Vistra Corp. 10-K

Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The discussion below, as well as other portions of this annual report on Form 10-K, contain forward-looking statements within the meaning of Section 27A of the Securities Act, Section 21E of the Exchange Act and the Private Securities Litigation Reform Act of 1995. In addition, management may make forward-looking statements orally or in other writing, including, but not limited to, in press releases, quarterly earnings calls, executive presentations, in the annual report to stockholders and in other filings with the SEC. Readers can usually identify these forward-looking statements by the use of such words as “may,” “will,” “should,” “likely,” “plans,” “projects,” “expects,” “anticipates,” “believes” or similar words. These statements involve a number of risks and uncertainties. Actual results could materially differ from those anticipated by such forward-looking statements. For more discussion about risk factors that could cause or contribute to such differences, see Part I, Item 1A "Risk Factors" and other risks discussed herein. Forward-looking statements reflect the information only as of the date on which they are made. The Company does not undertake any obligation to update any forward-looking statements to reflect future events, developments, or other information. If Vistra does update one or more forward-looking statements, no inference should be drawn that additional updates will be made regarding that statement or any other forward-looking statements. This discussion is intended to clarify and focus on our results of operations, certain changes in our financial position, liquidity, capital structure and business developments for the periods covered by the consolidated financial statements included under Part II, Item 8 of this annual report on Form 10-K for the year ended December 31, 2020. This discussion should be read in conjunction with those consolidated financial statements and the related notes and is qualified by reference to them. The following discussion and analysis of our financial condition and results of operations for the years ended December 31, 2020, 2019 and 2018 should be read in conjunction with our consolidated financial statements and the notes to those statements. Results are impacted by the effects of the Ambit Transaction, the Crius Transaction and the Merger (see Note 2 to the Financial Statements). The discussion and analysis of our financial condition and results of operations for the year ended December 31, 2018 and for the year ended December 31, 2019 compared to the year ended December 31, 2018 are included in Item 7. Management's Discussion and Analysis of Financial Condition and Results in our 2019 Form 10-K and is incorporated herein by reference except for the operational results from the former ERCOT, PJM, NY/NE and MISO segments that were replaced by the Texas, East, West and Sunset segments in an update of our reportable segments in the third quarter of 2020. Operational results for the Texas, East, West and Sunset segments for the year ended December 31, 2018 and for the year ended December 31, 2019 compared to the year ended December 31, 2018 are included in Results of Operations below to reflect this update of reportable segments. 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 is a holding company operating an integrated retail and electric power generation business primarily in markets throughout the U.S. Through our subsidiaries, we are engaged in competitive energy market activities including power generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity and natural gas to end users. Effective July 2, 2020, we changed our name from Vistra Energy Corp. to Vistra Corp. to distinguish from companies that are involved in the exploring for, producing, refining, or transporting fossil fuels (many of which use "energy" in their names) and to better reflect our integrated business model, which combines a retail electricity and natural gas business focused on serving its customers with new and innovative products and services and an electric power generation business powering the communities we serve with safe, reliable power. Operating Segments Vistra has six reportable segments: (i) Retail, (ii) Texas, (iii) East (iv) West, (v) Sunset and (vi) Asset Closure. In the third quarter of 2020, Vistra updated its reportable segments to reflect changes in how the Company's CODM makes operating decisions, assesses performance and allocates resources. Management believes that the revised reportable segments provide enhanced transparency into the Company's long-term sustainable assets and its commitment to managing the retirement of economically and environmentally challenged plants. See Notes 1 and 20 to the Financial Statements for further information concerning the updates to our reportable business segments. 51 Table of Contents Significant Activities and Events and Items Influencing Future Performance Winter Storm Uri In February 2021, the U.S. experienced an unprecedented winter storm Uri, bringing extreme cold temperatures to the central U.S., including Texas. On February 12, 2021, the Governor of Texas declared a state of disaster for all 254 counties in the State in response to the then-forecasted weather conditions. The declaration certified that severe winter weather posed an imminent threat due to prolonged freezing temperatures, heavy snow, and freezing rain statewide. On February 14, 2021, President Biden issued a federal emergency declaration for all 254 Texas counties. As part of its annual winter season preparations, our power plant teams executed a significant winter preparedness strategy, which included installing windbreaks and large radiant heaters to supplement existing freeze protection and insulation and performing preventative maintenance on freeze protection equipment such as the insulation and automatic circuitry designed to keep pipes at the power plants from freezing. In addition, in anticipation of winter storm Uri we took additional steps to prepare, including procuring additional demineralized water supply trailers to ensure sufficient water availability to run for extended periods and verifying that freeze protection circuits were operational. This severe weather resulted in surging demand for power, gas supply shortages, operational challenges for generators, and a significant load shed event ( i.e. , involuntary outages to customers across the system for varying periods of time) that was ordered by ERCOT beginning on February 15, 2021 and continuing through February 18, 2021. The biggest challenges to our plants throughout the storm were securing adequate natural gas supplies for our gas plants and the handling of frozen fuel at our coal plants. Despite these challenges, we estimate that our fleet generated approximately 25 to 30% of the power on the grid during the height of the outages, as compared to our approximately 18% market share. The overall financial impact from winter storm Uri is still being calculated, but Vistra expects it will have a material adverse impact on its financial results driven by generation output being constrained due to challenges with receiving a steady supply of fuel for some plants as well as challenges with handling fuel already on site given the freezing conditions. As a result of these challenges, Vistra had to procure power in the ERCOT market at prices at or near the price cap to meet its supply obligations. While the financial impacts of winter storm Uri to Vistra are not yet finalized, Vistra management preliminarily estimates the one-time adverse impact on pre-tax net income will be in the range of approximately $900 million to $1.3 billion. This estimated range is preliminary and based on currently available information and management estimates. The final amount of the estimated loss is subject to a variety of factors including, but not limited to, outstanding pricing, load, and settlement data from ERCOT (which is released at various intervals during a period of up to 180 days after the transaction day); the outcome of potential litigation arising from this event (including any litigation that we may pursue or be a party to); or any corrective action taken by the State of Texas, ERCOT, the RCT, or the PUCT to resettle pricing across any portion of the supply chain that is currently being considered or may be considered by any such parties. There have already been several announced efforts by the state and federal governments and regulatory agencies to investigate and determine the causes of this event and its impact on consumers. We have received a civil investigative demand from the Attorney General of Texas as well as a request for information from ERCOT related to this event and may receive additional inquiries. We are cooperating with these entities and are working to respond to these requests. Those efforts may result in changes in regulations that impact our industry including but not limited to additional requirements for winterization of various facets of the electricity supply chain including generation, transmission, and fuel supply; improvements in coordination among the various participants in the electricity supply chain during any future event; potential revisions to the way in which the ERCOT market compensates and incentivizes the continued operation of assets that only run during times of scarcity; and potential changes to the types of plans permitted to be marketed to residential customers. We are continuing to monitor this situation as it develops but at this time cannot estimate any impacts of any legislative or regulatory changes or actions (including enforcement actions that may be brought against various market participants) that may occur as a result of the event on our business, financial condition, results of operations, or cash flows. As of December 31, 2020, Vistra had total available liquidity of approximately $2.4 billion, which was primarily comprised of cash and availability under its revolving credit facility. During this storm event, Vistra was required to post a significant amount of collateral, including to ERCOT, clearinghouses for natural gas and power transactions and other trading counterparties. Despite these posting requirements, Vistra has consistently maintained, and it continues to maintain, sufficient liquidity to conduct its operations in the ordinary course. As of February 25, 2021, Vistra had more than $1.5 billion of cash and availability under its revolving credit facility to meet any of its liquidity needs. 52 Table of Contents In response to the storm, Vistra committed to donate $5 million to assist Texas communities and individuals meet their most pressing needs, including support for food banks and food pantries, critical needs, bill payment assistance, and more. Vistra also assured residential customers across its retail brands that they will not see any near-term impact on their rates due to the winter weather event, though bills may increase due to high usage during the cold weather period in February. Investments in Clean Energy and CO2 Reductions In September 2020, we announced the planned development of up to 668 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas. We will only invest in these growth projects if we are confident in the expected returns. See Note 3 to the Financial Statements for a summary of our solar and battery energy storage projects. In September 2020 and December 2020, we announced our intention to retire (a) all of our remaining coal generation facilities in Illinois and Ohio, (b) one coal generation facility in Texas and (c) one natural gas facility in Illinois, no later than year-end 2027 due to economic challenges, including incremental expenditures that would be required to comply with the CCR rule and ELG rule (see Note 13 to the Financial Statements), and in furtherance of our efforts to significantly reduce our carbon footprint. See Note 4 to the Financial Statements for a summary of these planned generation retirements as well as our generation plant retirements in 2019. COVID-19 Pandemic With the global outbreak of the novel coronavirus (COVID-19) and the declaration of a pandemic by the World Health Organization on March 11, 2020, the U.S. government has deemed electricity generation, transmission and distribution as "critical infrastructure" providing essential services during this global emergency. As a provider of critical infrastructure, Vistra has an obligation to provide critically needed power to homes, businesses, hospitals and other customers. Vistra remains focused on protecting the health and well-being of its employees and the communities in which it operates while assuring the continuity of its business operations. We have updated and implemented our company-wide pandemic plan to address specific aspects of the COVID-19 pandemic to guide our emergency response, business continuity, and the precautionary measures we are taking on behalf of employees and the public. We will continue to monitor developments affecting both our workforce and our customers, and we have taken, and will continue to take, health and safety measures that we determine are necessary in order to mitigate the impacts. To date, as a result of these business continuity measures, the Company has not experienced material disruptions in our operations due to COVID-19. The fundamentals of the Company remain strong. Vistra believes it has sufficient available liquidity to continue business operations during this volatile period. As described under Available Liquidity, the Company has total available liquidity of $2.399 billion as of December 31, 2020, consisting of cash on hand and available capacity under our revolving credit facility (Revolving Credit Facility) of the Vistra Operations Credit Facilities. In addition, the maturities of our long-term debt are relatively modest until 2023. If the Company experienced a significant reduction in revenues or increases in costs or collateral requirements, the Company believes it would have additional alternatives to maintain access to liquidity, including drawing upon available liquidity or reductions to capital expenditures, planned voluntary debt repayments or operating costs. As a result of the Company's ongoing initiatives, the Company believes it is well-positioned to be able to respond to changes in customer demand, regulation or other factors impacting the Company's business related to the COVID-19 pandemic. In response to the economic and employment impacts of the COVID-19 outbreak, various states have instituted moratoriums or other conditions on disconnections for retail electricity customers. For example, in March and April 2020, the PUCT issued multiple orders requiring REPs in the ERCOT market to suspend late fees for residential customers through May 15, 2020, and to offer deferred payment plans to customers upon request. The PUCT also enacted the COVID-19 Electricity Relief Program whereby REPs must forego disconnecting customers certified as experiencing COVID-19-related hardship, and if such customer would otherwise be subject to disconnection and meets other qualifications, such REP would request suppression of the delivery charges from the transmission and distribution utility and request a proxy energy charge reimbursement from the COVID-19 Electricity Relief Program of $0.04/kWh. The PUCT ceased accepting new enrollments under the COVID-19 Electricity Relief Program after August 31, 2020, and the disconnection protections and financial assistance expired after September 30, 2020. See Note 7 to the Financial Statements for a summary of certain anticipated tax-related impacts of the CARES Act to the Company. 53 Table of Contents The COVID-19 pandemic has presented potential new risks to the Company's business. Although there have been logistical and other challenges to date, there has been no material adverse impact on the Company's 2020 results of operations. The situation surrounding COVID-19 remains fluid and the potential for a material impact on the Company's results of operations, financial condition and liquidity increases the longer the virus impacts the level of economic activity in the U.S. and globally. As a result, COVID-19 may have a range of impacts on the Company's operations, the full extent and scope of which are currently unknown. See Part I, Item 1A Risk Factors — The outbreak of COVID-19, or the future outbreak of any other highly infectious or contagious diseases, could have a material and adverse effect on our business, financial condition, and results of operations . Acquisitions and Merger Ambit Transaction — On November 1, 2019 (Ambit Acquisition Date), Volt Asset Company, Inc., an indirect, wholly owned subsidiary of Vistra, completed the acquisition of Ambit (Ambit Transaction). See Note 2 to the Financial Statements for a summary of the Ambit Transaction and business combination accounting. Crius Transaction — On July 15, 2019, Vienna Acquisition B.C. Ltd., an indirect, wholly owned subsidiary of Vistra, completed the acquisition of the equity interests of two wholly owned subsidiaries of Crius that indirectly own the operating business of Crius (Crius Transaction). See Note 2 to the Financial Statements for a summary of the Crius Transaction and business combination accounting. Dynegy Merger Transaction — On the Merger Date, Vistra and Dynegy completed the transactions contemplated by the Merger Agreement. See Note 2 to the Financial Statements for a summary of the Merger transaction and business combination accounting. Dividend Program In November 2018, we announced that the Board had adopted a dividend program which we initiated in the first quarter of 2019. See Note 14 to the Financial Statements for more information about our dividend program. Share Repurchase Program In September 2020, we announced that the Board had authorized a new share repurchase program (Share Repurchase Program) under which up to $1.5 billion of our outstanding common stock may be repurchased. The Share Repurchase Program was effective January 1, 2021, at which time the Prior Share Repurchase Plan terminated. From January 1, 2021 through February 23, 2021, 5,902,720 shares of our common stock had been repurchased under the Share Repurchase Program for $125 million at an average price per share of common stock of $21.15, and at February 23, 2021, $1.375 billion was available for repurchase under the Share Repurchase Program. See Note 14 to the Financial Statements for more information concerning the Share Repurchase Program and the Prior Share Repurchase Program. Debt Activity We have stated our objective to reduce our consolidated net leverage. We also intend to continue to simplify and optimize our capital structure, maintain adequate liquidity and pursue opportunities to refinance our long-term debt to extend maturities and/or reduce ongoing interest expense. In 2019 and 2020, we completed several transactions, including the redemption and repayment of all of Parent's previously outstanding senior notes, that we believe, in the aggregate, advanced all of these goals. See Note 11 to the Financial Statements for details of our long-term debt activity and Note 10 to the Financial Statements for details of our accounts receivable financing. 54 Table of Contents Capacity Markets PJM — Reliability Pricing Model (RPM) auction results, for the zones in which our assets are located, are as follows for each planning year: 2020-2021 2021-2022 (average price per MW-day) RTO zone (a) $ 88.32 $ 140.00 ComEd zone 188.12 195.55 MAAC zone 86.04 140.00 EMAAC zone 187.87 165.73 ATSI zone 76.53 171.33 PPL zone 86.04 140.00 ____________ (a) Planning Year 2020-2021 includes Duke Energy Ohio Kentucky (DEOK) zone, which cleared at $130.00 per MW-day. RTO Zone excluding DEOK Zone was $76.53 per MW-day. Our capacity sales, net of purchases, aggregated by planning year and capacity type through planning year 2022-2023, are as follows: 2020-2021 2021-2022 2022-2023 CP auction capacity sold, net (MW) 9,065 9,309 125 Bilateral capacity sold, net (MW) 100 250 200 Total segment capacity sold, net (MW) 9,165 9,559 325 Average price per MW-day $ 128.24 $ 157.30 $ 165.77 NYISO — The most recent seasonal auction results for NYISO's Rest-of-State zones, in which the capacity for our Independence plant clears, are as follows for each planning period: Summer 2021 Winter 2021 - 2022 Price per kW-month $ 2.71 $ 0.10 Due to the short-term, seasonal nature of the NYISO capacity auctions, we monetize the majority of our capacity through bilateral trades. Our capacity sales, aggregated by season through winter 2022-2023, are as follows: Winter 2020 - 2021 Summer 2021 Winter 2021 - 2022 Summer 2022 Winter 2022 - 2023 Auction capacity sold (MW) 144 — — — — Bilateral capacity sold (MW) 747 843 305 210 71 Total capacity sold (MW) 891 843 305 210 71 Average price per kW-month $ 0.72 $ 2.43 $ 0.97 $ 1.13 $ 1.13 ISO-NE — The most recent Forward Capacity Auction results for ISO-NE Rest-of-Pool, in which most of our assets are located, are as follows for each planning year: 2020-2021 2021-2022 2022-2023 2023-2024 Price per kW-month $ 5.30 $ 4.63 $ 3.80 $ 2.00 Performance incentive rules increase capacity payments for those resources that are providing excess energy or reserves during a shortage event, while penalizing those that produce less than the required level. We continue to market and pursue longer term multi-year capacity transactions that extend through planning year 2024-2025. 2020-2021 2021-2022 2022-2023 2023-2024 2024-2025 Auction capacity sold (MW) 3,085 2,798 2,996 2,496 — Bilateral capacity sold (MW) 191 170 95 20 20 Total capacity sold (MW) 3,276 2,968 3,091 2,516 20 Average price per kW-month $ 5.11 $ 4.57 $ 3.92 $ 2.16 $ 4.93 55 Table of Contents MISO — The capacity auction results for MISO Local Resource Zone 4, in which our assets are located, are as follows for each planning year: 2020-2021 Price per MW-day $ 5.00 MISO capacity sales through planning year 2023-2024 are as follows: 2020-2021 2021-2022 2022-2023 2023-2024 Bilateral capacity sold in MISO (MW) 2,672 2,098 573 251 CP auction capacity sold in PJM (MW) — 15 — — Total MISO segment capacity sold (MW) 2,672 2,113 573 251 Average price per kW-month $ 3.04 $ 3.12 $ 4.05 $ 3.69 CAISO — Our capacity sales, aggregated by calendar year for 2021 through 2022 for Moss Landing, are as follows: 2021 2022 Bilateral capacity sold (Avg MW) 1,020 831 56 Table of Contents Key Operational Risks and Challenges Following is a discussion of certain key operational 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 business, results of operations, liquidity, financial condition, cash flows, reputation, prospects and the market price for our securities (including our common stock). See also Item 1A. Risk Factors in this annual report on Form 10-K for additional discussion on risks that could have a material effect on our results of operations, liquidity, financial condition, cash flows, reputation, prospects and the market price for our securities (including our common stock). Natural Gas Price and Market Heat Rate Exposure The price of power is typically set by natural gas-fueled generation facilities, with wholesale prices generally tracking increases or decreases in the price of natural gas, with exceptions such as those periods during which ERCOT power prices rise significantly as a result of the scarcity of available generation resources relative to power demand. In recent years, natural gas supply has outpaced demand primarily as a result of development and expansion of hydraulic fracturing in natural gas extraction; this supply/demand environment has resulted in historically low natural gas prices, and such prices have historically been volatile. 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. Consequently, all other factors being equal, these nuclear-, lignite- and coal-fueled generation assets increase or decrease in value as wholesale electricity prices change either as a result of changes in natural gas prices or market heat rates, because of the effect on our operating margins. A persistent decline in the price of natural gas, if not offset by an increase in market heat rates, 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 and wholesale hedges. 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. For example, increasing renewable (wind and solar) generation capacity generally depresses market heat rates, particularly during periods when total demand is relatively low. However, increasing penetration of renewable generation capacity may also contribute to greater volatility of wholesale market prices independent of changes in the price of natural gas, given their intermittent nature. Decreases in market heat rates decrease the value of our generation assets because lower market heat rates result in lower wholesale electricity prices, and vice versa. As a result of our exposure to the variability of natural gas prices and market heat rates, 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. 57 Table of Contents Estimated hedging levels for generation volumes in our Texas, East, West and Sunset segments at December 31, 2020 were as follows: 2021 2022 Nuclear/Renewable/Coal Generation: Texas 91 % 46 % Sunset 98 % 57 % Gas Generation: Texas 76 % 16 % East 92 % 23 % West 99 % 9 % The following sensitivity table provides approximate estimates of the potential impact of movements in power prices and spark spreads (the difference between the power revenue and fuel expense of natural gas-fired generation as calculated using an assumed heat rate of 7.2 MMBtu/MWh) on realized pretax earnings (in millions) taking into account the hedge positions noted above for the periods presented. The residual gas position is calculated based on two steps: first, calculating the difference between actual heat rates of our natural gas generation units and the assumed 7.2 heat rate used to calculate the sensitivity to spark spreads; and second, calculating the residual natural gas exposure that is not already included in the gas generation spark spread sensitivity shown in the table below. The estimates related to price sensitivity are based on our expected generation, related hedges and forward prices as of December 31, 2020. 2021 2022 Texas: Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price $ 12 $ 63 Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price $ (9) $ (59) Gas Generation: $1.00/MWh increase in spark spread $ 12 $ 33 Gas Generation: $1.00/MWh decrease in spark spread $ (9) $ (30) Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ (13) $ (15) Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price $ 1 $ 3 East: Gas Generation: $1.00/MWh increase in spark spread $ 5 $ 38 Gas Generation: $1.00/MWh decrease in spark spread $ (3) $ (35) Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ (5) $ (4) Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price $ 5 $ 4 West: Gas Generation: $1.00/MWh increase in spark spread $ — $ 4 Gas Generation: $1.00/MWh decrease in spark spread $ — $ (4) Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ 1 $ 1 Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price $ (1) $ (1) Sunset: Coal Generation: $2.50/MWh increase in power price $ 5 $ 40 Coal Generation: $2.50/MWh decrease in power price $ (1) $ (34) 58 Table of Contents 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 approximately 1% in 2020 and approximately 2% in both 2019 and 2018. Based upon December 31, 2020 results discussed below in Results of Operations , a 1% decline in retail customers in ERCOT would result in a decline in annual revenues of approximately $57 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 December 31, 2020, these units represented approximately 6% 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 2021 at December 31, 2020) 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 to understand the importance and limits of our insurance protection. 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 , Ambit Energy, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric brands, expose the company to legal claims and regulatory scrutiny or impair our ability to execute on business strategies. 59 Table of Contents 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. 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. Seasonality The demand for and market prices of electricity and natural gas are affected by weather. As a result, our operating results are impacted by extreme or sustained weather conditions and may fluctuate on a seasonal basis. Typically, demand for and the price of electricity is higher in the summer and winter seasons, when the temperatures are more extreme, and the demand for and price of natural gas is also generally higher in the winter. More severe weather conditions such as heat waves or extreme winter weather have made, and may make such fluctuations more pronounced. The pattern of this fluctuation may change depending on, among other things, the retail load served and the terms of contracts to purchase or sell electricity. 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. Purchase Accounting On November 1, 2019, an indirect, wholly owned subsidiary of Vistra completed the Ambit Transaction. On July 15, 2019, an indirect, wholly owned subsidiary of Vistra completed the Crius Transaction. Each of the Ambit Transaction and Crius Transaction, respectively, was accounted for in accordance with ASC 805, Business Combinations (ASC 805), with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the Ambit Acquisition Date and the Crius Acquisition Date, respectively. See Note 2 to the Financial Statements for the purchase price allocations for both the Ambit Transaction and Crius Transaction as well as the related adjustments through the respective measurement periods. Determining fair values of assets acquired and liabilities assumed requires significant estimates and judgments. We determine fair value based on the estimated price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The acquired assets that involved the most subjectivity in determining fair value consisted of the customer relationship intangible assets. The assignment of fair value to the identifiable intangible assets requires judgment. We apply an income-based valuation methodology in measuring the customer relationships acquired, which include certain assumptions such as forecasted future cash flows, customer attrition rates, and discount rates. Customer relationship intangibles assets are generally amortized using an accelerated method based on historical customer attrition rates and reflecting the expected pattern in which the economic benefits are realized over their estimated useful lives. On the Merger Date, Dynegy merged with and into Vistra, with Vistra continuing as the surviving corporation. The Merger was accounted for in accordance with ASC 805, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the Merger Date. Vistra is the acquirer for both federal tax and accounting purposes. The combined results of operations are reported in our consolidated financial statements beginning as of the Merger Date. See Note 2 to the Financial Statements. 60 Table of Contents The acquired assets and liabilities that involved the most subjectivity in determining fair value consisted of property, plant and equipment and executory contracts, primarily long-term service agreements for maintenance of power plants, a unit-specific power sales agreement and rail transportation contracts. The fair value of each power plant was estimated using a combination of an income approach and a market approach. The income approach is the present value of future cash flows over the life of each power plant that are based on management’s estimates of revenues and operating expenses, and appropriate discount rates. The estimate of long term prices of electricity and natural gas at each plant location that was used in developing forecasted revenues for the income approach was especially subjective, because as of the Merger Date, limited market information about future prices beyond the year 2022 was available. The market valuation method uses prices paid for a reasonably similar asset by other purchasers in the relevant market, with adjustments relating to any differences between the assets and locations. The determination of deferred tax assets was complex as it required assessing income tax rules and regulations and proposed regulations that impose limitations on the future use of acquired net operating losses and other limitations on deductions. 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. Where quoted market prices are not available, the fair value is based on unobservable inputs, which require significant judgment. Derivative instruments valued based on unobservable inputs primarily include (i) forward sales and purchases of electricity, natural gas and coal, (ii) electricity, natural gas and coal options, and (iii) financial transmission rights. 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 proprietary 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. 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. Accounting standards also permit an entity to designate certain qualifying derivative contracts in a hedge accounting relationship, whereby changes in fair value are not recognized immediately in earnings. Vistra 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 CME transactions that 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 Vistra files a U.S. federal income tax return that includes the results of its consolidated subsidiaries. Vistra is the corporate parent of the Vistra consolidated group. Pursuant to applicable U.S. Department of the 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. 61 Table of Contents 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. See Notes 1 and 7 to the Financial Statements for further discussion of income tax matters. Accounting for Tax Receivable Agreement On the Effective Date, Vistra entered into a tax receivable agreement (the TRA) with a transfer agent. Pursuant to the TRA, we issued the TRA Rights for the benefit of the first-lien creditors of TCEH entitled to receive such TRA Rights under the Plan of Reorganization. Vistra reflected the obligation associated with TRA Rights at fair value in the amount of $574 million as of the Emergence Date related to these future payment obligations. As of December 31, 2020, the TRA obligation has been adjusted to $450 million. During the year ended December 31, 2020, we recorded a decrease to the carrying value of the TRA obligation totaling $69 million as a result of adjustments to forecasted taxable income, including the impacts of the CARES Act, changes to Section 163(j) percentage limitation amount, the impacts from the issuance of the final Section 163(j) regulations and the anticipated tax benefits from renewable development projects. At December 31, 2020, expected undiscounted federal and state payments under the TRA is estimated to be approximately $1.4 billion. The TRA obligation value is the discounted amount of projected 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 blended federal/state corporate income tax rate in all future years of 23.3%; • future taxable income by year for future years; • the Company generally expects to generate sufficient taxable income to be able to utilize the deductions arising out of (i) the tax basis step up attributable to the PrefCo Preferred Stock Sale, (ii) the entire tax basis of the assets acquired as a result of the Lamar and Forney Acquisition, and (iii) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA in the tax year in which such deductions arise; • a discount rate of 15%, which represented our view at the Emergence Date of the rate that a market participant would use based on the risk associated with the uncertainty in the amount and timing of the cash flows, at the time of Emergence; and • additional states that Vistra now operates in, the relevant tax rates of those states and how income will be apportioned to those states. 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 consolidated statements of operations 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 federal and state tax laws and regulations, changes in estimates of the amount or timing of future consolidated taxable income, utilization of acquired net operating losses, reversals of temporary book/tax differences and other items. Changes in those estimates are recognized as adjustments to the related TRA Rights liability, with offsetting impacts recorded in the consolidated statements of operations as Impacts of Tax Receivable Agreement. See Note 8 to the Financial Statements. 62 Table of Contents Asset Retirement Obligations (ARO) As part of business combination accounting, new fair values were established for all AROs assumed in the Merger. A liability is initially recorded at fair value for an ARO associated with the legal obligation associated with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets. Changes to the estimate of the ARO requires us to make significant estimates and assumptions. Specifically, the estimates and assumptions required for the mining land reclamation related to lignite mining, such as the costs to fill in mining pits and interpreting the mining permit closure requirements, are complex and require a significant amount of judgment. To develop the estimate associated with the costs to fill in mining pits, we utilize a complex proprietary model to estimate the volume of the pit. A significant portion of the estimate is associated with the Asset Closure Segment, thus related to closed facilities with changes in the estimate recorded to our consolidated statements of operations. During the years ended December 31, 2020 and 2019, we transferred $15 million and $135 million, respectively, in ARO obligations to third parties for remediation. Any remaining unpaid third-party obligation was reclassified to other current liabilities and other noncurrent liabilities and deferred credits in our consolidated balance sheets. At December 31, 2020, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.585 billion and includes an assumption that Vistra receives a license extension of 20 years from the NRC to continue to operate the Comanche Peak facility. The costs to ultimately decommission that facility are recoverable through the regulatory rate making process as part of Oncor's delivery fees and therefore changes in estimates of the ARO do not impact Vistra's earnings. See Note 21 to the Financial Statements for additional discussion of ARO obligations and adjustments made to the ARO obligation estimates during the years ended 2020, 2019 and 2018. 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. See Note 21 to the Financial Statements for discussion of impairments of long-lived assets recorded in 2020. Recoverability of long-lived assets is determined by a comparison of the carrying amount of the long-lived asset group to the net cash flows expected to be generated by the asset group, through considering specific assumptions for forward natural gas and electricity prices, forward capacity prices, the effects of enacted environmental rules, generation plant performance, forecasted capital expenditures, forecasted fuel prices and forecasted operating costs. The carrying value of such asset groups is determined to be unrecoverable if the projected undiscounted cash flows are less than the carrying value. If an asset group carrying value is determined to be unrecoverable, fair value will be calculated based on a market participant view and a loss will be recorded for the amount the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows (income approach) and supported by available market valuations, if applicable. The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity prices, forward capacity prices, market heat rates, the effects of enacted environmental rules, generation plant performance, forecasted capital expenditures and forecasted fuel prices. Another key assumption in the income approach is the discount rate applied to the forecasted cash flows. 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. Additional material impairments related to our generation facilities may occur in the future if forward wholesale electricity prices decline in the markets in which we operate in or if additional environmental regulations increase the cost of producing electricity at our generation facilities. 63 Table of Contents Goodwill and intangible assets with indefinite useful lives, such as the intangible asset related to the trade names of TXU Energy TM , Ambit Energy, 4Change Energy TM , Homefield, Dynegy Energy Services, TriEagle Energy, Public Power and U.S. Gas & Electric, respectively, are required to be evaluated for impairment at least annually (we have selected October 1 as our annual goodwill 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 standards allow a company to qualitatively assess if the carrying value of a reporting unit with goodwill is more likely than not less than the fair value of that reporting unit. If the entity determines the carrying value, including goodwill, is not more likely greater than the fair value, no further testing of goodwill for impairment is required. On the most recent goodwill testing date, we applied qualitative factors and determined that it was more likely than not that the fair value of our Retail and Texas Generation reporting units exceeded their carrying value at October 1, 2020. Significant qualitative factors evaluated included reporting unit financial performance and market multiples, cost factors, customer attrition, interest rates and changes in reporting unit book value. Accounting guidance requires goodwill to be allocated to our reporting units, and at December 31, 2020, $2.461 billion of our goodwill was allocated to our Retail reporting unit and $122 million was allocated to our Texas Generation 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 of a reporting unit 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. 64 Table of Contents RESULTS OF OPERATIONS Vistra Consolidated Financial Results — Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 and Year Ended December 31, 2019 Compared to Year Ended December 31, 2018 Year Ended December 31, 2020 vs 2019 Favorable (Unfavorable) $ Change 2019 vs 2018 Favorable (Unfavorable) $ Change 2020 2019 2018 Operating revenues $ 11,443 $ 11,809 $ 9,144 $ (366) $ 2,665 Fuel, purchased power costs and delivery fees (5,174) (5,742) (5,036) 568 (706) Operating costs (1,622) (1,530) (1,297) (92) (233) Depreciation and amortization (1,737) (1,640) (1,394) (97) (246) Selling, general and administrative expenses (1,035) (904) (926) (131) 22 Impairment of long-lived assets (356) — — (356) — Operating income 1,519 1,993 491 (474) 1,502 Other income 34 56 47 (22) 9 Other deductions (42) (15) (5) (27) (10) Interest expense and related charges (630) (797) (572) 167 (225) Impacts of Tax Receivable Agreement 5 (37) (79) 42 42 Equity in earnings of unconsolidated investment 4 16 17 (12) (1) Income (loss) before income taxes 890 1,216 (101) (326) 1,317 Income tax (expense) benefit (266) (290) 45 24 (335) Net income (loss) $ 624 $ 926 $ (56) $ (302) $ 982 Year Ended December 31, 2020 Retail Texas East West Sunset Asset Closure Eliminations / Corporate and Other Vistra Consolidated Operating revenues $ 8,270 $ 4,116 $ 2,415 $ 282 $ 1,252 $ 3 $ (4,895) $ 11,443 Fuel, purchased power costs and delivery fees (6,857) (1,078) (1,262) (168) (704) — 4,895 (5,174) Operating costs (123) (727) (270) (30) (408) (63) (1) (1,622) Depreciation and amortization (303) (475) (721) (19) (133) (22) (64) (1,737) Selling, general and administrative expenses (675) (75) (89) (26) (71) (27) (72) (1,035) Impairment of long-lived assets — — — — (356) — — (356) Operating income (loss) 312 1,761 73 39 (420) (109) (137) 1,519 Other income 6 3 1 1 6 10 7 34 Other deductions 1 (12) (30) — 2 (2) (1) (42) Interest expense and related charges (10) 8 (7) 10 (2) — (629) (630) Impacts of Tax Receivable Agreement — — — — — — 5 5 Equity in earnings of unconsolidated investment — — 4 — — — — 4 Income (loss) before income taxes 309 1,760 41 50 (414) (101) (755) 890 Income tax expense — — — — — — (266) (266) Net income (loss) $ 309 $ 1,760 $ 41 $ 50 $ (414) $ (101) $ (1,021) $ 624 65 Table of Contents Year Ended December 31, 2019 Retail Texas East West Sunset Asset Closure Eliminations / Corporate and Other Vistra Consolidated Operating revenues $ 6,872 $ 3,836 $ 2,790 $ 338 $ 1,602 $ 341 $ (3,970) $ 11,809 Fuel, purchased power costs and delivery fees (5,816) (1,283) (1,393) (187) (767) (267) 3,971 (5,742) Operating costs (71) (691) (236) (27) (366) (138) (1) (1,530) Depreciation and amortization (292) (472) (680) (19) (120) — (57) (1,640) Selling, general and administrative expenses (538) (76) (83) (17) (78) (43) (69) (904) Operating income (loss) 155 1,314 398 88 271 (107) (126) 1,993 Other income — 28 — — 7 3 18 56 Other deductions — (8) (1) — — (5) (1) (15) Interest expense and related charges (21) 8 (13) — (4) — (767) (797) Impacts of Tax Receivable Agreement — — — — — — (37) (37) Equity in earnings of unconsolidated investment — — 16 — — — — 16 Income (loss) before income taxes 134 1,342 400 88 274 (109) (913) 1,216 Income tax expense — — — — — — (290) (290) Net income (loss) $ 134 $ 1,342 $ 400 $ 88 $ 274 $ (109) $ (1,203) $ 926 Year Ended December 31, 2018 Retail Texas East West Sunset Asset Closure Eliminations / Corporate and Other Vistra Consolidated Operating revenues $ 5,597 $ 2,497 $ 1,895 $ 208 $ 1,183 $ 371 $ (2,607) $ 9,144 Fuel, purchased power costs and delivery fees (4,126) (1,461) (1,131) (134) (505) (286) 2,607 (5,036) Operating costs (39) (661) (164) (17) (305) (109) (2) (1,297) Depreciation and amortization (318) (390) (519) (14) (81) — (72) (1,394) Selling, general and administrative expenses (424) (88) (71) (8) (50) (39) (246) (926) Operating income (loss) 690 (103) 10 35 242 (63) (320) 491 Other income 29 34 1 — — 2 (19) 47 Other deductions — (7) (1) — 1 (1) 3 (5) Interest expense and related charges (7) (12) (10) (1) (1) — (541) (572) Impacts of Tax Receivable Agreement — — — — — — (79) (79) Equity in earnings of unconsolidated investment — — 18 — — — (1) 17 Income (loss) before income taxes 712 (88) 18 34 242 (62) (957) (101) Income tax benefit — — — — — — 45 45 Net income (loss) $ 712 $ (88) $ 18 $ 34 $ 242 $ (62) $ (912) $ (56) 66 Table of Contents In 2020, our operating segments delivered strong operating performance with a disciplined focus on cost management, while generating and selling essential electricity in a safe and reliable manner during a period of significant economic disruption. Our performance reflected the stability of our integrated model, including a diversified generation fleet, retail and commercial and hedging activities in support of our integrated business, to produce results that exceeded expectations and generated significant cash from operations of $3.337 billion for the year ended December 31, 2020. The increase of 22% versus 2019 was particularly strong given the general uncertainty in the overall economy and the challenges of dealing with COVID-19. Consolidated results decreased $302 million to net income of $624 million in the year ended December 31, 2020 compared to the year ended December 31, 2019. The change in results was driven by a $465 million pre-tax decrease in unrealized gains on commodity hedging transactions, a $356 million pre-tax impairment of assets related to our Kincaid, Zimmer and Joppa/EEI coal generation facilities and a $29 million pre-tax loss on disposal of our equity method investment in NELP, offset by strong operating results, particularly in the Texas segment, and the addition of Crius and Ambit. See Note 21 to the Financial Statements. Operating costs increased $92 million to $1.622 billion in the year ended December 31, 2020 compared to the year ended December 31, 2019 primarily driven by higher estimated costs for ARO, increased LTSA costs and COVID-related expenses and increased operating costs in Retail driven by the acquisition of Ambit and Crius, partially offset by lower property taxes. SG&A expense increased $131 million to $1.035 billion in the year ended December 31, 2020 compared to the year ended December 31, 2019 primarily due to the increased expense resulting from the acquisition of Crius in July 2019 and Ambit in November 2019. Interest expense and related charges decreased $167 million to $630 million in the year ended December 31, 2020 compared to the year ended December 31, 2019 driven by a $109 million decrease in interest paid/accrued reflecting the reduction in higher interest Vistra senior unsecured notes through the Redemptions and Tender Offers in 2019 and 2020 and a $65 million decrease in unrealized mark-to-market losses on interest rate swaps. Debt extinguishment gains totaled $17 million and $21 million in the years ended December 31, 2020 and 2019, respectively. See Note 21 to the Financial Statements. For the years ended December 31, 2020 and 2019, the impacts of the TRA totaled income of $5 million and expense of $37 million, respectively. See Note 8 to the Financial Statements for discussion of the impacts of the TRA obligation. For the year ended December 31, 2020, income tax expense totaled $266 million and the effective tax rate was 29.9%. For the year ended December 31, 2019, income tax benefit totaled $290 million and the effective tax rate was 23.8%. See Note 7 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate. For the years ended December 31, 2020 and 2019, consolidated cash flows from operations totaled $3.337 billion and $2.736 billion, respectively. Discussion of Adjusted EBITDA Non-GAAP Measures — In analyzing and planning for our business, we supplement our use of GAAP financial measures with non-GAAP financial measures, including EBITDA and Adjusted EBITDA as performance measures. These non-GAAP financial measures reflect an additional way of viewing aspects of our business that, when viewed with our GAAP results and the accompanying reconciliations to corresponding GAAP financial measures included in the tables below, may provide a more complete understanding of factors and trends affecting our business. These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are, by definition an incomplete understanding of Vistra and must be considered in conjunction with GAAP measures. In addition, non-GAAP financial measures are not standardized; therefore, it may not be possible to compare these financial measures with other companies' non-GAAP financial measures having the same or similar names. We strongly encourage investors to review our consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure. 67 Table of Contents EBITDA and Adjusted EBITDA — We believe EBITDA and Adjusted EBITDA provide meaningful representations of our operating performance. We consider EBITDA as another way to measure financial performance on an ongoing basis. Adjusted EBITDA is meant to reflect the operating performance of our segments for the period presented. We define EBITDA as earnings (loss) before interest expense, income tax expense (benefit) and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA adjusted to exclude (i) gains or losses on the sale or retirement of certain assets, (ii) the impacts of mark-to-market changes on derivatives, (iii) the impact of impairment charges, (iv) certain amounts associated with fresh-start reporting, acquisitions, dispositions, transition costs or restructurings, (v) non-cash compensation expense, (vi) impacts from the Tax Receivable Agreement and (vii) other material nonrecurring or unusual items. Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers, and evaluate overall financial performance, we believe they provide useful information for investors. When EBITDA or Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss). Adjusted EBITDA — Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 and Year Ended December 31, 2019 Compared to Year Ended December 31, 2018 Year Ended December 31, 2020 vs 2019 Favorable (Unfavorable) $ Change 2019 vs 2018 Favorable (Unfavorable) $ Change 2020 2019 2018 Net income (loss) $ 624 $ 926 $ (56) $ (302) $ 982 Income tax expense (benefit) 266 290 (45) (24) 335 Interest expense and related charges (a) 630 797 572 (167) 225 Depreciation and amortization (b) 1,812 1,713 1,472 99 241 EBITDA 3,332 3,726 1,943 (394) 1,783 Unrealized net (gain) loss resulting from commodity hedging transactions (231) (696) 380 465 (1,076) Generation plant retirement expenses 43 54 — (11) 54 Fresh start/purchase accounting impacts 38 30 41 8 (11) Impacts of Tax Receivable Agreement (5) 37 79 (42) (42) Non-cash compensation expenses 63 48 73 15 (25) Transition and merger expenses 16 115 233 (99) (118) Impairment of long-lived assets 356 — — 356 — Loss on disposal of investment in NELP 29 — — 29 — COVID-19-related expenses (c) 25 — — 25 — Odessa earnout buybacks — — 18 — (18) Other, net 19 11 (7) 8 18 Adjusted EBITDA $ 3,685 $ 3,325 $ 2,760 $ 360 $ 565 ____________ (a) Includes unrealized mark-to-market net losses on interest rate swaps of $155 million, $220 million and $5 million for the years ended December 31, 2020, 2019 and 2018, respectively. (b) Includes nuclear fuel amortization in the Texas segment of $75 million, $73 million and $78 million for the years ended December 31, 2020, 2019 and 2018, respectively. (c) Includes material and supplies and other incremental costs related to our COVID-19 response. 68 Table of Contents Vistra recorded its strongest performance in 2020 with Adjusted EBITDA of $3.685 billion, up nearly 11% versus 2019, despite economic challenges and uncertainties dealing with COVID-19. This performance exceeded our expectations set prior to the onset of the pandemic. Our balanced business was driven by strong performance in our Retail segment, delivering $983 million of Adjusted EBITDA, and our Texas generation segment, which delivered $1.646 billion of Adjusted EBITDA. Our other segments, including East, West, Sunset, Asset Closure and Corp delivered $1.056 billion. The performance of our Retail business on a variety of metrics, including customer satisfaction, customer count and margin are all strong. In Generation, we exceeded our commercial availability and safety targets. Our people drove strong results through our Operations Performance Initiative driving incremental gross margin and cost reduction opportunities, and our Best Defense safety program. Finally, our Commercial team optimized our integrated operations through disciplined risk management and hedging activities to ensure we lock in value for our generation business, while cost effectively supplying our retail business. This strong collaboration among our segments has produced consistent, strong results in each year since Vistra became a public company in 2016. Year Ended December 31, 2020 Retail Texas East West Sunset Asset Closure Eliminations / Corporate and Other Vistra Consolidated Net income (loss) $ 309 $ 1,760 $ 41 $ 50 $ (414) $ (101) $ (1,021) $ 624 Income tax expense — — — — — — 266 266 Interest expense and related charges (a) 10 (8) 7 (10) 2 — 629 630 Depreciation and amortization (b) 303 550 721 19 133 22 64 1,812 EBITDA 622 2,302 769 59 (279) (79) (62) 3,332 Unrealized net (gain) loss resulting from commodity hedging transactions 340 (691) 15 10 95 — — (231) Generation plant retirement expenses — — — — 43 — — 43 Fresh start/purchase accounting impacts 5 (8) 22 — 19 — — 38 Impacts of Tax Receivable Agreement — — — — — — (5) (5) Non-cash compensation expenses — — — — — — 63 63 Transition and merger expenses 5 2 1 — — (3) 11 16 Impairment of long-lived assets — — — — 356 — — 356 Loss on disposal of investment in NELP — — 29 — — — — 29 COVID-19-related expenses (c) — 15 3 — 5 — 2 25 Other, net 11 26 10 4 3 1 (36) 19 Adjusted EBITDA $ 983 $ 1,646 $ 849 $ 73 $ 242 $ (81) $ (27) $ 3,685 ____________ (a) Includes $155 million of unrealized mark-to-market net losses on interest rate swaps. (b) Includes nuclear fuel amortization of $75 million in the Texas segment. (c) Includes material and supplies and other incremental costs related to our COVID-19 response. 69 Table of Contents Year Ended December 31, 2019 Retail Texas East West Sunset Asset Closure Eliminations / Corporate and Other Vistra Consolidated Net income (loss) $ 134 $ 1,342 $ 400 $ 88 $ 274 $ (109) $ (1,203) $ 926 Income tax expense — — — — — — 290 290 Interest expense and related charges (a) 21 (8) 13 — 4 — 767 797 Depreciation and amortization (b) 292 545 680 19 120 — 57 1,713 EBITDA 447 1,879 1,093 107 398 (109) (89) 3,726 Unrealized net (gain) loss resulting from commodity hedging transactions 278 (591) (196) (41) (146) — — (696) Generation plant retirement expenses — — — — 12 42 — 54 Fresh start/purchase accounting impacts 23 (4) 4 (4) 14 (3) — 30 Impacts of Tax Receivable Agreement — — — — — — 37 37 Non-cash compensation expenses — — — — — — 48 48 Transition and merger expenses 49 11 9 1 22 — 23 115 Other, net 10 12 15 — 8 2 (36) 11 Adjusted EBITDA $ 807 $ 1,307 $ 925 $ 63 $ 308 $ (68) $ (17) $ 3,325 ____________ (a) Includes $220 million of unrealized mark-to-market net losses on interest rate swaps. (b) Includes nuclear fuel amortization of $73 million in the Texas segment. Year Ended December 31, 2018 Retail Texas East West Sunset Asset Closure Eliminations / Corporate and Other Vistra Consolidated Net income (loss) $ 712 $ (88) $ 18 $ 34 $ 242 $ (62) $ (912) $ (56) Income tax benefit — — — — — — (45) (45) Interest expense and related charges (a) 7 12 10 (1) 1 — 543 572 Depreciation and amortization (b) 318 468 519 14 81 — 72 1,472 EBITDA 1,037 392 547 47 324 (62) (342) 1,943 Unrealized net (gain) loss resulting from commodity hedging transactions (206) 498 81 15 (8) — — 380 Fresh start/purchase accounting impacts 26 (4) 11 — 7 1 — 41 Impacts of Tax Receivable Agreement — — — — — — 79 79 Non-cash compensation expenses — — — — — — 73 73 Transition and merger expenses 1 9 16 1 9 2 195 233 Odessa earnout buybacks — 18 — — — — — 18 Other, net (13) (1) 25 2 9 (4) (25) (7) Adjusted EBITDA $ 845 $ 912 $ 680 $ 65 $ 341 $ (63) $ (20) $ 2,760 ____________ (a) Includes $5 million of unrealized mark-to-market net losses on interest rate swaps. (b) Includes nuclear fuel amortization of $78 million in the Texas segment. 70 Table of Contents Retail Segment — Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 Year Ended December 31, Favorable (Unfavorable) Change 2020 2019 Operating revenues: Revenues in ERCOT $ 5,880 $ 5,061 $ 819 Revenues in Northeast/Midwest 2,406 1,818 588 Amortization expense (5) (15) 10 Other revenues (11) 8 (19) Total operating revenues $ 8,270 $ 6,872 $ 1,398 Fuel, purchased power costs and delivery fees: Purchases from affiliates (4,566) (3,571) (995) Unrealized net losses on hedging activities with affiliates (329) (305) (24) Unrealized net gains on hedging activities — 19 (19) Delivery fees (1,893) (1,629) (264) Other costs (a) (69) (330) 261 Total fuel, purchased power costs and delivery fees $ (6,857) $ (5,816) $ (1,041) Net income $ 309 $ 134 $ 175 Adjusted EBITDA $ 983 $ 807 $ 176 Retail sales volumes (GWh): Retail electricity sales volumes: Sales volumes in ERCOT 54,075 47,345 6,730 Sales volumes in Northeast/Midwest 36,274 30,255 6,019 Total retail electricity sales volumes 90,349 77,600 12,749 Weather (North Texas average) - percent of normal (b): Cooling degree days 90.0 % 96.0 % Heating degree days 91.0 % 113.0 % ____________ (a) For the year ended December 31, 2020 and 2019, includes third-party fuel and power purchases of $69 million and $329 million, respectively. (b) Weather data is obtained from Weatherbank, Inc. For the year ended December 31, 2020, normal is defined as the average over the 10-year period from December 2010 to December 2019. For the year ended December 31, 2019, normal is defined as the average over the 10-year period from December 2009 to December 2018. Net income increased by $175 million to $309 million and Adjusted EBITDA increased by $176 million to $983 million in the year ended December 31, 2020 compared to the year ended December 31, 2019. Year Ended December 31, 2020 Compared to 2019 Margin primarily driven by the addition of Crius acquired in July 2019 and Ambit acquired in November 2019 $ 339 Other driven by higher operating costs and SG&A expense (including bad debt expense) primarily due to the addition of Crius and Ambit (162) Change in Adjusted EBITDA $ 177 Change in depreciation and amortization expenses driven by Crius/Ambit intangibles (11) (Unfavorable) impact of higher unrealized net losses on commodity hedging activities (62) Lower transition and merger and other expenses 71 Change in Net income $ 175 71 Table of Contents Generation — Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 Year Ended December 31, Texas East West Sunset 2020 2019 2020 2019 2020 2019 2020 2019 Operating revenues: Electricity sales $ 896 $ 1,048 $ 833 $ 1,355 $ 289 $ 293 $ 883 $ 969 Capacity revenue from ISO/RTO — — (52) 170 — — 164 197 Sales to affiliates 2,543 2,213 1,655 1,074 3 — 365 285 Rolloff of unrealized net gains (losses) representing positions settled in the current period 2 371 159 59 (22) (10) (205) (74) Unrealized net gains (losses) on hedging activities 217 72 (121) (44) 12 51 133 249 Unrealized net gains (losses) on hedging activities with affiliates 458 132 (61) 180 — — (68) (7) Other revenues — — 2 (4) — 4 (20) (17) Operating revenues 4,116 3,836 2,415 2,790 282 338 1,252 1,602 Fuel, purchased power costs and delivery fees: Fuel for generation facilities and purchased power costs (960) (1,117) (1,225) (1,381) (166) (187) (744) (739) Fuel for generation facilities and purchased power costs from affiliates 6 — (8) (2) — — 2 2 Unrealized (gains) losses from hedging activities 14 16 8 1 — — 45 (22) Ancillary and other costs (138) (182) (37) (11) (2) — (7) (8) Fuel, purchased power costs and delivery fees (1,078) (1,283) (1,262) (1,393) (168) (187) (704) (767) Net income (loss) $ 1,760 $ 1,342 $ 41 $ 400 $ 50 $ 88 $ (414) $ 274 Adjusted EBITDA $ 1,646 $ 1,307 $ 849 $ 925 $ 73 $ 63 $ 242 $ 308 Production volumes (GWh): Natural gas facilities 35,093 39,433 55,938 55,555 5,284 5,228 Lignite and coal facilities 26,013 24,558 29,971 34,424 Nuclear facilities 19,480 19,305 Solar/Battery facilities 432 439 Capacity factors: CCGT facilities 49.2 % 55.0 % 57.9 % 58.4 % 59.1 % 58.5 % Lignite and coal facilities 77.1 % 72.8 % 47.1 % 54.1 % Nuclear facilities 96.7 % 95.8 % Weather - percent of normal (a): Cooling degree days 98 % 99 % 105 % 103 % 130 % 104 % 102 % 110 % Heating degree days 85 % 111 % 92 % 101 % 95 % 105 % 89 % 99 % ____________ (a) Reflects cooling degree days or heating degree days for the region based on Weather Services International (WSI) data. 72 Table of Contents Year Ended December 31, Year Ended December 31, 2020 2019 2020 2019 Market pricing Average Market On-Peak Power Prices ($MWh) (b): Average ERCOT North power price ($/MWh) $ 21.46 $ 35.93 PJM West Hub $ 24.55 $ 30.87 AEP Dayton Hub $ 24.49 $ 31.02 Average NYMEX Henry Hub natural gas price ($/MMBtu) $ 1.99 $ 2.51 NYISO Zone C $ 19.37 $ 25.90 Massachusetts Hub $ 26.57 $ 34.89 Average natural gas price (a): Indiana Hub $ 26.77 $ 31.23 TetcoM3 ($/MMBtu) $ 1.59 $ 2.39 Northern Illinois Hub $ 22.47 $ 28.16 Algonquin Citygates ($/MMBtu) $ 2.00 $ 3.17 ____________ (a) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us. (b) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized. The following table presents changes in net income (loss) and Adjusted EBITDA for the year ended December 31, 2020 compared to the year ended December 31, 2019. Year Ended December 31, 2020 Compared to 2019 Texas East West Sunset Favorable/(unfavorable) change in revenue net of fuel $ 390 $ (35) $ 18 $ (39) Favorable/(unfavorable) change in other operating costs (20) (15) (3) (4) Favorable/(unfavorable) change in SG&A expenses (7) (7) (6) (22) Other (24) (19) 1 (1) Change in Adjusted EBITDA $ 339 $ (76) $ 10 $ (66) Unfavorable change in depreciation and amortization (5) (41) — (13) Change in unrealized net gains/(losses) on commodity hedging activities 100 (211) (51) (241) Fresh start/purchase accounting impacts 4 (18) (4) (5) Transition and merger expenses 9 8 1 22 Impairment of long-lived assets — — — (356) Generation plant retirement expenses — — — (31) Loss on disposal of investment in NELP — (29) — — Other (including interest and COVID-19 related expenses) (29) 8 6 2 Change in Net income $ 418 $ (359) $ (38) $ (688) The change in Texas segment results was driven by higher realized prices through hedging activities and plant optimization efforts and unrealized hedging gains, partially offset by lower insurance reimbursement and COVID-19 related expenses in the current year. The change in East segment results was driven by lower capacity revenue, unrealized hedging losses in current year versus unrealized hedging gains in prior year, loss on disposal of equity method investment in NELP for 100% ownership of NJEA (see Note 21 to the Financial Statements) and COVID-19 related expenses in the current year. The change in West segment results was driven by unrealized hedging losses in current year versus unrealized hedging gains in prior year, partially offset by higher realized prices through hedging activities and plant optimization efforts. The change in Sunset segment results was driven by impairment of assets related to our Kincaid, Zimmer and Joppa/EEI coal generation facilities and related generation plant retirement expenses, unrealized hedging losses in current year versus unrealized hedging gains in prior year, lower capacity revenue, and higher operating costs. 73 Table of Contents Generation — Year Ended December 31, 2019 Compared to Year Ended December 31, 2018 Year Ended December 31, Texas East West Sunset 2019 2018 2019 2018 2019 2018 2019 2018 Operating revenues: Electricity sales $ 1,048 $ 1,162 $ 1,355 $ 990 $ 293 $ 193 $ 969 $ 769 Capacity revenue from ISO/RTO — — 170 375 — 30 197 258 Sales to affiliates 2,213 1,819 1,074 614 — — 285 168 Rolloff of unrealized net gains (losses) representing positions settled in the current period 371 404 59 3 (10) 20 (74) 60 Unrealized net gains (losses) on hedging activities 72 (689) (44) (43) 51 (35) 249 (87) Unrealized net gains (losses) on hedging activities with affiliates 132 (198) 180 (36) — — (7) 16 Other revenues — (1) (4) (8) 4 — (17) (1) Operating revenues 3,836 2,497 2,790 1,895 338 208 1,602 1,183 Fuel, purchased power costs and delivery fees: Fuel for generation facilities and purchased power costs (1,117) (1,307) (1,381) (1,111) (187) (132) (739) (547) Fuel for generation facilities and purchased power costs from affiliates — — (2) (8) — — 2 30 Unrealized (gains) losses from hedging activities 16 (15) 1 (5) — — (22) 19 Ancillary and other costs (182) (139) (11) (7) — (2) (8) (7) Fuel, purchased power costs and delivery fees (1,283) (1,461) (1,393) (1,131) (187) (134) (767) (505) Net income (loss) $ 1,342 $ (88) $ 400 $ 18 $ 88 $ 34 $ 274 $ 242 Adjusted EBITDA $ 1,307 $ 912 $ 925 $ 680 $ 63 $ 65 $ 308 $ 341 Production volumes (GWh): Natural gas facilities 39,433 35,790 55,555 41,036 5,228 3,664 Lignite and coal facilities 24,558 26,243 34,424 29,734 Nuclear facilities 19,305 20,416 Solar/Battery facilities 439 344 Capacity factors: CCGT facilities 55.0 % 58.8 % 58.4 % 59.1 % 58.5 % 56.1 % Lignite and coal facilities 72.8 % 77.8 % 54.1 % 63.4 % Nuclear facilities 95.8 % 101.3 % Weather - percent of normal (a): Cooling degree days 99 % 100 % 103 % 120 % 105 % 105 % 110 % 134 % Heating degree days 111 % 113 % 101 % 103 % 105 % 86 % 99 % 97 % ____________ (a) Reflects cooling degree days or heating degree days for the region based on Weather Services International (WSI) data. 74 Table of Contents Year Ended December 31, Year Ended December 31, 2019 2018 2019 2018 Market pricing Average Market On-Peak Power Prices ($MWh) (b): Average ERCOT North power price ($/MWh) $ 35.93 $ 29.96 PJM West Hub $ 30.87 $ 41.79 AEP Dayton Hub $ 31.02 $ 40.47 Average NYMEX Henry Hub natural gas price ($/MMBtu) $ 2.51 $ 3.12 NYISO Zone C $ 25.90 $ 37.03 Massachusetts Hub $ 34.89 $ 50.11 Average natural gas price (a): Indiana Hub $ 31.23 $ 39.01 TetcoM3 ($/MMBtu) $ 2.39 $ 3.69 Northern Illinois Hub $ 28.16 $ 34.46 Algonquin Citygates ($/MMBtu) $ 3.17 $ 4.84 ____________ (a) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us. (b) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized. The following table presents changes in net income and Adjusted EBITDA for the year ended December 31, 2019 compared to the year ended December 31, 2018. Year Ended December 31, 2019 Compared to 2018 Texas East West Sunset Favorable impact related to operations acquired in the Merger (a) $ — $ 268 $ 20 $ 84 Favorable/(unfavorable) change in revenue net of fuel 421 10 (11) (159) Favorable/(unfavorable) change in other operating costs (28) (13) (4) 41 Favorable/(unfavorable) change in SG&A expenses 9 (11) (7) 1 Other (7) (9) — — Change in Adjusted EBITDA $ 395 $ 245 $ (2) $ (33) Unfavorable change in depreciation and amortization (77) (161) (5) (39) Change in unrealized net gains on commodity hedging activities 1,089 277 56 138 Fresh start/purchase accounting impacts — 7 4 (7) Transition and merger expenses (2) 7 — (13) Generation plant retirement expenses — — — (12) Impact of Odessa earnout buybacks 18 — — — Other (including interest) 7 7 1 (2) Change in Net income $ 1,430 $ 382 $ 54 $ 32 The change in Texas segment results was driven by higher realized prices through hedging activities and plant optimization efforts, unrealized gains in 2019 versus unrealized losses in 2018, insurance reimbursement received in 2019, and the Odessa earnout buybacks in 2018. The change in East segment results was driven by operations in the first quarter of 2019 acquired in the Merger, partially offset by lower generation in the second through fourth quarters. The change in West segment results was driven by operations in the first quarter of 2019 acquired in the Merger and unrealized hedging gains in 2019 versus unrealized hedging losses in 2018. The change in Sunset segment results was driven by operations in the first quarter of 2019 acquired in the Merger and unrealized hedging gains in 2019, partially offset by decrease in revenue net of fuel reflecting lower realized power prices and capacity revenue. 75 Table of Contents Asset Closure Segment — Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 Year Ended December 31, Favorable (Unfavorable) Change 2020 2019 Operating revenues $ 3 $ 341 $ (338) Fuel, purchased power costs and delivery fees — (267) 267 Operating costs (63) (138) 75 Depreciation and amortization (22) — (22) Selling, general and administrative expenses (27) (43) 16 Operating loss (109) (107) (2) Other income 10 3 7 Other deductions (2) (5) 3 Net loss $ (101) $ (109) $ 8 Adjusted EBITDA $ (81) $ (68) $ (13) Production volumes (GWh) — 7,484 (7,484) Results for the Asset Closure segment primarily reflect the retirement of the Coffeen, Duck Creek, Havana and Hennepin plants in November and December 2019, respectively, the retirement of the Northeastern waste coal plant in October 2018, retirement of the Stuart and Killen plants in May 2018 (acquired in the Merger), and the retirement of the Monticello, Sandow and Big Brown plants in January and February 2018, respectively (see Note 4 to the Financial Statements). Operating costs for the years ended December 31, 2020 and 2019 included ongoing costs associated with the decommissioning and reclamation of retired plants and mines. Energy-Related Commodity Contracts and Mark-to-Market Activities The table below summarizes the changes in commodity contract assets and liabilities for the years ended December 31, 2020 and 2019. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $231 million and $696 million in unrealized net gains for the year ended December 31, 2020 and 2019, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio. Year Ended December 31, 2020 2019 Commodity contract net liability at beginning of period $ (279) $ (850) Settlements/termination of positions (a) (14) 358 Changes in fair value of positions in the portfolio (b) 245 338 Acquired commodity contracts (c) — (28) Other activity (d) (27) (97) Commodity contract net liability at end of period $ (75) $ (279) ____________ (a) Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). The years ended December 31, 2020 and 2019 include reversals of $1 million of previously recorded unrealized losses and $3 million of previously recorded unrealized gains related to Vistra beginning balances. respectively. The years ended December 31, 2020 and 2019 also include reversals of $12 million and $124 million, respectively, of previously recorded unrealized losses related to commodity contracts acquired in the Merger, Crius Transaction and Ambit Transaction. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month. (b) Represents unrealized net gains (losses) recognized, reflecting the effect of changes in fair value. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month. (c) Includes fair value of commodity contracts acquired on the Ambit Acquisition Date and the Crius Acquisition Date in 2019 (see Note 2 to the Financial Statements). (d) Represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses. Amounts are generally related to premiums related to options purchased or sold as well as certain margin deposits classified as settlement for certain transactions executed on the CME. 76 Table of Contents Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair values at December 31, 2020, scheduled by the source of fair value and contractual settlement dates of the underlying positions. Maturity dates of unrealized commodity contract net liability at December 31, 2020 Source of fair value Less than 1 year 1-3 years 4-5 years Excess of 5 years Total Prices actively quoted $ (41) $ (80) $ (5) $ — $ (126) Prices provided by other external sources 30 (2) 1 — 29 Prices based on models 107 23 (43) (65) 22 Total $ 96 $ (59) $ (47) $ (65) $ (75) FINANCIAL CONDITION Operating Cash Flows Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 — Cash provided by operating activities totaled $3.337 billion and $2.736 billion in the years ended December 31, 2020 and 2019, respectively. The favorable change of $601 million reflects the strong operating performance of both the Texas and Retail segments. Additionally, the increase in operating cash flows includes a lower increase in working capital, lower cash interest paid and increased income taxes received, partially offset by an increase in cash margin deposits posted with third-parties. Depreciation and amortization — Depreciation and amortization expense reported as a reconciling adjustment in the consolidated statements of cash flows exceeds the amount reported in the consolidated statements of operations by $311 million, $236 million and $139 million for the year ended December 31, 2020, 2019 and 2018, respectively. The difference represented amortization of nuclear fuel, which is reported as fuel costs in the consolidated statements of operations consistent with industry practice, and amortization of intangible net assets and liabilities that are reported in various other consolidated statements of operations line items including operating revenues and fuel and purchased power costs and delivery fees. Investing Cash Flows Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 — Cash used in investing activities totaled $1,572 million and $1.717 billion in the years ended December 31, 2020 and 2019, respectively. Capital expenditures totaled $1.259 billion and $713 million in the years ended December 31, 2020 and 2019, respectively. Cash used in investing activities in the year ended December 31, 2020 and 2019 also reflected net purchases of environmental allowances of $339 million and $125 million, respectively. Cash used in investing activities in the year ended December 31, 2019 also reflected $880 million of net cash paid in the Crius and Ambit Transactions. Capital Expenditures — In the years ended December 31, 2020 and 2019, capital expenditures consisted of: Year Ended December 31, 2020 2019 Capital expenditures, including LTSA prepayments $ 770 $ 520 Nuclear fuel purchases 88 89 Growth and development expenditures 401 104 Capital expenditures 1,259 $ 713 77 Table of Contents Financing Cash Flows Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 — Cash used in financing activities totaled $1.796 billion and $1.237 billion in the years ended December 31, 2020 and 2019, respectively. The change was primarily driven by: • issuance of $5.7 billion principal amount of Vistra Operations senior secured and unsecured notes in 2019; • redemption of $747 million principal amount of outstanding Vistra Unsecured Senior Notes in 2020; • net repayments of $350 million in short-term borrowings under the Revolving Credit Facility in 2020 compared to $350 million in net short-term borrowings under the Revolving Credit Facility in 2019; • net repayments of $150 million under the Receivables Facility in 2020 compared to net borrowings of $111 million in 2019; and • repayment of $100 million of term loans under the Vistra Operations Credit Facilities in 2020, partially offset by: • cash tender offers and early redemptions to purchase approximately $3.0 billion of senior unsecured notes assumed in the Merger in 2019; • repayment of approximately $3.1 billion of term loans under the Vistra Operations Credit Facilities in 2019; • $656 million in cash paid for share repurchases in in 2019; and • $186 million decrease in debt tender offer and other financing fees in 2020 compared to 2019. Debt Activity See Note 10 to the Financial statements for details of the Receivables Facility and Repurchase Facility and Note 11 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, 2020: December 31, 2020 December 31, 2019 Change Cash and cash equivalents $ 406 $ 300 $ 106 Vistra Operations Credit Facilities — Revolving Credit Facility 1,988 1,426 562 Vistra Operations — Alternate Letter of Credit Facility 5 — 5 Total available liquidity (a) $ 2,399 $ 1,726 $ 673 ____________ (a) Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See Note 10 to the Financial Statements for detail on our account receivable financing. The $673 million increase in available liquidity for the year ended December 31, 2020 was primarily driven by cash from operations, repayments of cash borrowings under the Revolving Credit Facility and a reduction of letters of credit outstanding under the Revolving Credit Facility reflecting the issuance of $303 million of letters of credit under the Secured LOC Facilities, partially offset by $1.259 billion of capital expenditures (including LTSA prepayments, nuclear fuel and development and growth expenditures), $747 million principal amount of outstanding Vistra Unsecured Senior Notes redeemed in 2020, $266 million in dividends paid to stockholders, the maturity of a $250 million Alternate LOC Facility and $100 million of term loans under the Vistra Operation Credit Facility repaid in March 2020. During the winter storm Uri event, Vistra was required to post a significant amount of collateral, including to ERCOT, clearinghouses for natural gas and power transactions and other trading counterparties. Despite these posting requirements, Vistra has consistently maintained, and it continues to maintain, sufficient liquidity to conduct its operations in the ordinary course. As of February 25, 2021, Vistra had more than $1.5 billion of cash and availability under its revolving credit facility to meet any of its liquidity needs. In February 2021, we borrowed $600 million under the Revolving Credit Facility to fund our general corporate needs, including posting requirements in connection with the expected impacts of winter storm Uri. Based upon our current internal financial forecasts, we believe that we will have sufficient liquidity to fund our anticipated cash requirements, including those related to our capital allocation initiatives, through at least the next 12 months. Our operational cash flows tend to be seasonal and weighted toward the second half of the year. 78 Table of Contents Capital Expenditures Estimated capital expenditures and nuclear fuel purchases for 2021 are expected to total approximately $1.379 billion and include: • $575 million for investments in generation and mining facilities; • $108 million for nuclear fuel purchases; • $9 million for information technology and other corporate investments; and • $687 million for growth and development expenditures. 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 11 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, 2020, we received or posted cash and letters of credit for commodity hedging and trading activities as follows: • $257 million in cash has been posted with counterparties as compared to $202 million posted at December 31, 2019; • $33 million in cash has been received from counterparties as compared to $8 million received at December 31, 2019; • $878 million in letters of credit have been posted with counterparties as compared to $1.150 billion posted at December 31, 2019; and • $18 million in letters of credit have been received from counterparties as compared to $17 million received at December 31, 2019. Income Tax Payments In the next 12 months, we do not expect to make federal income tax payments due to Vistra's use of NOL carryforwards. We expect to make approximately $56 million in state income tax payments, offset by $9 million in state tax refunds, and $3 million in TRA payments in the next 12 months. For the year ended December 31, 2020, we received refunds of $170 million related to AMT credits. For the year ended December 31, 2020, there were no federal income tax payments, $40 million in state income tax payments, $10 million in state income tax refunds and less than $1 million in TRA payments. Capitalization Our capitalization ratios consisted of 52% and 56% long-term debt (less amounts due currently) and 48% and 44% stockholders' equity at December 31, 2020 and 2019, respectively. Total long-term debt (including amounts due currently) to capitalization was 53% and 57% at December 31, 2020 and 2019, respectively. 79 Table of Contents Financial Covenants The Credit Facilities Agreement 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 $300 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, 2020 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 11 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. 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, 2020, Vistra has posted letters of credit in the amount of $102 million with the PUCT, which is subject to adjustments. The ISOs/RTOs we operate in have rules in place to assure adequate creditworthiness of parties that participate in the markets operated by those ISOs/RTOs. Under these rules, Vistra has posted collateral support totaling $290 million in the form of letters of credit, $10 million in the form of a surety bond and $1 million of cash at December 31, 2020 (which is subject to daily adjustments based on settlement activity with the ISOs/RTOs). 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 $2.57 billion at December 31, 2020) 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 equal to or above a threshold defined in the applicable agreement that results in the acceleration of such debt, would give such 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. Under the Vistra Operations Senior Unsecured Indentures and the Vistra Operations Senior Secured Indenture, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more may result in a cross default under the Vistra Operations Senior Unsecured Notes, the Senior Secured Notes, the Vistra Operations Credit Facilities, the Receivables Facility, the Alternate LOC Facilities, and other current or future documents evidencing any indebtedness for borrowed money by the applicable borrower or issuer, as the case may be, and the applicable Guarantor Subsidiaries party thereto. 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. 80 Table of Contents The Receivables Facility contains a cross-default provision. The cross-default provision applies, among other instances, if TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands and TriEagle, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), fails to make a payment of principal or interest on any indebtedness that is outstanding in a principal amount of at least $300 million, or, in the case of TXU Energy or any of the other Originators, in a principal amount of at least $50 million, after the expiration of any applicable grace period, or if other events occur or circumstances exist under such indebtedness which give rise to a right of the debtholder to accelerate such indebtedness, or if such indebtedness becomes due before its stated maturity. If this cross-default provision is triggered, a termination event under the Receivables Facility would occur and the Receivables Facility may be terminated. The Repurchase Facility contains a cross-default provision. The cross-default provision applies, among other instances, if an event of default (or similar event) occurs under the Receivables Facility or the Vistra Operations Credit Facilities. If this cross-default provision is triggered, a termination event under the Repurchase Facility would occur and the Repurchase Facility may be terminated. Under the Alternate LOC Facilities, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more, may result in a termination of the Alternate LOC Facilities. Under the Secured LOC Facilities, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more, may result in a termination of the Secured LOC Facilities. Guarantor Summary Financial Information During the year ended December 31, 2020, we fully redeemed the Vistra Senior Unsecured Notes that were previously guaranteed by substantially all of our wholly owned subsidiaries. The following tables summarize the combined financial information of (i) Vistra Corp. (Parent), which is the ultimate parent company and issuer of the Vistra Senior Unsecured Notes with effect as of the Merger Date, on a stand-alone, unconsolidated basis and (ii) the guarantor subsidiaries of Vistra (Guarantor Subsidiaries). The Guarantor Subsidiaries consist of the wholly owned subsidiaries, which jointly, severally, fully and unconditionally, guaranteed the payment obligations under the Vistra Senior Unsecured Notes. See Note 11 to the Financial Statements for discussion of the Vistra Senior Unsecured Notes and Note 14 to the Financial Statements for discussion of dividend restrictions of Vistra Operations (a guarantor subsidiary of Vistra) and Parent. This financial information should be read in conjunction with the consolidated financial statements and notes thereto of Vistra. Transactions between the Parent and the Guarantor Subsidiaries have been eliminated. The inclusion of Vistra's subsidiaries as Guarantor Subsidiaries in the summary financial information is determined as of the most recent balance sheet date presented. The Parent files a consolidated U.S. federal income tax return. All consolidated income tax expense or benefits and deferred tax assets and liabilities are included in the Guarantor summary financial information presented below, with no allocation made to the non-guarantor subsidiaries. Additionally, all corporate shared service costs are included in the Guarantor summary financial information with no allocation to the non-guarantor subsidiaries. Year Ended December 31, 2020 Revenues $ 10,954 Operating income $ 1,592 Net income $ 678 Net income attributable to Vistra $ 678 December 31, 2020 December 31, 2020 Current assets $ 2,404 Current liabilities $ 1,828 Noncurrent assets 21,307 Noncurrent liabilities 13,599 Total assets $ 23,711 Total liabilities $ 15,427 Noncontrolling interest $ — 81 Table of Contents Contractual Obligations and Commitments See Note 11 to the Financial Statements for long-term debt maturities, Note 12 to the Financial Statements for maturities of lease liabilities and Note 13 to the Financial Statements for commitments related to long-term service and maintenance contracts, energy-related contracts and other agreements. Guarantees See Note 13 to the Financial Statements for discussion of guarantees. 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.