Vistra Corp. 10-K

vistra-20221231 Table of Contents UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31 , 2022 — OR — ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __ to __ Commission File Number 001-38086 Vistra Corp. (Exact name of registrant as specified in its charter) Delaware 36-4833255 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.) 6555 Sierra Drive Irving, Texas 75039 (214) 812-4600 (Address of principal executive offices) (Zip Code) (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Trading Symbol(s) Name of Each Exchange on Which Registered Common stock, par value $0.01 per share VST New York Stock Exchange Warrants VST.WS.A New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐ Indicated by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ Table of Contents Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ As of June 30, 2022, the aggregate market value of the Vistra Corp. common stock held by non-affiliates of the registrant was $ 9,583,092,896 based on the closing sale price as reported on the New York Stock Exchange. As of February 23, 2023, there were 381,453,001 shares of common stock, par value $0.01, outstanding of Vistra Corp. DOCUMENTS INCORPORATED BY REFERENCE Portions of the proxy statement for the registrant's 2023 annual meeting of stockholders are incorporated in Part III of this annual report on Form 10-K. Table of Contents TABLE OF CONTENTS PAGE Glossary ii PART I. Item 1. BUSINESS 1 Item 1A. RISK FACTORS 19 Item 1B. UNRESOLVED STAFF COMMENTS 46 Item 2. PROPERTIES 46 Item 3. LEGAL PROCEEDINGS 49 Item 4. MINE SAFETY DISCLOSURES 49 PART II. Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 50 Item 6. [RESERVED] 51 Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 51 Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 82 Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 89 Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 167 Item 9A. CONTROLS AND PROCEDURES 167 Item 9B. OTHER INFORMATION 168 Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTION 168 PART III. Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 169 Item 11. EXECUTIVE COMPENSATION 169 Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 169 Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 169 Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES 169 PART IV. Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 170 Item 16. FORM 10-K SUMMARY 187 Signatures 188 Vistra Corp.'s (Vistra) annual reports, quarterly reports, current reports and any amendments to those reports are made available to the public, free of charge, on the Vistra website at http://www.vistracorp.com , as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended. Additionally, Vistra posts important information, including press releases, investor presentations, sustainability reports, and notices of upcoming events on its website and utilizes its website as a channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under Regulation FD. Investors may be notified of posting to the website by signing up for email alerts and RSS feeds on the "Investor Relations" page of Vistra's website. The information on Vistra's website shall not be deemed a part of, or incorporated by reference into, this annual report on Form 10-K. The representations and warranties contained in any agreement that we have filed as an exhibit to this annual report on Form 10-K, or that we have or may publicly file in the future, may contain representations and warranties that may (i) be made by and to the parties thereto at specific dates, (ii) be subject to exceptions and qualifications contained in separate disclosure schedules, (iii) represent the parties' risk allocation in the particular transaction, or (iv) be qualified by materiality standards that differ from what may be viewed as material for securities law purposes. This annual report on Form 10-K and other Securities and Exchange Commission filings of Vistra and its subsidiaries occasionally make references to Vistra (or "we," "our," "us" or "the Company"), Luminant, TXU Energy, Ambit, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power or U.S. Gas & Electric, when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with, or otherwise reflected in, the Vistra financial statements for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or vice versa. i Table of Contents GLOSSARY When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below. 2021 Form 10-K Vistra's annual report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 25, 2022 Ambit Ambit Holdings, LLC, and/or its subsidiaries (d/b/a Ambit), depending on context Ambit Transaction the acquisition of Ambit by an indirect, wholly owned subsidiary of Vistra on November 1, 2019 (Ambit Acquisition Date) ARO asset retirement and mining reclamation obligation CAA Clean Air Act CAISO The California Independent System Operator CARES Act Coronavirus Aid, Relief, and Economic Security Act CCGT combined cycle gas turbine CCR coal combustion residuals CFTC U.S. Commodity Futures Trading Commission Chapter 11 Cases Cases in the U.S. Bankruptcy Court for the District of Delaware (Bankruptcy Court) concerning voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code (Bankruptcy Code) filed on April 29, 2014 (Petition Date) by Energy Future Holdings Corp. (EFH Corp.) and the majority of its direct and indirect subsidiaries, including Energy Future Intermediate Holding Company LLC, Energy Future Competitive Holdings Company LLC and TCEH but excluding Oncor Electric Delivery Holdings Company LLC and its direct and indirect subsidiaries (Debtors). On October 3, 2016 (Effective Date), subsidiaries of TCEH that were Debtors in the Chapter 11 Cases (TCEH Debtors), along with certain other Debtors that became subsidiaries of Vistra on that date (Contributed EFH Debtors), completed their reorganization under the Bankruptcy Code and emerged from the Chapter 11 Cases as subsidiaries of a newly formed company, Vistra (Emergence). CME Chicago Mercantile Exchange CO 2 carbon dioxide CPUC California Public Utilities Commission Crius Crius Energy Trust and/or its subsidiaries, depending on context Crius Transaction the acquisition of equity interests of two wholly owned subsidiaries of Crius that indirectly owned the operating business of Crius by an indirect, wholly owned subsidiary of Vistra on July 15, 2019 (Crius Acquisition Date) CT combustion turbine Dynegy Dynegy Inc., and/or its subsidiaries, depending on context Dynegy Energy Services Dynegy Energy Services, LLC and Dynegy Energy Services (East), LLC (each d/b/a Dynegy, Better Buy Energy, Brighten Energy, Honor Energy and True Fit Energy), indirect, wholly owned subsidiaries of Vistra, that are REPs in certain areas of MISO and PJM, respectively, and are engaged in the retail sale of electricity to residential and business customers. EBITDA earnings (net income) before interest expense, income taxes, depreciation and amortization ESG environmental, social and governance EPA U.S. Environmental Protection Agency ERCOT Electric Reliability Council of Texas, Inc. ESS energy storage system Exchange Act Securities Exchange Act of 1934, as amended FERC U.S. Federal Energy Regulatory Commission Fitch Fitch Ratings Inc. (a credit rating agency) FTC Federal Trade Commission GAAP generally accepted accounting principles GHG greenhouse gas GWh gigawatt-hours ii Table of Contents Green Finance Framework Framework adopted by the Company and made available on its website pursuant to which the Company may issue financial instruments to fund new or existing projects that support renewable energy and energy efficiency, with alignment to the Company's environmental, social, and governance strategy Homefield Energy Illinois Power Marketing Company (d/b/a Homefield Energy), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of MISO that is engaged in the retail sale of electricity to municipal customers ICE Intercontinental Exchange IEPA Illinois Environmental Protection Agency IPCB Illinois Pollution Control Board IRC Internal Revenue Code of 1986, as amended IRS U.S. Internal Revenue Service ISO independent system operator ISO-NE ISO New England Inc. kW kilowatt LIBOR London Interbank Offered Rate, an interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market load demand for electricity LTSA long-term service agreements for plant maintenance Luminant subsidiaries of Vistra engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management market heat rate Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier (generally natural gas plants), by the market price of natural gas. Merger the merger of Dynegy with and into Vistra, with Vistra as the surviving corporation Merger Date April 9, 2018, the date Vistra and Dynegy completed the transactions contemplated by the Agreement and Plan of Merger, dated as of October 29, 2019, by and between Vistra and Dynegy MISO Midcontinent Independent System Operator, Inc. MMBtu million British thermal units Moody's Moody's Investors Service, Inc. (a credit rating agency) MSHA U.S. Mine Safety and Health Administration MW megawatts MWh megawatt-hours NELP Northeast Energy, LP, a joint venture between Dynegy Northeast Generation GP, Inc. and Dynegy Northeast Associates LP, Inc., both indirect subsidiaries of Vistra, and certain subsidiaries of NextEra Energy, Inc. Prior to the NELP Transaction, NELP indirectly owned Bellingham NEA facility and the Sayreville facility. NELP Transaction a transaction among Dynegy Northeast Generation GP, Inc., Dynegy Northeast Associates LP, Inc. and certain subsidiaries of NextEra Energy, Inc. wherein the indirect subsidiaries of Vistra redeemed their ownership interest in NELP partnership in exchange for 100% ownership interest in NJEA, the entity which owns the Sayreville facility NERC North American Electric Reliability Corporation NJEA North Jersey Energy Associates, A Limited Partnership NO X nitrogen oxide NRC U.S. Nuclear Regulatory Commission NYISO New York Independent System Operator, Inc. NYMEX the New York Mercantile Exchange, a commodity derivatives exchange NYSE New York Stock Exchange iii Table of Contents Oncor Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings and formerly an indirect subsidiary of EFH Corp., that is engaged in regulated electricity transmission and distribution activities OPEB postretirement employee benefits other than pensions Parent Vistra Corp. PJM PJM Interconnection, LLC Plan of Reorganization Third Amended Joint Plan of Reorganization filed by the Debtors in August 2016 and confirmed by the Bankruptcy Court in August 2016 solely with respect to the TCEH Debtors and the Contributed EFH Debtors PrefCo Vistra Preferred Inc. PrefCo Preferred Stock Sale as part of the Spin-Off, the contribution of certain of the assets of the Predecessor and its subsidiaries by a subsidiary of TEX Energy LLC to PrefCo in exchange for all of PrefCo's authorized preferred stock, consisting of 70,000 shares, par value $0.01 per share Public Power Public Power, LLC (d/b/a Public Power), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of PJM, ISO-NE, NYISO and MISO that is engaged in the retail sale of electricity to residential and business customers PUCT Public Utility Commission of Texas PURA Texas Public Utility Regulatory Act REP retail electric provider RCT Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas, and has jurisdiction over oil and natural gas exploration and production, permitting and inspecting intrastate pipelines, and overseeing natural gas utility rates and compliance RTO regional transmission organization S&P Standard & Poor's Ratings (a credit rating agency) SEC U.S. Securities and Exchange Commission Securities Act Securities Act of 1933, as amended Series A Preferred Stock Vistra's 8.0% Series A Fixed Rate Reset Cumulative Redeemable Perpetual Preferred Stock, $0.01 par value, with a liquidation preference of $1,000 per share Series B Preferred Stock Vistra's 7.0% Series B Fixed Rate Reset Cumulative Redeemable Perpetual Preferred Stock, $0.01 par value, with a liquidation preference of $1,000 per share SG&A selling, general and administrative SO 2 sulfur dioxide Spin-Off the tax-free spin-off from EFH Corp. executed pursuant to the Plan of Reorganization on the Effective Date by the TCEH Debtors and the Contributed EFH Debtors ST steam turbine Tax Matters Agreement Tax Matters Agreement, dated as of the Effective Date, by and among EFH Corp., Energy Future Intermediate Holding Company LLC, EFIH Finance Inc. and EFH Merger Co. LLC TCJA The Tax Cuts and Jobs Act of 2017, federal income tax legislation enacted in December 2017, which significantly changed the tax laws applicable to business entities TCEH or Predecessor Texas Competitive Electric Holdings Company LLC, a direct, wholly owned subsidiary of Energy Future Competitive Holdings Company LLC, and, prior to the Effective Date, the parent company of the TCEH Debtors whose major subsidiaries included Luminant and TXU Energy TCEQ Texas Commission on Environmental Quality TRA Tax Receivable Agreement, containing certain rights (TRA Rights) to receive payments from Vistra related to certain tax benefits, including benefits realized as a result of certain transactions entered into at Emergence (see Note 7 to the Financial Statements) TRE Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with NERC standards and monitors compliance with ERCOT protocols TriEagle Energy TriEagle Energy, LP (d/b/a TriEagle Energy, TriEagle Energy Services, Eagle Energy, Energy Rewards, Power House Energy and Viridian Energy), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of ERCOT and PJM that is engaged in the retail sale of electricity to residential and business customers iv Table of Contents TXU Energy TXU Energy Retail Company LLC (d/b/a TXU), an indirect, wholly owned subsidiary of Vistra that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers U.S. United States of America U.S. Gas & Electric U.S. Gas and Electric, Inc. (d/b/a USG&E, Illinois Gas & Electric and ILG&E), an indirect, wholly owned subsidiary of Vistra, a REP in certain areas of PJM, ISO-NE, NYISO and MISO that is engaged in the retail sale of electricity to residential and business customers Value Based Brands Value Based Brands LLC (d/b/a 4Change Energy, Express Energy and Veteran Energy), an indirect, wholly owned subsidiary of Vistra that is a REP in competitive areas of ERCOT and is engaged in the retail sale of electricity to residential and business customers Vistra Vistra Corp., and/or its subsidiaries, depending on context. On the Effective Date, the TCEH Debtors and the Contributed EFH Debtors emerged from Chapter 11 and became subsidiaries of Vistra Energy Corp. Effective July 2, 2020, Vistra Energy Corp. changed its name to Vistra Corp. Vistra Intermediate Vistra Intermediate Company LLC, a direct, wholly owned subsidiary of Vistra Vistra Operations Vistra Operations Company LLC, an indirect, wholly owned subsidiary of Vistra that is the issuer of certain series of notes (see Note 10 to the Financial Statements) and borrower under the Vistra Operations Credit Facilities Vistra Operations Commodity-Linked Credit Agreement Credit agreement, dated as of February 4, 2022 (as amended, restated, amended and restated, supplemented, and/or otherwise modified from time to time) by and among Vistra Operations, Vistra Intermediate, the lenders party thereto, the other credit parties thereto, the administrative agent, the collateral agent, and the other parties named therein Vistra Operations Credit Agreement Credit agreement, dated as of October 3, 2016 (as amended, restated, amended and restated, supplemented and/or otherwise modified from time to time), by and among Vistra Operations, Vistra Intermediate, the lenders party thereto, the letter of credit issuers party thereto, the administrative agent, the collateral agent, and the other parties named therein Vistra Operations Credit Facilities Vistra Operations senior secured financing facilities (see Note 10 to the Financial Statements) Vistra Zero Vistra Zero LLC v Table of Contents PART I Item 1. BUSINESS References in this report to "we," "our," "us" and "the Company" are to Vistra and/or its subsidiaries, as apparent in the context. See Glossary for defined terms. 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. We incorporated under Delaware law in 2016. Effective July 2, 2020, we changed our name from Vistra Energy Corp. to Vistra Corp. to distinguish from companies that are involved in exploring for, producing, refining, or transporting fossil fuels (many of which use "energy" in their names) and to better reflect our integrated business model, which combines a retail electricity and natural gas business focused on serving its customers with new and innovative products and services and an electric power generation business leading the clean power transition through our Vistra Zero portfolio while powering the communities we serve with safe, reliable and affordable power. We serve approximately 3.5 million customers and operate in 20 states and the District of Columbia. Our generation fleet totals approximately 37,000 MW of generation capacity with a portfolio of natural gas, nuclear, coal, solar and battery energy storage facilities. Vistra has six reportable segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. See Market Discussion below and Note 19 to the Financial Statements for further information concerning our reportable segments. Business Strategy Vistra is a leader in the clean power transition. With a strong zero-carbon generation portfolio and a deliberate and responsible strategy to decarbonize, the company is focused on delivering healthy returns and value for all stakeholders. Our business strategy is focused on the following areas: 1 Table of Contents • Growth and transformation. Vistra's strategy is to responsibly and reliably grow our businesses through economically attractive investments, including in retail business and renewable, energy storage and other assets that assist in reducing our carbon footprint and create a more sustainable and resilient company well positioned to generate long-term value for all of our stakeholders. Since 2010, Vistra has retired more than 14,500 MW of coal and gas power plants resulting in a 45% reduction in carbon dioxide (CO 2 ) emissions, a 61% reduction in nitrogen oxide (NO X ) emissions, and a 81% reduction in sulfur dioxide (SO 2 ) emissions through year-end 2022, compared to a 2010 baseline. Now, we are transforming our generation portfolio through investments in zero-carbon resources and new carbon-reducing technologies, targeting net-zero carbon emissions by 2050. Additionally, we have announced the retirement of approximately 5,000 MW of coal-fueled power plants by 2027, with plans to repurpose feasible sites to solar and energy storage developments. Repurposed sites provide a strategic advantage in the development of greener power due to the interconnection infrastructure already available, but additionally, and importantly, they allow us to continue supporting the local communities and our employees in those areas. We believe our diversified asset mix will support the reliability of the electric system while providing customers with cost-effective energy that meets their sustainable preferences throughout the clean power transition. Our growth strategy leverages our core capabilities of multi-channel retail marketing in large and competitive markets, operating large-scale, environmentally sensitive, and diverse assets across a variety of fuel technologies, fuel logistics and management, commodity risk management, cost control, and energy infrastructure investing. To advance our sustainability and energy transition initiatives, in December 2021, we adopted our Green Finance Framework, pursuant to which we issued $1.0 billion of Series B Preferred Stock to finance or refinance, in whole or in part, new or existing eligible green projects. We intend to opportunistically evaluate the acquisition and development of high-quality generation and storage assets and power-related businesses, including retail businesses and renewable, energy storage and other assets, that complement our core capabilities and align with our operational, financial and sustainability goals. We pride ourselves on our deliberate and responsible approach to grow and transform, considering impacts on all stakeholders. We make disciplined investments that are consistent with our focus on maintaining both a strong balance sheet and strong liquidity profile and our commitment to ensuring grid reliability, affordable power, and pursuit of a just transition away from carbon-emitting generation assets for the communities in which we operate and serve. As a result, consistent with our disciplined capital allocation approval process, we endeavor to pursue growth opportunities that have compelling economic value and align with or enhance our purpose and core principles. • Disciplined capital allocation. Vistra takes a disciplined approach to capital allocation in support of our commitment to maintain a strong balance sheet. We thoughtfully make capital allocation decisions that we believe will lead to attractive cash returns on investment, including returning capital to our stockholders through quarterly dividends and our share repurchase program as reflected in our current plans to return up to $7.75 billion in capital to common shareholders from November 2021 through 2026. In addition to our dedicated approach to returning value to all stakeholders, we invest prudently in the maintenance of our existing assets and potential growth acquisitions. A strong balance sheet ensures Vistra's interest expense is manageable in a variety of wholesale power price environments while giving Vistra access to flexible and diverse sources of liquidity needed to operate its business and make prudent capital investment decisions. We believe in cost discipline and strong commercial management of our assets and commodity positions to deliver long-term value to our stakeholders, to maintain the safety and reliability of our facilities, all while accelerating growth in our Vistra Zero portfolio pipeline with cost-efficient capital and investment in new technologies when economic, including solar assets and ESS projects, resulting in a continued modernization of Vistra's generation fleet. • Integrated business model. Our integrated business model is an important component of our business strategy. This element of our business provides long-term sustainable solutions enabled by our diversified portfolio. This key factor distinguishes us from our electricity competitors by pairing our reliable and efficient mining, diversified generation fleet and wholesale commodity risk management capabilities with our retail platform. Coupling retail with generation is a core competitive advantage that reduces the effects of commodity price movements and contributes to the stability and predictability of our cash flows, a crucial feature of the strategy as Vistra responsibly grows its renewables portfolio and winds down its coal-fueled assets. 2 Table of Contents • Superior customer service. Through our retail brands, including TXU Energy, Ambit Energy, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric, we serve the retail electricity and natural gas needs of end-use residential, small business and commercial and industrial electricity customers through multiple sales and marketing channels. In addition to benefitting from our integrated business model, we leverage our brands, our commitment to safe, reliable and affordable product offerings, our wholesale commodity risk management operations and our strong customer service to differentiate our products and solutions from our competitors. We strive to be at the forefront of innovation with new environmentally-conscious and sustainable-focused product offerings and customer experiences to reinforce our value proposition. We maintain a focus on solutions that provide our customers with choice, convenience and control over how and when they use electricity and related services, including TXU Energy's Free Nights and Solar Days SM residential plans, TXU Energy's Free EV Miles SM residential plans, MyEnergy Dashboard SM , the TXU Energy Green Up SM renewable energy credit program and a diverse set of solar options. Our focus on superior customer service guides our efforts in acquiring new residential and commercial customers, serving and retaining existing customers, and maintaining valuable sales channels for our electricity generation resources. We believe our dependable customer service, innovative products and trusted brands will result in high residential customer retention rates, particularly in Texas where our TXU Energy brand has maintained its residential customers in a highly competitive retail market. • Excellence in operations while maintaining an efficient cost structure. We believe delivering long-term stakeholder value is increased as a result of making disciplined investments that enable our generation facilities to operate not only effectively and efficiently, but also safely, reliably and in an environmentally compliant manner as we lead in the clean power transition through the acceleration of our renewables portfolio. We believe that an ongoing focus on operational excellence and safety is a key component to success in a highly competitive environment and is part of the unique value proposition of our integrated model. Additionally, we are committed to optimizing our cost structure, reducing our debt levels, and implementing enterprise-wide process and operating improvements without compromising the safety of our communities, customers and employees. We believe we have a highly effective and efficient cost structure and that our cost structure supports excellence in our operations and is instrumental in our long-term value proposition. • Integrated hedging and commercial management. Our commercial team is focused on effectively and efficiently managing risk, through opportunistic hedging, and optimizing our assets and business positions. We proactively manage our exposure to wholesale electricity prices and fuel costs in markets in which we operate, on an integrated basis, through contracts for physical delivery of electricity, exchange-traded and over-the-counter financial contracts, term, day-ahead and real-time market transactions, and bilateral contracts with other wholesale market participants, including other power generators and end-user electricity customers. We actively hedge near-term cash flows and optimize long-term value through hedging and forward sales contracts. We believe our integrated hedging and commercial management strategy, in combination with a strong balance sheet and attractive liquidity profile, will provide long-term advantages through cycles of higher and lower commodity prices. • Corporate responsibility and ESG initiatives. It is our purpose to light up people's lives and power a better way forward. We strive to be a good corporate citizen by investing in our employees, putting customers and suppliers first, and improving communities where we live, work and serve as we accelerate toward a clean energy future. Vistra and its employees are actively engaged in programs intended to support our customers and strengthen the communities in which we conduct operations. Our foremost giving initiatives are through the United Way, TXU Energy Aid and Ambit Cares campaigns. TXU Energy Aid serves as an integral resource for social service agencies that assist those in need across Texas pay their electricity bills. Ambit Cares partners with Feeding America® to assist those in need across the U.S. by fighting hunger through a network of food banks. Beyond these giving initiatives, Vistra endeavors to consider ESG and all of its stakeholders – customers, suppliers, local communities, employees, contractors, investors and the environment, among others – into our material decisions, processes and activities. The Board has ultimate oversight of our ESG initiatives. We know that prioritizing our stakeholders leads to higher customer satisfaction, more community involvement and support, and committed employees and suppliers, which in turn, leads to a more sustainable company. Our ESG initiatives complement our business strategy and strengthen our resiliency. For instance, our investment in and growth of Vistra Zero supports our long-term goal to achieve net-zero carbon emissions by 2050. We stay informed of evolving ESG standards and remain committed to provide specific and measurable ESG goals and initiatives in a transparent manner. 3 Table of Contents Recent Developments Dividend Declarations — In February 2023, the Board declared a quarterly dividend of $0.1975 per share of common stock that will be paid in March 2023 and a semi-annual dividend of $40.00 per share of Series A Preferred Stock that will be paid in April 2023. Market Discussion The operations of Vistra are aligned into six reportable business segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. The following is a summary of our segments: • The Retail segment represents Vistra's retail sales of electricity and natural gas to residential, small business and commercial and industrial customers. • The Texas segment represents Vistra's electricity generation operations in the ERCOT market, other than assets that are now part of the Sunset or Asset Closure segments, respectively. • The East segment represents Vistra's electricity generation operations in the Eastern Interconnection of the U.S. electric grid, other than assets that are now part of the Sunset or Asset Closure segments, respectively, and includes operations in the PJM, ISO-NE and NYISO markets. • The West segment represents Vistra's electricity generation operations in the CAISO market, including our development of battery ESS projects at our Moss Landing power plant site (see Note 2 to the Financial Statements). • The Sunset segment represents generation plants with announced retirement dates after December 31, 2022. Separately reporting the Sunset segment differentiates operating plants with announced retirement plans from our other operating plants in the Texas, East and West segments. • The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines. The Asset Closure segment also includes results from generation plants we retired in the year ended December 31, 2022. See Note 19 to the Financial Statements for further information concerning reportable segments. Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) Separately, ISOs/RTOs administer the transmission infrastructure and markets across a regional footprint in most of the markets in which we operate. They are responsible for dispatching all generation facilities in their respective footprints and are responsible for both maximum utilization and reliable and efficient operation of the transmission system. ISOs/RTOs administer energy and ancillary service markets in the short term, which usually consists of day-ahead and real-time markets. Several ISOs/RTOs also ensure long-term planning reserves through monthly, semiannual, annual and multi-year capacity markets. The ISOs/RTOs that oversee most of the wholesale power markets in which we operate currently impose, and will likely continue to impose, bid and price limits or other similar mechanisms. NERC regions and ISOs/RTOs often have different geographic footprints, and while there may be geographic overlap between NERC regions and ISOs/RTOs, their respective roles and responsibilities do not generally overlap. In ISO/RTO regions with centrally dispatched market structures (e.g., ERCOT, PJM, ISO-NE, NYISO, MISO, and CAISO), all generators selling into the centralized market receive the same price for energy sold based on the bid price associated with the production of the last MWh that is needed to balance supply with demand within a designated zone or at a given location. Different zones or locations within the same ISO/RTO may produce different prices respective to other zones or locations within the same ISO/RTO due to transmission losses and congestion. For example, a less efficient and/or less economical natural gas-fueled unit may be needed in some hours to meet demand. If this unit's production is required to meet demand on the margin, its offer price will set the market clearing price for all dispatched generation in the same market (although the price paid at other zones or locations may vary because of transmission losses and congestion), regardless of the price that any other unit may have offered into the market. Generators will receive the location-based marginal price for their output. Retail Segment The Retail segment is engaged in retail sales of electricity, natural gas and related services to approximately 3.5 million customers. Substantially all of these activities are conducted by TXU Energy, Ambit Energy, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric across 19 U.S. states and the District of Columbia. 4 Table of Contents The largest portion of our retail operations are in Texas, where we provide retail electricity to approximately 2.4 million customers in ERCOT. We are an active participant in the competitive ERCOT retail market and continue to be a market leader, which we believe is driven by, among other things, strong brands, innovative products and services and excellent customer service. As of December 31, 2022, we provided electricity to approximately 30% of the residential customers in ERCOT and for approximately 16% of business customers' demand. We believe that we have differentiated ourselves by providing a distinctive customer experience predicated on delivering reliable and innovative power products and solutions to our customers, which give our customers choice, convenience and control over how and when they use electricity and related services. Our retail business also offers a comprehensive suite of green products and services, including 100% wind and solar options, as well as thermostats, dashboards and other programs designed to encourage reduced consumption and increased energy efficiency. Our integrated power generation and wholesale operation allows us to efficiently obtain the electricity needed to serve our customers at the lowest cost. The integrated model enables us to structure products and contracts in a way that offers significant value compared to stand-alone retail electric providers. Additionally, our wholesale commodity risk management operations help increase the profitability of our retail business by allowing us to bypass bid-ask spread in the market (particularly for illiquid products and time periods) and achieve lower collateral costs as compared to other, non-integrated retail electric providers. Moreover, our retail business can reduce, to some extent, the exposure of our wholesale generation business to wholesale power price volatility. This is because the retail load requirements of our retail operations can provide a natural offtake to the length of Luminant's generation portfolio when economic, thereby reducing the exposure to wholesale power price volatility as compared to a non-integrated independent power producer. Outside of ERCOT, we also serve residential, municipal, commercial and industrial customers substantially through our Homefield Energy, Dynegy Energy Services, Public Power, U.S. Gas & Electric and Ambit Energy retail businesses, through which we provide retail electricity, natural gas and related services to approximately 1.1 million customers in 18 states and the District of Columbia. Texas Segment Our Texas segment is comprised of 21 power generation facilities totaling 18,141 MW of generation capacity in ERCOT. ISO/RTO Technology Primary Fuel Number of Facilities Net Capacity (MW) ERCOT CCGT Natural Gas 7 7,838 ERCOT ST Coal 2 3,850 ERCOT CT or ST Natural Gas 7 3,455 ERCOT Nuclear Nuclear 1 2,400 ERCOT Solar/Battery Renewable 4 598 Total Texas Segment 21 18,141 We have announced the potential for additional development of solar photovoltaic power generation facilities and battery ESS in Texas, with estimated commercial operation dates for these facilities beginning in 2024. See Note 2 to the Financial Statements for a summary of our solar and battery energy storage projects. ERCOT — ERCOT is an ISO that manages the flow of electricity from approximately 98,000 MW of expected Summer 2023 peak generation capacity to approximately 26 million Texas customers, representing approximately 90% of the state's electric load. 5 Table of Contents As an energy-only market, ERCOT's market design is distinct from other competitive electricity markets in the U.S. Other markets maintain a minimum planning reserve margin through regulated planning, resource adequacy requirements and/or capacity markets. In contrast, ERCOT's resource adequacy is currently predominately dependent on energy-market price signals. The PUCT recently voted to recommend a Performance Credit Mechanism (PCM) that would align a required reliability standard with resource availability during higher-risk system conditions in a centrally-cleared market. These changes are currently being evaluated by the PUCT and the Texas legislature and have not been implemented as of the date hereof. In 2014, ERCOT implemented the Operating Reserve Demand Curve (ORDC), pursuant to which wholesale electricity prices in the real-time electricity market increase automatically as available operating reserves decrease below defined threshold levels, creating a price adder. The slope of the ORDC curve is determined through a mathematical loss of load probability calculation using forecasted reserves and historical data. In both March 2019 and March 2020, ERCOT implemented 0.25 standard deviation shifts in the loss of load probability calculation and moved to using a single blended ORDC curve; these changes resulted in a more rapid escalation in power prices as operating reserves fall below defined thresholds. Effective January 1, 2022, when operating reserves drop to 3,000 MW or less, the ORDC automatically adjusts power prices to the established value of lost load (VOLL), which is set at $5,000/MWh which is equal to the high system-wide offer cap. ERCOT also calculates the "peaker net margin" based on revenues a hypothetical unhedged peaking unit would collect in the market. If the peaker net margin exceeds a certain threshold, the system-wide offer cap is reduced to the low system-wide offer cap of $2,000/MWh for the remainder of the calendar year. Historically, high demand due to elevated temperatures in the summer months or high demand due to reduced temperatures in the winter months, combined with underperformance of wind generation, has created the conditions during which the ORDC contributes meaningfully to power prices. Extreme weather conditions can also lead to scarcity conditions regardless of season. Other than during periods of "scarcity pricing," the price of power is typically set by natural gas-fueled generation facilities (see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Key Operational Risks and Challenges ). Transactions in ERCOT take place in two key markets: the day-ahead market and the real-time market. The day-ahead market is a voluntary, financial electricity market conducted the day before each operating day in which generators and purchasers of electricity may bid for one or more hours of electricity supply or consumption. The real-time market is a physical market in which electricity is dispatched and priced in five-minute intervals. The day-ahead market provides market participants with visibility into where prices are expected to clear, and the prices are not impacted by subsequent events. Conversely, the real-time market exposes purchasers to the risk of transient operational events and price spikes. These two markets allow market participants to manage their risk profile by adjusting their participation in each market. In addition, ERCOT uses ancillary services to maintain system reliability, including regulation service, responsive reserve service and non-spinning reserve service. Ancillary services are provided by generators and qualified loads to help maintain the stable voltage and frequency requirements of the transmission system. Because ERCOT has one of the highest concentrations of wind and solar capacity generation among U.S. markets, the ERCOT market is more susceptible to fluctuations in wholesale electricity supply due to intermittent wind and solar production, making ERCOT more vulnerable to periods of generation scarcity. Beginning in July 2021, ERCOT has increased its ancillary service procurement volumes to maintain a more conservative level of operating reserves. East Segment Our East segment is comprised of 21 power generation facilities in 10 states totaling 12,093 MW of generating capacity in PJM, ISO-NE and NYISO. ISO/RTO Technology Primary Fuel Number of Facilities Net Capacity (MW) PJM CCGT Natural Gas 8 6,081 PJM CT Natural Gas 4 1,346 PJM CT Fuel Oil 2 93 ISO-NE CCGT Natural Gas 6 3,361 NYISO CCGT Natural Gas 1 1,212 Total East Segment 21 12,093 We plan to develop 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 with estimated commercial operation dates for these facilities ranging from 2024 to 2025. See Note 2 to the Financial Statements for a summary of our solar and battery energy storage projects. 6 Table of Contents PJM — PJM is an RTO that manages the flow of electricity from approximately 185,000 MW of generation capacity to approximately 65 million customers in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. Like ERCOT, PJM administers markets for wholesale electricity and provides transmission planning for the region, utilizing a locational marginal pricing (LMP) methodology which calculates a price for every generator and load point within PJM. PJM operates day-ahead and real-time markets into which generators can bid to provide energy and ancillary services. PJM also administers a forward capacity auction, the Reliability Pricing Model (RPM), which establishes a long-term market for capacity. We have participated in RPM auctions for years up to and including PJM's planning year 2024-2025, which ends May 31, 2025. We also enter into bilateral capacity transactions. PJM's Capacity Performance (CP) rules were designed to improve system reliability and include penalties for under-performing units and reward for over-performing units during shortage events. Full transition of the capacity market to CP rules occurred in planning year 2020-2021. An independent market monitor continually monitors PJM markets to ensure a robust, competitive market and to identify improper behavior by any entity. ISO-NE — ISO-NE is an ISO that manages the flow of electricity from approximately 32,600 MW of winter generation capacity to approximately 15 million customers in the states of Vermont, New Hampshire, Massachusetts, Connecticut, Rhode Island and Maine. ISO-NE dispatches power plants to meet system energy and reliability needs and settles physical power deliveries at LMPs. Its energy markets allow market participants to buy and sell energy and ancillary services at prices established through real-time and day-ahead auctions. Energy prices vary among the locations in ISO-NE and are largely influenced by transmission constraints and fuel supply. ISO-NE offers a forward capacity market where capacity prices are determined through auctions. Performance incentive rules have the potential to increase capacity payments for those resources that are providing excess energy or reserves during a shortage event, while penalizing those that produce less than the required level. NYISO — NYISO is an ISO that manages the flow of electricity from approximately 37,500 MW of installed summer generation capacity to approximately 20 million New York customers. NYISO dispatches power plants to meet system energy and reliability needs and settles physical power deliveries at LMPs. Its energy markets allow market participants to buy and sell energy and ancillary services at prices established through real-time and day-ahead auctions. Energy prices vary among the regional zones and locations in the NYISO and are largely influenced by transmission constraints and fuel supply. NYISO offers a forward capacity market where capacity prices are determined through auctions. Strip auctions occur one to two months prior to the commencement of a six-month seasonal planning period. Subsequent auctions provide an opportunity to sell excess capacity for the balance of the seasonal planning period or the upcoming month. Due to the short-term nature of the NYISO-operated capacity auctions and a relatively liquid bilateral market for NYISO capacity products, our Independence facility sells a significant portion of its capacity through bilateral transactions. The balance is cleared through the seasonal and monthly capacity auctions. West Segment Our West segment is comprised of two power generation facilities totaling 1,130 MW of generation capacity and the first two phases of a battery ESS facility totaling 400 MW in CAISO, all of which are located in California. ISO/RTO Technology Primary Fuel Number of Facilities Net Capacity (MW) CAISO CCGT Natural Gas 1 1,020 CAISO Battery Renewable 1 400 CAISO CT Fuel Oil 1 110 Total West Segment 3 1,530 We plan to develop an additional 350 MW in the third phase of our battery ESS at our Moss Landing Power Plant site with an estimated commercial operation date in the summer of 2023. CAISO — CAISO is an ISO that manages the flow of electricity to approximately 32 million customers primarily in California, representing approximately 80% percent of the state's electric load. 7 Table of Contents Energy is priced in CAISO utilizing an LMP methodology. The capacity market is comprised of Generic, Flexible and Local Resource Adequacy (RA) Capacity and is administered by the California Public Utilities Commission (CPUC). Unlike other centrally cleared capacity markets, the resource adequacy markets in California are primarily bilaterally traded markets. In 2020, the CPUC introduced a central procurement entity for Local RA Capacity effective for the 2023 compliance year. The central procurement entity runs a pay-as-bid auction for Local RA Capacity. In November 2016, CAISO implemented a voluntary capacity auction for annual, monthly, and intra-month procurement to cover for deficiencies in the market. The voluntary Competitive Solicitation Process, which FERC approved in October 2015, is a modification to the Capacity Procurement Mechanism (CPM) and provides another avenue to sell RA capacity. Sunset Segment Our Sunset segment is comprised of six power generation facilities totaling 5,163 MW of generating capacity in MISO, PJM and ERCOT. The Sunset segment represents plants with announced retirement plans between 2022 and 2027 that were previously reported in the ERCOT, PJM and MISO segments. See Note 3 to the Financial Statements for more information related to these planned generation retirements. ISO/RTO Technology Primary Fuel Number of Facilities Net Capacity (MW) ERCOT ST Coal 1 650 MISO (a) ST Coal 3 2,385 PJM ST Coal 2 2,128 Total Sunset Segment 6 5,163 ___________ (a) Includes the 585 MW Edwards facility that was retired on January 1, 2023. See Texas Segment above for a discussion of the ERCOT ISO and East Segment above for a discussion of the PJM RTO. MISO — MISO is an RTO that manages the flow of electricity from approximately 190,000 MW of installed generation capacity to approximately 45 million customers in all or parts of Iowa, Minnesota, North Dakota, Wisconsin, Michigan, Kentucky, Indiana, Illinois, Missouri, Arkansas, Mississippi, Texas, Louisiana, Montana, South Dakota and Manitoba, Canada. MISO dispatches power plants to meet system energy and reliability needs and settles physical power deliveries at LMPs. Its energy markets allow market participants to buy and sell energy and ancillary services at prices established through real-time and day-ahead auctions. Energy prices vary among the regional zones and locations in MISO and are largely influenced by transmission constraints and fuel supply. An independent market monitor is responsible for evaluating the performance of the markets and identifying conduct by market participants or MISO that may compromise the efficiency or distort the outcome of the markets. MISO administers a one-year Planning Resource Auction for the next planning year from June 1st of the current year to May 31st of the following year. In 2022, FERC approved MISO's proposal to change the annual Planning Resource Auction into a seasonal auction, effective for the 2023-2024 planning year. We participate in these auctions with open capacity that has not been committed through bilateral or retail transactions. We also participate in the MISO annual and monthly financial transmission rights auctions to manage the cost of our transmission congestion, as measured by the congestion component of the LMP price differential between two points on the transmission grid across the market area. 8 Table of Contents Wholesale Operations Our wholesale commodity risk management group is responsible for dispatching our generation fleet in response to market needs after implementing portfolio optimization strategies, thus linking and integrating the generation fleet production with our retail customer and wholesale sales opportunities. Market demand, also known as load, faced by electric power systems, such as those we operate in, varies from moment to moment as a result of changes in business and residential demand, which is often driven by weather. Unlike most other commodities, the production and consumption of electricity must remain balanced on an instantaneous basis. There is a certain baseline demand for electricity across an electric power system that occurs throughout the day, which is typically satisfied by baseload generating units with low variable operating costs. Baseload generating units can also increase output to satisfy certain incremental demand and reduce output when demand is unusually low. Intermediate/load-following generating units, which can more efficiently change their output to satisfy increases in demand, typically satisfy a large proportion of changes in intraday load as they respond to daily increases in demand or unexpected changes in supply created by reduced generation from renewable resources or other generator outages. Peak daily loads may be satisfied by peaking units. Peaking units are typically the most expensive to operate, but they can quickly start up and shut down to meet brief peaks in demand. In general, baseload units, intermediate/load following units and peaking units are dispatched into the ISO/RTO grid in order from lowest to highest variable cost. Price formation is typically based on the highest variable cost unit that clears the market to satisfy system demand at a given point in time. Our commodity risk management group also enters into electricity, gas and other commodity derivative contracts to reduce exposure to changes in prices primarily to hedge future revenues and fuel costs for our generation facilities and purchased power costs for our Retail segment. 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. Competition Competition in the markets in which we operate is impacted by electricity and fuel prices, congestion along the power grid, subsidies provided by state and federal governments for new and existing generation facilities, including renewables generation and battery ESS, new market entrants, construction of new generating assets, technological advances in power generation, the actions of environmental and other regulatory authorities, and other factors. We primarily compete with other electricity generators and retailers based on our ability to generate electric supply, market and sell electricity at competitive prices and to efficiently utilize transportation from third-party pipelines and transmission from electric utilities to deliver electricity to end-users. Competitors in the generation and retail power markets in which we participate include numerous regulated utilities, industrial companies, non-utility generators, competitive subsidiaries of regulated utilities, independent power producers, REPs and other energy marketers. See Item 1A. Risk Factors for additional information concerning the risks faced with respect to the markets in which we operate. Brand Value Our TXU Energy brand, which has been used to sell electricity to customers in the competitive retail electricity market in Texas for approximately 20 years, is registered and protected by trademark law and is the only material intellectual property asset that we own. We have also acquired the trade names for Ambit Energy, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric through the Ambit Transaction, Crius Transaction and the Merger, as the case may be. As of December 31, 2022, we have reflected intangible assets on our balance sheet for our trade names of approximately $1.341 billion (see Note 5 to the Financial Statements). 9 Table of Contents Human Capital Resources As a key component of our core principle that we work as a team , Vistra believes our most valuable asset is our talented, dedicated and diverse group of employees who work together to achieve our objectives, and our top priority is ensuring their safety. One of Vistra's core principles is that we care about our key stakeholders , including our employees. We invest in our people through numerous development and training opportunities, engaging employee programs and generous benefit and wellness offerings. As of December 31, 2022, we had approximately 4,910 full-time employees, including approximately 1,295 employees under collective bargaining agreements. Safety Vistra's mindset around safety is exemplified by our motto: Best Defense. Everyone wins. No one gets hurt. Our safety culture revolves around people and human performance. We place a high importance on continuous improvement, along with a keen focus on numerous learning and error-prevention tools. To facilitate a learning environment, our various operating plants share their investigations and learnings of all safety events with all operations employees on weekly calls. The information is presented by front-line employees and supported by management. The lessons from each event are shared across the fleet to prevent similar incidents at other locations. All personnel at Vistra locations are encouraged to be actively involved in the safety process. Managers are required to participate in safety engagements with staff to enable constant communication and sustained interaction. In 2022, the generation fleet conducted more than 52,000 leadership safety engagements across the fleet continuing our employee driven safety program focused on engagement of all employees. Our focus on reducing the severity of injuries for both our employees and contractors who work with us has shown positive results. In 2022, we did not have any serious injuries, as determined in accordance with industry standards, or fatalities to our Vistra employees or business partners working at our sites. Although we do not focus on recordable incidents, our Total Recordable Incident rate (TRIR) for the company was 0.85, in the second quartile as compared to the Edison Electric Institute (EEI) 2021 Total Company Injury Data. We encourage near-miss reporting and review of events to promote a learning environment. In 2022, safety learning calls were held every week where 128 near-miss and safety events were reviewed by our operating teams to promote learning across the fleet. All Vistra employees are covered by our safety program. Corporate and retail employees are required to complete periodic training on safety topics through our online learning management system. Employees who are located at a power plant are required to complete trainings based on job function, which is also tracked through our central learning management system. In addition, the Company engages an independent third-party conformity assessment and certification vendor to manage adherence to our safety standards for all vendors and contractors who work at our plants. In addition, we work closely with our suppliers and contractors to ensure our safety practices are upheld. All of our power plant facilities have effective health and safety programs and comply with OSHA regulations. In addition to compliance, our generation fleet has a total of 14 plants that have been awarded the Voluntary Protection Program (VPP) Star designation by the OSHA for superior demonstration of effective safety and health management systems and for maintaining injury and illness rates below the national averages for our industry. Two additional plants have submitted applications and are awaiting review by the OSHA. VPP Star status is the highest designation of OSHA's Voluntary Protection Programs. The achievement recognizes employers and workers who have implemented effective safety and health management systems and maintain injury and illness rates below national Bureau of Labor Statistics averages for their respective industries. These sites are self-sufficient in their ability to control workplace hazards and are reevaluated every three to five years. Additionally, 32 of our power plants and mine locations have adopted a proactive Behavior Based Safety approach to safety which focuses on identifying and providing feedback on at-risk behaviors observed. In 2022, we continued our COVID-19 protections and protocols helping to ensure the safety of all of our employees. Diversity, Equity and Inclusion We recognize the value of having a diverse and inclusive workforce. Our diversity includes all the ways we differ, such as age, gender, ethnicity and physical appearance, as well as underlying differences such as thoughts, styles, religions, nationality, education and numerous other traits. Creating and maintaining an environment where differences are valued and respected enhances our ability to recruit and retain the best talent in the marketplace and to provide a work environment that allows all employees to be their best. 10 Table of Contents Vistra's diversity is evolving, and our Board and management are leading by example. Currently, four of the eleven Board members are women, and two of the eleven are ethnically diverse. Overall, 32% of the Company's workforce is ethnically diverse. Women currently hold 25% of the Company's senior management positions, and ethnically diverse employees represent 27% of senior management. During 2022, we continued our efforts to unlock the full potential of our people by launching multiple new initiatives within our diversity, equity, and inclusion efforts. Our Chief Diversity Officer continued to develop and lead Vistra's employee-led Diversity, Equity and Inclusion Advisory Council, established in 2020. In 2022, the council expanded its role and participated directly in the development of new diversity training modules, the launching of Vistra's 2022 Employee Engagement Survey and the launch of a new learning platform. We continued to utilize our thirteen Employee Resource Groups (ERGs) to promote the appreciation of and communicate awareness of diverse employee groups and communities and their contribution to the overall success of the organization, both internally and externally. ERGs represent not only diverse cultures, but also employees with disabilities, the LGBTQ+ community and employees engaged in innovation. Further initiatives were launched to support the education, recruitment and retention of current and future employees, with particular emphasis being placed on driving equal access to opportunities throughout the organization. The emphasis on skills based hiring continued in 2022. People managers across the organization also participated in one-day and two-day training sessions conducted by Basic Diversity, Inc. Vistra is active in our communities to promote inclusivity. Vistra's supply chain diversity initiative seeks to reflect our customer base and workforce compositions through creating a diverse supply chain. Vistra continued to expand its commitment to an inclusive economy by fostering mentorship of diverse businesses. Further, in the third year of Vistra's $10 million five-year commitment to support underserved communities, Vistra provided funding to educational and economic development nonprofits around the country working to transform underserved communities for the better. Training and Development We believe the development of employees at all levels is critical to Vistra's current and future success. We have launched key programs to develop leaders at all levels of the organization. Vistra's Essentials in Leadership provides first time managers with skills to lead organizations in situational leadership, business acumen, identification of communication styles and inclusive communication practices, and exposes them to best practices from across the company. We also reinstated in-person leadership development classes and continued to provide virtual opportunities. In 2022, Vistra added an emotional intelligence program that was well received by leaders across the organization. Vistra also provides many other training and development programs to help grow and develop employees at every level, including online learning platform courses, learning management system courses, recorded webinars and presentations, self-paced development and employee-specific skill training. The launch of the new and improved online learning platform in 2022 further supports employees in completing thousands of hours of professional training to support continuing education requirements for their respective professional licenses, including accounting, legal and nuclear. In 2022, Vistra continued its formal mentoring program available to all employees to focus on topics like organizational knowledge, career development, individual development, collaboration and leadership. Over 600 employees participated in 2022. In addition, all full-time employees, other than those in a collective bargaining unit, receive a formal performance review guiding development and improving results of the business. Employee Benefits Maintaining attractive benefits and pay are important for recruiting and retaining talent. We are committed to maintaining an equitable compensation structure, including performing annual salary reviews by employee category level within significant locations of operations. Eligible full- and part-time employees are provided access to medical, prescription drug, dental, vision, life insurance, accidental death and dismemberment, long-term disability coverage, accident coverage, critical illness coverage and hospital indemnity coverage. Regular full-time employees are eligible for short-term disability benefits, and all employees are eligible for the employee assistance program, parental leave, maternity leave and a 401(k) plan through which the Company matches employee contributions up to 6%. 11 Table of Contents Wellness We believe a healthy workforce leads to greater well-being at work and at home. To help keep our workforce healthy, we offer access to on-site medical clinics at six locations. Our healthcare plans are also designed to reward employees for getting annual physicals, age and gender health screenings and immunizations. In addition, our employee medical plans promote mental health and emotional wellness and offer resources for employees seeking assistance. Fitness centers in multiple facilities offer cardio equipment, a selection of free weights and exercise mats. Our employee-led wellness team engages our people to get active and support causes that promote healthy living. With support from the company, the wellness team covers the registration costs for employees to participate in running and cycling events throughout the year. Environmental Regulations and Related Considerations We are subject to extensive environmental regulation by governmental authorities, including the EPA and the environmental regulatory bodies of states in which we operate. The EPA has finalized or proposed several regulatory actions establishing new requirements for control of certain emissions from sources, including electricity generation facilities. See Item 1A. Risk Factors for additional discussion of risks posed to us regarding regulatory requirements. See Note 12 to the Financial Statements for a discussion of litigation related to EPA reviews. Climate Change There is continuing attention and interest domestically and internationally about global climate change and how GHG emissions, such as CO 2 , contribute to global climate change. GHG emissions from the combustion of fossil fuels, primarily by our coal-fueled-generation plants as well as our natural gas-fueled generation plants represent the substantial majority of our total GHG emissions. CO 2 , methane and nitrous oxide are emitted in this combustion process, with CO 2 representing the largest portion of these GHG emissions. We estimate that our generation facilities produced approximately 104 million short tons of CO 2 in the year ended 2022. To manage our environmental impact from our business activities and reduce our emissions profile, Vistra set emissions reduction targets. 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, including decarbonization of existing business lines and further diversification into low-to-no emission businesses, primarily renewables and energy storage. We have already taken or announced significant steps to transform our generation portfolio and reduce the emissions intensity of our generation fleet, including: • Solar Projects — We operate solar generations facilities totaling 338 MW in Texas. We have announced our plans to develop: ◦ additional solar generation facilities in Texas, with expected commercial operation dates beginning in 2024, and ◦ 300 MW of solar generation facilities at retired or to-be retired plant sites in Illinois with expected commercial operation dates ranging from 2024 to 2025. • Battery Energy Storage Projects — We operate battery ESSs totaling 270 MW in Texas and 400 MW in California. We have announced our plans to develop: ◦ 150 MW of battery ESS at retired or to-be-retired plant sites in Illinois with expected commercial operation dates ranging from 2024 to 2025, and ◦ 350 MW of battery ESS in California with an expected commercial operation date in 2023. • Acquisition of CCGTs — In 2016 and 2017, we acquired 4,042 MW of CCGTs in Texas. In 2018, we acquired 15,448 MW of CCGTs across various ISOs/RTOs in connection with the Merger. • Retirements of Fossil Fuel Generation — Since 2018, lignite/coal-fueled generation facilities retired include 4,167 MW in Texas, 3,455 MW in Illinois (including the Edwards facility that was retired on January 1, 2023) and 1,300 MW in Ohio. We expect to retire an additional 4,578 MW of coal-fueled generation facilities in Illinois, Ohio and Texas no later than year-end 2027. See Note 2 to the Financial Statements for discussion of our solar and battery ESS projects and Note 3 to the Financial Statements for discussion of our retirement of generation facilities. 12 Table of Contents GHG Emissions In July 2019, the EPA finalized a rule that repealed the Clean Power Plan (CPP) that had been finalized in 2015 and established new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the Affordable Clean Energy (ACE) rule. The ACE rule developed emission guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generating units. In response to challenges brought by environmental groups and certain states, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the ACE rule, including the repeal of the CPP, in January 2021 and remanded the rule to the EPA for further action. In June 2022, the U.S. Supreme Court issued an opinion reversing the D.C. Circuit Court's decision, and finding that the EPA exceeded its authority under Section 111 of the Clean Air Act when the EPA set emission requirements in the CPP based on generation shifting. In October 2022, the D.C. Circuit Court issued an amended judgment, denying petitions for review of the ACE rule and challenges to the repeal of the CPP. In addition, the EPA has opened a docket seeking input on questions related to the regulation of GHGs under Section 111(d) and has indicated its intent to issue a new proposal in Spring 2023. State Regulation of GHGs Many states where we operate generation facilities have, are considering, or are in some stage of implementing, state-only regulatory programs intended to reduce emissions of GHGs from stationary sources as a means of addressing climate change. Regional Greenhouse Gas Initiative (RGGI) — RGGI is a state-driven GHG emission control program that took effect in 2009 and was initially implemented by ten New England and Mid-Atlantic states to reduce CO 2 emissions from power plants. The participating RGGI states implemented a cap-and-trade program. Compliance with RGGI can be achieved by reducing emissions, purchasing or trading allowances, or securing offset allowances from an approved offset project. We are required to hold allowances equal to at least 50 percent of emissions in each of the first two years of the three-year control period. In December 2017, the RGGI states released an updated model rule with changes to the CO 2 budget trading program, including an additional 30 percent reduction in the CO 2 annual cap by the year 2030, relative to 2020 levels. RGGI is currently conducting its third program review to be completed by the end of 2023 which may include an updated model rule. Our generating facilities in Connecticut, Maine, Massachusetts, New Jersey, New York and Virginia emitted approximately 9 million tons of CO 2 during 2022. The spot market price of RGGI allowances required to operate these facilities as of December 31, 2022 was approximately $13.57 per allowance. The spot market price of RGGI allowances required to operate our affected facilities during 2023 was approximately $12.63 per allowance on February 23, 2023. While the cost of allowances required to operate our RGGI-affected facilities is expected to increase in future years, we expect that the cost of compliance would be reflected in the power market, and the actual impact to gross margin would be largely offset by an increase in revenue. Massachusetts — In August 2017, the Massachusetts Department of Environmental Protection (MassDEP) adopted final rules establishing an annual declining limit on aggregate CO 2 emissions from 21 in-state fossil-fueled electricity generation units. The rules establish an allowance trading system under which the annual aggregate electricity generation unit sector cap on CO 2 emissions declines from 8.96 million metric tons in 2018 to 1.8 million metric tons in 2050. MassDEP allocated emission allowances to affected facilities for 2018. Beginning in 2019, the allocation process transitioned to a competitive auction process whereby allowances are partially distributed through a competitive auction process and partially distributed based on the process and schedule established by the rule. Beginning in 2021, all allowances were distributed through the auction. Limited banking of unused allowances is allowed. Virginia — In May 2019, the Virginia Department of Environmental Quality issued a final rule to adopt a carbon cap-and trade program for fossil-fueled electricity generation units, including our Hopewell facility, beginning in 2020. The program is based on the RGGI proposed 2017 model rule and linked Virginia to RGGI in 2021. The Governor of Virginia issued an executive order in January 2022 to begin the process of removing the state from RGGI; however, the Virginia General Assembly would need to modify the law to exit the program. At this time, no new laws have passed and Virginia remains in RGGI. New Jersey — In January 2018, the Governor of New Jersey signed an executive order directing the state's environmental agency and public utilities board to begin the process of rejoining RGGI, and New Jersey formally rejoined RGGI in June 2019. In June 2019, New Jersey adopted two rules that govern New Jersey's reentry into the RGGI auction and distribution of the RGGI auction proceeds. 13 Table of Contents Pennsylvania — In April 2022, the Pennsylvania Environmental Quality Board finalized regulations that would establish Pennsylvania's participation in RGGI. In July 2022, the Commonwealth Court took action to uphold a preliminary injunction over Pennsylvania's RGGI regulations. The Pennsylvania Supreme Court denied a request for emergency relief from the injunction in August 2022 and review of the legality of the injunction is now pending before the Pennsylvania Supreme Court. As a result, RGGI is not being implemented or enforced in Pennsylvania at this time. California — Our assets in California are subject to the California Global Warming Solutions Act, which required the California Air Resources Board (CARB) to develop a GHG emission control program to reduce emissions of GHGs in the state to 1990 levels by 2020. In April 2015, the Governor of California issued an executive order establishing a new statewide GHG reduction target of 40 percent below 1990 levels by 2030 to ensure California meets its 2050 GHG reduction target of 80 percent below 1990 levels. We have participated in quarterly auctions or in secondary markets, as appropriate, to secure allowances for our affected assets. In July 2017, California enacted legislation extending its GHG cap-and-trade program through 2030 and the CARB adopted amendments to its cap-and-trade regulations that, among other things, established a framework for extending the program beyond 2020 and linking the program to the new cap-and-trade program in Ontario, Canada beginning in January 2018. Air Emissions The Clean Air Act (CAA) The CAA and comparable state laws and regulations relating to air emissions impose various responsibilities on owners and operators of sources of air emissions, which include requirements to obtain construction and operating permits, pay permit fees, monitor emissions, submit reports and compliance certifications, and keep records. The CAA requires that fossil-fueled electricity generation plants meet certain pollutant emission standards and have sufficient emission allowances to cover SO 2 emissions and in some regions NO X emissions. In order to ensure continued compliance with the CAA and related rules and regulations, we utilize various emission reduction technologies. These technologies include flue gas desulfurization (FGD) systems, dry sorbent injection (DSI), baghouses and activated carbon injection or mercury oxidation systems on select units and electrostatic precipitators, selective catalytic reduction (SCR) systems, low-NO X burners and/or overfire air systems on all units. Cross-State Air Pollution Rule (CSAPR) In 2016, the EPA finalized the Cross-State Air Pollution Rule Update (CSAPR Update) to address 22 states' obligations with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). In 2019, following challenges by numerous parties, the D.C. Circuit Court found that the CSAPR Update did not fully address certain states' 2008 ozone NAAQS obligations. In October 2020, the EPA proposed an action to address the outstanding 2008 ozone NAAQS obligations in response to the D.C. Circuit Court's 2019 ruling. Vistra subsidiaries filed comments on that rulemaking in December 2020, and the EPA published a final rule in the Federal Register on April 30, 2021 that reduces ozone season NO X budgets in certain states. We do not believe that the final rule causes a material adverse impact on our future financial results. 14 Table of Contents In October 2015, the EPA revised the primary and secondary ozone NAAQS to lower the 8-hour standard for ozone emissions during ozone season (May to September). As required under the CAA, in October 2018, the State of Texas submitted a State Implementation Plan (SIP) to the EPA demonstrating that emissions from Texas sources do not contribute significantly to nonattainment in, or interfere with maintenance by, any other state with respect to the revised ozone NAAQS. In February 2023, the EPA disapproved Texas's SIP. In April 2022, prior to the EPA's disapproval of Texas's SIP, the EPA proposed a Federal Implementation Plan (FIP) to address the 2015 ozone NAAQS. The proposed FIP would apply to 25 states beginning with the 2023 ozone seasons. States where Vistra operates generation units that would be subject to this proposed rule are Illinois, New Jersey, New York, Ohio, Pennsylvania, Texas, Virginia and West Virginia. The revised Group 3 trading program (previously established in the Revised CSAPR Update Rule) would include emission budgets for 2023 that the EPA says are achievable through existing controls installed at power plants. Starting in 2026, the budgets would be based on levels achieved through installation of SCR controls at the approximately 20% of large coal-fueled power plants that do not currently have such controls. Starting in 2025, the budgets would be updated annually to account for source retirements. Starting in 2024, the rule would also impose a daily emissions rate limit for coal-fueled units with existing controls and would impose such a limit for units installing new controls in 2027. We, along with many other companies, trade groups, states and ISOs, including ERCOT, PJM and MISO, filed responsive comments to the EPA's proposal in June 2022, expressing concerns about certain elements of the proposal, particularly those that may result in challenges to electric reliability under certain conditions. The EPA is expected to finalize the proposed FIP in March 2023. In February 2022, the State of Texas, Luminant, certain trade groups, and others filed legal challenges to the EPA's disapproval of Texas's SIP in the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court). If the EPA finalizes the FIP described above as expected in March 2023, it will impose reduced ozone season NO X budgets under the CSAPR program for our Texas power plants. We cannot predict the outcome of our legal challenges to the EPA's disapproval of the SIP, any legal action related to the EPA's FIP once finalized, or the effects of the final rule (after the conclusion of legal challenges) on operations of our generation fleet. Regional Haze — Reasonable Progress and Best Available Retrofit Technology (BART) for Texas The Regional Haze Program of the CAA establishes "as a national goal the prevention of any future, and the remedying of any existing, impairment of visibility in mandatory class I federal areas which impairment results from man-made pollution." There are two components to the Regional Haze Program. First, states must establish goals for reasonable progress for Class I federal areas within the state and establish long-term strategies to reach those goals and to assist Class I federal areas in neighboring states to achieve reasonable progress set by those states towards a goal of natural visibility by 2064. Second, certain electricity generation units built between 1962 and 1977 are subject to BART standards designed to improve visibility if such units cause or contribute to impairment of visibility in a federal class I area. In October 2017, the EPA issued a final rule addressing BART for Texas electricity generation units, with the rule serving as a partial approval of Texas' 2009 SIP and a partial FIP. For SO 2 , the rule established an intrastate Texas emission allowance trading program as a "BART alternative" that operates in a similar fashion to a CSAPR trading program. The program includes 39 generating units (including the Martin Lake, Big Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2 and Graham 2 plants). The compliance obligations in the program started on January 1, 2019. For NO X , the rule adopted the CSAPR's ozone program as BART and for particulate matter, the rule approved Texas' SIP that determines that no electricity generation units are subject to BART for particulate matter. In August 2020, the EPA issued a final rule affirming the prior BART final rule but also included additional revisions that were proposed in November 2019. Challenges to both the 2017 rule and the 2020 rules have been consolidated in the D.C. Circuit Court, where we have intervened in support of the EPA. We are in compliance with the rule, and the retirements of our Monticello, Big Brown and Sandow 4 plants have enhanced our ability to comply. The EPA has stated it is starting a proceeding for reconsideration of the BART rule, which we expect in 2023. The challenges in the D.C. Circuit Court have been held in abeyance pending the EPA's action on reconsideration. National Ambient Air Quality Standards (NAAQS) The CAA requires the EPA to regulate emissions of pollutants considered harmful to public health and the environment. The EPA has established NAAQS for six such pollutants, including SO 2 and ozone. Each state is responsible for developing a SIP that will attain and maintain the NAAQS. These plans may result in the imposition of emission limits on our facilities. 15 Table of Contents SO 2 Designations for Texas In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Martin Lake generation plant and our now retired Big Brown and Monticello plants. The final designations require Texas to develop nonattainment plans for these areas. In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court. In August 2019, the EPA issued a proposed Error Correction Rule for all three areas, which, if finalized, would have revised its previous nonattainment designations and each area at issue would be designated unclassifiable. In May 2021, the EPA finalized a "Clean Data" determination for the areas surrounding the retired Big Brown and Monticello plants, redesignating those areas as attainment based on monitoring data supporting an attainment designation. In June 2021, the EPA published two notices; one that it was withdrawing the August 2019 Error Correction Rule and a second separate notice denying petitions from Luminant and the State of Texas to reconsider the original nonattainment designations. We, along with the State of Texas, challenged that EPA action and have consolidated it with the pending challenge in the Fifth Circuit Court, and this case was argued before the Fifth Circuit Court in July 2022. In September 2021, the TCEQ considered a proposal for its nonattainment SIP revision for the Martin Lake area and an agreed order to reduce SO 2 emissions from the plant. The proposed agreed order associated with the SIP proposal reduces emission limits as of January 2022. Emission reductions required are those necessary to demonstrate attainment with the NAAQS. The TCEQ's SIP action was finalized in February 2022 and has been submitted to the EPA for review and approval. Ozone Designations The EPA issued a final rule in October 2015 lowering the ozone NAAQS from 75 to 70 parts per billion. Areas surrounding our Dicks Creek, Miami Fort and Zimmer facilities in Ohio, our Calumet facility in Illinois and our Wise, Ennis and Midlothian facilities in Texas were designated marginal nonattainment areas in June 2018 by the EPA with an attainment deadline of August 2021. The EPA is required to take action on areas that did not attain by that date by bumping up the region to a "moderate" designation with an attainment deadline of August 2024. States will be required to develop SIPs to address emissions in areas with a higher (more stringent) classification. CCR/Groundwater The combustion of coal to generate electric power creates large quantities of ash and byproducts that are managed at power generation facilities in dry form in landfills and in wet form in surface impoundments. Each of our coal-fueled plants has at least one CCR surface impoundment. At present, CCR is regulated by the states as solid waste. Coal Combustion Residuals The EPA's CCR rule, which took effect in October 2015, establishes minimum federal requirements for the construction, retrofitting, operation and closure of, and corrective action with respect to, existing and new CCR landfills and surface impoundments, as well as inactive CCR surface impoundments. The requirements include location restrictions, structural integrity criteria, groundwater monitoring, operating criteria, liner design criteria, closure and post-closure care, recordkeeping and notification. The deadlines for beginning and completing closure vary depending on several factors. The Water Infrastructure Improvements for the Nation Act (the WIIN Act), which was enacted in December 2016, provides for EPA review and approval of state CCR permit programs. 16 Table of Contents In August 2018, the D.C. Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR rule, including an applicability exemption for legacy impoundments. In August 2020, the EPA issued a final rule establishing a deadline of April 11, 2021 to cease receipt of waste and initiate closure at unlined CCR impoundments. The final rule allows a generation plant to seek the EPA's approval to extend this deadline if no alternative disposal capacity is available and either a conversion to comply with the CCR rule is underway or retirement will occur by either 2023 or 2028 (depending on the size of the impoundment at issue). Prior to the November 2020 deadline, we submitted applications to the EPA requesting compliance extensions under both conversion and retirement scenarios. In November 2020, environmental groups petitioned for review of this rule in the D.C. Circuit Court, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020. Also, in November 2020, the EPA finalized a rule that would allow an alternative liner demonstration for certain qualifying facilities. In November 2020, we submitted an alternate liner demonstration for one CCR unit at Martin Lake. In August 2021, we submitted a request to transfer our conversion application for the Zimmer facility to a retirement application following announcement that Zimmer will close by May 31, 2022. In January 2022, the EPA determined that our conversion and retirement applications for our CCR facilities were complete but has not yet proposed action on any of those applications. In addition, in January 2022, the EPA also made a series of public statements, including in a press release, that purported to impose new, more onerous closure requirements for CCR units. The EPA issued these new purported requirements without prior notice and without following the legal requirements for adopting new rules. These new purported requirements announced by the EPA are contrary to existing regulations and the EPA's prior positions. In April 2022, we, along with the Utility Solid Waste Activities Group (USWAG), a trade association of over 130 utility operating companies, energy companies, and certain other industry associations, filed petitions for review with the D.C. Circuit Court and have asked the court to determine that the EPA cannot implement or enforce the new purported requirements because the EPA has not followed the required procedures. The State of Texas and the TCEQ have intervened in support of the petitions filed by the Vistra subsidiaries and USWAG, and various environmental groups have intervened on behalf of the EPA. Briefing on this petition will be complete by May 2023. MISO — In 2012, the Illinois Environmental Protection Agency (IEPA) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities' CCR surface impoundments. These violation notices remain unresolved; however, in 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east, and west fly ash CCR surface impoundments. We have completed closure activities at those ponds at our Baldwin facility. At our retired Vermilion facility, which was not potentially subject to the EPA's 2015 CCR rule until the aforementioned D.C. Circuit Court decision in August 2018, we submitted proposed corrective action plans involving closure of two CCR surface impoundments ( i.e. , the old east and the north impoundments) to the IEPA in 2012, and we submitted revised plans in 2014. In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options. In May 2018, Prairie Rivers Network (PRN) filed a citizen suit in federal court in Illinois against Dynegy Midwest Generation, LLC (DMG), alleging violations of the Clean Water Act for alleged unauthorized discharges. In August 2018, we filed a motion to dismiss the lawsuit. In November 2018, the district court granted our motion to dismiss and judgment was entered in our favor. In June 2021, the U.S. Court of Appeals for the Seventh Circuit affirmed the district court's dismissal of the lawsuit. In April 2019, PRN also filed a complaint against DMG before the Illinois Pollution Control Board (IPCB), alleging that groundwater flows allegedly associated with the ash impoundments at the Vermilion site have resulted in exceedances both of surface water standards and Illinois groundwater standards dating back to 1992. We answered that complaint in July 2021, and this matter is currently abated. In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities' CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the federal CCR rule. In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface impoundments at our retired Vermilion facility, which is owned by our subsidiary DMG, and that notice was referred to the Illinois Attorney General. In June 2021, the Illinois Attorney General and the Vermilion County State Attorney filed a complaint in Illinois state court with an agreed interim consent order which the court subsequently entered. Given the violation notices and the enforcement action, the unique characteristics of the site, and the proximity of the site to the only national scenic river in Illinois, we agreed to enter into the interim consent order to resolve this matter. Per the terms of the agreed interim consent order, DMG is required to evaluate the closure alternatives under the requirements of the newly implemented Illinois Coal Ash regulation (discussed below) and close the site by removal. In addition, the interim consent order requires that during the impoundment closure process, impacted groundwater will be collected before it leaves the site or enters the nearby Vermilion river and, if necessary, DMG will be required to install temporary riverbank protection if the river migrates within a certain distance of the impoundments. The interim order was modified in December 2022 to require certain amendments to the Safety Emergency Response Plan. These proposed closure costs are reflected in the ARO in our consolidated balance sheets (see Note 20 to the Financial Statements). 17 Table of Contents In July 2019, coal ash disposal and storage legislation in Illinois was enacted. The legislation addresses state requirements for the proper closure of coal ash ponds in the state of Illinois. The law tasks the IEPA and the IPCB to set up a series of guidelines, rules and permit requirements for closure of ash ponds. Under the final rule, which was finalized and became effective in April 2021, coal ash impoundment owners would be required to submit a closure alternative analysis to the IEPA for the selection of the best method for coal ash remediation at a particular site. The rule does not mandate closure by removal at any site. In May 2021, we filed an appeal in the Illinois Fourth Judicial District over certain provisions of the final rule and that case remains pending. Other parties have also filed appeals of certain provisions of the final rule. In October 2021, we filed operating permit applications for 18 impoundments as required by the Illinois coal ash rule, and filed construction permit applications for three of our sites in January 2022 and five of our sites in July 2022. One additional closure construction application will be filed for our Baldwin facility in 2023. For all of the above matters, if certain corrective action measures, including groundwater treatment or removal of ash, are required at any of our coal-fueled facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows. The Illinois coal ash rule was finalized in April 2021 and does not require removal. However, the rule required us to undertake further site specific evaluations required by each program. We will not know the full range of decommissioning costs, including groundwater remediation, if any, that ultimately may be required under the Illinois rule until permit applications have been approved by the IEPA. However, the currently anticipated CCR surface impoundment and landfill closure costs, as reflected in our existing ARO liabilities, reflect the costs of closure methods that our operations and environmental services teams believe are appropriate and protective of the environment for each location. Water The EPA and the environmental regulatory bodies of states in which we operate have jurisdiction over the diversion, impoundment and withdrawal of water for cooling and other purposes and the discharge of wastewater (including storm water) from our facilities. We believe our facilities are presently in material compliance with applicable federal and state requirements relating to these activities. We believe we hold all required permits relating to these activities for facilities in operation and have applied for or obtained necessary permits for facilities under construction. We also believe we can satisfy the requirements necessary to obtain any required permits or renewals. Effluent Limitation Guidelines (ELGs) — In November 2015, the EPA revised the ELGs for steam electricity generation facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, such as FGD, fly ash, bottom ash and flue gas mercury control wastewaters. Various parties filed petitions for review of the ELG rule, and the petitions were consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions requesting reconsideration of the ELG rule and administratively stayed the rule's compliance date deadlines. In April 2019, the Fifth Circuit Court vacated and remanded portions of the EPA's ELG rule pertaining to effluent limitations for legacy wastewater and leachate. The EPA published a final rule in October 2020 that extends the compliance date for both FGD and bottom ash transport water to no later than December 2025, as negotiated with the state permitting agency. Additionally, the final rule allows for a retirement exemption that exempts facilities certifying that units will retire by December 2028 provided certain effluent limitations are met. In November 2020, environmental groups petitioned for review of the new ELG revisions, and Vistra subsidiaries filed a motion to intervene in support of the EPA in December 2020. In July 2021, the EPA announced its intent to revise the ELG rule and moved to hold the 2020 ELG revision litigation in abeyance pending the EPA's completion of its reconsideration rulemaking. Notifications were made to Texas, Illinois and Ohio state agencies on the retirement exemption for applicable coal plants by the regulatory deadline of October 13, 2021. Radioactive Waste The nuclear industry has developed ways to store used nuclear fuel on site at nuclear generation facilities, primarily using dry cask storage, since there are no facilities for reprocessing or disposal of used nuclear fuel currently in operation in the U.S. Luminant stores its used nuclear fuel on-site in storage pools or dry cask storage facilities and believes its on-site used nuclear fuel storage capability is sufficient for the foreseeable future. 18 Table of Contents Item 1A. RISK FACTORS Summary of Risk Factors The following summarizes the principal factors that make an investment in our company speculative or risky, all of which are more fully described in the Risk Factors section below. This summary should be read in conjunction with the Risk Factors section and should not be relied upon as an exhaustive summary of the material risks facing our business. The following factors could result in harm to our business, financial condition, results of operations, cash flows, and prospects, among other impacts: Market, Financial and Economic Risks • Our revenues, results of operations and operating cash flows are affected by price fluctuations in the wholesale power market and other market factors beyond our control. • We purchase natural gas, coal, fuel oil, and nuclear fuel for our generation facilities, and higher than expected fuel costs or disruptions in these fuel markets may have an adverse impact on, our costs, revenues, results of operations, financial condition and cash flows. • We have retired, announced planned retirements of, and may be forced to retire or idle additional underperforming generation units which could result in significant costs and have an adverse effect on our operating results. • Our assets or positions cannot be fully hedged against changes in commodity prices and market heat rates, and hedging transactions may not work as planned or hedge counterparties may default on their obligations. • Competition, changes in market structure, and/or state or federal interference in the wholesale and retail power markets, together with subsidized generation, may have a material adverse effect on our financial condition, results of operations and cash flows. • Our results of operations and financial condition could be materially and adversely affected by energy market participants continuing to construct new generation facilities or expanding or enhancing existing generation facilities despite relatively low power prices and such additional generation capacity results in a reduction in wholesale power prices. • Our liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets or during times of significant fluctuation in commodity prices, and we may be unable to access capital on favorable terms or at all in the future, which could have a material adverse effect on us. • The agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures, contain restrictions and limitations that could affect our ability to operate our business, our liquidity, and our results of operations, and any failure to comply with these restrictions could have a material adverse effect on us. • We may not be able to complete future acquisitions on favorable terms or at all, successfully integrate future acquisitions into our business, or effectively identify and invest in value-creating businesses, assets or projects, which could result in unanticipated expenses and losses or otherwise hinder or delay our growth strategy. • Our ability to achieve the expected growth of our Vistra Zero portfolio, consisting of our solar generation, ESS, and other renewables development projects, is subject to substantial capital requirements and other significant uncertainties. • Tax legislation initiatives or challenges to our tax positions, or potential future legislation or the imposition of new or increased taxes or fees, could have a material adverse effect on our financial condition, results of operations and cash flows. • We are required to pay the holders of TRA Rights for certain tax benefits, which amounts are expected to be substantial. 19 Table of Contents Regulatory and Legislative Risks • Our businesses are subject to ongoing complex governmental regulations and legislation that have adversely impacted, and may in the future adversely impact, our businesses, results of operations, liquidity and financial condition. • Our cost of compliance with existing and new environmental laws could have a material adverse effect on us. • Pending or proposed laws or regulations, including those proposed or implemented under the Biden administration, could have a material adverse effect on our businesses, results of operations, liquidity and financial condition. • Changes to laws, rules or regulations related to market structures in the markets in which we participate may have a material adverse effect on our businesses, results of operation, liquidity and financial condition. • We could be materially and adversely affected if current regulations are implemented or if new federal or state legislation or regulations are adopted to address global climate change, or if we are subject to lawsuits for alleged damage to persons or property resulting from greenhouse gas emissions. • Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant liabilities and reputational damage that could have a material adverse effect on us. Operational Risks • Volatile power supply costs and demand for power have and could in the future adversely affect the financial performance of our retail businesses. • Our retail operations are subject to significant competition from other REPs, which could result in a loss of existing customers and the inability to attract new customers. • The operation of our businesses is subject to information security and operational technology risks, including cybersecurity breaches and failure of critical information and operations technology systems. Attacks on our infrastructure that breach cyber/data security measures could expose us to significant liabilities, reputational damage, regulatory action, and disrupt business operations, which could have a material adverse effect on us. • We may suffer material losses, costs and liabilities due to operational risks, regulatory risks, and the risk of nuclear accidents arising from the ownership and operation of the Comanche Peak nuclear generation facility. • The operation and maintenance of power generation facilities and related mining operations are capital intensive and involve significant risks that could adversely affect our results of operations, liquidity and financial condition. • We may be materially and adversely affected by obligations to comply with federal and state regulations, laws, and other legal requirements that govern the operations, assessments, storage, closure, corrective action, disposal and monitoring relating to CCR. • We have been and may in the future be materially and adversely affected by, the effects of extreme weather conditions and seasonality. • Events outside of our control, including an epidemic or outbreak of an infectious disease, such as COVID-19, may materially adversely affect our business. • Changes in technology, increased electricity conservation efforts, or energy sustainability efforts may reduce the value of our generation facilities and may otherwise have a material adverse effect on us. Risks Related to Our Structure and Ownership of our Common Stock • Evolving expectations from stakeholders, including investors, on ESG issues, including climate change and sustainability matters, and erosion of stakeholder trust or confidence could influence actions or decisions about our company and our industry and could adversely affect our business, operations, financial results, or stock price. • We may not pay any dividends on our common stock in the future, and we may not realize the anticipated benefits of our share repurchase program. 20 Table of Contents Please carefully consider the following discussion of significant factors, events, and uncertainties that make an investment in our securities risky. These factors, in addition to others specifically addressed in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) , provide important information for the understanding of our forward-looking statements in this annual report on Form 10-K. If one or more of the factors, events and uncertainties discussed below or in the MD&A were to materialize, our business, results of operations, liquidity, financial condition, cash flows, reputation or prospects could be materially adversely affected. In addition, if one or more of such factors, events and uncertainties were to materialize, it could cause results or outcomes to differ materially from those contained in or implied by any forward-looking statement in this annual report on Form 10-K. There may be further risks and uncertainties that are not currently known or that are not currently believed to be material that may adversely affect our business, results of operations, liquidity, financial condition and prospects and the market price of our common stock in the future. The realization of any of these factors could cause investors in our securities (including our common stock) to lose all or a substantial portion of their investment. Market, Financial and Economic Risks Our revenues, results of operations and operating cash flows generally are affected by price fluctuations in the wholesale power market and other market factors beyond our control. We are not guaranteed any rate of return on capital investments in our businesses. We conduct integrated power generation and retail electricity activities, focusing on power generation, wholesale electricity sales and purchases, retail sales of electricity and natural gas to end users and commodity risk management. Our wholesale and retail businesses are to some extent countercyclical in nature, particularly for the wholesale power and ancillary services supplied to the retail business. However, we do have a wholesale power position that is subject to wholesale power price moves, which may be significant. As a result, our revenues, results of operations and operating cash flows depend in large part upon wholesale market prices for electricity, natural gas, uranium, lignite, coal, fuel, and transportation in our regional markets and other competitive markets in which we operate and upon prevailing retail electricity rates, which may be impacted by, among other things, actions of regulatory authorities. Market prices for power, capacity, ancillary services, natural gas, coal and fuel oil are unpredictable and may fluctuate substantially over relatively short periods of time. Unlike most other commodities, electric power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility due to supply and demand imbalances, especially in the day-ahead and spot markets. Demand for electricity can fluctuate dramatically, creating periods of substantial under- or over-supply. Over-supply can occur as a result of the construction of new power generation sources, as we have observed in recent years. During periods of over-supply, electricity prices might be depressed. For example, the cost of electricity from renewable resources, such as solar, wind and battery ESS, has dropped substantially in recent years. In many instances, energy from these sources are bid into the relevant spot market at a price of zero or close to zero during certain times of the day, lowering the clearing price for all power wholesalers in such market. Also, at times there is political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, bidding rules and other mechanisms to address volatility and other issues in these markets. Extreme weather events can also materially impact power prices or otherwise exacerbate conditions or circumstances that result in volatility of power prices. For example, in February 2021, the U.S. experienced Winter Storm Uri and extreme cold temperatures in the central U.S., including Texas. This severe weather event substantially increased the demand for natural gas used in our electric power generation business, and the cold further limited the availability of renewable generation across the region contributing to extremely high market prices for natural gas and electricity, which resulted in substantial increases in the costs to procure sufficient fuel supply and increased collateral posting requirements. Winter Storm Elliott, in December 2022, was another example of extreme weather across the U.S. that resulted in widespread wholesale power market volatility. The majority of our facilities operate as "merchant" facilities without long-term power sales agreements. As a result, we largely sell electric energy, capacity and ancillary services into the wholesale energy spot market or into other wholesale and retail power markets on a short-term basis and are not guaranteed any rate of return on our capital investments. Consequently, there can be no assurance that we will be able to sell any or all of the electric energy, capacity or ancillary services from those facilities at commercially attractive rates or that our facilities will be able to operate profitably. We depend, in large part, upon prevailing market prices for power, capacity and fuel. Given the volatility of commodity power prices, to the extent we are unable to hedge or otherwise secure long-term power sales agreements for the output of our power generation facilities, our revenues and profitability will be subject to volatility, and our financial condition, results of operations and cash flows could be materially adversely affected. 21 Table of Contents We purchase natural gas, coal, fuel oil, and nuclear fuel for our generation facilities, and higher than expected fuel costs, volatility, or disruption in these fuel markets may have an adverse impact on our costs, revenues, results of operations, financial condition and cash flows. We rely on natural gas, coal, fuel oil, and nuclear fuel for the majority of our power generation facilities. Delivery of these fuels to the facilities is dependent upon the continuing availability of such fuels and financial viability of contractual counterparties as well as upon the infrastructure (including mines, rail lines, rail cars, barge facilities, roadways, riverways and natural gas pipelines) available and functioning to serve each generation facility, and geopolitical risk, including the current Russia and Ukraine conflict and the potential for additional U.S. sanctions against Russia. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Significant Activities and Events and Items Influencing Future Performance - Macroeconomic Conditions . As a result, we have experienced, and remain subject to the risks of disruptions or curtailments in the production of power at our generation facilities if no fuel is available at any price, if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure. Certain of our generation facilities rely on a limited number of counterparties, such as natural gas suppliers and railcar companies, to provide the necessary fuel. Disputes relating to or non-performance of contractual arrangements, have resulted in, and may continue to result in adverse impacts to our costs, revenues, results of operations, financial condition, and cash flows. As part of our strategy to mitigate the potential negative effects of commodity price volatility, we have sold forward a substantial portion of our expected power sales in the next three years in order to lock in long-term prices. In order to hedge our obligations under these forward power sales contracts, we have entered into long-term and short-term contracts for the purchase and delivery of fuel. Many of the forward power sales contracts do not allow us to pass through changes in fuel costs or discharge the power sale obligations in the case of a disruption in fuel supply due to force majeure events or the default of a fuel supplier or transporter. Fuel costs (including diesel, natural gas, lignite, coal and nuclear fuel) are volatile, and the wholesale price for electricity does not always change at the same rate as changes in fuel costs, and disruptions in our fuel supplies may therefore require us to find alternative fuel sources at costs which may be higher than planned, to find other sources of power to deliver to counterparties at a higher cost, or to pay damages to counterparties for failure to deliver power as contracted. Long-term and short-term contracts are subject to risk of non-delivery or claims of force majeure, which may impact our ability to economically recover the value of the contract. In addition, we purchase and sell natural gas and other energy related commodities, and volatility in these markets may affect costs incurred in meeting our obligations. Further, any changes in the costs of natural gas, coal, fuel oil, nuclear fuel or transportation rates and changes in the relationship between such costs and the market prices of power will affect our financial results. If we are unable to procure fuel for physical delivery at prices we consider favorable, or if we are unable to procure these fuels at all, our financial condition, results of operations and cash flows could be materially adversely affected. For example, supply challenges were among the primary drivers of the significant loss experienced in 2021 as a result of Winter Storm Uri. We also buy significant quantities of fuel on a short-term or spot market basis. Prices for all of our fuels fluctuate, sometimes rising or falling significantly over a relatively short period of time. The price we can obtain for the sale of energy may not rise at the same rate, or may not rise at all, to match a rise in fuel or delivery costs. This may have a material adverse effect on our financial and operating performance. Volatility in market prices for fuel and electricity results from, among other factors: • demand for energy commodities and general economic conditions, including impacts of inflation and the relative strength or weakness of U.S. dollar compared to other currencies; • volatility in commodity prices and the supply of commodities, including but not limited to natural gas, coal and fuel oil; • volatility in market heat rates; • volatility in coal and rail transportation prices; • volatility in nuclear fuel and related enrichment and conversion services; • transmission or transportation disruptions, constraints, congestion, inoperability or inefficiencies of electricity, natural gas or coal transmission or transportation, or other changes in power transmission infrastructure; • severe, sustained or unexpected weather conditions, including extreme cold, drought and limitations on access to water; • seasonality; • changes in electricity and fuel usage resulting from conservation efforts, changes in technology or other factors; • illiquidity in the wholesale electricity or other commodity markets; • importation of liquified natural gas to certain markets; • development and availability of new fuels, new technologies and new forms of competition for the production and storage of power, including competitively priced alternative energy sources or storage; • changes in market structure and liquidity; 22 Table of Contents • changes in the way we operate our facilities, including curtailed operation due to market pricing, environmental regulations and legislation, safety or other factors; • changes in generation capacity or efficiency; • outages or otherwise reduced output from our generation facilities or those of our competitors; • changes in electric capacity, including the addition of new supplies of power as a result of the development of new plants, expansion of existing plants, the continued operation of uneconomic power plants due to federal, state or local subsidies, or additional transmission capacity; • local, regional, national, or global supply chain constraints or shortages; • our creditworthiness and liquidity and the willingness of fuel suppliers and transporters to do business with us; • changes in the credit risk, payment practices, or financial condition of market participants; • changes in production and storage levels of natural gas, lignite, coal, uranium, diesel and other refined products; • pandemics and epidemics (including the impacts thereto, or recovery therefrom), natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events; and • changes in law, including judicial decisions, federal, state and local energy, environmental and other regulation and legislation. See " Economic downturns would likely have a material adverse effect on our businesses" for a discussion of potential risks arising from current U.S. and global economic and geopolitical conditions. We have retired, announced planned retirements of, and may be forced to retire or idle additional underperforming generation units which could result in significant costs and have an adverse effect on our operating results. A sustained decrease in the financial results from, or the value of, our generation units has resulted in the retirement or planned retirement of, and ultimately could result in additional retirements or idling of, generation units. We have operated certain of our lignite- and coal-fueled generation assets only during parts of the year that have higher electricity demand and, therefore, higher related wholesale electricity prices. In connection with the closure and remediation of retired generation units, we have spent, and may in the future spend, a significant amount of money, internal resources and time to complete the required closure and reclamation, which could have a material adverse effect on our financial and operating performance. Our assets or positions cannot be fully hedged against changes in commodity prices and market heat rates, and hedging transactions may not work as planned, or counterparties may default on their obligations, which could have a material adverse impact on our business, financial condition, results of operations and cash flows. Our hedging activities do not fully protect us against the risks associated with changes in commodity prices, most notably electricity and natural gas prices, because of the expected useful life of our generation assets and the size of our position relative to the duration of available markets for various hedging activities. Generally, commodity markets that we participate in to hedge our exposure to electricity prices and heat rates have limited liquidity after two to three years. Further, our ability to hedge our revenues by utilizing cross-commodity hedging strategies with natural gas hedging instruments is generally limited to a duration of four to five years. To the extent we have unhedged positions, fluctuating commodity prices and/or market heat rates can materially impact our results of operations, cash flows, liquidity and financial condition, either favorably or unfavorably. To manage our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge portions of purchase and sale commitments, fuel requirements and inventories of natural gas, lignite, coal, diesel fuel, uranium and refined products, and other commodities, within established risk management guidelines. As part of this strategy, we routinely utilize fixed-price forward physical purchase and sale contracts, futures, financial swaps and option contracts traded in over-the-counter markets or on exchanges. Given our exposure to risks of commodity price movements, we devote a considerable amount of time and effort to the establishment of risk management policies and procedures, as well as the ongoing review of the implementation of these policies and procedures. Additionally, we have processes and controls in place that are designed to monitor and accurately report hedging activities and positions. The policies, procedures, processes and controls in place may not always function as planned and cannot eliminate all the risks associated with these activities, including unauthorized hedging activity, or improper reporting thereof, by our employees in violation of our existing risk management policies and procedures. For example, we hedge the expected needs of our wholesale and retail customers, but unexpected changes due to weather, natural disasters, consumer behavior, market constraints or other factors could cause us to purchase electricity to meet unexpected demand in periods of high wholesale market prices or resell excess electricity into the wholesale market in periods of low prices. As a result of these and other factors, the impacts of our commodity hedging activities and risk management decisions may have a material adverse effect on our business, financial condition, results of operations and cash flows. 23 Table of Contents Based on economic and other considerations, including our available liquidity, we may not be able to, or we may decide not to, hedge the entire exposure of our operations to commodity price risk. To the extent we do not hedge against commodity price risk and applicable commodity prices change in ways adverse to us, we could be materially and adversely affected. To the extent we do hedge against commodity price risk, those hedges may ultimately prove to be ineffective. Additionally, there may be changes to existing laws or regulations that could significantly impact our ability to effectively hedge, which may have a material adverse effect on us. With the continued tightening of credit markets that began in 2008 and expansion of regulatory oversight through various financial reforms, there has been a decline in the number of market participants in the wholesale energy commodities markets, resulting in less liquidity. Notably, participation by financial institutions and other intermediaries (including investment banks) in such markets has declined. Extended declines in market liquidity could adversely affect our ability to hedge our financial exposure to desired levels. To the extent we engage in hedging and risk management, and power purchase agreement activities, we are exposed to the credit risk that counterparties that owe us money, energy or other commodities as a result of these activities will not perform their obligations to us. Should the counterparties to these arrangements fail to perform, we could be forced to enter into alternative hedging arrangements or honor the underlying commitment at then-current market prices. Additionally, our counterparties may seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the Bankruptcy Code. Our credit risk may be exacerbated to the extent collateral held by us cannot be realized or is liquidated at prices not sufficient to recover the full amount due to us. There can be no assurance that any such losses or impairments to the carrying value of our financial assets would not materially and adversely affect our financial condition, results of operations and cash flows. In such event, we could incur losses or forgo expected gains in addition to amounts, if any, already paid to the counterparties. Market participants in the ISOs/RTOs in which we operate are also exposed to risks that another market participant may default on its obligations to pay such ISO/RTO for electricity or services taken, in which case such costs, to the extent not offset by posted security and other protections available to such ISO/RTO, may be allocated to various non-defaulting ISO/RTO market participants, including us. We do not apply hedge accounting to our commodity derivative transactions, which may cause increased volatility in our quarterly and annual financial results. We engage in economic hedging activities to manage our exposure related to commodity price fluctuations through the use of financial and physical derivative contracts for commodities. These derivatives are accounted for in accordance with GAAP, which requires that we record all derivatives on the balance sheet at fair value with changes in fair value immediately recognized in earnings as unrealized gains or losses. GAAP permits an entity to designate qualifying derivative contracts as normal purchases and sales. If designated, those contracts are not recorded at fair value. GAAP also permits an entity to designate qualifying derivative contracts in a hedge accounting relationship. If a hedge accounting relationship is used, a significant portion of the changes in fair value is not immediately recognized in earnings. We have elected not to apply hedge accounting to our commodity contracts, and we have designated contracts as normal purchases and sales in only limited cases, such as certain retail sales contract portfolios. As a result, our quarterly and annual financial results in accordance with GAAP are subject to significant fluctuations caused by changes in forward commodity prices. Competition, changes in market structure, and/or state or federal interference in the wholesale and retail power markets, together with subsidized generation, may have a material adverse effect on our financial condition, results of operations and cash flows. Our generation and competitive retail businesses rely on a competitive wholesale marketplace. The competitive wholesale marketplace may be undermined by changes in market structure and out-of-market subsidies provided by federal or state entities, including bailouts of uneconomic plants, imports of power from Canada, renewable mandates or subsidies, as well as out-of-market payments to new generators. Multiple potential changes are currently being evaluated by the PUCT and the Texas legislature for the ERCOT market, including the PCM that would align a required reliability standard with resource availability during higher-risk system conditions, the ultimate resolution of which is unknown. 24 Table of Contents Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, other energy service companies and financial institutions in the sale of electric energy, capacity and ancillary services, as well as in the procurement of fuel, transmission and transportation services. Moreover, aggregate demand for power may be met by generation capacity based on several competing technologies, as well as power generating facilities fueled by alternative or renewable energy sources, including hydroelectric power, synthetic fuels, solar, wind, wood, geothermal, waste heat and solid waste sources. Regulatory initiatives designed to enhance and/or subsidize renewable generation increases competition from these types of facilities and out-of-market subsidies to existing or new generation can undermine the competitive wholesale marketplace, which can lead to premature retirement of existing facilities, including those owned by us. We also compete against other energy merchants on the basis of our relative operating skills, financial position and access to credit sources. Electric energy customers, wholesale energy suppliers and transporters often seek financial guarantees, credit support such as letters of credit and other assurances that their energy contracts will be satisfied. Companies with which we compete may have greater resources or experience in these areas. Over time, some of our plants may become unable to compete because of subsidized generation, including public utility commission supported power purchase agreements, and the construction of new plants. Such new plants could have a number of advantages including more efficient equipment and newer technology that could result in fewer emissions or more advantageous locations on the electric transmission system. Additionally, these competitors may be able to respond more quickly to new laws and regulations because of the newer technology utilized in their facilities or the additional resources derived from owning more efficient facilities. Other factors may contribute to increased competition in wholesale power markets. We expect that we will continue to face intense competition from numerous companies, including new entrants or consolidation of existing competitors, in the industry. Certain federal and state entities in jurisdictions in which we operate have either enacted or are considering regulations or legislation to subsidize otherwise uneconomic plants and attempt to incentivize, including through certain tax benefits, the construction and development of additional renewable resources as well as increases in energy efficiency investments. For example, the Inflation Reduction Act of 2022 contains a number of tax credits and incentives relating to renewable projects and clean energy technologies such as nuclear energy. New entrants or existing competitors may find it more economical to develop new renewable projects or invest in clean energy technologies in which we would like to invest. Subsidies (or increases thereto) to our competitors could result in increased competition for us, which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, our retail marketing efforts compete for customers in a competitive environment, which impacts the margins that we can earn on the volumes we are able to serve. Further, with retail competition, it is easier for residential customers where we serve load to switch to and from competitive electricity generation suppliers for their energy needs. The volatility and uncertainty that results from such mobility may have material adverse effects on our financial condition, results of operations and cash flows. For example, if fewer customers switch to another supplier than anticipated, the load we must serve will be greater than anticipated and, if market prices of fuel have increased, our costs will increase more than expected due to the need to go to the market to cover the incremental supply obligation. If more customers switch to another supplier than anticipated, the load we must serve will be lower than anticipated and, if market prices of electricity have decreased, our operating results could suffer. Our results of operations and financial condition could be materially and adversely affected by energy market participants continuing to construct new generation facilities or expanding or enhancing existing generation facilities despite relatively low power prices and such additional generation capacity results in a reduction in wholesale power prices. Given the overall attractiveness of certain of the markets in which we operate and certain tax benefits associated with renewable energy, among other matters, energy market participants have continued to construct new generation facilities or invest in enhancements or expansions of existing generation facilities despite relatively low wholesale power prices. Assuming this market dynamic continues, our results of operations and financial condition could be materially and adversely affected if such additional generation capacity results in an over-supply of electricity that causes a reduction in wholesale power prices. Additionally, new or existing market participants without, or with less, fossil fuel operations may gain additional market share, or reduce our market share, due to evolving expectations and sentiments of key stakeholders, government, and regulatory authorities regarding our operations and activities. 25 Table of Contents Economic downturns would likely have a material adverse effect on our businesses. Our results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including lower prices for power, generation capacity and natural gas, which can fluctuate substantially. Increased unemployment of residential customers and decreased demand for products and services by commercial and industrial customers resulting from an economic downturn could lead to declines in the demand for energy and an increase in the number of uncollectible customer balances, which would negatively impact our overall sales and cash flows. The convergence of current global conditions, including sustained inflation, rising interest rates, and the geopolitical climate, has and could lead to, or accelerate or exacerbate the occurrence of, a significant economic downturn, as well as changes in consumer and counterparty behavior, higher costs of capital, decreases in the value of our existing long-dated contracts, commodity price increases and volatility, supply chain shortages, and other adverse impacts to our business. Additionally, prolonged economic downturns that negatively impact our financial condition, results of operations and cash flows could result in future material impairment charges to write down the carrying value of certain assets to their respective fair values. Our liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets or during times of significant fluctuation in commodity prices, and we may be unable to access capital on favorable terms or at all in the future, which could have a material adverse effect on us. We currently maintain non-investment grade credit ratings that could negatively affect our ability to access capital on favorable terms or result in higher collateral requirements, particularly if our credit ratings were to be downgraded in the future. Our businesses are capital intensive. In general, we rely on access to financial markets and credit facilities as a significant source of liquidity for our capital requirements, hedging transactions and other obligations not satisfied by cash-on-hand or operating cash flows. The inability to raise capital or to access credit facilities, particularly on favorable terms, could adversely impact our liquidity and our ability to meet our obligations or sustain and grow our businesses and could increase capital costs and collateral requirements, any of which could have a material adverse effect on us. Our access to capital and the cost and other terms of acquiring capital are dependent upon, and could be adversely impacted by, various factors, including: • general economic and capital markets conditions, including changes in financial markets that reduce available liquidity or the ability to obtain or renew credit facilities on favorable terms or at all; • conditions and economic weakness in the U.S. power markets; • regulatory developments; • changes in interest rates; • a deterioration, or perceived deterioration, of our creditworthiness, enterprise value or financial or operating results; • a downgrade of Vistra's or its applicable subsidiaries' credit ratings, or credit ratings of its issuances; • our level of indebtedness and compliance with covenants in our debt agreements; • our ability to meet our sustainability targets in our secured credit facilities; • a deterioration of the creditworthiness or bankruptcy of one or more lenders or counterparties under our credit facilities that affects the ability of such lender(s) to make loans to us; • credit, security, or collateral requirements, including those relating to volatility in commodity prices; • general credit availability from banks or other lenders for us and our industry peers; • investor and lender confidence in and sentiment of the industry, our business, and the wholesale electricity markets in which we operate; • a material breakdown in or oversight in effectuating our risk management procedures; • the occurrence of changes in our businesses; • disruptions, constraints, or inefficiencies in the continued reliable operation of our generation facilities and ESSs; and • changes in or the operation of provisions of tax and regulatory laws. 26 Table of Contents There are also increasing financial risks for companies that own and operate fossil fuel generation as institutional lenders or other sources of capital have become more attentive to sustainable financing practices and some of them may seek commitments on emission reduction targets or expected use or proceeds when providing funding to, or decline to provide funding for companies who produce or utilize fossil fuel energy or that have higher levels of GHG emissions. We amended our Vistra Operations Credit Agreement to build in Sustainability Adjustments. These adjustments use baseline values from KPI Metrics and provide for decreases in the applicable credit spread adjustments and commitment fee rates if our reported metrics are a certain percentage below the baseline values, adjusted on a year to year basis. Conversely, if our reported metrics are a certain percentage above the baseline values, adjusted on a year to year basis, the applicable credit spread adjustments and fee rates are increased. Building in these adjustments to our credit agreement helps to show lenders we are committed to lowering our GHG emissions, but failing to meet the targets on a regular basis could be viewed negatively by such lenders. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists and others concerned about climate change not to provide funding for companies in the broader energy sector. Limitation on our access to, or increases in our cost of, capital could have a material adverse effect on us. In addition, we currently maintain non-investment grade credit ratings. As a result, we may not be able to access capital on terms (financial or otherwise) as favorable as companies that maintain investment-grade credit ratings or we may be unable to access capital at all at times when the credit markets tighten. In addition, due to our non-investment grade credit ratings, counterparties request collateral support (including cash or letters of credit) in order to enter into certain transactions with us. A downgrade in long-term debt ratings generally causes borrowing costs to increase and the potential pool of investors to shrink and could trigger liquidity demands pursuant to contractual arrangements. Future transactions by Vistra or any of its subsidiaries, including the issuance of additional debt, could result in a temporary or permanent downgrade in our credit ratings. Our indebtedness and the phaseout of LIBOR, or the replacement of LIBOR with a different reference rate, could adversely affect our ability in the future to raise additional capital to fund our operations. It could also expose us to the risk of increased interest rates and limit our ability to react to changes in the economy, or our industry, as well as impact our cash available for distribution. As of December 31, 2022, we had approximately $13.0 billion of total indebtedness and approximately $12.6 billion of indebtedness net of cash. Our debt could have negative consequences for our financial condition including: • increasing our vulnerability to general economic and industry conditions; • requiring a significant portion of our cash flows from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to pay dividends to holders of our common stock or to fund our operations, capital expenditures and future business opportunities; • limiting our ability to enter into long-term power sales or fuel purchases which require credit support; • limiting our ability to fund operations or future acquisitions; • limiting our ability to repurchase shares under the share repurchase program; • restricting our ability to make distributions or pay dividends with respect to our capital stock and the ability of our subsidiaries to make distributions to us, in light of restricted payment and other financial covenants in our credit facilities and other financing agreements; • inhibiting the growth of our stock price; • exposing us to the risk of increased interest rates because certain of our borrowings, including borrowings under the Vistra Operations Credit Facilities, are at variable rates of interest, only a portion of which are hedged; • limiting our ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; and • limiting our ability to adjust to changing market conditions and placing us at a competitive disadvantage compared to our competitors who may have less debt. We may not be successful in obtaining additional capital for these or other reasons. Furthermore, we may be unable to refinance or replace our existing indebtedness on favorable terms or at all upon the expiration or termination thereof. Our failure to obtain additional capital or enter into new or replacement financing arrangements when due may constitute a default under such existing indebtedness and may have a material adverse effect on our business, financial condition, results of operations and cash flows. 27 Table of Contents In July 2017, the United Kingdom's Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. LIBOR is the interest rate benchmark used as a reference rate on a portion of our variable rate debt, including our revolving credit facility and interest rate swaps. In November 2020, ICE Benchmark Administration (IBA), the administrator of LIBOR, with the support of the U.S. Federal Reserve and the United Kingdom's Financial Conduct Authority, announced plans to consult on ceasing publication of USD LIBOR on December 31, 2021 for only the one-week and two-month USD LIBOR tenors, and on June 30, 2023 for all other USD LIBOR tenors. While this announcement extends the transition period to June 2023, the U.S. Federal Reserve concurrently issued a statement advising banks to stop new USD LIBOR issuances by the end of 2021. In light of these announcements, the future of LIBOR at this time is uncertain and any changes in the methods by which LIBOR is determined or regulatory activity related to LIBOR's phaseout could cause LIBOR to perform differently than in the past or cease to exist. Over the course of the last year, in anticipation of LIBOR ceasing to exist for affected tenors, we amended our revolving credit facilities to implement a change to SOFR as our primary reference rate. For our Vistra Operations Credit Agreement, we made this change in conjunction with an extension amendment. Certain lenders chose not to extend their commitments past the original maturity date. As a result, the commitments of those lenders remain subject to a LIBOR based rate. However, unless extended, those commitments, in the amount of $200 million, shall terminate on June 14, 2023 and, assuming no extension of such commitments, at such time all of our revolving credit facilities shall be SOFR based. However, our Term Loan B-3 Facility, with a December 31, 2025 maturity date, remains LIBOR-based and may be subject to the LIBOR transition risks set forth above. Further, certain of our agreements which utilize LIBOR as the referenced rate are governed by New York law, and certain of these contracts do not contain any fallback provisions or otherwise contain fallback provisions that lead to replacement rate based on LIBOR or require polling for interbank rates. To the extent that we are unsuccessful in our efforts to amend such contracts prior to the LIBOR transition, we anticipate that the applicable New York legislation would apply to such contracts and would provide a replacement rate for inclusion in such contracts. Notwithstanding our efforts, these changes may result in interest rates and/or payments that do not correlate over time with the interest rates and/or payments that would have been made on our obligations if LIBOR was available in its current form. Any new contracts would need to reference an alternative benchmark rate or include suggested fallback language. Accordingly, we could be exposed to increased costs with respect to our variable rate debt, which could have an adverse impact on extensions of our credit and/or we might not be fully hedged on the variable rate exposure on our swapped indebtedness. Any such increased costs or exposure could increase our cost of capital and have a material adverse effect on us. The agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures, contain restrictions and limitations that could affect our ability to operate our business, or liquidity, and results of operations, and any failure to comply with these restrictions could have a material adverse effect on us. The agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures, contain restrictions that could adversely affect us by limiting our ability to operate our businesses and plan for, or react to, market conditions or to meet our capital needs and could result in an event of default under the Vistra Operations Credit Facilities and/or indentures. The Vistra Operations Credit Facilities and indentures contain events of default customary for financings of this type. If we fail to comply with the covenants in the Vistra Operations Credit Facilities and/or indentures and are unable to obtain a waiver or amendment, or a default exists and is continuing, the lenders under such agreements or notes, as the case may be, could give notice and declare outstanding borrowings thereunder immediately due and payable. The breach of any covenants or obligations in certain agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures, not otherwise waived or amended, could result in a default under the applicable debt obligations and could trigger acceleration of those obligations, which in turn could trigger cross defaults under other agreements governing our debt, and any such acceleration of outstanding borrowings could have a material adverse effect on us. 28 Table of Contents Certain of our obligations are required to be secured by letters of credit, surety bonds or cash, which increase our costs. If we are unable to provide such security, it may restrict our ability to conduct our business, which could have a material adverse effect on us. We undertake certain hedging and commodity activities and enter into certain financing arrangements with various counterparties that require cash collateral or the posting of letters of credit which are at risk of being drawn down in the event we default on our obligations. We currently use margin deposits, prepayments, surety bonds and letters of credit as credit support for commodity procurement and risk management activities. Future cash collateral requirements may increase based on the extent of our involvement in standard contracts and movements in commodity prices, and also based on our credit ratings and the general perception of creditworthiness in the markets in which we operate. In the case of commodity arrangements, the amount of such credit support that must be provided typically is based on the difference between the price of the commodity in a given contract and the market price of the commodity. Significant movements in market prices can result in our being required to provide cash collateral and letters of credit in very large amounts. The effectiveness of our strategy may be dependent on the amount of collateral available to enter into or maintain these contracts, and liquidity requirements may be greater than we anticipate or will be able to meet. Without a sufficient amount of working capital or other sources of available liquidity to post as collateral, we may not be able to manage price volatility effectively or to implement our strategy. A material increase in the amount of letters of credit or cash collateral required to be provided to our counterparties may have a material adverse effect on us. We may not be able to complete future acquisitions on favorable terms or at all, successfully integrate future acquisitions into our business, or effectively identify and invest in value-creating businesses, assets or projects, which could result in unanticipated expenses and losses or otherwise hinder or delay our growth strategy. As part of our growth strategy, including our desire to grow our retail platform, we may pursue acquisitions of assets or operating entities. This strategy depends on the Company's ability to successfully identify and evaluate acquisition opportunities and consummate acquisitions on favorable terms. Our ability to continue to implement this component of our growth strategy will be limited by our ability to identify appropriate acquisition or joint venture candidates and our financial resources, including available cash and access to capital. In addition, the Company will compete with other companies for these limited acquisition opportunities, which may increase the Company's cost of making acquisitions or limit the Company’s ability to make acquisitions at all. Any expense incurred in completing acquisitions or entering into joint ventures, the time it takes to integrate an acquisition or our failure to integrate acquired businesses successfully could result in unanticipated expenses and losses. Furthermore, we may not be able to fully realize the anticipated benefits from any future acquisitions or joint ventures we may pursue. In addition, the process of integrating acquired operations into our existing operations may involve unknown risks, result in unforeseen operating difficulties and expenses, and may require significant financial resources that would otherwise be available for the execution of our business strategy. If the Company is unable to identify and consummate future acquisitions, it may impede the Company's ability to execute its growth strategy. 29 Table of Contents Our ability to achieve the expected growth of our Vistra Zero portfolio, consisting of our solar generation, ESS, and other renewables development projects, is subject to substantial capital requirements and other significant uncertainties. We have a substantial capital allocation plan intended for investments in renewable assets, including solar development projects and ESSs. As part of our business strategy, we plan to continually assess potential strategic acquisitions or investments in renewable assets, emerging technologies and related projects. Notably, the Company's ability to successfully develop our current renewables projects, or in the future acquire additional renewable assets, may be impacted by the demand for and viability of renewable assets generally, which may vary depending on availability of projects and financing, as well as public policy, financial and tax mechanisms implemented at the state and federal levels to support the development of renewable assets. Various factors could result in increased costs or result in delays or cancellation of our current or future renewable projects, or the loss of, or declines in the value of, our investments in projects including, but not limited to, risks relating to siting, financing, engineering and construction, permitting, interconnection requests, federal and state regulatory approvals, new legislation or regulatory changes impacting the industry, commissioning delays, import tariffs, changes to federal income tax laws, economic events or factors, environmental and community concerns, availability of or requirements for additional funding, enhanced competition, or the potential for termination of the power sales contract as a result of a failure to meet certain milestones. Further, the recent proliferation of renewable projects has resulted in a large volume of interconnection requests submitted to grid operators, including the markets in which we operate, resulting in significant delays to the approval process and estimated completion dates for our projects and others. Additionally, the increased demand for construction of renewables projects, such as ESSs and solar projects, and other labor market and supply chain constraints have resulted, and may continue to result, in limited availability of qualified specialists, contractors, and necessary services or materials, leading to delays in and higher costs for the development and construction of our current and future planned projects. Should any of these factors occur, our financial position, results of operations, and cash flows could be adversely affected, or our future growth opportunities may not be realized as anticipated. While certain of our subsidiaries are in various stages of developing and constructing solar generation facilities and ESSs and certain of these projects have signed long-term contracts or made similar arrangements for the sale of electricity, in other cases, our subsidiaries may enter into obligations in the development process even though the subsidiaries have not yet secured power purchase arrangements or other important elements for a successful project. If the project does not proceed as planned, our subsidiaries may remain obligated for certain liabilities even though the project will not be completed. Development is inherently uncertain and we may forgo certain development opportunities and we may undertake significant development costs before determining that we will not proceed with a particular project. We believe that capitalized costs for projects under development are recoverable; however, there can be no assurance that any individual project will be completed and reach commercial operation. If these development efforts are not successful, we may abandon a project under development and write off the costs incurred in connection with such project and could incur additional losses associated with any related contingent liabilities. Circumstances associated with potential divestitures could adversely affect our results of operations and financial condition. In evaluating our business and the strategic fit of our various assets, we may determine to sell one or more of such assets. Despite a decision to divest an asset, we may encounter difficulty in finding a buyer willing to purchase the asset at an acceptable price and on acceptable terms and in a timely manner. In addition, a prospective buyer may have difficulty obtaining financing. Divestitures could involve additional risks, including: • difficulties in the separation of operations and personnel; • the need to provide significant ongoing post-closing transition support to a buyer; • management's attention may be temporarily diverted; • the retention of certain current or future liabilities in order to induce a buyer to complete a divestiture; • the obligation to indemnify or reimburse a buyer for certain past liabilities of a divested asset; • the disruption of our business; and • potential loss of key employees. We may not be successful in managing these or any other significant risks that we may encounter in divesting any asset, which could adversely affect our results of operations and financial condition. 30 Table of Contents If our goodwill, intangible assets, or long-lived assets become impaired, we may be required to record a significant charge to earnings. We have significant goodwill, intangible assets and long-lived assets recorded on our balance sheet. In accordance with U.S. GAAP, goodwill and non-amortizing intangible assets are required to be tested for impairment at least annually. Additionally, we review goodwill, our intangible assets and long-lived assets for impairment when events or changes in circumstances indicate the carrying value of the asset may not be recoverable. Factors that may be considered include a decline in future cash flows, slower growth rates in the energy industry, and a sustained decrease in the price of our common stock. We performed our annual assessment of goodwill and non-amortizing intangibles in the fourth quarter of 2022 and determined that no material impairment was required. However, impairment assessments will be performed in future periods and may result in an impairment loss, which could be material. Issuances or acquisitions of our common stock, or sales or dispositions of our common stock by stockholders, that result in an ownership change as defined in Internal Revenue Code (IRC) § 382 could further limit our ability to use certain tax attributes and our federal net operating losses to offset our future taxable income. If an "ownership change," as defined in Section 382 of the IRC (IRC §382) occurs, the amount of NOLs that could be used in any one year following such ownership change could be substantially limited. In general, an "ownership change" would occur when there is a greater than 50 percentage point increase in ownership of a company's stock by stockholders, each of which owns (or is deemed to own under IRC §382) 5 percent or more of such company's stock. Given IRC §382's broad definition, an ownership change could be the unintended consequence of otherwise normal market trading in our stock that is outside our control. Vistra acquired NOLs from its merger with Dynegy; however, Vistra's use of such attributes is limited under IRC §382 because the merger constituted an "ownership change" with respect to Dynegy. If there is an "ownership change" with respect to Vistra (including by the normal trading activity of greater than 5% stockholders), the utilization of all NOLs existing at that time would be subject to additional annual limitations based upon a formula provided under IRC §382 that is based on the fair market value of the Company and prevailing interest rates at the time of the ownership change. In addition, any ownership change with respect to Vistra could result in additional limitations on our ability to use certain tax attributes, including depreciation, existing at the time of any such ownership change and have an impact on our tax liabilities and on our obligations under the TRA. Tax legislation initiatives or challenges to our tax positions, or potential future legislation or the imposition of new or increased taxes or fees, could have a material adverse effect on our financial condition, results of operations and cash flows. We are subject to the tax laws and regulations of the U.S. federal, state and local governments. From time to time, legislative measures may be enacted that could adversely affect our overall tax positions regarding income or other taxes. There can be no assurance that our effective tax rate or tax payments will not be adversely affected by these legislative measures. The Tax Cuts and Jobs Act of 2017 (TCJA), enacted December 22, 2017, and the Inflation Reduction Act (IRA), enacted August 16, 2022, both introduced significant changes to current U.S. federal tax law. For example, the IRA includes the enactment of several new proposals, including, but not limited to (i) a corporate alternative minimum tax based on book income and (ii) additional requirements to qualify for enhanced renewable energy tax credits. These changes are complex and continue to be the subject of additional guidance issued by the U.S. Treasury and the Internal Revenue Service. In addition, the reaction to the federal tax changes by the individual states continues to evolve. Our interpretations and assumptions around U.S. tax reform may evolve in future periods as further administrative guidance and regulations are issued, which may materially affect our effective tax rate or tax payments. U.S. federal, state and local tax laws and regulations are extremely complex and subject to varying interpretations. There can be no assurance that our tax positions will be sustained if challenged by relevant tax authorities and if not sustained, there could be a material impact on our results of operations and financial condition. U.S. federal income tax reform and changes in other tax laws could adversely affect us. Additionally, states in which we operate or own assets may impose new or increased taxes or fees on various aspects of our operations. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income tax laws or the imposition of new or increased taxes or fees could have a material adverse effect on our financial condition, results of operations and cash flows. 31 Table of Contents We are required to pay the holders of TRA Rights for certain tax benefits, which amounts could be substantial. On the Effective Date, we entered into the TRA with American Stock Transfer & Trust Company, LLC, as the transfer agent. Pursuant to the TRA, we issued beneficial interests in the rights to receive payments under the TRA (TRA Rights) to the first lien creditors of our Predecessor to be held in escrow for the benefit of the first lien creditors of our Predecessor entitled to receive such TRA Rights under the Plan of Reorganization. Our financial statements reflect a liability of $522 million as of December 31, 2022 related to these future payment obligations (see Note 7 to the Financial Statements). This amount is based on certain assumptions as described more fully in the notes to the financial statements and the actual payments made under the TRA could be materially different than this estimate. The TRA generally provides for the payment by us to the holders of TRA Rights of 85% of the amount of cash savings, if any, in U.S. federal, state and local income tax that we and our subsidiaries actually realize as a result of our use of (a) the tax basis step up attributable to the PrefCo Preferred Stock Sale, (b) the entire tax basis of the assets acquired as a result of the purchase and sale agreement, dated as of November 25, 2015 by and between La Frontera Ventures, LLC and Luminant, and (c) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA, plus interest accruing from the due date of the applicable tax return. The amount and timing of any payments under the TRA will vary depending upon a number of factors, including the amount and timing of the taxable income we generate in the future and the tax rate then applicable, our use of loss carryovers and the portion of our payments under the TRA constituting imputed interest. Although we are not aware of any issue that would cause the IRS to challenge the tax benefits that are the subject of the TRA, recipients of the payments under the TRA will not be required to reimburse us for any payments previously made if such tax benefits are subsequently disallowed. As a result, in such circumstances, Vistra could make payments under the TRA that are greater than its actual cash tax savings. Any amount of excess payment can be used to reduce future TRA payments, but cannot be immediately recouped, which could adversely affect our liquidity. Because Vistra is a holding company with no operations of its own, its ability to make payments under the TRA is dependent on the ability of its subsidiaries to make distributions to it. To the extent that Vistra is unable to make payments under the TRA because of the inability of its subsidiaries to make distributions to us for any reason, such payments will be deferred and will accrue interest until paid, which could adversely affect our results of operations and could also affect our liquidity in periods in which such payments are made. The payments we will be required to make under the TRA could be substantial. We may be required to make an early termination payment to the holders of TRA Rights under the TRA. The TRA provides that, in the event that Vistra breaches any of its material obligations under the TRA, or upon certain mergers, asset sales, or other forms of business combination or certain other changes of control, the transfer agent under the TRA may treat such event as an early termination of the TRA, in which case Vistra would be required to make an immediate payment to the holders of the TRA Rights equal to the present value (at a discount rate equal to LIBOR plus 100 basis points) of the anticipated future tax benefits based on certain valuation assumptions. As a result, upon any such breach or change of control, we could be required to make a lump sum payment under the TRA before we realize any actual cash tax savings and such lump sum payment could be greater than our future actual cash tax savings. The aggregate amount of these accelerated payments could be materially more than our estimated liability for payments made under the TRA set forth in our financial statements, which could have a substantial negative impact on our liquidity. 32 Table of Contents Regulatory and Legislative Risks Our businesses are subject to ongoing complex governmental regulations and legislation that have adversely impacted, and may in the future adversely impact, our businesses, results of operations, liquidity, financial condition and cash flows. Our businesses operate in changing market environments influenced by various state and federal legislative and regulatory initiatives regarding the restructuring of the energy industry, including competition in power generation and sale of electricity, natural gas, carbon offsets and renewable energy certificates, and other commodities. Although we attempt to comply with changing legislative and regulatory requirements, there is a risk that we will fail to adapt to any such changes successfully or on a timely basis. Compliance with, or changes to, the requirements under these legal and regulatory regimes, including those proposed or implemented under the Biden administration, may adversely impact our businesses, results of operations, liquidity, financial condition and cash flows. Our businesses are subject to numerous state and federal laws (including, but not limited to, PURA, the Federal Power Act, the Natural Gas Policy Act, the Atomic Energy Act, the Public Utility Regulatory Policies Act of 1978, the Clean Air Act (CAA), the Clean Water Act (CWA), the Resource Conservation and Recovery Act (RCRA), the Energy Policy Act of 2005, the Dodd-Frank Wall Street Reform and the Consumer Protection Act and the Telephone Consumer Protection Act), changing governmental policy and regulatory actions (including those of the FERC, the NERC, the RCT, the MSHA, the EPA, the NRC, the DOJ, the FTC, the CFTC, state public utility commissions and state environmental regulatory agencies), and the rules, guidelines and protocols of ERCOT, CAISO, ISO-NE, MISO, NYISO and PJM with respect to various matters, including, but not limited to, market structure and design, operation of nuclear generation facilities, construction and operation of other generation facilities, development, operation and reclamation of lignite mines, recovery of costs and investments, decommissioning costs, market behavior rules, present or prospective wholesale and retail competition, administrative pricing mechanisms (and adjustments thereto), rates for wholesale sales of electricity, mandatory reliability standards and environmental matters. We, along with other market participants, are subject to electricity pricing constraints and market behavior and other competition-related rules and regulations. Additionally, Ambit’s direct selling business (i) could be found by federal, state or foreign regulators not to be in compliance with applicable law or regulations, which may lead to our inability to obtain or maintain a license, permit, or similar certification and (ii) may be required to alter its compensation practices in order to comply with applicable federal or state law or regulations. Changes in, revisions to, or reinterpretations of, existing laws and regulations may have a material adverse effect on our businesses, results of operations, liquidity, financial condition and cash flows. Extreme weather events have resulted, and in the future may result, in efforts by both federal and state government and regulatory agencies to investigate and determine the causes of such events. For example, as a result of Winter Storm Uri, we received a civil investigative demand from the Attorney General of Texas as well as a request for information from ERCOT, NERC, and other regulatory bodies related to this event. The recent Winter Storm Elliott has also led to regulatory requests for information and notices of investigation by NERC, FERC, regional reliability entities, and independent market monitors for regions across the country. Such efforts have resulted, and in the future may result, in changes in laws or regulations that impact our industry and businesses including, but not limited to, additional requirements for winterization of various facets of the electricity supply chain including generation, transmission, and fuel supply; improvements in coordination among the various participants in the electricity supply chain during any future event; restrictions or limitations on the types of plans permitted to be offered to customers; potential revisions to the method or calculation of market compensation and incentives relating to the continued operation of assets that only run periodically, including during extreme weather events or other times of scarcity; and other potential legislative and regulatory corrective actions that may be taken. Previously announced or future legal proceedings, regulatory actions, investigations, or other administrative proceedings involving market participants may lead to adverse determinations or other findings of violations of laws, rules or regulations, any of which may impact the ability of market participants to satisfy, in whole or in part, their respective obligations. The Texas Legislature, the PUCT, and ERCOT have implemented new requirements and continue to consider future market design and other rule changes in response to Winter Storm Uri and other extreme weather events. 33 Table of Contents Finally, the regulatory environment has undergone significant changes in the last several years due to state and federal policies affecting wholesale and retail competition and the creation of incentives for the addition of large amounts of new renewable generation. For example, changes to, or development of, legislation that requires the use of clean renewable and alternate fuel sources or mandate the implementation of energy conservation programs that require the implementation of new technologies, could increase our capital expenditures and/or impact our financial condition. Additionally, in some retail energy markets, state legislators, government agencies and other interested parties have made proposals to change the use of market-based pricing, re-regulate areas of these markets that have previously been competitive, or permit electricity delivery companies to construct or acquire generating facilities. Other proposals to re-regulate the retail energy industry may be made, and legislative or other actions affecting electricity and natural gas deregulation or restructuring process may be delayed, discontinued or reversed in states in which we currently operate or may in the future operate. If such changes were to be enacted by a regulatory body, we may lose customers, incur higher costs and/or find it more difficult to acquire new customers. These changes are ongoing, and we cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on our business. We are required to obtain, and to comply with, government permits and approvals. We are required to obtain, and to comply with, numerous permits and licenses from federal, state and local governmental agencies. The process of obtaining and renewing necessary permits and licenses can be lengthy and complex and can sometimes result in the establishment of conditions that make the project or activity for which the permit or license was sought unprofitable or otherwise unattractive. In addition, such permits or licenses may be subject to denial, revocation or modification under various circumstances. Failure to obtain or comply with the conditions of permits or licenses, or failure to comply with applicable laws or regulations, may result in the delay or temporary suspension of our operations and electricity sales or the curtailment of our delivery of electricity to our customers and may subject us to penalties and other sanctions. Although various regulators routinely renew existing permits and licenses, renewal of our existing permits or licenses could be denied or jeopardized by various factors, including (a) failure to provide adequate financial assurance for closure, (b) failure to comply with environmental, health and safety laws and regulations or permit conditions, (c) local community, political or other opposition and (d) executive, legislative or regulatory action. Our inability to procure and comply with the permits and licenses required for our operations, or the cost to us of such procurement or compliance, could have a material adverse effect on us. In addition, new environmental legislation or regulations, if enacted, or changed interpretations of existing laws, may cause activities at our facilities to need to be changed to avoid violating applicable laws and regulations or elicit claims that historical activities at our facilities violated applicable laws and regulations. In addition to the possible imposition of fines in the case of any such violations, we may be required to undertake significant capital investments and obtain additional operating permits or licenses, which could have a material adverse effect on us. Our cost of compliance with existing and new environmental laws could have a material adverse effect on us. We are subject to extensive environmental regulation by governmental authorities, including federal and state environmental agencies and/or attorneys general. We may incur significant additional costs beyond those currently contemplated to comply with these regulatory requirements. If we fail to comply with these regulatory requirements, we could be subject to administrative, civil or criminal liabilities and fines. Existing environmental regulations could be revised or reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air emissions and CCR, all of which could result in significant additional costs beyond those currently contemplated to comply with existing requirements. Any of the foregoing could have a material adverse effect on us. The EPA has recently finalized or proposed several regulatory actions establishing new requirements for control of certain emissions from sources, including electricity generation facilities. In the future, the EPA may also propose and finalize additional regulatory actions that may adversely affect our existing generation facilities or our ability to cost-effectively develop new generation facilities. There is no assurance that the currently installed emissions control equipment at our lignite, coal and/or natural gas-fueled generation facilities will satisfy the requirements under any future EPA or state environmental regulations. Some of the recent regulatory actions, such as the EPA's proposed Cross-State Air Pollution Rule Update, the ACE rule and any proposed or future actions to replace the ACE rule, and actions under the Regional Haze program, could require us to install significant additional control equipment, resulting in potentially material costs of compliance for our generation units, including capital expenditures, higher operating and fuel costs and potential production curtailments or plant retirements. These costs or operation impacts could have a material adverse effect on us. 34 Table of Contents We may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, if we fail to obtain, maintain or comply with any such approval or if an approval is retroactively disallowed or adversely modified, the operation of our generation facilities could be stopped, disrupted, curtailed or modified or become subject to additional costs. Any such stoppage, disruption, curtailment, modification or additional costs could have a material adverse effect on us. In addition, we may be responsible for any on-site liabilities associated with the environmental condition of facilities that we have acquired, leased, developed or sold, regardless of when the liabilities arose and whether they are now known or unknown. In connection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certain environmental liabilities. Another party could, depending on the circumstances, assert an environmental claim against us or fail to meet its indemnification obligations to us, which could have a material adverse effect on us. We could be materially and adversely affected if new federal or state legislation or regulations are adopted to address global climate change that could require efforts that exceed or are more expensive than our currently planned initiatives or if we are subject to lawsuits for alleged damage to persons or property resulting from greenhouse gas emissions. There is attention and interest nationally and internationally about global climate change and how GHG emissions, such as CO 2 , contribute to global climate change. Over the last several years, the U.S. Congress has considered and debated several proposals intended to address climate change using different approaches, including a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade), a tax on carbon or GHG emissions, incentives for the development of low-carbon technology and federal renewable portfolio standards. In July 2019, the EPA finalized the ACE rule that developed emissions guidelines that states must use when developing plans to regulate GHG emissions from existing coal-fueled electric generating units. In January 2021, the ACE rule was vacated by the D.C. Circuit Court and remanded to the EPA for further consideration in accordance with the court's ruling. The D.C. Circuit Court's decision was appealed to the U.S. Supreme Court. In June 2022, the U.S. Supreme Court issued its decision in West Virginia v. EPA , in which it held that the EPA does not have the authority to apply generation shifting in the regulation of GHG emissions. The judgment reversed the D.C. Circuit Court's decision and remanded the case for further proceedings consistent with the U.S. Supreme Court's opinion. The EPA may develop a more stringent and more encompassing rule to replace the ACE rule in its remand proceeding and has been directed by the Biden Administration to review this rule and others promulgated by the EPA during the Trump Administration. Prior to the vacatur and remand by the D.C. Circuit Court, states where we operate coal plants (Texas, Illinois and Ohio) had begun the development of their state plans to comply with the ACE rule. In addition, a number of federal court cases have been filed in recent years asserting damage claims related to GHG emissions, and the results in those proceedings could establish adverse precedent that might apply to companies (including us) that produce GHG emissions. We could be materially and adversely affected if new federal and/or state legislation or regulations are adopted to address global climate change that could require efforts that exceed or are more expensive than our currently planned initiatives or if we are subject to lawsuits for alleged damage to persons or property resulting from GHG emissions. Additionally, in January 2021, President Biden issued written notification to the United Nations of the U.S.'s intention to rejoin the Paris Agreement, effective in February 2021. Although the Paris Agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions, and various corporations, investors and U.S. states and local governments have previously pledged to further the goals of the Paris Agreement. Additionally, the Biden Administration has directed certain agencies to submit a plan to the National Climate Task Force to achieve a carbon-pollution-free electricity sector by 2035. The Company's plan to transition to clean power generation sources and reduce its GHG emissions may not be completed in this timeframe and we may not otherwise achieve our sustainability and emissions reduction targets as expected. Accordingly, we may be required to accelerate or change our targets, incur additional expenses, and/or adjust or cease certain operations as a result of newly implemented federal and/or state regulations to reduce future carbon emissions. 35 Table of Contents Luminant's mining operations are subject to RCT oversight. We currently own and operate, or are in the process of reclaiming, various surface lignite coal mines in Texas to provide fuel for our electricity generation facilities. We also own or lease, and are in the process of reclaiming, multiple waste-to-energy surface facilities in Pennsylvania. The RCT, which exercises broad authority to regulate reclamation activity, reviews on an ongoing basis whether Luminant is compliant with RCT rules and regulations and whether it has met all the requirements of its mining permits in Texas. Any new rules and regulations adopted by the RCT or the Department of Interior Office of Surface Mining, which also regulates mining activity nationwide, or any changes in the interpretation of existing rules and regulations, could result in higher compliance costs or otherwise adversely affect our financial condition or cause a revocation of a mining permit. Any revocation of a mining permit would mean that Luminant would no longer be allowed to mine lignite at the applicable mine to serve its generation facilities. Luminant's lignite mining reclamation activity will require significant resources as existing and retired mining operations are reclaimed over the next several years. In conjunction with Luminant's announcements in 2017 to retire several power generation assets and related mining operations, along with the continuous reclamation activity at its continuing mining operations for its mines related to the Oak Grove generation asset, Luminant is expected to spend a significant amount of money, internal resources and time to complete the required reclamation activities. For the next five years, Vistra is projected to spend approximately $234 million (on a nominal basis) to achieve its mining reclamation objectives. Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant liabilities and reputational damage that could have a material adverse effect on us. We are involved in the ordinary course of business in a number of lawsuits involving, among other matters, employment, commercial, and environmental issues, and other claims for injuries and damages. We evaluate litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these evaluations and estimates, when required by applicable accounting rules, we establish reserves and disclose the relevant litigation claims or legal proceedings, as appropriate. These evaluations and estimates are based on the information available to management at the time and involve a significant amount of judgment. Actual outcomes or losses may differ materially from current evaluations and estimates. The settlement or resolution of such claims or proceedings may have a material adverse effect on us. We use appropriate means to contest litigation threatened or filed against us, but the litigation environment poses a significant business risk. We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings, and we are exposed to the risk that we may become the subject of additional regulatory investigations or administrative proceedings. While we cannot predict the outcome of any regulatory investigation or administrative proceeding, any such regulatory investigation or administrative proceeding could result in us incurring material penalties and/or other costs and have a materially adverse effect on us. 36 Table of Contents Our retail businesses, which each have REP certifications that are subject to review of the public utility commissions in the states in which we operate, are subject to changing state rules and regulations that could have a material impact on the profitability of our business. The competitiveness of our U.S. retail businesses partially depends on state regulatory policies that establish the structure, rules, terms and conditions on which services are offered to retail customers. Specifically, the public utility commissions and/or the attorney generals of the various jurisdictions in which the Retail segment operates may at any time initiate an investigation into whether our retail operations comply with certain commission rules or state laws and whether we have met the requirements for REP certification, including financial requirements. These state policies and investigations, which can include controls on the retail rates our retail businesses can charge, the imposition of additional costs on sales, restrictions on our ability to obtain new customers through various marketing channels and disclosure requirements, investigations into whether our retail operations comply with certain commission rules or state laws and whether we have met the requirements for REP certification, including financial requirements, can affect the competitiveness of our retail businesses. Any removal or revocation of a REP certification would mean that we would no longer be allowed to provide electricity service to retail customers in the applicable jurisdiction, and such decertification could have a material adverse effect on us. Additionally, state or federal imposition of net metering or renewable portfolio standard programs can make it more or less expensive for retail customers to supplement or replace their reliance on grid power. Our retail businesses may have limited ability to influence development of these state rules, regulations and policies, and our business model may be more or less effective, depending on changes to the regulatory environment. Operational Risks Volatile power supply costs and demand for power have and could in the future adversely affect the financial performance of our retail businesses. Although we are the primary provider of our retail businesses' wholesale electricity supply requirements, our retail businesses purchase a portion of their supply requirements from third parties. As a result, the financial performance of our retail business depends on their ability to obtain adequate supplies of electric generation from third parties at prices below the prices they charge their customers. Consequently, our earnings and cash flows could be adversely affected in any period in which the retail businesses' wholesale electricity supply costs rise at a greater rate than the rates they charge to customers. The price of wholesale electricity supply purchases associated with the retail businesses' energy commitments can be different than that reflected in the rates charged to customers due to, among other factors: • varying supply procurement contracts used and the timing of entering into related contracts; • subsequent changes in the overall price of natural gas; • daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices; • transmission constraints and the Company's ability to move power to our customers; • out-of-market payments, uplifts, or other non-pass through charges, and • changes in market heat rate. The retail businesses' earnings and cash flows could also be adversely affected in any period in which their customers' actual usage of electricity significantly varies from the forecasted usage, which could occur due to, among other factors, weather events, transmission and distribution outages, demand-side management programs, competition and economic conditions, such as Winter Storm Uri in February 2021. Our retail operations are subject to significant competition from other REPs, which could result in a loss of existing customers and the inability to attract new customers. We operate in a very competitive retail market and, as a result, our retail operation faces significant competition for customers. We believe our brands are viewed favorably in the retail electricity markets in which we operate, but despite our commitment to providing superior customer service and innovative products, customer sentiment toward our brands, including by comparison to our competitors' brands, depends on certain factors beyond our control. For example, competitor REPs may offer different products, lower electricity prices and other incentives, which, despite our long-standing relationship with many customers, may attract customers away from us. If we are unable to successfully compete with competitors in the retail market it is possible our retail customer counts could decline, which could have a material adverse effect on us. 37 Table of Contents As we try to grow our retail business and operate our business strategy, we compete with various other REPs that may have certain advantages over us. For example, in new markets, our principal competitor for new customers may be the incumbent REP, which has the advantage of long-standing relationships with its customers, including well-known brand recognition. In addition to competition from the incumbent REP, we may face competition from a number of other energy service providers, other energy industry participants, or nationally branded providers of consumer products and services who may develop businesses that will compete with us. Some of these competitors or potential competitors may be larger than we are or have greater resources or access to capital than we have. If there is inadequate potential margin in retail electricity markets with substantial competition to overcome the adverse effect of relatively high customer acquisition costs in such markets, it may not be profitable for us to compete in these markets. Our retail operations rely on the infrastructure of local utilities or independent transmission system operators to provide electricity to, and to obtain information about, our customers. Any infrastructure failure could negatively impact customer satisfaction and could have a material adverse effect on us. The substantial majority of our retail operations depend on transmission and distribution facilities owned and operated by unaffiliated utilities to deliver the electricity that we sell to our customers. If transmission capacity is inadequate, our ability to sell and deliver electricity may be hindered and we may have to forgo sales or buy more expensive wholesale electricity than is available in the capacity-constrained area or, with respect to capacity performance in PJM and performance incentives in ISO-NE, we may be subject to significant penalties. For example, during some periods, transmission access is constrained in some areas of the Dallas-Fort Worth metroplex, where we have a significant number of customers. The cost to provide service to these customers may exceed the cost to provide service to other customers, resulting in lower operating margins. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to our customers could negatively impact customer satisfaction with our service. Any of the foregoing could have a material adverse effect on us. The operation of our businesses is subject to advanced persistent cyber-based security threats and integrity risk. Attacks on our infrastructure that breach cyber/data security measures could expose us to significant liabilities, reputational damage, regulatory action, and disrupt business operations, which could have a material adverse effect on us. Numerous functions affecting the efficient operation of our businesses are dependent on the secure and reliable storage, processing and communication of electronic data and the use of sophisticated computer hardware and software systems and much of our information technology infrastructure is connected (directly or indirectly) to the internet. Our information technology systems and infrastructure, and those of our vendors and suppliers, are susceptible to threats which could compromise confidentiality, integrity or availability. While we have controls in place designed to protect our infrastructure, such breaches and threats are becoming increasingly sophisticated and complex, requiring continuing evolution of our program. Any such breach, disruption or similar event that impairs our information technology infrastructure could disrupt normal business operations and affect our ability to control our generation assets, maintain confidentiality, availability and integrity of our restricted data, access retail customer information and limit communication with third parties, which could have a material adverse effect on us. As part of the continuing development of new and modified reliability standards, the FERC has approved changes to its Critical Infrastructure Protection reliability standards and has established standards for assets identified as "critical cyber assets." Under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1 million per day, per violation) for failure to comply with mandatory electric reliability standards, including standards to protect the power system against potential disruptions from cyber/data and physical security breaches. Further, our retail business requires us to access, collect, store and transmit sensitive customer data in the ordinary course of business. Concerns about data privacy and data protection have led to increased regulation and other actions that could impact our businesses and changes in data privacy and data protection laws and regulations or any failure to comply with such laws and regulations could adversely affect our business and financial results. Our retail business may need to provide sensitive customer data to vendors and service providers who require access to this information in order to provide services, such as call center operations, to the retail business. 38 Table of Contents Although we take precautions to protect our infrastructure, we have been, and will likely continue to be, subject to attempts at phishing and other cybersecurity intrusions. International conflict increases the risk of state-sponsored cyber threats and escalated use of cybercriminal and cyber-espionage activities. In particular, the current geopolitical climate has further escalated cybersecurity risk, with various government agencies, including the U.S. Cybersecurity & Infrastructure Security Agency, issuing warnings of increased cyber threats, particularly for U.S. critical infrastructure. 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 there is no assurance that we will be able to prevent any such impacts in the future. If a material breach of our information technology systems were to occur, the critical operational capabilities and reputation of our business may be adversely affected, customer confidence may be diminished, and our business may be subject to substantial legal or regulatory scrutiny and claims, any of which may contribute to potential legal or regulatory actions against the Company, loss of customers and otherwise have a material adverse effect on us. Any loss or disruption of critical operational capabilities to support our generation, commercial or retail operations, loss of customers, or loss of confidential or proprietary data through a breach, unauthorized access, disruption, misuse or disclosure could adversely affect our reputation, expose us to material legal or regulatory claims and impair our ability to execute our business strategy, which could have a material adverse effect on us. In addition, we may experience increased capital and operating costs to implement increased security for our information technology infrastructure. We cannot provide any assurance that such events and impacts will not be material in the future, and our efforts to deter, identify and mitigate future breaches may require additional significant capital and may not be successful. We may suffer material losses, costs and liabilities due to operation risks, regulatory risks, and the risk of nuclear accidents arising from the ownership and operation of the Comanche Peak nuclear generation facility. We own and operate a nuclear generation facility in Glen Rose, Texas (Comanche Peak Facility). The ownership and operation of a nuclear generation facility involves certain risks. These risks include: • unscheduled outages or unexpected costs due to equipment, mechanical, structural, cybersecurity, insider threat, third-party compromise or other problems; • inadequacy or lapses in maintenance protocols; • the impairment of reactor operation and safety systems due to human error or force majeure; • the costs of, and liabilities relating to, storage, handling, treatment, transport, release, use and disposal of radioactive materials; • the costs of procuring nuclear fuel, including impacts from restrictions on imports from Russia or China; • the costs of storing and maintaining spent nuclear fuel at our on-site dry cask storage facility; • terrorist or cybersecurity attacks by nation-states or other threat actors and the cost to protect and recover against any such attack; • the impact of a natural disaster; • limitations on the amounts and types of insurance coverage commercially available; and • uncertainties with respect to the technological and financial aspects of modifying or decommissioning nuclear facilities at the end of their useful lives. Any prolonged unavailability of the Comanche Peak Facility could have a material adverse effect on our results of operation, cash flows, financial position and reputation. The following are among the more significant related risks: • Operational Risk — Operations at any generation facility could degrade to the point where the facility would have to be shut down. If such degradations were to occur at the Comanche Peak Facility, the process of identifying and correcting the causes of the operational downgrade to return the facility to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments. Furthermore, a shut-down or failure at any other nuclear generation facility could cause regulators to require a shut-down or reduced availability at the Comanche Peak Facility. • Regulatory Risk — The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under it or the terms of the licenses of nuclear generation facilities. Unless extended, as to which no assurance can be given, the NRC operating licenses for the two licensed operating units at the Comanche Peak Facility will expire in 2030 and 2033, respectively. Changes in regulations by the NRC, as well as any extension of our operating licenses, could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs. 39 Table of Contents • Nuclear Accident Risk — Although the safety record of the Comanche Peak Facility and other nuclear generation facilities generally has been very good, accidents and other unforeseen problems have occurred both in the U.S. and elsewhere. The consequences of an accident can be severe and include loss of life, injury, lasting negative health impacts and property damage. Any accident, or perceived accident, could result in significant liabilities and damage our reputation. Any such resulting liability from a nuclear accident could exceed our resources, including insurance coverage, and could ultimately result in the suspension or termination of power generation from the Comanche Peak Facility. The operation and maintenance of power generation facilities and related mining operations are capital intensive and involve significant risks that could adversely affect our results of operations, liquidity and financial condition. The operation and maintenance of power generation facilities and related mining operations involve many risks, including, as applicable, start-up risks, breakdown or failure of facilities, equipment or processes, operator error, lack of sufficient capital to maintain the facilities, the dependence on a specific fuel source, the ability to timely obtain parts for equipment repairs, the inability to transport our product to our customers in an efficient manner due to the lack of transmission capacity or the impact of unusual or adverse weather conditions or other natural events, or terrorist attacks, as well as the risk of performance below expected levels of output, efficiency or reliability, the occurrence of any of which could result in substantial lost revenues and/or increased expenses. A significant number of our facilities were constructed many years ago. Older generating equipment, even if maintained or refurbished in accordance with good engineering practices, may require significant capital expenditures to operate at peak efficiency or reliability. The risk of increased maintenance and capital expenditures arises from (a) increased starting and stopping of generation equipment due to the volatility of the competitive generation market and the prospect of continuing low wholesale electricity prices that may not justify sustained or year-round operation of all our generation facilities, (b) any unexpected failure to generate power, including failure caused by equipment breakdown or unplanned outage (whether by order of applicable governmental regulatory authorities, the impact of weather events or natural disasters or otherwise), (c) damage to facilities due to storms, natural disasters, wars, terrorist or cyber/data security acts, including nation-state attacks or organized cyber and other catastrophic events and (d) the passage of time and normal wear and tear. Further, our ability to successfully and timely complete routine maintenance or other capital projects at our existing facilities is contingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful, we could be subject to additional costs or losses and write downs of our investment in the project. We cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety laws and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected events (such as environmental impacts, natural disasters or terrorist or cyber/data security attacks). The unexpected requirement of large capital expenditures could have a material adverse effect on us. Moreover, if we significantly modify a unit, we may be required to install the best available control technology or to achieve the lowest achievable emission rates as such terms are defined under the new source review provisions of the CAA, which would likely result in substantial additional capital expenditures. In addition, unplanned outages at any of our generation facilities, whether because of equipment breakdown or otherwise, typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWh or non-performance penalties or require us to incur significant costs as a result of running one of our higher cost units or to procure replacement power at spot market prices in order to fulfill contractual commitments. If we do not have adequate liquidity to meet margin and collateral requirements, we may be exposed to significant losses, may miss significant opportunities and may have increased exposure to the volatility of spot markets, which could have a material adverse effect on us. Further, our inability to operate our generation facilities efficiently, manage capital expenditures and costs, and generate earnings and cash flows from our asset-based businesses could have a material adverse effect on our results of operations, financial condition or cash flows. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance, warranties or performance guarantees may not be adequate to cover our lost revenues, increased expenses or liquidated damages payments should we experience equipment breakdown or non-performance by contractors or vendors. 40 Table of Contents Operation of power generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on our revenues and results of operations, and we may not have adequate insurance to cover these risks and hazards. Our employees, contractors, customers and the general public may be exposed to a risk of injury due to the nature of our operations. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of equipment and delivering electricity to transmission and distribution systems. In addition to natural risks such as extreme weather, earthquake, flood, lightning, hurricane and wind, other human-made hazards, such as nuclear accidents, dam failure, gas or other explosions, mine area collapses, fire, structural collapse, machinery failure and other dangerous incidents are inherent risks in our operations. These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. Further, our employees and contractors work in, and customers and the general public may be exposed to, potentially dangerous environments at or near our operations. As a result, employees, contractors, customers and the general public are at risk for serious injury, including loss of life. The occurrence of any one of these events may result in us being named as a defendant in lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties. We maintain an amount of insurance protection that we consider adequate, but we cannot provide any assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject and, even if we do have insurance coverage for a particular circumstance, we may be subject to a large deductible and maximum cap. A successful claim for which we are not fully insured could hurt our financial results and materially harm our financial condition. Further, due to rising insurance costs and changes in the insurance markets, including increasing pressure on firms that provide insurance to companies that own and operate fossil fuel generation, we cannot provide any assurance that our insurance coverage will continue to be available at all or at rates or on terms similar to those presently available. Any losses not covered by insurance could have a material adverse effect on our financial condition, results of operations or cash flows. We have been and may in the future be materially and adversely affected by obligations to comply with federal and state regulations, laws, and other legal requirements that govern the operations, assessments, storage, closure, corrective action, disposal and monitoring relating to CCR. As a result of electricity produced for decades at coal-fueled power plants in Illinois, Texas and Ohio, we manage large amounts of CCR material in surface impoundments. In addition to the federal requirements under the CCR rule, CCR surface impoundments will continue to be regulated by existing state laws, regulations and permits, as well as additional legal requirements that may be imposed in the future. These federal and state laws, regulations and other legal requirements may require or result in additional expenditures, increased operating and maintenance costs and/or result in closure of certain power generating facilities, which could affect the results of operations, financial position and cash flows of the Company. We have recognized ARO related to these CCR-related requirements. As the closure and CCR management work progresses and final closure plans and corrective action measures are developed and approved at each site, the scope and complexity of work and the amount of CCR material could be greater than current estimates and could, therefore, materially impact earnings through increased compliance expenditures. 41 Table of Contents The EPA has been directed by the Biden Administration to review a number of environmental rules adopted by the EPA during the Trump Administration, including the CCR rule, the ELG rule, the ACE rule and the particulate matter (PM) and NAAQS rules. All of these rules may significantly and adversely impact our existing coal fleet and may lead to accelerated plant closure timeframes. In addition, the expected replacement to the ACE rule and NAAQS also have the potential to adversely impact our gas-fired units. The EPA is reviewing applications submitted by us to extend closure deadlines for many of our CCR impoundments. The scope and cost of that closure work could increase significantly based on new or potential requirements imposed by the EPA or state agencies, including the EPA's interpretations on requirements for closure of CCR units. There is no assurance that our current assumptions for closure activities will be accepted by the EPA. If ponds must be closed sooner than anticipated, plant closures timeframes may be accelerated. The availability and cost of emission allowances could adversely impact our costs of operations. We are required to maintain, through either allocations or purchases, sufficient emission allowances for SO 2 , CO 2 and NO X to support our operations in the ordinary course of operating our power generation facilities. These allowances are used to meet the obligations imposed on us by various applicable environmental laws. If our operational needs require more than our allocated allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as not to exceed our available emission allowances or install costly new emission controls. As we use the emission allowances that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such allowances are available for purchase, but only at significantly higher prices, the purchase of such allowances could materially increase our costs of operations in the affected markets. We have been and may in the future be materially and adversely affected by the effects of extreme weather conditions and seasonality. We have been and may in the future be materially affected by weather conditions and our businesses may fluctuate substantially on a seasonal basis as the weather changes. In addition, we are subject to the effects of extreme weather conditions, including sustained or extreme cold or hot temperatures, hurricanes, floods, droughts, storms, fires, earthquakes or other natural disasters, which could stress our generation facilities and grid reliability, limit our ability to procure adequate fuel supply, or result in outages, damage or destroy our assets and result in casualty losses that are not ultimately offset by insurance proceeds, and could require increased capital expenditures or maintenance costs, including supply chain costs. Moreover, an extreme weather event could cause disruption in service to customers due to downed wires and poles or damage to other operating equipment, which could result in us foregoing sales of electricity and lost revenue. Similarly, certain extreme weather events have previously affected, and may in the future, affect, the availability of generation and transmission capacity, limiting our ability to source or deliver power where it is needed or limit our ability to source fuel for our plants, including due to damage to rail or natural gas pipeline infrastructure. Additionally, extreme weather has resulted, and may in the future result, in (i) unexpected increases in customer load, requiring our retail operation to procure additional electricity supplies at wholesale prices in excess of customer sales prices for electricity, (ii) the failure of equipment at our generation facilities, (iii) a decrease in the availability of, or increases in the cost of, fuel sources, including natural gas, diesel and coal, or (iv) unpredictable curtailment of customer load by the applicable ISO/RTO in order to maintain grid reliability, resulting in the realization of lower wholesale prices or retail customer sales. For example, Winter Storm Uri in February 2021 had a material impact on our results of operations. Additionally, climate change may produce changes in weather or other environmental conditions, including temperature or precipitation levels, and thus may impact consumer demand for electricity. In addition, the potential physical effects of climate change, such as increased frequency and severity of storms, floods, and other climatic events, could disrupt our operations and cause us to incur significant costs to prepare for or respond to these effects. Weather conditions, which cannot be reliably predicted, could have adverse consequences by requiring us to seek additional sources of electricity when wholesale market prices are high or to sell excess electricity when market prices are low, as well as significantly limiting the supply of, or increasing the cost of our fuel supply, each of which could have a material adverse effect on our business, results of operations, financial condition and liquidity. 42 Table of Contents Events outside of our control, including an epidemic or outbreak of an infectious disease, such as COVID-19, may materially adversely affect our business. We face risks related to epidemics, outbreaks or other public health events that are outside of our control, and could significantly disrupt our operations and adversely affect our financial condition. The global or national outbreak of an illness or other communicable disease, or any other public health crisis, such as COVID-19, may cause disruptions to our business and operational plans, as a result of a number of factors, including (a) a protracted slowdown of broad sectors of the economy, (b) changes in demand or supply for commodities, (c) significant changes in legislation or regulatory policy to address the pandemic (including prohibitions on certain marketing channels, moratoriums or conditions on disconnections or limits or restrictions on late fees), (d) reduced demand for electricity (particularly from commercial and industrial customers), (e) increased late or uncollectible customer payments, (f) negative impacts on the health of our workforce, (g) a deterioration of our ability to ensure business continuity (including increased vulnerability to cyber and other information technology risks as a result of a significant portion of our workforce continuing to work from home), and (h) the inability of the Company's contractors, suppliers, and other business partners to fulfill their contractual obligations. Changes in technology, increased electricity conservation efforts, or energy sustainability efforts may reduce the value of our generation facilities and may otherwise have a material adverse effect on us. Technological advances have improved, and are likely to continue to improve, for existing and alternative methods to produce and store power, including gas turbines, wind turbines, fuel cells, hydrogen, micro turbines, photovoltaic (solar) cells, batteries and concentrated solar thermal devices, along with improvements in traditional technologies. Such technological advances may be superior to, or may not be compatible with, some of our existing technologies, investments and infrastructure, and may require us to make significant expenditures to remain competitive, and have resulted, and are expected to continue to reduce the costs of power production or storage, which may result in the obsolescence of certain of our operating assets. Consequently, the value of our more traditional generation assets could be significantly reduced as a result of these competitive advances, which could have a material adverse effect on us and our future success will depend, in part, on our ability to anticipate and successfully adapt to technological changes, to offer services and products that meet customer demands and evolving industry standards. In addition, changes in technology have altered, and are expected to continue to alter, the channels through which retail customers buy electricity ( i.e. , self-generation or distributed-generation facilities). To the extent self-generation or distributed generation facilities become a more cost-effective option for customers, our financial condition, operating cash flows and results of operations could be materially and adversely affected. Technological advances in demand-side management and increased conservation efforts have resulted, and are expected to continue to result, in a decrease in electricity demand. A significant decrease in electricity demand as a result of such efforts would significantly reduce the value of our generation assets. Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce power consumption. Effective power conservation by our customers could result in reduced electricity demand or significantly slow the growth in such demand. Any such reduction in demand could have a material adverse effect on us. Furthermore, we may incur increased capital expenditures if we are required to increase investment in conservation measures. Additionally, increased governmental and consumer focus on energy sustainability efforts, including desire for, or incentives related to, the development, implementation and usage of low-carbon technology, may result in decreased demand for the traditional generation technologies that we currently own and operate. We may potentially be affected by emerging technologies that may over time affect change in capacity markets and the energy industry overall including distributed generation and clean technology. Some of these emerging technologies are shale gas production, distributed renewable energy technologies, energy efficiency, broad consumer adoption of electric vehicles, distributed generation and energy storage devices. Additionally, large-scale cryptocurrency mining is becoming increasingly prevalent in certain markets, including ERCOT, and many of these cryptocurrency mining facilities are "behind-the-meter." Such emerging technologies could affect the price of energy, levels of customer-owned generation, customer expectations and current business models and make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. These emerging technologies may also affect the financial viability of utility counterparties and could have significant impacts on wholesale market prices, which could ultimately have a material adverse effect on our financial condition, results of operations and cash flows could be materially adversely affected. 43 Table of Contents The loss of the services of our key management and personnel could adversely affect our ability to successfully operate our businesses. Our future success will depend on our ability to continue to attract and retain highly qualified personnel. We compete for such personnel with many other companies, in and outside of our industry, government entities and other organizations. We may not be successful in retaining current personnel or in hiring or retaining qualified personnel in the future. Further, we are facing an increasingly competitive market for hiring and retaining skilled employees in certain skill areas, which is exacerbated by the effects of the COVID-19 pandemic and increased acceptance of hiring remote working employees by our competitors and other companies. Difficulties in attracting and retaining highly qualified skilled employees may restrict our ability to adequately support our business needs and/or result in increased personnel costs. In addition, effective succession planning is important to our long-term success. Failure to timely and effectively ensure transfer of knowledge and smooth transitions involving senior management and other key personnel could hinder our strategic planning and execution. We could be materially and adversely impacted by strikes or work stoppages by our unionized employees. As of December 31, 2022, we had approximately 1,295 employees covered by collective bargaining agreements. The terms of all current collective bargaining agreements covering represented personnel engaged in lignite mining operations, lignite-, coal-, natural gas- and nuclear-fueled generation operation, as well as some battery operations, expire on various dates between March 2023 and August 2025, but remain effective thereafter unless and until terminated by either party. In the event that our union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, we would be responsible for procuring replacement labor or we could experience reduced power generation or outages. We have in place strike contingency plans that address the procurement of replacement labor. Strikes, work stoppages or the inability to negotiate current or future collective bargaining agreements on favorable terms or at all could have a material adverse effect on us. Risks Related to Our Structure and Ownership of our Common Stock Vistra is a holding company and its ability to obtain funds from its subsidiaries is structurally subordinated to existing and future liabilities of its subsidiaries. Vistra is a holding company that does not conduct any business operations of its own. As a result, Vistra's cash flows and ability to meet its obligations are largely dependent upon the operating cash flows of Vistra's subsidiaries and the payment of such operating cash flows to Vistra in the form of dividends, distributions, loans or otherwise. These subsidiaries are separate and distinct legal entities from Vistra and have no obligation (other than any existing contractual obligations) to provide Vistra with funds to satisfy its obligations. Any decision by a subsidiary to provide Vistra with funds to satisfy its obligations, including those under the TRA, whether by dividends, distributions, loans or otherwise, will depend on, among other things, such subsidiary's results of operations, financial condition, cash flows, cash requirements, contractual prohibitions and other restrictions, applicable law and other factors. The deterioration of income from, or other available assets of, any such subsidiary for any reason could limit or impair its ability to pay dividends or make other distributions to Vistra. Evolving expectations from stakeholders, including investors, on ESG issues, including climate change and sustainability matters, and erosion of stakeholder trust or confidence could influence actions or decisions about our company and our industry and could adversely affect our business, operations, financial results or stock price. Companies across all industries are facing evolving expectations or increasing scrutiny from stakeholders related to their approach to ESG matters. For Vistra, climate change, safety and stakeholder relations remain primary focus areas, and changing expectations of our practices and performance across these and other ESG areas may impose additional costs or create exposure to new or additional risks. Our operations, projects and growth opportunities require us to have strong relationships with key stakeholders, including local communities and other groups directly impacted by our activities, as well as governments and government agencies, investor advocacy groups, certain institutional investors, investment funds and others which are increasingly focused on ESG practices. Certain financial institutions have announced policies to presently or in the future cease investing or to divest investments in companies that derive any or a specified portion of their income from, or have any or a specified portion of their operations in, fossil fuels. 44 Table of Contents While we are strategically focused on successfully adapting to the energy transition and strongly committed to our ESG practices and performance (including transparency and accountability thereof), our plans to transition to clean power generation sources and reduce our carbon footprint may not be completed in the timeframe and we may not achieve our targets as expected, which could impact stakeholder trust and confidence. Any such erosion of stakeholder trust and confidence, evolving expectations from stakeholders on such ESG issues, and such parties' resulting actions or decisions about our company and our industry could have negative impacts on our business, operations, financial results, and stock price, including: • negative stakeholder sentiment toward us and our industry, including concerns over environmental or sustainability matters and potential changes in federal and state regulatory actions related thereto; • loss of business or loss of market share, including to competitors who do not have any, or comparable amounts, of operations involving fossil fuels; • loss of ability to secure growth opportunities; • the inability to, or increased difficulties and costs of, obtaining services, materials, or insurance from third parties; • reductions in our credit ratings or increased costs of, or limited access to, capital; • delays in project execution; • legal action; • inability or limitations on ability to receive applicable government subsidies, or competitors with smaller or no fossil operations receiving subsidies for which we are not eligible, or in larger amounts; • increased regulatory oversight; • loss of ability to obtain and maintain necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms; • impediments on our ability to acquire or renew rights-of-way or land rights on a timely basis and on acceptable terms; • changing investor sentiment regarding investment in the power and utilities industry or our company; • restricted access to and cost of capital; and • loss of ability to hire and retain top talent. We may not pay any dividends on our common stock in the future, and we may not realize the anticipated benefits of our share repurchase program. In November 2018, we announced that the Board had adopted a dividend program which we initiated in the first quarter of 2019. Each dividend under the program will be subject to declaration by the Board and, thus, may be subject to numerous factors in existence at the time of any such declaration including, but not limited to, prevailing market conditions, our results of operations, financial condition and liquidity, contractual prohibitions and other restrictions with respect to the payment of dividends. There is no assurance that the Board will declare, or that we will pay, any dividends on our common stock in the future. In October 2021, our Board approved a share repurchase program under which up to $2.0 billion of our outstanding common stock may be repurchased. In August 2022, our Board authorized an incremental $1.25 billion for repurchases to bring the total authorized under the share repurchase program to $3.25 billion. Under this share repurchase program or any other future share repurchase programs, we may make share repurchases through a variety of methods, including open share market purchases or privately negotiated transactions. The timing and amount of repurchases, if any, will depend on factors such as the stock price, economic and market conditions, and corporate and regulatory requirements. Any failure to repurchase shares after we have announced our intention to do so may negatively impact our reputation, investor confidence and the price of our common stock. 45 Table of Contents Holders of our preferred stock may have interests and rights that are different from our common stockholders. We are permitted under our certificate of incorporation to issue up to 100,000,000 shares of preferred stock. We can issue shares of our preferred stock in one or more series and can set the terms of the preferred stock without seeking any further approval from our common stockholders. Any preferred stock that we issue may rank ahead of our common stock in terms of dividend priority or liquidation premiums and may have greater voting rights than our common stock, which could dilute the value of our common stock to current stockholders and could adversely affect the market price of our common stock. As of December 31, 2022, 1,000,000 shares of Series A Preferred Stock and 1,000,000 shares of Series B Preferred Stock were issued and outstanding. The Preferred Stock represents a perpetual equity interest in the Company and, unlike our indebtedness, will not give rise to a claim for payment of a principal amount at a particular date; provided , the Company may redeem the Preferred Stock at the specified times (or upon certain specified events) at the applicable redemption price set forth in the certificate of designation of each of the Series A Preferred Stock and Series B Preferred Stock, respectively (Certificates of Designation). The Preferred Stock is not convertible into or exchangeable for any other securities of the Company. Upon the liquidation, dissolution or winding up of the Company, whether voluntary or involuntary, after payment or provision for payment of the debts and other liabilities of the Company, the holders of Preferred Stock will be entitled to receive, pro rata and in preference to the holders of any other capital stock, an amount per share equal to $1,000 plus accrued and unpaid dividends thereon, if any. Unless we have received the affirmative vote or consent of the holders of at least two-thirds of the outstanding Series A Preferred Stock and the holders of at least two-thirds of the outstanding Series B Preferred Stock, voting as a separate class, we may not adopt any amendment to our certificate of incorporation (including the applicable Certificates of Designation) that would have a material adverse effect on the powers, preferences, duties, or special rights of such series of Preferred Stock, subject to certain exceptions. In addition, unless we have received the affirmative vote or consent of the holders of at least two-thirds of the outstanding Series A Preferred Stock and the holders of at least two-thirds of the outstanding Series B Preferred Stock, voting as a class together with the holders of any parity securities upon which like voting rights have been conferred and are exercisable, we may not: (i) create or issue any senior securities, (ii) create or issue any parity securities (including any additional Preferred Stock) if the cumulative dividends payable on the outstanding Preferred Stock (or parity securities, if applicable) are in arrears; (iii) create or issue any additional Preferred Stock or any parity securities with an aggregate liquidation preference, together with the issued and outstanding Preferred Stock and any parity securities that are then outstanding, of greater than $2.5 billion, and (iv) engage in any Transaction that results in a Covered Disposition (as such terms are defined in the Certificates of Designation). In addition, holders of the Preferred Stock are entitled to receive, when, as, and if declared by our Board, semi-annual cash dividends on the Preferred Stock, which are cumulative from the applicable initial issuance date of the Preferred Stock and payable in arrears, and unless full cumulative dividends have been or contemporaneously are being paid or declared on the Preferred Stock, we may not (i) declare or pay any dividends on any junior securities, including our common stock, or (ii) redeem or repurchase any parity securities or junior securities, subject to limited exceptions set forth in the Certificates of Designation. There is no assurance that the Board will declare, or that we will pay, any dividends on our Preferred Stock in the future. The holders of Preferred Stock (along with any parity securities then outstanding with similar rights) are entitled to elect two additional directors in the event any dividends on Preferred Stock are in arrears for three or more semi-annual dividend periods (whether or not consecutive), and such directors may have competing and different interests to those elected by our common stockholders. The dividend rate for the Series A Preferred Stock from and including the initial issuance date of October 15, 2021 until the first reset date of October 15, 2026 will be 8.0% per annum of the $1,000 liquidation preference per share of Series A Preferred Stock. The dividend rate for the Series B Preferred Stock from and including the initial issuance date of December 10, 2021 until the first reset date of December 15, 2026 will be 7.0% per annum of the $1,000 liquidation preference per share of Series B Preferred Stock. On and after the first reset date of the Series A Preferred Stock, the dividend rate on the Series A Preferred Stock for each subsequent five-year period (each, a Reset Period) will be adjusted based upon the applicable Treasury rate, plus a spread of 6.93% per annum; provided that the applicable Treasury rate for each Reset Period will not be lower than 1.07%. On and after the first reset date of the Series B Preferred Stock, the dividend rate on the Series B Preferred Stock for each Reset Period will be adjusted based upon the applicable Treasury rate, plus a spread of 5.74% per annum; provided that the applicable Treasury rate for each Reset Period will not be lower than 1.26%. In the event that the Company does not exercise its option to redeem all the shares of Preferred Stock within 120 days after the first date on which a Change of Control Trigger Event (as defined in the Certificate of Designation) occurs, the then-applicable dividend rate for the Preferred Stock will be increased by 5.00%. Item 1B. UNRESOLVED STAFF COMMENTS None. 46 Table of Contents Item 2. PROPERTIES Luminant's asset fleet as of December 31, 2022, all of which are 100% (fee simple) owned, consists of power generation and battery ESS units in six ISOs/RTOs, with the location, ISO/RTO, technology, primary fuel type and net capacity for each generation facility shown in the table below: Facility Location ISO/RTO Technology Primary Fuel (a) Net Capacity (MW) (b) Ennis Ennis, TX ERCOT CCGT Natural Gas 366 Forney Forney, TX ERCOT CCGT Natural Gas 1,912 Hays San Marcos, TX ERCOT CCGT Natural Gas 1,047 Lamar Paris, TX ERCOT CCGT Natural Gas 1,076 Midlothian Midlothian, TX ERCOT CCGT Natural Gas 1,596 Odessa Odessa, TX ERCOT CCGT Natural Gas 1,054 Wise Poolville, TX ERCOT CCGT Natural Gas 787 Martin Lake Tatum, TX ERCOT ST Coal 2,250 Oak Grove Franklin, TX ERCOT ST Coal 1,600 DeCordova Granbury, TX ERCOT CT Natural Gas 260 Graham Graham, TX ERCOT ST Natural Gas 630 Lake Hubbard Dallas, TX ERCOT ST Natural Gas 921 Morgan Creek Colorado City, TX ERCOT CT Natural Gas 390 Permian Basin Monahans, TX ERCOT CT Natural Gas 325 Stryker Creek Rusk, TX ERCOT ST Natural Gas 685 Trinidad Trinidad, TX ERCOT ST Natural Gas 244 Comanche Peak Glen Rose, TX ERCOT Nuclear Nuclear 2,400 Brightside Live Oak County, TX ERCOT Solar Renewable 50 Emerald Grove Crane County, TX ERCOT Solar Renewable 108 Upton 2 Upton County, TX ERCOT Solar/Battery Renewable 180 DeCordova Granbury, TX ERCOT Battery Renewable 260 Total Texas Segment 18,141 Fayette Masontown, PA PJM CCGT Natural Gas 726 Hanging Rock Ironton, OH PJM CCGT Natural Gas 1,430 Hopewell Hopewell, VA PJM CCGT Natural Gas 370 Kendall Minooka, IL PJM CCGT Natural Gas 1,288 Liberty Eddystone, PA PJM CCGT Natural Gas 607 Ontelaunee Reading, PA PJM CCGT Natural Gas 600 Sayreville Sayreville, NJ PJM CCGT Natural Gas 349 Washington Beverly, OH PJM CCGT Natural Gas 711 Calumet Chicago, IL PJM CT Natural Gas 380 Dicks Creek Monroe, OH PJM CT Natural Gas 155 Miami Fort (CT) North Bend, OH PJM CT Fuel Oil 77 Pleasants Saint Marys, WV PJM CT Natural Gas 388 Richland Defiance, OH PJM CT Natural Gas 423 Stryker Stryker, OH PJM CT Fuel Oil 16 Bellingham Bellingham, MA ISO-NE CCGT Natural Gas 566 Blackstone Blackstone, MA ISO-NE CCGT Natural Gas 544 Casco Bay Veazie, ME ISO-NE CCGT Natural Gas 543 Lake Road Dayville, CT ISO-NE CCGT Natural Gas 827 Masspower Indian Orchard, MA ISO-NE CCGT Natural Gas 281 47 Table of Contents Facility Location ISO/RTO Technology Primary Fuel (a) Net Capacity (MW) (b) Milford Milford, CT ISO-NE CCGT Natural Gas 600 Independence Oswego, NY NYISO CCGT Natural Gas 1,212 Total East Segment 12,093 Moss Landing 1 & 2 Moss Landing, CA CAISO CCGT Natural Gas 1,020 Moss Landing Moss Landing, CA CAISO Battery Renewable 400 Oakland Oakland, CA CAISO CT Fuel Oil 110 Total West Segment 1,530 Coleto Creek Goliad, TX ERCOT ST Coal 650 Baldwin Baldwin, IL MISO ST Coal 1,185 Edwards (c) Bartonville, IL MISO ST Coal 585 Newton Newton, IL MISO ST Coal 615 Kincaid Kincaid, IL PJM ST Coal 1,108 Miami Fort 7 & 8 North Bend, OH PJM ST Coal 1,020 Total Sunset Segment 5,163 Total capacity 36,927 ___________ (a) Renewable represents generation assets fueled by renewable sources including energy storage and solar, which do not have significant fuel costs. (b) Approximate net generation capacity. Actual net generation capacity may vary based on a number of factors, including ambient temperature. We have not included units that have been retired or are out of operation. (c) Final day of operation was December 31, 2022. Retired on January 1, 2023. See Note 2 to the Financial Statements for discussion of our solar and battery energy storage projects currently under development and Note 3 to the Financial Statements for discussion of our retirement of certain generation facilities. Our wholesale commodity risk management group also procures renewable energy credits from renewable generation in ERCOT to support our electricity sales to wholesale and retail customers to satisfy the increasing demand for renewable resources from such customers. As of December 31, 2022, Vistra had long-term agreements to procure renewable energy credits from approximately 885 MW of renewable generation. These renewable generation sources deliver electricity when conditions make them available, and, when on-line, they generally compete with baseload units. Because they cannot be relied upon to meet demand continuously due to their dependence on weather and time of day, these generation sources are categorized as non-dispatchable and create the need for intermediate/load-following resources to respond to changes in their output. Fuel Supply Nuclear — We own and operate two nuclear generation units at the Comanche Peak plant site in ERCOT, each of which is designed for a capacity of 1,200 MW. Comanche Peak Unit 1 and Unit 2 went into commercial operation in 1990 and 1993, respectively, and are generally operated at full capacity. Refueling (nuclear fuel assembly replacement) outages for each unit are scheduled to occur every eighteen months during the spring or fall off-peak demand periods. Every three years, the refueling cycle results in the refueling of both units during the same year, which occurred in 2020. While one unit is undergoing a refueling outage, the remaining unit is intended to operate at full capacity. During a refueling outage, other maintenance, modification and testing activities are completed that cannot be accomplished when the unit is in operation. The Comanche Peak facility operated at a capacity factor of 94%, 96% and 97% in 2022, 2021 and 2020, respectively. We have contracts in place for all of our 2023 through 2025 nuclear fuel requirements. We do not anticipate any significant difficulties in acquiring uranium and contracting for associated conversion, enrichment and fabrication services in the foreseeable future. Natural Gas — Our natural gas-fueled generation fleet is comprised of 23 CCGT generating facilities totaling 19,512 MW and 11 peaking generation facilities totaling 4,801 MW. We satisfy our fuel requirements at these facilities through a combination of spot market and near-term purchase contracts. Additionally, we have near-term natural gas transportation agreements in place to ensure reliable fuel supply. 48 Table of Contents Coal/Lignite — Our coal/lignite-fueled generation fleet is comprised of eight generation facilities totaling 9,013 MW of generation capacity, including the 585 MW Edwards facility that was retired on January 1, 2023. Maintenance outages at these units are scheduled during the spring or fall off-peak demand periods. We meet our fuel requirements at our coal-fueled generation facilities in PJM and MISO with coal purchased from multiple suppliers under contracts of various lengths and transported to the facilities by either railcar or barges. We meet our fuel requirements in ERCOT using lignite that we mine at the Oak Grove generation facility and coal purchased and transported by railcar at the Coleto Creek and Martin Lake generation facilities. Item 3. LEGAL PROCEEDINGS See Note 12 to the Financial Statements for discussion of litigation, including matters related to our generation facilities and EPA reviews. Item 4. MINE SAFETY DISCLOSURES Vistra currently owns and operates, or is in the process of reclaiming, 12 surface lignite coal mines in Texas to provide fuel for its electricity generation facilities. Vistra also owns or leases, and is in the process of reclaiming, two waste-to-energy surface facilities in Pennsylvania. These mining operations are regulated by the MSHA under the Federal Mine Safety and Health Act of 1977, as amended (the Mine Act), as well as other federal and state regulatory agencies such as the RCT and Office of Surface Mining. The MSHA inspects U.S. mines, including Vistra's mines, on a regular basis, and if it believes a violation of the Mine Act or any health or safety standard or other regulation has occurred, it may issue a citation or order, generally accompanied by a proposed fine or assessment. Such citations and orders can be contested and appealed, which often results in a reduction of the severity and amount of fines and assessments and sometimes results in dismissal. Disclosure of MSHA citations, orders and proposed assessments are provided in Exhibit 95.1 to this annual report on Form 10-K. 49 Table of Contents PART II Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Vistra's authorized capital stock consists of 1,800,000,000 shares of common stock with a par value of $0.01 per share. Since May 10, 2017, Vistra's common stock has been listed on the NYSE under the symbol "VST". As of February 23, 2023, there were 381,453,001 shares of common stock issued and outstanding and 554 stockholders of record. In November 2018, we announced that the Board had adopted a common stock dividend program which we initiated in the first quarter of 2019. Our common stockholders are entitled to receive any such dividends or other distributions ratably. In February 2023, our Board declared a quarterly dividend of $0.1975 per share that will be paid in March 2023. Each dividend under the program is subject to declaration by the Board and, thus, may be subject to numerous factors in existence at the time of any such declaration including, but not limited to, prevailing market conditions, Vistra's results of operations, financial condition and liquidity, Delaware law and contractual limitations. For additional details, see Item 1A. Risk Factors and Note 13 to the Financial Statements. Stock Performance Graph The performance graph below compares Vistra's cumulative total return on common stock for the period from May 10, 2017 (the date we were listed on the NYSE) through December 31, 2022 with the cumulative total returns of the S&P 500 Stock Index (S&P 500) and the S&P Utility Index (S&P Utilities). The graph below compares the return in each period assuming that $100 was invested at May 10, 2017 in Vistra's common stock, the S&P 500 and the S&P Utilities, and that all dividends were reinvested. 50 Table of Contents Share Repurchase Program The following table provides information about our repurchase of equity securities that are registered by us pursuant to Section 12 of the Exchange Act, as amended, during the quarter ended December 31, 2022. Total Number of Shares Purchased Average Price Paid per Share Total Number of Shares Purchased as Part of a Publicly Announced Program Maximum Dollar Amount of Shares that may yet be Purchased under the Program (in millions) October 1 - October 31, 2022 6,876,619 $ 22.01 6,876,619 $ 1,197 November 1 - November 30, 2022 6,022,173 $ 23.46 6,022,173 $ 1,055 December 1 - December 31, 2022 2,112,632 $ 23.91 2,112,632 $ 1,005 For the quarter ended December 31, 2022 15,011,424 $ 22.86 15,011,424 $ 1,005 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 Share Repurchase Program by the end of 2023. Under the Share Repurchase Program, any purchases of shares of the Company's stock may be repurchased from time to time in open-market transactions at prevailing market prices, in privately negotiated transactions, pursuant to plans complying with the Exchange Act or by other means in accordance with federal securities laws. The actual timing, number and value of shares repurchased under the Share Repurchase Program or otherwise will be determined at our discretion and will depend on a number of factors, including our capital allocation priorities, the market price of our stock, general market and economic conditions, applicable legal requirements and compliance with the terms of our debt agreements and the certificate of designation of the Series A Preferred Stock and the Series B Preferred Stock, respectively. See Note 13 to the Financial Statements for more information concerning the Share Repurchase Program. Item 6. [RESERVED] Not applicable. 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. Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Market risk is the risk that in the normal course of business we may experience a loss in value because of changes in market conditions that affect economic factors such as commodity prices, interest rates and counterparty credit. Our exposure to market risk is affected by several factors, including the size, duration and composition of our energy and financial portfolio, as well as the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swaps to hedge debt costs, as well as exchange-traded, over-the-counter contracts and other contractual arrangements to hedge commodity prices. 82 Table of Contents Risk Oversight We manage the commodity price, counterparty credit and commodity-related operational risk related to the competitive energy business within limitations established by senior management and in accordance with overall risk management policies. Interest rate risk is managed centrally by our treasury function. Market risks are monitored by risk management groups that operate independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies. These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions and include, but are not limited to, position reporting and review, Value at Risk (VaR) methodologies and stress test scenarios. Key risk control activities include, but are not limited to, transaction review and approval (including credit review), operational and market risk measurement, transaction authority oversight, validation of transaction capture, market price validation and reporting, and portfolio valuation and reporting, including mark-to-market, VaR and other risk measurement metrics. Vistra has a risk management organization that enforces applicable risk limits, including the respective policies and procedures to ensure compliance with such limits, and evaluates the risks inherent in our businesses. Commodity Price Risk Our business is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. We actively manage the portfolio of generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. Similar to other participants in the market, we cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices. In managing energy price risk, we enter into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange-traded and over-the-counter financial contracts and bilateral contracts with customers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. We continuously monitor the valuation of identified risks and adjust positions based on current market conditions. We strive to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk. VaR Methodology — A VaR methodology is used to measure the amount of market risk that exists within the portfolio under a variety of market conditions. The resultant VaR produces an estimate of a portfolio's potential for loss given a specified confidence level and considers, among other things, market movements utilizing standard statistical techniques given historical and projected market prices and volatilities. Parametric processes are used to calculate VaR and are considered by management to be the most effective way to estimate changes in a portfolio's value based on assumed market conditions for liquid markets. The use of this method requires a number of key assumptions, such as use of (i) an assumed confidence level, (ii) an assumed holding period ( i.e. , the time necessary for management action, such as to liquidate positions) and (iii) historical estimates of volatility and correlation data. The table below details a VaR measure related to various portfolios of contracts. VaR for Underlying Generation Assets and Energy-Related Contracts — This measurement estimates the potential loss in value, due to changes in market conditions, of all underlying generation assets and contracts, based on a 95% confidence level and an assumed holding period of 60 days. The forward period covered by this calculation includes the current and subsequent calendar year at the time of calculation. Year Ended December 31, 2022 2021 Month-end average VaR $ 489 $ 424 Month-end high VaR $ 686 $ 684 Month-end low VaR $ 283 $ 222 The month-end high VaR risk measure in 2022 is currently consistent with the prior year. 83 Table of Contents Interest Rate Risk The following table provides information concerning our financial instruments at December 31, 2022 and 2021 that are sensitive to changes in interest rates. Debt amounts consist of the Vistra Operations Credit Facilities. See Note 10 to the Financial Statements for further discussion of these financial instruments. Expected Maturity Date 2022 Total Carrying Amount 2022 Total Fair Value 2021 Total Carrying Amount 2021 Total Fair Value 2023 2024 2025 2026 2027 There-after Long-term debt, including current maturities (a): Variable rate debt amount $ 28 $ 28 $ 2,458 $ — $ — $ — $ 2,514 $ 2,486 $ 2,543 $ 2,518 Average interest rate (b) 6.13 % 6.13 % 6.12 % — % — % — % 6.12 % 1.85 % Debt swapped to fixed (c): Notional amount $ 2,300 $ — $ — $ 2,300 $ — $ — $ 4,600 $ 4,600 Average pay rate 4.18 % 4.77 % 4.77 % 4.77 % — % — % Average receive rate 6.44 % 6.89 % 6.89 % 6.89 % — % — % ___________ (a) Unamortized premiums, discounts and debt issuance costs are excluded from the table. (b) The weighted average interest rate presented is based on the rates in effect at December 31, 2022. (c) Interest rate swaps have maturity dates through July 2026. Excludes $2.12 billion of debt swapped to variable that is matched against the terms of $2.12 billion of debt swapped to fixed that effectively fix the out-of-the-money position of such swaps (see Note 10 to the Financial Statements). As of December 31, 2022, the potential reduction of annual pretax earnings over the next twelve months due to a one percentage-point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $2 million taking into account the interest rate swaps discussed in Note 10 to Financial Statements. Credit Risk Credit risk relates to the risk of loss associated with nonperformance by counterparties. We minimize credit risk by evaluating potential counterparties, monitoring ongoing counterparty risk and assessing overall portfolio risk. This includes review of counterparty financial condition, current and potential credit exposures, credit rating and other quantitative and qualitative credit criteria. We also employ certain risk mitigation practices, including utilization of standardized master agreements that provide for netting and setoff rights, as well as credit enhancements such as margin deposits and customer deposits, letters of credit, parental guarantees and surety bonds. See Note 15 to the Financial Statements for further discussion of this exposure. Credit Exposure — Our gross credit exposure (excluding collateral impacts) associated with retail and wholesale trade accounts receivable and net derivative assets arising from commodity contracts and hedging and trading activities totaled $2.237 billion at December 31, 2022. As of December 31, 2022, Retail segment credit exposure totaled approximately $1.233 billion, including $1.211 billion of trade accounts receivable and $22 million related to derivatives. Cash deposits and letters of credit held as collateral for these receivables totaled $65 million, resulting in a net exposure of $1.168 billion. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition of large business customers. As of December 31, 2022, aggregate Texas, East, Sunset and Asset Closure segments credit exposure totaled $1.004 billion including $541 million related to derivative assets and $463 million of trade accounts receivable, after taking into account master netting agreement provisions but excluding collateral impacts. 84 Table of Contents Including collateral posted to us by counterparties, our net Texas, East, Sunset and Asset Closure segments exposure was $936 million, as seen in the following table that presents the distribution of credit exposure by counterparty credit quality at December 31, 2022. Credit collateral includes cash and letters of credit but excludes other credit enhancements such as guarantees or liens on assets. Exposure Before Credit Collateral Credit Collateral Net Exposure Investment grade $ 689 $ 20 $ 669 Below investment grade or no rating 315 48 267 Totals $ 1,004 $ 68 $ 936 Significant ( i.e. , 10% or greater) concentration of credit exposure exists with one counterparty, which represented an aggregate $136 million, or 15%, of our total net exposure. We view exposure to this counterparty to be within an acceptable level of risk tolerance due to the counterparty's credit ratings, the counterparty's market role and deemed creditworthiness and the importance of our business relationship with the counterparty. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts such as margin deposits are owed to the counterparties or delays in receipts of expected settlements owed to us. Contracts classified as "normal" purchase or sale and non-derivative contractual commitments are not marked-to-market in the financial statements and are excluded from the detail above. Such contractual commitments may contain pricing that is favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform. 85 Table of Contents FORWARD-LOOKING STATEMENTS This report and other presentations made by us contain "forward-looking statements." All statements, other than statements of historical facts, that are included in this report, or made in presentations, in response to questions or otherwise, that address activities, events or developments that may occur in the future, including (without limitation) such matters as activities related to our financial or operational projections, capital allocation, capital expenditures, liquidity, dividend policy, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of power generation assets, market and industry developments and the growth of our businesses and operations (often, but not always, through the use of words or phrases such as "intends," "plans," "will likely," "unlikely," "expected," "anticipated," "estimated," "should," "may," "projection," "target," "goal," "objective" and "outlook"), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves uncertainties and risks and is qualified in its entirety by reference to the discussion under Item 1A. Risk Factors and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in this annual report on Form 10-K and the following important factors, among others, that could cause our actual results to differ materially from those projected in or implied by such forward-looking statements: • the actions and decisions of judicial and regulatory authorities; • prohibitions and other restrictions on our operations due to the terms of our agreements; • prevailing federal, state and local governmental policies and regulatory actions, including those of the legislatures and other government actions of states in which we operate, the U.S. Congress, the FERC, the NERC, the TRE, the public utility commissions of states and locales in which we operate, CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM, the RCT, the NRC, the EPA, the environmental regulatory bodies of states in which we operate, the MSHA and the CFTC, with respect to, among other things: ▪ allowed prices; ▪ industry, market and rate structure; ▪ purchased power and recovery of investments; ▪ operations of nuclear generation facilities; ▪ operations of fossil-fueled generation facilities; ▪ operations of mines; ▪ acquisition and disposal of assets and facilities; ▪ development, construction and operation of facilities; ▪ decommissioning costs; ▪ present or prospective wholesale and retail competition; ▪ changes in federal, state and local tax laws, rates and policies, including additional regulation, interpretations, amendments, or technical corrections to the TCJA and/or the IRA; ▪ changes in and compliance with environmental and safety laws and policies, including the CCR Rule, National Ambient Air Quality Standards, the Cross-State Air Pollution Rule, the Mercury and Air Toxics Standard, regional haze program implementation and GHG and other climate change initiatives; and ▪ clearing over-the-counter derivatives through exchanges and posting of cash collateral therewith; • expectations regarding, or impacts of, environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts, and other laws and regulations that we are, or could become, subject to, which could increase our costs, result in an impairment of our assets, cause us to limit or terminate the operation of certain of our facilities, or otherwise negatively impact our financial results or stock price; • legal and administrative proceedings and settlements; • general industry trends; • economic conditions, including the impact of any inflationary period, recession or economic downturn; • investor sentiment relating to climate change and utilization of fossil fuels in connection with power generation could reduce demand for, or increase potential volatility in the market price of, our common stock; • the severity, magnitude and duration of pandemics, including the COVID-19 pandemic, and the resulting effects on our results of operations, financial condition and cash flows; • the severity, magnitude and duration of extreme weather events, drought and limitations on access to water, and other weather conditions and natural phenomena, contingencies and uncertainties relating thereto, most of which are difficult to predict and many of which are beyond our control, and the resulting effects on our results of operations, financial condition and cash flows; • acts of sabotage, geopolitical conflicts, wars, or terrorist, cybersecurity, cybercriminal, or cyber-espionage threats or activities; 86 Table of Contents • risk of contract performance claims by us or our counterparties, and risks of, or costs associated with, pursuing or defending such claims; • our ability to collect trade receivables from counterparties in the amount or at the time expected, if at all; • our ability to attract, retain and profitably serve customers; • restrictions on or prohibitions of competitive retail pricing or direct-selling businesses; • adverse publicity associated with our retail products or direct selling businesses, including our ability to address the marketplace and regulators regarding our compliance with applicable laws; • changes in wholesale electricity prices or energy commodity prices, including the price of natural gas; • changes in prices of transportation of natural gas, coal, fuel oil and other refined products; • sufficiency of, access to, and costs associated with coal, fuel oil, natural gas, and uranium inventories and transportation and storage thereof; • changes in the ability of counterparties and suppliers to provide or deliver commodities, materials, or services as needed; • beliefs and assumptions about the benefits of state- or federal-based subsidies to our market competition, and the corresponding impacts on us, including if such subsidies are disproportionately available to our competitors; • the effects of, or changes to, market design and the power, ancillary services and capacity procurement processes in the markets in which we operate; • changes in market heat rates in the CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM electricity markets; • our ability to effectively hedge against unfavorable commodity prices, including the price of natural gas, market heat rates and interest rates; • population growth or decline, or changes in market supply or demand and demographic patterns; • our ability to mitigate forced outage risk, including managing risk associated with Capacity Performance in PJM and performance incentives in ISO-NE; • efforts to identify opportunities to reduce congestion and improve busbar power prices; • access to adequate transmission facilities to meet changing demands; • changes in interest rates, commodity prices, rates of inflation or foreign exchange rates; • changes in operating expenses, liquidity needs and capital expenditures; • commercial bank market and capital market conditions and the potential impact of disruptions in U.S. and international credit markets; • access to capital, the attractiveness of the cost and other terms of such capital and the success of financing and refinancing efforts, including availability of funds in capital markets; • our ability to maintain prudent financial leverage and achieve our capital allocation, performance, and cost-saving initiatives and objectives; • our ability to generate sufficient cash flow to make principal and interest payments in respect of, or refinance, our debt obligations; • our expectation that we will continue to pay (i) a consistent aggregate cash dividend amount to common stockholders on a quarterly basis and (ii) the applicable semiannual cash dividend to the Series A Preferred Stock and Series B Preferred Stock stockholders, respectively; • our expectation that we will continue to make repurchases under, and the possibility that we may fail to realize the anticipated benefits of, our share repurchase program, and the possibility that the program may be suspended, discontinued or not completed prior to its termination; • our ability to implement and successfully execute upon our strategic and growth initiatives, including the completion and integration of mergers, acquisitions and/or joint venture activity, the identification and completion of sales and divestitures activity, and the completion and commercialization of our other business development and construction projects; • competition for new energy development and other business opportunities; • inability of various counterparties to meet their obligations with respect to our financial instruments; • counterparties' collateral demands and other factors affecting our liquidity position and financial condition; • changes in technology (including large-scale electricity storage) used by and services offered by us; • changes in electricity transmission that allow additional power generation to compete with our generation assets; • our ability to attract and retain qualified employees; • significant changes in our relationship with our employees, including the availability of qualified personnel, and the potential adverse effects if labor disputes or grievances were to occur or changes in laws or regulations relating to independent contractor status; • changes in assumptions used to estimate costs of providing employee benefits, including medical and dental benefits, pension and OPEB, and future funding requirements related thereto, including joint and several liability exposure under ERISA; • hazards customary to the industry and the possibility that we may not have adequate insurance to cover losses resulting from such hazards; 87 Table of Contents • the impact of our obligations under the TRA; • our ability to optimize our assets through targeted investment in cost-effective technology enhancements and operations performance initiatives; • our ability to effectively and efficiently plan, prepare for and execute expected asset retirements and reclamation obligations and the impacts thereof; • our ability to successfully complete the integration of businesses acquired by Vistra and our ability to successfully capture the full amount of projected operational and financial synergies relating to such transactions; and • actions by credit rating agencies. Any forward-looking statement speaks only at the date on which it is made, and except as may be required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events or circumstances. New factors emerge from time to time, and it is not possible for us to predict them. In addition, we may be unable to assess the impact of any such event or condition or the extent to which any such event or condition, or combination of events or conditions, may cause results to differ materially from those contained in or implied by any forward-looking statement. As such, you should not unduly rely on such forward-looking statements. INDUSTRY AND MARKET INFORMATION Certain industry and market data and other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including certain data published by CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM, the environmental regulatory bodies of states in which we operate and NYMEX. We did not commission any of these publications, reports or other sources. Some data is also based on good faith estimates, which are derived from our review of internal surveys, as well as the independent sources listed above. Industry publications, reports and other sources generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of these studies, publications, reports and other sources is reliable, we have not independently investigated or verified the information contained or referred to therein and make no representation as to the accuracy or completeness of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we do not know what assumptions were used in preparing such forecasts. Statements regarding industry and market data and other statistical information used throughout this report involve risks and uncertainties and are subject to change based on various factors. 88 Table of Contents Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the stockholders and the Board of Directors of Vistra Corp. Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Vistra Corp. and its subsidiaries (the “Company”) as of December 31, 2022 and 2021, the related consolidated statements of operations, consolidated statements of comprehensive income (loss), consolidated statements of cash flows, and consolidated statement of changes in equity, for each of the three years in the period ended December 31, 2022, and the related notes and the schedule listed in the Index at Item 15(b) (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2023, expressed an unqualified opinion on the Company’s internal control over financial reporting. Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. Tax Receivable Agreement Obl