstanding balances (approximately $4.3 billion at December 31, 2017) under such facilities.

Each of Vistra Operations' (or its subsidiaries') commodity hedging agreements and interest rate swap agreements that are secured with a lien on its assets on a pari passu basis with the Vistra Operations Credit Facilities lenders contains a cross default provision. An event of a default by Vistra Operations or any of its subsidiaries relating to indebtedness in excess of $300 million that results in the acceleration of such debt, would give each counterparty under these hedging agreements the right to terminate its hedge or interest rate swap agreement with Vistra Operations (or its applicable subsidiary) and require all outstanding obligations under such agreement to be settled.

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

Contractual Obligations and Commitments

The following table summarizes the amounts and related maturities of our contractual cash obligations at December 31, 2017. See Notes 12 and 13 to the Financial Statements for additional disclosures regarding these debts and noncancellable purchase obligations.

Contractual Cash Obligations:	Less Than One Year		One to Three Years		Three to Five Years		More Than Five Years		Total
Debt – principal, including capital leases (a)	$	44	$	88	$	87	$	4,189	$	4,408
Debt – interest	197		389		382		147		1,115
Operating leases	17		27		18		150		212
Obligations under commodity purchase and services agreements (b)	520		368		316		582		1,786
Total contractual cash obligations	$	778	$	872	$	803	$	5,068	$	7,521

___________

(a) Includes $4.311 billion of borrowings under the Vistra Operations Credit Facility and $97 million principal amount of long-term debt, including mandatorily redeemable preferred stock and capital leases. Excludes unamortized premiums, discounts and debt costs.

(b) Includes a long-term service and maintenance contract related to our generation assets, capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear related outsourcing and other purchase commitments. Amounts presented for variable priced contracts reflect the year-end 2017 price for all periods except where contractual price adjustment or index-based prices are specified.

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The following are not included in the table above:

• the TRA obligation (see Note 9 to the Financial Statements);

• arrangements between affiliated entities and intercompany debt (see Note 19 to the Financial Statements);

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

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

• employment contracts with management.

Guarantees

See Note 13 to the Financial Statements for discussion of guarantees.

OFF–BALANCE SHEET ARRANGEMENTS

We do not have any off-balance sheet arrangements.

COMMITMENTS AND CONTINGENCIES

See Note 13 to the Financial Statements for discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

See Note 1 to the Financial Statements for discussion of changes in accounting standards.

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