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, 2022. This discussion should be read in conjunction with those consolidated financial statements and the related notes and is qualified by reference to them. 51 Table of Contents The following discussion and analysis of our financial condition and results of operations for the years ended December 31, 2022, 2021 and 2020 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, 2020 and for the year ended December 31, 2021 compared to the year ended December 31, 2020 are included in Item 7. Management's Discussion and Analysis of Financial Condition and Results in our 202 1 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 19 to the Financial Statements for further information concerning our reportable business segments. CEO Transition In March 2022, Vistra announced that the Board had named Jim Burke as its next Chief Executive Officer (CEO), effective August 1, 2022. Mr. Burke, who previously served as President and Chief Financial Officer, also joined the Company's Board upon assuming his new role. Vistra's previous CEO and director, Curt Morgan, will serve as a special advisor to Mr. Burke and the Board until April 30, 2023. The transition from Mr. Morgan to Mr. Burke was a product of the Company's formal succession planning process. In July 2022, the Company announced the appointment of Kris Moldovan as the Company's Executive Vice President and Chief Financial Officer, effective August 1, 2022. Significant Activities and Events and Items Influencing Future Performance 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 Effluent Limitation Guidelines (ELG) rule. See Item 1. Business – Environmental Regulations and Related Considerations , and Item 1A. Risk Factors – Regulatory and Legislative Risks and Note 12 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. 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 strategy. See Preferred Stock Offerings below for discussion of the Series B Preferred Securities issued under our Green Finance Framework. 52 Table of Contents Solar Generation and Energy Storage Projects — • 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. Of this planned development in Texas, 158 MW of solar generation and the 260 MW of battery ESS came online in 2022. • 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 January 2022, we announced that, subject to approval by the CPUC, we would enter into a 15-year resource adequacy and energy settlement contract with PG&E to develop an additional 350 MW battery ESS at our Moss Landing Power Plant site. The CPUC approved the resource adequacy and energy settlement contract in April 2022. We will only invest in these growth projects if we are confident in the expected returns. See Note 2 to the Financial Statements for a summary of our solar and battery ESS 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 12 to the Financial Statements), and in furtherance of our efforts to significantly reduce our carbon footprint. In June 2022, September 2022 and January 2023, we retired the Zimmer coal-fueled generation facility, the Joppa generation facilities and the Edwards coal-fueled generation facility, respectively. See Note 3 to the Financial Statements for a summary of these planned generation retirements. Comanche Peak Nuclear Plant License Renewal In October 2022, we announced the submission of our application to the NRC for license renewal at our two-unit Comanche Peak Nuclear Plant. The current licenses for Units 1 and 2 extend into 2030 and 2033, respectively, and we are applying to renew the licenses into 2050 and 2053, respectively. Inflation Reduction Act of 2022 In August 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA), which, among other things, implements substantial new and modified energy tax credits, including a nuclear production tax credit (PTC), a solar PTC, a first-time stand-alone battery storage investment tax credit, a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases. Treasury regulations are expected to define the scope of the legislation in many important respects over the next twelve months. Vistra is not subject to the CAMT in the next fiscal year since it applies only to corporations that have a three-year average annual adjusted financial statement income in excess of $1 billion. The excise tax is not expected to have a material impact on our financial statements. As of December 31, 2022, we have taken the CAMT and relevant extensions or expansions of existing tax credits applicable to projects in our immediate development pipeline into account when forecasting cash taxes for periods after the law takes effect and for estimating the TRA liability. Macroeconomic Conditions Global market demand, geopolitical events and high natural gas price volatility have resulted in increased market prices for energy and other commodities, and we expect these conditions to persist, in particular in the near term. Due in large part to the Russia and Ukraine conflict as well as other factors, we have experienced substantial shifts in commodity prices, which in turn have (i) facilitated our comprehensive hedging strategy which we believe has positioned us to lock in significant revenues and Adjusted EBITDA opportunities in 2023 through 2025, (ii) led to significant mark-to-market impacts on forward commodity derivative instruments, and (iii) combined with our comprehensive hedging strategy, resulted in significant increases in our collateral posting obligations and required substantial liquidity to support such obligations. Additionally, we continue to monitor domestic drivers of gas prices, including the pace of investment and buildout of liquefied natural gas (LNG) export capabilities, which have the potential to more closely align U.S. natural gas pricing with the further elevated international gas markets over the next couple of years. See also Financial Condition for further discussion of our collateral posting obligations and liquidity management activities. 53 Table of Contents We continue to monitor the impacts of energy volatility on the retail and associated default service markets. As electricity pricing trended higher in 2022, we experienced increased customer migration to the default service provider in territories outside of Texas, where default service rates do not yet fully reflect the higher commodity pricing environment. Generators (including Vistra) with contracts to serve a percentage of the resultingly higher than planned default service load (previously awarded through the default service auction process) are likely to incur losses on these particular default service contracts, as estimates of the potential migration were lower than the level of migration that was realized and the underlying cost to provide the incremental power rose above the contracted revenue rate. As a result of this customer migration, we incurred losses in 2022 and anticipate these losses will continue to have a negative impact on our East segment through the end of these default service contracts in mid-2023. With forward power and natural gas curves increasing materially in 2022, we have increased our hedging for future periods. As of December 31, 2022, we have hedged approximately 73% of our expected generation volumes on average for the three-year period 2023 to 2025 (with approximately 90% hedged for 2023 and approximately 76% hedged for 2024). Changes to the geopolitical situation and the inflationary environment, among other factors, have also created supply chain constraints that have reduced the availability and increased the costs of certain fuels, such as coal, reduced the availability of certain equipment and supply relevant to construction of renewables projects, and increased the lead time to procure certain materials necessary to maintain our natural gas, nuclear and coal fleet. We are proactively managing the increased costs of materials and supply chain disruptions and continuing to prudently re-evaluate the business cases and timing of our planned development projects, which has resulted in a deferral of some of our planned capital spend for our renewables projects from 2022 to 2023 and beyond. In addition, we have proactively engaged our suppliers to secure key materials needed to maintain our existing generation facilities prior to future planned outages, and our Vistra Zero operational and development projects are anticipated to benefit from the impact of the recently passed IRA. The inflationary environment has also led to, and is expected to cause further increases in, interest rates, resulting in increased refinancing or borrowing costs, including project financing for our development projects. Additionally, we have been monitoring, and will continue to closely monitor, developments of the Russia and Ukraine conflict, including sanctions (or potential sanctions) against Russian energy exports and Russian nuclear fuel supply and enrichment activities, as well as actions by Russia to limit energy deliveries, which may further impact commodity prices in Europe and globally. Our 2022 refueling has not been affected by the Russia and Ukraine conflict. We work with a diverse set of global nuclear fuel cycle suppliers to procure our nuclear fuel, and therefore, we expect to have enough nuclear fuel to support all our refueling needs through 2025. We are taking affirmative action by including mitigating strategies in our procurement portfolio to ensure we can secure the nuclear fuel needed to continue to operate our nuclear facility. If imports from Russia were restricted, U.S. merchant nuclear power generators could be challenged in their refueling operations in future years. Winter Storm Uri In February 2021, a severe winter storm with extremely cold temperatures affected much of the U.S., including Texas. This severe weather resulted in surging demand for power, gas supply shortages, operational challenges for generators, and a significant load shed event that was ordered by ERCOT beginning on February 15, 2021 and continuing through February 18, 2021. Winter Storm Uri had a material adverse impact on our results of operations and operating cash flows. 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 after taking into account approximately $544 million in securitization proceeds Vistra received 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. 54 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 received $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 were 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. The final financial impact of Winter Storm Uri continues to be subject to the outcome of litigation arising from the event. Vistra has taken 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. Dividend Program In November 2018, we announced that the Board had adopted a dividend program which we initiated in the first quarter of 2019. During the years ended December 31, 2022, 2021 and 2020, we paid dividends to common stockholders totaling $302 million, $290 million and $266 million, respectively. See Note 13 to the Financial Statements for more information about our dividend program. Share Repurchase Program In October 2021, we announced that the Board had authorized a 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. In August 2022, the Board authorized an incremental $1.25 billion for repurchases to bring the total authorized under the Share Repurchase Program to $3.25 billion. We expect to complete repurchases under the current $3.25 billion Share Repurchase Program by the end of 2023. $3.25 Billion Board Authorization Total Number of Shares Repurchased Average Price Paid Per Share Amount Paid for Shares Repurchased Amount Available for Additional Repurchases at the End of the Period Year Ended December 31, 2021 19,330,365 $ 21.16 $ 409 Year Ended December 31, 2022 78,470,547 23.40 1,836 Total repurchased through December 31, 2022 97,800,912 $ 22.96 $ 2,245 $ 1,005 January 1, 2023 through February 23, 2023 8,824,640 22.72 201 Total repurchased through February 23, 2023 106,625,552 $ 22.94 $ 2,446 $ 804 See Note 13 to the Financial Statements for more information concerning the Share Repurchase Program. Preferred Stock Offerings In October 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 above). 55 Table of Contents In December 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 have used and will continue to use an amount equal to the net proceeds from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments in accordance with the Green Finance Framework. See Note 13 to the Financial Statements for more information concerning the Series A Preferred Stock and the Series B Preferred Stock. 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 and higher margining requirements as a result of increasing power and natural gas prices have caused an increase in our consolidated net leverage, the Company remains committed to a strong balance sheet. See Note 10 to the Financial Statements for details of our debt activity and Note 9 to the Financial Statements for details of our accounts receivable financing. Vistra Operations Credit Agreement Amendments — In April 2022 and July 2022, the Vistra Operations Credit Agreement was amended to, among other things, (i) establish new classes of extended revolving credit commitments maturing in April 2027 in aggregate amounts of $2.8 billion and $725 million as of April 2022 and July 2022, respectively, (ii) appoint certain additional revolving letter of credit issuers, and (iii) require Vistra Operations to terminate at least $350 million in revolving commitments maturing April 29, 2027 by December 30, 2022 or earlier if Vistra Operations or any guarantor receives proceeds from any capital markets transaction whose primary purpose is designed to enhance the liquidity of Vistra Operations and its guarantors. In accordance with this requirement, effective December 30, 2022, Vistra Operations terminated $350 million in revolving commitments. After giving effect to the reduction, Vistra Operations has $3.175 billion of revolving credit commitments maturing in April 2027. See Note 10 to the Financial Statements for details of the Vistra Operations Credit Agreement amendments. Commodity-Linked Revolving Credit Facility — In February 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 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. In May 2022, June 2022 and October 2022, the Credit Agreement was amended to, among other things, (i) effect certain additions and reductions (as applicable) to the revolving commitments of certain lenders, and extend the maturity date thereof, (ii) modify certain pricing provisions, financial covenants and provisions related to the collateral, and (iii) adjust certain borrowing and repayment provisions, including the calculation of the borrowing base. See Note 10 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: 2022-2023 2023-2024 2024-2025 (average price per MW-day) RTO zone $ 50.00 $ 34.13 $ 28.92 ComEd zone 68.96 34.13 28.92 MAAC zone 95.79 49.49 49.49 EMAAC zone 97.86 49.49 54.95 ATSI zone 50.00 34.13 28.92 DEOK zone 71.69 34.13 96.24 56 Table of Contents Our capacity sales in PJM, net of purchases, aggregated by planning year and capacity type through planning year 2024-2025, are as follows: 2022-2023 2023-2024 2024-2025 East Segment Sunset Segment East Segment Sunset Segment East Segment Sunset Segment CP auction capacity sold, net (MW) 5,964 1,519 5,538 1,332 5,567 1,338 Bilateral capacity sold, net (MW) 311 124 343 — 400 — Total segment capacity sold, net (MW) 6,275 1,643 5,881 1,332 5,967 1,338 Average price per MW-day $ 64.46 $ 66.54 $ 38.45 $ 34.13 $ 36.80 $ 75.37 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 2022 - 2023 Price per kW-month $ 1.18 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 2024-2025, are as follows: East Segment Winter 2022 - 2023 Summer 2023 Winter 2023 - 2024 Summer 2024 Winter 2024 - 2025 Auction capacity sold (MW) 90 — — — — Bilateral capacity sold (MW) 1,094 936 670 299 100 Total capacity sold (MW) 1,184 936 670 299 100 Average price per kW-month $ 1.29 $ 2.86 $ 1.66 $ 2.00 $ 2.00 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: 2022-2023 2023-2024 2024-2025 2025-2026 Price per kW-month $ 3.80 $ 2.00 $ 2.61 $ 2.59 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 2022-2023 2023-2024 2024-2025 2025-2026 Auction capacity sold (MW) 3,125 3,091 2,967 3,032 Bilateral capacity sold (MW) 97 20 78 78 Total capacity sold (MW) 3,222 3,111 3,045 3,110 Average price per kW-month $ 3.82 $ 2.12 $ 3.18 $ 2.72 MISO — The capacity auction results for MISO Local Resource Zone 4, in which our assets are located, are as follows for each planning year: 2022-2023 Price per MW-day $ 236.66 57 Table of Contents MISO capacity sales through planning year 2025-2026 are as follows: Sunset Segment 2022-2023 2023-2024 2024-2025 2025-2026 Bilateral capacity sold in MISO (MW) 1,672 1,394 471 209 Total MISO segment capacity sold (MW) 1,672 1,394 471 209 Average price per kW-month $ 2.57 $ 4.54 $ 4.51 $ 5.19 CAISO — Our capacity sales in CAISO, aggregated by calendar year for 2023 through 2024 for Moss Landing, are as follows: West Segment 2023 2024 Bilateral capacity sold (Avg MW) 1,481 1,770 58 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. Natural gas 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 higher or lower wholesale electricity prices that have corresponded to increases or declines in natural gas prices. When natural gas prices are elevated or depressed, we continue to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward wholesale and retail electricity sales. 59 Table of Contents Estimated hedging levels for generation volumes in our Texas, East, West and Sunset segments as of December 31, 2022 were as follows: 2023 2024 Nuclear/Renewable/Coal Generation: Texas 94 % 86 % Sunset 88 % 47 % Gas Generation: Texas 83 % 58 % East 91 % 72 % West 91 % 79 % 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 as of December 31, 2022. 2023 2024 Texas: Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price $ 8 $ 16 Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power price $ (7) $ (16) Gas Generation: $1.00/MWh increase in spark spread $ 9 $ 19 Gas Generation: $1.00/MWh decrease in spark spread $ (8) $ (18) Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ 3 $ (12) Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price $ (7) $ 6 East: Gas Generation: $1.00/MWh increase in spark spread $ 6 $ 16 Gas Generation: $1.00/MWh decrease in spark spread $ (5) $ (14) Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ (4) $ (5) Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price $ 4 $ 5 West: Gas Generation: $1.00/MWh increase in spark spread $ 1 $ 1 Gas Generation: $1.00/MWh decrease in spark spread $ (1) $ (1) Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ 1 $ 1 Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price $ (1) $ (1) Sunset: Coal Generation: $2.50/MWh increase in power price $ 8 $ 33 Coal Generation: $2.50/MWh decrease in power price $ (7) $ (32) Residual Natural Gas Position: $0.25/MMBtu increase in natural gas price $ (6) $ (12) Residual Natural Gas Position: $0.25/MMBtu decrease in natural gas price $ 6 $ 12 60 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%, 3% and 1% in 2022, 2021 and 2020, respectively. Based upon December 31, 2022 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 $68 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 1,200 MW. As of December 31, 2022, 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 2023 at December 31, 2022) 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 12 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. 61 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. 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 operates 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. Critical Accounting Estimates 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 estimates 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. 62 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. Any significant changes to these inputs could result in a material change to the value of the assets or liabilities recorded on our consolidated balance sheets and could result in a material change to the unrealized gains or losses recorded in our consolidated statements of operations. We estimate fair value as described in Note 14 to the Financial Statements. Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections, which generally eliminate the requirement for mark-to-market recognition in net income. Normal purchases and sales (NPNS) 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 NPNS election is made and are accounted for on an accrual basis. Determining whether a contract qualifies for the normal purchase or sale election requires judgment as to whether or not the contract will physically deliver and requires that management ensure compliance with all associated qualification and documentation requirements. If it is determined that a transaction designated as a normal purchase or sale no longer meets the scope exception due to changes in estimates, the related contract would be recorded on the balance sheet at fair value with immediate recognition through earnings. See Note 15 to the Financial Statements for further discussion regarding derivative instruments. Accounting for Income Taxes 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. Further, we assess the likelihood that we will be able to realize or utilize our deferred tax assets. If realization is not more likely than not, we would record a valuation allowance against such deferred tax assets for the amount we would not expect to utilize, which would reduce the carrying value of the deferred tax amounts. When evaluating the need for a valuation allowance, we consider all available positive and negative evidence, including the following: • the creation and timing of future income associated with the reversal of deferred tax liabilities in excess of deferred tax assets; • the existence, or lack thereof, of statutory limitations on the period that net operating losses may be carried forward; and • the amounts and history of income or losses, adjusted for certain non-recurring items. 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 6 to the Financial Statements for further discussion of income tax matters. 63 Table of Contents Accounting for Tax Receivable Agreement (TRA) On the Effective Date, Vistra entered into 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, 2022, the TRA obligation has been adjusted to $522 million. During the year ended December 31, 2022, we recorded an increase to the carrying value of the TRA obligation totaling $64 million as a result of adjustments to forecasted book and taxable income due to increases in commodity price forecasts. As of December 31, 2022, 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. 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 7 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. These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, and remediation or closure of coal ash basins. In estimating the ARO liability, we are required to make significant estimates and assumptions. For the estimates and assumptions of the nuclear generation plant decommissioning, we use unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs (in current year dollars) and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates. Decommissioning cost studies are updated for each of our nuclear units at least every five years unless circumstances warrant a more frequent update. In estimating the liability for December 31, 2022, we have included an assumption that Vistra receives a license extension of 20 years from the NRC to continue to operate Comanche Peak Units 1 and 2 through 2050 and 2053, respectively. The costs to ultimately decommission the 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. 64 Table of Contents The estimates and assumptions required for the mining land reclamation related to lignite mining, such as costs to fill in mining pits and interpretation of the mining permit closure requirements, are complex and require a significant amount of judgment. To develop the estimate of 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. These obligations are adjusted on a regular basis to reflect the passage of time and to incorporate revisions to the following significant estimates and assumptions: • estimation of dates for retirement, which can be dependent on environmental and other legislation; • amounts and timing of future cash expenditures associated with retirement, settlement or remediation activities; • discount rates; • cost escalation factors; • market risk premium; • inflation rates; and • if applicable, past experience with government regulators regarding similar obligations. For the next five years, Vistra is projected to spend approximately $432 million (on a nominal basis) to achieve its mining reclamation and other coal ash remediation objectives. During the years ended December 31, 2022, 2021 and 2020, we transferred $61 million, zero and $15 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. See Note 20 to the Financial Statements for additional discussion of ARO obligations and adjustments made to the ARO obligation estimates during the years ended December 31, 2022, 2021 and 2020. 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 20 to the Financial Statements for discussion of impairments of long-lived assets recorded in the years ended December 31, 2022, 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. 65 Table of Contents Goodwill and intangible assets with indefinite useful lives, such as the intangible asset related to the trade names of TXU Energy TM , Ambit Energy, 4Change Energy TM , Homefield, Dynegy Energy Services, TriEagle Energy, Public Power and U.S. Gas & Electric, respectively, are required to be evaluated for impairment at least annually (we have selected October 1 as our annual impairment test date) or whenever events or changes in circumstances indicate an impairment may exist, such as the indicators used to evaluate impairments to long-lived assets discussed above or declines in values of comparable public companies in our industry. As of December 31, 2022, our goodwill balances totaled $2.461 billion and $122 million for our Retail reporting unit and Texas Generation reporting unit, respectively. Under this goodwill impairment analysis, if at the assessment date, a reporting unit’s carrying value exceeds its estimated fair value, the excess carrying value is written off as an impairment charge. 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 performed a qualitative assessment 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, 2022. Significant qualitative factors evaluated included reporting unit financial performance and market multiples, general macroeconomic, industry, and market conditions, cost factors, customer attrition, interest rates and changes in reporting unit book value. As of December 31, 2022, intangible assets with indefinite useful lives related to our retail trade names totaled $1.341 billion. Under this impairment analysis, if at the assessment date, a retail trade name's carrying value exceeds its estimated fair value, the excess carrying value is written off as an impairment charge. Accounting standards allow a company to qualitatively assess if the carrying value of our retail trade name intangible assets is more likely than not less than the fair value. On the most recent testing date, we performed a qualitative assessment and determined that it was more likely than not that the fair value of our retail trade names exceeded their carrying value at October 1, 2022. Significant qualitative factors evaluated included trade name financial performance, general macroeconomic, industry, and market conditions, customer attrition and interest rates. RESULTS OF OPERATIONS In the year ended December 31, 2022, our operating segments delivered strong operating performance with a disciplined focus on cost management, while generating and selling essential electricity in a safe and reliable manner. Our performance reflected the stability of our integrated model, including a diversified generation fleet, retail and commercial and hedging activities in support of our integrated business. As part of our comprehensive hedging strategy, we hedged longer-dated revenues and fuel costs to reduce risk and lock in value as forward power and gas curves moved up materially, and we believe this has positioned us to significantly benefit operating results in 2023 and beyond. In addition, we executed on our share repurchase strategy. 66 Table of Contents Vistra Consolidated Financial Results — Year Ended December 31, 2022 Compared to Year Ended December 31, 2021 Year Ended December 31, Favorable (Unfavorable) $ Change 2022 2021 Operating revenues $ 13,728 $ 12,077 $ 1,651 Fuel, purchased power costs and delivery fees (10,401) (9,169) (1,232) Operating costs (1,645) (1,559) (86) Depreciation and amortization (1,596) (1,753) 157 Selling, general and administrative expenses (1,189) (1,040) (149) Impairment of long-lived and other assets (74) (71) (3) Operating loss (1,177) (1,515) 338 Other income 117 140 (23) Other deductions (4) (16) 12 Interest expense and related charges (368) (384) 16 Impacts of Tax Receivable Agreement (128) 53 (181) Loss before income taxes (1,560) (1,722) 162 Income tax benefit 350 458 (108) Net loss $ (1,210) $ (1,264) $ 54 Year Ended December 31, 2022 Retail Texas East West Sunset Asset Closure Eliminations / Corporate and Other Vistra Consolidated Operating revenues $ 9,455 $ 3,733 $ 3,706 $ 336 $ 956 $ 296 $ (4,754) $ 13,728 Fuel, purchased power costs and delivery fees (7,169) (2,968) (3,546) (481) (743) (249) 4,755 (10,401) Operating costs (143) (808) (255) (42) (280) (116) (1) (1,645) Depreciation and amortization (145) (537) (706) (42) (76) (21) (69) (1,596) Selling, general and administrative expenses (826) (131) (66) (21) (39) (40) (66) (1,189) Impairment of long-lived and other assets — — — — (74) — — (74) Operating income (loss) 1,172 (711) (867) (250) (256) (130) (135) (1,177) Other income 2 78 2 6 — 16 13 117 Other deductions (2) (2) — — 1 (2) 1 (4) Interest expense and related charges (14) 20 (3) 6 (3) (3) (371) (368) Impacts of Tax Receivable Agreement — — — — — — (128) (128) Income (loss) before income taxes 1,158 (615) (868) (238) (258) (119) (620) (1,560) Income tax benefit — — — — — — 350 350 Net income (loss) $ 1,158 $ (615) $ (868) $ (238) $ (258) $ (119) $ (270) $ (1,210) 67 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 $ 653 $ 86 $ (2,284) $ 12,077 Fuel, purchased power costs and delivery fees (4,568) (3,991) (2,123) (253) (407) (111) 2,284 (9,169) Operating costs (127) (704) (243) (37) (254) (193) (1) (1,559) Depreciation and amortization (212) (608) (698) (60) (104) (35) (36) (1,753) Selling, general and administrative expenses (718) (88) (75) (32) (31) (50) (46) (1,040) Impairment of long-lived assets and other assets (33) — — — — (38) — (71) Operating income (loss) 2,213 (2,601) (552) (8) (143) (341) (83) (1,515) Other income 1 84 — — 6 44 5 140 Other deductions (7) (9) — — 3 (1) (2) (16) Interest expense and related charges (9) 14 (15) 9 (3) — (380) (384) Impacts of Tax Receivable Agreement — — — — — — 53 53 Income (loss) before income taxes 2,198 (2,512) (567) 1 (137) (298) (407) (1,722) Income tax benefit (expense) (2) — — — — — 460 458 Net income (loss) $ 2,196 $ (2,512) $ (567) $ 1 $ (137) $ (298) $ 53 $ (1,264) Consolidated operating loss decreased $338 million to $1.177 billion in the year ended December 31, 2022 compared to the year ended December 31, 2021. The change in results was primarily driven by the $2.2 billion negative impact on our pre-tax earnings associated with Winter Storm Uri in the year ended December 31, 2021. Partially offsetting the 2021 Winter Storm Uri impact, results for the year ended December 31, 2022 were unfavorably impacted by a $1.75 billion increase in pre-tax unrealized mark-to-market losses on derivative positions. Power and natural gas forward market curves moved up during the year ended December 31, 2022 driving the pre-tax unrealized mark-to-market losses on commodity hedging transactions. Included within these unrealized mark-to-market changes are pre-tax net unrealized losses of $544 million and $298 million recorded in the years ended December 31, 2022 and 2021, respectively, due to the discontinuance of NPNS accounting on retail electric contract portfolios where physical settlement is no longer considered probable throughout the contract term. We believe the overall increase in forward power and natural gas prices during 2022 has positioned us to significantly benefit operating results in 2023 and beyond. Interest expense and related charges decreased $16 million to $368 million in the year ended December 31, 2022 compared to the year ended December 31, 2021 driven by unrealized mark-to-market gains on interest rate swaps of $250 million in 2022 compared to $134 million in 2021 due to a more significant rise in interest rates in 2022. The favorable variance is partially offset by an increase in interest paid/accrued of $111 million driven by higher average borrowings during the year ended December 31, 2022 as compared to the year ended December 31, 2021, reflecting costs associated with increased collateral posting obligations supporting our comprehensive hedging strategy. See Note 20 to the Financial Statements. For the years ended December 31, 2022 and 2021, the impacts of the TRA totaled expense of $128 million and income of $53 million, respectively. See Note 7 to the Financial Statements for discussion of the impacts of the TRA obligation. For the year ended December 31, 2022, income tax benefit totaled $350 million and the effective tax rate was 22.4%. For the year ended December 31, 2021, income tax benefit totaled $458 million and the effective tax rate was 26.6%. See Note 6 to the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate. 68 Table of Contents 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. 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 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). Vistra Adjusted EBITDA — Year Ended December 31, 2022 Compared to Year Ended December 31, 2021 Year Ended December 31, Favorable (Unfavorable) $ Change 2022 2021 Net loss $ (1,210) $ (1,264) $ 54 Income tax benefit (350) (458) 108 Interest expense and related charges (a) 368 384 (16) Depreciation and amortization (b) 1,682 1,831 (149) EBITDA before Adjustments 490 493 (3) Unrealized net loss resulting from commodity hedging transactions (c) 2,510 759 1,751 Generation plant retirement expenses 4 18 (14) Fresh start/purchase accounting impacts 6 (138) 144 Impacts of Tax Receivable Agreement 128 (53) 181 Non-cash compensation expenses 65 51 14 Transition and merger expenses 13 (8) 21 Impairment of long-lived and other assets 74 71 3 Winter Storm Uri impacts (d) (319) 698 (1,017) Other, net 23 17 6 Adjusted EBITDA $ 2,994 $ 1,908 $ 1,086 ____________ (a) Includes unrealized mark-to-market net gains on interest rate swaps of $250 million and $134 million for the years ended December 31, 2022 and 2021, respectively. (b) Includes nuclear fuel amortization in the Texas segment of $86 million and $78 million for the years ended December 31, 2022 and 2021, respectively. 69 Table of Contents (c) Net pre-tax unrealized mark-to-market losses on commodity and hedging transactions were driven by an increase in power and natural gas price curves during the year ended December 31, 2022. Additionally, we recorded pre-tax net unrealized losses of $544 million and $298 million in the years ended December 31, 2022 and 2021, respectively, due to the discontinuance of NPNS accounting on retail electric contract portfolios where physical settlement is no longer considered probable throughout the contract term. (d) For the year ended December 31, 2021, includes the following of the Winter Storm Uri impacts, which we believe are not reflective of our normal operating performance: the allocation of ERCOT default uplift charges which were expected to be paid over several decades under protocols existing at the time of the storm, accrual of Koch earn-out amounts that we paid in the second quarter of 2022 (see Note 12 to the Financial Statements), future bill credits related to Winter Storm Uri and Winter Storm Uri related legal fees and other costs. For the year ended December 31, 2022, includes reductions to Adjusted EBITDA reflecting ERCOT default uplift charges of $183 million and bill credit applications of $144 million. The adjustment for ERCOT default uplift charges relates to (i) ERCOT receiving payments that reduced the market wide default balance and (ii) the fourth quarter 2022 derecognition of the remaining default balance in connection with a settlement between Brazos and ERCOT (see Note 12 to the Financial Statements). 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. 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. Year Ended December 31, 2022 Retail Texas East West Sunset Asset Closure Eliminations / Corporate and Other Vistra Consolidated Net income (loss) $ 1,158 $ (615) $ (868) $ (238) $ (258) $ (119) $ (270) $ (1,210) Income tax benefit — — — — — — (350) (350) Interest expense and related charges (a) 14 (20) 3 (6) 3 3 371 368 Depreciation and amortization (b) 145 623 706 42 76 21 69 1,682 EBITDA before Adjustments 1,317 (12) (159) (202) (179) (95) (180) 490 Unrealized net (gain) loss resulting from commodity hedging transactions (291) 1,610 759 351 112 (31) — 2,510 Generation plant retirement expenses — — — — 7 (3) — 4 Fresh start/purchase accounting impacts — (2) (1) — 9 — — 6 Impacts of Tax Receivable Agreement — — — — — — 128 128 Non-cash compensation expenses — — — — — — 65 65 Transition and merger expenses 7 — 1 — — — 5 13 Impairment of long-lived and other assets — — — — 74 — — 74 Winter Storm Uri impacts (c) (141) (178) — — — — — (319) Other, net 31 20 8 3 15 8 (62) 23 Adjusted EBITDA $ 923 $ 1,438 $ 608 $ 152 $ 38 $ (121) $ (44) $ 2,994 ____________ (a) Includes $250 million of unrealized mark-to-market net gains on interest rate swaps. (b) Includes nuclear fuel amortization of $86 million in the Texas segment. (c) Includes the application of bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri and a reduction in the allocation of ERCOT default uplift charges which were expected to be paid over several decades under protocols existing at the time of the storm. We estimate remaining bill credit amounts to be applied in future periods are for 2023 (approximately $54 million), 2024 (approximately $6 million) and 2025 (approximately $28 million). 70 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 (137) (298) 53 $ (1,264) Income tax expense (benefit) 2 — — — — — (460) (458) Interest expense and related charges (a) 9 (14) 15 (9) 3 — 380 384 Depreciation and amortization (b) 212 686 698 60 104 35 36 1,831 EBITDA before Adjustments 2,419 (1,840) 146 52 (30) (263) 9 493 Unrealized net (gain) loss resulting from commodity hedging transactions (1,403) 1,139 655 38 211 119 — 759 Generation plant retirement expenses — — — — (1) 19 — 18 Fresh start/purchase accounting impacts 2 (14) (74) — (28) (24) — (138) Impacts of Tax Receivable Agreement — — — — — — (53) (53) Non-cash compensation expenses — — — — — — 51 51 Transition and merger expenses (2) — — — — (15) 9 (8) Impairment of long-lived and other assets 33 — — — — 38 — 71 Winter Storm Uri (c) 239 457 — — 1 — 1 698 Other, net 24 22 10 3 (5) 5 (42) 17 Adjusted EBITDA $ 1,312 $ (236) $ 737 $ 93 $ 148 $ (121) $ (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 the following of the Winter Storm Uri impacts, which we believe are not reflective of our operating performance: the allocation of ERCOT default uplift charges which were expected to be paid over several decades under protocols existing at the time of the storm, accrual of Koch earn-out amounts that we paid in the second quarter of 2022, future bill credits related to Winter Storm Uri 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 reverse and impact Adjusted EBITDA in future periods as the credits are applied to customer bills. 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. 71 Table of Contents Retail Segment — Year Ended December 31, 2022 Compared to Year Ended December 31, 2021 Year Ended December 31, Favorable (Unfavorable) Change 2022 2021 Operating revenues: Revenues in ERCOT $ 7,684 $ 5,943 $ 1,741 Revenues in Northeast/Midwest 2,303 2,255 48 Amortization expense — (2) 2 Unrealized net losses on hedging activities (a) (532) (325) (207) Total operating revenues $ 9,455 $ 7,871 $ 1,584 Fuel, purchased power costs and delivery fees: Purchases from affiliates (5,572) (4,002) (1,570) Unrealized net gains on hedging activities with affiliates (b) 819 1,719 (900) Unrealized net gains on hedging activities 4 9 (5) Delivery fees (2,285) (1,937) (348) Other costs (c) (135) (357) 222 Total fuel, purchased power costs and delivery fees $ (7,169) $ (4,568) $ (2,601) Net income $ 1,158 $ 2,196 $ (1,038) Adjusted EBITDA $ 923 $ 1,312 $ (389) Retail sales volumes (GWh): Retail electricity sales volumes: Sales volumes in ERCOT 65,207 57,033 8,174 Sales volumes in Northeast/Midwest 32,882 36,070 (3,188) Total retail electricity sales volumes 98,089 93,103 4,986 Weather (North Texas average) - percent of normal (d): Cooling degree days 111 % 93 % Heating degree days 108 % 92 % ____________ (a) Includes pre-tax unrealized net losses of $544 million and $298 million for the years ended December 31, 2022 and 2021, recognized due to the discontinuance of NPNS accounting on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract term. (b) Includes unrealized net gains/(losses) from mark-to-market valuations of commodity positions with the Texas, East and Sunset segments. (c) For the year ended December 31, 2021, includes $153 million of future bill credits to large commercial and industrial customers. (d) Reflects cooling degree or heating degree days for the region based on Weather Services International (WSI) data. 72 Table of Contents The following table presents changes in net income (loss) and Adjusted EBITDA for the year ended December 31, 2022 compared to the year ended December 31, 2021. Year Ended December 31, 2022 Compared to 2021 Timing of power costs, including self-help gains in 2021 and multi-year customer contracts in a backwardated market $ (248) Winter Storm Uri impact primarily driven by 2022 bill credits issued exceeding the net impact of the storm in 2021 (63) Higher margins reflecting favorable weather in 2022 and ERCOT performance, partially offset by pressure in Midwest and Northeast markets 30 Other primarily driven by higher bad debt expense due to higher revenues in 2022 (108) Change in Adjusted EBITDA $ (389) Decrease in unrealized net gains on hedging activities (1,112) Bill credits and other costs related to Winter Storm Uri 380 Decrease in depreciation and amortization expenses 67 Change in transition and merger and other expenses 16 Change in Net income $ (1,038) 73 Table of Contents Generation — Year Ended December 31, 2022 Compared to Year Ended December 31, 2021 Year Ended December 31, Texas East West Sunset 2022 2021 2022 2021 2022 2021 2022 2021 Operating revenues: Electricity sales $ 1,816 $ 1,999 $ 2,719 $ 1,619 $ 653 $ 410 $ 448 $ 589 Capacity revenue from ISO/RTO — — 20 (22) — 1 63 138 Sales to affiliates 3,389 2,063 1,724 1,553 7 5 454 382 Rolloff of unrealized net gains (losses) representing positions settled in the current period 536 (207) (50) (159) 96 62 422 166 Unrealized net gains (losses) on hedging activities (1,191) (37) (669) 51 (422) (104) (459) (448) Unrealized net gains (losses) on hedging activities with affiliates (817) (1,028) (38) (529) 2 — 34 (162) Other revenues — — — 74 — — (6) (12) Operating revenues 3,733 2,790 3,706 2,587 336 374 956 653 Fuel, purchased power costs and delivery fees: Fuel for generation facilities and purchased power costs (2,495) (2,829) (3,509) (2,072) (449) (251) (630) (629) Fuel for generation facilities and purchased power costs from affiliates (8) — 2 2 — — 4 (3) Unrealized (gains) losses from hedging activities (138) 133 (2) (18) (27) 4 (109) 233 Ancillary and other costs (327) (1,295) (37) (35) (5) (6) (8) (8) Fuel, purchased power costs and delivery fees (2,968) (3,991) (3,546) (2,123) (481) (253) (743) (407) Net income (loss) $ (615) $ (2,512) $ (868) $ (567) $ (238) $ 1 $ (258) $ (137) Adjusted EBITDA $ 1,438 $ (236) $ 608 $ 737 $ 152 $ 93 $ 38 $ 148 Production volumes (GWh): Natural gas facilities 34,784 30,921 54,569 55,428 5,134 5,365 Lignite and coal facilities 25,211 25,514 24,555 27,247 Nuclear facilities 19,688 19,402 Solar facilities 822 454 Capacity factors: CCGT facilities 48.8 % 43.2 % 57.2 % 57.6 % 57.1 % 60.0 % Lignite and coal facilities 74.8 % 75.6 % 54.3 % 60.2 % Nuclear facilities 93.6 % 96.3 % Weather - percent of normal (a): Cooling degree days 109 % 94 % 107 % 108 % 107 % 90 % 113 % 115 % Heating degree days 123 % 94 % 99 % 93 % 109 % 111 % 99 % 90 % ____________ (a) Reflects cooling degree days or heating degree days for the region based on Weather Services International (WSI) data. 74 Table of Contents Year Ended December 31, Year Ended December 31, 2022 2021 2022 2021 Market pricing Average Market On-Peak Power Prices ($MWh) (b): Average ERCOT North power price ($/MWh) $ 62.17 $ 149.60 PJM West Hub $ 83.59 $ 45.55 AEP Dayton Hub $ 79.51 $ 44.81 Average NYMEX Henry Hub natural gas price ($/MMBtu) $ 6.39 $ 3.82 NYISO Zone C $ 65.54 $ 35.57 Massachusetts Hub $ 92.17 $ 51.77 Average natural gas price (a): Indiana Hub $ 82.03 $ 48.55 TetcoM3 ($/MMBtu) $ 6.81 $ 3.40 Northern Illinois Hub $ 71.76 $ 41.10 Algonquin Citygates ($/MMBtu) $ 9.16 $ 4.51 CAISO NP15 $ 93.12 $ 56.37 ____________ (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, 2022 compared to the year ended December 31, 2021. Year Ended December 31, 2022 Compared to 2021 Texas East West Sunset Favorable/(unfavorable) change in revenue net of fuel $ 309 $ (76) $ 49 $ (45) Winter Storm Uri impact 1,535 (50) — (17) Unfavorable change in other operating costs (114) (12) (6) (38) Favorable/(unfavorable) change in selling, general and administrative expenses (37) 9 16 (15) Other (19) — — 5 Change in Adjusted EBITDA $ 1,674 $ (129) $ 59 $ (110) Favorable/(unfavorable) change in depreciation and amortization 63 (8) 18 28 Change in unrealized net gains/(losses) on hedging activities (471) (104) (313) 99 Impairment of long-lived and other assets — — — (74) Generation plant retirement, transition and merger expenses — (1) — (8) Fresh start/purchase accounting impacts (12) (73) — (37) Winter Storm Uri impact (ERCOT default uplift and legal disputes) 635 — — 1 Other (including interest and COVID-19 related expenses) 8 14 (3) (20) Change in Net income (loss) $ 1,897 $ (301) $ (239) $ (121) The change in Texas segment results was primarily driven by the Winter Storm Uri impacts in 2021. The increases in revenue net of fuel and operating costs are due to strong generation fleet performance during periods of higher pricing and inflationary pressures, respectively, in the year ended December 31, 2022. Additionally, unrealized hedging losses increased in the year ended December 31, 2022 compared to the year ended December 31, 2021 due to increases in forward power prices in the year ended December 31, 2022. The change in East segment results was primarily driven by (i) higher unrealized hedging losses in the year ended December 31, 2022 compared to the year ended December 31, 2021 due to increases in forward power prices in the year ended December 31, 2022 (ii) lower revenue net of fuel in the year ended December 31, 2022 compared to the year ended December 31, 2021 due primarily to higher-than-expected migration of customers to default service providers at rates below prevailing wholesale market prices and lower capacity revenue and (iii) termination of an unfavorable acquired contract in 2021 which resulted in derecognition of an intangible liability. 75 Table of Contents The change in West segment results was driven by higher unrealized hedging losses in the year ended December 31, 2022 as compared to the year ended December 31, 2021 as forward power prices increased more in the year ended December 31, 2022 compared to the year ended December 31, 2021. Additionally, revenue net of fuel is higher in the year ended December 31, 2022 as compared to the year ended December 31, 2021 reflecting higher realized margins from our battery ESS projects (see Note 2 to the Financial Statements). The change in Sunset segment results was driven by an unfavorable change in revenue net of fuel due primarily to lower generation volumes from coal plants due to industry-wide fuel delivery challenges in the year ended December 31, 2022 and the impairment of assets related to our Miami Fort generation facility (see Note 20 to the Financial Statements). Asset Closure Segment — Year Ended December 31, 2022 Compared to Year Ended December 31, 2021 Year Ended December 31, Favorable (Unfavorable) Change 2022 2021 Operating revenues $ 296 $ 86 $ 210 Fuel, purchased power costs and delivery fees (249) (111) (138) Operating costs (116) (193) 77 Depreciation and amortization (21) (35) 14 Selling, general and administrative expenses (40) (50) 10 Impairment of long-lived assets — (38) 38 Operating loss (130) (341) 211 Other income 16 44 (28) Other deductions (2) (1) (1) Interest expense and related charges (3) — (3) Income (loss) before income taxes (119) (298) 179 Net loss $ (119) $ (298) $ 179 Adjusted EBITDA $ (121) $ (121) $ — Production volumes (GWh) 6,670 9,706 (3,036) Results and volumes for the Asset Closure segment include those from the Zimmer and Joppa generation plants that we retired in May 2022 and September 2022, respectively. Operating costs for the years ended December 31, 2022 and 2021 also include ongoing costs associated with the decommissioning and reclamation of retired plants and mines. The change in Asset Closure segment results for the year ended December 31, 2022 is primarily due to (i) unrealized hedging gains of $31 million related to coal and power derivatives in the year ended December 31, 2022 compared to unrealized losses of $119 million in the year ended December 31, 2021 and (ii) severance and impairment expense recorded in the year ended December 31, 2021, in connection with plant closure announcements (see Note 3 to the Financial Statements). 76 Table of Contents 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, 2022 and 2021. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $2.51 billion and $759 million in unrealized net losses for the years ended December 31, 2022 and 2021, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio. Year Ended December 31, 2022 2021 Commodity contract net liability at beginning of period $ (866) $ (75) Settlements/termination of positions (a) 1,218 (295) Changes in fair value of positions in the portfolio (b) (3,728) (464) Other activity (c) 228 (32) Commodity contract net liability at end of period $ (3,148) $ (866) ____________ (a) Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period). Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month. (b) Represents unrealized net gains (losses) recognized, reflecting the effect of changes in fair value. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month. (c) 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, 2022, 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, 2022 Source of fair value Less than 1 year 1-3 years 4-5 years Excess of 5 years Total Prices actively quoted $ (1,136) $ (651) $ 2 $ — $ (1,785) Prices provided by other external sources (11) (133) — — (144) Prices based on models (321) (592) (205) (101) (1,219) Total $ (1,468) $ (1,376) $ (203) $ (101) $ (3,148) FINANCIAL CONDITION Operating Cash Flows Year Ended December 31, 2022 Compared to Year Ended December 31, 2021 — Cash provided by operating activities totaled $485 million in the year ended December 31, 2022 compared to cash used in operating activities of $206 million in the year ended December 31, 2021. The favorable change of $691 million was primarily driven by lower cash from operations in 2021 due to Winter Storm Uri impacts and $544 million of securitization proceeds from ERCOT in 2022 (see Note 1 to the Financial Statements), partially offset by margin deposits of $1.874 billion in 2022 as compared to $1.0 billion in 2021 related to commodity contracts which support our comprehensive hedging strategy. 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 $451 million, $297 million and $311 million for the year ended December 31, 2022, 2021 and 2020, 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. 77 Table of Contents Investing Cash Flows Year Ended December 31, 2022 Compared to Year Ended December 31, 2021 — Cash used in investing activities totaled $1.239 billion and $1.153 billion in the years ended December 31, 2022 and 2021, respectively. The increase of $86 million was driven by a $268 million increase in capital expenditures and $50 million in lower insurance proceeds received, partially offset by $185 million in lower net purchases of environmental allowances and $57 million in proceeds from the sale of nuclear fuel. Year Ended December 31, Increase (Decrease) 2022 2021 Capital expenditures, including LTSA prepayments $ (628) $ (549) (79) Nuclear fuel purchases (198) (44) (154) Growth and development expenditures (475) (440) (35) Total capital expenditures (1,301) (1,033) (268) Net sales (purchases) of environmental allowances (28) (213) 185 Net sales of (investments in) nuclear decommissioning trust fund securities (23) (22) (1) Insurance proceeds related to capital activity 39 89 (50) Proceeds from sale of nuclear fuel 57 — 57 Other investing activity 17 26 (9) Cash used in investing activities $ (1,239) $ (1,153) $ (86) Financing Cash Flows Year Ended December 31, 2022 Compared to Year Ended December 31, 2021 — Cash used in financing activities totaled $80 million in the year ended December 31, 2022 compared to cash provided by financing activities of $2.274 billion in the year ended December 31, 2021. The change of $2.354 billion was driven by the issuance of preferred stock in 2021 and higher share repurchases in 2022, partially offset by increases in net borrowings under our accounts receivable financing facilities and net short-term borrowings in 2022. Year Ended December 31, Increase (Decrease) 2022 2021 Issuances of preferred stock in 2021 $ — $ 2,000 $ (2,000) Share repurchases (1,949) (471) (1,478) Other net borrowings (repayments), including the forward capacity agreements (251) 119 (370) Dividends paid to common stockholders (302) (290) (12) Dividends paid to preferred stockholders (151) — (151) Issuance of senior secured (2022) and senior unsecured (2021) notes 1,498 1,250 248 Net borrowings (repayments) under the accounts receivable financing facilities 425 (300) 725 Net short-term borrowings (repayments) 650 — 650 Other financing activity — (34) 34 Cash provided by (used in) financing activities $ (80) $ 2,274 $ (2,354) Debt Activity See Note 9 to the Financial Statements for details of the Receivables Facility and Repurchase Facility and Note 10 to the Financial Statements for details of the Vistra Operations Credit Facilities, the Commodity-Linked Facility and other long-term debt. 78 Table of Contents Available Liquidity The following table summarizes changes in available liquidity for the year ended December 31, 2022: December 31, 2022 December 31, 2021 Change Cash and cash equivalents $ 455 $ 1,325 $ (870) Vistra Operations Credit Facilities — Revolving Credit Facility 1,236 1,254 (18) Vistra Operations — Commodity-Linked Facility (a) 808 — 808 Total available liquidity (b) $ 2,499 $ 2,579 $ (80) ____________ (a) As of December 31, 2022, available capacity reflects the borrowing base of $1.208 billion less $400 million in cash borrowings. The borrowing base is less than the facility limit of $1.35 billion. (b) Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See Note 9 to the Financial Statements for detail on our accounts receivable financing. The $80 million decrease in available liquidity for the year ended December 31, 2022 was primarily driven by $1.949 billion in cash paid for share repurchases, $1.301 billion of capital expenditures (including LTSA prepayments, nuclear fuel and development and growth expenditures), a $418 million increase in letters of credit outstanding under the Revolving Credit Facility, $302 million in dividends paid to common stockholders and $151 million in dividends paid to preferred stockholders, partially offset by cash provided by operations, cash received from the issuance of $1.5 billion principal amount of Vistra Operations senior secured notes issued, $808 million in available capacity under the Commodity-Linked Facility under the aggregate commitments in effect as of December 31, 2022, $650 million in additional aggregate commitments under the Revolving Credit Facility resulting from the Credit Agreement Amendments and $425 million in net cash borrowings under the accounts receivable financing facilities. We believe that we will have access to 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. Higher commodity market prices combined with our comprehensive hedging strategy have resulted in significantly increased collateral posting obligations during the year ended December 31, 2022. The majority of this collateral relates to hedges in place through 2023 and is expected to be returned as we satisfy our obligations under those contracts. As of February 23, 2023, Vistra had approximately $2.8 billion of cash and availability under its credit facilities to meet its liquidity needs. The Company believes it has 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. The maturities of our long-term debt are relatively modest until 2024. Interest payments on long-term debt are expected to total approximately $596 million in 2023, $1.082 billion in 2024-2025, $552 million in 2026-2027 and $165 million thereafter. See Note 10 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 $3.174 billion in 2023, $2.098 billion in 2024-2025, $919 million in 2026-2027 and $406 million thereafter. See Note 11 to the Financial Statements for maturities of lease liabilities and Note 12 to the Financial Statements for commitments related to long-term service and maintenance contracts. Capital Expenditures Estimated 2023 capital expenditures and nuclear fuel purchases as of November 4, 2022 total approximately $2.023 billion and include: • $977 billion for solar and energy storage development; • $744 million for investments in generation and mining facilities; • $139 million for nuclear fuel purchases; • $12 million for plant winterization investment, information technology and other corporate investments; and • $151 million for other growth expenditures. 79 Table of Contents 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 10 to the Financial Statements for discussion of the Vistra Operations Credit Facilities and the Commodity-Linked Facility. 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, 2022, we received or posted cash and letters of credit for commodity hedging and trading activities as follows: • $3.137 billion in cash has been posted with counterparties as compared to $1.263 billion posted at December 31, 2021; • $39 million in cash has been received from counterparties as compared to $39 million received at December 31, 2021; • $2.314 billion in letters of credit have been posted with counterparties as compared to $1.558 billion posted at December 31, 2021; and • $74 million in letters of credit have been received from counterparties as compared to $35 million received at December 31, 2021. See Collateral Support Obligations below for information related to collateral posted in accordance with the PUCT and ISO/RTO rules. Income Tax Payments In the next 12 months, we do not expect to make federal income tax payments due to Vistra's NOL carryforwards. We expect to make approximately $27 million in state income tax payments, offset by $13 million in state tax refunds, and $8 million in TRA payments in the next 12 months. For the year ended December 31, 2022, there was $1 million in federal income tax payments, $33 million in state income tax payments, $8 million in state income tax refunds and $1 million in TRA payments. Capitalization Our capitalization ratios consisted of 71% and 56% long-term debt (less amounts due currently) and 29% and 44% stockholders' equity at December 31, 2022 and 2021, respectively. Total long-term debt (including amounts due currently) to capitalization was 71% and 56% at December 31, 2022 and 2021, respectively. 80 Table of Contents Financial Covenants The Vistra Operations Credit Agreement and the Vistra Operations Commodity-Linked Credit Agreement each includes a covenant, solely with respect to the Revolving Credit Facility and the Commodity-Linked Facility and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit exceed 30% of the revolving commitments, provided that solely with respect to the Revolving Credit Facility only such amounts in excess of $300 million are taken into account for purposes of determining whether a compliance period is in effect), that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, during a collateral suspension period, not to exceed 5.50 to 1.00). In addition, each of the Secured LOC Facilities includes a covenant that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, for certain facilities that include a collateral suspension mechanism, during a collateral suspension period, not to exceed 5.50 to 1.00). As of December 31, 2022, we were in compliance with the Vistra Operations Credit Agreement and Secured LOC Facilities financial covenants. Although the period ended December 31, 2022 was not a compliance period for the Vistra Operations Commodity-Linked Credit Agreement, we would have been in compliance with this financial covenant if it was required to be tested at such time. See Note 10 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, 2022, 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 $525 million in the form of letters of credit, $30 million in the form of a surety bond and $17 million of cash at December 31, 2022 (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 $2.764 billion at December 31, 2022. 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. 81 Table of Contents 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 Commodity-Linked Facility 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 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 12 to the Financial Statements for discussion of guarantees. COMMITMENTS AND CONTINGENCIES See Note 12 to the Financial Statements for discussion of commitments and contingencies. CHANGES IN ACCOUNTING STANDARDS See Note 1 to the Financial Statements for discussion of changes in accounting standards.