Vistra Corp. 10-K

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