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, 2021. This discussion should be read in conjunction with those consolidated financial statements and the related notes and is qualified by reference to them. 50 Table of Contents The following discussion and analysis of our financial condition and results of operations for the years ended December 31, 2021, 2020 and 2019 should be read in conjunction with our consolidated financial statements and the notes to those statements. The discussion and analysis of our financial condition and results of operations for the year ended December 31, 2019 and for the year ended December 31, 2020 compared to the year ended December 31, 2019 are included in Item 7. Management's Discussion and Analysis of Financial Condition and Results in our 2020 Form 10-K and are incorporated herein by reference. 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 electricity generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity and natural gas to end users. Operating Segments Vistra has six reportable segments: (i) Retail, (ii) Texas, (iii) East (iv) West, (v) Sunset and (vi) Asset Closure. See Note 20 to the Financial Statements for further information concerning our reportable business segments. 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. 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 weather event resulted in a $2.2 billion negative impact on the Company's pre-tax earnings in the year ended December 31, 2021 (see Note 1 to the Financial Statements), after taking into account approximately $544 million in securitization proceeds Vistra expects to receive from ERCOT as further described below. The primary drivers of the loss were the need to procure power in ERCOT at market prices at or near the price cap due to lower output from our natural gas-fueled power plants driven by natural gas deliverability issues and our coal-fueled power plants driven by coal fuel handling challenges, high fuel costs, and high retail load costs. 51 Table of Contents As part of the 2021 regular Texas legislative sessions and in response to extraordinary costs incurred by electricity market participants during Winter Storm Uri, the Texas legislature passed House Bill (HB) 4492 for ERCOT to obtain financing to distribute to load-serving entities (LSEs) that were charged and paid to ERCOT exceptionally high price adders and ancillary service costs during Winter Storm Uri. In October 2021, the PUCT issued a debt obligation order approving ERCOT's $2.1 billion financing and the methodology for allocation of proceeds to the LSEs. In December 2021, ERCOT finalized the amount of allocations to the LSEs, and we expect to receive $544 million in proceeds from ERCOT in the second quarter of 2022. We concluded that the threshold for recognizing a receivable was met in December 2021 as the amounts to be received are determinable and ERCOT was directed by its governing body, the PUCT, to take all actions required to effectuate the $2.1 billion funding approved in the debt obligation order. Accordingly, we recognized the $544 million in expected proceeds as an expense reduction in the fourth quarter of 2021 within fuel, purchased power costs and delivery fees in our consolidated statements of operation. We continue to be subject to 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. The Texas legislature also continues to consider potential legislation, such as Senate Bill (SB) 1580, which was passed in May 2021. SB 1580 may impact the total amount of balances owed by electric cooperatives to the market. The potential impact of this legislation is uncertain as the final details will be specific to each electric cooperative. There have 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 requests for information from ERCOT, NERC and other regulatory bodies related to this event and may receive additional inquiries. We are cooperating with these entities and have responded 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 and natural gas supply chains during any future event; potential revisions to the method or calculation of market compensation and incentives relating to the continued operation of assets that only run periodically, including during extreme weather events or other times of scarcity; and restrictions or limitations on the types of plans permitted to be offered to customers. We are continuing to monitor this situation as it develops. The full impact of litigation or 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 could have a material impact on our business, financial condition, results of operations, or cash flows, but cannot be estimated at this time. See Note 13 to the Financial Statements for further discussion of these matters. 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 would not see any near-term impact on their rates due to the winter weather event, though bills could increase due to high usage during the cold weather period in February 2021. Furthermore, Vistra has taken or intends to take various actions to improve its risk profile for future weather-driven volatility events, including investing in improvements to further harden its coal fuel handling capabilities and to further weatherize its ERCOT fleet for even colder temperatures and longer durations; carrying more backup generation into the peak seasons after accounting for weatherization investments and ERCOT market improvements implemented going forward; contracting for incremental gas storage to support its gas fleet; adding additional dual fuel capabilities at its gas steam units and increasing fuel oil inventory at its existing dual fuel sites; participating in processes with the PUCT and ERCOT for registration of gas infrastructure as critical resources with the transmission and distribution utilities and for enhanced winterization of both gas and power assets in the state; and engaging in processes to evaluate potential market reforms. Climate Change, Investments in Clean Energy and CO 2 Reductions Environmental Regulations — We are subject to extensive environmental regulation by governmental authorities, including the EPA and the environmental regulatory bodies of states in which we operate. Environmental regulations could have a material impact on our business, such as certain corrective action measures that may be required under the CCR rule and the ELG rule. See "Item 1. Business – Environmental Regulations and Related Considerations," and "Item 1A. Risk Factors – Regulatory and Legislative Risks" and Note 13 to the Financial Statements. However, such rules and the regulatory environment are continuing to evolve and change, and we cannot predict the ultimate effect that such changes may have on our business. 52 Table of Contents Emissions Reductions — Vistra is targeting to achieve a 60% reduction in Scope 1 and Scope 2 CO 2 equivalent emissions by 2030 as compared to a 2010 baseline with a long-term goal to achieve net-zero carbon emissions by 2050, assuming necessary advancements in technology and supportive market constructs and public policy. In furtherance of Vistra's efforts to meet its net-zero target, Vistra expects to deploy multiple levers to transition the company to operating with net-zero emissions. Green Finance Framework — In December 2021, we announced the publication of our Green Finance Framework, which allows us to issue green financial instruments to fund new or existing projects that support renewable energy and energy efficiency with alignment to our ESG initiatives. See Preferred Stock Offerings below for discussion of the Series B Preferred Securities issued under our Green Finance Framework. Solar Generation and Energy Storage Projects — In January 2022, we announced that, subject to approval by the CPUC, we would enter into a 15-year resource adequacy contract with PG&E to develop an additional 350 MW battery ESS at our Moss Landing Power Plant site. In September 2021, we announced the planned development, at a cost of approximately $550 million, of up to 300 MW of solar photovoltaic power generation facilities and up to 150 MW of battery ESS at retired or to-be-retired plant sites in Illinois, based on the passage of Illinois Senate Bill 2408, the Energy Transition Act. In September 2020, we announced the planned development, at a cost of approximately $850 million, 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. CO 2 Reductions — 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. In April 2021, we announced we would retire the Joppa generation facilities by September 1, 2022, and in July 2021, we announced we would retire the Zimmer coal generation facility by May 31, 2022. See Note 4 to the Financial Statements for a summary of these planned generation retirements. Moss Landing Outages In September 2021, Moss Landing Phase I experienced an incident impacting a portion of the battery ESS. A review found that only a small, single digit-percentage of batteries at the facility were impacted and that the root cause originated in systems separate from the battery system. The facility will be offline as we perform the work necessary to return the facility to service. Moss Landing Phase II was not affected by this incident. In February 2022, Moss Landing Phase II experienced an incident impacting a portion of the Battery ESS. An investigation is underway to determine the root cause of the incident. The facility will be offline as we perform the work necessary to return the facility to service. Moss Landing Phase I was not affected by the incident, but the facility will remain offline during the assessment stage of the Moss Landing Phase II incident. We do not expect these incidents to have a material impact on our results of operations. Mining Reclamation Award In October 2021, the Office of Surface Mining Reclamation and Enforcement (OSM) announced Luminant as a recipient of its 2021 Excellence in Surface Coal Mining Reclamation Award for the work done to reclaim and restore previously mined land at its Monticello-Winfield Mine. The award recognizes companies that achieve the most exemplary coal mine reclamation in the nation. Luminant has a long history of environmental stewardship, reclaiming land long before being required under federal or state law. 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. 53 Table of Contents 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. See Note 7 to the Financial Statements for a summary of certain tax-related impacts of the CARES Act to the Company. 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 results of operations for the years ended December 31, 2021 and 2020. 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 . 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. Preferred Stock Offerings On October 15, 2021, we issued 1,000,000 shares of Series A Preferred Stock in a private offering (Offering). The net proceeds of the Offering were approximately $990 million, after deducting underwriting commissions and offering expenses. We intend to use the net proceeds from the Offering to repurchase shares of our outstanding common stock under the Share Repurchase Program (discussed below). On December 10, 2021, we issued 1,000,000 shares of Series B Preferred Stock in a private offering (Series B Offering) under our Green Finance Framework. The net proceeds of the Series B Offering were approximately $985 million, after deducting underwriting commissions and offering expenses. We intend to use the proceeds from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments. See Note 14 to the Financial Statements for more information concerning the Series A Preferred Stock and the Series B Preferred Stock. Share Repurchase Program In October 2021, we announced that the Board had authorized a new share repurchase program (Share Repurchase Program) under which up to $2.0 billion of our outstanding common stock may be repurchased. The Share Repurchase Program became effective on October 11, 2021. The Share Repurchase Program supersedes the $1.5 million share repurchase program previously announced in September 2020 (2020 Share Repurchase Program). In the three months ended December 31, 2021, 19,330,365 shares of our common stock were repurchased under the Share Repurchase Program for approximately $409 million at an average price of $21.16 per share of common stock. As of December 31, 2021, approximately $1.591 billion was available for additional repurchases under the Share Repurchase Program. From January 1, 2022 through February 22, 2022, 16,059,290 shares of our common stock had been repurchased under the Share Repurchase Program for $355 million at an average price per share of common stock of $22.07, and at February 22, 2022, $1.236 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 2020 Share Repurchase Program. 54 Table of Contents 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. While the financial impacts resulting from Winter Storm Uri caused an increase in our consolidated net leverage, the Company remains committed to a strong balance sheet, and the anticipated securitization proceeds from ERCOT are expected to enable us to further execute this objective. See Note 1 to the Financial Statements for details of the securitization proceeds receivable from ERCOT, 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. Commodity-Linked Revolving Credit Facility On February 4, 2022, Vistra Operations entered into a credit agreement by and among Vistra Operations, Vistra Intermediate, the lenders, joint lead arrangers and joint bookrunners party thereto, and Citibank, N.A., as administrative agent and collateral agent. The Credit Agreement provides for a $1.0 billion senior secured commodity-linked revolving credit facility (the Commodity-Linked Facility). Vistra Operations intends to use the liquidity provided under the Commodity-Linked Facility to make cash postings as required under various commodity contracts to which Vistra Operations and its subsidiaries are parties as power prices increase from time-to time and for other working capital and general corporate purposes. See Note 11 to the Financial Statements for more information concerning the Commodity-Linked Facility. 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: 2021-2022 2022-2023 (average price per MW-day) RTO zone $ 140.00 $ 50.00 ComEd zone 195.55 68.96 MAAC zone 140.00 95.79 EMAAC zone 165.73 97.86 ATSI zone 171.33 50.00 DEOK zone 140.00 71.69 Our capacity sales in PJM, net of purchases, aggregated by planning year and capacity type through planning year 2022-2023, are as follows: 2021-2022 2022-2023 East Segment Sunset Segment East Segment Sunset Segment CP auction capacity sold, net (MW) 6,384 3,028 5,500 1,519 Bilateral capacity sold, net (MW) 200 50 200 — Total segment capacity sold, net (MW) 6,584 3,078 5,700 1,519 Average price per MW-day $ 159.18 $ 148.83 $ 68.54 $ 70.52 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: Winter 2021 - 2022 Summer 2022 Price per kW-month $ 1.00 $ — 55 Table of Contents 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 2023-2024, are as follows: East Segment Winter 2021 - 2022 Summer 2022 Winter 2022 - 2023 Summer 2023 Winter 2023 - 2024 Auction capacity sold (MW) 125 — — — — Bilateral capacity sold (MW) 1,017 565 212 104 38 Total capacity sold (MW) 1,142 565 212 104 38 Average price per kW-month $ 0.94 $ 2.18 $ 1.31 $ 1.76 $ 1.78 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: 2021-2022 2022-2023 2023-2024 2024-2025 Price per kW-month $ 4.63 $ 3.80 $ 2.00 $ 2.61 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 2025-2026. East Segment 2021-2022 2022-2023 2023-2024 2024-2025 2025-2026 Auction capacity sold (MW) 3,037 2,996 3,091 2,967 — Bilateral capacity sold (MW) 213 95 20 78 78 Total capacity sold (MW) 3,250 3,091 3,111 3,045 78 Average price per kW-month $ 4.35 $ 3.92 $ 2.12 $ 3.18 $ 3.47 MISO — The capacity auction results for MISO Local Resource Zone 4, in which our assets are located, are as follows for each planning year: 2021-2022 Price per MW-day $ 5.00 MISO capacity sales through planning year 2024-2025 are as follows: Sunset Segment 2021-2022 2022-2023 2023-2024 2024-2025 Bilateral capacity sold in MISO (MW) 3,012 1,075 569 265 Total MISO segment capacity sold (MW) 3,012 1,075 569 265 Average price per kW-month $ 2.31 $ 1.94 $ 2.58 $ 4.26 CAISO — Our capacity sales in CAISO, aggregated by calendar year for 2022 through 2023 for Moss Landing, are as follows: West Segment 2022 2023 Bilateral capacity sold (Avg MW) 1,287 1,275 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. When natural gas prices are 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 as of December 31, 2021 were as follows: 2022 2023 Nuclear/Renewable/Coal Generation: Texas 90 % 55 % Sunset 98 % 47 % Gas Generation: Texas 71 % 8 % East 94 % 35 % West 100 % 6 % 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 pre-tax 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 at December 31, 2021. 2022 2023 Texas: Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price $ 13 $ 53 Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price $ (11) $ (50) Gas Generation: $1.00/MWh increase in spark spread $ 13 $ 39 Gas Generation: $1.00/MWh decrease in spark spread $ (12) $ (37) Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ (6) $ (18) Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price $ 6 $ 10 East: Gas Generation: $1.00/MWh increase in spark spread $ 4 $ 32 Gas Generation: $1.00/MWh decrease in spark spread $ (2) $ (30) Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ 1 $ (2) Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price $ (1) $ 2 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 $ — Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price $ (1) $ — Sunset: Coal Generation: $2.50/MWh increase in power price $ 2 $ 32 Coal Generation: $2.50/MWh decrease in power price $ (1) $ (28) 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 3%, 1% and 2% in 2021, 2020 and 2019, respectively. Based upon December 31, 2021 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 $56 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, 2021, 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 2022 at December 31, 2021) to be approximately $2 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. 59 Table of Contents Cyber/Data Security and Infrastructure Protection Risk A breach of cyber/data security measures that impairs our information technology infrastructure, operations technology systems, supporting components, and/or associated sites utilized by the Company or one of our service providers could disrupt normal business operations and affect our ability to control our generation assets, access retail customer information and limit communication with third parties. Breaches and threats are becoming increasingly sophisticated, complex, change frequently and may be difficult to detect, and our increased use of remote work environments and virtual platforms in response to the COVID-19 pandemic may also increase our risk of cyber-attack or data security breaches. Any loss of confidential or proprietary data through a breach could materially affect our reputation, including our TXU Energy, 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, significant liabilities, reputational damage, regulatory action, and disrupt business operations, which could impair our ability to execute on business strategies. We participate in industry groups and with regulators to remain current on emerging threats and mitigating techniques. These groups include, but are not limited to, the Federal Bureau of Investigation, Cybersecurity and Infrastructure Security Agency, U.S. Department of Homeland Security, Electricity Information Sharing and Analysis Center, U.S. Cyber Emergency Response Team, 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 marketplace 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 have controls in place designed to protect our infrastructure, provide our employees awareness training of cybersecurity threats, routinely utilize information technology security experts to assist us in our evaluations of the effectiveness of our information technology systems and controls, and we regularly enhance our security measures to protect our systems and data, including encryption, tokenization and authentication technologies to mitigate cybersecurity risks and increasing our monitoring capabilities to enhance early detection and rapid response to potential cyber threats. In response to the fact that a portion of our workforce continues to work remotely and within a hybrid work environment, we have reduced our attack surface process and technology, which removes remote network risk from our internal systems, assets, or data. We also apply the knowledge gained through industry and government organizations, external partner cyber risk and maturity assessments 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 and Estimates 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. 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. 60 Table of Contents 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. 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. 61 Table of Contents 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 Effective Date related to these future payment obligations. As of December 31, 2021, the TRA obligation has been adjusted to $395 million. During the year ended December 31, 2021, we recorded a decrease to the carrying value of the TRA obligation totaling $115 million as a result of adjustments to forecasted taxable income, including the financial impacts of Winter Storm Uri, and anticipated tax benefits available under current tax laws for planned additional renewable development projects. As of December 31, 2021, 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 22.9%; • 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 Effective 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. 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. For the next five years, Vistra is projected to spend approximately $265 million (on a nominal basis) to achieve its reclamation objectives. 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. 62 Table of Contents As of December 31, 2021, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.635 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 December 31, 2021, 2020 and 2019. 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 the years ended December 31, 2021 and 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. 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, 2021. 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. 63 Table of Contents Accounting guidance requires goodwill to be allocated to our reporting units, and at December 31, 2021, $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 excess carrying value 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. RESULTS OF OPERATIONS Vistra Consolidated Financial Results — Year Ended December 31, 2021 Compared to Year Ended December 31, 2020 Year Ended December 31, Favorable (Unfavorable) $ Change 2021 2020 Operating revenues $ 12,077 $ 11,443 $ 634 Fuel, purchased power costs and delivery fees (9,169) (5,174) (3,995) Operating costs (1,559) (1,622) 63 Depreciation and amortization (1,753) (1,737) (16) Selling, general and administrative expenses (1,040) (1,035) (5) Impairment of long-lived and other assets (71) (356) 285 Operating income (loss) (1,515) 1,519 (3,034) Other income 140 34 106 Other deductions (16) (42) 26 Interest expense and related charges (384) (630) 246 Impacts of Tax Receivable Agreement 53 5 48 Equity in earnings of unconsolidated investment — 4 (4) Income (loss) before income taxes (1,722) 890 (2,612) Income tax (expense) benefit 458 (266) 724 Net income (loss) $ (1,264) $ 624 $ (1,888) 64 Table of Contents Year Ended December 31, 2021 Retail Texas East West Sunset Asset Closure Eliminations / Corporate and Other Vistra Consolidated Operating revenues $ 7,871 $ 2,790 $ 2,587 $ 374 $ 739 $ — $ (2,284) $ 12,077 Fuel, purchased power costs and delivery fees (4,568) (3,991) (2,123) (253) (518) — 2,284 (9,169) Operating costs (127) (704) (243) (37) (417) (30) (1) (1,559) Depreciation and amortization (212) (608) (698) (60) (139) — (36) (1,753) Selling, general and administrative expenses (718) (88) (75) (32) (55) (26) (46) (1,040) Impairment of long-lived and other assets (33) — — — (38) — — (71) Operating income (loss) 2,213 (2,601) (552) (8) (428) (56) (83) (1,515) Other income 1 84 — — 15 35 5 140 Other deductions (7) (9) — — 2 — (2) (16) Interest expense and related charges (9) 14 (15) 9 (2) (1) (380) (384) Impacts of Tax Receivable Agreement — — — — — — 53 53 Income (loss) before income taxes 2,198 (2,512) (567) 1 (413) (22) (407) (1,722) Income tax benefit (expense) (2) — — — — — 460 458 Net income (loss) $ 2,196 $ (2,512) $ (567) $ 1 $ (413) $ (22) $ 53 $ (1,264) 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 and other 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 In February 2021, Winter Storm Uri resulted in a $2.2 billion negative impact on the Company's pre-tax earnings in the year ended December 31, 2021, after taking into account approximately $544 million in securitization proceeds Vistra expects to receive from ERCOT as further described in Note 1 to the Financial Statements. For the remainder of 2021, our operating segments delivered strong operating performance with a disciplined focus on cost management and self-help activities while generating and selling essential electricity in a safe and reliable manner. Consolidated results decreased $3.034 billion to a net operating loss of $1.515 billion in the year ended December 31, 2021 compared to the year ended December 31, 2020. The change in results was driven by the Winter Storm Uri impacts, including the need to procure power in ERCOT at market prices at or near the price cap due to lower output from our natural gas-fueled power plants driven by natural gas deliverability issues and our coal-fueled power plants driven by coal fuel handling challenges, high fuel costs, and high retail load costs including ancillary service costs and reliability deployment price adders. Results were adversely impacted by $759 million in pre-tax unrealized losses on commodity hedging transactions in 2021 compared to $231 million in pre-tax unrealized gains on commodity hedging transactions in 2020. Power, natural gas and coal forward market curves moved up during the year ended December 31, 2021, driving these net pre-tax unrealized losses on commodity hedging transactions. Operating costs decreased $63 million to $1.559 billion in the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily driven by lower LTSA costs and lower property taxes. Interest expense and related charges decreased $246 million to $384 million in the year ended December 31, 2021 compared to the year ended December 31, 2020 driven by $134 million in unrealized mark-to-market gains on interest rate swaps in 2021 compared to $155 million in unrealized mark-to-market losses on interest rate swaps in 2020. See Note 21 to the Financial Statements. For the years ended December 31, 2021 and 2020, the impacts of the TRA totaled income of $53 million and $5 million, respectively. See Note 8 to the Financial Statements for discussion of the impacts of the TRA obligation. For the year ended December 31, 2021, income tax benefit totaled $458 million and the effective tax rate was 26.6%. For the year ended December 31, 2020, income tax benefit totaled $266 million and the effective tax rate was 29.9%. See Note 7 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate. Consolidated cash flows used in operations totaled $206 million for the year ended December 31, 2021 compared to consolidated cash flows provided by operations of $3.337 billion for the year ended December 31, 2020. The unfavorable change of $3.543 billion was primarily driven by lower cash from operations due to Winter Storm Uri impacts and higher cash margin deposits posted with third-parties. Cash margin deposits posted were driven by net pre-tax unrealized losses on commodity hedging transactions reflecting power, natural gas and coal forward market curves that moved up during the year ended December 31, 2021. 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. 66 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, 2021 Compared to Year Ended December 31, 2020 Year Ended December 31, Favorable (Unfavorable) $ Change 2021 2020 Net income (loss) $ (1,264) $ 624 $ (1,888) Income tax expense (benefit) (458) 266 (724) Interest expense and related charges (a) 384 630 (246) Depreciation and amortization (b) 1,831 1,812 19 EBITDA 493 3,332 (2,839) Unrealized net (gain) loss resulting from commodity hedging transactions 759 (231) 990 Generation plant retirement expenses 18 43 (25) Fresh start/purchase accounting impacts (138) 38 (176) Impacts of Tax Receivable Agreement (53) (5) (48) Non-cash compensation expenses 51 63 (12) Transition and merger expenses (8) 16 (24) Other, including impairment of long-lived and other assets 80 375 (295) Loss on disposal of investment in NELP — 29 (29) COVID-19-related expenses (c) 8 25 (17) Winter Storm Uri impacts (d) 698 — 698 Adjusted EBITDA $ 1,908 $ 3,685 $ (1,777) ____________ (a) Includes unrealized mark-to-market net gains on interest rate swaps of $134 million and unrealized mark-to-market net losses on interest rate swaps of $155 million for the years ended December 31, 2021 and 2020, respectively. (b) Includes nuclear fuel amortization in the Texas segment of $78 million and $75 million for the years ended December 31, 2021 and 2020, respectively. (c) Includes material and supplies and other incremental costs related to our COVID-19 response. (d) For the year ending December 31, 2021, includes the following of the Winter Storm Uri impacts, which we believe are not reflective of our operating performance: allocation of ERCOT default uplift charges which are expected to be paid over more than 90 years under current protocols; accrual of Koch earn-out amounts that the Company will pay by the end of the second quarter of 2022; future bill credits related to Winter Storm Uri (as further described below); and Winter Storm Uri related legal fees and other costs. The adjustment for future bill credits relates to large commercial and industrial customers that curtailed their usage during Winter Storm Uri and will reverse and impact Adjusted EBITDA in future periods as the credits are applied to customer bills. We estimate the amounts to be applied in future periods are 2022 (approximately $150 million), 2023 (approximately $67 million), 2024 (approximately $11 million) and 2025 (approximately $4 million). The Company believes the inclusion of the bill credits as a reduction to Adjusted EBITDA in the years in which such bill credits are applied more accurately reflects its operating performance. 67 Table of Contents Year Ended December 31, 2021 Retail Texas East West Sunset Asset Closure Eliminations / Corporate and Other Vistra Consolidated Net income (loss) $ 2,196 $ (2,512) $ (567) $ 1 $ (413) $ (22) $ 53 $ (1,264) Income tax expense (benefit) 2 — — — — — (460) (458) Interest expense and related charges (a) 9 (14) 15 (9) 2 1 380 384 Depreciation and amortization (b) 212 686 698 60 139 — 36 1,831 EBITDA 2,419 (1,840) 146 52 (272) (21) 9 493 Unrealized net (gain) loss resulting from commodity hedging transactions (1,403) 1,139 655 38 330 — — 759 Generation plant retirement expenses — — — — 18 — — 18 Fresh start/purchase accounting impacts 2 (14) (74) — (52) — — (138) Impacts of Tax Receivable Agreement — — — — — — (53) (53) Non-cash compensation expenses — — — — — — 51 51 Transition and merger expenses (2) — — — — (15) 9 (8) Other, including impairment of long-lived and other assets 57 18 9 3 33 3 (43) 80 COVID-19-related expenses (c) — 4 1 — 2 — 1 8 Winter Storm Uri impacts (d) 239 457 — — 1 — 1 698 Adjusted EBITDA $ 1,312 $ (236) $ 737 $ 93 $ 60 $ (33) $ (25) $ 1,908 ____________ (a) Includes $134 million of unrealized mark-to-market net gains on interest rate swaps. (b) Includes nuclear fuel amortization of $78 million in the Texas segment. (c) Includes material and supplies and other incremental costs related to our COVID-19 response. (d) Includes the following of the Winter Storm Uri impacts, which we believe are not reflective of our operating performance: allocation of ERCOT default uplift charges which are expected to be paid over more than 90 years under current protocols; accrual of Koch earn-out amounts that the Company will pay by the end of the second quarter of 2022; future bill credits related to Winter Storm Uri (as further described below); and Winter Storm Uri related legal fees and other costs. The adjustment for future bill credits relates to large commercial and industrial customers that curtailed their usage during Winter Storm Uri and will reverse and impact Adjusted EBITDA in future periods as the credits are applied to customer bills. We estimate the amounts to be applied in future periods are 2022 (approximately $150 million), 2023 (approximately $67 million), 2024 (approximately $11 million) and 2025 (approximately $4 million). The Company believes the inclusion of the bill credits as a reduction to Adjusted EBITDA in the years in which such bill credits are applied more accurately reflects its operating performance. 68 Table of Contents 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 Other, including impairment of long-lived and other assets 11 26 10 4 359 1 (36) 375 Loss on disposal of investment in NELP — — 29 — — — — 29 COVID-19-related expenses (c) — 15 3 — 5 — 2 25 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 Retail Segment — Year Ended December 31, 2021 Compared to Year Ended December 31, 2020 Year Ended December 31, Favorable (Unfavorable) Change 2021 2020 Operating revenues: Revenues in ERCOT $ 5,943 $ 5,880 $ 63 Revenues in Northeast/Midwest 2,255 2,406 (151) Amortization expense (2) (5) 3 Unrealized net losses on hedging activities (a) (325) (11) (314) Total operating revenues $ 7,871 $ 8,270 $ (399) Fuel, purchased power costs and delivery fees: Purchases from affiliates (4,002) (4,566) 564 Unrealized net gains (losses) on hedging activities with affiliates 1,719 (329) 2,048 Unrealized net gains on hedging activities 9 — 9 Delivery fees (1,937) (1,893) (44) Other costs (b) (357) (69) (288) Total fuel, purchased power costs and delivery fees $ (4,568) $ (6,857) $ 2,289 Net income $ 2,196 $ 309 $ 1,887 Adjusted EBITDA $ 1,312 $ 983 $ 329 Retail sales volumes (GWh): Retail electricity sales volumes: Sales volumes in ERCOT 57,033 54,075 2,958 Sales volumes in Northeast/Midwest 36,070 36,274 (204) Total retail electricity sales volumes 93,103 90,349 2,754 Weather (North Texas average) - percent of normal (c): Cooling degree days 90.0 % 90.0 % Heating degree days 92.0 % 91.0 % ____________ (a) For the year ended December 31, 2021, a net loss of $298 million was recognized in operating revenues due to the third quarter 2021 discontinuance of normal purchase and sale accounting on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract term. (b) For the year ended December 31, 2021, includes $153 million of future bill credits to large commercial and industrial customers. (c) Weather data is obtained from Weatherbank, Inc. For the year ended December 31, 2021, normal is defined as the average over the 10-year period from December 2011 to December 2020. For the year ended December 31, 2020, normal is defined as the average over the 10-year period from December 2010 to December 2019. 70 Table of Contents The following table presents changes in net income (loss) and Adjusted EBITDA for the year ended December 31, 2021 compared to the year ended December 31, 2020. Year Ended December 31, 2021 Compared to 2020 Winter Storm Uri, including securitization proceeds receivable from ERCOT and bill credits $ (75) Monetization of certain commercial positions 207 Higher margins 228 Other driven by higher SG&A expense (31) Change in Adjusted EBITDA $ 329 Favorable impact of higher unrealized net gains on commodity hedging activities 1,743 Future bill credits and other costs related to Winter Storm Uri (245) Decrease in depreciation and amortization expenses 91 Other, including impairment of long-lived and other assets (31) Change in Net income $ 1,887 71 Table of Contents Generation — Year Ended December 31, 2021 Compared to Year Ended December 31, 2020 Year Ended December 31, Texas East West Sunset 2021 2020 2021 2020 2021 2020 2021 2020 Operating revenues: Electricity sales $ 1,999 $ 896 $ 1,619 $ 833 $ 410 $ 289 $ 819 $ 883 Capacity revenue from ISO/RTO — — (22) (52) 1 — 184 164 Sales to affiliates 2,063 2,543 1,553 1,655 5 3 382 365 Rolloff of unrealized net gains (losses) representing positions settled in the current period (207) 2 (159) 159 62 (22) 241 (205) Unrealized net gains (losses) on hedging activities (37) 217 51 (121) (104) 12 (713) 133 Unrealized net gains (losses) on hedging activities with affiliates (1,028) 458 (529) (61) — — (162) (68) Other revenues — — 74 2 — — (12) (20) Operating revenues 2,790 4,116 2,587 2,415 374 282 739 1,252 Fuel, purchased power costs and delivery fees: Fuel for generation facilities and purchased power costs (2,829) (960) (2,072) (1,225) (251) (166) (810) (744) Fuel for generation facilities and purchased power costs from affiliates — 6 2 (8) — — (4) 2 Unrealized (gains) losses from hedging activities 133 14 (18) 8 4 — 304 45 Ancillary and other costs (1,295) (138) (35) (37) (6) (2) (8) (7) Fuel, purchased power costs and delivery fees (3,991) (1,078) (2,123) (1,262) (253) (168) (518) (704) Net income (loss) $ (2,512) $ 1,760 $ (567) $ 41 $ 1 $ 50 $ (413) $ (414) Adjusted EBITDA $ (236) $ 1,646 $ 737 $ 849 $ 93 $ 73 $ 60 $ 242 Production volumes (GWh): Natural gas facilities 30,921 35,093 55,428 55,938 5,365 5,284 Lignite and coal facilities 25,513 26,013 36,953 29,971 Nuclear facilities 19,402 19,480 Solar/Battery facilities 454 432 4 Capacity factors: CCGT facilities 43.2 % 49.2 % 57.6 % 57.9 % 60.0 % 59.1 % Lignite and coal facilities 75.6 % 77.1 % 58.0 % 47.1 % Nuclear facilities 96.3 % 96.7 % Weather - percent of normal (a): Cooling degree days 94 % 98 % 108 % 105 % 90 % 130 % 115 % 102 % Heating degree days 94 % 85 % 93 % 92 % 111 % 95 % 90 % 89 % ____________ (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, 2021 2020 2021 2020 Market pricing Average Market On-Peak Power Prices ($MWh) (b): Average ERCOT North power price ($/MWh) $ 149.57 $ 21.46 PJM West Hub $ 45.62 $ 24.55 AEP Dayton Hub $ 44.88 $ 24.49 Average NYMEX Henry Hub natural gas price ($/MMBtu) $ 3.82 $ 1.99 NYISO Zone C $ 35.59 $ 19.37 Massachusetts Hub $ 51.81 $ 26.57 Average natural gas price (a): Indiana Hub $ 48.62 $ 26.77 TetcoM3 ($/MMBtu) $ 3.40 $ 1.59 Northern Illinois Hub $ 41.15 $ 22.47 Algonquin Citygates ($/MMBtu) $ 4.51 $ 2.00 ____________ (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, 2021 compared to the year ended December 31, 2020. Year Ended December 31, 2021 Compared to 2020 Texas East West Sunset Favorable/(unfavorable) change in revenue net of fuel $ (447) $ (175) $ 34 $ (178) Winter Storm Uri impact (1,535) 50 — 17 Favorable/(unfavorable) change in other operating costs 19 8 (7) (39) Favorable/(unfavorable) change in selling, general and administrative expenses — 10 (6) 8 Other (including other income and other deductions) (a) 81 (5) (1) 10 Change in Adjusted EBITDA $ (1,882) $ (112) $ 20 $ (182) Favorable/(unfavorable) change in depreciation and amortization (136) 23 (41) (6) Change in unrealized net losses on hedging activities (1,830) (640) (28) (235) Other, including impairment of long-lived and other assets 25 (5) — 329 Generation plant retirement expenses — — — 25 Fresh start/purchase accounting impacts 6 96 — 71 Transition and merger expenses 2 1 — — Winter Storm Uri impact (ERCOT default uplift and legal disputes) (457) — — (1) Loss on disposal of investment in NELP — 29 — — Change in Net income (loss) $ (4,272) $ (608) $ (49) $ 1 ____________ (a) For the year ended December 31, 2021, includes insurance proceeds of $80 million in the Texas segment and $7 million in the Sunset segment. The change in Texas segment results was primarily driven by the Winter Storm Uri impacts, including the need to procure power in ERCOT at market prices at or near the price cap due to lower output from our natural gas-fueled power plants driven by natural gas deliverability issues, lower margins from our natural gas-fueled power plants due to extremely high fuel costs, and, to a lesser extent, operational challenges associated with Winter Storm Uri, and unrealized hedging losses in the year ended December 31, 2021 versus unrealized hedging gains in the year ended December 31, 2020, partially offset by insurance proceeds received in 2021. The change in East segment results was driven by lower revenue net of fuel and larger unrealized hedging losses in the year ended December 31, 2021 versus the year ended December 31, 2020, partially offset by loss on disposal of equity method investment in NELP for 100% ownership of NJEA (see Note 21 to the Financial Statements) in 2020. 73 Table of Contents The change in West segment results was driven by larger unrealized hedging losses in year ended December 31, 2021 versus the year ended December 31, 2020, partially offset by higher realized prices through hedging activities and plant optimization efforts. The change in Sunset segment results was driven by larger unrealized hedging losses in year ended December 31, 2021 versus the year ended December 31, 2020 and lower margins due to lower realized prices and higher operating costs, partially offset by higher impairment of long-lived assets generation plant retirement expenses related to our Joppa/EEI, Kincaid and Zimmer coal generation facilities in 2020. Asset Closure Segment — Year Ended December 31, 2021 Compared to Year Ended December 31, 2020 Year Ended December 31, Favorable (Unfavorable) Change 2021 2020 Operating revenues $ — $ 3 $ (3) Operating costs (30) (63) 33 Depreciation and amortization — (22) 22 Selling, general and administrative expenses (26) (27) 1 Operating loss (56) (109) 53 Other income 35 10 25 Other deductions — (2) 2 Interest expense and related charges (1) — (1) Income (loss) before income taxes (22) (101) 79 Net loss $ (22) $ (101) $ 79 Adjusted EBITDA $ (33) $ (81) $ 48 Operating costs for the years ended December 31, 2021 and 2020 included ongoing costs associated with the decommissioning and reclamation of retired plants and mines. The year ended December 31, 2021 includes a gain on the settlement of rail transportation disputes (see Note 21 to the Financial Statements). 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, 2021 and 2020. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $759 million in unrealized net losses and $231 million in unrealized net gains for the years ended December 31, 2021 and 2020, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio. Year Ended December 31, 2021 2020 Commodity contract net liability at beginning of period $ (75) $ (279) Settlements/termination of positions (a) (295) (14) Changes in fair value of positions in the portfolio (b) (464) 245 Other activity (c) (32) (27) Commodity contract net liability at end of period $ (866) $ (75) ____________ (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, 2021 and 2020 also include reversals of $3 million and $12 million, respectively, of previously recorded unrealized losses related to commodity contracts acquired in the Merger, Crius Transaction and Ambit Transaction. The year ended December 31, 2020 includes reversals of $1 million of previously recorded unrealized losses related to Vistra beginning balances. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month. (b) Represents unrealized net gains (losses) recognized, reflecting the effect of changes in fair value. 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. 74 Table of Contents (c) Represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses. Amounts are generally related to premiums related to options purchased or sold as well as certain margin deposits classified as settlement for certain transactions executed on the CME. Maturity Table — The following table presents the net commodity contract liability arising from recognition of fair values at December 31, 2021, 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, 2021 Source of fair value Less than 1 year 1-3 years 4-5 years Excess of 5 years Total Prices actively quoted $ (631) $ (116) $ 2 $ — $ (745) Prices provided by other external sources 352 (113) 1 (1) 239 Prices based on models (72) (83) (108) (97) (360) Total $ (351) $ (312) $ (105) $ (98) $ (866) FINANCIAL CONDITION Operating Cash Flows Year Ended December 31, 2021 Compared to Year Ended December 31, 2020 — Cash used in operating activities totaled $206 million in the year ended December 31, 2021 compared to cash provided by operating activities of $3.337 billion in the year ended December 31, 2020. The unfavorable change of $3.543 billion was primarily driven by lower cash from operations due to Winter Storm Uri impacts and higher cash margin deposits posted with third-parties. Cash margin deposits posted were driven by net pre-tax unrealized losses on commodity hedging transactions reflecting power, natural gas and coal forward market curves that moved up during the year ended December 31, 2021. 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 $297 million, $311 million and $236 million for the year ended December 31, 2021, 2020 and 2019, 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, 2021 Compared to Year Ended December 31, 2020 — Cash used in investing activities totaled $1.153 billion and $1.572 billion in the years ended December 31, 2021 and 2020, respectively. Capital expenditures totaled $1.033 billion and $1,259 million in the years ended December 31, 2021 and 2020, respectively, and. consisted of the following: Year Ended December 31, 2021 2020 Capital expenditures, including LTSA prepayments $ 549 $ 770 Nuclear fuel purchases 44 88 Growth and development expenditures 440 401 Capital expenditures 1,033 $ 1,259 Cash used in investing activities in the year ended December 31, 2021 and 2020 also reflected net purchases of environmental allowances of $213 million and $339 million, respectively. In the year ended December 31, 2021 and 2020, we received insurance proceeds of $89 million and $35 million, respectively. 75 Table of Contents Financing Cash Flows Year Ended December 31, 2021 Compared to Year Ended December 31, 2020 — Cash provided by financing activities totaled $2.274 billion in the year ended December 31, 2021 and cash used in financing activities totaled $1.796 billion in the year ended December 31, 2020. The change was primarily driven by: • proceeds of $1.975 billion from the issuance of preferred stock in 2021; • the issuance of $1.250 billion principal amount of Vistra Operations senior unsecured notes in 2021; • $500 million in cash received from the sale of a portion of the PJM capacity that cleared for Planning Years 2021-2022 in 2021; • redemption of $747 million principal amount of outstanding of Vistra unsecured senior notes in 2020; • net repayment of $350 million in short-term borrowings under the Revolving Credit Facility in 2020; and • repayment of $100 million of term loans under the Vistra Operations Credit Facilities in 2020; partially offset by: • $471 million in cash paid for share repurchases in 2021; and • net repayments of $300 million under the Receivables Facility in 2021 compared to net repayments of $150 million in 2020. 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, 2021: December 31, 2021 December 31, 2020 Change Cash and cash equivalents $ 1,325 $ 406 $ 919 Vistra Operations Credit Facilities — Revolving Credit Facility 1,254 1,988 (734) Vistra Operations — Alternate Letter of Credit Facility — 5 (5) Total available liquidity (a) $ 2,579 $ 2,399 $ 180 ____________ (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 accounts receivable financing. The $180 million increase in available liquidity for the year ended December 31, 2021 was primarily driven by proceeds of $1.975 billion from the issuance of preferred stock in 2021, cash received from the issuance of $1.250 billion principal amount of Vistra Operations senior unsecured notes in May 2021 and $500 million in cash received from the sale of a portion of the PJM capacity that cleared for Planning Years 2021-2022, partially offset by cash used in operations, including higher cash margin deposits posted with third parties, $1.033 billion of capital expenditures (including LTSA prepayments, nuclear fuel and development and growth expenditures), a $734 increase in letters of credit outstanding under the Revolving Credit Facility, $290 million in dividends paid to stockholders, $471 million in cash paid for share repurchases, $300 million in net cash repayments under the accounts receivable financing facilities and the maturity of a $250 million Alternate LOC Facility. Additionally, in February 2022, we entered into a $1.0 billion senior secured commodity-linked revolving credit facility (the Commodity-Linked Facility) (see Note 11 to the Financial Statements). Based upon our current internal financial forecasts, we believe that we will have sufficient liquidity to fund our anticipated cash requirements through at least the next 12 months. Our operational cash flows tend to be seasonal and weighted toward the second half of the year. If the Company experienced a significant reduction in revenues or increases in costs or collateral requirements, such as a result of Winter Storm Uri, the Company believes it would have additional alternatives to maintain access to liquidity, including drawing upon available liquidity, accessing additional sources of capital or reducing capital expenditures, planned voluntary debt repayments or operating costs. 76 Table of Contents The maturities of our long-term debt are relatively modest until 2023. Interest payments on long-term debt are expected to total approximately $499 million in 2022, $946 million in 2023-2024, $753 million in 2025-2026 and $372 million thereafter. See Note 11 to the Financial Statements for details of our long-term debt maturities. Our obligations under commodity purchase and services agreements, including capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase commitments, are expected to total approximately $1.850 billion in 2022, $1.250 billion in 2023-2024, $700 million in 2025-2026 and $585 million thereafter. See 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. Capital Expenditures Estimated 2022 capital expenditures and nuclear fuel purchases as of November 5, 2021 total approximately $1.814 billion and include: • $1.002 billion for solar and energy storage development; • $570 million for investments in generation and mining facilities; • $117 million for nuclear fuel purchases; • $72 million for information technology and other corporate investments; and • $53 million for other growth 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. As of December 31, 2021, we received or posted cash and letters of credit for commodity hedging and trading activities as follows: • $1.263 billion in cash has been posted with counterparties as compared to $257 million posted at December 31, 2020; • $39 million in cash has been received from counterparties as compared to $33 million received at December 31, 2020; • $1.558 billion in letters of credit have been posted with counterparties as compared to $878 million posted at December 31, 2020; and • $35 million in letters of credit have been received from counterparties as compared to $18 million received at December 31, 2020. See Collateral Support Obligations below for information related to collateral posted in accordance with the PUCT and ISO/RTO rules. 77 Table of Contents Income Tax Payments In the next 12 months, we do not expect to make federal income tax payments due to Vistra's loss position in 2021 and use of NOL carryforwards. We expect to make approximately $35 million in state income tax payments, offset by $11 million in state tax refunds, and less than $1 million in TRA payments in the next 12 months. For the year ended December 31, 2021, there were no federal income tax payments, $52 million in state income tax payments, $2 million in state income tax refunds and $2 million in TRA payments. Capitalization Our capitalization ratios consisted of 56% and 52% long-term debt (less amounts due currently) and 44% and 48% stockholders' equity at December 31, 2021 and 2020, respectively. Total long-term debt (including amounts due currently) to capitalization was 56% and 53% at December 31, 2021 and 2020, respectively. 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. As of December 31, 2021, we were in compliance with this financial covenant. 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, 2021, Vistra has posted letters of credit in the amount of $74 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 $420 million in the form of letters of credit, $20 million in the form of a surety bond and $1 million of cash at December 31, 2021 (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 were 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 under such facilities, which totaled approximately $2.54 billion at December 31, 2021. 78 Table of Contents 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. 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. Under the Commodity-Linked Facility, 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 Commodity-Linked Facility. 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. 79 Table of Contents CHANGES IN ACCOUNTING STANDARDS See Note 1 to the Financial Statements for discussion of changes in accounting standards.