Vistra Annual Report 2021

Plain-text annual report

2021 A N N U A L R E P O R T Powering a Better Way Forward: Chicago For decades, one of Vistra’s premier retail brands, Dynegy, has served millions of customers across the Midwest and Northeast, and we’re excited to power some of Chicago’s most beloved and iconic sites, including Wrigley Field and Willis Tower. Wrigley Field Dynegy is the Official and Exclusive Energy Provider for the Chicago Cubs and Wrigley Field. Dynegy is committed to delivering best-in-class service and powering the gameday experience for fans visiting Chicago’s beloved Wrigley Field. Dynegy understands the unique operational needs of professional sports facilities and is committed to creating tailored solutions that work for each of its customers. Willis Tower Sustainability is a shared top priority for Dynegy and Chicago’s iconic Willis Tower. As the retail electric supplier for the 110-story tower, Dynegy provides 100% renewable electricity, supporting the building’s sustainability goals. Dynegy is proud to power the historic Willis Tower and serve the millions of people who work and visit it each year. Vistra has established itself as a leader in ESG and the clean energy transition with our Vistra Zero carbon-free generation portfolio and our many green retail products and solutions we offer to customers. Curt Morgan Chief Executive Officer By year-end, we had delivered squarely on each of these four strategic imperatives, and I’ll touch on each in the following pages to highlight our performance in 2021 and the prospects for the future of our company. Accelerating our Zero-Carbon Growth Pipeline with Cost-Effective Capital Vistra has established itself as a leader in ESG and the clean energy transition with our Vistra Zero carbon-free generation portfolio and our many green retail products and solutions we offer to customers. We continue to focus on opportunities to grow our business responsibly through economically attractive investments that contribute to our decarbonization goals, including achieving net zero by 2050, while also delivering commen- surate returns and value for all stakeholders. In 2021, we reinforced our commitment to growing our renewable and battery storage portfolio to support the broader decarbonization of the U.S. economy, maintain the reliability and affordability of electricity, and enhance the long-term sustainability of Vistra. In December, we published our Green Finance Framework, which enables us to issue green ﬁnancial instruments to fund new or existing renewable and energy efficiency projects. We then successfully launched an attractively priced and upsized $1 billion of Green Perpetual Preferred Dear Fellow Vistra Stockholders, t d f d di There is no doubt that 2021 was a challenging year; however, in many ways, 2021 was also a pivotal one. We began the year facing the hardships presented by Winter Storm Uri (Uri), but with our team of dedicated employees, we came together l t to not only confront and mitigate the impact but also grow from the experience. Back in 2016, when Vistra emerged from bankruptcy we embarked on a strategy emphasizing a strong balance sheet as one of the cornerstones of the company. That strategic priority enabled us to withstand Uri and get back on track in a relatively short period of time. th t After understanding the full impact of Uri, we began a comprehensive process in the second quarter of 2021 to review our strategic direction and approach to capital allocation. As a result of this process, we identiﬁed and prioritized four key strategic imperatives: 1. Accelerating our zero-carbon growth pipeline with cost-effective capital 2. Returning signiﬁcant capital to stockholders from our core business 3. Maintaining a strong balance sheet 4. Driving long-term, sustainable value through Vistra’s integrated business model VISTRA 2021 ANNUAL REPORT 1 Stock—the ﬁrst green preferred stock offering from a U.S. corporate issuer—to fund existing and new eligible green projects, including our renewable and battery storage development projects. Ultimately, this capital infusion will fund a portion of the development pipeline of several zero-carbon projects in our Vistra Zero portfolio in a cost- effective manner. In connection with the Green Perpetual Preferred Stock offering, we announced our intention to grow Vistra Zero to at least 7,300 megawatts by 2026, with ~2,900 MW currently online (including our 2,300 MW low-cost nuclear facility, Comanche Peak). The $5 billion investment in Vistra Zero through 2026 is projected to contribute $450–$500 million of Adjusted EBITDA1 annually by year-end 2026 (in addition to Adjusted EBITDA1 generated by Comanche Peak). We intend to fund these development projects primarily through project ﬁnancing, supplemented by Vistra Zero project cash ﬂows and the net proceeds of the Green Perpetual Preferred Stock offering. Vistra’s green and sustainable growth strategy through Vistra Zero is bolstered by our ability to use our existing sites, including repurposing retired or to-be-retired sites, which have existing access to transmission infrastructure. Key development announcements and progress of our Vistra Zero projects in 2021 include: In California: • Moss Landing Energy Storage Facility continues to expand—Phases I (300 MW) and II (100 MW) both achieved commercial operations in 2021, and in February 2022, we announced further expansion through Phase III (350 MW), bringing the site’s total energy storage capacity to 750 MW/3,000 MWh. We have the potential to eventually reach 1,500 MW, supporting the state of California’s electricity needs. We experienced certain operational delays as the water-based heat suppression systems improperly leaked water on a small percentage of the battery modules, temporarily taking Phases I and II offline. However, we have identiﬁed the issues, are taking corrective actions, and expect to be storing and releasing energy to support California’s grid during the all-important 2022 summer season. VISTRA 2021 ANNUAL REPORT 2 In Illinois: • A three-year effort culminated in the passage of an omnibus energy package that included our Illinois Coal to Solar & Energy Storage Initiative. As enacted, the legislation supports Vistra’s future construction and operation of up to 300 MW of utility-scale solar and 150 MW of battery energy storage facilities at nine retired or to-be-retired coal plant sites across central and southern Illinois. The initiative will also include diverse suppliers while bringing a much-needed property tax base to local communities. In Texas: • Our Electric Reliability Council of Texas (ERCOT) 1,000 MW Phase I projects, announced in September 2020, took shape with three projects scheduled to achieve commercial operations prior to summer 2022: 50 MW Brightside Solar Facility 108 MW Emerald Grove Solar Facility 260 MW DeCordova Energy Storage Facility • We also grew the Vistra Zero portfolio in Texas by acquiring the to-be-constructed 110 MW Angus Solar Facility, expected online in 2023. We believe Vistra is exactly the kind of company that should be embraced as a leader in the energy transition—our track record includes responsibly and justly retiring carbon-emitting resources, reclaiming sites, and investing in new green technology and resources. Since 2010, Vistra has retired more than 12,000 MW of coal and gas power plants, resulting in a 45% reduction of greenhouse gas (GHG) emissions through year-end 2020, compared to a 2010 baseline. Additionally, we have announced the expected retirement of nearly 8,000 MW of additional fossil-fueled power plants by 2027, for a total of ~20,000 MW since 2010, with plans to repurpose feasible sites to solar and energy storage developments. We are conﬁdent that our diversiﬁed asset mix will support the reliability of the electric system while providing customers with affordable energy that meets their sustainable preferences throughout the clean energy transition. Vistra Zero carbon-free generation portfolio includes solar (Upton 2 Solar Facility, left), nuclear (Comanche Peak Power Plant, right), and battery storage (DeCordova Energy Storage Facility, below). We believe Vistra is exactly the kind of company that should be embraced as a leader in the energy transition. Returning Signiﬁcant Capital to Stockholders Our long-term capital allocation plan reﬂects an anticipated return of capital of at least $7.5 billion to our common stockholders through year-end 2026. In October 2021, our board of directors approved a $2 billion share repurchase program, which we are on track to fully execute by year-end 2022. The share repurchase program is partially funded by the $1 billion of 8% preferred equity we issued in October 2021, and as announced on our fourth quarter 2021 earnings call, Vistra had repurchased ~$764 million of the $2 billion as of Feb. 22, 2022, resulting in a 7% reduction in shares outstanding since our previously reported share count as of Nov. 2, 2021. Once we conclude this initial $2 billion share repurchase plan, we then expect to allocate at least an average of $1 billion per year toward share repurchases from 2023 through 2026 for a total of at least $6 billion in ﬁve years. Vistra’s core business is expected to generate on average $3+ billion per year of Adjusted EBITDA1 and we expect to convert 60–70%+ of Adjusted EBITDA1 to free cash ﬂow, affording the signiﬁcant cash ﬂow to return to shareholders, especially since the Vistra Zero growth will be funded by internally generated Vistra Zero cash ﬂow and third-party capital. Hence, our philosophy is simple and straight forward—for as long as we believe our stock is undervalued, we will dedicate signiﬁcant cash ﬂow from our core business to repurchase our shares. p Our capital allocation plan also reinforced our O commitment to pay a meaningful and growing c dividend. In October 2021, we announced our d i ntent to allocate $300 million per year toward our common dividend. We anticipate this dividend o policy will offer greater dividend yield growth for p stockholders rather than identifying a target annual s g growth rate as we retire shares through our ongoing repurchases. This $300 million dividend pool will be spread over fewer shares, providing growth in dividend yield on the remaining shares. Our ﬁrst quarter 2022 dividend of $0.17 per share of Vistra’s common stock, represents a ~13% increase in the company’s quarterly common stock dividend per share from its ﬁrst quarter 2021 dividend. Maintaining a Strong Balance Sheet Vistra has always focused on a strong balance sheet, and it will remain a priority. A strong balance sheet provided the support we needed to withstand the hardships brought by Uri. Immediately following Uri, we executed ﬁnancing transactions to support our liquidity needs, increasing our net debt by just over $2 billion. However, just a few months later, we announced as part of our capital allocation plan that we expect to further reduce corporate-level debt by ~$1.5 billion by year-end 2022 with plans to retire up to ~$3 billion of corporate-level debt in ﬁve years. By year-end 2021, we had already decreased corporate-level debt by ~$625 million and we believe we will approach pre-Uri debt levels by year-end 2022. We project that we will be able to maintain leverage in our current range of 3–3.5 times net debt to Adjusted EBITDA1 in the near- term and reach the mid- to high-2s over the next ﬁve years, exclusive of the leverage to support the Vistra Zero growth. Driving Long-Term, Sustainable Value Through Vistra’s Integrated Business Model Vistra’s integrated model—a best-in-class generation ﬂeet and premier retail business that we have grown and expanded over the past ﬁve years—provides the foundation and cash ﬂow that support the three strategic priorities detailed above. We have always believed in the value of our integrated operations, and we remain conﬁdent that the pairing of our low-cost, efficient, and diversiﬁed generation ﬂeet—including our growing zero-carbon business—with our customer-centric retail platform and best-in-class commercial capabilities is the optimal way to maintain resiliency and create value for our stockholders. In fact, the uniquely low maintenance capital and operations and maintenance expense required to produce the $3 billion+ of Adjusted EBITDA1 affords us a signiﬁcant amount of free cash ﬂow to support a diverse capital allocation plan with an emphasis on returning capital to ﬁnancial stakeholders. Financial Execution We entered 2021 on the heels of an outstanding 2020 where we achieved results above the high end of our raised guidance range and marked the ﬁfth year in a row that our ﬁnancial results exceeded the midpoint of our Adjusted EBITDA from Ongoing Operations1 guidance range. Uri led to a conﬂuence of unpredictable events, exposing issues with the integrated natural gas and electric systems in the Texas ERCOT market, including impaired gas deliverability, challenging the ﬁnancial strength we had worked hard to put in place. We faced the challenge and stabilized the company, and then immediately got back to work signiﬁcantly offsetting the Uri ﬁnancial impact and getting the company back on the path of exceptional perfor- mance and creating long-term shareholder value. To mitigate the ﬁnancial impact of Uri, we identiﬁed various self-help initiatives, including the monetization of certain commercial positions, optimizing spend on our generation O&M project work, retail cost savings and margin performance, and support group cost savings, culminating in value creation that exceeded our $500 million target. In addition, we have also been very active in VISTRA 2021 ANNUAL REPORT 4 the Texas 2021 legislative and ongoing regulatory deliberations regarding Uri, which, among other accomplishments, resulted in Vistra being allocated ~$544 million in ERCOT securitization payments. The self-help and securitization efforts resulted in an improvement following Uri of over $1 billion. These efforts also helped de-risk the integrated Texas natural gas and power systems reducing the potential volatility in the Texas ERCOT market and Vistra’s ﬁnancial and operating performance. In the end, we reported 2021 Adjusted EBITDA from Ongoing Operations1 of $1,941 million, including the impacts from Uri-related retail bill credit settle- ments resulting in high returns to Vistra. Excluding the $53 million related to these settlements, 2021 Adjusted EBITDA from Ongoing Operations1 was $1,994 million, slightly favorable to the November revised and tightened midpoint of guidance. Under very difficult circumstances following Uri, we executed and accomplished exactly what we set out to do: stabilize the company and recover as much lost value as possible in order to put our company back on track to maximize our ﬁnancial results for our stockholders. Generation During the week of Uri, our Texas generation ﬂeet, which makes up 18% of the capacity available in ERCOT, provided between 25–30% of the power on the grid, far exceeding our market share. Unfortunately, the ﬁnancial results did not match this performance due to the failures of the natural gas system and the uneven allocation of customer curtailments in ERCOT. Our employees went to extraordinary efforts, working around-the-clock in sub-freezing temperatures to keep our assets running and to maintain and restore power for the people of Texas. This was achieved while also effectively managing COVID-19 at all plant sites and constantly tracking and adjusting to CDC and OSHA recommendations. Vistra ﬁnished the year with commercial availability, a measure of the ﬂeet’s ability to meet demand during the highest margin hours, of ~92%—very strong performance for a ﬂeet with the characteristics of ours. In 2021, Vistra continued our operations performance improvement (OPI) initiative, realizing Vistra’s ﬂagship retail brand, TXU Energy, launched a product speciﬁcally for electric vehicle owners, giving customers 50% off energy charges every weeknight and all weekend long—times when customers most often charge their vehicles. $500 million of savings—a $275 million increase from the 2018 projection established with the Dynegy merger. OPI is now a part of our DNA with continuous idea generation and conversion of ideas to executable opportunities on a regular basis. Focused on learnings from Uri, we enhanced and further de-risked our ﬂeet by investing more than $50 million in 2021, with execution beginning on another $30 million in 2022. These expenditures include the addition of onsite backup fuel at six plants with enough fuel for several days, additional offsite gas storage, and several actions to guard against severe weather impacts on critical equipment. Our people are our most important asset, and their safety is our highest priority. Vistra’s plants operated safely throughout the year—a testament to our “Best Defense” mindset which puts safety above all else. Through the team’s efforts, Vistra ended the year without any serious injuries or fatalities to our Vistra employees or business partners working at our sites. Our focus on safety is further highlighted with 12 power plant sites achieving VPP Star status from OSHA, demonstrating superior efficacy of their safety and health management systems, and maintaining injury and illness rates below industry average. In 2021, we introduced the VPP process to ﬁve new facilities, and four of our power plants submitted VPP applications that are awaiting OSHA review. Retail Vistra’s retail business rose to the challenge as well while maintaining our customer-centric approach despite the challenges of COVID-19 and Uri. During Uri, we assured customers they would be insulated from storm-related rate increases, donated $5 million to support our communities in need, and provided bill-pay assistance. By year end, Vistra’s retail business grew ERCOT residential counts by ~23,000 customers, the highest organic growth we’ve seen since 2008. Most of this growth was within our ﬂagship retail brand TXU Energy, demonstrating the strength of our brand promise and continued importance to our customers. This was also a standout year for our two largest retail brands, with the launch of several ﬁrst-to- market customer-centric products and others VISTRA 2021 ANNUAL REPORT 5 Our people are our most important asset and their safety is our highest priority. Vistra’s plants operated safely throughout the year—a testament to our “Best Defense” mindset which puts safety above all else. designed for increased use of electricity to fuel vehicles. • Ambit’s Winter Break plan gives customers in the Midwest and Northeast savings when they need it most by offering 50% off all winter long. • Ambit Energy Bank gives Texas customers year- round control and predictability. • TXU Energy continued to broaden its most imitated product portfolio with the launch of TXU Energy Freedom Rewards. This ﬁrst-of-its-kind plan allows customers to earn 30% in free electricity for every dollar they spend on energy charges, automatically, all year long. • TXU Energy EV Pass is designed speciﬁcally for electric vehicle owners. Innovation remains a pillar of our retail business. As electric vehicle adoption takes off, we’ll continue to develop products and partnerships to attract this important segment of customers. Additionally, we saw an increase in customers buying more than just electricity from us in 2021, growing our business of value-added products such as HVAC maintenance, home warranties, and surge protection plans. Vistra’s approach to value-added services has been to partner with companies providing these services, earning a percentage of margin, rather than owning and competing in these businesses which have their own challenges and require their own sets of capabilities. This approach also allows us to be nimble and make changes while improving our offerings if the situation dictates. We believe this is the most cost-effective manner to broaden our product offering and protect our balance sheet and brands. From the world’s largest battery energy storage facility to miles and miles of solar panels, Vistra Zero is bringing a zero-carbon future to life. SOLAR ENERGY STORAGE SOLAR + ENERGY STORAGE DeCordova Energy Storage Facility 260 MW Hood County, TX Edwards Energy Storage Facility 37 MW Peoria County, IL Havana Energy Storage Facility 37 MW Mason County, IL Joppa Energy Storage Facility 37 MW Massac County, IL Moss Landing Energy Storage Facility 750 MW/3,000MWh Moss Landing, CA Oakland Energy Storage Facility 43.25 MW Oakland, CA Andrews Solar Facility 100 MW Andrews County, TX Angus Solar Facility 110 MW Bosque County, TX Brightside Solar Facility 50 MW Live Oak County, TX Emerald Grove Solar Facility 108 MW Crane County, TX Forest Grove Solar Facility 200 MW Henderson County, TX Oak Hill Solar Facility 200 MW Rusk County, TX NUCLEAR Comanche Peak Nuclear Power Plant 2,300 MW Somervell County, TX VISTRA 2021 ANNUAL REPORT 6 Baldwin Solar & Energy Storage Facility 68 MW solar; 9 MW battery Randolph County, IL Coffeen Solar & Energy Storage Facility 44 MW solar; 6 MW battery Montgomery County, IL Duck Creek Solar & Energy Storage Facility 20 MW solar; 3 MW battery Fulton County, IL Hennepin Solar & Energy Storage Facility 50 MW solar; 6 MW battery Putnam County, IL Kincaid Solar & Energy Storage Facility 60 MW solar; MW battery Christian County, IL Newton Solar & Energy Storage Facility 52 MW solar; 7 MW battery Jasper County, IL Upton 2 Solar & Energy Storage Facility 180 MW solar; 10 MW/42 MWh battery Upton County, TX List includes publicly announced projects under development ESG Accomplishments Conclusion Before I close, while our business portfolio transformation is a key element of our sustainability strategy, I would be remiss if I did not highlight other ESG accomplishments we achieved this year: • Named one of America’s Most JUST Companies, by JUST Capital and its media partner CNBC, for a commitment to serving workers, customers, communities, the environment, and stockholders. • Honored with 2021 Texan by Nature 20 designation by the conservation non-proﬁt Texan by Nature for a demonstrative commitment to conservation and sustainability. • Received the 2021 Excellence in Surface Coal Mining Reclamation Award from the Office of Surface Mining Reclamation & Enforcement, a bureau of the U.S. Department of the Interior, for work done to reclaim and restore previously mined land at Monticello-Winﬁeld Mine. The award recognizes companies that achieve the most exemplary coal mine reclamation in the nation. • Joined Disability:IN, the leading non-proﬁt resource for business disability inclusion world- wide, reinforcing commitment to equality and inclusion at Vistra. • Continued year two of a ﬁve-year, $10 million commitment to support organizations that grow minority-owned small businesses, enhance economic development, and provide educational opportunities for students from diverse backgrounds. • Advanced diversity, equity, and inclusion (DEI) in the workplace through strengthening internal hiring and recruiting practices through numerous initiatives including training for hiring managers and partnerships with minority-serving institutions. • Incorporated an ESG Index, with a 10% weighting, into Vistra’s compensation scorecard, ensuring accountability all the way to the top of the company. We continue to believe that the most effective and sustainable companies have a well-balanced focus on a variety of stakeholders including you—our investors—and our customers, communities, people, and suppliers. We are supplying a vital product to society, and we must balance that crucial role with our environmental footprint. In 2021, we advanced our company in many important ways, especially in the areas represented by ESG. Although we endured an unprecedented weather event that resulted in a signiﬁcant ﬁnancial impact and a temporary loss of value, we ﬁnished the year strong, fully recovering the loss in value of our stock from Uri by year end. Ultimately, I am most proud of how this company responded to the impacts from Uri, most of which were uncontrollable, and continued to live our core principles of doing business the right way, competing as a team to win, and caring for all of our stakeholders. We never wavered and we did not give up, and we are now back on track with our stock price continuing to respond favorably to our new and improved capital allocation plan. We cannot change what happened during Uri, but we can and did learn from it, de-risking and strengthening our company for the future. We completed 2021 with a clear strategic direction as a leader in the clean energy transition coupled with a capital allocation plan that we believe will provide exceptional value to our stockholders for years to come. We begin 2022 from a position of strength for which we can all be proud. It was with this strength in mind that on March 21, 2022, I announced that I will be transitioning the role of CEO to my colleague, Jim Burke. Leading Vistra has been the most rewarding experience of my 40-year career. I remain excited about the long-term opportunity ahead as Vistra returns signiﬁcant capital to investors while transitioning our ﬂeet to lower carbon resources. Jim is a proven leader who possesses deep experience in our company and industry and understands the company’s commitment to all our stakeholders. I’m excited to watch him lead Vistra to continued success. Thank you for your interest in Vistra—as always, we look forward to its future! Curt Morgan Chief Executive Officer 1 Adjusted EBITDA is a non-GAAP ﬁnancial measure. Please refer to the “Non-GAAP Reconciliation” table on page 8 of this Annual Report. VISTRA 2021 ANNUAL REPORT 7 Non-GAAP Financial Measures and Forward-Looking Statements This letter includes references to Adjusted EBITDA which is a non-GAAP ﬁnancial measure. For reconciliations between our non-GAAP measures and the nearest GAAP measures, please refer to the table below. As non-GAAP ﬁnancial measures are not intended to be considered in isolation or as a substitute for GAAP ﬁnancial measures, you should carefully read the Form 10-K included in this Annual Report, which includes our consolidated ﬁnancial statements prepared in accordance with GAAP. Additionally, this letter includes state- ments that, to the extent they are not recitations of historical fact, constitute forward-looking statements within the meaning of the federal securities laws, and are based on Vistra’s current expectations and assumptions. For a discussion identifying important factors that could cause actual results to vary materially from those anticipated in the forward-looking statements, see Vistra’s ﬁlings with the SEC including, but not limited to, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Risk Factors” in the Form 10-K portion of this Annual Report. Non-GAAP Reconciliation — 2021 Adjusted EBITDA Year Ended December 31, 2021 (Unaudited) (Millions of Dollars) Retail Texas East West Sunset Eliminations/ Corp and Other Ongoing Operations Consolidated Asset Closure Vistra Consolidated Net income (loss) 2,196 (2,512) (567) (cid:43)(cid:80)(cid:69)(cid:81)(cid:79)(cid:71)(cid:2)(cid:86)(cid:67)(cid:90)(cid:2)(cid:71)(cid:90)(cid:82)(cid:71)(cid:80)(cid:85)(cid:71)(cid:2)(cid:10)(cid:68)(cid:71)(cid:80)(cid:71)(cid:386)(cid:86)(cid:11) (cid:43)(cid:80)(cid:86)(cid:71)(cid:84)(cid:71)(cid:85)(cid:86)(cid:2)(cid:71)(cid:90)(cid:82)(cid:71)(cid:80)(cid:85)(cid:71)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:84)(cid:71)(cid:78)(cid:67)(cid:86)(cid:71)(cid:70)(cid:2)(cid:69)(cid:74)(cid:67)(cid:84)(cid:73)(cid:71)(cid:85)(cid:2)(cid:10)(cid:67)(cid:11) (cid:38)(cid:71)(cid:82)(cid:84)(cid:71)(cid:69)(cid:75)(cid:67)(cid:86)(cid:75)(cid:81)(cid:80)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:67)(cid:79)(cid:81)(cid:84)(cid:86)(cid:75)(cid:92)(cid:67)(cid:86)(cid:75)(cid:81)(cid:80)(cid:2)(cid:10)(cid:68)(cid:11) 2 9 212 — (cid:10)(cid:19)(cid:22)(cid:11) 686 EBITDA before Adjustments 2,419 (1,840) (cid:55)(cid:80)(cid:84)(cid:71)(cid:67)(cid:78)(cid:75)(cid:92)(cid:71)(cid:70)(cid:2)(cid:80)(cid:71)(cid:86)(cid:2)(cid:10)(cid:73)(cid:67)(cid:75)(cid:80)(cid:11)(cid:17)(cid:78)(cid:81)(cid:85)(cid:85)(cid:2)(cid:84)(cid:71)(cid:85)(cid:87)(cid:78)(cid:86)(cid:75)(cid:80)(cid:73)(cid:2)(cid:72)(cid:84)(cid:81)(cid:79)(cid:2) hedging transactions (cid:10)(cid:19)(cid:14)(cid:22)(cid:18)(cid:21)(cid:11) 1,139 Generation plant retirement expenses (cid:40)(cid:84)(cid:71)(cid:85)(cid:74)(cid:2)(cid:85)(cid:86)(cid:67)(cid:84)(cid:86)(cid:2)(cid:17)(cid:2)(cid:82)(cid:87)(cid:84)(cid:69)(cid:74)(cid:67)(cid:85)(cid:71)(cid:2)(cid:67)(cid:69)(cid:69)(cid:81)(cid:87)(cid:80)(cid:86)(cid:75)(cid:80)(cid:73) impacts (cid:43)(cid:79)(cid:82)(cid:67)(cid:69)(cid:86)(cid:85)(cid:2)(cid:81)(cid:72)(cid:2)(cid:54)(cid:67)(cid:90)(cid:2)(cid:52)(cid:71)(cid:69)(cid:71)(cid:75)(cid:88)(cid:67)(cid:68)(cid:78)(cid:71)(cid:2)(cid:35)(cid:73)(cid:84)(cid:71)(cid:71)(cid:79)(cid:71)(cid:80)(cid:86) Non-cash compensation expenses (cid:54)(cid:84)(cid:67)(cid:80)(cid:85)(cid:75)(cid:86)(cid:75)(cid:81)(cid:80)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:79)(cid:71)(cid:84)(cid:73)(cid:71)(cid:84)(cid:2)(cid:71)(cid:90)(cid:82)(cid:71)(cid:80)(cid:85)(cid:71)(cid:85) (cid:49)(cid:86)(cid:74)(cid:71)(cid:84)(cid:14)(cid:2)(cid:75)(cid:80)(cid:69)(cid:78)(cid:87)(cid:70)(cid:75)(cid:80)(cid:73)(cid:2)(cid:75)(cid:79)(cid:82)(cid:67)(cid:75)(cid:84)(cid:79)(cid:71)(cid:80)(cid:86)(cid:2)(cid:81)(cid:72)(cid:2)(cid:78)(cid:81)(cid:80)(cid:73)(cid:15) (cid:78)(cid:75)(cid:88)(cid:71)(cid:70)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:81)(cid:86)(cid:74)(cid:71)(cid:84)(cid:2)(cid:67)(cid:85)(cid:85)(cid:71)(cid:86)(cid:85) (cid:37)(cid:49)(cid:56)(cid:43)(cid:38)(cid:15)(cid:19)(cid:27)(cid:15)(cid:84)(cid:71)(cid:78)(cid:67)(cid:86)(cid:71)(cid:70)(cid:2)(cid:71)(cid:90)(cid:82)(cid:71)(cid:80)(cid:85)(cid:71)(cid:85)(cid:2)(cid:10)(cid:69)(cid:11) (cid:57)(cid:75)(cid:80)(cid:86)(cid:71)(cid:84)(cid:2)(cid:53)(cid:86)(cid:81)(cid:84)(cid:79)(cid:2)(cid:55)(cid:84)(cid:75)(cid:2)(cid:75)(cid:79)(cid:82)(cid:67)(cid:69)(cid:86)(cid:85)(cid:2)(cid:10)(cid:70)(cid:11) Adjusted EBITDA — 2 — — (cid:10)(cid:20)(cid:11) 57 — — (cid:10)(cid:19)(cid:22)(cid:11) — — — 18 4 239 457 1,312 (236) — 737 — 15 698 146 655 — (cid:10)(cid:25)(cid:22)(cid:11) — — — 9 1 1 — (cid:10)(cid:27)(cid:11) 60 52 38 — — — — — 3 — — 93 (413) — 2 139 (272) 330 18 (cid:10)(cid:23)(cid:20)(cid:11) — — — 33 2 1 60 53 (cid:10)(cid:22)(cid:24)(cid:18)(cid:11) 380 36 9 — — — (cid:10)(cid:23)(cid:21)(cid:11) 51 9 (cid:10)(cid:22)(cid:21)(cid:11) 1 1 (25) (1,242) (22) (1,264) (cid:10)(cid:22)(cid:23)(cid:26)(cid:11) 383 1,831 514 759 18 (cid:10)(cid:19)(cid:21)(cid:26)(cid:11) (cid:10)(cid:23)(cid:21)(cid:11) 51 7 77 8 698 1,941 — 1 — (21) — — — — — (cid:10)(cid:19)(cid:23)(cid:11) 3 — — (33) (cid:10)(cid:22)(cid:23)(cid:26)(cid:11) 384 1,831 493 759 18 (cid:10)(cid:19)(cid:21)(cid:26)(cid:11) (cid:10)(cid:23)(cid:21)(cid:11) 51 (cid:10)(cid:26)(cid:11) 80 8 698 1,908 (cid:10)(cid:67)(cid:11)(cid:2)(cid:43)(cid:80)(cid:69)(cid:78)(cid:87)(cid:70)(cid:71)(cid:85)(cid:2)(cid:6)(cid:19)(cid:21)(cid:22)(cid:2)(cid:79)(cid:75)(cid:78)(cid:78)(cid:75)(cid:81)(cid:80)(cid:2)(cid:81)(cid:72)(cid:2)(cid:87)(cid:80)(cid:84)(cid:71)(cid:67)(cid:78)(cid:75)(cid:92)(cid:71)(cid:70)(cid:2)(cid:79)(cid:67)(cid:84)(cid:77)(cid:15)(cid:86)(cid:81)(cid:15)(cid:79)(cid:67)(cid:84)(cid:77)(cid:71)(cid:86)(cid:2)(cid:80)(cid:71)(cid:86)(cid:2)(cid:73)(cid:67)(cid:75)(cid:80)(cid:85)(cid:2)(cid:81)(cid:80)(cid:2)(cid:75)(cid:80)(cid:86)(cid:71)(cid:84)(cid:71)(cid:85)(cid:86)(cid:2)(cid:84)(cid:67)(cid:86)(cid:71)(cid:2)(cid:85)(cid:89)(cid:67)(cid:82)(cid:85)(cid:16) (cid:10)(cid:68)(cid:11)(cid:2)(cid:43)(cid:80)(cid:69)(cid:78)(cid:87)(cid:70)(cid:71)(cid:85)(cid:2)(cid:80)(cid:87)(cid:69)(cid:78)(cid:71)(cid:67)(cid:84)(cid:2)(cid:72)(cid:87)(cid:71)(cid:78)(cid:2)(cid:67)(cid:79)(cid:81)(cid:84)(cid:86)(cid:75)(cid:92)(cid:67)(cid:86)(cid:75)(cid:81)(cid:80)(cid:2)(cid:81)(cid:72)(cid:2)(cid:6)(cid:25)(cid:26)(cid:2)(cid:79)(cid:75)(cid:78)(cid:78)(cid:75)(cid:81)(cid:80)(cid:2)(cid:75)(cid:80)(cid:2)(cid:86)(cid:74)(cid:71)(cid:2)(cid:54)(cid:71)(cid:90)(cid:67)(cid:85)(cid:2)(cid:85)(cid:71)(cid:73)(cid:79)(cid:71)(cid:80)(cid:86)(cid:16) (cid:10)(cid:69)(cid:11)(cid:2)(cid:43)(cid:80)(cid:69)(cid:78)(cid:87)(cid:70)(cid:71)(cid:85)(cid:2)(cid:79)(cid:67)(cid:86)(cid:71)(cid:84)(cid:75)(cid:67)(cid:78)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:85)(cid:87)(cid:82)(cid:82)(cid:78)(cid:75)(cid:71)(cid:85)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:81)(cid:86)(cid:74)(cid:71)(cid:84)(cid:2)(cid:75)(cid:80)(cid:69)(cid:84)(cid:71)(cid:79)(cid:71)(cid:80)(cid:86)(cid:67)(cid:78)(cid:2)(cid:69)(cid:81)(cid:85)(cid:86)(cid:85)(cid:2)(cid:84)(cid:71)(cid:78)(cid:67)(cid:86)(cid:71)(cid:70)(cid:2)(cid:86)(cid:81)(cid:2)(cid:81)(cid:87)(cid:84)(cid:2)(cid:37)(cid:49)(cid:56)(cid:43)(cid:38)(cid:15)(cid:19)(cid:27)(cid:2)(cid:84)(cid:71)(cid:85)(cid:82)(cid:81)(cid:80)(cid:85)(cid:71)(cid:16) (cid:10)(cid:70)(cid:11)(cid:2)(cid:43)(cid:80)(cid:69)(cid:78)(cid:87)(cid:70)(cid:71)(cid:85)(cid:2)(cid:86)(cid:74)(cid:71)(cid:2)(cid:72)(cid:81)(cid:78)(cid:78)(cid:81)(cid:89)(cid:75)(cid:80)(cid:73)(cid:2)(cid:81)(cid:72)(cid:2)(cid:86)(cid:74)(cid:71)(cid:2)(cid:57)(cid:75)(cid:80)(cid:86)(cid:71)(cid:84)(cid:2)(cid:53)(cid:86)(cid:81)(cid:84)(cid:79)(cid:2)(cid:55)(cid:84)(cid:75)(cid:2)(cid:75)(cid:79)(cid:82)(cid:67)(cid:69)(cid:86)(cid:85)(cid:14)(cid:2)(cid:89)(cid:74)(cid:75)(cid:69)(cid:74)(cid:2)(cid:89)(cid:71)(cid:2)(cid:68)(cid:71)(cid:78)(cid:75)(cid:71)(cid:88)(cid:71)(cid:2)(cid:67)(cid:84)(cid:71)(cid:2)(cid:80)(cid:81)(cid:86)(cid:2)(cid:84)(cid:71)(cid:387)(cid:71)(cid:69)(cid:86)(cid:75)(cid:88)(cid:71)(cid:2)(cid:81)(cid:72)(cid:2)(cid:81)(cid:87)(cid:84)(cid:2)(cid:81)(cid:82)(cid:71)(cid:84)(cid:67)(cid:86)(cid:75)(cid:80)(cid:73)(cid:2)(cid:82)(cid:71)(cid:84)(cid:72)(cid:81)(cid:84)(cid:79)(cid:67)(cid:80)(cid:69)(cid:71)(cid:28)(cid:2)(cid:67)(cid:78)(cid:78)(cid:81)(cid:69)(cid:67)(cid:86)(cid:75)(cid:81)(cid:80)(cid:2)(cid:81)(cid:72)(cid:2)(cid:39)(cid:52)(cid:37)(cid:49)(cid:54)(cid:2)(cid:70)(cid:71)(cid:72)(cid:67)(cid:87)(cid:78)(cid:86)(cid:2)(cid:87)(cid:82)(cid:78)(cid:75)(cid:72)(cid:86)(cid:2)(cid:69)(cid:74)(cid:67)(cid:84)(cid:73)(cid:71)(cid:85)(cid:2)(cid:89)(cid:74)(cid:75)(cid:69)(cid:74)(cid:2)(cid:67)(cid:84)(cid:71)(cid:2) (cid:71)(cid:90)(cid:82)(cid:71)(cid:69)(cid:86)(cid:71)(cid:70)(cid:2)(cid:86)(cid:81)(cid:2)(cid:68)(cid:71)(cid:2)(cid:82)(cid:67)(cid:75)(cid:70)(cid:2)(cid:81)(cid:88)(cid:71)(cid:84)(cid:2)(cid:79)(cid:81)(cid:84)(cid:71)(cid:2)(cid:86)(cid:74)(cid:67)(cid:80)(cid:2)(cid:27)(cid:18)(cid:2)(cid:91)(cid:71)(cid:67)(cid:84)(cid:85)(cid:2)(cid:87)(cid:80)(cid:70)(cid:71)(cid:84)(cid:2)(cid:69)(cid:87)(cid:84)(cid:84)(cid:71)(cid:80)(cid:86)(cid:2)(cid:82)(cid:84)(cid:81)(cid:86)(cid:81)(cid:69)(cid:81)(cid:78)(cid:85)(cid:29)(cid:2)(cid:67)(cid:69)(cid:69)(cid:84)(cid:87)(cid:67)(cid:78)(cid:2)(cid:81)(cid:72)(cid:2)(cid:45)(cid:81)(cid:69)(cid:74)(cid:2)(cid:71)(cid:67)(cid:84)(cid:80)(cid:15)(cid:81)(cid:87)(cid:86)(cid:2)(cid:67)(cid:79)(cid:81)(cid:87)(cid:80)(cid:86)(cid:85)(cid:2)(cid:86)(cid:74)(cid:67)(cid:86)(cid:2)(cid:86)(cid:74)(cid:71)(cid:2)(cid:37)(cid:81)(cid:79)(cid:82)(cid:67)(cid:80)(cid:91)(cid:2)(cid:89)(cid:75)(cid:78)(cid:78)(cid:2)(cid:82)(cid:67)(cid:91)(cid:2)(cid:68)(cid:91)(cid:2)(cid:86)(cid:74)(cid:71)(cid:2)(cid:71)(cid:80)(cid:70)(cid:2)(cid:81)(cid:72)(cid:2)(cid:86)(cid:74)(cid:71)(cid:2)(cid:85)(cid:71)(cid:69)(cid:81)(cid:80)(cid:70)(cid:2)(cid:83)(cid:87)(cid:67)(cid:84)(cid:86)(cid:71)(cid:84)(cid:2)(cid:81)(cid:72)(cid:2)(cid:20)(cid:18)(cid:20)(cid:20)(cid:29)(cid:2)(cid:72)(cid:87)(cid:86)(cid:87)(cid:84)(cid:71)(cid:2) (cid:68)(cid:75)(cid:78)(cid:78)(cid:2)(cid:69)(cid:84)(cid:71)(cid:70)(cid:75)(cid:86)(cid:85)(cid:2)(cid:84)(cid:71)(cid:78)(cid:67)(cid:86)(cid:71)(cid:70)(cid:2)(cid:86)(cid:81)(cid:2)(cid:57)(cid:75)(cid:80)(cid:86)(cid:71)(cid:84)(cid:2)(cid:53)(cid:86)(cid:81)(cid:84)(cid:79)(cid:2)(cid:55)(cid:84)(cid:75)(cid:2)(cid:10)(cid:67)(cid:85)(cid:2)(cid:72)(cid:87)(cid:84)(cid:86)(cid:74)(cid:71)(cid:84)(cid:2)(cid:70)(cid:71)(cid:85)(cid:69)(cid:84)(cid:75)(cid:68)(cid:71)(cid:70)(cid:2)(cid:68)(cid:71)(cid:78)(cid:81)(cid:89)(cid:11)(cid:29)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:57)(cid:75)(cid:80)(cid:86)(cid:71)(cid:84)(cid:2)(cid:53)(cid:86)(cid:81)(cid:84)(cid:79)(cid:2)(cid:55)(cid:84)(cid:75)(cid:2)(cid:84)(cid:71)(cid:78)(cid:67)(cid:86)(cid:71)(cid:70)(cid:2)(cid:78)(cid:71)(cid:73)(cid:67)(cid:78)(cid:2)(cid:72)(cid:71)(cid:71)(cid:85)(cid:2)(cid:67)(cid:80)(cid:70)(cid:2)(cid:81)(cid:86)(cid:74)(cid:71)(cid:84)(cid:2)(cid:69)(cid:81)(cid:85)(cid:86)(cid:85)(cid:16)(cid:2)(cid:54)(cid:74)(cid:71)(cid:2)(cid:67)(cid:70)(cid:76)(cid:87)(cid:85)(cid:86)(cid:79)(cid:71)(cid:80)(cid:86)(cid:2)(cid:72)(cid:81)(cid:84)(cid:2)(cid:72)(cid:87)(cid:86)(cid:87)(cid:84)(cid:71)(cid:2)(cid:68)(cid:75)(cid:78)(cid:78)(cid:2)(cid:69)(cid:84)(cid:71)(cid:70)(cid:75)(cid:86)(cid:85)(cid:2)(cid:84)(cid:71)(cid:78)(cid:67)(cid:86)(cid:71)(cid:85)(cid:2)(cid:86)(cid:81)(cid:2)(cid:78)(cid:67)(cid:84)(cid:73)(cid:71)(cid:2) 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(cid:67)(cid:69)(cid:69)(cid:87)(cid:84)(cid:67)(cid:86)(cid:71)(cid:78)(cid:91)(cid:2)(cid:84)(cid:71)(cid:387)(cid:71)(cid:69)(cid:86)(cid:85)(cid:2)(cid:75)(cid:86)(cid:85)(cid:2)(cid:81)(cid:82)(cid:71)(cid:84)(cid:67)(cid:86)(cid:75)(cid:80)(cid:73)(cid:2)(cid:82)(cid:71)(cid:84)(cid:72)(cid:81)(cid:84)(cid:79)(cid:67)(cid:80)(cid:69)(cid:71)(cid:16) VISTRA 2021 ANNUAL REPORT 8 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, 2021 — OR — RR ☐ TRANSIT ION 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 (State or other jurisdiction of incorporation or organization) 36-4833255 (I.R.S. Employer Identification No.) 6555 Sierra Drive 75039 (Address of principal executive offices) (Zip Code) Irving, Texas (214) 812-4600 (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Common stock, par value $0.01 per share Warrants Trading Symbol(s) VST VST.WS.A Name of Each Exchange on Which Registered New York Stock Exchange 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 RuleRR 405 of the Securities Act. Yes ☒ No ☐ Indicated by check mark if the registrant is not required to fileff 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. ff Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ff ☐ 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. ☒ 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, 2021, the aggregate market value of the Vistra Corp. common stock held by non-affiliates of the registrant was $8,921,038,713 based on the closing sale price as reported on the New York Stock Exchange. As of February 22, 2022, there were 448,803,986 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 2022 annual meeting of stockholders are incorporated in Part III of this annual report on Form 10-K. TABLE OF CONTENTS PAGE Glossary Item 1. Item 1A. Item 1B. Item 2. Item 3. Item 4. Item 5. Item 6. Item 7. Item 7A. Item 8. Item 9. Item 9A. Item 9B. Item 9C. Item 10. Item 11. Item 12. Item 13. Item 14. Item 15. Item 16. Signatures PART I. BUSINESS RISK FACTORS UNRESOLVED STAFF COMMENTS PROPERTIES LEGAL PROCEEDINGS MINE SAFETY DISCLOSURES PART II. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES [RESERVED] MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATRR IONS QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE CONTROLS AND PROCEDURES OTHER INFORMATION DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTION PART III. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE EXECUTIVE COMPENSATION SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE PRINCIPAL ACCOUNTANT FEES AND SERVICES EXHIBITS AND FINANCIAL STATEMENT SCHEDULES FORM 10-K SUMMARY PART IV. ii 1 19 46 46 48 48 49 50 50 80 86 164 164 166 166 167 167 167 167 167 168 183 184 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 forff 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 When the folff lowing terms and abbreviations appear in the text of this report, they have the meanings indicated below. GLOSSARY 2020 Form 10-K Ambit or Ambit Energy ARO CAA CAISO Vistra's annual report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February Ambit Holdings, LLC, and/or its subsidiaries (d/b/a Ambit), depending on context 26, 2021 rr asset retirement and mining reclamation obligation Clean Air Act The California Independent System Operator CARES Act Coronavirus Aid, Relief, and Economic Security Act CCGT CCR CFTC Chapter 11 Cases CME CO2 CPUC Crius CT Dynegy Dynegy Energy Services EBITDA Effecff tive Date Emergence ESG EPA ERCOT ESS Exchange Act FERC Fitch FTC GAAP GHG GWh combined cycle gas turbine coal combustion residuals U.S. Commodity Futures Trading Commission 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.r (EFH Corp.) and the majoa rity 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 the 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) emerged fromff the Chapter 11 Cases. Chicago Mercantile Exchange carbon dioxide ff Californi a Public Utilities Commission Crius Energy Trust and/or its subsidiaries, depending on context combustion turbine Dynegy Inc., and/or its subsidiaries, depending on context Dynegy Energy Services, LLC and Dynegy Energy Services (East), LLC (each d/bdd /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. earnings (net income) before interest expense, income taxes, depreciation and amortization October 3, 2016, the date the TCEH Debtors and the Contributed EFH Debtors completed their reorganization under the Bankruptcy Code and emerged fromff emergence of the TCEH Debtors and the Contributed EFH Debtors from the Chapter 11 Cases as subsidiaries of a newly formed company, Vistra, on the Effective Date environmental, social and governance the Chapter 11 Cases U.S. Environmental Protection Agency Electric Reliabila ity Council of Texas, Inc. energy storage system Securities Exchange Act of 1934, as amended U.S. Federal Energy Regulatory Commission Fitch Ratings Inc. (a credit rating agency) Federal Trade Commission generally accepted accounting principles greenhouse gas gigawatt-hours 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 ii ICE IEPA IPCB IRC IRS ISO ISO-NE kW LIBOR load LTSA Luminant market heat rate Merger Merger Agreement Merger Date MISO MMBtu Moody's MSHA MW MWh NELP NELP Transaction NERC NJEA NOX NRC NYISO NYMEX NYSE Oncor OPEB Parent PJM Intercontinental Exchange Illinois Environmental Protection Agency Illinois Pollution Control Board Internal Revenue Code of 1986, as amended U.S. Internal Revenue Service independent system operator ISO New England Inc. kilowatt London Interbank Offered Rate, an interest rate at which banks can borrow funds, in marketable size, fromff demand for electricity other banks in the London interbank market long-term service agreements for plant maintenance subsidiaries of Vistra engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management source to electricity. Market Heat rate is a measure of the efficiency of converting a fuel 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 naturat l gas. ff t t the merger of Dynegy with and into Vistra, with Vistra as the surviving corporation the Agreement and Plan of Merger, dated as of October 29, 2017, by and between Vistra and Dynegy April 9, 2018, the date Vistra and Dynegy completed the transactions contemplated by the Merger Agreement Midcontinent Independent System Operator, Inc. million British thermal units Moody's Investors Service, Inc. (a credit rating agency) U.S. Mine Safety and Health Administration megawatts megawatt-hours Northeast Energy, LP, a joint venturet 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 facff ility. 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 North American Electric Reliabila ity Corporation North Jersey Energy Associates, A Limited Partnership nitrogen oxide U.S. Nuclear Regulatory Commission New York Independent System Operator, Inc. the New York Mercantile Exchange, a commodity derivatives exchange New York Stock Exchange 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 postretirement employee benefits other than pensions Vistra Corp. PJM Interconnection, LLC iii 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 Preferred Stock Public Power as part of the Spin-Off, tff he 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 Vistra's Series A Preferred Stock and Series B Preferred Stock 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 PURARR REP RCT RTO S&P SEC Public Utility Commission of Texas Texas Public Utility Regulatory Act retail electric provider Railroad Commission of Texas, which among other things, has oversight of lignite mining gas exploration and production, activity in Texas, and has jurisdiction over oil and natural permitting and inspecting intrastate pipelines, and overseeing natural gas utility rates and compliance regional transmission organization t t Standard & Poor's Ratings (a credit rating agency) U.S. Securities and Exchange Commission Securities Act Securities Act of 1933, as amended Series A Preferrff ed Stock Series B Preferred Stock SG&A SO2 Spin-Off ST Tax Matters Agreement TCJA TCEH or Predecessor Vistra's 8.0% Series A Fixed Rate Reset Cumulative Redeemable Perpet t ual Stock, $0.01 par value, with a liquidation preference of $1,000 per share Vistra's 7.0% Series B Fixed Rate Reset Cumulative Redeemable Perpet t ual Stock, $0.01 par value, with a liquidation preference of $1,000 per share selling, general and administrative r r Preferred Preferred sulfur dioxide 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 steam turbine 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 The Tax Cuts and Jobs Act of 2017, federal income tax legislation enacted in December 2017, which significantly changed the tax laws appli 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 majoa r subsidiaries included Luminant and TXU Energy to business entities cablea a TCEH Debtors the subsidiaries of TCEH that were Debtors in the Chapter 11 Cases TCEQ TRA TRE TriEagle Energy TWh TXU Energy Texas Commission on Environmental Quality ights) to receive payments Tax Receivables Agreement, containing certain rights (TRA RRR from Vistra related to certain tax benefits, including benefits realized as a result of certain transactions entered into at Emergence (see Note 8 to the Financial Statements) Texas Reliability Entity, Inc., an independent organization that develops reliabia lity standards for the ERCOT region and monitors and enforces compliance with NERC standards and monitors compliance with ERCOT protocols 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 terawatt-hours 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 iv U.S. U.S. Gas & Electric Value Based Brands Vistra Vistra Intermediate Vistra Operations United States of America 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 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 Corp., formerly known as TCEH Corp., and/or its subsidiaries, depending on context. On the Effective Date, the TCEH Debtors and the Contributed EFH Debtors emerged fromff Chapter 11 and became subsidiaries of Vistra Energy Corp. Effective July 2, 2020, Vistra Energy Corp. changed its name to Vistra Corp. Vistra Intermediate Company LLC, a direct, wholly owned subsidiary of Vistra Vistra Operations Company LLC, an indirect, wholly owned subsidiary of Vistra that is the issuer of certain series of notes (see Note 11 to the Financial Statements) and borrower under the Vistra Operations Credit Facilities Vistra Operations Credit Facilities Vistra Zero Vistra Operations senior secured financing facilities (see Note 11 to the Financial Statements) Vistra Zero LLC v [THIS PAGE INTENTIONALLY LEFT BLANK] Item 1. BUSINESS PART I Refereff nces 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 activities including electricity generation, gas to end users. wholesale energy sales and purchases, commodity risk management and retail sales of electricity and natural Vistra Energy Corp. to We incorporated under Delaware law in 2016. Effective July 2, 2020, we changed our name fromff Vistra Corp. to distinguish from companies that are involved in exploring for, producing, refining, or transporting fossil fuel s (many of which use "energy" in their names) and to better reflect our integrated business model, which combines a retail on serving its customers with new and innovative products and services and an electricity and natural electric power generation business leading the clean power transition through our Vistra Zero portfolio while powering the communities we serve with safe, reliable and affordablea gas business focused power. ff ff t t We serve approximately 4.3 million customers and operate in 20 states and the District of Columbia. Our generation fleet totals approxi gas, nuclear, coal, solar and battery energy a storage facilities. mately 38,700 MW of generation capac ity with a portfolio of natural a t Vistra has six reportablea t Discussion below and Note 20 to the Financial Statements for furff MarMM kerr including an update of our reportable segments in the third quarter of 2020. segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. See ther information concerning our reportable segments, Business Strate gye tt Vistra is a leader in the clean power transition. With a strong zero-carbon generation portfolio and a deliberate and and value for all stakeholders. Our responsible strategy to decarbonize, the company is focused on delivering healthy returns business strategy is focused on the following areas: t 1 • • • ation. Vistra's strategy is to responsibly and reliablya and resilient company well positioned to generate stablea grow our business through economically Growth and transforms , and energy storage assets that assist in reducing our carbon footprint and attractive investments in retail, renewablea create a more sustainablea long-term value for all of our stakeholders. Since 2010, Vistra has retired more than 12,000 MW of coal and gas power plants resulting in a 45% reduction of greenhouse gas (GHG emissions), a 45% reduction in carbon dioxide (CO2) emissions, a 55% reduction in nitrogen oxide (NOX) emissions, and a 75% reduction in sulfur dioxide (SO2) emissions through year-end 2020, 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. By year-end 2026, our Vistra Zero portfolio is expected to grow to 7,300 MW of zero-carbon generation, including solar, energy storage and our Comanche Peak nuclear power plant. Additionally, we have announced the retirement of approximately sible sites to solar and energy storage 7,500 MW of coal-fueled power plants by 2027, with plans to repurpose feaff to the developments. Repurposed sites provide a strategic advantage in the development of greener power dued interconnection infrastructuret they allow us to continue already available, but additionally, and importantly, 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-effeff ctive energy that meets their lities of sustainable preferences throughout the clean power transition. Our growth strategy leverages our core capabi multi-channel retail marketing in large and competitive markets, operating large-scale, environmentally sensitive, and technologies, fuel logistics and management, commodity risk management, cost diverse assets across a variety of fuel ff control, and energy infrastructuret 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, that complement our core capabi ncial 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 reliabila power, and pursuit of a just transition away from carbon-emitting generation assets for the communities in which we operate and serve. As a l process, the growth opportunities we pursue must a result, consistent with our disciplined capita have compelling economic value and align with or enhance our purpose and core principles. including renewable energy and battery storage assets as well as retail businesses, lities and align with our operational, finaff al allocation approva ity, affordablea a a t capita In addition to our dedicated approa Disciplined capital allocation. Vistra takes a disciplined approach to capital allocation in support of our commitment al allocation decisions that we believe will lead to to maintain a strong balance sheet. We thoughtfully make capita al to our stockholders through quarterly dividends and attractive cash returns on investment, including returning our share repurchase program as reflected in our current plans to returnt al to common up to $7.5 billion in capita o $3 billion in debt (exclusive of potential limited recourse project financing) through shareholders and reduce up tu value to all stakeholders, we invest prudently in the 2026. 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 make prudent capita al 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, ity of our facilities, all while accelerating growth in our Vistra Zero portfolio to maintain the safety a pipeline with cost-efficient capita al and investment in new technologies when economic, including solar assets and energy storage systems, resulting in a continued modernization of Vistra's generation fleet. t ch to returning nd reliabila a t e business model. Our integrated business model is an important component of our business strategy. This Integrated d by our diversified portfolio. This key factor element of our business provides long-term sustainable solutions enablea and efficient mining, diversified generation distinguishes us from our electricity competitors by pairing our reliablea fleet and wholesale commodity risk management capabi lities with our retail platform. Coupling retail with generation is a core competitive advantage that reduces the effects of commodity price movements and contributes to stable earnings and predictable cash flow, ture of the strategy as Vistra responsibly grows its renewables portfolio and winds down its carbon-em a crucial feaff itting assets. a ff r 2 • • • • t and affordablea 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 gas needs of end-use residential, small business, commercial and industrial electricity retail electricity and natural In addition to benefitting from our integrated business customers through multiple sales and marketing channels. model, we leverage our brands, our commitment to a safe, reliablea product offering, the backstop of the electricity generated by our generation fleet, 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 of innovation with new environmentally-conscious and sustainable-focused product offerings and customer ff forefront experiences to reinforce our value proposition. We maintain a focuff s 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 residential plans, MyEnergy DashboardSM, TXU Energy's iThermostat product and mobile solution, the TXU Energy Rewards program, the TXU Energy Green UpSM renewabla e 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 forff 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. o Excellence in operati ons while maintaining an effiff cient 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, reliablya 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 i s 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 safetyff 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. t d hedging and commercial management. Our commercial team is focuse Integrate d on effectively and efficiently e 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 ncial contracts, basis, through contracts for physical delivery of electricity, exchange-traded and over-the-counter finaff 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. ff s ity att nd ESG initiatives. Corporate responsibil 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 embeds ESG and considers all stakeholders – customers, suppliers, local communities, employees, contractors, investors and the environment, among others – into all of our decisions, processes and activities. The Board has ultimate oversight of all our ESG initiatives and ensures these considerations are embedded at every level of our company. 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 sustainablea 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 measurablea ESG goals and initiatives in a transparent manner. t 3 Recent Developme o nts Dividendd d Declarations — In February 2022, the Board declared a quarterly dividend of $0.17 per share of common stock that will be paid in March 2022 and a semi-annual dividend of $40.00 per share of Series A Preferred Stock that will be paid in April 2022. Green Finance Framework — In December 2021, we announced the publication of our Green Finance Framework, which ncial instruments to fund new or existing projects that support renewabla e energy and energy allows us to issue green finaff efficiency with alignment to our ESG initiatives. See below and Note 14 to the Financial Statements for more information concerning the Series B Preferre d Stock, which was issued in December 2021 under the Green Finance Framework. ff ff d StocS Series A Preferre k OffeO ring — On October 15, 2021, we issued 1,000,000 shares of Series A Preferred Stock in a private offering (Series A Offering). The net proceeds of the Series A Offering were approximately $990 million, after deducting underwriting commissions and offering expenses. We intend to use the net proceeds from the Series A Offering to repurchase shares of our outstanding common stock under the Share Repurchase Program. See Note 14 to the Financial Statements for more information concerning the Series A Preferred Stock and our Share Repurchase Program. ff d StocS Series B Preferre k OffeO ring — On December 10, 2021, we issued 1,000,000 shares of Series B Preferred Stock in a private offering (Series B Offering) under our Green Finance Framework. The net proceeds of the Series B Offering were approximately $985 million, after deducting underwriting commissions and offering expenses. We intend to use the proceeds from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments. See Note 14 to the Financial Statements forff more information concerning the Series B Preferred Stock. Commodity-Linked Revolving Credit Facility — On February 4, 2022, Vistra Operations entered into a credit agreement by and among Vistra Operations, Vistra Intermediate, the lenders, joint lead arrangers and joint bookrunners party thereto, and Citibank, N.A., as administrative agent and collateral agent. The Credit Agreement provides forff a $1.0 billion senior secured commodity-linked revolving credit facility (the Commodity-Linked Facility). Vistra Operations intends to use the liquidity provided under the Commodity-Linked Facility to make cash postings as required under various commodity contracts to which al and Vistra Operations and its subsidiaries are parties as power prices increase from time-to time and for other working capita general corporate purposes. See Note 11 to the Financial Statements for more information concerning the Commodity-Linked Facility. 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 folff lowing is a summary of our segments: • • • • • • t gas to residential, commercial and The Retail segment represents Vistra's retail sales of electricity and natural industrial customers. The Texas segment represents Vistra's electricity generation operations in ERCOT, 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 PJM, ISO-NE and NYISO. The West segment represents Vistra's electricity generation operations in CAISO. As reflected by the Moss Landing and Oakland ESS projects (see Note 3 to the Financial Statements), the Company expects to expand its operations in the West segment. The Sunset segment represents plants with announced retirement plans that were previously reported in the ERCOT, PJM and MISO segments. Given recent and expected future retirements of certain power plants, management ates between operating plants with defined retirement plans believes it is important to have a segment which differenti and operating plants without defined retirement plans. The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines. ff See Note 20 to the Financial Statements forff further information concerning reportable segments. 4 Independent System Operator O (( s (rr ISOs) and Regioe nal Transmissi ii on Organizati ii ons (RTOs) both maximum utilization and reliablea 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 forff 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 overlap between NERC regions and ISOs/RTOs, their respective a roles and responsibilities do not generally overlap.a and efficient operation of the transmission system. footprints, and while there may be geographic a ff t 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 forff 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 prices respective to other zones given location. Different zones or locations within the same ISO/RTO may produce different within the same ISO/RTO due to transmission losses and congestion. For example, a less efficient and/or less economical gas-fueled unit may be needed in some hours to meet demand. If this unit's production is required to meet demand on natural t the margin, its offer price will set the market clearing price that will be paid forff all dispatched generation in the same zone or location (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. ff t Retail MarkMM etkk stt The Retail segment is engaged in retail sales of electricity, natural mately 4.3 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. gas and related services to approxi a t 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, 2021, we provided electricity to approximately 30% of the residential customers in ERCOT and for approximately 15% of business customers' demand. We believe that we have differentiated ourselves by providing a distinctive customer experience predicated on delivering reliablea 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 consumptim on 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 enablea s 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 protect our retail business from power price volatility by allowing us to bypass bid-ask spread in the market (particularly for illiquid products and time periods) and achieve lower collateral costs for our retail business as compared to other, non-integrated retail electric providers. Moreover, our retail business reduces, 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 provide a natural offset to the length of Luminant's generation portfolio thereby reducing the exposure to wholesale power price volatility as compared to a non-integrated independent power producer. t 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 1.9 million customers in 18 states and the District of Columbia. t 5 ee Texas Segment Our Texas segment is comprised of 18 power generation facilities totaling 17,623 MW of generation capac a ity in ERCOT. We also operate a 10 MW battery ESS at our Upton 2 solar facility. ISO/RTO ERCOT ERCOT ERCOT ERCOT ERCOT Technology CCGT ST CT or ST Nuclear Solar/Battery Primary Fuel Naturt al Gas Coal Naturat l Gas Nuclear Renewable Total Texas Segment Number of Facilities 7 2 7 1 1 18 Net Capacity (MW) 7,838 3,850 3,455 2,300 180 17,623 We plan to develop up to 768 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas with estimated commercial operation dates between first quarter of 2022 to fourth quarter of 2023. See Note 3 to the Financial Statements for a summary orr f our solar and battery energy storage projects. ERCOT — ERCOT is an ISO that manages the flow of electricity from approximately 86,000 MW of summer peak generation capaa city to approximately 26 million Texas customers, representing approximately 90% of the state's electric load. As an energy-only market, ERCOT's market design is distinct fromff other competitive electricity markets in the U.S. Other markets maintain a minimum planning reserve margin through regulated planning, resource adequacy requirements and/ ity markets. In contrast, ERCOT's resource adequacy is predominately dependent on energy-market price signals. In a or capac 2014, ERCOT implemented the Operating Reserve Demand Curve (ORDC), pursuant to which wholesale electricity prices in the real-time electricity market increase automatically as availablea 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 In both March 2019 and March 2020, ERCOT implemented 0.25 standard using forecasted reserves and historical data. 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 falff l below defined thresholds. Effective January 1, 2022, when operating reserves drop to 3,000 MW or less, the ORDC automatically adjud sts power prices to the established value ERCOT also calculates the of lost load (VOLL), which is set at $5,000/MWh which is equal to the high system-wide offer cap.a If the peaker net "peaker net margin" based on revenues a hypothetical unhedged peaking unit would collect in the market. margin exceeds a certain threshold, the system-wide offer cap ia f $2,000/MWh for s reduced to the low system-wide offer cap oa the remainder of the calendar year. The peaker net margin exceeded the threshold for the first time during Winter Storm Uri, as in place for the balance of 2021. Historically, high demand due to elevated and as a result the low system-wide offer cap wa 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 ilities (see Item 7. Management's Discussion and Analysis t f Oo of Financial Condition and Results ott gas-fueled generation facff peO rations – KeyKK Operational Risks in the summer months or high demand due to reduced temperatures and Challenges). t ll t ii 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 In addition, markets allow market participants to manage their risk profile by adjusting their participation in each market. ERCOT uses ancillary services to maintain system reliabia lity, including regulation service, responsive reserve service and non- voltage and frequency spinning reserve service. Ancillary services are provided by generators to help maintain the stablea requirements of the transmission system. Because ERCOT has one of the highest concentrations of wind and solar capac ity tuations in wholesale electricity supply due to generation among U.S. markets, the ERCOT market is more susceptible to flucff intermittent wind and solar production, making ERCOT more vulnerable to periods of generation scarcity. Beginning in July 2021, ERCOT has increased its ancillary s ervice procurement volumes to maintain a more conservative level of operating reserves. a rr 6 East Segment Our East segment is comprised of 21 power generation facilities in 10 states totaling 12,093 MW of generating capac a ity in PJM, ISO-NE and NYISO. ISO/RTO PJM PJM PJM ISO-NE NYISO Technology CCGT CT CT CCGT CCGT Primary Fuel Natural Gas Natural Gas Fuel Oil Natural Gas Natural Gas Total East Segmen t Number of Facilities 8 4 2 6 1 1 2 Net Capacity (MW) 6,081 1,346 93 3,361 1,212 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 2023 to 2025. See Note 3 to the Financial Statements for a summary of our solar and battery energy storage projects. ity to PJMJJ — PJM is an RTO that manages the flow of electricity from approximately 180,000 MW of generation capac 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. a ff a capac Like ERCOT, PJM administers markets forff wholesale electricity and provides transmission planning for the region, every generator and load point within utilizing a locational marginal pricing (LMP) methodology which calculates a price forff 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 ity auction, the Reliability Pricing Model (RPM), which establishes a long-term market for capac ity. We have participated in RPM auctions for years up to and including PJM's planning year 2022-2023, which ends a May 31, 2023. Due to a FERC order issued in December 2021, PJM's RPM auction for planning year 2023-2024 will be delayed and is expected to be run in the summer of 2022. We also enter into bilateral capacity transactions. PJM's Capacity Performance (CP) ruler 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. s were designed to improve system reliabia lity and include penalties forff ISO-NENN — ISO-NE is an ISO that manages the flow of electricity from approximately 31,000 MW of installed generation mately 15 million customers in the states of Vermont, New Hampshire, Massachusetts, Connecticut, Rhode a ity to approxi a capac Island and Maine. ISO-NE dispatches power plants to meet system energy and reliabila ity 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 participating states in ISO-NE and are largely influenced by transmission constraints and fuel supply. ity prices are determined ff through auctions. Performanc ity 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. ISO-NE offers a forward e incentive rules have the potential to increase capac ity market where capac a capac a a ff NYISOYY — NYISO is an ISO that manages the flow of electricity from approximately 39,000 MW of installed summer generation capaa city to approximately 20 million New York customers. NYISO dispatches power plants to meet system energy and reliabila ity 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 in the NYISO and are largely influenced by transmission constraints and fuel supply. NYISO offers a forward ity prices are determined ff through auctions. Strip auctions occur one to two months prior to the commencement of a six-month seasonal planning period. the balance of the seasonal planning period or the Subsequent auctions provide an opportunity to sell excess capac a upcoming month. Due to the short-term naturet ity auctions and a relatively liquid bilateral market of the NYISO-operated capac for NYISO capac ility sells a significant portion of its capacity through bilateral transactions. The balance is cleared through the seasonal and monthly capaa ity products, our Independence facff ity market where capac ity forff a city auctions. a capac a a 7 West SegSS megg nt Our West segment is comprised of two power generation facilities totaling 1,130 MW of generation capac a ity and the first two phases of a battery ESS facff ility totaling 400 MW in CAISO, all of which are located in California. ISO/RTO CAISO CAISO CAISO Technology CCGT Battery CT Primary Fuel Natural Gas Renewable Fuel Oil Total West Segmen t Number of Facilities 1 1 1 3 Net Capacity (MW) 1,020 400 110 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. Energy is priced in CAISO utilizing an LMP methodology. The capac ity market is comprised of Generic, Flexible and Local Resource Adequacy (RA) Capacity and is administered by the California Public Utilities Commission. Unlike other In November centrally cleared capac ity auction for annual, monthly, and intra-month procurement to cover forff 2016, CAISO implemented a voluntary capac d in October 2015, is a deficiencies in the market. The voluntary Competitive Solicitation Process, which FERC approve apacity. ity Procurement Mechanism (CPM) and provides another avenue to sell RA cRR modification to the Capac ity markets, the resource adequacy market in California is a bilaterally traded market. a a a a a Sunset Segment Our Sunset segment is comprised of 10 power generation facff ity 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 4 to the Financial Statements for more information related to these planned generation retirements. ilities totaling 7,486 MW of generating capac a ISO/RTO ERCOT MISO MISO PJM Technology ST ST CT ST Primary Fuel Coal Coal Natural Gas Coal Total Sunset Segment Number of Facilities 1 4 2 3 10 Net Capacity (MW) 650 3,187 221 3,428 7,486 See Texas Segme SS nt 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 202,000 MW of generation capac ity to approximately 42 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. a MISO dispatches power plants to meet system energy and reliabila ity 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 in MISO and are largely influenced by transmission evaluating the perforff mance of the markets and constraints and fuel supply. An independent market monitor is responsible forff 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 fromff June 1st of the current year to ity that has not been committed through May 31st of the following year. We participate in these auctions with open capac 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. a 8 Wholesale Operations Our wholesale commodity risk management group is responsible forff dispatching our generation fleet in response to market needs after implementing portfolio optimization strategies, thus linking and integrating the generation fleff et 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 by peaking units. Peaking units are typically the most expensive to operate, but they can quickly start up loads may be satisfiedff owing units and peaking units and shut down to meet brief peaks in demand. In general, baseload units, intermediate/load foll tion is typically based on the are dispatched into the ISO/RTO grid in order from lowest to highest variable cost. Price forma highest variable cost unit that clears the market to satisfy system demand at a given point in time. ff ff 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. Seasonalitll ytt ed by weather. As a result, our operating results The demand for and market prices of electricity and natural are impacted by extreme or sustained weather conditions and may flucff tuate 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 gas is also generally higher in the winter. More severe weather conditions such as heat waves or extreme and price of natural tuation may change winter weather have made, and may make such fluctuations more pronounced. The pattern of this flucff depending on, among other things, the retail load served and the terms of contracts to purchase or sell electricity. gas are affect ff t t Compem titiii on 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 forff new and existing generation facilities, new market entrants, construction of new generating assets, technological advances in power generation, the actions of environmental and other tors. We primarily compete with other electricity generators and retailers based on our regulatory authorities, and other facff 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 appa property roximately 19 years, is registered and protected by trademark law and is the only material intellectual asset that we own. We have also acquired the trade names forff 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, 2021, we have reflected intangible assets on our balance sheet for our trade names of approximately $1.341 billion (see Note 6 to the Financial Statements). t 9 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.t One of Vistra's core principles is that we care about our key se srr , including our employees. We invest in our people through numerous development and training opportunities, engaging employee programs and generous benefit and wellness offerings. l takehol der kk As of December 31, 2021, we had approximately 5,060 full-time employees, including approximately 1,400 employees under collective bargaining agreements. Safety t Vistra's mindset around safety i s exemplim fied by our motto: Best Defense urt. Our safetyt culture revolves around people and human performance. We place a high importance on continuous improvement, along with a on numerous learning and error-prevention tools. To facilitate a learning environment, our various operating plants ff keen focus 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 constant communication and safety pt sustained interaction. In 2021, the generation fleff et conducted more than 57,000 leadership safety et ngagements across the fleet continuing our employee driven safety program focused on engagement of all employees. rocess. Managers are required to participate in safety et ngagements with staff to enablea . Everyor ne wins. No oNN ne gets htt ff Our focus on reducing the severity of injuries forff both our employees and contractors who work with us has shown positive results. In 2021, 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 0.87, better than the second quartile as compared to the Edison Electric (EEI) 2020 Total Company Injury Data. We encourage near-miss reporting and review of events to promote a learning Institutet vents were reviewed by our environment. operating teams to promote learning across the fleff et. earning calls were held every week where near-miss and safety et In 2021, safety l t t All Vistra employees are covered by our safety pt rogram. Corporate and retail employees are required to complete opics through our online learning management system. Employees who are located at a power plant periodic training on safety t are required to complete trainings based on job function, which is also tracked through our central learning management In addition, the Company engages an independent third-party conformity assessment and certification vendor to system. manage adherence to our safety st tandards for all vendors and contractors who work at our plants. In addition, we work closely with our suppli ers and contractors to ensure our safety practices are upheld. u rograms and comply with OSHA regulations. All of our power plant facilities have effective health and safety pt In addition to compliance, our generation fleet has a total of 12 plants that have been awarded the Voluntary Protection Program nd health management systems and for (VPP) Star designation by the OSHA for superior demonstration of effective safety at our industry. Four additional plants have submitted maintaining injury and illness rates below the national averages forff is the highest designation of OSHA's Voluntary Protection applications and are awaiting review by the OSHA. VPP Star statust Programs. The achievement recognizes employers and workers who have implemented effecff nd health management tive safety at systems and maintain injury and illness rates below national Bureau of Labor Statistics averages for their respective industries. years. These sites are self-sufficient in their ability to control workplace hazards and are reevaluated every three to fiveff Additionally, 31 of our power plants and mine locations have adopted a proactive Behavior Based Safety at ch to safetyt a which focuses on identifying and providing feedback on at-risk behaviors observed. pproa In 2021, we continued our COVID-19 protections and protocols ensuring the safety of all of our employees. Diversityii , Eyy quityii 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 appe arance, 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 marketplat ce and to provide a work environment that allows all employees to be their best. a 10 Vistra's diversity is evolving, and our Board and management are leading by example. Currently, three of the ten Board members are women, and two of the ten are ethnically diverse. Overall, 28% of the Company's workforce is ethnically diverse. Women currently hold 26% of the Company's senior management positions, and ethnically diverse employees represent 27% of senior management. During 2021, we launched multiple initiatives to unlock the full potential of our people - and our company - through our diversity, equity, and inclusion efforts. We named our first Chief Diversity Officer in January 2021 who sponsors Vistra's shed in 2020. We continued to expand our Employee employee-led Diversity, Equity and Inclusion Advisory Council, establia Resource Groups (ERG) 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. Seven new ERGs were forff med in 2021, bringing the total number to twelve. New 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. Hiring manager training was developed and deployed to train managers on the importance of skills based hiring and inclusive recruiting processes, and we continue to work with Basic Diversity to develop training for employees to identify bias and develop strong inclusive leaders. t our Vistra is active in our communities to promote inclusivity. Vistra's supply chain diversity initiative seeks to reflect customer base and workforce compositions through creating a diverse supply chain. Through a new partnership with Disability:IN, the leading nonprofit resource for business disability inclusion worldwide, Vistra expanded its commitment to an inclusive global economy. Further, in the second 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. ff ff 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, including monthly leader meetings for director-level employees focusing on gaining a deeper understanding of Vistra's strategy, developing cross-functional relationships and interacting with senior leadership of the company. 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 fromff across the company. We also revised multiple leadership programs to continue virtual ly while we continue with remote work during the current pandemic. ff t 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. Thousands of web-based targeted courses are available to all employees, and the company further supports employees in completing thousands of hours of professional training to support their respective professional licenses, including accounting, legal and nuclear. In 2021, continuing education requirements forff Vistra launched a forma to all employees to focus on topics like organizational knowledge, career ff ion and leadership. Over 600 employees participated in 2021 and logged over development, individual development, collaborat 4,000 hours of development. -time employees, other than those in a collective bargaining unit, receive a ff formal performance review guiding development and improving results of the business. l mentoring program availablea In addition, all full a ll Emplm oye e Benefitsii t compensation structure, Maintaining attractive benefits and pay are important for recruiting and retaining talent. We are committed to maintaining an equitablea 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 employe e contributions up to 6%. m ff 11 Wellnell ss 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 In addition, our employee medical plans promote annual physicals, age and gender health screenings and immunizations. mental health and emotional wellness and offer resources forff employees seeking assistance. Fitness centers in multiple facilities offer cardio equipment, a selection of free weights and exercise mats. While deferred at times during COVID-19, 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 forff employees to participate in running and cycling events throughout the year. u Environmental Regulations and Related Considerations We are subject to extensive environmental regulation by governmental authorities, including the EPA and the lized or proposed several regulatory environmental regulatory bodies of states in which we operate. The EPA has recently finaff shing new requirements for control of certain emissions from sources, including electricity generation facilities. actions establia See Item 1A. Riskii Factors for additional discussion of risks posed to us regarding regulatory requirements. See Note 13 to the Financial Statements for a discussion of litigation related to EPA reviews. nd the Environment and Restoring Science to Tackl In January 2021, the Biden administration issued a series of Executive Orders, including one titled Protecting Public Health att e the Climate Crisis (the Environment Executive Order) which directed agencies, including the EPA, to review various agency actions promulgated during the prior administration and take action where the previous administration's action conflicts with national objectives. Several of the EPA agency actions discussed below are now subject to this review. TT ll Clima te Change There is continuing attention and interest domestically and internationally about global climate change and how GHG s, primarily by emissions, such as CO2, contribute to global climate change. GHG emissions from the combustion of fossil fuel our coal-fueled-generation plants as well as our natural gas-fueled generation plants represent the substantial majority of our total GHG emissions. CO2, methane and nitrous oxide are emitted in this combustion process, with CO2 representing the largest portion of these GHG emissions. We estimate that our generation facilities produced approxi mately 108 million short tons of CO2 in the year ended 2021. a ff t To manage our environmental impact fromff 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 CO2 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 diversification into low-emission businesses, primarily renewables and energy storage. We have already taken or announced significant steps to transform our generation portfolio and reduce the emissions profile of our generation fleet, including: • • • Solar Development have announced our plans to develop: o Projectstt — We began commercial operation of our 180 MW Upton 2 solar facility in 2018. We ◦ ◦ up to 768 MW of solar generation facilities in Texas with expected commercial operation dates during 2022-2023, and 300 MW of solar generation facilities at retired or to-be retired plant sites in Illinois with expected commercial operation dates ranging from 2023 to 2025. Storage Projectstt — We began commercial operation of our 10 MW battery ESS at our Upton 2 solar Battery Energyr facility in 2018 and our 400 MW of battery ESSs at our Moss Landing facility in 2021. We have announced our plans to develop: ◦ ◦ ◦ 260 MW of battery ESS in Texas with an expected commercial operation date in 2022; 150 MW of battery ESS at retired or to-be-retired plant sites in Illinois with expected commercial operation dates ranging from 2023 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. 15,448 MW of CCGTs across various ISOs/RTOs in connection with the Merger. In 2018, we acquired 12 • Retirements of Fossil Fuel Generation — In 2018, we retired 4,167 MW of lignite/coal-fueled generation facilities in Texas. In 2019, we retired 2,068 MW of coal-fueled generation facilities in Illinois. We expect to retire an additional 7,486 MW of fossil-fueled generation facilities in Illinois, Ohio and Texas no later than year-end 2027. See Note 3 to the Financial Statements forff discussion of our solar and battery energy storage projects and Note 4 to the Financial Statements for discussion of our retirement of generation facilities. GHG Emissions Clean Energy (ACE) rule. The ACE ruler that repealed the Clean Power Plan (CPP) that had been finaff In July 2019, the EPA finalized a rulerr lized in 2015 and shed new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the establia developed emission guidelines that states must use when developing plans Affordablea In response to challenges brought by to regulate GHG emissions from existing coal-fueled electric generating units. the District of Columbia Circuit (D.C. Circuit Court) Environmental groups and certain states, the U.S. Court of Appeals forff vacated the ACE ruler , including the repeal of the CPP in, January 2021 and remanded the rule to the EPA for further action. In October 2021, the U.S. Supreme Court granted four petitions for certiorari of the D.C. Circuit Court's decision and consolidated oral argument in February 2022. Additionally, in January the cases for review. The case is now fully briefed and scheduled forff 2021, the EPA, just prior to the transition to the Biden administration, issued a finaff a significant contribution finding for the purpose of regulating GHG emissions from new, modified, or reconstructed electric utility generating units. In and remand of the GHG April 2021, the D.C. Circuit Court granted the EPA's unopposed motion for voluntary vacaturt significant contribution rule. The ACE ruler and the rule on significant contribution are subject to the Environment Executive . Order discussed above setting forth l rulerr a ff State Regulation of GHGsHH Many states where we operate generation facilities have, are considering, or are in some stage of implementing, state-only regulatory programs intended to reduced emissions of GHGs from stationary sources as a means of addressing climate change. e 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 CO2 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 fromff 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 ruler including an additional 30 percent reduction in the CO2 annual cap ba conducting its third program review to be completed in 2022 which may include an updated model rule. with changes to the CO2 budget trading program, y the year 2030, relative to 2020 levels. RGGI is currently Our generating facilities in Connecticut, Maine, Massachusetts, New Jersey, New York and Virginia emitted approximately 8.5 million tons of CO2 during 2021. The spot market price of RGGI allowances required to operate these facilities as of December 31, 2021 was approximately $13.68 per allowance. The spot market price of RGGI allowances 2022 was approximately $14.01 per allowance on February 22, 2022. While required to operate our affected facilities during the cost of allowances required to operate our RGGI-affected facff ilities 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. d Massachusettstt — In August 2017, the Massachusetts Department of Environmental Protection (MassDEP) adopted final shing an annual declining limit on aggregate CO2 emissions from 21 in-state fossil-fueled electricity generation rules establia units. The rules establia sh an allowance trading system under which the annual aggregate electricity generation unit sector capa on CO2 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 forff 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 establia shed by the rule. Beginning in 2021, all allowances were distributed through the auction. Limited banking of unused allowances is allowed. 13 r Virgini a — In May 2019, the Virginia Department of Environmental Quality issued a finaff a 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 rulerr and linked Virginia to RGGI in 2021. The Governor of Virginia issued an RGGI; however, the Virginia General Executive Order in January 2022 to begin the process of removing the state fromff Assembly would need to modify the law to exit the program. At this time, no new laws have passed and Virginia remains in RGGI. to adopt a carbon l rulerr r New JersJJ ey — 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 forma lly 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. ff California — Our assets in California are subject to the California Global Warming Solutions Act, which required the ff a Air Resources Board (CARB) to develop a GHG emission control program to reduce emissions of GHGs in the state Californi ff to 1990 levels by 2020. In April 2015, the Governor of California issued an executive order establia shing 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-t rade program through 2030 and the CARB adopted amendments to its cap-and-t ework for extending the rade regulations that, among other things, establia program beyond 2020 and linking the program to the new cap-a and-trade program in Ontario, Canada beginning in January 2018. shed a framff a a Air Ei miEE ssio ii ns The Clean Air Act (CAA)A The CAA and comparablea 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 SO2 emissions and in some regions NOX 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 desulfuriz ation (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-NOX burners and/or overfire air systems on all units. Additionally, our MISO coal- fueled facilities mainly use low sulfur coal. ff Regional e Haze — Reasonable Progress and Best Available Retrofit tt Technology (BARBB T) for Texas ee The Regional Haze Program of the CAA establia shes "as a national goal the prevention of any future, and the remedying of man-made pollution." any existing, impairment of visibility in mandatory class I fede reasonable progress for Class I There are two components to the Regional Haze Program. First, states must establish goals forff eral areas in federal areas within the state and establia 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. sh long-term strategies to reach those goals and to assist Class I fedff ral areas which impairment results fromff ff t 14 l rulerr In October 2017, the EPA issued a finaff addressing BART for Texas electricity generation units, with the rule serving as a partial approval of Texas' 2009 State Implementation Plan (SIP) and a partial Federal Implementation Plan (FIP). For SO2, the rule establia shed 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 NOX, the rule adopted the CSAPR's ozone program as BART and for particulate matter, the rulerr approved Texas's SIP that determines that no electricity generation units are subject to BART forff particulate matter. In August 2020, the but also included additional revisions that were proposed in EPA issued a finaff November 2019. Challenges to both the 2017 rule and the 2020 rules have been consolidated in the D.C. Circuit Court, where , and the retirements of our Monticello, Big we have intervened in support of the EPA. We are in compliance with the rulerr is subject to the Environment Executive Brown and Sandow 4 plants have enhanced our ability to comply. The BART ruler . The challenges Order discussed above, and the EPA has stated it is starting a proceeding for reconsideration of the BART ruler in the D.C. Circuit Court have been held in abeyance pending the EPA's action on reconsideration. affirming the prior BART finaff l ruler l ruler National Ambient Air Quality Stt taS ndards (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 SO2 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. SO2 Designati i ons for Texas ee u u In December 2017, the TCEQ submi tted a petition for reconsideration to the EPA. the Fifth Circuit (Fifth Circuit Court). Subsequent 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 U.S. Court of Appeals forff ly, in October 2017, the Fifth Circuit Court granted the EPA's motion to hold the case in abeyance considering the EPA's representation that it intended to revisit the nonattainment rule. 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 unclassifiablea In August 2020, the EPA issued a . Finding of Failure for Texas to submit an attainment plan. 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 In June 2021, the EPA published two notices; one that it was withdrawing the data supporting an attainment designation. 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, with the matter likely being fully briefed by March 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 SO2 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 will be submitted to the EPA forff review and approval. Ozone Designati i ons l ruler The EPA issued a finaff in October 2015 lowering the ozone NAAQS from 75 to 70 parts per billion. Areas ility in Illinois and our Wise, Ennis surrounding our Dicks Creek, Miami Fort and Zimmer facilities in Ohio, our Calumet facff and Midlothian faci lities 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. ff 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 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 subsidia l rulr e in the Federal Register u on April 30, 2021 that reduces ozone season NOX budgets in certain states. We do not believe that the final rulrr e causes a material adverse impact on our future financial results. These actions are subject to the Environment Executive Order discussed above. ries fileff d comments on that rulerr making in December 2020, and the EPA published a finaff 15 Coal Combustion Residuals (CCR)/GR roundw GG ater The combustion of coal to generate electric power creates large quantities of ash and byproducts that are managed at in surface impoundments. Each of our coal-fueled plants power generation facilities in dry form in landfills and in wet formff has at least one CCR surface impoundment. At present, CCR is regulated by the states as solid waste. CC Coal Combust ion Residualsll The EPA's CCR ruler , which took effect in October 2015, establia shes 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 surfaceff impoundments. The requirements include location restrictions, structural integrity criteria, groundwater monitoring, operating criteria, liner design criteria, closure and post-closure care, recordkeeping tors. The Water and notification. The deadlines for beginning and completing closure vary depending on several facff Infrastructure Improvements forff EPA review and approval of state CCR permit programs. the Nation Act (the WIIN Act), which was enacted in December 2016, provides forff t In August 2018, the D.C. Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR establishing a rule, including an applicability exemption for legacy impoundments. In August 2020, the EPA issued a finaff allows a deadline of April 11, 2021 to cease receipt of waste and initiate closure at unlined CCR impoundments. The final ruler and either a generation plant to seek the EPA's approval to extend this deadline if no alternative disposal capac conversion to comply with the CCR rulrr e 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 forff review of this rulerr in the D.C. Circuit Court, and Vistra subsidiaries filff ed a motion to intervene in support of the EPA in December 2020. that would allow an alternative liner demonstration for certain qualifying Also, in November 2020, the EPA finalized a rulerr 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 In January 2022, the EPA determined that our conversion and announcement that Zimmer will close by May 31, 2022. determination on any of those retirement applications for our CCR facff applications. ilities were complete but has not yet made a final ity is availablea l ruler a ff 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. a In May 2018, Prairie Rivers Network (PRN)RR At our retired Vermilion facility, which was not potentially subject to the EPA's 2015 CCR rulerr 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 forff additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options. filed a citizen suit in federal court in Illinois against our subsidiary 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 the Seventh Circuit affiff rmed the district court's judgment was entered in our favor. In June 2021, the U.S. Court of Appeals forff dismissal of the lawsuit, but stated that PRN may refile. In April 2019, PRN aRR lso filff ed 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. In July 2021, we answered that complaint, and this matter is in the very err arly stages. ff 16 In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeeff n ral facilities' CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the fede . In June 2018, the IEPA issued a violation notice for alleged seep discharges claimed to be coming from the surface CCR rulerr to the impoundments at our retired Vermilion facility, which is owned by our subsidiary DMG, and that notice was referredr Illinois Attorney General. In June 2021, the Illinois Attorney General and the Vermilion County State Attorney filff ed 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. These proposed closure costs are reflected in the ARO in our condensed consolidated balance sheets (see Note 21 to the Financial Statements). ff In July 2019, coal ash disposal and storage legislation in Illinois was enacted. The legislation addresses state requirements forff 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 rulr e, which was finalized and became effective in April 2021, coal ash impoundment owners would be required to submit a closure alternative analysis to the does not mandate closure by IEPA for the selection of the best method for coal ash remediation at a particular site. The rulerr removal at any site. In May 2021, we filed an appeal in the Illinois Fourth Judicial District over certain provisions of the final rule. We fileff d our opening brief in October 2021. Other parties have also filed appeals of certain provisions of the final rulrr e. rr 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. For all of the above matters, if certain corrective action measures, including groundwater treatment or removal of ash, are ilities, we may incur significant costs that could have a material adverse effect on our required at any of our coal-fueled facff financial condition, results of operations, and cash flows. The Illinois coal ash rule was final ized in April 2021 and does not require removal. However, the rule will require 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 submitted and approved by the IEPA. However, the currently anticipated CCR surface impoundment and landfill closure costs, as reflected in our existing ARO liabia lities, reflect the costs of closure methods that our operations and environmental services teams believe are appropriate and protective of the environment for each location. ff Water The EPA and the environmental regulatory bodies of states in which we operate have jurisdiction over the diversion, impoundment and withdrawal of water forff 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 ilities in operation and relating to these activities. We believe we hold all required permits relating to these activities for facff have applied for or obtained necessary permits forff facilities under construction. We also believe we can satisfy the requirements necessary to obtain any required permits or renewals. II S e Skk truct Cooling WateWW r Intak ures — Clean Water Act Section 316(b) regulations pertaining to existing water intake structures at large generation facilities became effective in 2014. This provision generally requires that the location, design, construction and capac t the best technology available for minimizing adverse environmental impacts. Although the rule does not mandate a certain control technology, it does require site-specificff assessments of technology feasibility on a case-by-case basis at the state level. ity of cooling water intake structures reflecff a t At this time, we estimate the cost of our compliance with the cooling water intake structure rulerr to be minimal at our Illinois plants due to the planned retirements of those plants by 2027. Our estimate could change materially depending upon a variety of factors, including site-specific determinations made by states in implementing the rule, the results of impingement and entrainment studies required by the rule, the results of site-specific engineering studies and the outcome of litigation concerning the rulrr e and potential plant retirements. 17 ff Effluent Limitation Guidelines (ELGs)GG — In November 2015, the EPA revised the ELGs forff steam electricity generation facilities, which will impose more stringent standards (as individual permits are renewed) for wastewater streams, such as fluff e gas desulfuriz ation (FGD), fly ash, bottom ash and flue gas mercury control wastewaters. Various parties filff ed petitions for review of the ELG rulrr e, and the petitions were consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions requesting reconsideration of the ELG rulrr e and administratively stayed the rule's compliance date deadlines. In August 2017, the EPA announced that its reconsideration of the ELG rulrr e would be limited to a review of the effluent limitations applicable to FGD and bottom ash wastewaters and the agency subsequently postponed the earliest compliance dates in the ELG rulrr e forff cation of effluent limitations for FGD and bottom ash wastewaters. Based on these administrative developments, the a the appli Fifth Circuit Court agreed to sever and hold in abeyance challenges to those effluent limitations. The remainder of the case proceeded, and in April 2019 the Fifth Circuit Court vacated and remanded portions of the EPA's ELG rulerr pertaining to effluent limitations forff in October 2020 that extends the both FGD and bottom ash transport water to no later than December 2025, as negotiated with the state compliance date forff permitting agency. Additionally, the final rulrr e allows for a retirement exemption that exempts facff ilities certifying that units will retire by December 2028 provided certain effluent limitations are met. In November 2020, environmental groups review of the new ELG revisions, and Vistra subsidiaries filff ed a motion to intervene in support of the EPA in petitioned forff and moved to hold the 2020 ELG revision December 2020. In July 2021, the EPA announced its intent to revise the ELG rulerr 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. legacy wastewater and leachate. The EPA published a finaff l ruler Radiodd active Wastett The nuclear industry has developed ways to store used nuclear fuel ff on site at nuclear generation facilities, primarily using currently in operation in the U.S. on-site in storage pools or dry cask storage facilities and believes its on-site used nuclear reprocessing or disposal of used nuclear fuel ff dry cask storage, since there are no facilities forff Luminant stores its used nuclear fuel fuel storage capabi a ff lity is sufficient for the foreseeable futff ure. t 18 Item 1A. RISK FACTORS Summary of Risk Factors The following summarizes the principal facff tors 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 ng our business. The following factors as an exhaustive summary of the material risks faci could result in harm to our business, financial condition, results of operations, cash flows, and prospects, among other impacts: u ff Market, Finanii ciali and Economic Risks • Our revenues, results of operations and operating cash flows are affected by price flucff market and other market facff tors beyond our control. tuations in the wholesale power • We purchase natural 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. gas, coal, fuel oil, and nuclear fuel ff t • We have retired, announced planned retirements of, and may be force ff d to retire or idle additional underperforming • • • • generation units which could result in significant costs and have an adverse effecff t 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. ral interference in the wholesale and retail power Competition, changes in market structure, markets, together with subsidized generation, may have a material adverse effect on our financial condition, results of operations and cash flows. and/or state or fede ff t Our results of operations and financial condition could be materially and adversely affected if energy market participants continue to construct new generation facilities or expand or enhance existing generation facilities despite relatively low power prices and such additional generation capac ion in wholesale power prices. ity results in a reductd a 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 favorablea 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 to substantial capital requirements and other significant uncertainties. renewables development projects, is subject 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 RRR ights forff certain tax benefits, which amounts are expected to be substantial. Regue latorytt and Legie slati ii ve 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 effecff t on us. 19 • • 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 material adverse effect on our businesses, results of operation, liquidity and financial condition. in the markets in which we participate may have a t • 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 effecff t on us. Operational Risks ii • • • 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 infrastructuret 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 effecff t 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 capita involve significant risks that could adversely affecff t our results of operations, liquidity and financial condition. al intensive and • 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 are subjeu ct to, and may be materially and adversely affected by, the effects of extreme weather conditions and seasonality. • • The outbreak of COVID-19, or the future outbreak of any other highly infectious or contagious diseases, could have a material and adverse effect on our business, financial condition, results of operations and cash flows. 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. ii Risks Relatedtt to Our Struc tt ture and Ownership oii f oo ur Common Stock • Evolving expectations from stakeholders, 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 affecff t our business, operations, financial results, or stock price. including investors, on ESG issues, 20 ll Please carefully consider the following discussion of significant factors, events, and uncertainties that make an tors, in addition to others specifically addressed in Item 7. Management's investment in our securities risky. These facff 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 In addition, if one or more of such condition, cash flows, reputation or prospects could be materially adversely affected. those contained factors, events and uncertainties were to materialize, it could cause results or outcomes to differ materially fromff risks and ff in or implied by any forward-looking statement in this annual report on Form 10-K. There may be further 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, resultsll power market and other market facff tors beyond our control.ll of operations and operatingii cash flowff s gw enerally all re affected by pb ff rice fluct uations in the wholesll ale t on capita We are not guaranteed any rate of returnt al investments in our businesses. We conduct integrated power generation and retail electricity activities, focusing on power generation, wholesale electricity sales and purchases, retail sales gas to end users and commodity risk management. Our wholesale and retail businesses are to some of electricity and natural 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 gas, uranium, lignite, coal, fuel, and transportation in our regional markets and other competitive markets in electricity, natural which we operate and upon prevailing retail electricity rates, which may be impacted by, among other things, actions of regulatory authorities. t t a ity, ancillary services, natural Market prices for power, capac gas, coal and fuel oil are unpredictable and may flucff tuate t 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 In many instances, energy from these sources are bid into the storage systems, has dropped substantially in recent years. all power relevant spot market at a price of zero or close to zero during certain times of the day, lowering the clearing price forff 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. t 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 gas ity of renewable generation across the used in our electric power generation business, and the cold further limited the availabila 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. in the central U.S., including Texas. This severe weather event substantially increased the demand for natural t t a The majoa rity of our facilities operate as "merchant" facff ilities without long-term power sales agreements. As a result, we ity and ancillary services into the wholesale energy spot market or into other wholesale and largely sell electric energy, capac al investments. Consequently, retail power markets on a short-term basis and are not guaranteed any rate of returnt there can be no assurance that we will be able to sell any or all of the electric energy, capac ity 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 ity and fuel. Given the volatility of commodity power prices, to the extent we are a prevailing market prices for power, capac unable to hedge or otherwise secure long-term power sales agreements forff the output of our power generation facilities, our revenues and profitability will be subjeu ct to volatility, and our financial condition, results of operations and cash flows could be materially adversely affect on our capita ed. a ff 21 We purchase natural gas, coal, fll uel volati , oyy ll financial conditiontt and cash flows. liii tyii ff ll r disrdd uption in these fuel markets may have an adverse impactm on our costs, revenues, resultsll oil, all nd nuclear fuel forff our generation faciliii tiii es, as nd higher than expectedtt fuel costs, of operations, t ff ff gas, coal, fuel We rely on natural oil, and nuclear fuel for the majoa rity of our power generation facilities. Delivery orr f these fuels to the facilities is dependent upon the continuing availability of such fuel ity of contractual counterparties as well as upon the infrastructure (including mines, rail lines, rail cars, barge facilities, roadways, riverways and gas pipelines) available and functioning to serve each generation facility. As a result, we have experienced, and remain t natural 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 i Certain of our nfrastructure. 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. s and financial viabila rr ff t t ff supplier or transporter. Fuel costs (including diesel, natural We have sold forward a substantial portion of our expected power sales in the next one to two 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 majea ure events or the default of a fuel gas, lignite, coal and nuclear electricity does not always change at the same rate as changes in fuel costs, and fuel) are volatile, and the wholesale price forff 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 majea ure, which may impact our ability to economically recover the value of the contract. In addition, we purchase and sell gas and other energy related commodities, and volatility in these markets may affect costs incurred in meeting our t natural obligations. Further, any changes in the costs of natural or transportation rates and changes in ff gas, coal, fuel 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 favorablea , 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 am gong hthe signifificant lloss expe irienced id in 2021 as a res lult of Wiinter Storm iUri. iprim yary d idrivers of hthe signi oil, nuclear fuel ff t t We also buy significant quantities of fuel tuate, 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: on a short-term or spot market basis. Prices for all of our fuels flucff ff ff • • • • • • • • • • • • • • • • t ff gas, coal and fuel and related enrichment and conversion services; energy commodities and general economic conditions, including impacts of inflation and the relative demand forff 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 oil; volatility in market heat rates; volatility in coal and rail transportation prices; volatility in nuclear fuel 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; ff changes in electricity and fuel 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 structuret 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 capaa outages or otherwise reduced output from our generation facilities or those of our competitors; usage resulting from conservation efforts, changes in technology or other factors; city or efficff t and liquidity; iency; ff t t 22 • • • • • • • a ity; 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 capac 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 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. disasters, wars, sabotage, t See "Economic downturns would likely have a material adverse effect ff on our businesses" for a discussion of potential risks arising from current U.S. and global economic and geopolitical conditions. We have retired generation unitsii which could result ill n s nnounced planned retireme ii ignigg fici nts of, and may be forced to retireii tt dditional ll esults. ant costs and have an adverse effect on our operating rn or idle all , add ii tt underperforming 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 transactions may na ot work as planned or hedgedd a tt counterpart changes in c e ii iett s may default on their oii tt bligations. ommodity ptt rices and market heat rates, as nd hedgingn t Our hedging activities do not fully protect us against the risks associated with changes in commodity prices, most notablya gas prices, because of the expected useful life of our generation assets and the size of our position relative electricity and natural to the duration of available markets forff 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 ion of four to five years. To the extent we have unhedged positions, fluctuating commodity prices and/or market heat a durat d rates can materially impact our results of operations, cash flows, liquidity and financial condition, either favora or unfavorably. blya a ff t To manage our financial exposure related to commodity price flucff tuations, we routinely enter into contracts to hedge gas, lignite, coal, diesel fuel, uranium portions of purchase and sale commitments, fuel requirements and inventories of natural and refined products, and other commodities, within establia shed 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 considerablea 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 tors could cause us to purchase disasters, consumer behavior, market constraints or other facff 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 facff tors, 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. t 23 Based on economic and other considerations, 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, ons 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. participation by financial instituti a tt To the extent we engage in hedging and risk management 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 , we could be forced to enter into alternative hedging arrangements or the counterparties to these arrangements fail to performff 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. ff We do not apply hedge accountingtt tt quarterly and annual financial results. ll to our commodityii derivativett transactions, tt which may cause increased volati liii tyii ll in our We engage in economic hedging activities to manage our exposure related to commodity price flucff commodities. These derivatives are accounted forff tuations through the use of financial and physical derivative contracts forff 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 If designated, those contracts are not recorded at fair value. GAAP also permits an entity to normal purchases and sales. 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 our retail sales contracts. As a result, our quarterly and annual finaff ncial results in accordance with GAAP are subject to significant fluctuat ions caused by changes in forward commodity prices. t Compem titiii on, changes in mii together withii ll cash flows. ower markets,s tt subsidized generation, may have a material adverse effect on our financial condition, resultsll of operations and arket structure, ae nd/or state or federal interfer ence in the wholesale and retail pii ll Our generation and competitive retail businesses rely on a competitive wholesale marketplace. The competitive wholesale marketplat ral 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. ce may be undermined by changes in market structuret and out-of-market subsidies provided by fede ff Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, other energy service companies and financial instituti ity 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 capac ity based on several competing technologies, as well as power generating facilities including hydroelectric power, synthetic fuels, solar, wind, wood, fueled by alternative or renewable energy sources, geothermal, waste heat and solid waste sources. Regulatory initiatives designed to enhance and/or subsidize renewabla e generation increases competition from these types of facilities and out-of-market subsidies to existing or new generation can undermine the competitive wholesale marketplat retirement of existing facilities, including those ce, which can lead to prematuret owned by us. ons in the sale of electric energy, capac a a tt 24 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, newer technology that could result in fewer emissions or more advantageous locations on the electric transmission system. Additionally, these competitors may be abla e to respond more quickly to new laws and regulations because of the newer technology utilized in their facilities or the additional resources derived fromff owning more efficff ient 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 fedff eral 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 incent, including through certain tax benefits, the construction and development of additional renewabla e resources as well as increases in energy efficiency investments. Subsidies (or increases thereto) to our competitors could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, our retail marketing efforts compete forff 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 fromff 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 If more customers switch to another supplier than the need to go to the market to cover the incremental supply obligation. anticipated, the load we must serve will be lower than anticipated and, if market prices of electricity have decreased, our operating results could suffer. of operations and financial condition could be material Our resultsll continue ii power prices and such additional generation capacityii t new generatiott n facff to construc resultsll tt tt ilities or expand or enhance exiee stinii g gn in a reduction in wholesale power prices. and adversely affected ifi energyr market participants vely low eneration faciliii tiii es despis teii ll relati lyll 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. If 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, dued to evolving expectations and sentiments of key stakeholders, government, and regulatory authorities regarding our operations and activities. ff Economic dowdd nturns would likel y hll ii ave a material tt adverse effect on our businesse ii s. t a ity and natural gas, which can flucff Our results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including Increased unemployment of lower prices for power, generation capac 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, could lead to, or accelerate or exacerbate the occurrence of, a significant economic downturn, leading to changes in consumer and counterparty behavior, higher costs of capita al, 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. tuate substantially. ff ff 25 ii Our liquidi timeii s of so the future, which could hll a that could negativtt ely all if our credit ratings particularly ffec ll tyii needs could be difficult t tt ll o s ignificant fluctuation in commodityii atisfyii ll articularly s of uo , pyy ll prices, and we may be unable t duringii timeii tt ncertaint tt n t ii y i ccess capitaltt o att hett ave a material adverse effect on us. We currently maintain non-investmtt ent grade credit rii t our abilitll y t ii o att were to be downgraded ccess capitaltt n tt in the future.ee on favorable t rr ertt ms ll tt or result in higher collat eral financialii markets or duringii on favorable terms or at all in ii atings requirements, ll Our businesses are capita al intensive. In general, we rely on access to finaff source of liquidity forff inabila ity to raise capita our ability to meet our obligations or sustain and grow our businesses and could increase capita requirements, any of which could have a material adverse effecff ncial markets and credit facilities as a significant our capital requirements and other obligations not satisfied by cash-on-hand or operating cash flows. The terms, could adversely impact our liquidity and al or to access credit facilities, particularly on favorablea al costs and collateral t on us. Our access to capita al and the cost and other terms of acquiring capita al are dependent upon, and could be adversely impacted by, various factors, including: • • • • • • • • • • • • • • • a ity to obtain or renew credit facff ilities on favff orable terms or at all; icable subsidiaries' credit ratings, or credit ratings of its issuances; al markets conditions, including changes in financial markets that reduce available general economic and capita liquidity or the abila 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 a downgrade of Vistra's or its appl our level of indebtedness and compliance with covenants in our debt agreements; a deterioration of the creditworthiness or bankruptcy of one or more lenders or counterparties under our credit facilities that affects the abila 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 effectuat the occurrence of changes in our businesses; disruptiu changes in or the operation of provisions of tax and regulatory laws. ons, constraints, or inefficiencies in the continued reliable operation of our generation facilities and ESSs; and ity of such lender(s) to make loans to us; value or financial or operating results; ing our risk management procedures; rr t companies that own and operate fossil fuel There are also increasing financial risks forff al have become more attentive to sustainable finaff onal lenders generation as instituti or other sources of capita ncing 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. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in climate change not to provide funding for companies in the nature, t al could have a material adverse effect on broader energy sector. Limitation on our access to, or increases in our cost of, capita us. by environmental activists and others concerned about a ff ff t In addition, we currently maintain non-investment grade credit ratings. As a result, we may not be able to access capital e as companies that maintain investment-grade credit ratings or we may be unable In addition, due to our non-investment grade credit ratings, on terms (financial or otherwise) as favorabl to access capita counterparties request collateral support (including cash or letters of credit) in order to enter into certain transactions with us. al at all at times when the credit markets tighten. ff 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. 26 Our indebtedness and the phaseout of LIBOR, oR r thett tt affect our abilitll y i ii ii eres increased int tt tt distribu orff ll e f ii availabl tt future to raise additional tt o r t oii ur abilitll y t t rates and limi ee replac capitaltt eact to changesn tion. hett n t tt ii ement of LIBOR withii to fund our operations. It could also expose us to t in the economy,m or our industry,r as well as impactm tt nce rate, could all hett dversely risk of our cash a difdd ferff ent refereff As of December 31, 2021, we had approximately $10.7 billion of total indebtedness and approximately $9.4 billion of indebtedness net of cash. Our debt could have negative consequences forff our financial condition including: • • • • • • • • • ff purchases which require credit support; ity to general economic and industry conditions; increasing our vulnerabila 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 limiting our ability to fund operations or future acquisitions; restricting our ability to make distributions or pay dividends with respect to our capita subsidiaries to make distributions to us, in light of restricted payment and other finaff facilities and other finaff 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 rates of interest; Vistra Operations Credit Facilities, are at variablea limiting our ability to obtain additional financing for working capita expenditures, 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. debt service requirements, acquisitions and general corporate or other purposes; and al stock and the ability of our ncial covenants in our credit including collateral postings, capital ncing agreements; al t al for these or other reasons. Furthermore, we may be unable to We may not be successful in obtaining additional capita the expiration or termination thereof. Our terms or at all upon refinance or replace our existing indebtedness on favorablea failure to obtain additional capita al 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. u 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 swapsa . 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 y than in the past or cease to exist. In anticipation of LIBOR ceasing to exist phaseout could cause LIBOR to perform differentl for affected tenors, we have amended certain of our agreements with LIBOR as the referenced rate to include an alternative benchmark rate or suggested fallback language. Additionally, in light of what we believe to be faff vorabla e relationships with lending and financial counterparties, we expect to seek necessary amendments to our remaining debt instruments and other agreements which utilize LIBOR as the referenced rate in the normal course. 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 appli New York legislation would apply to such contracts and would provide a replacement rate forff inclusion in such contracts. cablea a ff 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 forff m. lback language. Accordingly, Any new contracts would need to reference an alternative benchmark rate or include suggested falff rate debt, which could have an adverse impact on extensions we could be exposed to increased costs with respect to our variablea of our credit and/or we might not be fully hedged on the variable rate exposure on our swapped indebtedness. Any such a t on us. increased costs or exposure could increase our cost of capita al and have a material adverse effecff 27 The agrea contain r ii operations, and any failure to comply wll nd instruments governingii tt ions ii s and limi tat ements att iontt tt estrict tt ith t tt hes ii tt that could affect our abilitll y t our debt, i tt ncii ludingii tt tions could hll the Vistra ii pero o o Operations Credit Faciliii tiii es and indentures, of ii or liquidi nd resultsll , ayy tyii ate our business, ave a material adverse effect on us. ii e restrictt The agreements and instruments governing our debt, including the Vistra Operations Credit Facilities and indentures, or react to, contain restrictions that could adversely affect us by limiting our ability to operate our businesses and plan for, market conditions or to meet our capita al 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 faiff l 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 payablea . 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 applicablea 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 effecff t on us. ff Certain of our obligati to provideii i such security, it may ra ons are requiredii tt estrict to be secured by letters our abilityii of credit oii ii to conduct our business, tt r cash, which increase our costs. If wII which could have a material tt e are unablell adverse effect on us. r 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 currentl y use margin deposits, prepayments 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 differen ce 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 capita al 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. ff ff We may not be able to completell into ott ur business, or effectivtt ely i unantictt xx expense ipatedtt future acquisitions on favorabl ermtt ll e t dentify and invest in value-creatingtt e integrate s, assets or projects, which could r .yy or delay our growth strategy s or at all, sll uccessfullyll businesse ii tt future acquisitions ll nii esult i s and losses or otherwise hinder ff ll ii ll terms. Our ability t 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 o continue to implement this component of our opportunities and consummate acquisitions on favorablea growth strategy will be limited by our ability to identify appropriate acquisition or joint venturet candidates and our financial resources, including available cash and access to capita 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 fromff 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 significff ant financial resources If the Company is unable to identify and that would otherwise be available for the execution of our business strategy. consummate futff uret acquisitions, it may impede the Company's ability to execute its growth strategy. al. t 28 Our abilitll y t renewablesll chieve thett o att ll developme expected growth of our Vistrii tt ubstanti is subject to stt a ZerZZ o portfolio, altt ali capita requirements and other significant uncertaitt nti of our solar generation, ESS,SS es. consistingii nt projects,tt tt ii ll and other ff a investments in renewablea We have a substantial capita al allocation plan intended forff assets, emerging technologies and related projects. Notably, assets, including solar development projects and ESSs. As part of our business strategy, we plan to continually assess potential strategic acquisitions or investments in renewablea 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 ity of renewable assets generally, which may vary depending on availability of projects and financing, as well as public viabila policy, financial and tax mechanisms implemented at the state and fede ral 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 renewabla e 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 forff 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 forff 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 forff 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 recoverablea ; 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. ff Circums i tances associatedtt withii potentialii divestitures could all dversely affect our results of operations tt ii and financ ial conditiii on. In evaluating our business and the strategic fitff of our various assets, we may determine to sell one or more of such assets. ty in finding a buyer willing to purchase the asset at an In addition, a prospective buyer may have diffiff culty Despite a decision to divest an asset, we may encounter difficul acceptable price and on acceptablea obtaining financing. Divestitures terms and in a timely manner. could involve additional risks, including: ff t diffiff culties 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. t We may not be successful in managing these or any other significant risks that we may encounter in divesting any asset, which could adversely affecff t our results of operations and financial condition. 29 If our goodwillii , ill nt tt earninrr gs.n ii angibl e all ssets, or long-livll ed assets become impaire m d, we may be required to record a significant charger to 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 forff 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 . 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. value of the asset may not be recoverablea rr We performff ed our annual assessment of goodwill and non-amortizing intangibles in the fourth quarter of 2021 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 an ownership cii attribute tt tt s and our federal net operati o hange as definedii of our common stock, or sales or dispositiii ons of our common stock by stockhokk tt Revenue Code (IRC) §382 could further ur abilitll y t ii limi ldersdd o utt t oii tt , ts hat se certaintt result i ll nii tax tt tt in Internal ii losses to offset our future taxable i ngii .ee ll ncome ff 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 foll owing 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 its merger with Dynegy; however, Vistra's use of such attributes is limited outside our control. Vistra acquired NOLs fromff 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 a provided under IRC §382 NOLs existing at that time would be subject to additional annual limitations based upon a formul 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 liabia lities and on our obligations under the TRA.RR ff Tax legislat iontt e increased taxesaa initiii ati ii or fees, could have a material ves or challenges tt ll to our tax positions, or potential future legise adverse effect on our financial condition, tt on of new or lation or the impositi ff resultsll of operations and cash flows. m 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, introduced significant changes to current U.S. federal tax law. 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 assumptim ons around U.S. tax reform may evolve in future periods as further administrative guidance and regulations are issued, which may materially affecff tive tax rate or tax payments. t our effecff 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. Additionally, U.S. federal income tax reform and changes in other tax laws could adversely affect us. For example, President Biden has set forth several tax proposals that would, if enacted into law, make significant changes to U.S. tax laws. Such proposals include, but are not limited to (i) an increase in the U.S. corporate income tax rate and (ii) implementation of a 15% minimum tax on a corporation’s worldwide book income. Congress could consider some or all of these proposals in connection with tax reform to be undertaken by the Biden administration. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. 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. 30 We are required to pay the holders of TRA Rightgg s ftt orff ii certaitt n t axtt i benefite s,tt which amounts could be substanti al. tt On the Effective Date, we entered into the TRA wRR ith American Stock Transfer & Trust Company, LLC, as the transfer agent. Pursuant to the TRARR , we issued beneficial interests in the rights to receive payments under the TRA (RR 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 $395 million as of December 31, 2021 related to these future payment obligations (see Note 8 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 cRR ould be materially different than this estimate. ff ttributablea The TRA gRR enerally provides forff ights of 85% of the amount of cash savings, if the payment by us to the holders of TRA RRR lly realize as a result of our use of (a) the tax any, in U.S. federal, state and local income tax that we and our subsidiaries actuat basis step up au 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 plus interest (c) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA,RR ill vary r accruing tors, including the amount and timing of the taxable income we generate in the future and the depending upon a number of facff ng imputed interest. tax rate then applicablea , our use of loss carryovers and the portion of our payments under the TRA cRR tax return. The amount and timing of any payments under the TRA wRR from the due date of the applicablea t onstituti 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,RR recipients of the payments under the TRA wRR ill 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 tRR hat are greater than its actual cash tax savings. Any amount of excess payment can be used to reduce future ayments, but cannot be immediately recouped, which could adversely affect our liquidity. TRA pRR ff s Because Vistra is a holding company with no operations of its own, its abia lity to make payments under the TRA iRR 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 bRR ecause 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. ii ermi nation tt We may be required to make an early t ll payment to the holders of TRA Righi ts under thett TRA.RR The TRA pRR rovides that, in the event that Vistra breaches any of its material obligations under the TRARR , or upon certain of business combination or certain other changes of control, the transfer agent under the ay treat such event as an early termination of the TRARR , in which case Vistra would be required to make an immediate ights equal to the present value (at a discount rate equal to LIBOR plus 100 basis points) u mergers, asset sales, or other forms TRA mRR payment to the holders of the TRA RRR ff of the anticipated future ff tax benefits based on certain valuation assumptim ons. u As a result, upon any such breach or change of control, we could be required to make a lump sum payment under the TRARR 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 liabia lity for payments made under the TRA sRR et forth in our financial statements, which could have a substantial negative impact on our liquidity. 31 Regulatory and Legislative Risks ii Our busines may in the futff ure adversely impactm ses are subject to ongoing cn omplem x gee ii overnmentaltt and legisl ati ll e ii financ y,tt i ses, resultsll of operations, liqui dit regulations tt i on that have adversely impactm tt ed, s.w and cash flowff ial conditiontt , ott ur busines and r gas, carbon Our businesses operate in changing market environments influenced by various state and federal legislative and regulatory ing of the energy industry, including competition in power generation and sale of electricity, initiatives regarding the restructurt energy certificates, and other commodities. Although we attempt to comply with t natural 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 cause the Company may adversely impact our businesses, results of operations, liquidity, financial condition and cash flows. offsets and renewablea Our businesses are subject to numerous state and federal laws (including, but not limited to, PURA,RR 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 Reformff 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 and design, operation of nuclear generation facilities, construction and operation of other not limited to, market structuret generation facilities, development, operation and reclamation of recovery of costs and investments, lignite mines, decommissioning costs, market behavior rules, present or prospective wholesale and retail competition, administrative pricing ity standards and mechanisms (and adjustments thereto), environmental matters. We, along with other market participants, are subject to electricity pricing constraints and market s and regulations. Additionally, Ambit’s direct selling business (i) could be found behavior and other competition-related ruler by federal, state or foreff icable 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 fede ral 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. rates for wholesale sales of electricity, mandatory reliabila ign regulators not to be in compliance with appl a ff ff 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 and may receive additional inquiries. 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, chain including generation, transmission, additional requirements for winterization of various facets of the electricity supply 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 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 ngs of administrative proceedings involving market participants may result lead to adverse determinations or other findi 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. We are continuing to monitor and evaluate the impacts of this developing situation but at this time we cannot estimate the likelihood or impacts of any legislative or regulatory changes or actions (including enforcement actions that may be brought against various market participants) that may occur as a result of the event on our business, financial condition, results of operations, or cash flows. u u ff 32 generation. For example, changes to, or development of, legislation that requires the use of clean renewablea Finally, the regulatory environment has undergone significant changes in the last several years due to state and federal the addition of large amounts of new policies affecting wholesale and retail competition and the creation of incentives forff and renewablea sources or mandate the implementation of energy conservation programs that require the implementation of new ff alternate fuel technologies, could increase our capita al 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 crr ompanies ilities. Other proposals to re-regulate the retail energy industry may be made, and to construct or acquire generating facff gas deregulation or restructuring process may be delayed, legislative or other actions affecting electricity and natural 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. t that These changes are ongoing, and we cannot predict the future design of the wholesale power markets or the ultimate effecff the changing regulatory environment will have on our business. t We are requiredii tt to obtain, and to complym with,tt rr governmen rr t permit s att nd 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 shment of conditions that make the project or activity forff which the permit or license was sought sometimes result in the establia to denial, revocation or unprofitable or otherwise unattractive. 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 l aws and regulations or permit conditions, (c) local community, political or other opposition and (d) executive, legislative or regulatory action. In addition, such permits or licenses may be subject t Our inabila ity 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 appli laws In addition to the possible imposition of fines in the case of any such violations, we may be required to and regulations. undertake significant capita al investments and obtain additional operating permits or licenses, which could have a material adverse effecff t on us. cablea a Our cost of co ii omplim ance withii existingii and new environmii ental laws could hll ave 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 liabia lities and fines. Existing environmental regulations could be revised or reinterpreted, new laws and regulations could be adopted or become applicablea 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, all of which could result in significant additional costs beyond those currently contemplated to comply with existing requirements. Any of the foreff going could have a material adverse effect on us. ff The EPA has recently finaff lized 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 t our existing generation facilities or our ability to cost-effectively develop additional regulatory actions that may adversely affecff 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 rulerr and any , and actions under the Regional Haze program, could require us to install proposed or future actions to replace the ACE ruler significant additional control equipment, resulting in potentially material costs of compliance forff our generation units, including capita al expenditures, higher operating and fuel costs and potential production curtailments. These costs could have a material adverse effect on us. 33 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 approva l 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. a 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 liabia lities. 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 effecff t on us. We could bll climll are subject to l e material tt ate change that could r awll suiw tsii equireii for allell gede tt ll lyll and adversely affected ifi new federal or state legislati ll on or regulati ll efforts t tt tt hat damage to persons or property resultill ngii exceed or are more expensive than our currently planned initiati from greenhouse gas emissi ii ons. ons are adopted to att ii ddress global ves or ifi we a de), a tax on carbon or GHG emissions, There is attention and interest nationally and internationally about global climate change and how GHG emissions, such as CO2, 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 the allowed to trade unused emission allowances (cap-and-tra development of low-carbon technology and federal renewabla e portfolio standards. In July 2019, the EPA finalized the ACE rulerr that developed emissions guidelines that states must use when developing plans to regulate GHG emissions from existing coal- was vacated by the D.C. Circuit Court and remanded to the EPA fueled electric generating units. In January 2021, the ACE rulerr for further consideration in accordance with the court’s ruling. The D.C. Circuit’s decision has been appea led to the U.S. February 2022. The EPA may develop a more stringent and more Supreme Court and oral argument is scheduled forff in its remand proceeding and has been directed by the Biden Administration to encompassing rule to replace the ACE ruler review this rule and others promulgated by the EPA during the Trump Administration. Prior to the vacaturt and remand, states where we operate coal plants (Texas, Illinois and Ohio) had begun the development of their state plans to comply with the now- in recent years asserting damage claims related ral court cases have been filedff vacated ACE ruler to GHG emissions, and the results in those proceedings could establia sh 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. . In addition, a number of fede incentives forff a ff 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 ution-free electricity sector by 2035. The Company's plan to transition to clean power generation Force to achieve a carbon-poll sources and reduce its GHG emissions may not be completed in this timeframe and we may not otherwise achieve our ff 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 fede ral and/or state regulations to reduce future carbon emissions. r ff ff ii Luminant's mining ii operations are subject to Rtt CT oversight. i 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 rulerr s 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. 34 Luminant's l ' are reclaimll e mtt igll nitgg ed over the next several years.rr ining reclamat iontt ll activtt ity wtt ill rll equire signigg fica i nt resources as exiee sti ii ngii and retireii d mining operations 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 $265 million (on a nominal basis) to achieve its reclamation objectives. Litiii gati i i liabil e on, legal proceedings, rs itll iett s and reputational tt egulatll orytt damage that could hll i investigati ave a materi tt ali adverse effect on us. ons or other adminis ii trativtt e proceedings could expose us to s tt ignificant We are involved in the ordinary course of business in a number of lawsuits involving, among other matters, employment, injuries and damages. We evaluate litigation claims and legal commercial, and environmental issues, and other claims forff proceedings to assess the likelihood of unfavorablea 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 fromff 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 filff ed 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 effecff t on us. ii Our retail bii usinesse statett profitabiliii tyii of our business. hich we operate, ae s in wii ii s, which each have REP cEE re subject to ctt ertificaff hangingii tions that are subject to r state rules and regulati eview of the public utilityii tt ons that could have a material commissions in the on the impactm tt ll t 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 n, including financial requirements, can affect the competitiveness of our retail businesses. Any removal or REP certificatio revocation of a REP certification would mean that we would no longer be allowed to provide electricity service to retail customers in the applicablea 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 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. rr ff 35 Operational Risks power supply costs and demand for power have and could in the future adversely affect thett leii VolVV ati ll of our retail bii usinesses. e financial performanc r Although we are the primary provider of our retail businesses' wholesale electricity supply requirements, our retail businesses purchase a portion of their supply requirements fromff 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 refleff cted in the rates charged to customers due to, among other facff tors: u • • • • • • supply procurement contracts used and the timing of entering into related contracts; varying rr subsequent changes in the overall price of natural daily, monthly or seasonal fluctuations in the price of naturat 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. l gas relative to the 12-month forwa gas; ff t rd prices; The retail businesses' earnings and cash flows could also be adversely affected in any period in which their customers' tors, transmission and distribution outages, demand-side management programs, competition and economic actual usage of electricity significantly varies from the forecasted usage, which could occur due to, among other facff weather events, conditions, such as Winter Storm Uri in February 2021. ons are subject to significff ant competm ittt iontt perati Our retail oii o ii nd the inabi customers arr t new customers. tt to attrac liii tyii from other REPsRR , ws hich could r ll ii esult i ll ll n a l oss gn of existinii 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 favora 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 fromff 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. blya ff In addition to competition from the incumbent REP, we may face competition fromff 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. 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 profitablea for us to competm e in these markets. 36 Our retail oii elecll tricityii ii satisfac ations rely on the infrastruc pero mat rr nfor ii to, and to obtain i tt tion and could have a material iontt ii adverse effect on us. tt ture of lo ocll al utiliii tiii es or indepenee about, our customers. Any infrastruc dent trantt ture fail tt ii smissi on systeyy m opero ff ure could negatively impactm ators to provide r tt custome a The substantial majoa rity of our retail operations depend on transmission and distribution facilities owned and operated by ity is inadequate, our ability to unaffiliated utilities to deliver the electricity that we sell to our customers. If transmission capac o sales or buy more expensive wholesale electricity than is sell and deliver electricity may be hindered and we may have to forgff ity-constrained area or, with respect to capacity performance in PJM and performance incentives in ISO- available in the capac 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, failure that interrupts or impairs delivery of electricity to our customers could negatively impact customer any infrastructuret satisfaction with our service. Any of the foregoing could have a material adverse effect on us. a The operation of our businesse tt our infrastruc ll regulatory action, and disrupt business ture that breach cyber/data rr ii ii s is sii ubject to att dvanced persistenii t cybc er-based security threats and integrity e security measures could expose us to significff ant liabil itll iett s, reputati ii operations, which could have a material tt adverse effect on us. risk. Attacks okk tt n onal damage,e Numerous functions affecting the efficient operation of our businesses are dependent on the secure and reliablea storage, processing and communication of electronic data and the use of sophisticated computer hardware and software systems and much of our information technology infrastructuret 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. could disrupt normal Any such breach, disruption or similar event that impairs our information technology infrastructuret 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 effecff t on us. t t As part of the continuing development of new and modified reliabila Critical Infrastructure Protection reliabila assets." Under the Energy Policy Act of 2005, the FERC can impose penalties (up tu failure to comply with mandatory electric reliabila disruptions from cyber/data and physical security breaches. ity standards, the FERC has approved changes to its ity standards and has established standards for assets identified as "critical cyber o $1 million per day, per violation) for ity standards, including standards to protect the power system against potential 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 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. 37 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 finaff ncial impact, we recognize the growing threat within the general marketplat ce and our industry, and there is no assurance that we will be able to prevent any such If a material breach of our information technology systems were to occur, the critical operational impacts in the future. capabi lities and reputation of our business may be adversely affected, customer confidence may be diminished, and our a 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 our generation, commercial or retail operations, loss of customers, or disruption of critical operational capabi 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. al and operating costs to We cannot provide any assurance that such events implement increased security for our information technology infrastructure. and impacts will not be material in the future, and our efforts to deter, identify and mitigate future breaches may require additional significant capia tal and may not be successful. In addition, we may experience increased capita lities to support u a ff t t We may suffer material arisingii tt from the ownership aii losses, costs and liabil nd operationtt i CC of the Comanch e PeakPP .yy nuclear generation faciliii tyii itll iett s due to operation risks, regulatorytt risks, as nd the risk ofo nuclear accidents 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: • • • • • • • • • • t , cybersecurity, insider threat, unscheduled outages or unexpected costs due to equipment, mechanical, structural third-party compromise or other problems; inadequacy or lapses in maintenance protocols; the impairment of reactor operation and safety systems dued the costs of, and liabilities relating to, storage, handling, treatment, transport, release, use and disposal of radioactive materials; the costs of procuring nuclear fuel; the costs of storing and maintaining spent nuclear fuel terrorist or cybersecurity attacks and the cost to protect against any such attack; the impact of a naturat 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. at our on-site dry cask storage facility; to human error or force majea ure; l disaster; ff 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 folff lowing are among the more significant related risks: • • Operational Riskii — Operations at any generation facility could degrade to the point where the facility would have to If such degradations were to occur at the Comanche Peak Facility, the process of identifying and be shut down. the facility to operation could require significant time and correcting the causes of the operational downgrade to returnt 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. Regulat 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 capita al expenditures or result in increased operating or decommissioning costs. ory Riskii — The NRC may modify, suspend or revoke licenses and impose civil penalties forff e 38 • Nuclear Accidendd t 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 mainten involvell ii ii ant risks significi ance of power generation facff ilities and relatedtt mining ii that could adversely affect our resultsll of operations, liquidi i operations are capitaltt tyii and financial condition. tt intensive and t a al to maintain the facff The operation and maintenance of power generation facilities and related mining operations involve many risks, , start-up risks, breakdown or failure of facilities, equipment or processes, operator error, lack of including, as applicablea ilities, the dependence on a specific fuel source, the inability to transport our product to our sufficient capita ity or the impact of unusual or adverse weather customers in an efficient manner due to the lack of transmission capac events, or terrorist attacks, as well as the risk of performance below expected levels of output, conditions or other natural efficiency or reliabila ity, 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 capita al expenditures to operate at peak al expenditures arises from (a) increased starting and ity. The risk of increased maintenance and capita efficiency or reliabila 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 disasters, wars, terrorist or cyber/data security acts, including nation-state attacks or organized facilities dued 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. to storms, natural t t al expenditures that will be required dued We cannot be certain of the level of capita to changing environmental and safetyt laws and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected disasters or terrorist or cyber/data security attacks). The unexpected events (such as environmental requirement of large capita al 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 capita impacts, natural al expenditures. t t 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 If we do not have adequate procure replacement power at spot market prices in order to fulfill contractual commitments. 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 al expenditures and costs, and generate us. Further, our inabila 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 fromff vendors and obligate contractors to meet certain performanc e 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. ity to operate our generation facilities efficiently, manage capita ff t 39 Operation of power generation faciliii tiii es involvell have a matertt these risks and hazards. Our employm due to the nature of our operations. ees, contractors, tt ial adverse effect on our revenues and resultsll of operations, and we may not have adequate insurance to ctt s significant risks and hazards customary to the power induii could over rs and the general public may be exposed to a risk of injury tt stry tr hat tt custome Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of equipment and delivering electricity to transmission and distribution systems. 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, collapse, machinery failure and other dangerous incidents t 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. In addition to natural fire, structural a t ff 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 dt amage 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 sufficien t 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 A successful claim forff 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. ff We may be material tt ii requireme e legal to CCR.CC relatingtt lyll and adversely affected by ob i bligati nts that govern the operations, assessments, ss ons to complym torage, ce federadd withii losure, ce l and state regue orrectivtt e action, tt , as nd other lations, ls aws tt disposal and monitoring ll As a result of electricity produced forff decades at coal-fueled power plants in Illinois, Texas and Ohio, we manage large amounts of CCR material in surface impoundments, all in compliance with applicable regulatory requirements. In addition to the federal requirements under the CCR rulrr e, CCR surfaceff 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. t 40 The EPA has been directed by the Biden Administration to review a number of environmental ruler s adopted by the EPA during the Trump Administration, including Coal Combustion Residuals (CCR) rule, the Emissions Limitation Guidelines (ELG) rule, the Affordable Clean Energy (ACE) rule and the PM and Ozone National Ambient Air Quality Standards (NAAQS) rules. All of these rules may significantly and adversely impact our existing coal fleff et and may lead to accelerated plant closure timefraff mes. In addition, the expected revisions to the ACE rulerr 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 requirements imposed by the EPA or state agencies. There is no assurance that our current assumptim ons for closure activities will be accepted by EPA. If ponds must be closed sooner than anticipated, plant closures timeframes may be accelerated. The availabil itll y att ll nd cost of eo missi ii on allowances could adversely impactm our costs of operations. We are required to maintain, through either allocations or purchases, sufficient emission allowances for SO2, CO2 and NOX 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 force 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 forff purchase, but only at significantly higher prices, the purchase of such allowances could materially increase our costs of operations in the affected markets. d to purchase such allowances on the open market, which could be costly. ff We may be materially all nd adversely affected by tb hett effects ott f eo xtree eme weather tt conditions and seasonalitll y.tt We may be materially affecff ted by weather conditions and our businesses may fluctuat e 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 disasters, which could stress t cold or hot temperatures, ity, limit our ability to procure adequate fuel supply, or result in outages, damage or our generation facilities and grid reliabila destroy our assets and result in casualty l osses that are not ultimately offset by insurance proceeds, and could require increased capita or maintenance costs, including supply chain costs. hurricanes, floods, droughts, storms, fireff s, earthquakes or other natural al expenditures t t t t 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 availabila ity of generation and transmission ity, limiting our ability to source or deliver power where it is needed or limit our ability to source fuel for our plants, a capac including due to damage to rail or natural Additionally, extreme weather has resulted, and may in t 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 gas, diesel and coal, or facilities, (iii) a decrease in the availabila (iv) unpredictable curtailment of customer load by the applicablea 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. ity of, or increases in the cost of, fuel sources, including natural gas pipeline infrastructure. t t Additionally, climate change may produce changes in weather or other environmental conditions, including temperature In addition, the potential physical effects of and other climatic events, could disrupt our or precipitation levels, and thus may impact consumer demand for electricity. climate change, such as increased frequency and severity of storms, floods, operations and cause us to incur significant costs to prepare forff or respond to these effecff ts. ff Weather conditions, which cannot be reliablya 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. 41 The outbreak of COVID-19, matertt ial and adverserr effect on our business, or the future outbreak of any other highly infectious ial condition, and results ott tt pero ii financ f oo II ii tt ations. or contagious diseases, could have a The outbreak of the COVID-19 pandemic has adversely impacted economic activity and conditions worldwide, and we are responding to the outbreak by taking steps to mitigate the potential risks to us posed by its spread. We continue to examine the impacts of the pandemic on our workforce, liquidity, reliabila ity, cybersecurity, customers, suppliers, along with other macroeconomic conditions and cannot currently predict whether COVID-19 will have a material impact on our results of operations, financial condition, and cash flows. Additionally, global recovery and transition from COVID-19 could have a material impact on supply, business and commodity market funda mentals on a national and global scale. ff Because we are deemed a critical infrastructuret provider that provides a critical service to our customers, we must keep our employees who operate our businesses safe and minimize unnecessary risk of exposure. We have updated and implemented our company-wide pandemic plan to address specific aspects of the COVID-19 pandemic. This plan guides our emergency response, business continuity, and the precautionary measures we are taking on behalf of employees and the public. We will continue to monitor developments affecting both our workforce and our customers, and we will take additional precautions that we determine are necessary in order to mitigate the impacts. In particular, we have taken extra precautions for our employees who work in the field and for employees who continue to work in our facilities including requiring, for both employees and contractors, social distancing where possible and requiring the use of appropriate personal protective equipment in certain circumstances. We have implemented work-from-home policies and other safety measures where appropriate, testing at including, but not limited to, encouraging vaccinations and boosters, answering screening questions and temperaturet all of our locations for unvaccinated employees, contractors, and other essential visitors and closing our facilities to non- essential visitors. While our systems and operations remain vulnerable to cyber-attacks and other disruptions due in part to the fact that a portion of our workforce continues to work remotely, we have implemented physical and cyber-security measures to ensure that our systems remain funct ional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers. We will continue to review and modify our plans as conditions change. ff Measures to control the spread of COVID-19, including restrictions on travel, public gatherings, and certain business operations, have affected the demand for the products and services of many businesses in the areas in which we operate and disrupted supply chains around the world. The full scope and extent of the impacts of COVID-19 on our operations are unknown at this time. However, COVID-19 or another pandemic could have material and adverse effects on our results of operations, financial condition and cash flows due to, among other facff tors, a protracted slowdown of broad sectors of the economy, changes in demand or supply for commodities, 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), reduced d demand for electricity (particularly from commercial and industrial customers), increased late or uncollectible customer payments, negative impacts on the health of our workforce, 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 the inability of the Company's contractors, suppliers, and other business partners to fulfill their contractual obligations. Despite our efforts to manage these impacts to the Company, their ultimate impact also depends on factors beyond our knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effecff ts. To the extent COVID-19 adversely affects our business and financial results, it may also have the effect of hastening, heightening, or increasing the negative impacts of, many of the other risks described in this Risk Factors section. 42 Changes in technology,o our generationtt faciliii tiii es and may otherwise have a material tt adverse effect on us. increased electritt cityii conservation efforts, or energy sustainabi liii tyii tt efforts mtt ay reduce the value of 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, to remain competitive, and have resulted, and are expected to continue to and may require us to make significant expenditures 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 to technological changes, to offer services and products that meet customer demands and anticipate and successfully adapta 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 affecff ted. t t 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 significan t decrease in electricity demand as a result of such efforts ff 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 al expenditures if we are required to could have a material adverse effect on us. Furthermore, we may incur increased capita increase investment on energy in conservation measures. Additionally, 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. increased governmental and consumer focus ff We may potentiallyll energyr industrytt be affected by eb merging tn may over timtt overall including distributed generation and clean tectt hnology. ectt hnologie tt s that ll ll a e affec t change in capacity mtt arkets att nd the 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 ity of utility counterparties and could have significant impacts on wholesale technologies may also affect the financial viabila market prices, which could ultimately have a material adverse effect on our financial condition, results of operations and cash flows could be materially adversely affecff ted. tt The loss of the services of our key management and personnel could adversely affect our abilitll y t ii businesse s. tt o s uccessfullyll operate our 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. Difficul ties 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. ff 43 We could be matertt iallyll and adversely impactm edtt by strikes or work stoppages by our unionized emplm oye ll es. t gas- and nuclear-fueled generation operation, as well as some battery orr As of December 31, 2021, we had approximately 1,400 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 perations, expire on various dates between March 2022 and May 2024, 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 strife or or we could experience reduced power generation or disruption, we would be responsible for procuring replacement labor 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 favora terms or at all could have a material adverse effecff a of labor t on us. blea a a ff ff Risks Related to Our Structure and Ownership of our Common Stock a is a h Vistrii ii ii future liabil oldingii itll iett s of io tsii subsidiaries. companym and its att tt bilitll y t o ott ff btain f unds ii from its stt ubsidiaries is structurallyll subordinate ii ii d tott existing and and Vistra is a holding company that does not conduct any business operations of its own. As a result, Vistra's cash flows 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 fund s to satisfy its obligations. Any decision by a subsidiary to provide Vistra with funds to satisfy its obligations, ff including those under the TRARR , 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 tors. The deterioration of income from, or other available assets of, any such restrictions, applicable law and other facff subsidiary for any reason could limit or impair its abia lity to pay dividends or make other distributions to Vistra. ff tt expectati Evolvill ngii mattett rs, and erosion of stakeholder trust industry and could adversely affect our business, tt or confidence could influence actiott ns or decisions about our companym ii ons from stakeholders, including investors, on ESG issues, including climll ial resultsll or stocktt ff operations, fs inanc price. ate change and sustainabil itll ytt and our tt Companies across all industries are facing evolving expectations or increasing scrutiny from stakeholders related to their nd stakeholder relations remain primary focus areas, and changing approach to ESG matters. For Vistra, climate change, safety at 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 investment funds and others which are government agencies, increasingly focused on ESG practices. Certain finff ancial 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. investor advocacy groups, certain institutional investors, While we are strategically focused on successfully adaptia ng 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 timefraff me 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: • • • • • • • • ff ls; negative stakeholder sentiment toward us and our industry, including concerns over environmental or sustainability ral and state regulatory actions related thereto; matters and potential changes in fede loss of business or loss of market share, including to competitors who do not have any, or comparablea operations involving fossil fueff loss of ability to secure growth opportunit the inability to, or increased difficulties and costs of, obtaining services, materials, or insurance from third parties; reductd delays in project o legal action; l inability or limitations on ability to receive applicable government subsidies, or competitors with smaller or no fossi operations receiving subsidies forff which we are not eligible, or in larger amounts; ions in our credit ratings or increased costs of, or limited access to, capital; amounts, of execution; ies; ff t 44 • • • • • • increased regulatory oversight; loss of ability to obtain and maintain necessary approvals and permits fromff timely basis and on acceptable terms; impediments on our ability to acquire or renew rights-of-wa changing investor sentiment regarding investment in the power and utilities industry or our company; restricted access to and cost of capia tal; and loss of ability to hire and retain top talent. ff y or land rights on a timely basis and on acceptablea terms; governments and regulatory agencies on a We may not pay any dividends on our common stock in the future. 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. ll Holders of our preferre e d stock may ha ave interests att nd 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 fromff 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, 2021, 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 perpet equity interest in the Company and, unlike our indebtedness, will t ual 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 forff 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 liabia lities of the Company, the holders of Preferred Stock will be entitled to receive, pro rata and in preference to the holders of any other capia tal stock, an amount per share equal to $1,000 plus accrued and unpaid dividends thereon, if any. rr 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 of Designation) that may not adopt any amendment to our certificate of incorporation (including the applicablea would have a material adverse effect on the powers, preferences, duties, or special rights of such series of Preferredr 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 payablea 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). ff Certificates 45 ff In addition, holders of the Preferred Stock are entitled to receive, when, as, and if declared by our Board, semi-annual initial issuance date of the Preferred Stock and cash dividends on the Preferred Stock, which are cumulative from the applicablea payablea 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 forff 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 the Series B Preferred Stock from and including the initial issuance share of Series A Preferred Stock. The dividend rate forff 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 each Reset Period applicable Treasury rate, plus a spread of 6.93% per annum; provided that the applicablea 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 Treasury rate, plus a spread of 5.74% per Preferred Stock for each Reset Period will be adjusted based upon the applicablea annum; provided that the applicablea 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-appli the Preferred Stock will be increased by 5.00%. each Reset Period will not be lower than 1.26%. Treasury rate forff Treasury rate forff dividend rate forff cablea a Item 1B. UNRESOLVED STAFF COMMENTS None. Item 2. PROPERTIES Luminant's asset fleff et consists of power generation and battery ESS units in six ISOs/RTOs, with the location, ISO/RTO, technology, primary fuel type, net capacity and ownership interest for each generation facility shown in the tablea below: Facility Ennis Forney Hays Lamar Midlothian Odessa Wise Martin Lake Oak Grove DeCordova Graham Lake Hubbard Morgan Creek Permian Basin Stryker Creek Trinidad Comanche Peak Upton 2 Location , TX Ennis, TX Forney, TX San Marcos, TX Paris, TX Midlothian, TX Odessa, TX Poolville, TX Tatumt Franklin, TX Granbury, TX Graham, TX Dallas, TX Colorado City, TX Monahans, TX Rusk, TX RR Trinidad, TX Glen Rose, TX Upton County, TX ISO/RTO ERCOT ERCOT ERCOT ERCOT ERCOT ERCOT ERCOT ERCOT ERCOT ERCOT ERCOT ERCOT ERCOT ERCOT ERCOT ERCOT ERCOT ERCOT Technology CCGT CCGT CCGT CCGT CCGT CCGT CCGT ST ST CT ST ST CT CT ST ST Nuclear rr Solar/Batter rr y Primary Fuel (a) Naturt al Gas Naturt al Gas Naturt al Gas Naturt al Gas Naturt al Gas Naturt al Gas Naturt al Gas Coal Coal Natural Gas Natural Gas Natural Gas Naturt al Gas Naturt al Gas Naturt al Gas Naturt al Gas Nuclear enewablea R Total Texas Segment Fayette Hanging Rock Masontown, PA Ironton, OH PJM PJM CCGT CCGT Naturat Naturat l Gas l Gas 46 Net Capacity (MW) (b) 366 1,912 1,047 1,076 1,596 1,054 787 2,250 1,600 260 630 921 390 325 685 244 2,300 180 17,623 726 1,430 Ownership Interest (c) 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% Facility well Kendall Liberty Ontelaunee Sayreville Washington Calumet Dicks Creek Miami Fort (CT) Pleasants Richland Stryker Bellingham Blackstone Casco Bay Lake Road Masspower Milford Independence Location Hopewell, VA Minooka, IL Eddystone, PA Reading, PA Sayreville, NJ Beverly, OH Chicago, IL Monroe, OH North Bend, OH Saint Marys, rr WV Defiance, OH Stryker, Bellingham, MA Blackstone, MA Veazie, ME Dayville, CT Indian Orchard, MA Milford, CT Oswego, NY OH rr Total East Segmen t Moss Landing 1 & 2 Moss Landing Oakland Moss Landing, CA Moss Landing, CA Oakland, CA Total West Segmen t Coleto Creek Baldwin Edwards Newton Joppa/EEI Joppa CT 1-3 Joppa CT 4-5 Kincaid Miami Fort 7 & 8 Zimmer Goliad, TX Baldwin, IL Bartonville, IL Newton, IL Joppa, IL Joppa, IL Joppa, IL Kincaid, IL North Bend, OH Moscow, OH ISO/RTO PJM PJM PJM PJM PJM PJM PJM PJM PJM PJM PJM PJM ISO-NE ISO-NE ISO-NE ISO-NE ISO-NE ISO-NE NYISO CAISO CAISO CAISO ERCOT MISO MISO MISO MISO MISO MISO PJM PJM PJM Technology CCGT CCGT CCGT CCGT CCGT CCGT CT CT CT CT CT CT CCGT CCGT CCGT CCGT CCGT CCGT CCGT CCGT Battery CT ST ST ST ST ST CT CT ST ST ST Primary Fuel (a) Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Fuel Oil Natural Gas Natural Gas Fuel Oil Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Natural Gas Renewable Fuel Oil Coal Coal Coal Coal Coal t Natural Natural t Coal Coal Coal Gas Gas Total Sunset Segment Total capac y it a Net Capacity (MW) (b) 370 1,288 607 600 349 711 380 155 77 388 423 16 566 544 543 827 281 600 1,212 2,093 1,020 400 110 ,530 650 1,185 585 615 802 165 56 1,108 1,020 1,300 7,486 8,732 1 1 3 Ownership Interest (c) 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 80% 100% 80% 100% 100% 100% ___________ (a) Renewable represents generation assets fueled by renewablea have significant fuel costs. sources including energy storage and solar, which do not (b) Unit capabi a lities are based on winter capac a ity and are reflected at our net ownership interest. We have not included units that have been retired or are out of operation. (c) Ownership interest of 100% indicates feeff simple ownership of the facility. Ownership of less than 100% indicates the share of ownership in the facility held by the Company. See Note 3 to the Financial Statements for discussion of our solar and battery energy storage projects currently under development and Note 4 to the Financial Statements for discussion of our retirement of certain generation facilities. 47 Our wholesale commodity risk management group also procures renewablea generation in ERCOT to support our electricity sales to wholesale and retail customers to satisfy the increasing demand for renewablea resources fromff such customers. As of December 31, 2021, Vistra had long-term agreements to procure renewabla e energy approximately 915 MW of renewable generation. These renewable generation sources deliver electricity when credits fromff 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-dispatchablea intermediate/load-following resources to respond to changes in their output. and create the need forff energy credits fromff renewablea yll Fuel Suppl SS 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 1,150 MW. Comanche Peak Unit 1 and Unit 2 went into commercial operation in 1990 and 1993, respectively, and are generally operated at full 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 the same year, which occurred in 2020. While one unit is refueling cycle results in the refueling of both units during undergoing a refueling outage, the remaining unit is intended to operate at full capaa city. 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 facff tor of 96%, 97% and 96% in 2021, 2020 and 2019, respectively. ing (nuclear fuel ity. Refuel a capac d ff ff ff We have contracts in place for all of our 2022 and 2023 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 futff ure. ff t Natural Gas — Our natural t MW and 13 peaking generation facilities totaling 5,022 MW. We satisfy off combination of spot market and near-term purchase contracts. Additionally, we have near-term natural agreements in place to ensure reliable fueff gas-fueled generation fleff et is comprised of 23 CCGT generating facilities totaling 19,512 ilities through a gas transportation ur fuel requirements at these facff l supply. t e — Our coal/lignite-fueled generation fleet is comprised of 10 generation facilities totaling 11,115 MW of Coal/Li i gnit ll generation capac the spring or fall off-peak demand periods. We d ity. Maintenance outages at these units are scheduled during a 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 13 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 Safetyff and Health Act of 1977, as amended (the Mine Act), as well as other fede ral 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. ff 48 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 22, 2022, there were 448,803,986 shares of common stock issued and outstanding and 620 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 2022, our Board declared a quarterly dividend of $0.17 per share that will be paid in March 2022. 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, our results of operations, financial condition and liquidity, Delaware law and contractual limitations. For additional details, see Item 1A. Riskii Factors and Note 14 to the Financial Statements. Stock Performance Graph The perforff mance graph below compares Vistra's cumulative total returnt on common stock for the period from May 10, 2017 (the date we were listed on the NYSE) through December 31, 2021 with the cumulative total returns of the S&P 500 in each period Stock Index (S&P 500) and the S&P Utility Index (S&P Utilities). The graph below compares the returnt 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. t Comparison of Cumulative Total Return Vistra Corp. S&P 500 S&P Utilities $225 $200 $175 $150 $125 $100 $75 05/10/17 12/31/17 12/31/18 12/31/19 12/31/20 12/31/21 49 Share Repurc ee hase Program The following tablea 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, 2021. October 1 - October 31, 2021 November 1 - November 30, 2021 December 1 - December 31, 2021 For the quarter ended December 31, 2021 Total Number of Shares Purchased Average Price Paid per Share — $ 5,094,030 14,236,335 19,330,365 $ $ $ — 20.22 21.50 21.16 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) — $ 5,094,030 14,236,335 19,330,365 $ $ $ 2,000 1,897 1,591 1,591 In October 2021, we announced that the Board had authorized a new share repurchase program (Share Repurchase o $2.0 billion of our outstanding common stock may be repurchased. The Share Repurchase Program) under which up tu Program became effective on October 11, 2021. The Share Repurchase Program supersedes the $1.5 billion share repurchase program previously announced in September 2020, which had $1.325 billion of remaining authorization as of September 30, 2021. As an initial step in our broader capital allocation plan, we intend to use all of the net proceeds from our October 2021 Series A Preferred Stock offering to repurchase shares of our outstanding common stock. We expect to complete repurchases under the Share Repurchase Program by the end of 2022. 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 eral securities laws. The actual timing, number and value of with the Exchange Act or by other means in accordance with fedff shares repurchased under the Share Repurchase Program or otherwise will be determined at our discretion and will depend on a number of facff al allocation priorities, the market price of our stock, general market and economic conditions, applicablea legal requirements and complim ance with the terms of our debt agreements. tors, including our capita See Note 14 to the Financial Statements forff 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 OPERATIRR ONS ff tt Act of 1o The discussion below, as well as other portions of this aii nnual report on Form 10-K, contain forward-looking statements withitt n the meaning of Section 27A of the Securities Act, Section 21E of the Exchange Act and the Private SecSS urities Litigation 995. In addition, management may make forward-looking statements orally or in other writing, including, but Reforme rs and in not limited to, in press releases, quarterly earnings calls, executive presentations, in the annual report to stockholde eaders can usually identify t he SEC. RCC s “may,” hese forward-looking statements by the use of such words add other filff ings with t “anticipates,” “believes” or similar words. These statements “plans,” “projects,” “expects,”tt “will,” “should,”l “likelkk y,”ll those anticipate involve a number of risks akk uch forward- nd uncertainties. Actual results could materially diffeff r fromff looking statements. ForFF more discussion about risk factors that could cause or contribute to such diffeff rences, see Part I, Item iscussed herein. Forward-looking statements refleff ct the inforff mation only as of the date on 1A "Riskii Factors" and other risks dkk on to update any forward-looking statements to reflect ny obligati which they ae does update one or more forward-looking statements, no inferenc future events, devdd elopments, or other information. e should be drawn that additional updates will be made regarding that statement or any other forwff ard-looking statements. ThisTT discussion is intended to clarify and focus on our results of operations, certain changes in our financial position, liquidity,yy capital structure and business devdd elopments for the periods covered by the consolidated financial statements included under Part II, Item 8 of to hitt s aii nnual report on Form 10-K for the year ended December 31, 2021. This discussion should be read in conjunction with those consolidated financial statements and the related notes and is qualifii ed by reference to them. re made. The Company does not undertake akk ii If Vistra d by sb kk ff ff i i tt 50 The folff lowing discussion and analysis of our financial condition and results of operations for the years ended December 31, 2021, 2020 and 2019 should be read in conjunction with our consolidated financial statements and the notes to those statements. The discussion and analysis of our financial condition and results of operations for the year ended December 31, 2019 and for the year ended December 31, 2020 compared to the year ended December 31, 2019 are included in Item 7. Management's Discussion and Analysis of Financial Condition and Results in our 2020 Form 10-K and are incorporated herein by reference. ll All dollar amounts in the tablea s 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. t Operatingtt Segme e nts Vistra has six reportablea segments: (i) Retail, (ii) Texas, (iii) East (iv) West, (v) Sunset and (vi) Asset Closure. See Note 20 to the Financial Statements forff further information concerning our reportable business segments. Significi ant Activitiii es and Events and Itemtt s Influenc II ing Future Performance Winter Storm Ur riUU In February 2021, the U.S. experienced an unprecedented Winter Storm Uri, bringing extreme cold temperatures to the central U.S., including Texas. On February 12, 2021, the Governor of Texas declared a state of disaster forff all 254 counties in the State in response to the then-forecasted weather conditions. The declaration certified that severe winter weather posed an imminent threat dued heavy snow, and freezing rain statewide. On February 14, 2021, President Biden issued a fedff eral emergency declaration for all 254 Texas counties. zing temperatures, to prolonged freeff t t As part of its annual winter season preparations, our power plant teams executed a significant winter preparedness strategy, which included installing windbreaks and large radiant heaters to supplement existing freeze protection and insulation and performing preventative maintenance on freeze protection equipment such as the insulation and automatic circuitry designed to keep pipes at the power plants from freezing. In addition, in anticipation of Winter Storm Uri we took additional sufficiient water availil biabilili yty to run steps to prepare, including procuring ddi for ext dendedd p ieri dods fying hthat freeze protectiion icirc iuits were operatiionall. lonal ddemiine lrali dized water supplypply traililers to ensure iverifying addi iti dand ffi u This severe weather resulted in surging demand for power, gas supply shortages, operational challenges for generators, and a significant load shed event (i.e., involuntary outages to customers across the system for varying periods of time) that was ordered by ERCOT beginning on February 15, 2021 and continuing through February 18, 2021. Despite these challenges, we estimate that our fleet generated approximately 25 to 30% of the power on the grid during the height of the outages, as compared to our approximately 18% market share. The weather event resulted in a $2.2 billion negative impact on the Company's pre-tax earnings in the year ended December 31, 2021 (see Note 1 to the Financial Statements), after taking into account approximately $544 million in securitization proceeds Vistra expects to receive from ERCOT as further described below. The primary drivers of the loss were gas-fueled the need to procure power in ERCOT at market prices at or near the price cap due to lower output from our natural handling gas deliverability issues and our coal-fueled power plants driven by coal fuel power plants driven by natural challenges, high fuel costs, and high retail load costs. ff t t 51 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 In October 2021, the PUCT issued a debt obligation order approving ERCOT's $2.1 service costs during Winter Storm Uri. billion financing and the methodology for allocation of proceeds to the LSEs. In December 2021, ERCOT finalized the amount of allocations to the LSEs, and we expect to receive $544 million in proceeds from ERCOT in the second quarter of 2022. We concluded that the threshold for recognizing a receivable was met in December 2021 as the amounts to be received are e the $2.1 determinablea 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. and ERCOT was directed by its governing body, the PUCT, to take all actions required to effectuat ff t We continue to be subject to the outcome of potential litigation arising from this event (including any litigation that we may pursue or be a party to); or any corrective action taken by the State of Texas, ERCOT, the RCT, or the PUCT to resettle pricing across any portion of the supply chain that is currently being considered or may be considered by any such parties. The also continues to consider potential legislation, such as Senate Bill (SB) 1580, which was passed in May 2021. Texas legislaturet SB 1580 may impact the total amount of balances owed by electric cooperatives to the market. The potential impact of this legislation is uncertain as the final details will be specific to each electric cooperative. There have been several announced efforts by the state and federal governments and regulatory agencies to investigate and determine the causes of this event and its impact on consumers. We have received a civil investigative demand from the Attorney General of Texas as well as requests for information from ERCOT, NERC and other regulatory bodies related to this event and may receive additional inquiries. We are cooperating with these entities and have responded to these requests. Those efforts may result in changes in regulations that impact our industry including but not limited to additional requirements for chain including generation, transmission, and fuel supply; improvements winterization of various facets of the electricity supply in coordination among the various participants in the electricity and natural chains during any future event; potential revisions to the method or calculation of market compensation and incentives relating to the continued operation of assets that only run periodically, including during extreme weather events or other times of scarcity; and restrictions or limitations on the types of plans permitted to be offered to customers. We are continuing to monitor this situation as it develops. The full impact of litigation or any impacts of any legislative or regulatory changes or actions (including enforcement actions that may be brought against various market participants) that may occur as a result of the event could have a material impact on our business, financial condition, results of operations, or cash flows, but cannot be estimated at this time. See Note 13 to the Financial Statements for further discussion of these matters. u gas supply u t In response to the storm, Vistra committed to donate $5 million to assist Texas communities and individuals meet their most pressing needs, including support for food banks and food pantries, critical needs, bill payment assistance, and more. Vistra also assured residential customers across its retail brands that they would not see any near-term impact on their rates due to the winter weather event, though bills could increase due to high usage during the cold weather period in February 2021. Furthermore, Vistra has taken or intends to take various actions to improve its risk profile forff future weather-driven lities and to further a volatility events, including investing in improvements to furthe weatherize its ERCOT fleet for even colder temperatures ions; 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 capabil ities 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. r harden its coal fuel and longer durat handling capabi d a ff ff t Climate Change, Investments tt in Clean EneEE rgy and CO2 Reductions e ions — We are subjeu Environmental Regulat ct 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 rulrr e and the ELG rule. See "Item 1. Business – Environmental Regulations and Related Considerations," and "Item 1A. Risk Factors – Regulatory and Legislative Risks" and Note 13 to the Financial Statements. However, such rules and the regulatory environment are continuing to evolve and change, and we cannot predict the ultimate effect that such changes may have on our business. ff 52 Emissii ions Reductions — Vistra is targeting to achieve a 60% reduction in Scope 1 and Scope 2 CO2 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 ncial instruments to fund new or existing projects that support renewabla e energy and energy discussion of the Series B Preferred allows us to issue green finaff efficiency with alignment to our ESG initiatives. See Preferr Securities issued under our Green Finance Framework. ed Stock OffO eri ngs below forff ff ff Solar Generation and Energy Storage Projectstt — In January 2022, we announced that, subject to approva l by the CPUC, we would enter into a 15-year resource adequacy contract with PG&E to develop an additional 350 MW battery ESS at our Moss Landing Power Plant site. In September 2021, we announced the planned development, at a cost of approximately $550 million, of up to 300 MW of solar photovoltaic power generation facilities and up to 150 MW of battery ESS at retired or to-be- retired plant sites in Illinois, based on the passage of Illinois Senate Bill 2408, the Energy Transition Act. In September 2020, we announced the planned development, at a cost of approximately $850 million, of up to 668 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas. We will only invest in these growth projects if we are confident in the expected returns. See Note 3 to the Financial Statements forff a summary of our solar and battery energy storage projects. a CO2 Reductdd ions — 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 lity in Illinois no later than year-end 2027 due to economic challenges, including incremental expenditures that would be required to comply (see Note 13 to the Financial Statements), and in furtherance of our efforts to significantly with the CCR rulrr e and ELG ruler reduce our carbon footprint. In April 2021, we announced we would retire the Joppa generation facilities by September 1, 2022, and in July 2021, we announced we would retire the Zimmer coal generation facility by May 31, 2022. See Note 4 to the Financial Statements for a summary of these planned generation retirements. ff gas faci t Moss Landing Outages In September 2021, Moss Landing Phase I experienced an incident impacting a portion of the battery Err SS. A review found that only a small, single digit-percentage of batteries at the facility were impacted and that the root cause originated in systems separate from the battery srr the facility to service. Moss Landing Phase II was not affected by this incident. ystem. The facility will be offlff ine as we perform the work necessary to returnt In February 2022, Moss Landing Phase II experienced an incident impacting a portion of the Battery Err SS. An investigation is underway to determine the root cause of the incident. The facility will be offline as we perform the work the facility to service. Moss Landing Phase I was not affected by the incident, but the facility will remain necessary to returnt offline during the assessment stage of the Moss Landing Phase II incident. We do not expect these incidents to have a material impact on our results of operations. Mining Reclamation Award In October 2021, the Office of Surface Mining Reclamation and Enforcement (OSM) announced Luminant as a recipient of its 2021 Excellence in Surface Coal Mining Reclamation Award for the work done to reclaim and restore previously mined land at its Monticello-Winfield Mine. The award recognizes companies that achieve the most exemplary coal mine reclamation in the nation. Luminant has a long history of environmental stewardship, reclaiming land long before being required under federal or state law. II COVID-19 Pandemic With the global outbreak of the novel coronavirus (COVID-19) and the declaration of a pandemic by the World Health Organization on March 11, 2020, the U.S. government has deemed electricity generation, transmission and distribution as providing essential services during this global emergency. As a provider of critical infrastructure, "critical infrastructure" Vistra has an obligation to provide critically needed power to homes, businesses, hospitals and other customers. Vistra remains focused on protecting the health and well-being of its employees and the communities in which it operates while assuring the continuity of its business operations. t 53 We have updated and implemented our company-wide pandemic plan to address specific aspects of the COVID-19 pandemic to guide our emergency response, business continuity, and the precautionary measures we are taking on behalf of employees and the public. We will continue to monitor developments affecting both our workforce and our customers, and we easures that we determine are necessary in order to mitigate the have taken, and will continue to take, health and safety mt impacts. To date, as a result of these business continuity measures, the Company has not experienced material disruptions in our operations due to COVID-19. See Note 7 to the Financial Statements forff a summary of certain tax-related impacts of the CARES Act to the Company. The COVID-19 pandemic has presented potential new risks to the Company's business. Although there have been logistical and other challenges to date, there has been no material adverse impact on the Company's results of operations for the years ended December 31, 2021 and 2020. The situation surrounding COVID-19 remains fluid and the potential for a material impact on the Company's results of operations, financial condition and liquidity increases the longer the virus impacts the level of economic activity in the U.S. and globally. As a result, COVID-19 may have a range of impacts on the Company's operations, the full extent and scope of which are currently unknown. See Part I, Item 1A Riskii Factors — The outbreak of ave a material and adverse II COVID- effeff ct on our business, financial condition, and results of operations. 19, or the future outbreak of any other highly i tious or contagious diseases, could hl nfecff ll Dividend Program In November 2018, we announced that the Board had adopted a dividend program which we initiated in the first quarter of 2019. See Note 14 to the Financial Statements forff more information about our dividend program. ff Preferre d StocSS ff k OffO erings On October 15, 2021, we issued 1,000,000 shares of Series A Preferred Stock in a private offering (Offering). The net proceeds of the Offering were approximately $990 million, after deducting underwriting commissions and offering expenses. We intend to use the net proceeds from the Offering to repurchase shares of our outstanding common stock under the Share Repurchase Program (discussed below). On December 10, 2021, we issued 1,000,000 shares of Series B Preferred Stock in a private offering (Series B Offering) under our Green Finance Framework. The net proceeds of the Series B Offering were approximately $985 million, after deducting underwriting commissions and offering expenses. We intend to use the proceeds from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments. See Note 14 to the Financial Statements for more information concerning the Series A Preferred Stock and the Series B Preferred Stock. e Share Repurchase Program In October 2021, we announced that the Board had authorized a new share repurchase program (Share Repurchase Program) under which up to $2.0 billion of our outstanding common stock may be repurchased. The Share Repurchase Program became effective on October 11, 2021. The Share Repurchase Program supersedes the $1.5 million share repurchase program previously announced in September 2020 (2020 Share Repurchase Program). In the three months ended December 31, 2021, 19,330,365 shares of our common stock were repurchased under the Share Repurchase Program for approximately $409 million at an average price of $21.16 per share of common stock. As of December 31, 2021, approximately $1.591 billion was available forff additional repurchases under the Share Repurchase Program. From January 1, 2022 through February 22, 2022, 16,059,290 shares of our common stock had been repurchased under the Share Repurchase Program for $355 million at an average price per share of common stock of $22.07, and at February repurchase under the Share Repurchase Program. See Note 14 to the Financial Statements for more information concerning the Share Repurchase Program and the 2020 Share Repurchase Program. 22, 2022, $1.236 billion was available forff rr 54 Debt Activity t al structure, We have stated our objective to reduce our consolidated net leverage. We also intend to continue to simplify and optimize maintain adequate liquidity and pursue opportunities to refinance our long-term debt to extend maturities our capita and/or reduce ongoing interest expense. While the financial impacts resulting fromff Winter Storm Uri caused an increase in our consolidated net leverage, the Company remains committed to a strong balance sheet, and the anticipated securitization us to further execute this objective. See Note 1 to the Financial Statements for proceeds from ERCOT are expected to enablea ERCOT, Note 11 to the Financial Statements for details of our long-term details of the securitization proceeds receivable fromff debt activity, and Note 10 to the Financial Statements for details of our accounts receivable finaff ncing. Commodity-Linked Revolving Credit Facilitytt On February 4, 2022, Vistra Operations entered into a credit agreement by and among Vistra Operations, Vistra Intermediate, the lenders, joint lead arrangers and joint bookrunners party thereto, and Citibank, N.A., as administrative agent and collateral agent. The Credit Agreement provides forff a $1.0 billion senior secured commodity-linked revolving credit facility (the Commodity-Linked Facility). Vistra Operations intends to use the liquidity provided under the Commodity-Linked Facility to make cash postings as required under various commodity contracts to which Vistra Operations and its subsidiaries are parties as power prices increase from time-to time and for other working capita al and general corporate purposes. See Note 11 to the Financial Statements forff more information concerning the Commodity-Linked Facility. Capacity Marketstt PJMJJ — Reliability Pricing Model (RPM) auction results, for the zones in which our assets are located, are as follows for each planning year: RTO zone ComEd zone MAAC zone EMAAC zone ATSI zone DEOK zone 2021-2022 2022-2023 (average price per MW-day) $ $ 140.00 195.55 140.00 165.73 171.33 140.00 50.00 68.96 95.79 97.86 50.00 71.69 Our capac a 2022-2023, are as follows: ity sales in PJM, net of purchases, aggregated by planning year and capac a ity type through planning year CP auction capac a Bilateral capac a ity sold, net (MW) ity sold, net (MW) Total segment capacity sold, net (MW) Average price per MW-day 2021-2022 2022-2023 East Segment 6,384 200 6,584 159.18 $ Sunset Segment 3,028 50 3,078 148.83 $ East Segment 5,500 200 5,700 68.54 $ Sunset Segment 1,519 — 1,519 70.52 $ NYISOYY — The most recent seasonal auction results forff NYISO's Rest-of-Sta ff te zones, in which the capac a t ity f orff our Independence plant clears, are as follows forff each planning period: Price per kW-month Winter 2021 - 2022 1.00 $ Summer 2022 $ — 55 Due to the short-term, seasonal naturt e of the NYISO capac a bilateral trades. Our capacity sales, aggregated by season through winter 2023-2024, are as foll ff ity auctions, we monetize the majora ows: ity of our capac a ity through a a a Auction capac Bilateral capac Total capac ity sold (MW) ity sold (MW) ity sold (MW) Average price per kW-month Winter 2021 - 2022 125 1,017 1,142 0.94 $ $ Summer 2022 — 565 565 2.18 East Segment Winter 2022 - 2023 — 212 212 1.31 $ $ Summer 2023 — 104 104 1.76 Winter 2023 - 2024 — 38 38 1.78 $ ISO-NENN — The most recent Forward Capaa city Auction results forff ISO-NE Rest-of-Pool, ff in which most of our assets are located, are as foll ff ows for each planning year: Price per kW-month 2021-2022 2022-2023 2023-2024 2024-2025 $ 4.63 $ 3.80 $ 2.00 $ 2.61 Performance incentive rules increase capac ayments 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 capaa city transactions that extend through planning year 2025-2026. ity pt a a a a Auction capac Bilateral capac Total capac ity sold (MW) ity st old (MW) ity sold (MW) Average price per kW-month East Segment 2021-2022 2022-2023 2023-2024 2024-2025 2025-2026 3,037 213 3,250 4.35 $ 2,996 95 3,091 3.92 $ 3,091 20 3,111 2.12 $ 2,967 78 3,045 3.18 $ $ — 78 78 3.47 MISO — The capac a ity auction results forff MISO Local Resource Zone 4, in which our assets are located, are as follows for each planning year: Price per MW-day 2021-2022 $ 5.00 MISO capacity sales through planning year 2024-2025 are as folff lows: 2021-2022 2022-2023 2023-2024 2024-2025 Sunset Segment Bilateral capac a ity sold in MISO (MW) Total MISO segment capaa city sold (MW) 3,012 3,012 1,075 1,075 569 569 Average price per kW-month $ 2.31 $ 1.94 $ 2.58 $ 265 265 4.26 2022 through 2023 for Moss Landing, are as West Segment 2022 2023 1,287 1,275 CAISO — Our capac a ity sales in CAISO, aggregated by calendar year forff follows: Bilateral capac a ity sold (Avg MW) 56 Key Operational Risks and Challenges Following is a discussion of certain key operational risks and challenges facff ing management and the initiatives currently underway to manage such challenges. These matters involve risks that could have a material effeff ct on our business, results of operations, liquidity, financial condition, cash flows, reputation, prospects and the market price forff our securities (including our common stock). See also Item 1A. Riskii Factors in this annual report on Form 10-K for additional discussion on risks that could have a material effeff ct on our results of operations, liquidity, financial condition, cash flows, reputation, prospects and the market price forff our securities (including our common stock). Natural Gas Price and Market HeatHH Rate Exposure The price of power is typically set by natural ilities, with wholesale prices generally tracking increases or decreases in the price of natural gas, with exceptions such as those periods during which ERCOT power prices rise significantly as a result of the scarcity of available generation resources relative to power demand. In recent years, natural gas supply has outpaced demand primarily as a result of development and expansion of hydraulic fracturing in natural gas gas prices, and such prices have historically extraction; this supply/demand environment has resulted in historically low natural been volatile. gas-fueled generation facff t t t t t In contrast to our natural gas-fueled generation facff gas prices have no significant effect on the tors being equal, these cost of generating power at our nuclear-, lignite- and coal-fueled facff nuclear-, lignite- and coal-fueled generation assets increase or decrease in value as wholesale electricity prices change either as gas prices or market heat rates, because of the effect on our operating margins. A persistent a result of changes in natural 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. ilities. Consequently, all other facff ilities, changes in natural t t t t The wholesale market price of electricity divided by the market price of natural gas represents the market heat rate. ted by a number of factors, including generation availability, mix of assets and the efficiency of the Market heat rate can be affecff ilities) in generating electricity. Our market heat rate exposure is gas-fueled generation facff marginal supplier (generally natural ity of generation resources, such as additions and retirements of generation facilities, and impacted by changes in the availabila mix of generation assets. For example, increasing renewable (wind and solar) generation capac ity generally depresses market heat rates, particularly during periods when total demand is relatively low. However, increasing penetration of renewable ity may also contribute to greater volatility of wholesale market prices independent of changes in the price of generation capac natural Decreases in market heat rates decrease the value of our generation assets because t lower market heat rates result in lower wholesale electricity prices, and vice versa. gas, given their intermittent nature. a a t t As a result of our exposure to the variability of natural t 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; foll ff magnitude improving retail customer service to attract and retain high-value customers. and costs of commodity price, liquidity risk and retail demand variability; and tely reflects the value of our product offering to customers, the owing a retail pricing strategy that appropria a t We have engaged in natural gas hedging activities to mitigate the risk of lower wholesale electricity prices that have corresponded to declines in natural gas prices. When natural gas prices are depressed, we continue to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward wholesale and retail electricity sales. 57 Estimated hedging levels forff generation volumes in our Texas, East, West and Sunset segments as of December 31, 2021 were as follows: Nuclear/Renewable/Coal // Generation: Texas Sunset Gas Generation: Texas East West 2022 2023 90 % 98 % 71 % 94 % 100 % 55 % 47 % 8 % 35 % 6 % a provides approxi The following sensitivity tablea mate estimates of the potential impact of movements in power prices and gas-fired generation as calculated using an spark spreads (the difference between the power revenue and fuel expense of natural 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 gas generation units and the assumed 7.2 heat rate used to calculate the sensitivity to between actual heat rates of our natural gas exposure that is not already included in the gas generation spark spark spreads; and second, calculating the residual natural spread sensitivity shown in the tablea below. The estimates related to price sensitivity are based on our expected generation, related hedges and forward prices at December 31, 2021. ff ff t t t 2022 2023 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 13 $ (11) $ 13 $ (12) $ (6) $ 6 4 $ $ (2) $ 1 $ (1) $ — $ — $ 1 $ (1) $ 2 $ (1) $ 53 (50) 39 (37) (18) 10 32 (30) (2) 2 4 (4) — — 32 (28) : Texas ee Nuclear/Renewable/Coal Generation: $2.50/MWh increase in power price e Nuclear/Renewable/Coal Generation: $2.50/MWh decrease in power pric Gas Generation: $1.00/MWh increase in spark spread Gas Generation: $1.00/MWh decrease in spark spread Residual Naturat l Gas Position: $0.25/MMBtu increase in natural t gas price Residual Natural t Gas Position: $0.25/MMBtu decrease in natural t gas price East: Gas Generation: $1.00/MWh increase in spark spread Gas Generation: $1.00/MWh decrease in spark spread Residual Natural t Gas Position: $0.25/MMBtu increase in natural t e gas pric Residual Natural t Gas Position: $0.25/MMBtu decrease in natural t gas price West: Gas Generation: $1.00/MWh increase in spark spread Gas Generation: $1.00/MWh decrease in spark spread Residual Natural t Gas Position: $0.25/MMBtu increase in natural t gas price Residual Natural Gas Position: $0.25/MMBtu decrease in natural t gas price Sunset: Coal Generation: $2.50/MWh increase in power price Coal Generation: $2.50/MWh decrease in power price 58 Competitive Retail Mii arMM kerr ts and CusCC tomer Retention Competitive retail activity in ERCOT has resulted in retail customer churn as customers switch retail electricity providers for various reasons. Based on numbers of meters, our total retail customer counts increased approximately 3%, 1% and 2% in 2021, 2020 and 2019, respectively. Based upon December 31, 2021 results discussed below in Results of Operations, a 1% decline in retail customers in ERCOT would result in a decline in annual revenues of approximately $56 million. In responding to the competitive landscape in the ERCOT market, we have attempted to reduce overall customer losses by focusing on the following key initiatives: ff • • • 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 EnergyTM 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 t contracting and pricing approach and economic segmentation of the business market to enhance targeted sales and ; tactical programs we have initiated include marketing efforts and to more effectively deploy our direct-sales force improved customer service, aided by an enhanced customer management system, new product price/service offerings and a multichannel approach for the small business market. ff Exposures Related to Nuclear Asset Outages tt a ity of 1,150 MW. As of December 31, 2021, these units represented approxi Our nuclear assets are comprised of two generation units at the Comanche Peak facility, each with an installed nameplate generation capac mately 6% of our total generation capac a ity. The nuclear generation units represent our lowest marginal cost source of electricity. Assuming both nuclear impact to pretax earnings is estimated (based upon generation units experienced an outage at the same time, the unfavorablea forward electricity market prices for 2022 at December 31, 2021) to be approximately $2 million per day before consideration of any costs to repair the cause of such outages or receipt of any insurance proceeds. Also see discussion of nuclear facilities insurance in Note 13 to the Financial Statements to understand the importance and limits of our insurance protection. a 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 things, operations, maintenance, emergency planning, security, and regulation by the NRC, covering, among other al or environmental and safety protection. The NRC may implement changes in regulations that result in increased capita operating costs and may require extended outages, modify, suspend or revoke operating licenses and impose fines forff 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 (NEI). We also apply the knowledge NRC, the Institutet 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,ff and efficient operations at the facff of Nuclear Power Operations (INPO) and the Nuclear Energy Institutet reliablea ility. 59 Cyber/Da// ta Securityii and Infrastruc tt ture ProtePP ctiontt Riskii A breach of cyber/data security measures that impairs our information technology infrastructure, operations technology systems, supporting components, and/or associated sites utilized by the Company or one of our service providers could disrupt normal business operations and affect our ability to control our generation assets, access retail customer information and limit communication with third parties. Breaches and threats are becoming increasingly sophisticated, complex, change frequently and may be difficult to detect, and our increased use of remote work environments and virtual platforms in response to the COVID-19 pandemic may also increase our risk of cyber-attack or data security breaches. Any loss of confidential or proprietary data through a breach could materially affect our reputation, including our TXU Energy, Ambit Energy, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric brands, expose the company to legal claims, significant liabilities, reputational damage, regulatory action, and disrupt business operations, which could impair our ability to execute on business strategies. t t 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 finaff ncial ce and our industry, and are proactively making strategic impact, we recognize the growing threat within the general marketplat 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 capabi lities to enhance early detection and rapid response to potential cyber threats. In response to the fact that a portion of our a workforce continues to work remotely and within a hybrid work environment, we have reduced our attack surface process and technology, which removes remote network risk fromff our internal systems, assets, or data. t 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. Seasonalitll ytt ed by weather. As a result, our operating results The demand for and market prices of electricity and natural tuate on a seasonal basis. Typically, demand for and the are impacted by extreme or sustained weather conditions and may flucff price of electricity is higher in the summer and winter seasons, when the temperatures are more extreme, and the demand for gas is also generally higher in the winter. More severe weather conditions such as heat waves or extreme and price of natural winter weather have made, and may make such fluctuations more pronounced. The pattern of this flucff tuation may change depending on, among other things, the retail load served and the terms of contracts to purchase or sell electricity. gas are affect ff t t Application of Critical Accounting Policies and Estimates Our significant accounting policies are discussed in Note 1 to the Financial Statements. We follow accounting principles generally accepted in the U.S. Application of these accounting policies in the preparation of our consolidated financial statements requires management to make estimates and assumptim ons about future events that affect the reporting of assets and liabilities at the balance sheet dates and revenues and expenses during the periods covered. The following is a summary of certain critical accounting policies that are impacted by judgments and uncertainties and under which different amounts might be reported using different assumptim ons or estimation methodologies. Derivativtt e Inst II rumtt ents and Mark-to-Marke tt t Accountingn We enter into contracts for the purchase and sale of energy-related commodities, and also enter into other derivative instruments such as options, swaps,a 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 assumptim ons and estimation techniques. 60 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 forff 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 gas, electricity, etc.), time period specified and delivery point. Where quoted dependent on the type of commodity (e.g., natural market prices are not available, the fair value is based on unobservable inputs, which require significant judgment. Derivative instrume gas r and coal, (ii) electricity, natural 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 availablea market information and other inputs that might not be readily observable in the market. We estimate fair value as described in Note 15 to the Financial Statements. nts valued based on unobservable inputs primarily include (i) forward sales and purchases of electricity, natural gas and coal options, and (iii) financial transmission rights. t t t Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. Normal purchases and sales are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business and are not subject to mark-to-market accounting if the normal purchase or sale election is made. Accounting standards also permit an entity to designate certain qualifying derivative contracts in a hedge accounting relationship, whereby changes in fair value are not recognized immediately in earnings. Vistra does not have derivative instruments with hedge accounting designations. We report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting arrangements that we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the consolidated balance sheets, with the exception of certain margin amounts related to changes in fair value on CME transactions that are legally characterized as settlement of derivative contracts rather than collateral. See Note 16 to the Financial Statements forff further discussion regarding derivative instruments. Accountingii for Income Taxes Vistra files a U.S. federal income tax return that includes the results of its consolidated subsidiaries. Vistra is the corporate parent of the Vistra consolidated group. Pursuant to applicable U.S. Department of the Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group. Our income tax expense and related consolidated balance sheet amounts involve significant management estimates and ities, as well as current and noncurrent accruals, involve estimates judgments. Amounts of deferred income tax assets and liabila In assessing the and judgments of the timing and probability of recognition of income and deductions by taxing authorities. taxablea likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future to the future impacts of various items, including changes income. Actual income taxes could vary f estimated amounts dued l review of filed in income tax laws, our forecasted financial condition and results of operations in future periods, as well as finaff tax returns by taxing 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. ct to examination by applicable tax authorities. Income tax returns are regularly subjeu romff rr ff ff t See Notes 1 and 7 to the Financial Statements forff further discussion of income tax matters. 61 Accounting forff Tax Receivable Agreement ff ights for the benefit of the first-lien creditors of TCEH entitled to receive such TRA RRR On the Effective Date, Vistra entered into a tax receivable agreement (the TRA)RR with a transfer agent. Pursuant to the ights under TRA,RR we issued the TRA RRR value in the amount of $574 the Plan of Reorganization. Vistra reflected million as of the Effective Date related to these future payment obligations. As of December 31, 2021, the TRA oRR bligation has been adjusted to $395 million. During the year ended December 31, 2021, we recorded a decrease to the carrying value of the bligation totaling $115 million as a result of adjustments to forecasted taxable income, including the financial impacts of TRA oRR planned additional renewabla e development Winter Storm Uri, and anticipated tax benefits available under current tax laws forff projects. As of December 31, 2021, expected undiscounted federal and state payments under the TRA iRR s estimated to be approximately $1.4 billion. The TRA oRR bligation 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 obligation associated with TRA RRR ights at fair ff • • • • • • • taxable income by year forff 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 ff future to utilize the deductions arising out of the Company generally expects to generate sufficient taxable income to be ablea (i) the tax basis step up au 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 apport to those states. years of 22.9%; ttributablea years; futuret ioned a ff We recognize accretion expense over the life of the TRA RRR ights liability as the present value of the liability is accreted upu over the life of the liability. This noncash accretion expense is reported in the consolidated statements of operations as Impacts of Tax Receivable Agreement. Further, there may be significant changes, which may be material, to the estimate of the related liability due to various reasons including changes in federal and state tax laws and regulations, changes in estimates of the amount or timing of future consolidated taxable income, utilization of acquired net operating losses, reversals of temporary book/tax differences and other items. Changes in those estimates are recognized as adjustments to the related TRA RRR ights liability, with offsetting impacts recorded in the consolidated statements of operations as Impacts of Tax Receivable Agreement. See Note 8 to the Financial Statements. Asset Retirement Obligati i ons (ARO) As part of business combination accounting, new fair values were establa ished for all AROs assumed in the Merger. A liability is initially recorded at fair value forff an ARO associated with the legal obligation associated with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets. Changes to the estimate of the ARO requires us to make significant estimates and assumptim ons. Specifically, the estimates and assumptim ons required for the mining land reclamation related to lignite mining, such as the costs to fill in mining pits and interpreting the mining permit closure requirements, are complex and require a significant amount of judgment. To develop the estimate associated with the costs to fill in mining pits, we utilize a complex proprietary model to estimate the volume of the pit. A significant portion of the estimate is associated with the Asset Closure Segment, thus related to closed facilities with changes in the estimate recorded to our consolidated statements of operations. For the next five years, Vistra is projected to spend approximately $265 million (on a nominal basis) to achieve its reclamation objectives. During the years ended December 31, 2020 and 2019, we transferred $15 million and $135 million, remediation. Any remaining unpaid third-party obligation was reclassified respectively, in ARO obligations to third parties forff d credits in our consolidated balance sheets. to other current liabilities and other noncurrent liabilities and deferre ff 62 As of December 31, 2021, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.635 billion and includes an assumption that Vistra receives a license extension of 20 years from the NRC to continue to operate the Comanche Peak facff 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. ility. The costs to ultimately decommission that facff ility are recoverablea rr See Note 21 to the Financial Statements for additional discussion of ARO obligations and adjustments made to the ARO obligation estimates during d the years ended December 31, 2021, 2020 and 2019. ii Impairme nt of GooGG dwillii and Other Long-Lived Assets ff impairment, te lives) forff We evaluate long-lived assets (including intangible assets with fini in accordance with accounting standards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances . For our generation assets, possible indications include an indicate that their carrying amount may not be recoverablea expectation of continuing long-term declines in naturat l 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 naturet and may require the use of estimates in forec asting future results and cash flows related to an asset or group of assets. Further, the of our property, plant and equipment, which includes a fleff et of generation assets with a diverse fuel mix and unique naturet judgments in individual generation units that have varying production or output rates, requires the use of significant determining the existence of impairment indications and the grouping of assets for impairment testing. See Note 21 to the Financial Statements forff discussion of impairments of long-lived assets recorded in the years ended December 31, 2021 and 2020. ff Recoverabila ity 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 assumptim ons for forward natural gas and electricity prices, forward capac s, generation plant performance, forecasted fuel prices and forecasted operating costs. The carrying value of such asset groups is forecasted capital expenditures, if the projected undiscounted cash flows are less than the carrying value. determined to be unrecoverablea ity prices, the effects of enacted environmental ruler a t t , faiff If an asset group carrying value is determined to be unrecoverablea r 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 gas t s, generation plant and electricity prices, forward capac a performance, forecasted capital expenditures and forecasted fuel ch is the Any significant change to one or more of these factors can have a material discount rate appli 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. that reflect assumptions regarding, among other things, forward natural ity prices, market heat rates, the effects of enacted environmental ruler prices. Another key assumptim on in the income approa ed to the forecasted cash flows. a a ff ff ff Goodwill and intangible assets with indefinite useful lives, such as the intangible asset related to the trade names of TXU EnergyTM, Ambit Energy, 4Change EnergyTM, Homefield, Dynegy Energy Services, TriEagle Energy, Public Power and U.S. Gas & Electric, respectively, are required to be evaluated forff impairment at least annually (we have selected October 1 as our annual goodwill test date) or whenever events or changes in circumstances indicate an impairment may exist, such as the indicators used to evaluate impairments to long-lived assets discussed above or declines in values of comparablea public companies in our industry. Accounting standards allow a company to qualitatively assess if the carrying value of a reporting unit with goodwill is more likely than not less than the fair value of that reporting unit. If the entity determines the carrying value, including goodwill, is not more likely greater than the fair value, no further testing of goodwill for impairment is required. On the most recent goodwill testing date, we applied qualitative factors and determined that it was more likely than not that the fair value of our Retail and Texas Generation reporting units exceeded their carrying value at October 1, 2021. Significant qualitative factors evaluated included reporting unit financial performance and market multiples, cost factors, customer attrition, interest rates and changes in reporting unit book value. 63 Accounting guidance requires goodwill to be allocated to our reporting units, and at December 31, 2021, $2.461 billion of our goodwill was allocated to our Retail reporting unit and $122 million was allocated to our Texas Generation reporting unit. Goodwill impairment testing is performff ed at the reporting unit level. Under this goodwill impairment analysis, if at the assessment date, a reporting unit's carrying value exceeds its estimated fair value (enterprise value), the excess carryirr ng value is written off as an impairment charge. t ff e that reflect assumptions regarding, among other things, forward natural The determination of enterprise value of a reporting unit involves a number of assumptions and estimates. We use a combination of fair value measurements to estimate enterprise values of our reporting units including: internal discounted cash publicly traded company values (market approach). The income approach flow analyses (income approach), and comparablea involves estimates of future performanc gas and electricity prices, market heat rates, the effect s, generation plant performance, forecasted capital and retail sales volume trends, as well as determination of a terminal value. Another key variable in the income expenditures The determination of approach is the discount rate, or weighted average cost of capita the discount rate takes into consideration the capita publicly traded companies as well as an estimate of returnt and current market volatility for the industry. The market approach involves using trading multiples of EBITDA of those selected publicly traded companies to derive appropriate multiples to appl y to the EBITDA of our reporting units. Critical judgments include the selection of publicly traded comparablea companies and the weighting of the value metrics in developing the best estimate of enterprise value. al structure, credit ratings and current debt yields of comparablea on equity that reflects historical market returns ied to the forecasted cash flows. s of environmental rulerr a al, appl a ff ff t t RESULTS OF OPERATRR IONS Vistra Consolidat CC ii edtt Financ ial Results — YeaYY r Ended EE Operating revenues Fuel, purchased power costs and delivery fees Operating costs Depreciation and amortization Selling, general and administrative expenses Impairment of long-lived and other assets Operating income (loss) Other income Other deductions Interest expense and related charges Impacts of Tax Receivablea Equity in earnings of unconsolidated investment Agreement Income (loss) before income taxes Income tax (expense) benefit Net income (loss) December 31, 2021 Compared to Year Ended December 31, 2020 Year Ended December 31, 2021 2020 Favorable (Unfavorable) $ Change $ $ $ 12,077 (9,169) (1,559) (1,753) (1,040) (71) (1,515) 140 (16) (384) 53 — (1,722) 458 (1,264) $ 11,443 (5,174) (1,622) (1,737) (1,035) (356) 1,519 34 (42) (630) 5 4 890 (266) 624 $ $ 634 (3,995) 63 (16) (5) 285 (3,034) 106 26 246 4 8 (4) (2,612) 724 (1,888) 64 Retail Texas $ 7,871 $ 2,790 $ East 2,587 Year Ended December 31, 2021 West Sunset Asset Closure Eliminations / Corporate and Other $ 374 $ 739 $ — $ (2,284) $ Vistra Consolidated 12,077 (4,568) (127) (3,991) (704) (2,123) (243) (253) (37) (212) (608) (698) (718) (88) (75) (33) 2,213 1 (7) (9) — — (2,601) 84 (9) 14 — — (552) — — (15) — 2,198 (2,512) (567) (2) 2,196 $ — $ (2,512) $ — (567) $ (60) (32) — (8) — — 9 — 1 — 1 (518) (417) (139) (55) (38) (428) 15 2 (2) — — (30) — (26) — (56) 35 — (1) — 2,284 (1) (36) (46) — (83) 5 (2) (9,169) (1,559) (1,753) (1,040) (71) (1,515) 140 (16) (380) (384) 53 53 (413) (22) (407) (1,722) — (413) $ $ — (22) $ 460 53 $ 458 (1,264) Operating revenues Fuel, purchased power costs and delivery fees Operating costs Depreciation and amortization Selling, general and administrative expenses Impairment of long-lived and other assets Operating income (loss) Other income Other deductions Interest expense and related charges Impacts of Tax Receivablea Agreement Income (loss) before income taxes Income tax benefit (expense) Net income (loss) Operating revenues $ 8,270 $ 4,116 $ Retail Texas East 2,415 West Sunset $ 282 $ 1,252 $ Asset Closure 3 Year Ended December 31, 2020 Eliminations / Corporate and Other $ (4,895) $ Vistra Consolidated 11,443 l, purchased power costs and delivery fees Operating costs Depreciation and amortization Selling, general and administrative expenses Impairment of long-lived assets and other assets Operating income (loss) Other income Other deductions Interest expense and related charges Impacts of Tax Receivablea Agreement Equity in earnings of unconsolidated investment Income (loss) before income taxes Income tax expense Net income (loss) $ (6,857) (123) (1,078) (727) (1,262) (270) (303) (475) (721) (675) (75) — 312 6 1 (10) — — 309 — 309 — 1,761 3 (12) 8 — — 1,760 — 1,760 $ $ (89) — 73 1 (30) (7) — 4 41 — 41 65 $ (168) (30) (19) (26) — 39 1 — 10 — — 50 — 50 (704) (408) (133) (71) (356) (420) 6 2 (2) — — — (63) (22) (27) — (109) 10 (2) — — — 4,895 (1) (64) (72) — (137) 7 (1) (629) 5 — (414) (101) (755) — (414) $ — (101) $ (266) (1,021) $ $ (5,174) (1,622) (1,737) (1,035) (356) 1,519 34 (42) (630) 5 4 890 (266) 624 rr In February 2021, Winter Storm Uri resulted in a $2.2 billion negative impact on the Company's pre-tax earnings in the year ended December 31, 2021, after taking into account approximately $544 million in securitization proceeds Vistra expects r described in Note 1 to the Financial Statements. For the remainder of 2021, our operating to receive from ERCOT as furthe on cost management and self-help activities while ff segments delivered strong operating performance with a disciplined focus generating and selling essential electricity in a safe and reliable manner. ff Consolidated results decreased $3.034 billion to a net operating loss of $1.515 billion in the year ended December 31, 2021 compared to the year ended December 31, 2020. The change in results was driven by the Winter Storm Uri impacts, including the need to procure power in ERCOT at market prices at or near the price cap due to lower output from our natural gas deliverability issues and our coal-fueled power plants driven by coal fuel gas-fueled power plants driven by natural handling challenges, high fuel costs, and high retail load costs including ancillary service costs and reliabila ity deployment price adders. Results were adversely impacted by $759 million in pre-tax unrealized losses on commodity hedging transactions in 2021 compared to $231 million in pre-tax unrealized gains on commodity hedging transactions in 2020. Power, natural gas and coal forward market curves moved up during the year ended December 31, 2021, driving these net pre-tax unrealized losses on ff commodity hedging transactions. ff t t t Operating costs decreased $63 million to $1.559 billion in the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily driven by lower LTSA costs and lower property taxes. Interest expense and related charges decreased $246 million to $384 million in the year ended December 31, 2021 compared to the year ended December 31, 2020 driven by $134 million in unrealized mark-to-market gains on interest rate swaps in 2021 compared to $155 million in unrealized mark-to-market losses on interest rate swapsa in 2020. See Note 21 to the Financial Statements. For the years ended December 31, 2021 and 2020, the impacts of the TRA tRR otaled income of $53 million and $5 million, respectively. See Note 8 to the Financial Statements for discussion of the impacts of the TRA obligation. For the year ended December 31, 2021, income tax benefit totaled $458 million and the effective tax rate was 26.6%. For totaled $266 million and the effective tax rate was 29.9%. See Note 7 to the year ended December 31, 2020, income tax benefitff the Financial Statements for reconciliation of the effective rates to the U.S. federal statutory rate. ff Consolidated cash flows used in operations totaled $206 million for the year ended December 31, 2021 compared to consolidated cash flows provided by operations of $3.337 billion for the year ended December 31, 2020. The unfavorablea change of $3.543 billion was primarily driven by lower cash from operations due to Winter Storm Uri impacts and higher cash margin deposits posted with third-parties. Cash margin deposits posted were driven by net pre-tax unrealized losses on commodity hedging transactions reflecting power, natural market curves that moved up during the year ended December 31, 2021. gas and coal forward ff t 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 performff ance 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 tablea s 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 filff ed reports in their entirety and not rely on any single finff ancial measure. 66 BB EBITDATT and Adjustedtt EBITDA — We believe EBITDA and Adjusted EBITDA provide meaningful representations of ncial perforff mance on an ongoing basis. our operating performance. We consider EBITDA as another way to measure finaff Adjusted EBITDA is meant to reflect the operating performance of our segments forff the period presented. We define EBITDA as earnings (loss) before interest expense, income tax expense (benefit) and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA adjusted to exclude (i) gains or losses on the sale or retirement of certain assets, (ii) the impacts of mark-to-market changes on derivatives, (iii) the impact of impairment charges, (iv) certain amounts associated with fresh- start reporting, acquisitions, dispositions, transition costs or restructurings, (v) non-cash compensation expense, (vi) impacts from the Tax Receivable Agreement and (vii) other material nonrecurring or unusual items. ff Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine ance against our peers, and evaluate overall financial performance, we al expenditures, assess performff our ability to fund capita 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 comparablea GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss). Adjustedtt EBITBB DATT — YeaYY r Ended EE December 31, 2021 Compared to Ytt earYY Ended December 31, 2020 Net income (loss) Income tax expense (benefit) Interest expense and related charges (a) Depreciation and amortization (b) EBITDA / Agreement se accounting impacts Unrealized net (gain) loss resulting from commodity hedging transactions Generation plant retirement expenses Fresh start/purcha Impacts of Tax Receivablea Non-cash compensation expenses Transition and merger expenses Other, including impairment of long-lived and other assets Loss on disposal of investment in NELP COVID-19-related expenses (c) Winter Storm Uri impacts (d) Adjusted EBITDA Year Ended December 31, 2021 2020 Favorable (Unfavorable) $ Change $ $ (1,264) $ (458) 384 1,831 493 759 18 (138) (53) 51 (8) 80 — 8 698 1,908 $ 624 266 630 1,812 3,332 (231) 43 38 (5) 63 16 375 29 25 — 3,685 $ $ (1,888) (724) (246) 19 (2,839) 990 (25) (176) (48) (12) (24) (295) (29) (17) 698 (1,777) ____________ (a) Includes unrealized mark-to-market net gains on interest rate swapsa losses on interest rate swapsa of $155 million for the years ended December 31, 2021 and 2020, respectively. of $134 million and unrealized mark-to-market net (b) Includes nuclear fuel ff amortization in the Texas segment of $78 million and $75 million for the years ended December 31, 2021 and 2020, respectively. Includes material and supplies and other incremental costs related to our COVID-19 response. (c) (d) For the year ending December 31, 2021, includes the following of the Winter Storm Uri impacts, which we believe are not reflective of our operating performance: allocation of ERCOT default uplift charges which are expected to be paid over more than 90 years under current protocols; accrual of Koch earn-out amounts that the Company will pay by the end of her described below); and Winter Storm the second quarter of 2022; future bill credits related to Winter Storm Uri (as furt Uri related legal fees and other costs. The adjustment for future bill credits relates to large commercial and industrial customers that curtailed their usage during Winter Storm Uri and will reverse and impact Adjusted EBITDA in future periods as the credits are applied to customer bills. We estimate the amounts to be applied in future periods are 2022 (approximately $150 million), 2023 (approximately $67 million), 2024 (approximately $11 million) and 2025 (approximately $4 million). The Company believes the inclusion of the bill credits as a reduction to Adjusted EBITDA in the years in which such bill credits are applied more accurately reflects its operating performance. ff ff ff 67 Year Ended December 31, 2021 Texas East $ (2,512) $ (567) $ Asset Closure Sunset $ (413) $ (22) $ Net income (loss) Income tax expense (benefit) Interest expense and related charges (a) Depreciation and amortization (b) EBITDA / se accounting impacts Unrealized net (gain) loss resulting from commodity hedging transactions Generation plant retirement expenses Fresh start/purcha Impacts of Tax Receivablea Non-cash compensation expenses Transition and merger expenses Other, including impairment of long- lived and other assets COVID-19-related expenses (c) Winter Storm Uri impacts (d) Agreement Retail $2,196 2 9 212 2,419 (1,403) — 2 — — (2) 57 — 239 — (14) 686 (1,840) 1,139 — (14) — — — 18 4 457 — 15 698 146 655 — (74) — — — 9 1 — West 1 — (9) 60 52 38 — — — — — 3 — — 93 — 2 139 (272) 330 18 (52) — — — 33 2 1 60 $ Eliminations / Corporate and Other 53 (460) 380 36 9 Vistra Consolidated (1,264) $ (458) 384 1,831 493 759 18 (138) (53) 51 (8) 80 8 698 — — — (53) 51 9 (43) 1 1 — 1 — (21) — — — — — (15) 3 — — Adjusted EBITDA $1,312 $ (236) $ 737 $ $ (33) $ (25) $ 1,908 ff Includes $134 million of unrealized mark-to-market net gains on interest rate swaps.a amortization of $78 million in the Texas segment. Includes material and supplies and other incremental costs related to our COVID-19 response. ____________ (a) (b) Includes nuclear fuel (c) (d) Includes the following of the Winter Storm Uri impacts, which we believe are not reflective of our operating performance: allocation of ERCOT default uplift charges which are expected to be paid over more than 90 years under current protocols; accrual of Koch earn-out amounts that the Company will pay by the end of the second quarter of 2022; future and other bill credits related to Winter Storm Uri (as furt costs. The adjustment for future bill credits relates to large commercial and industrial customers that curtailed their usage during Winter Storm Uri and will reverse and impact Adjusted EBITDA in future periods as the credits are applied to customer bills. We estimate the amounts to be applied in future periods are 2022 (approximately $150 million), 2023 ff (approximately $67 million), 2024 (approximately $11 million) and 2025 (approximately $4 million). The Company believes the inclusion of the bill credits as a reduction to Adjusted EBITDA in the years in which such bill credits are applied more accurately reflects its operating performance. her described below); and Winter Storm Uri related legal fees ff ff 68 Year Ended December 31, 2020 Asset Closure Sunset $ (414) $ (101) $ Eliminations / Corporate and Other Vistra Consolidated 624 266 630 1,812 3,332 (1,021) $ 266 629 64 (62) — — — (5) 63 11 (231) 43 38 (5) 63 16 375 29 25 3,685 359 — 5 $ 242 1 — — $ (81) $ (36) — 2 (27) $ Net income (loss) Income tax expense Interest expense and related charges (a) Depreciation and amortization (b) EBITDA Retail $ 309 — 10 303 622 Texas $1,760 — (8) 550 2,302 $ East 41 — 7 721 769 $ West 50 — (10) 19 59 / se accounting impacts Unrealized net (gain) loss resulting from commodity hedging transactions Generation plant retirement expenses Fresh start/purcha Impacts of Tax Receivablea Non-cash compensation expenses Transition and merger expenses Other, including impairment of long- lived and other assets Loss on disposal of investment in NELP COVID-19-related expenses (c) Agreement Adjusted EBITDA 340 — 5 — — 5 (691) — (8) — — 2 15 — 22 — — 1 11 — — $ 983 26 — 15 $1,646 10 29 3 $ 849 $ 10 — — — — — 4 — — 73 — 2 133 (279) 95 43 19 — — — — — 22 (79) — — — — — (3) ____________ (a) (b) Includes nuclear fuel (c) ff Includes $155 million of unrealized mark-to-market net losses on interest rate swaps.a amortization of $75 million in the Texas segment. Includes material and supplies and other incremental costs related to our COVID-19 response. 69 Retail Segme e nt — Year Ended December 31, 2021 Comparem d to Ytt earYY Operating revenues: Revenues in ERCOT tt Revenues in Northeast/Mi Amortization expense Unrealized net losses on hedging activities (a) dwest Total operating revenues Fuel, purchased power costs and delivery fees: iates Purchases from affilff Unrealized net gains (losses) on hedging activities with affiliates Unrealized net gains on hedging activities Delivery fees Other costs (b) Total fuel, purchased power costs and delivery fees Net income Adjusted EBITDA Retail sales volumes (GWh): Retail electricity sales volumes: Sales volumes in ERCOT Sales volumes in Northeast/Mi tt dwest Total retail electricity sales volumes Weather (North Texas average) - percent of normal (c): Cooling degree days Heating degree days Ended December 31, 2020 Year Ended December 31, 2021 2020 Favorable (Unfavorable) Change $ $ $ $ $ 5,943 2,255 (2) (325) 7,871 (4,002) 1,719 9 (1,937) (357) (4,568) 2,196 1,312 $ $ $ $ $ 5,880 2,406 (5) (11) 8,270 (4,566) (329) — (1,893) (69) (6,857) 309 983 $ $ $ $ $ 57,033 36,070 93,103 54,075 36,274 90,349 90.0 % 92.0 % 90.0 % 91.0 % 63 (151) 3 (314) (399) 564 2,048 9 (44) (288) 2,289 1,887 329 2,958 (204) 2,754 ____________ (a) For the year ended December 31, 2021, a net loss of $298 million was recognized in operating revenues due to the third quarter 2021 discontinuance of normal purchase and sale accounting on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract term. (b) For the year ended December 31, 2021, includes $153 million of future bill credits to large commercial and industrial customers. (c) Weather data is obtained fromff Weatherbank, Inc. For the year ended December 31, 2021, normal is defined as the average over the 10-year period from December 2011 to December 2020. For the year ended December 31, 2020, normal is defined as the average over the 10-year period from December 2010 to December 2019. 70 The folff lowing table presents changes in net income (loss) and Adjusted EBITDA forff the year ended December 31, 2021 compared to the year ended December 31, 2020. Winter Storm Uri, including securitization proceeds receivable fromff Monetization of certain commercial positions Higher margins Other driven by higher SG&A expense Change in Adjusted d EBITDA ERCOT and bill credits Favorable impact of higher unrealized net gains on commodity hedging activities Future bill credits and other costs related to Winter Storm Uri Decrease in depreciation and amortization expenses Other, including impairment of long-lived and other assets Change in Net income Year Ended December 31, 2021 Compared to 2020 (75) $ 207 228 (31) 329 1,743 (245) 91 (31) 1,887 $ $ Generation — Year Ended December 31, 2021 Compared to Ytt earYY Ended December 31, 2020 ity revenue from ISO/RTO Operating revenues: Electricity sales Capac a Sales to affiliates Rolloff of unrealized net gains (losses) representing positions settled in the current period Unrealized net gains (losses) on hedging activities Unrealized net gains (losses) on hedging activities with affiliates Other revenues Operating revenues Fuel, purchased power costs and delivery fees: Fuel for generation facilities and purchased power costs Fuel for generation facilities and purchased power costs from affiliates Unrealized (gains) losses fromff hedging activities Ancillary and other costs Fuel, purchased power costs and delivery fees Texas East West Sunset 2021 2020 2021 2020 2021 2020 2021 2020 Year Ended December 31, $ 1,999 — 2,063 $ 896 — 2,543 $1,619 (22) 1,553 $ 833 (52) 1,655 $ 410 1 5 $ 289 — 3 $ 819 184 382 $ 883 164 365 (207) 2 (159) 159 62 (22) 241 (205) (37) 217 51 (121) (104) (1,028) — 2,790 458 — 4,116 (529) 74 2,587 (61) 2 2,415 — — 374 12 — — 282 (713) 133 (162) (12) 739 (68) (20) 1,252 (2,829) (960) (2,072) (1,225) (251) (166) (810) (744) — 6 133 (1,295) 14 (138) 2 (18) (35) (8) 8 (37) — 4 (6) — — (2) (4) 304 (8) 2 45 (7) (3,991) (1,078) (2,123) (1,262) (253) (168) (518) (704) Net income (loss) $(2,512) $1,760 $ (567) $ 41 $ 1 $ 50 $ (413) $ (414) Adjusted EBITDA $ (236) $1,646 $ 737 $ 849 $ 93 $ 73 $ 60 $ 242 Production volumes (GWh): Natural gas facilities Lignite and coal facff Nuclear facilities Solar/Battery facilities ilities Capacity factors: CCGT facilities Lignite and coal facff Nuclear facilities ilities Weather - percent of normal (a): 30,921 25,513 19,402 454 35,093 26,013 19,480 432 43.2 % 49.2 % 75.6 % 77.1 % 96.3 % 96.7 % 55,428 55,938 5,365 5,284 36,953 29,971 4 57.6 % 57.9 % 60.0 % 59.1 % 58.0 % 47.1 % Cooling degree days Heating degree days 94 % 94 % 98 % 85 % 108 % 93 % 105 % 92 % 90 % 111 % 130 % 95 % 115 % 90 % 102 % 89 % ____________ (a) Reflects cooling degree days or heating degree days for the region based on Weather Services Internat r ional (WSI) data. 72 Year Ended December 31, 2021 2020 Market pricing Average ERCOT North power price ($/MWh) $ 149.57 Average NYMEX Henry Hubu t natural gas price ($/MMBtu) Average natural gas price (a): TetcoM3 ($/MMBtu) Algonquin Citygates ($/MMBtu) $ $ $ 3.82 3.40 4.51 $ $ $ $ 21.46 1.99 1.59 2.00 Average Market On-Peak Power Prices ($MWh) (b): PJM West Hub AEP Dayton Hub NYISO Zone C Massachusetts Hub Indiana Hub Northern Illinois Hub Year Ended December 31, 2021 2020 $ $ $ $ $ $ 45.62 44.88 35.59 51.81 48.62 41.15 $ $ $ $ $ $ 24.55 24.49 19.37 26.57 26.77 22.47 ____________ (a) Reflects the average of daily quoted prices forff (b) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we the periods presented and does not reflect costs incurred by us. realized. The folff lowing table presents changes in net income (loss) and Adjusted EBITDA forff the year ended December 31, 2021 compared to the year ended December 31, 2020. l ) change in revenue net of fueff Favorable/(unfavorablea Winter Storm Uri impact Favorable/(unfavorablea Favorablea administrative expenses Other (including other income and other deductions) (a) ed EBITDA /(unfavorable) change in selling, general and ) change in other operating costs Change in Adjust d /(unfavorable) change in depreciation and amortization Favorablea Change in unrealized net losses on hedging activities Other, including impairment of long-lived and other assets Generation plant retirement expenses Fresh start/purcha Transition and merger expenses se accounting impacts / Winter Storm Uri impact (ERCOT defaul Loss on disposal of investment in NELP ff t uplu ift and legal disputes) Change in Net income (loss) ____________ Year Ended December 31, 2021 Compared to 2020 Texas East West Sunset $ (447) $ (1,535) 19 — 81 (1,882) $ (136) (1,830) 25 — 6 2 (457) — (4,272) $ $ $ (175) $ 50 8 10 (5) (112) $ 23 (640) (5) — 96 1 — 29 (608) $ $ $ 34 — (7) (6) (1) 20 (41) (28) — — — — — — (49) $ (178) 17 (39) 8 10 (182) (6) (235) 329 25 71 — (1) — 1 (a) For the year ended December 31, 2021, includes insurance proceeds of $80 million in the Texas segment and $7 million in the Sunset segment. The change in Texas segment results was primarily driven by the Winter Storm Uri impacts, including the need to procure gas-fueled power plants driven power in ERCOT at market prices at or near the price cap due to lower output from our natural by natural gas-fueled power plants due to extremely high fuel costs, t t and, to a lesser extent, operational challenges associated with Winter Storm Uri, and unrealized hedging losses in the year ended December 31, 2021 versus unrealized hedging gains in the year ended December 31, 2020, partially offset by insurance proceeds received in 2021. gas deliverability issues, lower margins from our natural t The change in East segment results was driven by lower revenue net of fuel and larger unrealized hedging losses in the year ended December 31, 2021 versus the year ended December 31, 2020, partially offset by loss on disposal of equity method investment in NELP for 100% ownership of NJEA (see Note 21 to the Financial Statements) in 2020. 73 The change in West segment results was driven by larger unrealized hedging losses in year ended December 31, 2021 versus the year ended December 31, 2020, partially offset by higher realized prices through hedging activities and plant optimization efforts. The change in Sunset segment results was driven by larger unrealized hedging losses in year ended December 31, 2021 versus the year ended December 31, 2020 and lower margins due to lower realized prices and higher operating costs, partially offset by higher impairment of long-lived assets generation plant retirement expenses related to our Joppa/EEI, Kincaid and Zimmer coal generation facilities in 2020. Asset Closull re Segment — Year Ended December 31, 2021 Compared m Operating revenues Operating costs Depreciation and amortization Selling, general and administrative expenses Operating loss Other income Other deductions Interest expense and related charges Income (loss) before income taxes Net loss Adjusted EBITDA to Year Ended December 31, 2020 Year Ended December 31, 2021 2020 Favorable (Unfavorable) Change $ $ $ — $ (30) — (26) (56) 35 — (1) (22) (22) $ (33) $ $ 3 (63) (22) (27) (109) 10 (2) — (101) (101) $ (81) $ (3) 33 22 1 53 25 2 (1) 79 79 48 Operating costs for the years ended December 31, 2021 and 2020 included ongoing costs associated with the decommissioning and reclamation of retired plants and mines. The year ended December 31, 2021 includes a gain on the settlement of rail transportation disputes (see Note 21 to the Financial Statements). Energy-Relatell MM d ComCC modityii Contracts and Mark-to-M MM arket Activitiii es The tablea below summarizes the changes in commodity contract assets and liabilities for the years ended December 31, 2021 and 2020. The net change in these assets and liabilities, excluding "other activity" as described below, reflects $759 million in unrealized net losses and $231 million in unrealized net gains forff the years ended December 31, 2021 and 2020, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio. Year Ended December 31, 2021 2020 $ Commodity contract net liability at beginning of period Settlements/termination of positions (a) Changes in fair value of positions in the portfolio (b) Other activity (c) Commodity contract net liability at end of period ____________ (a) Represents reversals of previously recognized unrealized gains and losses upon settlement/ttt ermination (offsets realized gains and losses recognized in the settlement period). The years ended December 31, 2021 and 2020 also include reversals of $3 million and $12 million, respectively, of previously recorded unrealized losses related to commodity contracts acquired in the Merger, Crius Transaction and Ambit Transaction. The year ended December 31, 2020 includes reversals of $1 million of previously recorded unrealized losses related to Vistra beginning balances. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month. (75) $ (295) (464) (32) (866) $ (279) (14) 245 (27) (75) $ (b) Represents unrealized net gains (losses) recognized, reflecting the effect of changes in faiff r value. Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month. 74 (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 Ttt presents the net commodity contract liabia lity arising from recognition of fair values at December 31, 2021, scheduled by the source of fair value and contractual settlement dates of the underlying positions. ell — The following tablea ablTT Source of fair value Prices actively quoted Prices provided by other external sources Prices based on models Total Maturity dates of unrealized commodity contract net liability at December 31, 2021 Less than 1 year 1-3 years $ $ (631) 352 (72) (351) $ $ (116) (113) (83) (312) 4-5 years 2 1 (108) (105) $ $ $ $ Excess of 5 years — $ (1) (97) (98) $ Total (745) 239 (360) (866) FINANCIAL CONDITION s Operatingii Cash FlowFF Year Ended December 31, 2021 Comparem d to Year Ended December 31, 2020 — Cash used in operating activities totaled $206 million in the year ended December 31, 2021 compared to cash provided by operating activities of $3.337 billion in the year ended December 31, 2020. The unfavorablea change of $3.543 billion was primarily driven by lower cash from operations due to Winter Storm Uri impacts and higher cash margin deposits posted with third-parties. Cash margin deposits posted were gas and coal forward driven by net pre-tax unrealized losses on commodity hedging transactions reflecting power, natural market curves that moved up during the year ended December 31, 2021. ff t Depreciation and amortization — Depreciation and amortization expense reported as a reconciling adjustment in the consolidated statements of cash flows exceeds the amount reported in the consolidated statements of operations by $297 million, $311 million and $236 million for the year ended December 31, 2021, 2020 and 2019, respectively. The difference represented amortization of nuclear fuel costs in the consolidated statements of operations consistent ff 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. , which is reported as fuel ff sw Investingii Cash FlowFF Year Ended December 31, 2021 Compared to YearYY Ended December 31, 2020 — Cash used in investing activities totaled $1.153 billion and $1.572 billion in the years ended December 31, 2021 and 2020, respectively. Capita al expenditures totaled $1.033 billion and $1,259 million in the years ended December 31, 2021 and 2020, respectively, and. consisted of the following: , including LTSA prepayments t al expenditures Capita Nuclear fuel purchases Growth and development expenditures t al expenditures Capita $ Year Ended December 31, 2021 2020 549 $ 44 440 1,033 $ 770 88 401 1,259 Cash used in investing activities in the year ended December 31, 2021 and 2020 also reflected net purchases of environmental allowances of $213 million and $339 million, respectively. In the year ended December 31, 2021 and 2020, we received insurance proceeds of $89 million and $35 million, respectively. 75 Financing Cash Flowsw Year Ended December 31, 2021 Comparem ncing activities totaled $2.274 billion in the year ended December 31, 2021 and cash used in financing activities totaled $1.796 billion in the year ended December 31, 2020. The change was primarily driven by: Ended December 31, 2020 — Cash provided by finaff d to YearYY • • • • • • proceeds of $1.975 billion from the issuance of preferred stock in 2021; the issuance of $1.250 billion principal amount of Vistra Operations senior unsecured notes in 2021; $500 million in cash received fromff in 2021; redemption of $747 million principal amount of outstanding of Vistra unsecured senior notes in 2020; net repayment of $350 million in short-term borrowings under the Revolving Credit Facility in 2020; and repayment of $100 million of term loans under the Vistra Operations Credit Facilities in 2020; the sale of a portion of the PJM capacity that cleared for Planning Years 2021-2022 partially offset by: • $471 million in cash paid for share repurchases in 2021; and • net repayments of $300 million under the Receivables Facility in 2021 compared to net repayments of $150 million in 2020. Debt Activityii See Note 10 to the Financial Statements for details of the Receivables Facility and Repurchase Facility and Note 11 to the Financial Statements for details of the Vistra Operations Credit Facilities and other long-term debt. ll Available Liquidi tyii ii The following tabla e summarizes changes in availablea liquidity for the year ended December 31, 2021: Cash and cash equivalents Vistra Operations Credit Facilities — Revolving Credit Facility Vistra Operations — Alternate Letter of Credit Facility Total available liquidity (a) December 31, 2021 1,325 $ 1,254 — 2,579 $ December 31, 2020 406 $ 1,988 5 2,399 $ $ $ Change 919 (734) (5) 180 ____________ (a) Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively. See Note 10 to the Financial Statements for detail on our accounts receivablea financing. a The $180 million increase in available liquidity for the year ended December 31, 2021 was primarily driven by proceeds of $1.975 billion from the issuance of preferred stock in 2021, cash received from the issuance of $1.250 billion principal amount of Vistra Operations senior unsecured notes in May 2021 and $500 million in cash received from the sale of a portion ity that cleared for Planning Years 2021-2022, partially offset by cash used in operations, including higher of the PJM capac cash margin deposits posted with third parties, $1.033 billion of capita al expenditures (including LTSA prepayments, nuclear a $734 increase in letters of credit outstanding under the Revolving Credit fuel and development and growth expenditures), t Facility, $290 million in dividends paid to stockholders, $471 million in cash paid forff share repurchases, $300 million in net ncing facilities and the maturity of a $250 million Alternate LOC Facility. cash repayments under the accounts receivable finaff Additionally, in February 2022, we entered into a $1.0 billion senior secured commodity-linked revolving credit facility (the Commodity-Linked Facility) (see Note 11 to the Financial Statements). Based upon our current internal finaff ncial forecasts, we believe that we will have sufficient liquidity to fund our anticipated cash requirements through at least the next 12 months. Our operational cash flows tend to be seasonal and weighted toward the second half of the year. If the Company experienced a significant reduction in revenues or increases in costs or collateral requirements, such as a result of Winter Storm Uri, the Company believes it would have additional alternatives to maintain access to liquidity, including drawing upon available liquidity, accessing additional sources of capital or reducing capita al expenditures, planned voluntary debt repayments or operating costs. 76 The maturities of our long-term debt are relatively modest until 2023. Interest payments on long-term debt are expected to total approximately $499 million in 2022, $946 million in 2023-2024, $753 million in 2025-2026 and $372 million thereafter. See Note 11 to the Financial Statements forff details of our long-term debt maturities. Our obligations under commodity purchase and services agreements, including capac and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase t commitments, are expected to total approximately $1.850 billion in 2022, $1.250 billion in 2023-2024, $700 million in 2025-2026 and $585 million thereafter. See Note 12 to the Financial Statements forff maturities of lease liabia lities and Note 13 to the Financial Statements for commitments related to long-term service and maintenance contracts. ity payments, nuclear fuel a ff Capital ii Expenditures Estimated 2022 capita al expenditures and nuclear fuel ff purchases as of November 5, 2021 total approximately $1.814 billion and include: • • • • • $1.002 billion for solar and energy storage development; $570 million for investments in generation and mining facilities; $117 million for nuclear fuel purchases; $72 million for information technology and other corporate investments; and $53 million for other growth expenditures. Liquidit y Ett ffecE ii ts of Commodity Htt edgiHH ngii and Trading Activitiii es We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value. We use cash, letters of credit and other forms of credit support to satisfy such collateral posting obligations. See Note 11 to the Financial Statements for discussion of the Vistra Operations Credit Facilities. ff 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 al and other business purposes, including reducing borrowings under credit facilities, or is required to be used for working capita al and other corporate purposes. With respect deposited in a separate account and restricted from being used for working capita letters of credit for such cash collateral. In to over-the-counter transactions, counterparties generally have the right to substitutet 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. ff t As of December 31, 2021, we received or posted cash and letters of credit for commodity hedging and trading activities as follows: • • • • $1.263 billion in cash has been posted with counterparties as compared to $257 million posted at December 31, 2020; $39 million in cash has been received from counterparties as compared to $33 million received at December 31, 2020; $1.558 billion in letters of credit have been posted with counterparties as compared to $878 million posted at December 31, 2020; and $35 million in letters of credit have been received from counterparties as compared to $18 million received at December 31, 2020. See Collateral Support Obligati i ons below forff information related to collateral posted in accordance with the PUCT and ISO/RTO rules. 77 Income Tax Payma entstt In the next 12 months, we do not expect to make federal income tax payments dued a to Vistra's loss position in 2021 and use mately $35 million in state income tax payments, offset by $11 million in We expect to make approxi rr of NOL carryforwards. state tax refunds, and less than $1 million in TRA pRR ayments in the next 12 months. For the year ended December 31, 2021, there were no federal income tax payments, $52 million in state income tax payments, $2 million in state income tax refunds and $2 million in TRA payments. Capitalization Our capita alization ratios consisted of 56% and 52% long-term debt (less amounts due currently) and 44% and 48% stockholders' equity at December 31, 2021 and 2020, respectively. Total long-term debt (including amounts due currently) to capita alization was 56% and 53% at December 31, 2021 and 2020, respectively. Finaii ncial CoveCC nantstt The Credit Facilities Agreement includes a covenant, solely with respect to the Revolving Credit Facility and solely during a compliance period (which, in general, is appl icable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $300 million) exceed 30% of the revolving commitments), that requires the consolidated first-lien net leverage ratio not exceed 4.25 to 1.00. As of December 31, 2021, we were in compliance with this financ ial covenant. a ff See Note 11 to the Financial Statements for discussion of other covenants related to the Vistra Operations Credit Facilities. ll Collat tt ertt al Support Obligat ions ll ff 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 lien on all of Vistra Operations' assets (which ranks pari passu with the Vistra Operations Credit Facilities) effectively a first that contractually enablea ien 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 forff 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. s the RCT to be paid (up to $975 million) before the other first-l ff The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to returnt customer deposits, if necessary. Under these rules, at December 31, 2021, Vistra has posted letters of credit in the amount of $74 million with the PUCT, which is subject to adjustments. The ISOs/RTOs we operate in have rules in place to assure adequate creditworthiness of parties that participate in the markets operated by those ISOs/RTOs. Under these rules, Vistra has posted collateral support totaling $420 million in the form of letters of credit, $20 million in the form of a surety bond and $1 million of cash at December 31, 2021 (which is subject to daily adjustmd ents based on settlement activity with the ISOs/RTOs). // Material Cross-Default/ Acc e ll elerati on Provisions lure Certain of our contractual arrangements contain provisions that could result in an event of default if there were a faiff under financing arrangements to meet payment terms or to observe covenants that could result in an acceleration of payments due. Such provisions are referre d to as "cross-default" or "cross-acceleration" provisions. ff A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of $300 million may result in a cross default under the Vistra Operations Credit Facilities. Such a default would allow the lenders to accelerate the maturity of outstanding balances under such facilities, which totaled approximately $2.54 billion at December 31, 2021. 78 Each of Vistra Operations' (or its subsidiaries') commodity hedging agreements and interest rate swap aa greements 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 agreement that results in the acceleration of such debt, would give such counterparty under threshold defined in the applicablea these hedging agreements the right to terminate its hedge or interest rate swap a greement with Vistra Operations (or its a applicable subsidiary) and require all outstanding obligations under such agreement to be settled. Under the Vistra Operations Senior Unsecured Indentures a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more may result in a cross default under the Vistra Operations Senior Unsecured Notes, the Senior Secured Notes, the Vistra Operations Credit Facilities, the Receivables Facility, the Alternate LOC Facilities, and other current or future documents evidencing any indebtedness for borrowed money by the applicablea borrower or issuer, as the case may be, and the applicable Guarantor Subsidiaries party thereto. and the Vistra Operations Senior Secured Indenture, t t 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 brr y contract. The Receivablea s 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 Receivablea s 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 dued If this cross-default provision is triggered, a termination event under the Receivables Facility would occur and the Receivables Facility may be terminated. before its stated maturity. 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 Receivablea s Facility or the Vistra Operations Credit Facilities. If this cross-default provision is triggered, a termination event under the Repurchase Facility would occur and the Repurchase Facility may be terminated. Under the Alternate LOC Facilities, a defauff lt under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more, may result in a termination of the Alternate LOC Facilities. Under the Secured LOC Facilities, a defauff lt 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. s Guaranteett See Note 13 to the Financial Statements forff discussion of guarantees. COMMITMENTS AND CONTINGENCIES See Note 13 to the Financial Statements forff discussion of commitments and contingencies. 79 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 tors such as commodity prices, interest rates and counterparty credit. Our exposure market conditions that affect economic facff tors, including the size, duration and composition of our energy and financial portfolio, to market risk is affected by several facff as well as the volatility and liquidity of markets. Instruments used to manage this exposure include interest rate swapsa to hedge debt costs, as well as exchange-traded, over-the-counter contracts and other contractual arrangements to hedge commodity prices. t Riskii Oversigh rr We manage the commodity price, counterparty credit and commodity-related operational risk related to the competitive energy business within limitations establia shed 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 , market price validation and reporting, and portfolio valuation and reporting, including mark-to-market, transaction capture VaR and other risk measurement metrics. a Vistra has a risk management organization that enforces applicablea risk limits, including the respective policies and procedures to ensure complim ance with such limits, and evaluates the risks inherent in our businesses. Commoditdd y Ptt ricPP e 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. t t t In managing energy price risk, we enter into a variety of market transactions including, but not limited to, short- and long- ncial contracts and bilateral contracts with term contracts for physical delivery, exchange-traded and over-the-counter finaff customers. Activities include hedging, the structuring arrangements and proprietary trading. We of long-term contractual 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. t t VaR Methodology — A VaR methodology is used to measure the amount of market risk that exists within the portfolio loss given a specified under a variety of market conditions. The resultant VaR produces an estimate of a portfolio's potential forff 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 io's value based on assumed market conditions for liquid markets. The use of this method requires estimate changes in a portfolff a number of key assumptim ons, 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 tablea below details a VaR measure related to various portfolios of contracts. 80 VaR faa orff Underlying Generation Assets and Energy-Rr d ConCC tracts — This measurement estimates the potential loss elatell 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. Month-end average VaR Month-end high VaR Month-end low VaR Year Ended December 31, 2021 2020 $ $ $ 424 684 222 $ $ $ 234 361 164 The VaR risk measures in 2021 were primarily comparablea measure in 2021 is driven by a larger net open position, higher forwa ff compared to the prior year. to the prior year. The increase in month-end high VaR risk rd prices and an increase in market implied volatility as Interett st Rate Riskii The following tablea provides information concerning our financial instruments at December 31, 2021 and 2020 that are sensitive to changes in interest rates. Debt amounts consist of the Vistra Operations Credit Facilities. See Note 11 to the Financial Statements for furff ther discussion of these financial instruments. Expected Maturity Date 2022 2023 2024 2025 2026 2021 Total Carrying Amount 2021 Total Fair Value 2020 Total Carrying Amount 2020 Total Fair Value There- after $ 29 $ 28 $ 29 $2,457 $ — $ — $2,543 $ 2,518 $2,572 $ 2,565 1.85 % 1.85 % 1.85 % 1.85 % — % — % 1.85 % 1.90 % Long-term debt, including current maturities (a): Variablea rate debt amount Average interest rate (b) Debt swapped to fixed (c): Notional amount $ — $2,300 Average pay rate Average receive rate 3.77 % 4.10 % 4.75 % 4.77 % 4.77 % — % 1.86 % 2.24 % 2.98 % 3.01 % 3.01 % — % $ — $ — $2,300 $ — $4,600 $4,600 (a) Unamortized premiums, discounts and debt issuance costs are excluded fromff (b) The weighted average interest rate presented is based on the rates in effecff (c) the table. t at December 31, 2021. Interest rate swaps have maturity dates through July 2026. Excludes $2.12 billion of debt swapped matched against the terms of $2.12 billion of debt swapped such swapsa to variable that is to fixed that effectively fix the out-of-the-money position of (see Note 11 to the Financial Statements). a a As of December 31, 2021, 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 swapsa discussed in Note 11 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 16 to the Financial Statements for furthe r discussion of this exposure. ff 81 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 $2.357 billion at December 31, 2021. As of December 31, 2021, Retail segment credit exposure totaled approxi mately $900 million of primarily trade accounts receivable. Cash deposits and letters of credit held as collateral for these receivables totaled $60 million, resulting in a net exposure of $840 million. Allowances forff 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. a As of December 31, 2021, aggregate Texas, East and Sunset segments credit exposure totaled $1.457 billion including $687 million related to derivative assets and $770 million of accounts receivable, after taking into account master netting agreement provisions but excluding collateral impacts. Including collateral posted to us by counterparties, our net Texas, East and Sunset segments exposure was $1.390 billion, that presents the distribution of credit exposure by counterparty credit quality at December 31, as seen in the following tablea 2021. Credit collateral includes cash and letters of credit but excludes other credit enhancements such as guarantees or liens on assets. Investment grade Below investment grade or no rating Totals Exposure Before Credit Collateral 947 510 1,457 $ $ $ $ Credit Collateral Net Exposure 923 467 1,390 24 43 67 $ $ Significant (i.e., 10% or greater) concentration of credit exposure exists with one counterparty, which represented an aggregate $619 million, or 45%, of the total net exposure. We view exposure to this counterparty to be within an acceptablea 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 in the financial statements and are excluded from the detail above. favorablea a considering current market conditions and therefore represent economic risk if the counterparties do not perform. commitments are not marked-to-market Such contractual commitments may contain pricing that is t 82 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, capita al 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 assumptim ons, any such forward-looking statement involves uncertainties and risks and is qualified in its entirety by reference to the discussion under Item 1A. Riskii 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 fromff those projected in or implied by such forward-looking statements: al allocation, capita ll • • • • • • • • • • • • ▪ 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 legislaturt es 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; changes in and compliance with environmental and safety l aws and policies, including the Coal Combustion Residuad ls 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 recession or economic downturn; investor sentiment relating to climate change and utilization of fossil fuels reduce demand for, the severity, magnitude our results of operations, financial condition and cash flows; the severity, magnitude and duration of extreme weather events (including Winter Storm Uri), drought and limitations on access to water, and other weather conditions and natural phenomena, contingencies and uncertainties relating thereto, most of which are diffiff cult 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, wars or terrorist or cybersecurity threats or activities; risk of contract performance claims by us or our counterparties, and risks of, or costs associated with, pursuing or defending such claims; or increase potential volatility in the market price of, our common stock; t and duration of pandemics, including the COVID-19 pandemic, and the resulting effects on in connection with power generation could ff ff ff ff t t t 83 • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • t t t t ff ff ff a gas; laws; s fromff al expenditures; gas, market heat serve customers; gas inventories and transportation and al market conditions and the potential commodity prices, including the price of natural ies to reduce congestion and improve busbar power prices; ce and regulators regarding our compliance with applicablea counterparties in the amount or at the time expected, if at all; to our competitors; ity procurement processes in oil and other refined products; t d outage risk, including managing risk associated with Capacity Performance in PJM and nd assumptim ons about the benefits of state- or federal-based subsidies to our market competition, and the our ability to collect trade receivablea our ability to attract, retain and profitablya restrictions on competitive retail pricing or direct-selling businesses; adverse publicity associated with our retail products or direct selling businesses, including our ability to address the marketplat changes in wholesale electricity prices or energy commodity prices, including the price of natural changes in prices of transportation of natural gas, coal, fuel sufficiency of, access to, and costs associated with coal, fuel oil, and natural storage thereof; changes in the ability of counterparties and suppliers to provide or deliver commodities, materials, or services as needed; beliefs aff corresponding impacm ts on us, including if such subsidies are disproportionately availablea the effects of, or changes to, market design and the power, ancillary services, and capac 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 unfavorablea rates and interest rates; population growth or decline, or changes in market supply or demand and demographic patterns; our ability to mitigate force performance incentives in ISO-NE; efforts to identify opportunit 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 capita commercial bank market and capita international credit markets; access to capital, the attractiveness of the cost and other terms of such capita refinancing efforts, our ability to maintain prudent financial leverage and achieve our capita 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 a comparable cash dividend on a quarterly basis; our ability to implement and successfully execute upon and integration of mergers, acquisitions and/or joint venturet t divestitures 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 facff 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 availabila a potential adverse effects if labor independent contractor status; changes in assumptim ons 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 liabia lity 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; 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 a capture our strategic and growth initiatives, including the completion activity, the identification and completion of sales and activity, and the completion and commercialization of our other business development and construction ity of qualified personnel, and the disputes or grievances were to occur or changes in laws or regulations relating to the full amount of projected operational and financial synergies relating to such transactions; and tors affecting our liquidity position and financial condition; including availability of funds in capia tal markets; al allocation, performance, and cost-saving al and the success of financing and impact of disruptions in U.S. and u t 84 • 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 facff tors 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 fromff 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 firff ms 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 , but do not guarantee the accuracy and completeness of such information. While we believe that sources believed to be reliablea , we have not independently investigated or verified the each of these studies, publications, reports and other sources is reliablea 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 assumptim ons 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. 85 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, 2021 and 2020, 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, 2021, 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 financ ial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America. ff 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, 2021, based on criteria established in Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway e Internal Control—Integrated Commission and our report dated February 2rr 5, 2022, 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 applicablea 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 freff e of material misstatement, whether dued 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 finff ancial 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 finaff ncial 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 Obligation — Referff to Notes 1 and 8 to the financial statements Critical Audit MatMM ter Description ights holders based on cash savings in income tax resulting fromff The Company has a tax receivable agreement (TRA) obligation that requires the Company to make annual payments to the a step up in the tax basis of certain assets upon TRA rRR bligation is based on the discounted amount of forecasted emergence from bankruptcy in 2016. The carrying value of the TRA oRR payments to the TRA rRR bligation requires management to make ast of taxable income for a period of approximately 35 years. significant estimates and assumptim ons in preparing its forec Changes to either the estimated timing or amount of expected TRA pRR ayments impact the carrying value of the obligation. As of December 31, 2021, the carrying value of the TRA oRR ights holders. Determining the carrying value of the TRA oRR bligation totaled $395 million. ff 86 Given the significant judgements made by management to estimate the TRA oRR evaluate the reasonablea a high degree of auditor judgement and an increased extent of effort, bligation, performing audit procedures to ness of management’s estimate and assumptions related to the estimated future taxable income required including the need to involve our income tax specialists. ff How the Critical Audit MatMM ter WasWW Addressed in thett Audit Our audit procedures related to the evaluation of estimated future ff taxable income included the folff lowing, among others: • We tested the effectiveness of controls over management’s determination of the TRA oRR bligation carrying amount, including controls over developing estimated futuret taxablea income. • With the assistance of our income tax specialists, we evaluated the following elements in testing management’s estimated future ff taxable income: ◦ ◦ The application of tax laws and regulations Future reversals of existing temporary differences, including the timing and amount of loss carryforwards • We evaluated the reasonableness of management’s estimates of future taxable income by comparing the estimates to: ◦ ◦ ◦ Historical taxable income Internal communications to management and the Board of Directors Forecasted information included in the Company's press releases as well as in analyst and industry reports forff Company the • We assessed the consistency of future ff taxable income with evidence obtained in other areas of the audit. Fair Value Measurements — Level 3 Derivative Assets and Liabilities — Referff statements to Notes 1 and 15 to the financial Critical Audit MatMM ter Description The Company has assets and liabilities whose fair values are based on complex proprietary models and/or unobservable inputs. These financial instruments can span a broad array of product types and generally include (1) electricity purchases and sales gas options; that include power and heat rate positions; (2) physical electricity options, spread options, swaptia (3) forward purchase contracts of congestion revenue rights and financial transmission rights; and (4) contracts for natural gas, coal, and environmental allowances. Under accounting principles generally accepted in the United States of America, these financial instruments are generally classified as Level 3 derivative assets or liabilities. As of December 31, 2021, the fair value of the Level 3 derivative assets and liabilities totaled $442 million and $802 million, respectively. ons, and natural t t Given management uses complex proprietary models and/or unobservable inputs to estimate the fair value of Level 3 derivative assets and liabia lities, performing audit procedures to evaluate the reasonableness of the fair value of Level 3 derivative assets and liabia lities required a high degree of auditor judgment and an increased extent of effort, including the need to involve our energy commodity fair value specialists who possess significant quantitative and modeling expertise. How the Critical Audit MatMM ter WasWW Addressed in thett Audit Our audit procedures related to the evaluation of the fair value of Level 3 derivative assets and liabilities included the foll among others: ff owing, • We test ded hthe effectiiveness of cont lrols over d iderivatiive asset a dnd lili biabilili yty pricprice verifiifica ition of ilillili idquid iprice curves. lvaluatiions, iincl di ludi gng cont lrols lrelat ded to • We bobtaiinedd thhe Compa yny's com lplete lili dunderstanding 31, 2021, to co finfirm our isti gng of d iderivatiive assets dand lili biabilili ities nding. nding of hthe tyypes of iinstruments outstanding. dand lrelat ded f ifair v lalues as of Dece bmber • We assessedd thhe consiistency by byy whi hhich managgement hhas 87 appliiedd signi ignifificant l unobse b rvable v lalua ition as bl sumptions. i • i hWith hthe a issistance of our ene gyrgy com dimodi yty f ifair v lalue spe ici laliists, we ddevello dped i dinde lvalue of a sam lple of Level l 3 deriiva itive iinstruments a dnd comparedd our es itimates to thhe Compa yny's dpendent es itimates of thhe f ifair iestimates. d /s/ Deloitte & Touche LLP Dallas, Texas February 25, 2022 We have served as the Company's auditor since 2002. 88 VISTRA CORP. CONSOLIDATED STATEMENTS OF OPERATRR IONS (Millions of Dollars, Except Per Share Amounts) Operating revenues (Note 5) Fuel, purchased power costs and delivery fees Operating costs Depreciation and amortization Selling, general and administrative expenses Impairment of long-lived and other assets Operating income (loss) Other income (Note 21) Other deductions (Note 21) Interest expense and related charges (Note 21) Impacts of Tax Receivablea Agreement (Note 8) Equity in earnings of unconsolidated investment (Note 21) Income (loss) before income taxes Income tax (expense) benefit (Note 7) Net income (loss) Net (income) loss attributablea Net income (loss) attributablea Weighted average shares of common stock outstanding: to noncontrolling interest to Vistra Basic Diluted Net income (loss) per weighted average share of common stock outstanding: Basic Diluted See Notes to the Consolidated Financial Statements. Year Ended December 31, 2021 2020 2019 $ 12,077 (9,169) (1,559) (1,753) (1,040) (71) (1,515) 140 (16) (384) 53 — (1,722) 458 (1,264) (10) (1,274) $ 11,443 (5,174) (1,622) (1,737) (1,035) (356) 1,519 34 (42) (630) 5 4 890 (266) 624 12 636 $ $ 11,809 (5,742) (1,530) (1,640) (904) — 1,993 56 (15) (797) (37) 16 1,216 (290) 926 2 928 482,214,544 482,214,544 488,668,263 491,090,468 494,146,268 499,935,490 (2.69) $ (2.69) $ 1.30 1.30 $ $ 1.88 1.86 $ $ $ $ CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Millions of Dollars) Net income (loss) Other comprehensive income (loss), net of tax effects: Year Ended December 31, 2021 2020 2019 $ (1,264) $ 624 $ 926 Effects related to pension and other retirement benefit obligations (net of tax expense (benefit) of $9, ($5) and ($4)) Total other comprehensive income (loss) Comprehensive income (loss) Comprehensive income (loss) attributablea Comprehensive income (loss) attributablea to noncontrolling interest to Vistra 32 32 (1,232) (10) (18) (18) 606 12 $ (1,242) $ 618 $ (8) (8) 918 2 920 See Notes to the Consolidated Financial Statements. 89 VISTRA CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions of Dollars) Cash flowff s — operating activities: Net income (loss) Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities: Depreciation and amortization Deferred income tax expense (benefit), net Impairment of long-lived and other assets Loss on disposal of investment in NELP Unrealized net (gain) loss from mark-to-market valuations of commodities Unrealized net (gain) loss from mark-to-market valuations of interest rate swaps Change in asset retirement obligation liability Asset retirement obligation accretion expense Impacts of Tax Receivablea Bad debt expense Stock-based compensation Other, net Agreement Changes in operating assets and liabilities: Accounts receivablea — trade Inventories Accounts payable — trade Commodity and other derivative contractual assets and liabia lities Margin deposits, net Uplift securitization proceeds receivablea Accrued interest Accrued taxes Accrued employee incentive Tax Receivable Agreement payment Asset retirement obligation settlement Major plant outage deferral Other — net assets Other — net liabilities from ERCOT Cash provided by (used in) operating activities Cash flows — investing activities: t al expenditures, including nuclear fuel purchases and LTSA Capita prepayments Ambit acquisition (net of cash acquired) Crius acquisition (net of cash acquired) Proceeds from sales of nuclear decommissioning trust Investments in nuclear decommissioning trust fund securities Proceeds from sales of environmental allowances Purchases of environmental allowances Insurance proceeds Proceeds from sale of assets r fund securities 90 Year Ended December 31, 2021 2020 2019 $ (1,264) $ 624 $ 926 2,050 (475) 71 — 759 (134) (5) 38 (53) 110 47 41 (228) (100) 402 32 (1,000) (544) 13 (20) (68) (2) (88) 2 (27) 237 (206) (1,033) — — 483 (505) 392 (605) 89 30 2,048 230 356 29 1,876 281 — — (231) (696) 155 7 43 (5) 110 65 (22) (33) (59) (40) 27 (20) — (20) 22 39 — (118) 2 219 (91) 3,337 (1,259) — — 433 (455) 165 (504) 35 24 220 (48) 53 37 82 47 (12) (88) (44) (221) 98 170 — 80 (4) 1 (2) (121) (19) (22) 142 2,736 (713) (506) (374) 431 (453) 197 (322) 23 6 VISTRA CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions of Dollars) Year Ended December 31, 2021 2020 2019 (6) (1,717) — 6,507 (7,109) — — — 111 650 (300) (203) (656) (243) 6 (1,237) (218) 693 475 Other, net Cash used in investing activities Cash flows — finaff ncing activities: Issuances of preferred stock Issuances of long-term debt Repayments/repurchases of debt Borrowings under Term Loan A Repayment under Term Loan A Proceeds from forward capaa Net borrowings/(payments) under accounts receivable finaff Borrowings under Revolving Credit Facility Repayments under Revolving Credit Facility Debt tender offer and other financing fees Share repurchases Dividends paid to stockholders Other, net city agreement ncing Cash provided by (used in) finaff ncing activities (4) (1,153) 2,000 1,250 (381) 1,250 (1,250) 500 (300) 1,450 (1,450) (13) (471) (290) (21) 2,274 (11) (1,572) — — (1,008) — — — (150) 1,075 (1,425) (17) — (266) (5) (1,796) Net change in cash, cash equivalents and restricted cash Cash, cash equivalents and restricted cash — beginning balance Cash, cash equivalents and restricted cash — ending balance 915 444 1,359 $ $ (31) 475 444 $ See Notes to the Consolidated Financial Statements. 91 VISTRA CORP. CONSOLIDATED BALANCE SHEETS (Millions of Dollars) December 31, 2021 2020 Current assets: ASSETS Cash and cash equivalents Restricted cash (Note 21) Trade accounts receivablea — net (Note 21) Income taxes receivable Inventories (Note 21) Commodity and other derivative contractual assets (Note 16) Margin deposits related to commodity contracts Uplift securitization proceeds receivabla e fromff Prepaid expense and other current assets ERCOT (Note 1) Total current assets Restricted cash (Note 21) Investments (Note 21) Operating lease right-of-use assets (Note 12) Property, plant and equipment — net (Note 21) Goodwill (Note 6) Identifiable intangible assets — net (Note 6) Commodity and other derivative contractual assets (Note 16) Accumulated deferred income taxes (Note 7) Other noncurrent assets Total assets LIABILITIES AND EQUITY Current liabilities: Accounts receivablea financing (Note 10) Long-term debt due currently (Note 11) Trade accounts payable Commodity and other derivative contractual liabila Margin deposits related to commodity contracts Accrued income taxes Accrued taxes other than income Accrued interest Asset retirement obligations (Note 21) Operating lease liabilities (Note 12) Other current liabilities ities (Note 16) currently (Note 11) Total current liabilities Long-term debt, less amounts dued Operating lease liabilities (Note 12) Commodity and other derivative contractual liabila Accumulated deferred income taxes (Note 7) Tax Receivablea Asset retirement obligations (Note 21) Other noncurrent liabilities and deferred credits (Note 21) Agreement obligation (Note 8) ities (Note 16) Total liabilities 92 $ $ $ 1,325 21 1,397 15 610 2,513 1,263 544 195 7,883 13 2,049 40 13,056 2,583 2,146 250 1,302 361 29,683 $ $ — $ 254 1,515 3,023 39 — 207 143 104 5 553 5,843 10,477 38 804 — 394 2,346 1,489 21,391 406 19 1,279 — 515 748 257 — 205 3,429 19 1,759 45 13,499 2,583 2,446 258 838 332 25,208 300 95 880 789 33 16 210 131 103 8 471 3,036 9,235 40 624 1 447 2,333 1,131 16,847 VISTRA CORP. CONSOLIDATED BALANCE SHEETS (Millions of Dollars) Commitments and Contingencies (Note 13) Total equity (Note 14): Preferred stock, number of shares authorized — 100,000,000; Series A (liquidation preference — $1,000; shares outstanding: December 31, 2021 — 1,000,000; December 31, 2020 — zero); Series B (liquidation preference — $1,000; shares outstanding: December 31, 2021 — 1,000,000; December 31, 2020 — zero) Common stock (par value — $0.01; number of shares authorized — 1,800,000,000) (shares outstanding: December 31, 2021 — 469,072,597; December 31, 2020 — 489,305,888) al Treasury stock, at cost (shares: December 31, 2021 — 63,856,879; December 31, 2020 — 41,043,224) Additional paid-in-capita Retained deficit Accumulated other comprehensive loss Stockholders' equity Noncontrolling interest in subsidiary Total equity Total liabilities and equity $ e Notes to the Consolidated Financial Statements. December 31, 2021 2020 2,000 5 (1,558) 9,824 (1,964) (16) 8,291 1 8,292 29,683 $ — 5 (973) 9,786 (399) (48) 8,371 (10) 8,361 25,208 93 Balances at December 31, 2018 Stock repurchases Shares issued for tangible equity unit contracts Effeff cts of stock-based compensation Net loss Dividends declared on common stock Adoption of new accounting standards Pension and OPEB liability — change in funded status Other Balances at December 31, 2019 Effects of stock-based compensation Net income (loss) Dividends declared on common stock Adoption of new accounting standard Pension and OPEB liability — change in funded statust Investment by noncontrolling interest Other Balances at December 31, 2020 Stock repurchases Series A Preferred Stock issued Series B Preferred Stock issued Effects of stock-based compensation Net income (loss) Dividends declared on common stock Pension and OPEB liability — change in funded statust Investment by noncontrolling interest VISTRA CORP. CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (Millions of Dollars) Preferred Stock Common Stock Treasury Stock Additional Paid-In Capital Retained Deficit Accumulated Other Comprehensive Income (Loss) Total Stockholders' Equity Noncontrolling Interest in Subsidiary Total Equity $ — $ — 5 $ (778) $10,107 $(1,449) $ — (641) — — — — — — — — — — — — — — — — 446 (446) — — — — — — 62 — — — — (2) — — 928 (243) (2) — 2 (22) $ — 7,863 $ (641) 4 $ 7,867 (641) — — — — — — (8) — — 62 928 (243) (2) (8) — — — (2) — — — (1) — 62 926 (243) (2) (8) (1) $ — $ 5 $ (973) $ 9,721 $ (764) $ (30) $ 7,959 $ 1 $ 7,960 — — — — — — — — — — — — — — — — — — — — — 65 — — — — — — — 636 (266) (4) — — (1) — — — — 65 636 (266) (4) (18) (18) — — — (1) — (12) — — — 1 — 65 624 (266) (4) (18) 1 (1) $ — $ 5 $ (973) $ 9,786 $ (399) $ (48) $ (585) 1,000 — — 1,000 — — — — — — — — — — — — — — — (10) (15) 60 — — — (1,274) — (290) — — — — 94 8,371 $ (585) (10) $ 8,361 (585) — — — — 32 — 990 985 60 (1,274) (290) 32 — — — — 10 — — 1 990 985 60 (1,264) (290) 32 1 VISTRA CORP. CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (Millions of Dollars) Preferred Stock Common Stock Treasury Stock Additional Paid-In Capital Retained Deficit Accumulated Other Comprehensive Income (Loss) Total Stockholders' Equity Noncontrolling Interest in Subsidiary Total Equity — — — 3 (1) — 2 — 2 $ 2,000 $ 5 $(1,558) $ 9,824 $(1,964) $ (16) $ 8,291 $ 1 $ 8,292 Other Balances at December 31, 2021 See Notes to the Consolidated Financial Statements. 95 VISTRA CORP. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES Descriptiontt of 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. 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 Vistra Energy Corp. to Vistra Corp. (Vistra) to distinguish from end users. Effective July 2, 2020, we changed our name fromff s (many of which use "energy" companies that are involved in the exploring for, producing, refining, or transporting fossil fuel gas business in their names) and to better reflect or integrated business model, which combines a retail electricity and natural 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, reliablea ff and affordabl e power. ff t t Vistra has six reportablea segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure. See Note 20 for further information concerning our reportable business segments, including an update of our reportable segments in the third quarter of 2020. Wintertt Stormtt 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 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 deliverability issues and our coal-fueled power plants driven by coal gas-fueled power plants driven by natural fuel handling challenges, high fuel costs, and high retail load costs. t t t Uplift Sff ii ecSS uritization Proceeds Receivable from ERCOT — 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 uplifted 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 $2.1 billion financing and the methodology for allocation of proceeds to the LSEs. In December 2021, ERCOT finalized the amount of allocations to the LSEs, and we expect to receive approximately $544 million of proceeds from ERCOT. The Company accounted for the proceeds we will receive by analogy to the contribution itff Entities - Revenue Recognition and the grant model within Accounting Standards Codification (ASC) 958-605, Not-for-Prof model within International Accounting Standard 20, Accounting for Government Grants att nd Disclosure of Government Assistance , as a reduction to expenses in the statements of operations in the annual period for which the proceeds are intended to compensate. The proceeds are expected to be received from ERCOT in the second quarter of 2022, and 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 effectuat e the $2.1 billion funding approved in the Debt Obligation Order. The associated expense reduction is reflected in fuel, purchased power costs and delivery fees within our consolidated statements of operations as that is where the initial costs for which we are being compensated were recorded. ii t ff ff The final financial impact of Winter Storm Uri continues to be subject to the outcome of potential litigation arising from the event, or any corrective action taken by the State of Texas, ERCOT, the RCT, or the PUCT to resettle pricing across any supply, wholesale pricing of generation, or allocating the financial impacts of market-wide portion of the supply chain (i.e., fuel load shed ratablya across all retail market participants), that is currently being considered or may be considered by any such parties. ff 96 COVID-II 19 Pandemic In March 2020, the World Health Organization categorized the novel coronavirus (COVID-19) as a pandemic, and the U.S. Government declared the COVID-19 outbreak a national emergency. The U.S. government has deemed electricity generation, transmission and distribution as "critical infrastructure" providing essential services during this global emergency. As a provider of critical infrastructure, Vistra has an obligation to provide critically needed power to homes, businesses, hospitals and other customers. Vistra remains focff used on protecting the health and well-being of its employees and the communities in which it operates while assuring the continuity of its business operations. t The Company's consolidated financial statements reflect estimates and assumptim ons made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impact of COVID-19 on the assumptim ons and estimates used and determined that there have been no material adverse impacm ts on the Company's results of operations for the years ended December 31, 2021 and 2020. In response to the global pandemic related to COVID-19, the CARES Act was signed into law in March 2020. See Note 7 for a summary of certain anticipated tax-related impacts of the CARES Act to the Company. Recent Developments Green Finance Framework — In December 2021, we announced the publication of our Green Finance Framework, which allows us to issue green finaff ncial instruments to fund new or existing projects that support renewabla e energy and energy efficiency with alignment to our ESG initiatives. See below and Note 14 for more information concerning the Series B Preferred Stock, which was issued in December 2021 under the Green Finance Framework. ff d StocS Series B Preferre k OffeO ring — On December 10, 2021, we issued 1,000,000 shares of Series B Preferred Stock in a private offering (Series B Offering) under our Green Finance Network. The net proceeds of the Series B Offering were approximately $985 million, after deducting underwriting commissions and offering expenses. We intend to use the proceeds from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments. See Note 14 forff more information concerning the Series B Preferred Stock. Commodity-Linked Revolving Credit Facility — On February 4, 2022, Vistra Operations entered into a credit agreement by and among Vistra Operations, Vistra Intermediate, the lenders, joint lead arrangers and joint bookrunners party thereto, and Citibank, N.A., as administrative agent and collateral agent. The Credit Agreement provides forff a $1.0 billion senior secured commodity-linked revolving credit facility (the Commodity-Linked Facility). Vistra Operations intends to use the liquidity provided under the Commodity-Linked Facility to make cash postings as required under various commodity contracts to which al and Vistra Operations and its subsidiaries are parties as power prices increase from time-to time and for other working capita general corporate purposes. See Note 11 for more information concerning the Commodity-Linked Facility. Basis of Presentati tt on The consolidated finaff ncial statements have been prepared in accordance with U.S. GAAP and on the same basis as the audited finaff ncial statements included in our 2020 Form 10-K. All intercompany items and transactions have been eliminated in consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of U.S. dollars unless otherwise indicated. Use of Estimtt ates Preparation of financial statements requires estimates and assumptim ons about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements, estimates of expected obligations, judgments related to the potential timing of events and other estimates. In the event estimates and/or assumptim ons prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. 97 Derivative Instrumtt ents and Mark-to-Marke MM t Accountingtt t We enter into contracts for the purchase and sale of electricity, natural gas, coal, uranium and other commodities utilizing futures and forwards primarily to manage commodity price and interest rate risks. If the instruments such as options, swaps,a instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities, changes in the fair value of the derivative are recognized in net income as unrealized gains and losses. This recognition is referred to as mark-to-market accounting. The fair values of our unsettled derivative instruments under mark-to- assets or market accounting are reported in the consolidated balance sheets as commodity and other derivative contractual liabilities. We report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting arrangements we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the consolidated balance sheets, except for certain margin amounts related to changes in fair value on CME transactions that are legally characterized as settlement of derivative contracts rather than collateral. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed. See Notes 15 and 16 for additional information regarding fair value measurement and commodity and other derivative contractual assets and liabilities. A commodity-related derivative contract may be designated as a normal purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement. t t Because derivative instruments are frequently used as economic hedges, accounting standards related to derivative instruments and hedging activities allow for hedge accounting, which provides forff the designation of such instruments as cash flow or fair value hedges if certain conditions are met. As of December 31, 2021 and 2020, there were no derivative positions accounted for as cash flowff or fair value hedges. We report commodity hedging and trading results as revenue, fuel expense or purchased power in the consolidated gas hedges and trading statements of operations depending on the type of activity. Electricity hedges, financial natural activities are primarily reported as revenue. Physical or finaff ncial hedges for coal, diesel or uranium, along with physical natural gas trades, are primarily reported as fuel expense. Realized and unrealized gains and losses associated with interest rate swapa transactions are reported in the consolidated statements of operations in interest expense. t t Revenue Recognitgg iontt Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes delivered or services provided. Sales tax is excluded from revenue. Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Estimated amounts are adjusted when actual usage is known and billed. We record wholesale generation revenue when volumes are delivered or services are performed forff transactions that are not accounted for on a mark-to-market basis. These revenues primarily consist of physical electricity sales to the ISO/RTO, ity revenue for making installed generation and demand response ancillary service revenue for reliabila system reliability requirements, and certain other electricity sales contracts. See Note 5 for detailed descriptions of available forff revenue from contracts with customers. See Derivative Instruments and Mark-to-Markerr revenue recognition related to derivative contracts. ity services, capac t Accounting forff a Advertisintt g Expense EE We expense advertising costs as incurred and include them within SG&A expenses. Advertising expenses totaled $48 million, $43 million and $49 million forff the years ended December 31, 2021, 2020 and 2019, respectively. Impairmerr nt of Long-Li n ved Assets We evaluate long-lived assets (including intangible assets with finff ite lives) for impairment whenever indications of are less impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows than the carrying value. If there is such impairment, a loss is recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicablea . See Note 21 for details of impaim rments of long-lived assets recorded in 2021 and 2020. ff 98 Finite-lived intangibles identified as a result of fresh start reporting or purchase accounting are amortized over their details of intangible assets with estimated useful lives based on the expected realization of economic effects. See Note 6 forff finite lives, including discussion of fair value determinations. n Goodwill all nd Intantt gibl e All ssets withii e Indefini teii Lives As part of fresh start reporting and purchase accounting, reorganization value or the purchase consideration is generally intangible assets and liabilities, then any remaining allocated, firff st, to identifiable tangible assets and liabilities, identifiablea excess reorganization value is allocated to goodwill. We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually, or when indications of impairment exist. We have established October 1 as the date we evaluate goodwill and intangible assets with indefinite lives for impairment. See Note 6 for details of goodwill and intangible assets with indefinite lives, including discussion of fair value determinations. Nuclear Fuel Nuclear fuel is capita sheets. Amortization of nuclear fuel purchased power costs and delivery fees in our consolidated statements of operations. ff alized and reported as a component of our property, plant and equipment in our consolidated balance is calculated on the units-of-production method and is reported as a component of fuel, Major Mainteii nance CostsCC Major maintenance costs incurred during generation plant outages are deferred and amortized into operating costs over the period between the majoa r maintenance outages for the respective asset. Other routine costs of maintenance activities are charged to expense as incurred and reported as operating costs in our consolidated statements of operations. PP Defined Benefit Pii ensi on Plans and OPEB Plans ll Certain health care and life insurance benefits are offered to eligible employees and their dependents uponu of such employee fromff agreements based on either a traditional defined benefit formula or a cash balance formul are dependent upon numerous factors, assumptions and estimates. the retirement the company. Pension benefits are offered to eligible employees under collective bargaining a. Costs of pension and OPEB plans ff See Note 17 for additional information regarding pension and OPEB plans. Stock-Based Compe CC nsationtt Stock-based compensation is accounted forff r nsation. The faiff value of our non-qualified stock options is estimated on the date of grant using the Black-Scholes option-pricing model. are recognized as they occur. We recognize compensation expense for graded vesting awards on a straight-line Forfeitures t basis over the requisite service period for the entire award. See Note 18 forff additional information regarding stock-based compensation. in accordance with ASC 718, Compensati on - StocS k Compe m CC Sales and Excise Taxes Sales and excise taxes are accounted for as "pass through" items on the consolidated balance sheets with no effect on the consolidated statements of operations (i.e., the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liabila ity to the taxing jurisdiction in other current liabilities in our consolidated statements of operations). s Franchise and Revenue-Based TaxeTT Unlike sales and excise taxes, franchise and revenue-based taxes are not "pass through" items. These taxes are imposed on us by state and local taxing authorities, based on revenues or kWh delivered, as a cost of doing business and are recorded as an expense. Rates we charge to customers are intended to recover our costs, including the franchise and revenue-based receipt taxes, but we are not acting as an agent to collect the taxes from customers. We report franc hise and revenue-based taxes in SG&A expense in our consolidated statements of operations. ff 99 Income Taxes Investment tax credits are accounted forff under the deferral method, which resulted in a reduction to the basis of our solar and battery storage facilities of zero, zero and $2 million and a corresponding increase in the deferred tax assets in 2021, 2020 and 2019, respectively. Deferred income taxes are provided forff required under accounting rules. See Note 7. temporary differences between the book and tax basis of assets and liabilities as We report interest and penalties related to uncertain tax positions as current income tax expense. See Note 7. Tax Receivable All )A greement (TRATT The Company accounts forff its obligations under the TRA aRR s a liability in our consolidated balance sheets (see Note 8). bligation represents the discounted amount of projected payments under the TRARR . The The carrying value of the TRA oRR income tax rate, (b) projected payments are based on certain assumptim ons, including but not limited to (a) the federal corporate estimates of our taxable income in the current and future years and (c) additional states that Vistra operates in, including the relevant tax rate and apportionment factor forff each state. Our taxable income takes into consideration the current federal tax code and reflects our current estimates of future results of the business. rr The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective interest method. Changes in the estimated amount of this obligation resulting from changes to either the timing or amount of TRA pRR r value of the obligation. These changes are included on our consolidated statements of operations under the heading of Impacts of Tax Receivabla e Agreement. ayments are recognized in the period of change and measured using the discount rate inherent in the initial faiff Accountingii for Contingen ncies Our financial results may be affect loss contingencies are recorded when management determines that it is probable that a liabia lity has been incurred and that such to interpretations of current facts and economic loss can be reasonably estimated. circumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 13 forff a discussion of contingencies. ed by judgments and estimates related to loss contingencies. Accruals forff Such determinations are subject ff Cash and Cash Equivalents ll For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered cash equivalents. Restricted Cash The terms of certain agreements require the restriction of cash forff specific purposes. See Note 21 forff more details regarding restricted cash. Property, Pyy laPP nt and Equipment al improvements and individual facff Property, plant and equipment has been recorded at estimated fair values at the time of acquisition for assets acquired or at cost for capita ilities developed (see Notes 2 and 3). Significant improvements or additions to our property, plant and equipment that extend the life of the respective asset are capitalized at cost, while other costs are expensed when incurred. The cost of self-constructed property additions includes materials and both direct and indirect labor, including payroll-related costs. Interest related to qualifying construction projects and qualifying software projects is capita alized in accordance with accounting guidance related to capita alization of interest cost. See Note 21. a Depreciation of our property, plant and equipment (except for nuclear fuel ) is calculated on a straight-line basis over the estimated service lives of the properties. Depreciation expense is calculated on an asset-by-asset basis. Estimated depreciable lives are based on management's estimates of the assets' economic useful lives. See Note 21. ff 100 Asset Retirement Obligll ations (ARO)O r value is reasonably estimablea A liabia lity is initially recorded at fair value for an asset retirement obligation associated with the legal obligation associated with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets in the period in which it is incurred if a faiff . At initial recognition of an ARO obligation, an offsetting asset is also recorded for the long-lived asset that the liability corresponds with, which is subsequently depreciated over the estimated useful life of the asset. These liabilities primarily relate to our nuclear generation plant decommissioning, land reclamation related to lignite mining and removal of lignite/coal-fueled plant ash treatment facilities. Over time, the liability is accreted forff the change in present value and the initial capitalized costs are depreciated over the remaining useful lives of the assets. Generally, changes in estimates related to ARO obligations are recorded as increases or decreases to the liability and related asset as information becomes available. Changes in estimates related to assets that have been retired or forff which capita alized costs are not recoverable are recorded as operating costs in the consolidated statements of operations. See Note 21. Regue latorytt Asset or Liabil itll ytt ii The costs to ultimately decommission the Comanche Peak nuclear power plant are recoverablea through the regulatory rate making process as part of Oncor's delivery fees. As a result, the asset retirement obligation and the investments in the decommissioning trust are accounted forff as rate regulated operations. Changes in these accounts, including investment income and accretion expense, do not impact net income, but are reported as a change in the corresponding regulatory asset or liabia lity balance that is reflected in our consolidated balance sheets as other noncurrent assets or other noncurrent liabilities and deferred credits. Inventories Inventories consist of materials and supplies, fuel stock and natural t gas in storage. Materials and supplies inventory is alized when used for repairs/maintenance or capital projects, gas in storage are reported at the lower of cost (calculated on a weighted average basis) or valued at weighted average cost and is expensed or capita respectively. Fuel stock and natural t net realizablea value. We expect to recover the value of inventory costs in the normal course of business. See Note 21. Investments Investments in a nuclear decommissioning trust fund are carried at current market value in the consolidated balance sheets. Assets related to employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded at current market value. See Note 21 for discussion of these and other investments. r Noncontrollill ngii t Interes tt Noncontrolling interest is comprised of the 20% of Electric Energy, Inc. (EEI) that we do not own. EEI is our ility in Joppa, Illinois. This noncontrolling interest is classified as a component of consolidated subsidiary that owns a coal facff equity separate fromff stockholders' equity in the consolidated balance sheets. Treasury Stock Treasury stock purchases are accounted forff recorded as treasury stock, which is presented in our consolidated balance sheets as a reduction to additional paid-in capita See Note 14. under the cost method whereby the entire cost of the acquired stock is al. Leases At the inception of a contract we determine if it is or contains a lease, which involves the contract conveying the right to control the use of explicitly or implicitly identified property, plant, or equipment for a period of time in exchange for consideration. 101 Right-of-use (ROU) assets represent our right to use an underlying asset forff the lease term and lease liabia lities represent our obligation to make lease payments arising from the lease. ROU assets and lease liabia lities are recognized at the commencement date of the underlying lease based on the present value of lease payments over the lease term. We use our at the lease commencement date to determine the present secured incremental borrowing rate based on the information availablea value of lease payments. Operating leases are included in operating lease ROU assets, operating lease liabilities (current) and operating lease liabilities (noncurrent) on our consolidated balance sheet. Finance leases are included in property, plant and equipment, other current liabilities and other noncurrent liabilities and deferred credits on our consolidated balance sheet. Lease term includes options to extend or terminate the lease when it is reasonably certain that we will exercise the option. We apply the practical expedient permitted by ASC 842 to not separate lease and non-lease components forff a majority of our lease asset classes. r Leases with an initial lease term of 12 months or less are not recorded on the balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term. We also present lessor sublease income on a net basis against the related lessee lease expense. Adoptio on of Accountingii Standards Issued PriorPP to 2021 Simplifyll ing the Accountingtt for Income Taxes — In December 2019, the Financial Accounting Standards Board (FASB) ing the Accounting for Income Taxes (Topic 740). The ASU issued Accounting Standards Update (ASU) 2019-12, Simplifyi enhances and simplifies various aspects of the income tax accounting guidance including the elimination of certain exceptions intraperiod tax allocation, the methodology for calculating income taxes in an interim period and the related to the approach forff recognition of deferred tax liabia lities for outside basis differences. The new guidance also simplifiesff aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-upu in the tax basis of goodwill. We adopted all provisions of this ASU in the first quarter of 2020, and it did not have a material impact on our fiff nancial statements. Changes to the Disclosure Requirements for FaiFF r Vii alVV ue Measurement — In August 2018, the FASB issued ASU tt orff Fair Value Measurement. The ASU removes disclosure requirements for 2018-13, Changes to the Disclosure Requirements f (a) the reasons for transfers between Level 1 and Level 2, (b) the policy for timing of transfers between levels and (c) the valuation processes forff Level 3. The ASU requires new disclosures around (a) the changes in unrealized gains and losses forff value measurements held at the end of the the period included in other comprehensive income for recurring Level 3 fair value reporting period and (b) the range and weighted average of significant unobservable inputs used to develop Level 3 fair measurements. We adopted this ASU in the first ted disclosures are included in Note 15. quarter of 2020, and the upda u ff ff ff tt Customer's Accountintt g forff II Implementation Costs I ncurre d in a C Contract — In August 2018, the FASB issued ASU 2018-15, Customer's A' Cloud Computing Arrangement That Is a Servi is a service contract to determine which implementation costs to capita stage of the implementation. The ASU also requires the customer to expense the capita of the hosting arrangement. The customer is required to appl capita ff financial statements. ice d in a ce Contract. The ASU requires a customer in a cloud hosting arrangement that alize and which costs to expense based on the project alized implementation costs over the term y the existing impairment and abandonment guidance on the quarter of 2020, and it did not have a material impact on our alized implementation costs. We adopted this ASU in the first II ccounting for Implementation Costs I ncurre Arrangement That Is a ServSS loCC ud Computingii SS a ii tt Finanii cial Instrumtt Losses. The ASU requires organizations to measure all expected credit losses forff date based on historical experience, current conditions and reasonable and supportable foreca first quarter of 2020, and it did not have a material impact on our financial statements. ents—Credit Losses — In June 2016, the FASB issued ASU 2016-13, Financial Instruments — CreCC dit financial instruments held at the reporting sts. We adopted this ASU in the ff Leases — On January 1rr , 2019, we adopted Accounting Standards Update (ASU) 2016-02, Leases (Topic 842) and all related amendments (new lease standard) using the modified retrospective method with the cumulative-effect adjustment to the opening balance of retained deficit for all contracts outstanding at the time of adoption. The impact of the adoption of the new lease standard is immaterial to our net income on an ongoing basis. The primary impact of adopting the new lease standard relates to recognition of lease liabilities and ROU assets for all leases classified as operating leases. We recognized the effect of initially applying the new lease standard by recording ROU assets of $85 million and lease liabilities of $123 million in our consolidated balance sheet. See Note 12 forff the disclosures required by the new lease standard. (( 102 In March 2020, the FASB issued ASU 2020-04, Refee rence Rate Refoe rm (Topic ence Rate Reform on Financial Reporti of ng. The ASU provides optional expedients and exceptions for applying GAAP to Refere contract modifications and hedging relationships, subject to meeting certain criteria, that refereff nce LIBOR or another rate that is expected to be discontinued. The amendments in the ASU are effective for all entities as of March 12, 2020 through December 31, 2022. The adoption of this guidance did not have a material impact on our financial statements. 848): Facilitation of the Effects TT e ff In March 2020, the SEC amended Rule 3-10 of Regulation S-X regarding financial disclosure requirements for registered debt offerings involving subsidiaries as either issuers or guarantors and affiliates whose securities are pledged as collateral. This new guidance narrows the circumstances that require separate financial statements of subsidiary issuers and guarantors and streamlines the alternative disclosures required in lieu of those statements. This rule is effective January 4, 2021 with earlier adoption permitted. We elected to adopt this rule in the first quarter of 2020. Accordingly, summarized financial information has been presented only for the issuer and guarantors of the Company's registered debt securities, and the location of the required disclosures has been moved outside the Notes to the Consolidated Financial Statements and is provided in Part II, Item of Financial Condition and Results of Operations under Financial Condition — 7 Management's Discussion and Analysis Guarantor Summary Financial Information. In October 2020, the FASB issued ASU 2020-09, Debt (Topic 470) — Paragraphs Pursuant to SEC Release No. 33-10762, to reflect the SEC's new disclosure rules on Amendments t guaranteed debt securities adopted by the Company. o SECSS ll tt 2. ACQUISITIONS AND BUSINESS COMBINATION ACCOUNTING TT Ambit Tii ransac tion On November 1, 2019 (Ambit Acquisition Date), Volt Asset Company, Inc., an indirect, wholly owned subsidiary of gas products to ed the purchase price of $555 million (including cash acquired the purchase price at closing and Vistra, completed the Ambit Transaction. Ambit is an energy retailer selling both electricity and natural residential and small business customers in 16 states. Vistra fund and net working capita not assumed by Vistra. al) using cash on hand. All of Ambit's outstanding debt was repaid fromff ff t Crius TraTT nsaction On July 15, 2019 (Crius Acquisition Date), Vienna Acquisition B.C. Ltd., an indirect, wholly owned subsidiary of Vistra, completed the acquisition of the equity interests of two wholly owned subsidiaries of Crius that indirectly own the operating gas products to residential and small business business of Crius. Crius is an energy retailer selling both electricity and natural customers in 19 states. Vistra fund ed the purchase price of $400 million (including $382 million for outstanding trust units) using cash on hand. In addition, Vistra assumed $140 million of outstanding debt and acquired $26 million of cash at the closing of the Crius Transaction. See Note 11 for discussion of debt assumed in the Crius Transaction. ff t Ambit aii nd Crius Business Combination ii Accountingtt a We believe the Ambit Transaction has (i) augmented Vistra's existing retail marketing capabi lities with additional direct lity and a proprietary technology platform, (ii) reduced risk and aided expansion into higher margin channels by selling capabi improving Vistra's match of its generation to load profile dued to a high degree of overlap of Vistra's generation fleet with Ambit's approximately 11 TWh of annual load, primarily in ERCOT and PJM and (iii) enhanced the integrated value proposition through collateral and transaction efficff iencies, particularly via Ambit's retail electric portfolio. a We believe the Crius Transaction has (i) reduced risk and aided expansion into higher margin channels by improving to a high degree of overlap of Vistra's generation fleet with Crius' shed a platform for growth by leveraging Vistra's existing retail lities and Crius' experienced team and (iii) enhanced the integrated value proposition through collateral and Vistra's match of its generation to load profile dued approximately 10 TWh of annual electricity load, (ii) establia marketing capabi transaction efficff iencies, particularly via Crius' retail electric portfolio. a 103 Each of the Ambit Transaction and Crius Transaction, respectively, was accounted for in accordance with ASC 805, Business Combinations (ASC 805), with identifiablea assets acquired and liabilities assumed recorded at their estimated fair values on the Ambit Acquisition Date and Crius Acquisition Date, respectively. The combined results of operations are reported in our consolidated financial statements beginning as of the respective Ambit Acquisition Date and Crius Acquisition Date. A summary of the techniques used to estimate the fair value of the identifiable assets and liabilities, as well as their classification within the fair value hierarchy (see Note 15), is listed below: • Working capia tal was valued using availablea market information (Level 2). • • Acquired derivatives were valued using the methods described in Note 15 (Level 2 or Level 3). Acquired retail customer relationship was valued based on discounted cash flow analysis of acquired customers and estimated attrition rates (Level 3). Crius' long-term debt was valued using a market approach (Level 2). • The following tablea summarizes the allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Ambit Transaction and Crius Transaction, respectively, as of the Ambit Acquisition Date and Crius Acquisition Date, respectively. The Ambit Transaction purchase price was $555 million (including cash acquired and net working capita al) and the Crius Transaction purchase price was $400 million. The final purchase price allocations were completed in the second quarter of 2020 for the Crius Transaction and the third quarter of 2020 for the Ambit Transaction. Ambit Transaction and Crius Transactions Final Purchase Price Allocations Cash and cash equivalents Net working capia tal Accumulated deferred income taxes Identifiable intangible assets Goodwill Commodity and other derivative contractual assets Other noncurrent assets Total assets acquired Identifiable intangible liabila Long-term debt, including amounts due currently Commodity and other derivative contractual Accumulated deferred income taxes Other noncurrent liabilities and deferred credits ities t liabilities Total liabilities assumed Identifiable net assets acquired Ambit Transaction Crius Transaction Final Purchase Price Allocation Measurement Period Adjustmen d recorded ts Final Purchase Price Allocation Measurement Period Adjustmen d recorded ts $ $ 49 32 — 218 258 23 13 593 — — 28 — 10 38 555 $ $ — $ 3 — (45) 44 — — 2 — — — — 2 2 — $ 26 (9) — 317 243 18 17 612 2 140 40 14 16 212 400 $ $ — (42) (36) 23 38 — (3) (20) (34) — — 14 — (20) — quisition costs incurred in the Ambit Transaction and Crius Transaction totaled $1 million and $2 million, respectively. For the Ambit Acquisition Date through December 31, 2019, our consolidated statements of operations include revenues and net income acquired in the Ambit Transaction totaling $193 million and $2 million, respectively. For the Crius Acquisition Date through December 31, 2019, our consolidated statements of operations include revenues and net income acquired in the Crius Transaction totaling $453 million and zero, respectively. The net income acquired in the Ambit Transaction and Crius Transaction include intangible amortization and transition related expenses. 104 Ambit and Crius Transaction Unaudited Pro Forma FinFF ancial Information — The following unaudited consolidated pro the year ended December 31, 2019 assumes that the Ambit and Crius Transactions occurred on forma financial inforff mation forff January 1, 2019 (i.e., represents our results forff the year ended December 31, 2019 plus the results for either Ambit Transaction or Crius Transaction for the period not owned by us, respectively). The unaudited consolidated pro forma financial inforff mation is provided forff informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the Ambit Transaction and Crius Transaction been completed on January 1, 2019, nor is the unaudited consolidated pro forma financial information indicative of future results of operations, which may differ materially fromff the consolidated pro forma financial information presented here. Revenues Net income (a) Net income attributable to Vistra Net income attributable to Vistra per weighted average share of common stock outstanding — basic Net income attributable to Vistra per weighted average share of common stock outstanding — diluted Ambit Transaction Crius Transaction Year Ended December 31, 2019 12,931 949 951 1.92 1.90 $ $ $ $ $ Year Ended December 31, 2019 12,373 876 878 1.78 1.76 $ $ $ $ $ __________ (a) Decrease in pro forma net income compared to consolidated net income is driven by unrealized losses on hedging activities of Crius and amortization of intangible assets. The consolidated unaudited pro forma financial inforff mation presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired and the related impacts on tax expense. 105 3. DEVELOPMENT OF GENERATRR ION FACILITIES ee Texas Segment Solarll Generation and Energy Storage Projects We have announced our planned development of up to 768 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas. The first 158 MW of solar generation came online in January and February 2022. Estimated commercial operation dates for the remaining facilities range from the second quarter of 2022 to fourth quarter of 2023. As of ately $286 million in construction-work-in-process for these Texas segment December 31, 2021, we had accumulated approxim solar generation and battery ESS projects. a East SegSS megg nt Solarll GenerGG SS ation and Energy Sgg torage Projects In September 2021, we announced the planned development 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. Estimated commercial operation dates for these facilities range from 2023 to 2025. West Segment Energy Storage Projectstt Oakland — In June 2019, East Bay Community Energy (EBCE) signed a ten-year contract to receive resource adequacy capac . In April 2020, ity fromff the planned development of a 20 MW battery ESS at our Oakland Power Plant site in California a the project received necessary approvals from EBCE and from Pacific Gas and Electric Company (PG&E). The contract was ity of the planned development to a 36.25 MW battery ESS. In April 2020, the concurrent Local amended to increase the capac Area Reliabila ity as part of the Oakland Clean Energy Initiative was signed, l. PG&E did not receive CPUC approval as of April 15, but required California Public Utilities Commission (CPUC) approva 2021. On April 16, 2021, Vistra terminated the LARS agreement with PG&E. We are continuing development of the Oakland battery ESS project while seeking another contractual arrangement that will allow the investment to move forward. ity Service (LARS) agreement to ensure grid reliabila a a ff Moss Landing — In June 2018, we announced that, subject to approva l by the CPUC, we would enter into a 20-year resource adequacy contract with PG&E to develop a 300 MW battery ESS at our Moss Landing Power Plant site in California ication with the CPUC in June 2018 and the CPUC approved the resource (Moss Landing Phase I). PG&E filed its appl adequacy contract in November 2018. Under the contract, PG&E will pay us a fixeff d monthly resource adequacy payment, while we will receive the energy revenues and incur the costs from dispatching and charging the ESS. Moss Landing Phase I commenced commercial operations in May 2021. a a ff In May 2020, we announced that, subject to approva l by the CPUC, we would enter into a 10-year resource adequacy contract with PG&E to develop an additional 100 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase II). PG&E filed its appl ication with the CPUC in May 2020 and the CPUC approved the resource adequacy contract in August 2020. Moss Landing Phase II commenced commercial operations in July 2021. a a The total development costs for Moss Landing Phases I and II totaled approximately $600 million. In January 2022, we announced that, subject to approva l by the CPUC, we would enter into a 15-year resource adequacy contract with PG&E to develop an additional 350 MW battery ESS at our Moss Landing Power Plant site (Moss Landing Phase III). PG&E filed its appl ication with the CPUC in January 2022, and CPUC approval is expected in the second quarter of 2022. Moss Landing Phase III is expected to enter commercial operations in the summer of 2023. a a Moss Landing Outages — In September 2021, Moss Landing Phase I experienced an incident impacting a portion of the battery ESS. A review found that only a small, single-digit percentage of batteries at the facility were impacted and that the ystem. The facility will be offline as we perform the work necessary root cause originated in systems separate fromff to return the facff the battery srr ility to service. Moss Landing Phase II was not affected by this incident. In February 2022, Moss Landing Phase II experienced an incident impacting a portion of the Battery Err SS. An investigation is underway to determine the root cause of the incident. The facility will be offline as we perform the work necessary to return the facility to service. Moss Landing Phase I was not affected by the incident, but the facility will remain offline during the assessment stage of the Moss Landing Phase II incident. We do not expect these incidents to have a material impact on our results of operations. 106 4. RETIREMENT OF GENERATION FACILITIES Sunset SegSS megg nt Operational results forff plants with defined retirement dates identified below are included in our Sunset segment beginning in the quarter when a retirement plan is announced. Name Location Baldwin Coleto Creek Edwards Joppa Joppa Kincaid Miami Fort Newton Zimmer Total Baldwin, IL Goliad, TX Bartonville, IL Joppa, IL Joppa, IL Kincaid, IL North Bend, OH Newton, IL Moscow, OH ISO/RTO MISO ERCOT MISO MISO MISO PJM PJM MISO/PJM PJM Fuel Type Coal Coal Coal Coal Natural Gas Coal Coal Coal Coal Net Generation Capacity (MW) 1,185 650 585 802 221 1,108 1,020 615 1,300 7,486 Expected Retirement Date (a) By the end of 2025 By the end of 2027 By the end of 2022 By September 1, 2022 By September 1, 2022 By the end of 2027 By the end of 2027 By the end of 2027 By May 31, 2022 ____________ (a) Generation facilities may retire earlier than expected dates if economic or other conditions dictate. In September 2019, we announced the settlement of a lawsuit alleging violations of opacity and particulate matter limits at our Edwards facility in Bartonville, Illinois. As part of the settlement, which was approved by the U.S. District Court for the Central District of Illinois in November 2019, we will retire the Edwards facility by the end of 2022 (see Note 13). In September 2020 and December 2020, we announced our intention to retire all of our remaining coal generation facilities in Illinois and Ohio, one coal generation facility in Texas and one natural lity in Illinois no later than year-end 2027 due to economic challenges, including incremental expenditures that would be required to comply with the CCR rulrr e and ELG rulerr (see Note 13), and in furtherance of our efforts to significantly reduce our carbon footprint. Expected plant retirement expenses of $43 million, driven by severance cost, were accrued in the year ended December 31, 2020 in operating costs of our Sunset segment. ff gas faci t In April 2021, we announced we would retire the Joppa generation facilities by September 1, 2022 in order to settle a complaint fileff d with the Illinois Pollution Control Board (IPCB) by the Sierra Club in 2018 (see Note 13). We had previously announced that Joppa would retire no later than the end of 2027. In July 2021, we announced we would retire the Zimmer coal generation facility by May 31, 2022 due to the inability to secure capac ity auction held in May 2021. We had previously announced that Zimmer would retire no later than the end of 2027. ity revenues for the plant in the latest PJM capac a a See Note 21 for discussion of impaim rments recorded in connection with these announcements. ll Asset Closure Segment Operational results forff the Illinois plants retired in 2019 identified below are included in the Asset Closure segment. The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines, including those retired prior to 2019. Name Location ISO/RTO Fuel Type Net Generation Capacity (MW) Coffeen Coffeen, IL Duck Creek Canton, IL Havana Hennepin Total Havana, IL Hennepin, IL MISO MISO MISO MISO Coal Coal Coal Coal 915 425 434 294 2,068 Dates Units Retired November 1, 2019 December 15, 2019 November 1, 2019 November 1, 2019 107 a ity of 2,068 MW. We retired these units dued In August 2019, we announced the planned retirement of four power plants in Illinois with a total installed nameplate to changes in the Illinois Multi-Pollutant Standard rule (MPS generation capac rule) that require us to retire approximately 2,000 MW of generation capac ity. In light of the provisions of the Federal Power Act and the FERC regulations thereunder, the affected subsidiaries of Vistra identified the retired units by analyzing the economics of each of our Illinois plants and designating the least economic units forff retirement. Expected plant retirement expenses of $47 million, driven by severance costs, were accrued in the year ended December 31, 2019 and were included primarily in operating costs of our Asset Closure segment in our consolidated statements of operations. In August 2019, we remeasured our pension and OPEB plans resulting in an increase to the benefit obligation liability of $21 million, pretax other comprehensive loss of $18 million and curtailment expense of $3 million recognized as other deductions in our consolidated statements of operations. a 5. REVENUE The following tablea s disaggregate our revenue by majoa r source: Revenue from contracts with customers: Retail energy charge in ERCOT Retail energy charge in Northeast/ Midwest Wholesale generation revenue from ISO/RTO Capac a Revenue from other wholesale contracts ity revenue from ISO/RTO (a) Total revenue from contracts with customers Other revenues: Intangible amortization Hedging and other revenues (b) Affiliate sales (c) Total other revenues Total revenues Retail Texas East West Sunset Asset Closure Eliminations Consolidated Year Ended December 31, 2021 $ 5,733 $ — $ — $ — $ — $ — $ — $ 5,733 2,255 — — — 3,808 — — 786 (22) — 2,302 602 — 229 1 104 — 1,525 184 193 7,988 6,110 1,366 334 1,902 — — — — — — — — — — (2) (115) — (4,355) — 1,035 (3,320) $ 2,790 (117) $ 7,871 74 123 1,024 1,221 $ 2,587 — 35 5 40 374 (12) (1,371) 220 (1,163) 739 $ — — — — $ — $ — — (2,284) (2,284) (2,284) $ $ 2,255 6,348 163 3,201 17,700 60 (5,683) — (5,623) 12,077 ____________ (a) Represents net capac a t ity s old (purchased) in each ISO/RTO. The East segment includes $470 million of capac ity sold. The Sunset segment includes $4 million of capac purchased offset by $448 million of capac by $188 million of capaa Includes $1.191 billion of unrealized net losses from mark-to-market valuations of commodity positions. See Note 20 forff ity ity purchased offset unrealized net gains (losses) by segment. city sold. a a a (b) (c) Texas and East segments include $1.028 billion and $529 million, respectively, of affiliated unrealized net losses from mark-to-market valuations of commodity positions with the Retail segment. 108 Retail Texas East West Sunset Asset Closure Eliminations Consolidated Year Ended December 31, 2020 $ 5,813 $ — $ — $ — $ — $ — $ — $ 5,813 Revenue from contracts with customers: Retail energy charge in ERCOT Retail energy charge in Northeast/ Midwest Wholesale generation revenue from ISO/RTO a Capac Revenue from other wholesale contracts ity revenue from ISO/RTO (a) 2,406 — — — — 475 — 226 701 — 310 (52) 668 926 Total revenue from contracts with customers 8,219 Other revenues: Intangible amortization Hedging and other revenues (b) Affiliate sales Total other revenues Total revenues — (5) 416 56 — 2,999 51 3,415 $ 4,116 $ 8,270 2 (108) 1,595 1,489 $ 2,415 $ — 124 — 54 178 — 101 3 104 282 — 473 164 187 824 (21) 151 298 428 $ 1,252 $ — 1 — 1 2 — 1 — 1 3 — — — — — — — (4,895) (4,895) (4,895) $ $ 2,406 1,383 112 1,136 10,850 (24) 617 — 593 11,443 ____________ (a) Represents net capac a t ity s old (purchased) in each ISO/RTO. The East segment includes $542 million of capac ity sold. The Sunset segment includes $3 million of capac purchased offset by $490 million of capac by $167 million of capaa Includes $164 million of unrealized net gains from mark-to-market valuations of commodity positions. See Note 20 forff unrealized net gains (losses) by segment. ity ity purchased offset city sold. a a a (b) Revenue from contracts with customers: Retail energy charge in ERCOT Retail energy charge in Northeast/ Midwest Wholesale generation revenue from ISO/RTO Capac a Revenue from other wholesale contracts ity revenue from ISO/RTO (a) Total revenue from contracts with customers Other revenues: Intangible amortization Hedging and other revenues (b) Affiliate sales Total other revenues Total revenues Retail Texas East West Sunset Asset Closure Eliminations Consolidated Year Ended December 31, 2019 $ 4,983 $ — $ — $ — $ — $ — $ — $ 4,983 1,818 — — 1,477 — — — 264 — 629 170 702 — 193 — 9 — 751 197 147 — 194 11 2 6,801 1,741 1,501 202 1,095 207 — — — — — — (15) 86 (250) — 2,345 2,095 71 $ 3,836 $ 6,872 (4) 37 1,256 1,289 $ 2,790 $ 4 132 — 136 338 (17) 247 277 507 $ 1,602 $ — 42 92 134 341 $ — — (3,970) (3,970) (3,970) $ 1,818 3,244 378 1,124 11,547 (32) 294 — 262 11,809 ____________ (a) Represents net capac a t ity s purchased offset by $613 million of capac by $198 million of capaa city sold. old (purchased) in each ISO/RTO. The East segment includes $443 million of capac ity sold. The Sunset segment includes $1 million of capac ity ity purchased offset a a a 109 (b) Includes $682 million of unrealized net gains from mark-to-market valuations of commodity positions. See Note 20 for unrealized net gains (losses) by segment. EE Retail Eii nergy Charges Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes delivered or services provided. Sales tax is excluded fromff revenue. Payment terms vary from 15 to 60 days from invoice date. Revenue is recognized over-time using the output method based on kilowatt hours delivered. Energy charges are delivered as a series of distinct services and are accounted for as a single performance obligation. Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Estimated amounts are adjuste d when actual usage is known and billed. d As contracts for retail electricity can be forff multi-year periods, the Company has performff ance obligations under these contracts that have not yet been satisfied. These performance obligations have transaction prices that are both fixed and variable, and that vary based on the contract duration and customer type. For the fixed price contracts, the amount of any unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and customer activity and therefore it is not practicable to estimate such amounts. ll Wholesale s Generation Revenue from ISOs/RTO// Revenue is recognized when volumes are delivered to the ISO/RTO. Revenue is recognized over time using the output method based on kilowatt hours delivered and cash is settled within 10 days of invoicing. Vistra operates as a market participant within ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO and expects to continue to remain under contract with each ISO/RTO indefinitely. Wholesale generation revenues are delivered as a series of distinct services and are accounted forff as a single performanc e obligation. When electricity is sold to and purchased from the same ISO/RTO in the same period, the excess of the amount sold over the amount purchased is reflected in wholesale generation revenues. ff Capacityii Revenue From ISO/RTO// a We offer generation capac city ensures installed generation and demand response is available to satisfy system integrity and reliabila city revenues are recognized when the performanc ity into competitive ISO/RTO auctions in exchange for revenue from awarded capacity offers. ity requirements. Capaa Capaa e obligation is satisfied ratably over time as our power generation facilities stand ready to deliver power to the customer. Penalties are assessed by the ISO/RTO against generation facilities if the facility is not available during ity is sold to and purchased from the same ISO/RTO in the same period, the excess of the amount sold over the amount purchased is reflected in capacity revenue. ity period. The penalties are recorded as a reduction to revenue. When capac a the capac d a ff Revenue from Other tt Wholesale ll tt Contracts Other wholesale contracts include other revenue activity with the ISO/RTO, such as ancillary services, auction revenue, neutrality revenue and revenue from nonaffiliated retail electric providers, municipalities or other wholesale counterparties. Revenue is recognized when the service is performff ed. Revenue is recognized over time using the output method based on icable measurements, and cash settles shortly after invoicing. Vistra operates as a market kilowatt hours delivered or other appl participant within ERCOT, PJM, ISO-NE, NYISO, MISO and CAISO and expects to continue to remain under contract with each ISO/RTO indefinitely. Other wholesale contracts are delivered as a series of distinct services and are accounted forff as a single performance obligation. a Other Revenues Some of our contracts for the sale of electricity meet the definition of a derivative under the accounting standards related to derivative instruments. Revenue from derivative contracts is not considered revenue from contracts with customers under the accounting standards related to revenue. Our revenue from the sale of electricity under derivative contracts, including the impact of unrealized gains or losses on those contracts, is reported in the tabla e aboa ve as hedging and other revenues. We have classifiedff ates that are eliminated in consolidation as other revenues in the tablea all sales to affili above. ff 110 Contratt ct and Other tt Customer Acquisitiii on Costs We defer costs to acquire retail contracts and amortize these costs over the expected life off f the contract. The expected life of a retail contract is calculated using historical attrition rates, which we believe to be an accurate indicator of future attrition rates. The deferred acquisition and contract cost balance as of both December 31, 2021 and 2020 was $80 million. The amortization related to these costs during the year ended December 31, 2021, 2020 and 2019 totaled $75 million, $46 million and $21 million respectively, recorded as SG&A expenses, and $6 million, $7 million and $9 million, respectively, recorded as a reductd ion to operating revenues in the consolidated statements of operations. Practictt al Expedi xx ents The vast majority of revenues are recognized under the right to invoice practical expedient, which allows us to recognize revenue in the same amount that we have a right to invoice our customers. Unbilled revenues are recorded based on the volumes delivered and services provided to the customers at the end of the period, using the right to invoice practical expedient. We have elected to not disclose the value of unsatisfied performance obligations for contracts with variable consideration for which we recognize revenue using the right to invoice practical expedient. We use the portfolio approach in evaluating similar customer contracts with similar performance obligations. Sales taxes are not included in revenue. Performance Obligati i ons As of December 31, 2021, we have futuff re performff a ity auction volumes awarded through capac ance obligations that are unsatisfied, or partially unsatisfied, relating to capac ity auctions held by the ISO/RTO or contracts with customers. Therefore, an a obligation exists as of the date of the results of the respective ISO/RTO capacity auction or the contract execution date. These obligations total $652 million, $310 million, $212 million, $99 million and $45 million that will be recognized in the years ity revenues are ending December 31, 2022, 2023, 2024, 2025 and 2026, respectively, and $439 million thereafter. Capac recognized as capacity is made available to the related ISOs/RTOs or counterparties. a Accounts Receivablell The following tablea presents trade accounts receivable (net of allowance forff uncollectible accounts) relating to both contracts with customers and other activities: Trade accounts receivable fromff Other trade accounts receivablea — net Total trade accounts receivablea — net contracts with customers — net 6. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS AND LIABILITIES Goodwillll The following tabla e provides information regarding our goodwill balance. Balance at December 31, 2018 Measurement period adjustments recorded in connection with the Merger Goodwill recorded in connection with the Crius Transaction Goodwill recorded in connection with the Ambit Transaction Balance at December 31, 2019 Measurement period adjustments recorded in connection with the Crius Transaction Measurement period adjustments recorded in connection with the Ambit Transaction Balance at December 31, 2021 and 2020 December 31, 2021 2020 $ $ 1,087 310 1,397 $ $ 1,169 110 1,279 $ $ 2,068 14 257 214 2,553 (14) 44 2,583 As of December 31, 2021, the carrying value of goodwill totaled $2.583 billion and consisted of the following: • • • • $1.907 billion arose in connection with our application of fresh start reporting at Emergence and was allocated tax entirely to our Retail reporting unit. Of the goodwill recorded at Emergence, $1.686 billion is deductible forff purposes over 15 years on a straight-line basis. $175 million arose in connection with the Merger, of which $122 million was allocated to our Texas Generation reporting unit and $53 million was allocated to our Retail reporting unit. None of the goodwill related to the Merger is deductible for tax purposes. $243 million of goodwill arose in connection with the Crius Transaction and was allocated entirely to our Retail reporting unit. None of the goodwill related to the Crius Transaction is deductible forff $258 million of goodwill arose in connection with the Ambit Transaction and was allocated entirely to our Retail tax purposes over 15 years on a reporting unit. The goodwill related to the Ambit Transaction is deductible forff straight-line basis. tax purposes. Goodwill and intangible assets with indefinite useful lives are required to be evaluated forff impairment at least annually or whenever events or changes in circumstances indicate an impairment may exist. We have selected October 1 as our annual goodwill test date. On the most recent goodwill testing date, we applied qualitative factors and determined that it was more likely than not that the fair value of our Retail and Texas Generation reporting units exceeded their carrying value at October 1, 2021. Significant qualitative factors evaluated included reporting unit financial performance and market multiples, cost factors, customer attrition and changes in reporting unit book value. ii Identifi tt able Intangible tt Assets and Liabiliii tiii es Identifiable intangible assets are comprised of the folff lowing: Identifiable Intangible Asset Retail customer relationship Software and other technology-related assets Retail and wholesale contracts Contractual service agreements (a) Other identifiablea intangible assets (b) Total identifiablea amortization intangible assets subject to Retail trade names (not subjb ect to amortization) (c) Mineral interests (not currently subject to amortization) Total identifiablea intangible assets December 31, 2021 December 31, 2020 $ Gross Carrying Amount 2,083 421 248 23 95 $ Accumulated Amortization 1,631 $ 206 206 2 20 $ 2,870 $ 2,065 Net 452 215 42 21 75 805 1,341 $ Gross Carrying Amount 2,082 414 272 51 96 $ Accumulated Amortization 1,434 $ 186 204 1 19 $ 2,915 $ 1,844 Net 648 228 68 50 77 1,071 1,374 — $ 2,146 1 $ 2,446 ____________ (a) As of December 31, 2021 and 2020, amounts related to contractual service agreements that have become liabilities due to amortization of the economic impacts of the intangibles have been removed from both the gross carrying amount and accumulated amortization. (b) Includes mining development costs and environmental allowances (emissions allowances and renewablea energy certificates). (c) During the year ended December 31, 2021, we recorded a $33 million impairment to a retail trade name intangible asset. Identifiable intangible liabila ities are comprised of the following: Identifiable Intangible Liability Contractual service agreements Purchase and sale of power and capaa Fuel and transportation purchase contracts intangible liabilities Total identifiablea city Year Ended December 31, 2021 2020 $ $ 125 8 14 147 $ $ 129 87 73 289 112 Expense related to finite-lived identifiablea intangible assets and liabilities (including the classification in the consolidated statements of operations) consisted of: Identifiable Intangible Assets and Liabilities Retail customer relationship Software and other technology-related assets Retail and wholesale contracts/purcha / and sale/fuel and transportation contracts Other identifiablea intangible assets se Consolidated Statements of Operations Depreciation and amortization Depreciation and amortization Operating revenues/fuel, purchased power costs and delivery fees Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization Total intangible asset expense (a) Remaining usefuff l lives of identifiable intangible assets at December 31, 2021 (weighted average in years) 3 4 3 5 Year Ended December 31, 2021 2020 2019 $ 197 $ 283 $ 275 74 (56) 73 17 279 494 $ 223 596 $ $ 61 23 148 507 ____________ (a) Amounts recorded in depreciation and amortization totaled $275 million, $360 million and $340 million for the years ended December 31, 2021, 2020 and 2019 respectively. Amounts exclude contractual services agreements. Amounts include all expenses associated with environmental allowances including expenses accrued to comply with emissions allowance programs and renewable portfolio standards which are presented in fuel, purchased power costs and delivery fees on our consolidated statements of operations. Emissions allowance obligations are accrued as associated electricity is generated and renewable energy certificate obligations are accruedr as retail electricity delivery occurs. The following is a description of the separately identifiable intangible assets. In connection with fresh start reporting, the Merger, the Crius Transaction and the Ambit Transaction, the intangible assets were adjusted based on their estimated fair value as of the Effective Date, the Merger Date, the Crius Acquisition Date and the Ambit Acquisition Date, respectively, based on observable prices or estimates of fair value using valuation models. • • • l Retail customer relati onship — Retail customer relationship intangible asset represents the fair value of our non- contracted retail customer base, including residential and business customers, and is being amortized using an accelerated method based on historical customer attrition rates and reflecting the expected pattern in which economic benefits are realized over their estimated useful life. Retail trade names — Our retail trade name intangible assets represent the fair value of our retail brands, including the trade names of TXU EnergyTM, Ambit Energy, 4Change EnergyTM, Homefield Energy, Dynegy Energy Services, TriEagle Energy, Public Power and U.S. Gas & Electric, and were determined to be indefinite-lived assets not subject to amortization. These intangible assets are evaluated forff impairment at least annually in accordance with accounting guidance related to goodwill and other indefinite-lived intangible assets. Significant assumptim ons included within the development of the fair value estimates include estimated gross margins for future periods and implied royalty rates. On the most recent testing date, we recorded an impairment charge for $33 million related to an immaterial trade name. For all other trade names, we determined it was more likely than not that the fair value of the retail trade name intangible assets exceeded their carrying values at October 1, 2021. ff t e and sale contracts — These intangible assets represent the value of various ss Retail and wholesale contracts /purchas retail and wholesale contracts and purchase and sale contracts. The contracts were identified as either assets or liabilities based on the respective fair values as of the Effective Date, the Merger Date, the Crius Acquisition Date or the Ambit Acquisition Date utilizing prevailing market prices for commodities or services compared to the fixed prices contained in these agreements. The intangible assets or liabilities are being amortized in relation to the economic terms of the related contracts. tt 113 • or unfavorablea contract obligations with respect r value of Contractual service agreementstt — Our acquired contractual service agreements represent the estimated faiff favorablea to long-term plant maintenance agreements, rail transportation agreements and rail car leases, and are being amortized based on the expected usage of the service ty of the plant maintenance services relate to capital improvements agreements over the contract terms. The majori and the related amortization of the plant maintenance agreements is recorded to property, plant and equipment. Amortization of rail transportation and rail car lease agreements is recorded to fuel, purchased power costs and delivery fees. a Estimatedtt Amortization ii i of Identifi tt able Intangible tt Assets and Liabiliii tiii es As of December 31, 2021, the estimated aggregate amortization expense of identifiablea intangible assets and liabilities for each of the next fivff e fisff cal years is as shown below. Year 2022 2023 2024 2025 2026 7. INCOME TAXES Estimated Amortization Expense 202 $ 148 $ 99 $ 73 $ 49 $ Vistra filff es a U.S. federal income tax returnt that includes the results of its consolidated subsidiaries. Vistra is the corporate parent of the Vistra consolidated group. Pursuant to applicable U.S. Department of the Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liabia lity for the taxes of such group. Income Tax Expense xx (Benefit)ii The components of our income tax expense (benefit) are as follow ff s: Current: U.S. Federal State Total current Deferred: U.S. Federal State Total deferred Total Year Ended December 31, 2021 2020 2019 $ $ $ 1 16 17 (336) (139) (475) (458) $ (5) $ 41 36 171 59 230 266 $ (1) 10 9 260 21 281 290 114 Reconciliation of income taxes computed at the U.S. federal statutory rate to income tax expense (benefit) recorded: Income (loss) before income taxes U.S. federal statutory rate Income taxes at the U.S. federal statutory rate Nondeductible TRA accretion State tax, net of federal benefit Federal and State returnt Nondeductible compensation Nondeductible transaction costs Equity awards Valuation allowance on state NOLs Lignite depletion Texas gross margin amended returnt Other to provision adjust d ment Income tax expense (benefit) Effective tax rate Defere red IncII ome Tax Balances Year Ended December 31, 2021 (1,722) $ 2020 2019 $ 890 $ 1,216 21 % (362) (8) (2) (2) 4 — 1 (94) (3) — 8 (458) 26.6 % $ 21 % 187 (7) 32 13 — — — 41 (3) — 3 266 29.9 % $ 21 % 255 5 48 (17) 3 2 (4) 13 (6) (3) (6) 290 23.8 % $ Deferred income taxes provided forff temporary differences based on tax laws in effect at December 31, 2021 and 2020 are as follows: Noncurrent Deferred Income Tax Assets Tax credit carryforwards Loss carryforwards Identifiable intangible assets Long-term debt Employee benefit obligations Commodity contracts and interest rate swapsa Other Total deferred tax assets Noncurrent Deferred Income Tax Liabilities Property, plant and equipment ities Total deferred tax liabila Valuation allowance Net Deferff red Income Tax Asset December 31, 2021 2020 76 1,193 346 15 121 238 148 2,137 767 767 68 1,302 $ $ $ 75 953 293 19 129 96 47 1,612 632 632 143 837 $ $ $ a As of December 31, 2021, we had total deferred tax assets of approxi mately $1.302 billion that were substantially comprised of book and tax basis differences related to our generation and mining property, plant and equipment, as well as l and state net operating loss (NOL) carryforwards. Our deferred tax assets were significantly impacted by the impacts of ff federa Winter Storm Uri as well as the Merger. For the year ended December 31, 2021, we recognized a tax benefit of $74 million on the release of state valuation allowances largely related to Illinois. Illinois enacted legislation in 2021 extending the carryforward period of net operating losses and we forecast to utilize all losses before expiration. For the year ended December 31, 2020, we recognized a partial valuation allowance of $32 million on the net operating loss carryforwards related largely to Illinois and New York due to forecasted expiration. As of December 31, 2021, we assessed the need forff a valuation allowance related to our deferred tax asset and considered both positive and negative evidence related to the likelihood of realization of the deferred tax assets. In connection with our analysis, we concluded that it is more likely than not that the federal deferred tax assets will be fully utilized by futuret income, and thus no valuation allowance was required. taxablea 115 As of December 31, 2021, we had $4.5 billion pre-tax net operating loss (NOL) carryforwards for federal income tax purposes that will begin to expire in 2032. As of December 31, 2021, we had no remaining AMT credits refundable through . the TCJA availablea The income tax effects of the components included in accumulated other comprehensive income totaled a net deferred tax liability of $9 million at December 31, 2021 and a net deferred tax asset of $5 million at December 31, 2020. Coronavirus Aid, Relief aff nd Economic SecSS urityii Act (CARES AEE tt ct) at nd Final Sectiott n 163(j) Regulat ions e the ability to accelerate timing of refundablea In response to the global pandemic related to COVID-19, the CARES Act was signed into law in March 2020. The CARES Act provides numerous relief provisions for corporate taxpayers, including modification of the utilization limitations expansion of the deduction for business interest expense under IRC Section 163(j) (Section on net operating losses, favorablea 163(j)), AMT credits and the temporary suspension of certain payment requirements forff the employer portion of social security taxes. Additionally, the final Section 163(j) regulations were issued in July 2020 and provided a critical correction to the proposed regulations with respect to the computation of adjusted taxable income. In 2021, Vistra is benefiting from the final 163(j) regulations and able to utilize its remaining 163(j) carryforward of $12 million. Certain provisions in the final 163(j) regulations begin to sunset in 2022, for which Vistra will continue its legislative monitoring and advocacy efforts to amend consistent with the intent of the law, including the permanent addback of d taxable income. Vistra is also utilizing the CARES Act payroll deferral mechanism to depreciation and amortization to adjuste mately half of the previously defer the payment of approximately $22 million from 2020 to 2021 and 2022. We paid approxi deferred taxes in December 2021. d a i Liabil tt itll y f orff Uncertain Tii axTT tt Positions Accounting guidance related to uncertain tax positions requires that all tax positions subject to uncertainty be reviewed and assessed with recognition and measurement of the tax benefitff based on a "more-likely-than-not" standard with respect to the ultimate outcome, regardless of whether this assessment is favorablea . or unfavorablea We classify interest and penalties related to uncertain tax positions as current income tax expense. The amounts were immaterial for the years ended December 31, 2021, 2020 and 2019. The following tablea summarizes the changes to the uncertain tax positions, reported in accumulated deferred income taxes and other current liabilities in the consolidated balance sheets forff the years ended December 31, 2021, 2020 and 2019. ions based on tax positions related to prior years Balance at beginning of period, excluding interest and penalties Additions based on tax positions related to prior years Reductd Additions based on tax positions related to the current year Settlements with taxing authorities Balance at end of period, excluding interest and penalties Year Ended December 31, 2021 2020 2019 39 1 — — (2) 38 $ $ 126 3 (90) — — 39 $ $ 39 3 — 87 (3) 126 $ $ Vistra and its subsidiaries filff e income tax returns in U.S. federal, state and foreign jurisdictions and are, at times, subject In February 2021, Vistra was notified that the IRS had opened a tax years 2018 and 2019 and an employment tax audit for tax year 2018. Crius is currently under to examinations by the IRS and other taxing authorities. federal income tax audit forff audit by the IRS forff the tax years 2015 and 2016. Uncertain tax positions totaled $38 million at December 31, 2021. Tax Matters tt Agreement On the Effective Date, we entered into the Tax Matters Agreement with EFH Corp. whereby the parties have agreed to take certain actions and refrain from taking certain actions in order to preserve the intended tax treatment of the Spin-Off and to indemnify the other parties to the extent a breach of such agreement results in additional taxes to the other parties. Among other things, the Tax Matters Agreement allocates the responsibility for taxes for periods prior to the Spin-Off between EFH Corp. and us. For periods prior to the Spin-Off: (a) Vistra is generally required to reimburse EFH Corp. with respect to any taxes paid by EFH Corp. that are attributablea to us and (b) EFH Corp. is generally required to reimburse us with respect to any taxes paid by us that are attributablea to EFH Corp. 116 We are also required to indemnify EFH Corp. against taxes, under certain circumstance, if the IRS or another taxing authority successfully challenges the amount of gain relating to the PrefCo Preferred Stock Sale or the amount or allowance of EFH Corp.'s net operating loss deductions. Subject to certain exceptions, the Tax Matters Agreement prohibits us from taking certain actions that could reasonably be expected to undermine the intended tax treatment of the Spin-Off or to jeopardize the conclusions of the private letter ruling we obtained fromff the IRS or opinions of counsel received by us or EFH Corp., in each case, in connection with the Spin-Off. Certain of these restrictions apply for two years after the Spin-Off. Under the Tax Matters Agreement, we may engage in an otherwise restricted action if (a) we obtain written consent from EFH Corp., (b) such action or transaction is described in or otherwise consistent with the facts in the private letter ruling we the IRS in connection with the Spin-Off, (c) we obtain a supplemental private letter ruling from the IRS, or (d) obtained fromff we obtain an unqualified opinion of a nationally recognized law or accounting firm that is reasonably acceptablea to EFH Corp. that the action will not affect the intended tax treatment of the Spin-Off. 8. TAX RECEIVABLE AGREEMENT OBLIGATION ff ien creditors of TCEH. The TRA gRR On the Effective Date, Vistra entered into a tax receivable agreement (the TRARR ) with a transfer agent on behalf of certain former first-l ights of 85% of the amount of cash savings, if any, in U.S. federal and state income tax that we realize in periods after Emergence as a result of (a) certain transactions consummated pursuant to the Plan of Reorganization (including the step-up in tax basis in our assets resulting from the PrefCo Preferred Stock Sale), (b) the tax basis of all assets acquired in connection with the acquisition of two CCGT natural gas-fueled generation facilities in April 2016 and (c) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA,RR plus interest accruing from the due date of the applicable tax return. the payment by us to holders of TRA RRR enerally provides forff r t Pursuant to the TRARR , we issued the TRA RRR receive such TRA RRR fully described in the Registration Rights Agreement (see Note 19). ights under the Plan of Reorganization. Such TRA RRR ights for the benefit of the first-lien secured creditors of TCEH entitled to ights are entitled to certain registration rights more The following tablea summarizes the changes to the TRA oRR bligation, reported as other current liabilities and Tax Receivable Agreement obligation in our consolidated balance sheets, for the years ended December 31, 2021, 2020 and 2019. bligation at the beginning of the period TRA oRR Accretion expense Changes in tax assumptions impacting timing of payments (a) Impacts of Tax Receivable Agreement Payments TRA oRR bligation at the end of the period Less amounts dued currently Noncurrent TRA oRR bligation at the end of the period Year Ended December 31, 2021 2020 2019 $ $ 450 62 (115) (53) (2) 395 (1) 394 $ $ 455 64 (69) (5) — 450 (3) 447 $ $ 420 59 (22) 37 (2) 455 — 455 ff ____________ (a) During the year ended December 31, 2021, we recorded a decrease to the carrying value of the TRA oRR bligation totaling asted taxable income, including the financial impacts of Winter Storm Uri, $115 million as a result of adjustments to forec planned additional renewable development projects. and anticipated tax benefits available under current tax laws forff bligation totaling During the year ended December 31, 2020, we recorded a decrease to the carrying value of the TRA oRR asted taxable income, including the impacts of the CARES approximately $69 million as a result of adjustments to forec Act, changes to Section 163(j) percentage limitation amount, the impacts from the issuance of the final Section 163(j) renewable development projects. During the year ended December 31, regulations and the anticipated tax benefits fromff 2019, we recorded an decrease to the carrying value of the TRA oRR bligation totaling $22 million as a result of adjustments to the timing of forecasted taxable income and state apportionment due to the expansion of Vistra's state income tax profile, including the Dynegy, Crius and Ambit acquisitions. ff 117 rr As of December 31, 2021, the estimated carrying value of the TRA oRR bligation totaled $395 million, which represents the discounted amount of projected payments under the TRARR . The projected payments are based on certain assumptions, including but not limited to (a) the federal corporate income tax rate of 21%, (b) estimates of our taxable income in the current and future each years and (c) additional states that Vistra now operates in, including the relevant tax rate and apport state. Our taxable income takes into consideration the current federal tax code, various relevant state tax laws and reflects our current estimates of future results of the business. The estimates of future business results include assumptions related to renewable development projects that Vistra is planning to execute that generate significant tax benefits. These benefits have a bligation payments. These assumptim ons are subject to change, and those changes could material impact on the timing of TRA oRR have a material impact on the carrying value of the TRA oRR bligation. As of December 31, 2021, the aggregate amount of undiscounted federal and state payments under the TRA iRR s estimated to be approximately $1.4 billion, with more than half of such amount expected to be paid during the next 15 years, and the final payment expected to be made around the year 2056 (if the TRA iRR s not terminated earlier pursuant to its terms). ionment factor forff d a ff The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective interest method. Changes in the amount of this obligation resulting from changes to either the timing or amount of TRARR r value of the payments are recognized in the period of change and measured using the discount rate inherent in the initial faiff obligation. 9. EARNINGS PER SHARE Basic earnings per share availablea to common stockholders are based on the weighted average number of common shares outstanding during the period. Diluted earnings per share is calculated using the treasury stock method and includes the effect of all potential issuances of common shares under stock-based incentive compensation arrangements. ff to Series A Preferred Stock d Stock to Series B Preferre Net income (loss) attributable to Vistra Less cumulative dividends attributablea Less cumulative dividends attributablea Net income (loss) attributable to common stock — basic Weighted average shares of common stock outstanding — basic Net income (loss) per weighted average share of common stock outstanding — basic Dilutive securities: Stock-based incentive compensation plan Weighted average shares of common stock outstanding — diluted Net income (loss) per weighted average share of common stock outstanding — diluted Year Ended December 31, 2021 2020 2019 (1,274) $ (17) (4) (1,295) 482,214,544 636 — — 636 488,668,263 $ 928 — — 928 494,146,268 (2.69) $ — 482,214,544 1.30 2,422,205 491,090,468 $ 1.88 5,789,223 499,935,490 (2.69) $ 1.30 $ 1.86 $ $ $ Stock-based incentive compensation plan awards excluded from the calculation of diluted earnings per share because the would have been antidilutive totaled 14,412,299, 12,553,414 and 2,447,850 shares for the years ended December 31, effect ff 2021, 2020 and 2019, respectively. 118 10. ACCOUNTS RECEIVABLE FINANCING Accounts Receivable Securitizat iontt tt Program TXU Energy Receivablea s Company LLC (RecCo), an indirect subsidiary of Vistra, has an accounts receivable finaff ncing facility (Receivables Facility) provided by issuers of asset-backed commercial paper and commercial banks (Purchasers). In December 2020, the Receivables Facility was amended to include Ambit Texas, LLC (Ambit Texas), Value Based Brands and TriEagle Energy, as originators, and increase the commitment of the Purchasers to $500 million for the remaining term of the 2021, the Receivables Facility was amended to allow for a one-time, $596 million borrowing Receivabla es Facility. In February to take advantage of a higher receivable balance at such time. The borrowing limit returned to $500 million in March 2021. In March 2021, the Receivables Facility was amended to increase the commitment of the Purchasers to $600 million through the July 2021 renewal. The Receivables Facility was renewed in July 2021, extending the term of the Receivables Facility to July 2022, with the abila ity to borrow $600 million beginning with the settlement date in July 2021 until the settlement date in August 2021, $725 million from the settlement date in August 2021 until the settlement date in November 2021 and $600 million from the settlement date in November 2021 and thereafter forff the remaining term of the Receivables Facility. rr t s Facility), arising fromff In connection with the Receivables Facility, TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands and TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivablea s Facility (Originators), each sell and/or contribute, subject to certain exclusions, all of its receivables (other than any receivables excluded pursuant to the terms the sale of electricity to its customers and related rights (Receivables), to RecCo, a of the Receivablea consolidated, wholly owned, bankruptcy-remote, direct subsidiary of TXU Energy. RecCo, in turn, is subject to certain a conditions, and may draw under the Receivablea to fund its acquisition of the Receivabla es from the Originators. RecCo has granted a security interest on the Receivablea s and all related assets for the benefit of the Purchasers under the Receivablea s Facility and Vistra Operations has agreed to guarantee the obligations under the s Facility. Amounts funded by the Purchasers to RecCo are reflected as short-term agreements governing the Receivablea s Facility are reflected as cash borrowings on the consolidated balance sheets. Proceeds and repayments under the Receivablea flows from financing activities in our consolidated statements of cash flows. s transferred to the Purchasers remain on Vistra's balance sheet and Vistra reflects a liabila ity equal to the amount advanced by the Purchasers. The Company records interest expense on amounts advanced. TXU Energy continues to service, administer and collect the Receivables on behalf of . RecCo and the Purchasers, as applicablea s Facility up to the limits described above Receivablea ff As of December 31, 2021, there were no outstanding borrowings under the Receivablea s Facility. As of December 31, s Facility totaled $300 million and were supported by $735 million of 2020, outstanding borrowings under the Receivablea RecCo gross receivablea s. Repuee rchase Faciliii tyii In October 2020, TXU Energy and the other originators under the Receivablea s Facility entered into a $125 million repurchase facility (Repurchase Facility) that is provided on an uncommitted basis by a commercial bank as buyer (Buyer). In July 2021, the Repurchase Facility was renewed until August 2021 and increased from $125 million to $150 million. In August 2021, the Repurchase Facility was renewed until July 2022 and the facility size was decreased from $150 million to $125 million. The Repurchase Facility is collateralized by a subordinated note (Subordinated Note) issued by RecCo in favor of s Facility and representing a portion of the outstanding balance TXU Energy for the benefit of Originators under the Receivablea of the purchase price paid forff s Facility. Under the Repurchase Facility, TXU Energy may request that Buyer transfer funds to TXU Energy in exchange for a transfer of the Subordinated Note, with a simultaneous agreement by TXU Energy to transfer funds to Buyer at a date certain or on demand in exchange for the returnt of the Subordinated Note (collectively, the Transactions). Each Transaction is expected to have a term of one month, unless terminated earlier on demand by TXU Energy or terminated by Buyer afteff s sold by the Originators to RecCo under the Receivablea r an event of default. the Receivablea TXU Energy and the other Originators have each granted Buyer a first-pri ority security interest in the Subordinated Note to secure its obligations under the agreements governing the Repurchase Facility, and Vistra Operations has agreed to guarantee the obligations under the agreements governing the Repurchase Facility. Unless earlier terminated under the agreements governing the Repurchase Facility, the Repurchase Facility will terminate concurrently with the schedule termination of the Receivabla es Facility. ff There were no outstanding borrowings under the Repurchase Facility at both December 31, 2021 and December 31, 2020. 119 11. LONG-TERM DEBT Amounts in the tablea below represent the categories of long-term debt obligations incurred by the Company. Vistra Operations Credit Facilities Vistra Operations Senior Secured Notes: 3.550% Senior Secured Notes, due July 15, 2024 3.700% Senior Secured Notes, dued 4.300% Senior Secured Notes, dued January 30, 2027 July 15, 2029 Total Vistra Operations Senior Secured Notes Vistra Operations Senior Unsecured Notes: 5.500% Senior Unsecured Notes, due September 1, 2026 5.625% Senior Unsecured Notes, due February 15, 2027 5.000% Senior Unsecured Notes, due July 31, 2027 4.375% Senior Unsecured Notes, due May 15, 2029 Total Vistra Operations Senior Unsecured Notes Other: a ity Agreements Forward Capac Equipment Financing Agreements 8.82% Building Financing due semiannually through February 11, 2022 (a) Other Total other long-term debt Unamortized debt premiums, discounts and issuance costs Total long-term debt including amounts due currently Less amounts dued Total long-term debt less amounts dued currently currently December 31, 2021 2020 $ 2,543 $ 2,572 1,500 800 800 3,100 1,000 1,300 1,300 1,250 4,850 213 92 3 3 311 (73) 10,731 (254) 10,477 $ $ 1,500 800 800 3,100 1,000 1,300 1,300 — 3,600 45 68 10 3 126 (68) 9,330 (95) 9,235 ____________ (a) Obligation related to a corporate office space finance lease. This obligation will be funded ff by amounts held in an escrow account that is refleff cted in current assets in our consolidated balance sheets. Vistrii a OperOO ations Credit Facilitll iett s As of December 31, 2021, the Vistra Operations Credit Facilities consisted of up tu o $5.268 billion in senior secured, first- lien revolving credit commitments and outstanding term loans, which consisted of revolving credit commitments of up to $2.725 billion, including a $2.35 billion letter of credit sub-facility (Revolving Credit Facility) and term loans of $2.543 billion ing transactions and amendments completed in 2021, 2020 and (Term Loan B-3 Facility). These amounts reflect the follow 2019: ff • • In March 2021, Vistra Operations borrowed $1.0 billion principal amount under the Term Loan A Facility. In April 2021, Vistra Operations borrowed an additional $250 million principal amount under the Term Loan A Facility. Proceeds from the Term Loan A Facility, together with cash on hand, were used to repay certain amounts outstanding under the Revolving Credit Facility. Borrowings under the Term Loan A Facility were reported in short-term borrowings in our condensed consolidated balance sheet. In May 2021, Vistra Operations used the proceeds from the 2029 (described below), together with cash on issuance of the Vistra Operations 4.375% senior unsecured notes dued hand, to repay the $1.250 billion borrowings under the Term Loan A Facility. We recorded an extinguishment loss of $1 million on the transaction in the nine months ended September 30, 2021. In March 2020, Vistra Operations repurchased and cancelled $100 million principal amount of Term Loan B-3 Facility borrowings at a weighted average price of $93.875. We recorded an extinguishment gain of $6 million on the transaction in the year ended December 31, 2020. 120 • • • • In November 2019, Vistra Operations used the net proceeds from the November 2019 Senior Secured Notes Offering described below and $799 million of incremental borrowings under the Term Loan B-3 Facility to repay the entire amount outstanding of $1.897 billion of term loans under the B-1 Facility (Term Loan B-1 Facility). Fees and expenses related to the transactions totaled $2 million in the year ended December 31, 2019, which were recorded as interest expense and other charges on the consolidated statements of operations. In October 2019, Vistra Operations borrowed $550 million under the Revolving Credit Facility. The proceeds of the borrowings were used for general corporate purposes, including the funding of a $425 million dividend to Vistra to pay the principal, premium and interest due in connection with the redemption by Vistra of the entire $387 million aggregate principal amount outstanding of 7.625% senior notes described below. In November 2019, Vistra Operations repaid $200 million under the Revolving Credit Facility. In June 2019, Vistra Operations used the net proceeds from the June 2019 Senior Secured Notes Offerings (described below) to repay $889 million under the Term Loan B-1 Facility, the entire amount outstanding of $977 million of term loans under the B-2 Facility (Term Loan B-2 Facility, and together with the Term Loan B-1 Facility and the Term Loan B-3 Facility, the Term Loan B Facility) and $134 million under the Term Loan B-3 Facility. We recorded an extinguishment loss of $4 million on the transactions in the year ended December 31, 2019. In March 2019 and May 2019, the Vistra Operations Credit Facilities were amended whereby we obtained $225 million of incremental Revolving Credit Facility commitments. The letter of credit sub-facility was also increased by $50 million. Fees and expenses related to the amendments to the Vistra Operations Credit Facilities totaled $2 million for the year ended December 31, 2019, which were capia talized as a noncurrent asset. During the year ended December 31, 2021, we borrowed $1.450 billion and repaid $1.450 billion under the Revolving Credit Facility, with proceeds from the borrowings used forff general corporate purposes. The Vistra Operations Credit Facilities and related availablea a capac ity at December 31, 2021 are presented below. December 31, 2021 Vistra Operations Credit Facilities Revolving Credit Facility (a) Term Loan B-3 Facility (b) Maturity Date June 14, 2023 December 31, 2025 Total Vistra Operations Credit Facilities Facility Limit $ $ 2,725 2,543 5,268 Cash Borrowings $ — $ Letters of Credit Outstanding Available Capacity 2,543 2,543 $ $ 1,471 1,471 $ $ 1,254 — 1,254 ___________ (a) Revolving Credit Facility used forff general corporate purposes. The Facility includes a $2.35 billion letter of credit sub- facility. Letters of credit outstanding reduce our available capacity. Cash borrowings under the Revolving Credit Facility are reported in short-term borrowings in our consolidated balance sheets. (b) Cash borrowings under the Term Loan B-3 Facility are subject to a required scheduled quarterly payment in annual amount equal to 1.00% of the original principal amount with the balance paid at maturity. Amounts paid cannot be reborrowed. As of December 31, 2021, cash borrowings under the Revolving Credit Facility would bear interest based on applicable LIBOR rates, plus a fixeff d spread of 1.75%, and there were no outstanding borrowings. Letters of credit issued under the Revolving Credit Facility bear interest of 1.75%. Amounts borrowed under the Term Loan B-3 Facility bears interest based on spreads of 1.75%. As of December 31, 2021, the weighted average interest rates before applicable LIBOR rates plus fixed taking into consideration interest rate swapsa on outstanding borrowings was 1.86% under the Term Loan B-3 Facility. The Vistra Operations Credit Facilities also provide for certain additional fees payable to the agents and lenders, including fronting fees with respect to outstanding letters of credit and availability fees payablea with respect to any unused portion of the availablea Revolving Credit Facility. ff Obligations under the Vistra Operations Credit Facilities are secured by a lien covering substantially all of Vistra Operations' (and its subsidiaries') consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra Operations Credit Facilities, provided that the amount of loans outstanding under the Vistra Operations Credit Facilities that may be secured by a lien covering certain principal properties of the Company is expressly limited by the terms of the Vistra Operations Credit Facilities. ff 121 The Vistra Operations Credit Facilities also permit certain hedging agreements to be secured on a pari-passu basis with the th in the Vistra Operations Vistra Operations Credit Facilities in the event those hedging agreements met certain criteria set forff Credit Facilities. The Vistra Operations Credit Facilities provide for affirmative and negative covenants appl icable to Vistra Operations (and its restricted subsidiaries), including affirmative covenants requiring it to provide financial and other information to the agents under the Vistra Operations Credit Facilities and to not change its lines of business, and negative covenants restricting Vistra Operations' (and its restricted subsidiaries') ability to incur additional indebtedness, make investments, dispose of assets, pay dividends, grant liens or take certain other actions, in each case, except as permitted in the Vistra Operations Credit Facilities. Vistra Operations' ability to borrow under the Vistra Operations Credit Facilities is subject to the satisfaction of certain customary conditions precedent set forth therein. a The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties, material breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against Vistra Operations. Solely with respect to the Revolving Credit Facility, and solely during when the aggregate revolving a compliance period (which, in general, is appli borrowings and issued revolving letters of credit (in excess of $300 million) exceed 30% of the revolving commitments), the agreement includes a covenant that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first lien debt compared to an EBITDA calculation defined under the terms of the Vistra Operations Credit Facilities, not to exceed 4.25 to 1.00. As of December 31, 2021, we were in compliance with this financial covenant. Upon the existence of an event of default, the Vistra Operations Credit Facilities provide that all principal, interest and other amounts due thereunder will become immediately due and payablea , either automatically or at the election of specified lenders. cablea d a tt Interes t Rate Swaps — Vistra employs interest rate swapsa to hedge our exposure to variable rate debt. As of December 31, 2021, Vistra has entered into the folff lowing series of interest rate swap ta ransactions. a Swapped Swapped a Swapped a Swapped a a Swapped a Swapped to fixed to variable to fixed (a) to variable to fixed (b) to variable (b) Notional Amount $3,000 $700 $720 $720 $3,000 $700 Expiration Date July 2023 July 2023 February 2024 2024 rr February July 2026 July 2026 Rate Range 3.67 % - 3.91% 3.20 % - 3.23% 3.71 % - 3.72% 3.20 % - 3.20% 4.72 % - 4.79% 3.28 % - 3.33% (a) In June 2018, we completed the novation of $1.959 billion of Vistra (legacy Dynegy) interest rate swapsa Operations, of which $398 million expired and $841 million were terminated in June 2019. to Vistra (b) Effective from July 2023 through July 2026. During 2019, Vistra entered into $2.12 billion of new interest rate swaps,a and receive a fixeff offsetting the hedge of the existing swapsa settle over time, in accordance with the original contractual exposure on $2.30 billion of debt through July 2026. t d rate. The terms of these new swaps were matched against the terms of certain existing swaps,a and fixing the out-of-the-money position of such swaps.a pursuant to which Vistra will pay a variable rate effectively These matched swapsa will continue to hedge our terms. The remaining existing swapsa 122 Commodity-Ltt inked Revolvill ngii Credit Facilitll ytt r On February 4, 2022, Vistra Operations entered into a credit agreement by and among Vistra Operations, Vistra Intermediate, the lenders, joint lead arrangers and joint bookrunners party thereto, and Citibank, N.A., as administrative agent and collateral agent. The Credit Agreement provides forff a $1.0 billion senior secured commodity-linked revolving credit facility (the Commodity-Linked Facility). Under the Commodity-Linked Facility, the borrowing base is calculated on a weekly basis based on a set of theoretical transactions which approximate the hedge portfolio of Vistra Operations and certain of its subsidiaries in certain power markets, with availability thereunder not to exceed the facility limit nor be less than zero. Vistra Operations may, at its option, borrow an amount up to the borrowing base, as adjusted from time to time, provided that if outstanding borrowings at any time would exceed the borrowing base, Vistra Operations shall make a repayment to reduce outstanding borrowings to be less than or equal to the borrowing base. 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 capita al and general corporate purposes. Secured Lettertt of Credit Faciliii tiii es In August and September 2020, Vistra entered into uncommitted standby letter of credit facilities that are each secured by a first lien on substantially all of Vistra Operations' (and its subsidiaries') assets (which ranks pari passu with the Vistra ff Operations Credit Facilities) (each, a Secured LOC Facility and collectively, the Secured LOC Facilities). The Secured LOC Facilities are used for general corporate purposes. In October 2021, Vistra entered into an additional Secured LOC Facility which will also be used for general corporate purposes. As of December 31, 2021, $406 million of letters of credit were outstanding under the Secured LOC Facilities. rr Altertt nate Lettertt of Credit Faciliii tiii es Two alternate letter of credit facilities (each, an Alternate LOC Facility) became effective in the years ended December ility limit of $250 million matured in ility limit of $250 million matured in December 31, 2018 and 2019, respectively. One Alternate LOC Facility with an aggregate facff December 2020. The remaining Alternate LOC Facility with an aggregate facff 2021. tt Vistra Operat ions OO Senior Secured NotesNN In 2019, Vistra Operations issued and sold $3.1 billion aggregate principal amount of senior secured notes (June 2019 Senior Secured Notes and the November 2019 Senior Secured Notes) in offerings (the June 2019 Senior Secured Notes Offering and the November 2019 Senior Secured Notes Offering) to eligible purchasers under Rule 144A and Regulation S under the Securities Act consisting of the folff lowing: Senior Secured Notes 3.550% Senior Secured Notes 3.700% Senior Secured Notes 4.300% Senior Secured Notes Total senior secured notes Net proceeds Debt issuance and other fees (c) Maturity Year 2024 2027 2029 Interest Terms (Due Semiannually in Arrears) January 15 and July 15 January 30 and July 30 January 15 and July 15 June 2019 Senior Secured Notes Offering (a) 1,200 $ — 800 2,000 1,976 20 $ $ $ November 2019 Senior Secured Notes Offering (b) 300 $ 800 — 1,100 1,099 10 $ $ $ ___________ (a) The June 2019 Senior Secured Notes were sold pursuant to a purchase agreement by and among Vistra Operations, certain direct and indirect subsidiaries of Vistra Operations and Citigroup Global Markets Inc., as representative of the several initial purchasers. Net proceeds, together with cash on hand, were used to prepay certain amounts outstanding and accrued interest (together with feeff s and expenses) under the Term Loan B Facility. (b) The November 2019 Senior Secured Notes were sold pursuant to a purchase agreement by and among Vistra Operations, certain direct and indirect subsidiaries of Vistra Operations and J.P. Morgan Securities LLC., as representative of the several initial purchasers. Net proceeds, together with borrowings under the Term Loan B-3 Facility and cash on hand, were used to repay the entire amount outstanding and accrued interest (together with fees and expenses) under the Term Loan B-1 Facility. 123 (c) Capita alized as a reduction in the carrying amount of the debt. The indenturet (as may be amended or supplemented fromff time to time, the Vistra Operations Senior Secured Indenture) governing the June 2019 Senior Secured Notes and the November 2019 Senior Secured Notes (collectively, the Senior Secured the full and unconditional guarantee by certain of Vistra Operations' current and future subsidiaries that also Notes) provides forff guarantee the Vistra Operations Credit Facilities. The Senior Secured Notes are secured by a first-pri ority security interest in the same collateral that is pledged for the benefit of the lenders under the Vistra Operations Credit Facilities, which consists of a substantial portion of the property, assets and rights owned by Vistra Operations and certain direct and indirect subsidiaries of Vistra Operations as subsidiary guarantors (collectively, the Guarantor Subsu idiaries) as well as the stock of Vistra Operations held by Vistra Intermediate. The collateral securing the Senior Secured Notes will be released if Vistra Operations' senior, unsecured long-term debt securities obtain an investment grade rating fromff two out of the three rating agencies, subject to reversion if such rating agencies withdraw the investment grade rating of Vistra Operations' senior, unsecured long-term debt securities or downgrade such rating below investment grade. The Vistra Operations Senior Secured Indenturet contains certain covenants and restrictions, including, among others, restrictions on the ability of Vistra Operations and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets. ff t tt Vistra Operat ions OO Senior Unsecured NotesNN In 2019 and 2021, Vistra Operations issued and sold $3.9 billion aggregate principal amount of senior unsecured notes in offerings (the February 2019 Senior Unsecured Notes Offering, June 2019 Senior Unsecured Notes Offerings and the May 2021 Senior Unsecured Offerings) to eligible purchasers under Rule 144A and Regulation S under the Securities Act consisting of the following: Maturity Year 2027 2027 2029 Interest Terms (Due Semiannually in Arrears) February 15 and August 15 January 31 and July 31 May 1 and November 1 Senior Unsecured Notes 5.625% Senior Unsecured Notes 5.000% Senior Unsecured Notes 4.375% Senior Unsecured Notes Total Net Proceeds Debt issuance and other fees (d) February 2019 Senior Unsecured Notes Offering (a) 1,300 — — 1,300 $ 1,287 $ 16 $ June 2019 Senior Unsecured Notes Offering (b) — 1,300 — 1,300 $ 1,287 $ 13 $ May 2021 Senior Unsecured Notes Offering (c) — — 1,250 1,250 1,235 15 $ $ $ ___________ (a) The 5.625% senior unsecured notes dued 2027 (the Februar 019 Senior Unsecured Notes) were sold pursuant to a purchase agreement by and among Vistra Operations, the Guarantor Subsidiaries and J.P. Morgan Securities LLC., as representative of the several initial purchasers. Net proceeds, together with cash on hand, were used to pay the purchase 019 Tender price and accrued interest (together with fees and expenses) required in connection with (i) the Februarr Offer, (defined below) and (ii) the redemption of approximately $35 million aggregate principal amount of our 7.375% senior unsecured notes dued 2022 (7.375% senior notes) and approximately $25 million aggregate principal amount of our outstanding 8.034% senior unsecured notes dued 2024 (8.034% senior notes). ry 2rr ry 2rr (b) The 5.000% senior unsecured notes dued 2027 (the June 2019 Senior Unsecured Notes) were sold pursuant to a purchase agreement by and among Vistra Operations, the Guarantor Subsidiaries and Goldman Sachs & Co. LLC, as representative of the several initial purchasers. Net proceeds, together with cash on hand, were used to pay the purchase price and accrued interest (together with fees and expenses) required in connection with (i) the June 2019 Tender Offer (defined below) and (ii) the redemption of approximately $306 million of our outstanding 7.375% senior notes and approximately $87 million of our 7.625% senior unsecured notes dued 2024 (7.625% senior notes) in July 2019. We recorded an extinguishment gain of $2 million on the redemptions in the year ended December 31, 2019 (c) The 4.375% senior unsecured notes dued 2029 (the May 2021 Senior Unsecured Notes) were sold pursuant to a purchase the Guarantor Subsidiaries and J.P. Morgan Securities LLC., as agreement by and among Vistra Operations, representative of the several initial purchasers. Net proceeds. together with cash on hand, were used to pay all amounts outstanding under the Term Loan A Facility and to pay feeff s and expenses of $15 million related to the offering. (d) Capitalized as a reductd ion in the carrying amount of the debt. 124 Since 2018, Vistra Operations has issued and sold $4.850 billion aggregate principal amount of senior unsecured notes in offerings to eligible purchasers under Rule 144A and Regulation S under the Securities Act. The indentures governing the May 2021 Senior Unsecured Notes, the June 2019 Senior Unsecured Notes, the Februarr 019 Senior Unsecured Notes and the 2026 (collectively, as each may be amended or supplemented from time to time, the Vistra 5.500% senior unsecured notes dued provide for the full and unconditional guarantee by the Guarantor Subsidiaries of the Operations Senior Unsecured Indentures) t punctual contain payment of the principal and interest on such notes. The Vistra Operations Senior Unsecured Indentures t certain covenants and restrictions, including, among others, restrictions on the ability of Vistra Operations and its subsidiaries, as applicable, to create certain liens, merge or consolidate with another entity, and sell all or substantially all of their assets. ry 2rr t ee Debt Repurc hase Program In July 2019, the Board authorized up to $1.0 billion to repay or repurchase any outstanding debt of the Company (or its subsidiaries). Through April 2020, $684 million of debt had been repurchased under the $1.0 billion July 2019 authorization, including the repurchase of $100 million principal amount of Term Loan B-3 Facility borrowings discussed above and the redemption of $81 million aggregate principal amount outstanding of 8.000% senior unsecured notes dued 2025 (8.000% senior notes) discussed below. In April 2020, the Board authorized up to $1.0 billion to repay or repurchase additional outstanding debt, with this new authority superseding and replacing the $316 million of availability under the previously authorized $1.0 billion debt repurchase program. Through December 31, 2021, approximately $666 million had been repurchased under the $1.0 billion April 2020 authorization, consisting of the redemption of the Vistra 5.875% senior unsecured notes dued 2023 2026 (8.125% senior notes), each as (5.875% senior notes) and the redemption of the Vistra 8.125% senior unsecured notes dued described below. SS Vistra Senio r UnseUU cured NotesNN On the Merger Date, Vistra assumed $6.138 billion principal amount of Dynegy's senior unsecured notes (Vistra Senior In June 2018, each of the Company's subsidiaries that guaranteed the Vistra Operations Credit Facilities Unsecured Notes). (and did not already guarantee the senior notes) provided a guarantee on the senior notes that remained outstanding. The following amounts reflect redemption, repurchase and tender offer transactions completed in 2019 and 2020. Vistra had no outstanding senior notes at the Parent level as of December 31, 2021 and 2020. Vistra Senior Unsecured Notes 6.750%Senior Unsecured Notes 7.375% Senior Unsecured Notes 5.875% Senior Unsecured Notes 7.625% Senior Unsecured Notes 8.034% Senior Unsecured Notes 8.000% Senior Unsecured Notes 8.125%Senior Unsecured Notes Total Extinguishment gain/(loss) Maturity Year 2019 2022 2023 2024 2024 2025 2026 February 2019 Tender Offer (a) June 2019 Tender Offer (b) 2019 Redemptions (c) 2020 Redemptions (d) $ $ $ — $ 1,193 — — — — — 1,193 $ 7 $ — $ 173 — 672 — — — 845 7 $ $ — $ 341 — 475 25 — — 841 11 $ $ — — 500 — — 81 166 747 11 ____________ (a) In February 2019, Vistra used the net proceeds from the Februar tender offer (the February senior notes. 019 Senior Unsecured Notes Offering to fund a cash 2019 Tender Offer) to purchase for cash $1.193 billion aggregate principal amount of 7.375% y 2rr rr r (c) (b) In June 2019, Vistra used the net proceeds from the June 2019 Notes Offering to fund a cash tender offer (the June 2019 Tender Offer) to purchase for cash $173 million of 7.375% senior notes and $672 million of 7.625% senior notes. In July 2019, Vistra accepted and settled an additional approximately $1 million aggregate principal amount of outstanding 7.625% senior notes that were tendered after the early tender date of the June 2019 Tender Offer. In November 2019, Vistra redeemed $387 million aggregate principal amount outstanding of 7.625% senior notes at a redemption price equal to 103.8% of the aggregate principal amount thereof, plus accrued and unpaid interest to, but excluding, the date of redemption (the 2019 Redemption). Vistra redeemed $341 million, $87 million and $25 million aggregate principal amount of 7.375% senior notes, 7.625% senior notes and 8.034% senior notes, respectively, using proceeds from the February 2019 Senior Unsecured Notes Offering and the June 2019 Senior Unsecured Notes Offerings discussed above. rr 125 (d) In January 2020, June 2020 and July 2020, Vistra redeemed aggregate principal amounts of $81 million of 8.000% senior notes, $500 million of 5.875% senior notes and $166 million of 8.125% senior notes, respectively, at redemption prices of 104%, 100.979% and 104.063%, respectively, of the aggregate principal amounts thereof, plus accrued and unpaid interest to, but excluding, the dates of redemption (the 2020 Redemptions, and together with the 2019 Redemption, the Redemptions). February 2019 Consent Solicitation — In connection with the February rr 2019 Tender Offer, Vistra also commenced holders of the 7.375% senior notes. Vistra received the requisite consents from the holders of the governing these senior notes to, among other things, eliminate substantially all solicitation of consents fromff 7.375% senior notes and amended the indenturet of the restrictive covenants and certain events of default. Other Long-TermTT Debt Amortizing Notes — On the Merger Date, Vistra assumed the obligations of Dynegy's senior unsecured amortizing note (Amortizing Notes) that maturet d on July 1, 2019. The Amortizing Notes were issued in connection with the issuance of the tangible equity units (TEUs) by Dynegy (see Note 14). Each installment payment per Amortizing Note was paid in cash and constituted a partial repayment of principal and a payment of interest, computed at an annual rate of 7.00%. Interest was calculated on the basis of a 360-day year consisting of twelve 30-day months. Payments were applied first to the interest due (Amortizing Notes and payablea and the Amortizing t Indenture). Notes Indenturet and then to the reduction of the unpaid principal amount, allocated as set forth in the indenturet On the maturity date, the Company paid all amounts due under the Amortizing Notes Indenturet ceased to be of further force and effecff t. ff Forward Capacity Agreementstt — In March 2021, the Company sold a portion of the PJM capac Planning Years 2021-2022 to a finaff will receive capacity payments fromff We will continue to be subject to the performanc payments forff of approximately 4.25%. ff t ity that cleared for ncial instituti on (2021-2022 Forward Capacity Agreement). The buyer in this transaction PJM during the Planning Years 2021-2022 in the amount of approximately $515 million. e obligations as well as any associated performance penalties and bonus as a debt issuance with an implied interest rate a those planning years. As a result, this transaction is accounted forff On the Merger Date, the Company assumed the obligation of Dynegy's agreements under which a portion of the PJM capac on (Legacy ity that cleared for Planning Years 2018-2019, 2019-2020 and 2020-2021 was sold to a finaff a Forward Capacity Agreements, and, together with the 2021-2022 Forward Capacity Agreement, the Forward Capacity In May 2021, the final capacity payment from PJM during the Planning Years 2020-2021 was paid, and the Agreements). terms of the Legacy Forward Capacity were fulfilled. ncial instituti tt i Equipment Financing Agreements — On the Merger Date, the Company assumed the obligation of Dynegy's agreements our gas-fueled generation fleet, we have obtained parts and under which we receive maintenance and capital improvements forff equipment intended to increase the output, efficiency and availability of our generation units. We financed these parts and equipment under agreements with maturit ies ranging from 2021 to 2026. t Mandatorily Rll k — In October 2019, PrefCo voluntarily redeemed the entire $70 million aggregate principal amount outstanding of its authorized preferred stock at a price per share equal to the preferred liquidation amount, plus accrued and unpaid dividends to and including the date of redemption. edeedd mable Subsidiary Pr ff referre d StocSS Debt Assumed in CriCC us Transaction — On the Crius Acquisition Date, Vistra assumed $140 million in long-term debt obligations in connection with the Crius Transaction consisting of the folff lowing: • • • $44 million of 9.5% promissory notes due July 2025 (2025 promissory notes); $8 million of 2% Connecticut Department of Economic and Community Development (CT DECD) term loans due February 2rr $88 million of borrowings and $9 million of issued letters of credit under the legacy Crius credit facility. 027; and In In July 2019, borrowings of $88 million under the legacy Crius credit facility were repaid using cash on hand. November 2019, (i) borrowings of approximately $38 million under the 2025 promissory notes were repaid using cash on hand and (ii) borrowings of approximately $2 million were offset by legacy indemnification obligations of the holders of the 2025 promissory notes. In November 2019, borrowings of $8 million under the Connecticut Department of Economic and Community Development term loans were repaid using cash on hand. 126 Maturitiett s Long-term debt maturities at December 31, 2021 are as follows: 2022 2023 2024 2025 2026 Thereafter Unamortized premiums, discounts and debt issuance costs Total long-term debt, including amounts due currently LEASES December 31, 2021 258 $ 40 1,540 2,470 1,006 5,490 (73) 10,731 $ Vistra has both finance and operating leases for real estate, rail cars and equipment. Our leases have remaining lease o 15 years. Certain leases also contain options to terminate the terms for 1 to 36 years. Our leases include options to renew up tu lease. Lease Cost The following tablea presents costs related to lease activities: Operating lease cost Finance lease: Finance lease right-of-use asset amortization Interest on lease liabilities Total finance lease cost Variablea lease cost (a) Short-term lease cost Sublease income (b) Net lease cost Year Ended December 31, 2021 2020 2019 $ 11 $ 14 $ 9 10 19 29 35 (7) 87 $ 7 7 14 29 31 (8) 80 $ $ 14 4 4 8 26 19 (8) 59 ____________ (a) Represents coal stockpile management services, common area maintenance services and rail car payments based on the number of rail cars used. (b) Represents sublease income related to real estate leases. 127 Balance SheSS et Infon rmation The following tablea presents lease related balance sheet information: Lease assets: Operating lease right-of-use assets Finance lease right-of-use assets (net of accumulated depreciation) Total lease right-of-use assets Current lease liabila ities: Operating lease liabia lities Finance lease liabilities Total current lease liabila ities Noncurrent lease liabilities: Operating lease liabila ities Finance lease liabilities Total noncurrent lease liabila Total lease liabilities ities Cash FlowFF s aw nd Other Information The following tablea presents lease related cash flows ff and other information: December 31, 2021 2020 $ $ $ $ 40 173 213 5 8 13 38 235 273 286 $ Cash paid for amounts included in the measurement of lease liabila ities: Operating cash flows fromff Operating cash flows from finance leases Finance cash flows fromff finance leases operating leases Non-cash disclosure upon commencement of new lease: Right-of-use assets obtained in exchange for new operating lease liabilities Right-of-use assets obtained in exchange for new finance lease liabilities Non-cash disclosure upon modification of existing lease: Modification of operating lease right-of-use assets Modification of finance lease right-of-use assets ightedtt Average Remaininii g Ln ease Term Year Ended December 31, 2021 2020 2019 $ $ 11 9 5 7 — (4) (1) $ 17 5 10 14 108 (1) 23 45 182 227 8 8 16 40 206 246 262 17 4 4 95 13 (41) 50 The following tablea presents weighted average remaining lease term information: Weighted average remaining lease term: Operating lease Finance lease Weighted average discount rate: Operating lease Finance lease 128 December 31, 2021 2020 17.6 years 25.0 years 12.3 years 24.2 years 5.76% 4.95% 5.80 % 4.92 % Maturity ott f Lo ease Liabiliii tiii es The following tabla e presents maturity of lease liabilities: 2022 2023 2024 2025 2026 Thereafter Total lease payments Less: Interest Present value of lease liabila ities 13. COMMITMENTS AND CONTINGENCIES Contractual Commitmii ents Operating Lease 6 $ 7 4 3 3 51 74 (31) 43 $ Finance Lease 17 16 17 17 14 369 450 (207) 243 $ $ $ $ Total Lease 23 23 21 20 17 420 524 (238) 286 As of December 31, 2021, we had minimum contractual ff contracts, energy-related contracts, leases and other agreements as foll commitments under long-term service and maintenance ows. t 2022 2023 2024 2025 2026 Thereafter Total Long-Term Service and Maintenance Contracts (a) Coal transportation agreements Pipeline transportation and storage reservation fees Water Contracts $ $ 202 268 236 207 196 2,130 3,239 $ $ 104 22 24 25 26 27 228 $ $ 86 54 40 36 23 91 330 $ $ 9 9 9 9 9 58 103 ____________ (a) Long-term service and maintenance contracts reflect expected expenditures t as these contracts do not include minimum spending requirements, but can only be terminated based on events outside the control of the Company. In addition to the commitments detailed above a , we have nuclear fuel ff contracts with early termination penalties. As of December 31, 2021, termination costs of $54 million would be incurred if we terminated those contracts. Expenditures t under our coal purchase and coal transportation agreements totaled $850 million, $845 million, and $1.092 billion for the years ended December 31, 2021, 2020 and 2019, respectively. s Guaranteett We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. Material guarantees are discussed below. 129 Letters orr f Co redCC itdd As of December 31, 2021, we had outstanding letters of credit totaling $1.877 billion as follows: • • • • • $1.558 billion to support commodity risk management collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and collateral postings with ISOs/RTOs; $157 million to support battery and solar development projects; $27 million to support executory contracts and insurance agreements; $74 million to support our REP finaff $61 million for other credit support requirements. ncial requirements with the PUCT; and Surety Bonds As of December 31, 2021, we had outstanding surety bonds totaling $561 million to support performff ance under various contracts and legal obligations in the normal course of business. i Litiii gati on and Regulatll orytt Proceedings ii Our material legal proceedings and regulatory proceedings affecting our business are described below. We believe that we have valid defenses to the legal proceedings described below and intend to defend them vigorously. We also intend to participate in the regulatory processes described below. We record reserves for estimated losses related to these matters when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable, we have established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as incurred. Management has assessed each of the following legal matters based on current information and made a judgment of damages sought, and the concerning its potential outcome, considering the naturet probability of success. Unless specified below, we are unable to predict the outcome of these matters or reasonablya estimate the scope or amount of any associated costs and potential liabilities, but they could have a material impact on our results of operations, liquidity, or financial condition. As additional information becomes available, we adjust our assessment and to inherent estimates of such contingencies accordingly. Because litigation and rulemaking proceedings are subject uncertainties and unfavorablea rulings or developments, it is possible that the ultimate resolution of these matters could be at amounts that are different from our currently recorded reserves and that such differences could be material. of the claim, the amount and naturet i Gas Index Pricing Litigati on — We, through our subsidiaries, and other companies are named as defendants in several lawsuits claiming damages resulting from alleged price manipulation through false reporting of natural gas prices to various index publications, wash trading and churn trading from 2000-2002. The plaintiffs in these cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices during the relevant time period and seek damages under the respective state antitrust statutes. In December 2021, we settled an individual action with Reorganized FLI, Inc., as successor to Farmland Industries, Inc., that was pending in Kansas fede ral court, and that case has now been dismissed. We remain as a defendant in one other action, which is a consolidated putative class action lawsuit pending in federal court in Wisconsin. ff t t Wood River Rail Dispute — In November 2017, Dynegy Midwest Generation, LLC (DMG) received notification that BNSF Railway Company and Norfolk Southern Railway Company were initiating dispute resolution related to DMG's suspension of its Wood River Rail Transportation Agreement with the railroads. In March 2018, BNSF Railway Company (BNSF) and Norfolk Southern Railway Company (NS) filed a demand for arbitration. In March 2021, the parties entered into a In connection with that settlement, confidential settlement to resolve this matter and the Coffeen matter discussed below. BNSF and NS dismissed with prejudice their arbitration disputes forff Wood River and Coffeen and these matters are fully resolved. 130 o Coffeen and Duck CreekCC Rail Disputes — In April 2020, IPH, LLC (IPH) received notification that BNSF and NS were initiating dispute resolution related to IPH's suspension of its Coffeen Rail Transportation Agreement with the railroads, and Illinois Power Resources Generating, LLC (IPRG), received notification that BNSF was initiating dispute resolution related to In November 2019, IPH and IPRG sent IPRG's suspension of its Duck Creek Rail Transportation Agreement with BNSF. suspension notices to the railroads asserting that the MPS rule requirement to retire at least 2,000 megawatts of generation (see discussion below) was a change-in-law under the agreement that rendered continued operation of the plants no longer sible. In addition, IPH and IPRG asserted that the MPS rule's retirement requirement also qualified as a force economically feaff In March 2021, we entered into a confidential settlement majeua agreement with BNSF to resolve the Duck Creek matter and a separate confidential settlement agreement with BNSF and NS to resolve the Coffeen and Wood River matter discussed above. BNSF has dismissed with prejudice the Duck Creek arbitration dispute and this matter is now fully resolved. The settlement of these rail disputes did not have a material impact on our financial statements. re event under the agreements excusing performance. Wintertt Stormtt e Uri Legal Proceedings e Reprici In our brief, we argue that the prior PUCT rushed ng Challenges — In March 2021, we filed an appeal in the Third Court of Appeals in Austin, Texas (Third Court of Appeals), challenging the PUCT's February 15 and February 16, 2021 orders governing ERCOT's determination of wholesale power prices during load-shedding events. We filed our opening brief in June 2021, and response briefs were filed in that dramatically raised the price of September 2021. the PUCT to undertake an electricity in ERCOT, but in doing so failed to follow any of the rulemaking procedures required forff emergency rulemaking, and we have asked the court to vacate this rulerr . Other parties also filed briefs in support of our challenge to the PUCT's orders. In addition, we have also submitted settlement disputes with ERCOT over power prices and other issues during Winter Storm Uri. Following an appeal of the PUCT's March 5, 2021 verbal order and other statements made by the PUCT, the Texas Attorney General, on behalf of the PUCT, its client, represented in a letter agreement filed with l decision on whether to reprice and that we and the Third Court of Appeals that the PUCT has not prejudged or made a finaff other parties may continue disputing the pricing through the ERCOT process. to adopt a rulerr d r rr Koch Disputes — In March 2021, we filed a lawsuit in Texas state court against Odessa-Ector Power Partners, L.P., Koch relief in Resources, LLC, Koch AG & Energy Solutions, LLC, and Koch Energy Services, LLC (Koch) seeking equitablea which we contested the amount of the February 2021 earnout payment under the terms of the 2017 asset purchase agreement (APA) with Koch. Koch subsequently filed its own related lawsuit in Delaware Chancery Court, and the Delaware Chancery Court ruled that all claims related to the APA dispute (including our equitablea claims) would proceed in Delaware. We 021 earnout payment as an unjust windfall and inconsistent with contested Koch's demand for $286 million for the February 2rr the parties' intent when they entered into the APA in 2017. We recorded a $286 million liability in other noncurrent liabilities and deferred credits in our consolidated balance sheets. In March 2021, we also filed a lawsuit in New York state court against ff Koch for breach of contract and ineffective notice of force majea ure related to Koch's failure to deliver contracted-for quantities In November 2021, the disputes we had with Koch of gas during Winter Strom Uri, which Koch removed to federal court. were resolved to the parties' mutual satisfact ion and all the lawsuits have been dismissed. The matter was resolved within the amount that was reserved and will be paid in the second quarter of 2022. ff i e Regulat ory Investigations and Other Litigati on Matters — Following the events of Winter Storm Uri, various regulatory bodies, including ERCOT, the ERCOT Independent Market Monitor, the Texas Attorney General, the FERC and the NRC initiated investigations or issued requests for information of various parties related to the significant load shed event that occurred during the event as well as operational challenges forff generators arising from the event, including performance and fuel and supply issues. We responded to all those investigatory requests. In addition, a number of personal injury and wrongful death lawsuits related to Winter Storm Uri have been filff ed in various Texas state courts against us and numerous generators, transmission and distribution utilities, retail and electric providers, as well as ERCOT. We and other defendants requested that all pretrial proceedings in these personal injury cases be consolidated and transferred to a single multi-district litigation (MDL) pretrial judge. In June 2021, the MDL panel granted the request to consolidate all these cases into a MDL for pretrial 022, an insurance subrogation lawsuit was filed in Austin state court by over one hundred proceedings. In addition, in January 2rr insurance companies against ERCOT, Vistra and several other defendants. The lawsuit seeks recovery of insurance funds paid out by these insurance companies to various policyholders for claims related to Winter Storm Uri. We believe we have strong defenses to this lawsuit and the other tort lawsuits and intend to defend against these cases vigorously. 131 Climate Change nd the Environment and Restoring Science to Tackl In January 2021, the Biden administration issued a series of Executive Orders, including one titled Protecting Public (the Environment Executive Order) which Health att directed agencies, including the EPA, to review various agency actions promulgated during the prior administration and take action where the previous administration's action conflicts with national objectives. Several of the EPA agency actions discussed below are now subject to this review. e the Climate Crisisii TT Greenhouse Gas Emissions (GHG)HH Clean Energy (ACE) rule. The ACE ruler to that repealed the Clean Power Plan (CPP) that had been finaff In July 2019, the EPA finalized a ruler lized in 2015 and shed new regulations addressing GHG emissions from existing coal-fueled electric generation units, referred to as the establia developed emission guidelines that states must use when developing plans Affordablea In response to challenges brought by to regulate GHG emissions from existing coal-fueled electric generating units. the District of Columbia Circuit (D.C. Circuit Court) Environmental groups and certain states, the U.S. Court of Appeals forff vacated the ACE ruler , including the repeal of the CPP, in January 2021 and remanded the rule to the EPA for further action. In October 2021, the U.S. Supreme Court granted four petitions for certiorari of the D.C. Circuit Court's decision and consolidated the cases for review. The case is now fully briefed and scheduled for oral argument in February 2022. Additionally, in January 2021, the EPA, just prior to the transition to the Biden administration, issued a finaff a significant contribution finding for the purpose of regulating GHG emissions from new, modified, or reconstructed electric utility generating units. In and remand of the GHG April 2021, the D.C. Circuit Court granted the EPA's unopposed motion for voluntary vacaturt significant contribution rule. The ACE ruler and the rule on significant contribution are subject to the Environment Executive Order discussed above. setting forth l rulerr ff PP Regie onal Haze — Reasonable Pll rogress and Best Availabl e Rll ii tt etrofit Technology (BARBB T) for Texas ee l ruler addressing BART forff In October 2017, the EPA issued a finaff Texas electricity generation units, with the rule serving as a partial approval of Texas' 2009 State Implementation Plan (SIP) and a partial Federal Implementation Plan (FIP). For SO2, the rule established an intrastate Texas emission allowance trading program as a "BART alternative" that operates in a to a CSAPR trading program. The program includes 39 generating units (including the Martin Lake, Big ff similar fashion Brown, Monticello, Sandow 4, Coleto Creek, Stryker 2 and Graham 2 plants). The compliance obligations in the program started on January 1, 2019. For NOX, the rule adopted the CSAPR's ozone program as BART and for particulate matter, the ruler In but also included additional revisions that were August 2020, the EPA issued a finaff proposed in November 2019. Challenges to both the 2017 rule and the 2020 rules have been consolidated in the D.C. Circuit , and the retirements of our Court, where we have intervened in support of the EPA. We are in compliance with the ruler Monticello, Big Brown and Sandow 4 plants have enhanced our ability to comply. The BART rulerr is subject to the Environment Executive Order discussed above, and the EPA has stated it is starting a proceeding for reconsideration of the BART rule. The challenges in the D.C. Circuit Court have been held in abeyance pending the EPA's action on reconsideration. approved Texas's SIP that determines that no electricity generation units are subject to BART forff affirming the prior BART finaff particulate matter. l rulerr l ruler 132 SO2 Designations for Texas u u In December 2017, the TCEQ submi tted a petition for reconsideration to the EPA. the Fifth Circuit (Fifthff Circuit Court). Subsequent 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 U.S. Court of Appeals forff ly, in October 2017, the Fifth Circuit Court granted the EPA's motion to hold the case in abeyance considering the EPA's representation that it intended to revisit the In August 2019, the nonattainment rule. 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 unclassifiablea In August 2020, the EPA issued a . Finding of Failure for Texas to submit an attainment plan. 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, with the matter likely being fully briefed by March 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 SO2 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 will be submitted to the EPA forff review and approval. Effluff ent Limitati tt on Guidelines ll (ELGs)GG ff In November 2015, the EPA revised the ELGs forff steam electricity generation facilities, which will impose more stringent ation (FGD), fly ash, bottom standards (as individual permits are renewed) for wastewater streams, such as flue gas desulfuriz ash and flue gas mercury control wastewaters. Various parties filff ed petitions for review of the ELG rulrr e, and the petitions were consolidated in the Fifth Circuit Court. In April 2017, the EPA granted petitions requesting reconsideration of the ELG rulrr e and administratively stayed the rule's compliance date deadlines. In August 2017, the EPA announced that its reconsideration of the ELG rulrr e would be limited to a review of the effluent limitations applicable to FGD and bottom ash wastewaters and the agency subsequently postponed the earliest compliance dates in the ELG rulrr e forff cation of effluent limitations for FGD and bottom ash wastewaters. Based on these administrative developments, the Fifth Circuit Court agreed to sever and hold in abeyance challenges to those effluent limitations. The remainder of the case proceeded, and in April 2019 the Fifth Circuit pertaining to effluent limitations for legacy wastewater and Court vacated and remanded portions of the EPA's ELG ruler leachate. The EPA published a finaff both FGD and bottom ash transport water to no later than December 2025, as negotiated with the state permitting agency. Additionally, the final rulrr e ilities certifying that units will retire by December 2028 provided certain allows for a retirement exemption that exempts facff review of the new ELG revisions, and effluent limitations are met. Vistra subsidiaries filff ed a motion to intervene in support of the EPA in December 2020. In July 2021, the EPA announced its intent to revise the ELG rulerr 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. In November 2020, environmental groups petitioned forff in October 2020 that extends the compliance date forff a the appli l ruler CC Coal Combust iontt Residuals (CCR)/Groundw R ater In August 2018, the D.C. Circuit Court issued a decision that vacates and remands certain provisions of the 2015 CCR establishing a rule, including an applicability exemption for legacy impoundments. In August 2020, the EPA issued a finaff deadline of April 11, 2021 to cease receipt of waste and initiate closure at unlined CCR impoundments. The final ruler 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 rulrr e 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 in the D.C. Circuit Court, and Vistra subsidiaries fileff d a motion to intervene in support of the EPA in December 2020. this rulerr Also, in November 2020, the EPA finalized a rulerr 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 transferff owing 022, the EPA determined that our conversion and announcement that Zimmer will close by May 31, 2022. retirement applications for our CCR facff determination on any of those applications. In January 2rr ilities were complete but has not yet made a final our conversion application for the Zimmer facility to a retirement application foll l ruler ff ff 133 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. a In May 2018, Prairie Rivers Network (PRN)RR At our retired Vermilion facility, which was not potentially subject to the EPA's 2015 CCR ruler 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 forff additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing filed a citizen suit in federal court in Illinois against DMG, alleging options. In August 2018, we filed a motion to dismiss the violations of the Clean Water Act for alleged unauthorized discharges. lawsuit. In November 2018, the district court granted our motion to dismiss and judgment was entered in our favor. In June the Seventh Circuit affirmed the district court's dismissal of the lawsuit, but stated that PRN 2021, the U.S. Court of Appeals forff may refile. In April 2019, PRN aRR 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 remains in the very early stages. lso filff ed a complaint against DMG before the IPCB, alleging that groundwater flows ff 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 referredr to the Illinois Attorney General. In June 2021, the Illinois Attorney General and the Vermilion County State Attorney filff ed 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 beforff e 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. These proposed closure costs are reflecff ted in the ARO in our condensed consolidated balance sheets (see Note 21). d 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 rulr e, 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 rulerr 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 We filff ed our opening brief in October 2021. Other parties have also filed appeals of certain provisions of the final rulrr e. rr 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. ilities, we may incur significant costs that could have a material adverse effect For all of the above matters, if certain corrective action measures, including groundwater treatment or removal of ash, are on our required at any of our coal-fueled facff financial condition, results of operations, and cash flows. The Illinois coal ash rule was finali zed in April 2021 and does not require removal. However, the rule will require 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 ications have been submitted and approved by the IEPA. However, the required under the Illinois rule until permit appl 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. a ff ff 134 MISO 2015-2016 Plannll ing Resource Auction t In May 2015, three complaints were filff ed at FERC regarding the Zone 4 results forff the 2015-2016 planning resource auction (PRA)RR conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc., the Illinois Attorney General and Southwestern Electric Cooperative, Inc. (Complainants), challenged the results of the PRA aRR s unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO planning resource auction structuret going forward. Complainants also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 The Independent Market Monitor for MISO (MISO IMM), which was constituti responsible for monitoring the PRA,RR determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filff ing responding to the complaints, that there is no basis for the remedies sought by the Complainants. We filed our answer to these complaints explaining that we complied full y with the terms of the MISO tariff nd disputing the allegations. The Illinois Industrial Energy Consumers filed a related complaint at in connection with the PRA aRR FERC against MISO in June 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this complaint with respect to Dynegy's conduct alleged in the complaint. ng market manipulation in the PRA.RR ff In October 2015, FERC issued an order of nonpublic, formal investigation (the investigation) into whether market manipulation or other potential violations of FERC orders, rules and regulations occurred before or during the PRA.RR In December 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff provisions effective as of the 2016-2017 planning resource auction. The order did not address the arguments of the Complainants regarding the PRA aRR nd stated that those issues remained under consideration and would be addressed in a future order. ff In July 2019, FERC issued an order denying the remaining issues raised by the complaints and noted that the investigation d that Dynegy's conduct did not constitute market manipulation and the results of the PRARR into Dynegy was closed. FERC foun were just and reasonable because the PRA was conducted in accordance with MISO's tariff. With the issuance of the order, this matter has been resolved in Dynegy's favor. The request for rehearing was denied by FERC in March 2020. The order was appealed by Public Citizen, Inc. to the D.C. Circuit Court in May 2020, and Vistra, Dynegy and Illinois Power Marketing ng denying Public Citizen, Company intervened in the case in June 2020. In August 2021, the D.C. Circuit Court issued a ruli ed to meet its obligation to ensure just and reasonable rates because it did not review the prices Inc.'s arguments that FERC fail resulting from the auction before those prices went into effecff ious in failing to t and that FERC was arbit adequately explain its decision to close its investigation into whether Dynegy engaged in market manipulation. The D.C. Circuit Court of Appeals granted Public Citizen, Inc.'s petition in part finding that FERC's decision that the auction results were just and reasonable solely because the auction process complied with the filed tariff was unreasoned and remanded the case back to FERC forff , 2022 the Illinois Attorney General and Public Citizen, Inc. filed a motion at FERC requesting that FERC on remand reverse its prior decision and either find that auction results were not just and reasonable and order Dynegy to pay refunds to Illinois or, in the alternative, initiate an evidentiary hearing and discovery. We intend to vigorously defend our position, including by filing a response to the motion. further proceedings on that issue. On February 4rr rary and capric a ff rr r Other MatteMM rs We are involved in various legal and administrative proceedings and other disputes in the normal course of business, the on our results of ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect operations, liquidity or finaff ncial condition. ff Labor Contracts We employ certain personnel who are represented by labor unions, the terms of whose employment are governed by a 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 operations, as well as some battery operations, expire on various dates between March 2022 and May 2024, but remain effective thereafter unless and until terminated by either party. While we cannot predict the outcome of labor contract negotiations, we do not expect any changes in our existing agreements to have a material adverse effect on our results of operations, liquidity or finaff ncial condition. a 135 Nuclear Insurance Nuclear insurance includes nuclear liabia lity coverage, property damage, nuclear accident decontamination and accidental decommissioning coverage and accidental outage and/or extra expense coverage. We maintain nuclear insurance prematuret that meets or exceeds requirements promulgated by Section 170 (Price-Anderson) of the Atomic Energy Act (the Act) and Title 10 of the Code of Federal Regulations. We intend to maintain insurance against nuclear risks as long as such insurance is available. We are self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Any such self-insured losses could have a material adverse effect on our results of operations, liquidity or financial condition. With regard to nuclear liabia lity coverage, the Act provides forff rr financial protection for the public in the event of a significant nuclear generation plant incident. The Act sets the statutory l imit of public liabia lity for a single nuclear incident at $13.5 billion and requires nuclear generation plant operators to provide financial protection for this amount. However, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims that exceed the $13.5 billion limit forff a ility resulting in public single incident. As required, we insure against a possible nuclear incident at our Comanche Peak facff nuclear-related bodily injury and property damage through a combination of private insurance and an industry-wide retrospective payment plan known as Secondary Financial Protection (SFP). Under the SFP, in the event of any single nuclear liabia lity loss in excess of $450 million at any nuclear generation facility in the U.S., each operating licensed reactor in the U.S. is subject to an annual assessment of up to $137.6 million. This approximately $137.6 million maximum assessment is subject to increases for inflation every five years, with the next expected adjustment scheduled to occur by November 2023. Assessments are currently limited to $20.5 million per operating licensed reactor per year per incident. As of December 31, 2021, our maximum potential assessment under the industry retrospective each incident. The plan would be approximately $275 million per incident but no more than $41 million in any one year forff ility. potential assessment is triggered by a nuclear liability loss in excess of $450 million per accident at any nuclear facff The United States Nuclear Regulatory Commission (NRC) requires that nuclear generation plant license holders maintain ization insurance, and requires that the at least $1.06 billion of nuclear accident decontamination and reactor damage stabila condition, to decontaminate a plant pursuant to a plan submitted to, proceeds thereof be used to place a plant in a safe aff the NRC prior to using the proceeds for plant repair or restoration, or to provide for prematuret and approved by, decommissioning. We maintain nuclear accident decontamination and reactor damage stabilization insurance forff our Comanche Peak facility in the amount of $2.25 billion and non-nuclear accident related property damage in the amount of $1.0 billion (subject to a $5 million deductible per accident except forff hazards which are subject to a $9.5 million deductible per accident), above which we are self-insured. nd stablea t natural We also maintain Accidental Outage insurance to cover the additional costs of obtaining replacement electricity from another source if one or both of the units at our Comanche Peak facility are out of service forff more than twelve weeks as a result of covered direct physical damage. Such coverage provides forff weekly payments per unit up to $4.5 million for the first 52 weeks and up to $3.6 million for the remaining 71 weeks. The total maximum coverage is $328 million for non-nuclear property damage and $490 million for nuclear property damage. The coverage amounts applicable to each unit will be reduced to 80% if both units are out of service at the same time as a result of the same accident. 136 14. EQUITY Common Stoctt k Issuanc II es and Repurchases Changes in the number of shares of common stock issued and outstanding for the years ended December 31, 2021, 2020 and 2019 are refleff cted in the tablea below. Balance at December 31, 2018 Shares issued (a) (b) Shares retired Shares repurchased Balance at December 31, 2019 Shares issued (a) Shares retired Balance at December 31, 2020 Shares issued (a) Shares retired Shares repurchased (c) Balance at December 31, 2021 Shares Issued Treasury Shares Shares Outstanding 526,031,092 (32,815,783) 493,215,309 2,716,349 18,773,958 21,490,307 (6,106) — (6,106) — (27,001,399) (27,001,399) 528,741,335 (41,043,224) 487,698,111 1,611,462 (3,685) — — 1,611,462 (3,685) 530,349,112 (41,043,224) 489,305,888 2,583,761 — 2,583,761 (3,397) — — (27,988,518) (3,397) (27,988,518) 532,929,476 (69,031,742) 463,897,734 ____________ (a) Shares issued includes share awards granted to nonemployee directors. (b) The year ended December 31, 2019 includes 18,773,958 treasury shares issued in connection with the settlement of all outstanding TEUs as discussed below. (c) Shares repurchased in the year ended December 31, 2021 include 5,174,863 of unsettled shares as of December 31, 2021. Share Repurchase Programs In October 2021, we announced that the Board has authorized a new share repurchase program (Share Repurchase Program) under which up to $2.0 billion of our outstanding shares of common stock may be repurchased. The Share Repurchase Program became effective on October 11, 2021, at which time it superseded the 2020 Share Repurchase Program (described below) and any authorization remaining as of such date. We intend to use the net proceeds from the Offering (described below) to repurchase shares of our outstanding common stock. In the three months ended December 31, 2021, 19,330,365 shares of our common stock were repurchased under the Share Repurchase Program for approximately $409 million at an average price of $21.16 per share of common stock. As of December 31, 2021, approximately $1.591 billion was available forff additional repurchases under the Share Repurchase Program. From January 1, 2022 through February 22, 2022, 16,059,290 of our common stock had been repurchased under the Share Repurchase Program for $355 million at an average repurchase under the ry 2rr price per share of common stock of $22.07, and at Februarr Share Repurchase Program. We expect to complete repurchases under the Share Repurchase Program by the end of 2022. 2, 2022, $1.236 billion was available forff Under the Share Repurchase Program, shares of the Company's common stock may be repurchased in open market transactions at prevailing market prices, in privately negotiated transactions, pursuant to plans complying with the Exchange eral securities laws. The actual timing, number and value of shares repurchased Act, or by other means in accordance with fedff under the Share Repurchase Program or otherwise will be determined at our discretion and will depend on a number of facff tors, including our capita al allocation priorities, the market price of our stock, general market and economic conditions, applicable legal requirements and complim ance with the terms of our debt agreements. In September 2020, we announced that the Board authorized a share repurchase program (2020 Share Repurchase Program) under which up to $1.5 billion of our outstanding shares of common stock may be repurchased. The 2020 Share Repurchase Program was effective January 1, 2021, at which time the 2018 Share Repurchase Plan (described below) and all authorized amounts remaining thereunder terminated as of such date. In the year ended December 31, 2021, 8,658,153 shares of our common stock were repurchased under the 2020 Share Repurchase Program for approximately $175 million at an average price of $20.21 per share of common stock. The 2020 Share Repurchase Program was superseded by the Share Repurchase Program in October 2021. 137 In June 2018, we announced that the Board had authorized a share repurchase program under which up to $500 million of our outstanding common stock may be purchased, and this authorized amount was full y utilized in 2018. In November 2018, we announced that the Board had authorized an incremental share repurchase program under which up to $1.250 billion of our outstanding stock may be purchased, resulting in an aggregate $1.750 billion share repurchase program (collectively, 2018 Share Repurchase Program). In the year ended December 31, 2019, 26,322,166 shares of our common stock were repurchased under the 2018 Share Repurchase Program for approximately $640 million (including related fees and expenses) at an average price of $24.34 per share. There were no repurchases under the 2018 Share Repurchase Program in the year ended December 31, 2020. The 2018 Share Repurchase Program was terminated on January 1, 2021. ff Preferred Stock SS On October 15, 2021 (Series A Issuance Date), we issued of 1,000,000 shares of Series A Preferred Stock in a private offering (Series A Offering). The net proceeds of the Series A Offering were approximately $990 million, after deducting underwriting commissions and offering expenses. We intend to use the net proceeds from the Series A Offering to repurchase shares of our outstanding common stock under the Share Repurchase Program (described above). On December 10, 2021 (Series B Issuance Date), we issued of 1,000,000 shares of Series B Preferred Stock in a private offering (Series B Offering). The net proceeds of the Series B Offering were approximately $985 million, after deducting underwriting commissions and offering expenses. We intend to use the net proceeds from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments. The Series A Preferred Stock and the Series B Preferred Stock are not convertible into or exchangeable forff any other securities of the Company and have limited voting rights. The Series A Preferred Stock may be redeemed at the option of the Company at any time after the Series A First Reset Date (definff ed below) and in certain other circumstances prior to the Series A First Reset Date. The Series B Preferred Stock may be redeemed at the option of the Company at any time after the Series B First Reset Date (defined below) and in certain other circumstances prior to the Series B First Reset Date. ii Dividends Common Stock — In November 2018, Vistra announced the Board adopted a dividend program which we initiated in the first quarter of 2019. 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 any contractual limitations. t In February 2019, May 2019, July 2019 and October 2019, the Board declared quarterly dividends of $0.125 per share that were paid in March 2019, June 2019, September 2019 and December 2019, respectively. In February 2020, April 2020, July 2020 and October 2020, the Board declared quarterly dividends of $0.135 per share that were paid in March 2020, June 2020, September 2020 and December 2020, respectively. In February 2021, April 2021, July 2021 and October 2021, the Board declared quarterly dividends of $0.15 per share that were paid in March 2021, June 2021, September 2021 and December 2021, respectively. In February 2022, the Board declared a quarterly dividend of $0.17 per share that will be paid in March 2022. d StocS ff Preferre k — The annual dividend rate on each share of Series A Preferred Stock is 8.0% from the Series A Issuance Date to, but excluding October 15, 2026 (Series A First Reset Date). On and after the Series A First Reset Date, the dividend rate on each share of Series A Preferred Stock shall equal the five-year U.S. Treasury rate as of the most recent reset dividend determination date (subject to a floor of 1.07%), plus a spread of 6.93% per annum. The Series A Preferred Stock has a liquidation preference of $1,000 per share, plus accumulated but unpaid dividends. Cumulative cash dividends on the Series A Preferred Stock are payablea semiannually, in arrears, on each April 15 and October 15, commencing on April 15, 2022, when, as and if declared by the Board. ff In February 2022, the Board declared a semi-annual dividend of $40.00 per share of Series A Preferredr Stock that will be paid in April 2022. 138 The annual dividend rate on each share of Series B Preferred Stock is 7.0% from the Series B Issuance Date to, but excluding December 15, 2026 (Series B First Reset Date). On and after the Series B First Reset Date, the dividend rate on each share of Series B Preferred Stock shall equal the five-year U.S. Treasury rate as of the most recent reset dividend determination of 1.26%), plus a spread of 5.74% per annum. The Series B Preferred Stock has a liquidation preference date (subject to a floor of $1,000 per share, plus accumulated but unpaid dividends. Cumulative cash dividends on the Series B Preferred Stock are payablea semiannually, in arrears, on each June 15 and December 15, commencing on June 15, 2022, when, as and if declared by the Board. ff ii Dividend Restrictions The Credit Facilities Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of December 31, 2021, Vistra Operations can distribute approximately $7.3 billion to Parent under the Credit Facilities Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Parent of approximately $405 million, $1.1 billion and $3.9 billion during the years ended December 31, 2021, 2020 and 2019, respectively. Additionally, Vistra Operations may make distributions to Parent in amounts sufficient for Parent to make any payments required under the TRA oRR r the Tax Matters Agreement or, to the extent arising out of Parent's ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses. As of December 31, 2021, all of the restricted net assets of Vistra Operations may be distributed to Parent. In addition to the restrictions under the Credit Facilities Agreement, under applicable Delaware law, we are only permitted al (the aggregate the fiscal year in which the distribution is declared or to make distributions either out of "surplus," which is defined as the excess of our net assets above our capita par value of all outstanding shares of our stock), or out of net profits forff the prior fiscal year. Under the terms of the Series A Preferred Stock and the Series B Preferred Stock, unless full cumulative dividends have been or contemporaneously are being paid or declared and a sum sufficient for the payment thereof set apart for payment on all outstanding Series A Preferred Stock (and any parity securities) and Series B Preferred Stock (and any parity securities), respectively, with respect to dividends through the most recent dividend payment dates, (i) no dividend may be declared or paid or set apart for payment on any junior security (other than a dividend payablea solely in junior securities with respect to both dividends and the liquidation, winding-up and dissolution of our affairs), including our common stock, and (ii) we may not redeem, purchase or otherwise acquire any parity security or junior security, including our common stock, in each case subject Stock and the Series B Preferred to certain exceptions as described in the certificate of designation of the Series A Preferredr Stock, respectively. Accumulatell d Other ComCC prehm ensive Income During the years ended December 31, 2021, 2020 and 2019, we recorded changes in the funded statust of our pension and other postretirement employee benefit liability totaling $(24) million, $23 million and $11 million, respectively. During the years ended December 31, 2021, 2020 and 2019, $(8) million, $(5) million and $(3) million respectively was reclassified fromff accumulated other comprehensive income and reported in other deductions. Warrantstt At the Merger Date, the Company entered into an agreement whereby the holder of each outstanding warrant previously issued by Dynegy would be entitled to receive, upon paying an exercise, price of $35.00 (subject to adjustment from time to time), the number of shares of Vistra common stock that such holder would have been entitled to receive if it had held one share of Dynegy common stock at the closing of the Merger, or 0.652 shares of Vistra common stock. Accordingly, upon exercise, a warrant holder would effectively pay $53.68 (subject to adjustment of the exercise price fromff time to time) per share of Vistra agreement, the exercise price of each common stock received. warrant was adjusted downward to $34.54 (subject to furthe r adjustment from time to time), or $52.98 (subject to adjustment of the exercise price fromff time to time) per share of Vistra common stock received. As of December 31, 2021, nine million warrants expiring in 2024 were outstanding. The warrants were included in equity based on their fair value at the Merger Date. In July 2021, in accordance with the terms of the warrant r ff 139 )s Tangible Equityii Units (TEUs TT At the Merger Date, the Company assumed the obligations of Dynegy's 4,600,000 7.00% TEUs, each with a stated amount of $100.00 and each comprised of (i) a prepaid stock purchase contract that delivered to the holder on July 1, 2019, 4.0813 shares of Vistra common stock per contract with cash paid in lieu of any fractional shares at a rate of $22.5954 per share and (ii) a senior amortizing note with an outstanding principal amount of $38 million at the Merger Date that paid an equal quarterly cash installment of $1.75 per amortizing note (see Note 11). In the aggregate, the annual quarterly cash installments were equivalent to a 7.00% cash payment per year with respect to each $100.00 stated amount of TEUs. The amortizing notes were accounted forff as debt while the stock purchase contract was included in equity based on the fair value of the contract at the Merger Date (see note 11). The entire class of TEUs were suspended from trading on the New York Stock Exchange on July 1, 2019 and removed from listing and registration on July 12, 2019. On July 1, 2019, approximately 18.8 million treasury shares of Vistra common stock were issued in connection with the settlement of all outstanding TEUs. 15. FAIR VALUE MEASUREMENTS We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparablea assets and liabilities for those items that are measured on a recurring basis. We use a mid-market valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majoa rity of our assets and liabilities and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs. Our valuation policies and procedures were developed, maintained and validated by a centralized risk management group that reports to the Vistra Chief Financial Officer. Fair value measurements of derivative assets and liabilities incorporate an adjustment for credit-related nonperformance risk. These nonperformance risk adjustments take into consideration master netting arrangements, credit enhancements and the credit risks associated with our credit standing and the credit standing of our counterparties (see Note 16 for additional information regarding credit risk associated with our derivatives). We utilize credit ratings and default rate fact ors in calculating these fair value measurement adjustmd ents. ff We categorize our assets and liabilities recorded at faiff r value based upon the following fair value hierarchy: • • • Level 1 valuations use quoted prices in active markets forff identical assets or liabilities that are accessible at the measurement date. Our Level 1 assets and liabilities include CME or ICE (electronic commodity derivative exchanges) futures and options transacted through clearing brokers for which prices are actively quoted. We report the fair value of CME and ICE transactions without taking into consideration margin deposits, with the exception of ff certain margin amounts related to changes in fair value on certain CME transactions that are legally characterized as settlement of derivative contracts rather than collateral. Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means, and other valuation inputs such as interest rates and yield curves observable at commonly quoted intervals. We attempt to obtain multiple quotes from brokers that are active in the markets in which we participate and require at least one quote from two brokers to determine a pricing input as observablea . The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker's publication policy, recent trading volume trends and various other facff tors. inputs for the asset or liabia lity. Unobservablea inputs are used to the extent Level 3 valuations use unobservablea inputs are not available, thereby allowing for situations in which there is little, if any, market activity for observablea the market the asset or liabia lity at the measurement date. We use the most meaningful information available fromff r value. Significant combined with internally developed valuation methodologies to develop our best estimate of faiff unobservablea inputs used to develop the valuation models include volatility curves, correlation curves, illiquid pricing delivery periods and locations and credit-related nonperformance risk assumptions. These inputs and valuation models are developed and maintained by employees trained and experienced in market operations and fair value measurements and validated by the Company's risk management group. With respect to amounts presented in the following fair value hierarchy tablea s, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement. 140 Assets and liabilities measured at fair value on a recurring basis consisted of the following at the respective balance sheet December 31, 2021 December 31, 2020 Level 1 Level 2 Level 3 (a) Reclass (b) Total Level 1 Level 2 Level 3 (a) Reclass (b) Total dates shown below: Assets: Commodity contracts Interest rate swapsa Nuclear decommissioning trust – equity securities (c) Nuclear decommissioning trust – debt securities (c) Sub-total Assets measured at net asset value (d): Nuclear decommissioning trust – equity securities (c) Total assets Liabilities: $ 1,408 — $ 889 19 $ 442 — $ 724 — — — $ 2,132 679 $ 1,587 — $ 442 $ 5 — — — 5 $ 2,744 19 $ 452 $ 201 $ 205 — — 72 724 623 — — — — $ 1,075 $ 891 $ 205 618 679 4,166 557 $ 4,723 $ $ $ $ 76 — — — 76 $ 934 72 623 618 2,247 433 $ 2,680 76 — 76 $ 1,009 404 $ 1,413 Commodity contracts Interest rate swapa s Total liabilities $ 2,153 — $ 2,153 $ 650 217 $ 867 $ 802 — $ 802 $ $ 5 — 5 $ 3,610 217 $ 3,827 $ 578 $ 172 $ 183 — $ 578 $ 576 $ 183 404 — ____________ (a) See table below for description of Level 3 assets and liabilities. (b) Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or vice versa, as presented in our consolidated balance sheets. (c) The nuclear decommissioning trust investment is included in the other investments line in our consolidated balance sheets. See Note 21. (d) The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to the amounts presented in our consolidated balance sheets. Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been classified in the fair value hierarchy. Commodity contracts consist primarily of natural gas, electricity, coal and emissions agreements and include financial instruments entered into forff economic hedging purposes as well as physical contracts that have not been designated as normal purchases or sales. Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest to fixed rates. See Note 16 forff further discussion regarding derivative instruments. t Nuclear decommissioning trust assets represent securities held forff decommissioning of our nuclear generation facility. These investments include equity, debt and other fixeff consistent with investment rules established by the NRC and the PUCT. the purpose of funding the future retirement and d-income securities 141 The folff lowing tables present the fair value of the Level 3 assets and liabilities by majora contract type and the significant unobservable inputs used in the valuations at December 31, 2021 and 2020: Fair Value December 31, 2021 Significant Unobservable Input Hourly price curve shapea (c) Range (b) $ — to $ 60 MWh Average (b) $ 30 Illiquid delivery periods for hub power prices and heat rates (d) $ 20 to $140 $ 80 MWh ) Gas to power correlation (e 0 % to 1 100 % 56 % ) Power and gas volatility (e 5 o t% 4 90 % 248 % Illiquid price differe nces between settlement points (g) ff $(30) to $ 10 $ (9) MWh Gas basis (h) $ (1) to $ 16 $ 8 MMBtu — 61 Income Approach Probability of default (i) Recovery rate (j) — % to — % to 40 % 20% 40 % 20% Contract Type (a) Electricity purchases and sales Assets Liabilities Total $ 204 $ (470) $ (266) Valuation Technique Income Approach Options 1 (209) (208) Option Pricing Model Financial transmission rights 122 (34) 88 Market (86) (57) Approach (f) Income AApproa hch 29 61 Natural gas Coal Other (k) Total $ 25 442 $ (3) (802) $ 22 (360) Fair Value December 31, 2020 Contract Type (a) Electricity purchases and sales Assets Liabilities Total $ 61 $ (90) $ (29) Valuation Technique Income Approach Options Financial transmission rights Natural gas Coal Other (k) 38 92 7 1 6 (56) (18) Option Pricing Model (16) 76 Market 14) ( (5) (2) Approach (f) Income AApproa hch Income Approach (7) (4) 4 22 Total $ 205 $ (183) $ Significant Unobservable Input Hourly price curve shapea (c) Range (b) $ — to $ 85 MWh Average (b) $ 43 Illiquid delivery periods for hub power prices and heat rates (d) $ 25 to $125 $ 75 MWh ) Gas to power correlation (e 0 % to 3 100 % 64 % ) Power and gas volatility (e 5 o t% 6 65 % 336 % Illiquid price differe nces between settlement points (g) ff $ (5) to $ 50 $ 22 MWh Gas basis (h) $ (1) to $ — $ — Probability of default (i) Recovery rate (j)(( — % to — % to 40 % 20% 40 % 20% MMBtu ____________ (a) Electricity purchase and sales contracts include power and heat rate positions in ERCOT, PJM, ISO-NE, NYISO and MISO regions. The forward purchase contracts (swapsa and options) used to hedge electricity price differences between settlement points are referred to as congestion revenue rights (CRRs) in ERCOT and financial transmission rights (FTRs) ons in PJM, ISO-NE, NYISO and MISO regions. Options consist of physical electricity options, spread options, swaptia and natural gas options. (b) The range of the inputs may be influenced by factors such as time of day, delivery period, season and location. The average represents the arithmetic average of the underlying inputs and is not weighted by the related fair value or notional amount. (c) Primarily based on the historical range of forward average hourly ERCOT North Hub prices. 142 (d) Primarily based on historical forward ERCOT and PJM power prices and ERCOT heat rate variability. (e) Primarily based on the historical forward correlation and volatility within ERCOT and PJM. (f) While we use the market approach, there is insufficff (g) Primarily based on the historical price differe (h) Primarily based on the historical forward PJM and Northeast gas basis prices. (i) Estimate of the range of probabilities of default based on past experience, the length of the contract, and both the nces between settlement points within ERCOT hubs and load zones. ient market data to consider the valuation liquid. ff Company's and the counterparty's credit ratings. (j) Estimate of the default recovery rate based on historical corporate rates. (k) Other includes contracts for environmental allowances. There were no transfers between Level 1 and Level 2 of the fair value hierarchy for the years ended December 31, 2021, the years ended December 31, discussion of transfers between Level 2 and Level 3 forff below forff 2020 and 2019. See the tablea 2021, 2020 and 2019. The following tablea 31, 2021, 2020 and 2019. presents the changes in faiff r value of the Level 3 assets and liabilities for the years ended December Net asset (liability) balance at beginning of period Total unrealized valuation gains (losses) (a) Purchases, issuances and settlements (b): Purchases Issuances Settlements Transfers into Level 3 (c) Transfers out of Level 3 (c) Net change (d) Net asset (liability) balance at end of period Unrealized valuation gains (losses) relating to instruments held at end of period Year Ended December 31, 2021 2020 2019 $ $ $ 22 $ (53) 114 (36) (314) (2) (91) (382) (360) $ (74) $ (5) 164 (28) (90) (2) 57 96 22 $ (364) $ 18 $ (135) 8 176 (81) (64) 10 12 61 (74) (61) ____________ (a) During the year ended December 31, 2021, loss of $341 million due to the third quarter 2021 discontinuance of normal purchase and sale accounting on a retail electric contract portfolio where physical settlement is no longer considered probablea throughout the contract term. includes a net (b) Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and (c) t option premiums paid or received, including CRRs and FTRs. issuances reflecff Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. For the year ended December 31, 2021, transfers into Level 3 primarily consist of gas, emissions and coal derivatives where forward pricing inputs have become unobservable and transfers out of t natural Level 3 primarily consist of power and coal derivatives where forward pricing inputs have become observable. For the year ended December 31, 2020, transfers out of Level 3 primarily consist of natural gas, power and coal derivatives where forward pricing inputs have become observable. For the year ended December 31, 2019, transfers out of Level 3 . primarily consist of power and coal derivatives where forward pricing inputs have become observablea t (d) Activity excludes change in fair value in the month positions settle. Substantially all changes in values of commodity contracts (excluding the net liabilities assumed in connection with the Merger) are reported as operating revenues in our consolidated statements of operations. 16. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES tt Strategi c UseUU of Derivativtt es We transact in derivative instruments, such as options, swaps,a futures and forward contracts, to manage commodity price and interest rate risk. See Note 15 for a discussion of the fair value of derivatives. 143 dd edHH ging Commodity Htt and Trading Activityii — We utilize natural gas and electricity derivatives to reduce exposure to our generation assets and to hedge changes in electricity prices primarily to hedge future revenues from electricity sales fromff future purchased power costs for our retail operations. We also utilize short-term electricity, natural gas, coal and emissions derivative instruments for fuel hedging and other purposes. Counterparties to these transactions include energy companies, financial instituti ons, electric utilities, independent power producers, fuel oil and gas producers, local distribution companies and energy marketing companies. Unrealized gains and losses arising from changes in the fair value of derivative instruments as well as realized gains and losses upon settlement of the instruments are reported in our consolidated statements of operations in operating revenues and fuel, purchased power costs and delivery fees. t t t tt Interes t Rate Swaps — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate interest rates to fixed rates, thereby hedging future interest costs and related cash flows. Unrealized gains and are losses arising from changes in the fair value of the swapsa reported in our consolidated statements of operations in interest expense and related charges. During 2019, Vistra entered into $2.12 billion of new interest rate swaps, pursuant to which Vistra will pay a variable rate and receive a fixeff d rate. The terms of these new swaps were matched against the terms of certain existing swaps,a effectively offsetting the hedge of the existing swaps These matched swapsa will settle over time, in accordance with the and fixing the out-of-the-money position of such swaps.a original contractual continue to hedge our exposure on $2.30 billion of debt through July terms. The remaining existing swapsa 2026. as well as realized gains and losses uponu settlement of the swapsa t Financial Statement Effeff cts ott f Do erivatives t t Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent s provide detail of with accounting standards related to derivative instruments and hedging activities. The following tablea derivative contractual assets and liabilities as reported in our consolidated balance sheets at December 31, 2021 and 2020. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract. During the year ended December 31, 2021, a net loss of $298 million was recognized in operating revenues due to the third quarter 2021 discontinuance of normal purchase and sale accounting on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract term. These amounts are reflected in commodity contracts derivative liabilities at December 31, 2021. Current assets Noncurrent assets Current liabilities Noncurrent liabilities Net assets (liabila ities) Current assets Noncurrent assets Current liabilities Noncurrent liabilities Net assets (liabila ities) December 31, 2021 Derivative Assets Derivative Liabilities Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total $ $ $ $ 2,496 244 — (1) 2,739 $ $ 14 5 — — 19 $ $ $ 3 1 (2,964) (645) (3,605) $ December 31, 2020 — $ — (59) (158) (217) $ 2,513 250 (3,023) (804) (1,064) Derivative Assets Derivative Liabilities Commodity Contracts Interest Rate Swaps Commodity Contracts Interest Rate Swaps Total 665 197 (1) (3) 858 $ $ 19 53 — — 72 $ $ $ 64 8 (717) (288) (933) $ — $ — (71) (333) (404) $ 748 258 (789) (624) (407) As of December 31, 2021 and 2020, there were no derivative positions accounted forff as cash flow or fair value hedges. 144 The folff lowing table presents the pre-tax effect of derivative gains (losses) on net income, including realized and unrealized effects. Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts. Derivative (consolidated statements of operations presentation) 2021 2020 2019 Commodity contracts (Operating revenues) Commodity contracts (Fuel, purchased power costs and delivery fees) Interest rate swapsa (Interest expense and related charges) Net gain (loss) $ $ (1,196) $ 241 $ 732 81 4 (196) (383) $ 49 $ 339 (1) (217) 121 Year Ended December 31, ll Balanc e SheSS et Presentattt iontt of Derivatives tt We elect to report derivative assets and liabilities in our consolidated balance sheets on a gross basis without taking into consideration netting arrangements we have with counterparties to those derivatives. We maintain standardized master netting the right to offset assets and liabilities and collateral in order to reduce agreements with certain counterparties that allow forff credit exposure between us and the counterparty. These agreements contain specific language related to margin requirements, monthly settlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract counterparty. Generally, margin deposits that contractually offset these derivative instruments are reported separately in our consolidated balance sheets, with the exception of certain margin amounts related to changes in fair value on CME transactions that are legally characterized as settlement of forward exposure rather than collateral. Margin deposits received from counterparties are primarily used for working capia tal or other general corporate purposes. The following tablea s reconcile our derivative assets and liabilities on a contract basis to net amounts after taking into consideration netting arrangements with counterparties and financial collateral: December 31, 2021 December 31, 2020 Derivative Assets and Liabilities Offsetting Instruments (a) Cash Collateral (Received) Pledged (b) Net Amounts Derivative Assets and Liabilities Offsetting Instruments (a) Cash Collateral (Received) Pledged (b) Net Amounts Derivative assets: Commodity contracts Interest rate swapsa Total derivative assets Derivative liabilities: Commodity contracts Interest rate swapsa Total derivative liabilities $ 2,739 19 $ (2,051) $ (19) (27) $ — 2,758 (2,070) (27) (3,605) (217) 2,051 19 (3,822) 2,070 784 — 784 661 — 661 (770) (198) (968) $ 858 72 930 $ (667) $ (72) (11) $ — (739) (11) (933) (404) (1,337) 667 72 739 138 — 138 180 — 180 (128) (332) (460) Net amounts $ (1,064) $ — $ 757 $ (307) $ (407) $ — $ 127 $ (280) ____________ (a) Amounts presented exclude trade accounts receivablea (b) Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin and payable related to settled finaff ncial instruments. requirements, and, to a lesser extent, initial margin requirements. 145 Derivative Volumes The following tabla e presents the gross notional amounts of derivative volumes at December 31, 2021 and 2020: Derivative type Natural gas (a) Electricity Financial transmission rights (b) Coal Fuel oil Emissions Renewable energy certificates Interest rate swapsa Interest rate swapsa – variable/fixed (c) - fixff ed/variable (c) December 31, 2021 December 31, 2020 Notional Volume 4,701 440,236 224,876 25 87 18 32 6,720 2,120 $ $ Unit of Measure 5,264 Million MMBtu 438,863 GWh 217,350 GWh 20 Million U.S. tons 176 Million gallons 8 Million tons 18 Million certificates 6,720 Million U.S. dollars 2,120 Million U.S. dollars $ $ ____________ (a) Represents gross notional forward sales, purchases and options transactions, locational basis swapsa and other natural t gas transactions. (b) Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within regions. Includes notional amounts of interest rate swapsa with maturity dates through July 2026. (c) Credit Risk-Re- latedtt Contintt gent FeaFF tures of Derivativtt es Our derivative contracts may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other formff of credit enhancement. Certain of these agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies or include cross-default contractual provisions that could result in the settlement of such contracts if there was a faiff lure under other financing arrangements related to payment terms or other covenants. The following tablea presents the commodity derivative liabilities subject to credit risk-related contingent features that are not fully collateralized: Fair value of derivative contract liabila Offsetting fair value under netting arrangements (b) Cash collateral and letters of credit Liquidity exposure ities (a) December 31, 2021 2020 $ $ (1,200) $ 660 95 (445) $ (679) 262 35 (382) ____________ (a) Excludes faiff r value of contracts that contain contingent features that do not provide specific amounts to be posted if features are triggered, including provisions that generally provide the right to request additional collateral (material adverse change, performance assurance and other clauses). (b) Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master netting arrangements. Concentrations of Credit Riskii Relatell d to Dtt erivatives We have concentrations of credit risk with the counterparties to our derivative contracts. As of December 31, 2021, total credit risk exposure to all counterparties related to derivative contracts totaled $3.742 billion (including associated accounts receivable). The net exposure to those counterparties totaled $1.417 billion at December 31, 2021 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to ERCOT totaling $619 million. As of December 31, 2021, the credit risk exposure to the banking and financial sector represented 54% of the total credit risk exposure and 4% of the net exposure. 146 Exposure to banking and financial sector counterparties is considered to be within an acceptablea level of risk tolerance because all of this exposure is with counterparties with investment grade credit ratings. However, this concentration increases the risk that a defauff lt by any of these counterparties would have a material effeff ct on our financial condition, results of operations and liquidity. The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us. 17. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS Vistra is the plan sponsor of the Vistra Retirement Plan (the Retirement Plan), which provides benefits to eligible its interests in the employees of its subsidiaries. Oncor is a participant in the Retirement Plan. As Vistra accounts forff Retirement Plan as a multiple employer plan, only Vistra's share of the plan assets and obligations are reported in the pension benefit information presented below. After amendments in 2012, employees in the Retirement Plan now consist entirely of participants who were active and retired collective bargaining unit employees. The Retirement Plan is a qualified defined benefit pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of ERISA. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs. It is our policy to fund the Retirement Plan assets only to the extent required under existing federal regulations. ff Vistra and our participating subsidiaries offer other postretirement employee benefits (OPEB) in the form of certain health care and life insurance benefits to eligible retirees and their eligible dependents. The retiree contributions required forff ula depending on the retiree's age and years of service. such coverage vary based on a formff Effective January 1, 2018, Vistra entered into a contractual arrangement with Oncor whereby the costs associated with providing OPEB coverage for certain retirees (Split Participants) whose employment included service with both the regulated businesses of Oncor (or its predecessors) and the non-regulated businesses of Vistra (or its predecessors) are split between Oncor and Vistra. As Vistra accounts forff its interest in this OPEB plan as a multiple employer plan, only Vistra's share of the plan assets and obligations are reported in the OPEB information presented below. In addition, Vistra is the sponsor of OPEB plans that certain EFH Corp. and Dynegy retirees participate in. Pension and OPEB Coststt Pension costs OPEB costs Total benefit costs recognized as expense Market-Relatell d ValVV ue of Assets Held in Pension Benefite Trusts Year Ended December 31, 2021 2020 2019 $ $ 6 8 14 $ $ 11 7 18 $ $ 9 11 20 We use the calculated value method to determine the market-related value of the assets held in the trust for purposes of calculating pension costs. We include all gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gains and losses forff the current year and for each of the preceding three years is included in the market- related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year. 147 Detaileii d Inform II ation Regarding Pension Plans ll and OPEBPP Benefite stt The following information is based on a December 31, 2021, 2020 and 2019 measurement dates: Assumptions Used to Determine Net Periodic Pension and Benefitff Cost: Discount rate Expected rate of compensation increase Interest crediting rate for cash balance Expected return on plan assets (Vistra Plan) Expected return on plan assets (Dynegy Plan) Expected return on plan assets (EEI Plan) Expected return on plan assets (EEI Union) Expected return on plan assets (EEI Salaried) m s ott Service cost Interest cost Expected returnt Amortization of unrecognized amounts Immediate pension and postretirement benefit cost etNN Pension and Benefie t Cost:CC on assets f No Component Net periodic pension and OPEB cost in Plan Assets att nd Benefitff Obligati i ons in Other Compre CC hensive Income: Other Changes CC Recognizedii Retirement Plan OPEB Plans Year Ended December 31, Year Ended December 31, 2021 2020 2019 2021 2020 2019 2.50 % 3.24 % 4.37 % 3.41 % 3.29 % 3.35 % 3.00 % 3.50 % 3.50 % 3.77 % 4.44 % 4.80 % 4.42 % 5.28 % 5.31 % 4.72 % 5.45 % 5.56 % 2.51 % 3.25 % 4.35 % 6.79 % 7.07 % 5.36 % 2.95 % 3.43 % 4.70 % $ $ 5 16 (18) 3 — 6 $ 6 20 (23) 1 7 $ 11 $ $ 7 25 (26) — 3 9 $ $ 1 4 (2) 5 — 8 $ $ $ 2 4 (2) 4 (1) 7 $ 2 6 (1) 3 1 $ 11 5 $ — Net (gain) loss and prior service (credit) cost $ (29) $ 17 $ 11 $ (12) Total recognized in net periodic benefit cost and other comprehensive income Assumptions Used to Determine Benefie t Obligations at Period End: $ (23) $ 28 $ 20 $ (4) $ 12 $ 11 Discount rate Expected rate of compensation increase Interest crediting rate for cash balance plans 2.84 % 2.50 % 3.24 % 3.49 % 3.41 % 3.29 % 3.00 % 3.00 % 3.50 % 2.87 % 2.51 % 3.25 % Net Actuarial Gainsii (Losses) to increasing discount rates due to changes in the corporate bond markets and gains attributablea Retirement Plan — For the year ended December 31, 2021, the net actuarial gain of $24 million was driven by gains to actual asset to demographic assumptim on updates to reflect recent rial assumptim on updates to reflect current market conditions, plan amendments, settlements and plan attributablea performance exceeding expectations, partially offset by losses attributablea plan experience, actuat experience different than expected. to For the year ended December 31, 2020, the net actuarial loss of $29 million was driven by losses attributablea decreasing discount rates due to changes in the corporate bond markets, actuarial assumptim on updates to reflect current market conditions and plan amendments, partially offset by gains attributablea to actual asset performance exceeding expectations, life expectancy updat es, annuity purchases, lump sum windows and plan experience different than expected. u to For the year ended December 31, 2019, the net actuarial loss of $16 million was driven by losses attributablea decreasing discount rates due to changes in the corporate bond markets, actuarial assumptim on updates to reflect current market than expected, partially offset by gains conditions, annuity purchases, plan amendments and plan experience different attributablea to actual asset performance exceeding expectations and life expectancy updates. ff 148 Plans — For the year ended December 31, 2021, the net actuarial gain of $7 million was driven by gains OPEBPP attributablea than expected, to increasing discount rates due to changes in the corporate bond markets, plan experience different updates to health care claims and trend assumptim ons and actual asset performance exceeding expectations, partially offset by losses attributable to demographic assumption updates and life expectancy updat es. u ff For the year ended December 31, 2020, the net actuarial loss of $10 million was driven by losses attributablea decreasing discount rates due to changes in the corporate bond markets and plan experience different to actual asset performance exceeding expectations, life expectancy updat offset by gains attributablea care claims and trend assumptim ons. ff u to than expected, partially es and updates to health For the period ended December 31, 2019, the net actuarial loss of $5 million was driven by losses attributablea decreasing discount rates due to changes in the corporate bond markets and plan experience different offset by gains attributablea related assumptions and changes due to the repeal of certain Affordable Care Act fees. to than expected, partially to actual asset performance exceeding expectations, life expectancy changes, updates to health care ff Change in Pension and Postretirement Benefie t Obligations: Projected benefit obligation at beginning of period Service cost Interest cost Participant contributions Lump-sum window Annuity purchase Actuarial loss Benefits paid Projected benefit obligation at end of year Accumulated benefit obligation at end of year Change in Plan Assets: Fair value of assets at beginning of period Employer contributions Participant contributions Lump-sum window Annuity purchase t Actual Benefits paid gain on assets Fair value of assets at end of year Funded StatSS Projected pension benefit obligation Fair value of assets us: Funded status at end of year Amounts Rtt ecognizedii in the Balance l CC Sheet Consis t of:o Other noncurrent assets Other current liabilities Other noncurrent liabilities Net liability recognized ecognizedii Amounts Rtt Income Consist of: Net loss and prior service cost in Accumulated Other Compre CC hensive Retirement Plan OPEB Plans Year Ended December 31, Year Ended December 31, 2021 2020 2021 2020 643 $ 5 16 — — — (11) (48) 605 $ 600 $ 485 $ 1 — — — 30 (46) 470 $ (605) $ 470 (135) $ — $ — (135) (135) $ 674 6 20 — (6) (29) 46 (68) 643 639 528 16 — (6) (29) 40 (64) 485 (643) 485 (158) $ $ $ $ $ $ $ — $ — (158) (158) $ 157 $ 1 4 3 — — (6) (13) 146 $ — $ 37 $ 9 3 — — 3 (13) 39 $ (146) $ 39 (107) $ 26 $ (9) (124) (107) $ 151 2 4 3 — — 12 (15) 157 — 34 9 3 — — 4 (13) 37 (157) 37 (120) 23 (9) (134) (120) (13) $ (42) $ 8 $ 20 $ $ $ $ $ $ $ $ $ $ 149 Fair Value MeaMM surement of Pension and OPEBPP Planll Assets Retirement Plan — As of December 31, 2021 and 2020, all of the Retirement Plan assets were measured at fair value using the net asset value per share (or its equivalent) and consisted of the folff lowing: Asset Category: rr Cash commingled trusts Equity securities: Global equities Fixed income securities: Corporate bonds (a) Government bonds Other (b) Real estate Total assets measured at net asset value $ December 31, 2021 2020 11 149 199 31 30 50 470 $ 11 153 207 37 32 45 485 ___________ (a) Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody's. (b) Consists primarily of high-yield bonds, emerging market debt and bank loans. OPEB Plans l — As of December 31, 2021 and 2020, the Vistra OPEB plan assets measured at fair value on a recurring basis totaled $39 million and $37 million, respectively. At December 31, 2021, assets consisted of $37 million of comingled classifieff d as Level 1. At funds valued at net asset value and $2 million of municipal bond and cash equivalent mutual funds December 31, 2020, assets consisted of $29 million of U.S. equities classifieff d as Level 1 and $8 million of U.S. Treasuries and municipal bonds classified as Level 2. ff Pension Plans with Ptt rojPP ected Benefit Oii i bligati ons (PBO) and Accumulatell d Benefit Oii i bligati ons (ABO)O The following tablea provides information regarding pension plans with PBO and ABO in excess of the fair value of plan assets. Pension Plans with PBO and ABO in Excess Of Plan Assets:tt Projected benefit obligations Accumulated benefit obligation Plan assets December 31, 2021 2020 $ $ $ 605 600 470 $ $ $ 643 639 485 Retireii ment Planll tt Investmen t Strate SS gye tt and Asset Allocat ions ll Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptablea level of risk, while minimizing the volatility of contributions. Fixed income securities held primarily consist of corporate bonds from a diversified range of companies, U.S. Treasuries and agency securities and money by participating in a wide range of investment opportunities. market instruments. Equity securities are held to enhance returt nsr International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging markets. Real estate and credit strategies (primarily high yield bonds and emerging market debt) provide additional portfolio diversification and return potential. The target asset allocation ranges of pension plan investments by asset category are as follow ff s: Asset Category: Fixed income Global equity securities Real estate Credit strategies Target Allocation Ranges Vistra Plan 65 % - 75% 16 % - 24% 4 % - 8% 3 % - 7% Dynegy Plan 45 % - 55% 30 % - 38% 8 % - 12% 6 % - 10% EEI Plan 40 % - 50% 34 % - 42% 10 % - 14% 7 % - 11% Retirement PlaPP n Expec EE ted Long-TerTT m Rrr ate of Return orr n Assets Assumptim on The Retirement Plan strategic asset allocation is determined in conjunction with the plan's advisors and utilizes a ity modeling approach to evaluate potential long-term outcomes of various investment strategies. comprehensive Asset-Liabila assumptim ons for each asset class based on historical and future expected asset The study incorporates long-term rate of returnt class returns, economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management. current market conditions, rate of inflation, current prospects forff t Asset Class: Fixed income securities Global equity securities Real estate Credit strategies Weighted average Retirement Plan Expected Long-Term Rate of Return Vistra Plan Dynegy Plan EEI Plan 3.1 % 6.9 % 5.4 % 5.5 % 4.2 % 3.1 % 6.9 % 5.4 % 5.5 % 4.8 % 3.1 % 6.9 % 5.4 % 5.5 % 4.9 % Benefitff Planll Assumed Healthll Care Cost TreTT nd Rates The following tabla es provide information regarding the assumed health care cost trend rates. Assumed HeaHH lth Care Cost Trend Rates-Not Medicare Eligibl Health care cost trend rate assumed forff Rate to which the cost trend is expected to decline (the ultimate trend rate) Year that the rate reaches the ultimate trend rate next year e: i Assumed HeaHH lth Care Cost Trend Rates-Medicare Eligibl Health care cost trend rate assumed forff Salaried) Health care cost trend rate assumed forff Rate to which the cost trend is expected to decline (the ultimate trend rate) Year that the rate reaches the ultimate trend rate next year (Split-Participant Plan) e: i next year (Vistra Plan, EEI Union and EEI December 31, 2021 2020 6.30 % 4.50 % 2029 9.60 % 8.90 % 4.50 % 2031 6.20 % 4.50 % 2029 9.10 % 8.80 % 4.50 % 2030 Significant Concentrations of Risk al market conditions and other facff The plans' investments are exposed to risks such as interest rate, capita al market and credit risks. We seek to optimize on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing returnt capita investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings for certain investment securities to assist in the mitigation of the risk of large losses. tors specific to us. While we recognize the importance of return, t Assumed Discount Rate We selected the assumed discount rates using the Aon AA Above Median yield curve, which is based on corporate bond yields and at December 31, 2021 consisted of 307 corporate bonds with an average rating of AA using Moody's, S&P and Fitch ratings. s Contribution ii Contributions to the Retirement Plan forff million and zero, respectively, and no contributions are expected to be made in 2022. OPEB plan funding December 31, 2021, 2020 and 2019 totaled $9 million and funding in 2022 is expected to total $9 million. ff ff the years ended December 31, 2021, 2020 and 2019 totaled $1 million, $16 for each year ended 151 Future Benefitff Paymen a ts Estimated future benefitff payments to beneficiaries are as foll ff ows: Pension benefits OPEB 2022 2023 2024 2025 2026 2027-2031 $ $ 67 10 $ $ 42 10 $ $ 33 10 $ $ 34 9 $ $ 46 9 $ $ 162 39 Qualifi PP ll ed Savings Pgg lans Our employees may participate in a qualified savings plan (the Thrift Plan). This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code and is subject to the provisions of ERISA. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more than such threshold may contribute fromff 1% to 20% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% (75% for employees covered under the traditional formula in the Retirement Plan) of the first 6% of employee contributions. Employer matching contributions are made in cash and may be allocated by participants to any of the plan's investment options. At the Merger Date, Vistra assumed Dynegy's participant-directed defined contribution plan. In January 2019, this plan was merged into the Thrift Plan. Aggregate employer contributions to the qualified savings plans totaled $34 million, $34 million and $27 million for the years ended December 31, 2021, 2020 and 2019, respectively. 152 18. STOCK-BASED COMPENSATION VistVV ratt 2016 Omnibus Incentive Planll On the Effective Date, the Vistra board of directors (Board) adopted the 2016 Omnibus Incentive Plan (2016 Incentive Plan), under which an aggregate of 22,500,000 shares of our common stock were reserved forff issuance as equity-based awards to our non-employee directors, employees, and certain other persons. Following approval of the Board and approval by the stockholders at the 2019 annual meeting of the Company, the 2016 Incentive Plan was amended to increase the maximum number of shares reserved for issuance under the 2016 Incentive Plan to 37,500,000. The Board or any committee duly authorized by the Board will administer the 2016 Incentive Plan and has broad authority under the 2016 Incentive Plan to, among other things: (a) select participants, (b) determine the types of awards that participants are to receive and the number of shares that are to be subject to such awards and (c) establia sh the terms and conditions of awards, including the price (if any) to the shares of the award. The types of awards that may be granted under the 2016 Incentive Plan include stock be paid forff options, RSUs, restricted stock, performance awards and other forms of awards granted or denominated in shares of Vistra common stock, as well as certain cash-based awards. ff If any stock option or other stock-based award granted under the 2016 Incentive Plan expires, terminates or is canceled forff any reason without having been exercised in full, the number of shares of Vistra common stock underlying any unexercised award shall again be available forff awards under the 2016 Incentive Plan. If any shares of restricted stock, performance awards or other stock-based awards denominated in shares of Vistra common stock awarded under the 2016 Incentive Plan are forfeited for any reason, the number of forfei purposes of awards under the 2016 Incentive Plan. Any award under the 2016 Incentive Plan settled in cash shall not be counted against the maximum share limitation. No awards under the 2016 Incentive Plan have been settled in cash since the Effective Date. ted shares shall again be available forff ff As is customary in incentive plans of this nature, under the 2016 Incentive Plan and any outstanding awards, as well as the exercise or purchase price of awards, and performance targets under certain types of performance-based awards, are required to be adjusted in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property t each share limit and the number and kind of shares availablea o the Vistra stockholders. t t Stock-Based Compensationtt Expense xx Stock-based compensat m ion expense is reported as SG&A in the consolidated statements of operations as follows: Total stock-based compensation expense Income tax benefit Stock based-compensation expense, net of tax OO Stock Options Year Ended December 31, 2021 2020 2019 $ $ 51 (12) 39 $ $ 63 (15) 48 $ $ 47 (9) 38 The fair value of each stock option is estimated on the date of grant using a Black-Scholes option-pricing model. The risk-free interest rate used in the option valuation model was based on yields available on the grant dates for U.S. Treasury Strips with maturity consistent with the expected life assumption. The expected term of the option represents the period of time that options granted are expected to be outstanding and is based on the SEC Simplifiedff Method (midpoint of average vesting time and contractual term). Expected volatility is based on an average of the historical, daily volatility of a peer group selected by Vistra over a period consistent with the expected life aff ssumption ending on the grant date. We assumed no dividend yield in the valuation of the options granted from 2016 through 2018, and assumed 2.3% and 1.9% dividend yields in the valuation of options granted in 2020 and 2019, respectively. These options may be exercised over either three- or four-year graded vesting periods and will expire 10 years from the grant date. 153 Stock options outstanding at December 31, 2021 are all held by current or former employees. The following tablea summarizes our stock option activity: Total outstanding at beginning of period Granted Exercised Forfeited or expired Total outstanding at end of period Exercisablea at December 31, 2021 Year Ended December 31, 2021 Stock Options (in thousands) 16,030 Weighted Average Exercise Price 19.58 $ — — $ 14.25 (894) $ 28.18 (1,189) $ 19.28 $ 13,947 7,234 $ 17.60 Weighted Average Remaining Contractual Term (Years) 6.7 5.9 5.7 Aggregate Intrinsic Value (in millions) $ $ $ 30.8 55.7 42.1 As of December 31, 2021, $12 million of unrecognized compensation cost related to unvested stock options granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 1 year. Restricted StocSS k UnitsUU The following tablea summarizes our restricted stock unit activity: Total nonvested at beginning of period Granted Vested Forfeited Total nonvested at end of period Year Ended December 31, 2021 Weighted Restricted Stock Average Grant Units Date Fair Value (in thousands) 22.35 $ 2,252 22.61 1,858 $ 22.02 (1,082) $ 23.20 (217) $ 22.57 $ 2,811 of December 31, 2021, $38 million of unrecognized compensation cost related to unvested restricted stock units granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of approximately 2 years. We also issue Performance Stock Units (PSUs) to certain members of management on an annual basis. All PSUs have a three year performance period and a payout opportunity of 0-200% of target (100%), which is intended to be settled in shares of Vistra common stock. We recognized compensation expense associated with PSUs of $9 million, $15 million and zero for the years ended December 31, 2021, 2020 and 2019, respectively. As of December 31, 2021, we have $2 million of unrecognized compensation cost associated with PSUs. 19. RELATED PARTY TRANSACTIONS In connection with Emergence, we entered into agreements with certain of our affiliates and with parties who received shares of common stock and TRA RRR ights in exchange for their claims. Registr e ation Rights i Agreement Pursuant to the Plan of Reorganization, on the Effective Date, we entered into a Registration Rights Agreement (the RRARR ) with certain selling stockholders. Pursuant to the RRARR , we maintain a registration statement on Form S-3 providing for In addition, under the terms of the registration of the resale of the Vistra common stock held by such selling stockholders. RRA,RR among other things, if we propose to file certain types of registration statements under the Securities Act with respect to an offering of equity securities, we will be required to use our reasonable best efforts to offer the other parties to the RRA the opportunity to register all or part of their shares on the terms and conditions set forth in the RRA.RR Tax Receivable Agreement On the Effective Date, Vistra entered into the TRA wRR ith a transfer agent on behalf of certain former first-l ff ien creditors of TCEH. See Note 8 forff discussion of the TRA.RR 154 20. SEGMENT INFORMATION 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. In the third quarter of 2020, Vistra updat ed its reportable segments to reflect changes in how the u Company's Chief Operating Decision Maker (CODM) makes operating decisions, assesses performance and allocates resources. Management believes the revised reportable segments provide enhanced transparency into the Company's long-term sustainable assets and its commitment to managing the retirement of economically and environmentally challenged plants. The following is a summary of the upda ted segments: u • • • The Sunset segment represents plants with announced retirement plans that were previously reported in the ERCOT, PJM and MISO segments. Given recent and expected future retirements of certain power plants, management believes it is important to have a segment which differenti ates between operating plants with defined retirement plans and operating plants without defined retirement plans. 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 PJM, ISO-NE and NYISO that were previously reported in the PJM and NY/NE segments, respectively. The West segment represents Vistra's electricity generation operations in CAISO and was previously reported in the Corporat e and Other non-segment. As reflected by the Moss Landing and Oakland ESS projects (see Note 3), the r Company expects to expand its operations in the West segment. ff Our CODM reviews the results of these segments separately and allocates resources to the respective segments as part of our strategic operations. A measure of assets is not applicable, as segment assets are not regularly reviewed by the CODM for evaluating performance or allocating resources. The Retail segment is engaged in retail sales of electricity and natural gas to residential, commercial and industrial customers. Substantially all of these activities are conducted by TXU Energy, Ambit, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S. Gas & Electric across 19 states in the U.S. t The Texas and East segments are engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel production and fuel logistics management. The Texas segment represents results fromff the ERCOT market and was referred to as the ERCOT segment prior to the third quarter of 2020. The East segment represents results fromff these markets into one the PJM, ISO-NE and NYISO markets. We determined it was appropriate to aggregate results fromff reportable segment, East, given similar economic characteristics. The West segment represents results fromff the CAISO market, including our development of battery ESS projects at our Moss Landing and Oakland power plant sites (see Note 3). The Sunset segment consists of generation plants with announced retirement plans. Separately reporting the Sunset segment differentiates operating plants with announced retirement plans from our other operating plants in the Texas, East and West segments. We have allocated unrealized gains and losses on the commodity risk management activities to the Sunset segment for the generation plants that have announced retirement plans. The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines (see Note 4). Separately reporting the Asset Closure segment provides management with better information related to the performance and earnings power of Vistra's ongoing operations and facilitates management's focus on minimizing the cost associated with decommissioning and reclamation of retired plants and mines. We have not allocated any unrealized gains or losses on the commodity risk management activities to the Asset Closure segment for the generation plants that were retired in 2018, 2019 and 2020. Corporate r and Other represents the remaining non-segment operations consisting primarily of general corporate expenses, interest, taxes and other expenses related to our support functions that provide shared services to our operating segments. The accounting policies of the business segments are the same as those described in the summary of significff ant accounting policies in Note 1. Our CODM uses more than one measure to assess segment performance, including segment net income (loss), which is the measure most comparablea to consolidated net income (loss) prepared based on U.S. GAAP. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at market prices. Certain shared services costs are allocated to the segments. 155 For the year ended Retail Texas East West Sunset Asset Closure Corporate and Other (b) Eliminations Consolidated Operating revenues (a): December 31, 2021 December 31, 2020 December 31, 2019 Depreciation and amortization: December 31, 2021 December 31, 2020 December 31, 2019 Operating income (loss): $ 7,871 8,270 6,872 $ 2,790 4,116 3,836 $ 2,587 2,415 2,790 $ 374 282 338 $ 739 1,252 1,602 $ — $ 3 341 — $ — — (2,284) $ (4,895) (3,970) 12,077 11,443 11,809 $ (212) $ (608) $ (698) $ (475) (472) (721) (680) (303) (292) (60) $ (139) $ — $ (19) (19) (133) (120) (22) — (36) $ (64) (57) — $ — — (1,753) (1,737) (1,640) December 31, 2021 December 31, 2020 December 31, 2019 $ 2,213 312 155 $(2,601) $ (552) $ 1,761 1,314 73 398 (8) $ (428) $ 39 88 (420) 271 (56) $ (109) (107) (83) $ (137) (127) — $ — 1 (1,515) 1,519 1,993 $ 1 3 3 — $ — — (384) (630) (797) 458 (266) (290) — $ — 1 (1,264) 624 926 $ $ Interest expense and related charges: December 31, 2021 December 31, 2020 December 31, 2019 Income tax (expense) benefit: December 31, 2021 December 31, 2020 December 31, 2019 Net income (loss): $ $ (9) $ (10) (21) $ 14 8 8 (15) $ (7) (13) $ 9 10 — (2) $ (2) (4) (1) $ — — (381) $ (632) (770) (2) $ — $ — $ — $ — $ — $ — — — — — — — — — — — — 460 (266) (290) December 31, 2021 December 31, 2020 December 31, 2019 $ 2,196 309 134 $(2,512) $ (567) $ 1,760 1,342 41 400 1 50 88 $ (413) $ (414) 274 (22) $ (101) (109) 53 (1,021) (1,204) Capital expenditures, including nuclear fuel and excluding LTSA prepayments and development and growth expenditures: December 31, 2021 December 31, 2020 December 31, 2019 $ $ 1 2 1 $ 266 388 296 $ 44 71 61 $ 8 2 2 31 46 58 $ — $ — — $ 48 91 69 — $ — — 398 600 487 ____________ (a) The following unrealized net gains (losses) from mark-to-market valuations of commodity positions are included in operating revenues: For the year ended December 31, 2021 December 31, 2020 December 31, 2019 Retail $ (325) $ (1,272) $ (637) $ (42) $ (634) $ — $ Sunset Texas West East Asset Closure Corporate and Other (11) 8 677 575 (23) 195 (10) 41 (140) 168 — — Eliminations (1) 1,719 (329) (305) — $ — — $ Consolidated (1,191) 164 682 ____________ (1) Amounts offset in fuel ff , purchased power costs and delivery fees in the Retail segment, with no impact to consolidated results. (b) Income tax expense is generally not reflected in net income of the segments but is reflected almost entirely in Corporate and Other net income. 156 21. SUPPLEMENTARY FINANCIAL INFORMATION ii Impaim rme nt of Long-Lived Assets In the second quarter of 2021, we recognized an impairment loss of $38 million related to our Zimmer generation facility g a decrease in the economic in Ohio as a result of a significant decrease in the estimated usefulff forecast of the facilit ity auction held in May 2021. The impairments are reported in our Sunset segment and include a $33 million write-down of property, plant and equipment and a $5 million write-down of inventory. evenues for the plant in the latest PJM capac y and the inability to secure capac life of the facilities, reflectin t ity r a a ff ff In the third quarter of 2020, we recognized impairment losses of $173 million related to our Kincaid coal generation facility in Illinois and $99 million related to our Zimmer coal generation facility in Ohio, each as a result of a significant decrease in the estimated useful life of the facility, reflecff ting our recently announced plan to retire both facilities by the end of 2027 in response to the final CCR rule (see Notes 4 and 13). The impairment losses are reported in our Sunset segment and include a $260 million write-down of property, plant and equipment and a $12 million write-down of inventory. ff In the first quarter of 2020, we recognized an impairment loss of $52 million related to our Joppa/EEI coal generation ting a decrease in the facility in Illinois as a result of a significant decrease in the estimated useful life of the facility, reflecff ast of the facility and changes to the operating assumptim on based on lower forecasted wholesale electricity economic forec ility and prices. We also recorded a $32 million impairment to a capacity contract which was linked in part to the Joppa/EEI facff therefore determined to have a significant decrease in estimated useful life. The impairments are reported in our Sunset segment and include a $45 million write-down of property, plant and equipment, a $32 million write-down of intangible assets and a $7 million write-down of inventory. In determining the fair value of the impaired assets, we equally weighted a market approach based on transactions of similar assets and an income approach discounting our projected cash flows through the respective plant retirement dates. tt Interes t Expense EE and Relatell s d Charge CC Interest paid/accrued Unrealized mark-to-market net (gains) losses on interest rate swapsa Amortization of debt issuance costs, discounts and premiums Debt extinguishment (gain) loss Capita Other Total interest expense and related charges alized interest Year Ended December 31, 2021 2020 2019 $ $ 480 (134) 30 1 (26) 33 384 $ $ 467 155 18 (17) (21) 28 630 $ $ 576 220 9 (21) (12) 25 797 The weighted average interest rate appl a icable to the Vistra Operations Credit Facilities, taking into account the interest rate swapsa discussed in Note 11, was 3.90%, 3.88% and 4.03% as of December 31, 2021, 2020 and 2019, respectively. 157 tt Other Income and Deductions Other income: Insurance settlements (a) Gain on settlement of rail transportation disputes (b) Sale of land (b) Funds released from escrow to settle pre-petition claims of our predecessor (c) Interest income All other Total other income Other deductions: Loss on disposal of investment in NELP (d) All other Total other deductions Year Ended December 31, 2021 2020 2019 $ $ $ $ 88 15 9 — — 28 140 $ $ — $ 16 16 $ 6 — 8 — 2 18 34 29 13 42 $ $ $ $ 22 — — 9 10 15 56 — 15 15 ____________ (a) For the year ended December 31, 2021, $80 million reported in the Texas segment, $7 million reported in the Sunset segment and $1 million reported in the Corporate and Other non-segment. For the year ended December 31, 2020, $3 million reported in the Corporate and Other non-segment, $2 million reported in the Asset Closure segment and $1 million reported in the Texas segment. For the year ended December 31, 2019, reported in the Texas segment. (b) Reported in the Asset Closure segment. (c) Reported in the Corporate and Other non-segment. (d) Reported in the East segment. Restricted CasCC h Amounts related to remediation escrow accounts Total restricted cash December 31, 2021 December 31, 2020 Current Assets Noncurrent Assets Current Assets Noncurrent Assets $ $ 21 21 $ $ 13 13 $ $ 19 19 $ $ 19 19 Remediation Escrow — During the years ended December 31, 2020 and 2019, Vistra transferred asset retirement obligations related to several closed plant sites to a third-party remediation company. As part of certain transfers, Vistra into an escrow accounts, and the funds are released to the remediation company as milestones are reached in the deposits funds remediation process. Amounts contractually payablea to the third party in exchange for assuming the obligations are included in other current liabilities and other noncurrent liabilities and deferred credits. ff Trade Accounts Rtt eceivablell Wholesale and retail trade accounts receivable Allowance for uncollectible accounts Trade accounts receivablea — net December 31, 2021 2020 $ $ 1,442 (45) 1,397 $ $ 1,324 (45) 1,279 Gross trade accounts receivable as of December 31, 2021 and 2020 included unbilled retail revenues of $426 million and $468 million, respectively. 158 Allowance forff Uncollectible Accounts Receivable Allowance forff Increase forff Decrease forff uncollectible accounts receivable at beginning of period (a) bad debt expense account write-offs $ Allowance for uncollectible accounts receivablea ____________ (a) The beginning balance in 2020 includes a $6 million increase recorded dued at end of period $ Instruments—Credit Losses (see Note 1). Inventories by Major Category e Materials and supplies Fuel stock Natural gas in storage Total inventories Investments Nuclear plant decommissioning trust Assets related to employee benefit plans (Note 17) Land Miscellaneous other Total investments Year Ended December 31, 2021 2020 2019 45 110 (110) 45 $ $ 42 110 (107) 45 $ $ 19 82 (65) 36 to the adoption of ASU 2016-13, Financial December 31, 2021 2020 260 314 36 610 $ $ 260 236 19 515 December 31, 2021 2020 1,960 42 44 3 2,049 $ $ 1,674 41 44 — 1,759 $ $ $ $ Investment in Unconsolidat edtt ll ii Subsidiary On the Merger Date, we assumed Dynegy's 50% interest in NELP, a joint venturet with NextEra Energy, Inc., which indirectly owned the Bellingham NEA facility and the Sayreville facility. In December 2019, Dynegy Northeast Generation GP, Inc. and Dynegy Northeast Associates LP, Inc., indirect subsidiaries of Vistra, entered into a transaction agreement with NELP and certain indirect subsidiaries of NextEra Energy, Inc. wherein the indirect subsidiaries of Vistra redeemed their ownership interest in NELP in exchange for 100% ownership interest in NJEA, the company which owns the Sayreville facility. The NELP Transaction was approve d by FERC in February 2020, and the NELP Transaction closed on March 2, 2020. As a result of the NELP Transaction, Vistra indirectly owns 100% of the Sayreville facff lity. A loss of $29 million was between our derecognized investment in NELP recognized in connection with the NELP Transaction, reflecting the difference and the value of our acquired 100% interest in NJEA, which was measured in accordance with ASC 805. The loss is reported in our consolidated statements of operations in other deductions. ility and no longer has any ownership interest in the Bellingham NEA faci a ff ff Equity earnings related to our investment in NELP totaled $3 million and $14 million for the years ended December 31, 2020 and 2019, respectively, recorded in equity in earnings of unconsolidated investment in our consolidated statements of operations. We received distributions totaling $3 million and $22 million for the years ended December 31, 2020 and 2019, respectively. 159 Nuclear Decommissi ii TT oning Tn rust ff Investments in a trust that will be used to fundff value. Decommissioning costs are being recovered fromff the costs to decommission the Comanche Peak nuclear generation plant are Oncor customers as a delivery fee surcharge over the carried at fair life of the plant and deposited by Vistra (and prior to the Effective Date, a subsidiary of TCEH) in the trust fund. Income and expense, including gains and losses associated with the trust fund assets and the decommissioning liabia lity, are offset by a corresponding change in a regulatory asset/liability (currently a regulatory liability reported in other noncurrent liabilities and Oncor's deferred credits) that will ultimately be settled through changes in Oncor's delivery fees rates. If funds recovered fromff customers held in the trust fund are determined to be inadequate to decommission the Comanche Peak nuclear generation plant, Oncor would be required to collect all additional amounts from its customers, with no obligation from Vistra, provided that Vistra complied with PUCT ruler s and regulations regarding decommissioning trusts. A summary of the fair market value of investments in the fund follows: ff Year Ended December 31, 2021 2020 $ 679 1,281 1,960 618 1,056 1,674 Debt securities (a) Equity securities (b) $ Total ____________ (a) The investment objective for debt securities is to invest in a diversifieff d tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody's. The debt securities are heavily weighted with government and municipal bonds and investment grade corporate bonds. The debt securities had an average coupon rate of 2.54% and 2.91% as of December 31, 2021 and 2020, respectively, and an average maturity of 10 years as of both December 31, 2021 and 2020. $ $ (b) The investment objective for equity securities is to invest tax efficiently and to match the performff ance of the S&P 500 Index for U.S. equity investments and the MSCI EAFE Index forff non-U.S. equity investments. Debt securities held as of December 31, 2021 mature as follows: $247 million in one to five years, $190 million in five to 10 years and $242 million after 10 years. The following tabla e summarizes proceeds from sales of securities and investments in new securities. Year Ended December 31, 2021 2020 2019 $ $ 483 $ (505) $ 433 $ (455) $ 431 (453) Proceeds from sales of securities Investments in securities operty, Pyy laPP nt and Equipment Power generation and structures Land Office and other equipment Total Less accumulated depreciation Net of accumulated depreciation December 31, 2021 2020 16,195 608 183 16,986 (4,801) 12,185 173 212 486 13,056 $ $ 15,222 617 173 16,012 (3,614) 12,398 182 207 712 13,499 $ $ Finance lease right-of-use assets (net of accumulated depreciation) Nuclear fuel (net of accumulated amortization of $125 million and $91 million) Construction work in progress Property, plant and equipment — net preciation expenses totaled $1.478 billion, $1.377 billion and $1.300 billion for the years ended December 31, 2021, 2020 and 2019, respectively. 160 Our property, plant and equipment consist of our power generation assets, related mining assets, information system hardware, capitalized corporate office lease space and other leasehold improvements. The estimated remaining useful lives range from 1 to 32 years for our property, plant and equipment. Asset Retireii ment and MiningMM Reclamll ation Obligations tt (ARO)O These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, remediation or closure of coal ash basins, and generation plant disposal costs. There is no earnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverablea through the regulatory process as part of delivery fees charged by Oncor. As of December 31, 2021 and 2020, asbestos removal liabilities totaled $3 million and zero million, respectively. We have also identified conditional AROs for asbestos removal and disposal, which are specific to certain generation assets. As of December 31, 2021, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.635 billion, which is lower than the fair value of the assets contained in the nuclear decommissioning trust. Since the costs to ultimately decommission that plant are recoverablea through the regulatory rate making process as part of Oncor's delivery fees, a corresponding regulatory liability has been recorded to our consolidated balance sheet of $325 million in other noncurrent liabilities and deferred credits. The following tablea summarizes the changes to these obligations, reported as AROs (current and noncurrent liabilities) in our consolidated balance sheets, for the years ended December 31, 2021, 2020 and 2019: Nuclear Plant Decommissioning 1,276 $ Mining Land Reclamation Coal Ash and Other Total $ 442 $ 655 $ 2,373 Liability at December 31, 2018 Additions: Accretion Adjustment for change in estimates Adjustment for obligations assumed through acquisitions Reductions: Payments Liability transfers (a) Liability at December 31, 2019 Additions: Accretion Adjustment for change in estimates (b) Reductions: Payments Liability transfers (a) Liability at December 31, 2020 Additions: Accretion Adjustment for change in estimates Reductions: Payments Liability at December 31, 2021 Less amounts dued currently 44 — — — — 1,320 46 219 — — 1,585 50 — — 1,635 — 1,635 $ 22 16 — (70) — 410 20 (6) (65) — 359 16 13 (68) 320 (90) 230 $ 31 (1) (3) (39) (135) 508 23 25 (49) (15) 492 22 1 (20) 495 (14) 481 $ 97 15 (3) (109) (135) 2,238 89 238 (114) (15) 2,436 88 14 (88) 2,450 (104) 2,346 Noncurrent liability at December 31, 2021 $ (a) Represents ARO transferred remediation. Any remaining unpaid third-party obligation has been reclassififf ed to other current liabilities and other noncurrent liabilities and deferred credits in our consolidated balance sheets. to a third-party forff ff 161 (b) The adjustment for nuclear plant decommissioning resulted from a new cost estimate completed in 2020. Under applicable accounting standards, the liability is remeasured when significant changes in the amount or timing of cash flows occur, and the PUCT requires a new cost estimate at least every five years. The increase in the liability was driven equipment and services and a delay in timing of when the by changes in assumptim ons including increased costs for labor, U.S. Department of Energy is estimated to begin accepting spent fuel offsite. a NN Other Noncurre ii nt Liabil itll iett s and Deferre e d CreCC ditstt The balance of other noncurrent liabilities and deferred credits consists of the folff lowing: ities (Note 6) Retirement and other employee benefits (Note 17) Winter Storm Uri impact (a) Identifiable intangible liabila Regulatory liability Finance lease liabilities Uncertain tax positions, including accrued interest Liability for third-party remediation Accrued severance costs Other accrued expenses December 31, 2021 2020 276 261 147 325 235 13 17 39 176 1,489 $ $ 312 — 289 89 206 12 31 54 138 1,131 $ $ Total other noncurrent liabilities and deferred credits ____________ (a) Includes the allocation of ERCOT default uplift charges and future bill credits related to large commercial and industrial customers that curtailed during Winter Storm Uri. Fair Vii alueVV of Debt Long-term debt (see Note 11): Long-term debt under the Vistra Operations Credit Facilities Vistra Operations Senior Notes Forward Capac ity Agreements Equipment Financing Agreements Building Financing Other debt a December 31, 2021 December 31, 2020 Fair Value Hierarchy Carrying Amount Fair Value Carrying Amount Fair Value $ Level 2 Level 2 Level 3 Level 3 Level 2 Level 3 $ 2,549 7,880 211 85 3 3 $ 2,518 8,193 211 85 3 3 $ 2,579 6,634 45 59 10 3 2,565 7,204 45 59 10 3 determine fair value in accordance with accounting standards as discussed in Note 15. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services, such as Bloomberg. Supplemll ental Cash Flowll Information The following tablea reconciles cash, cash equivalents and restricted cash reported in our consolidated statements of cash flows to the amounts reported in our consolidated balance sheets at December 31, 2021 and 2020: Cash and cash equivalents Restricted cash included in current assets Restricted cash included in noncurrent assets Total cash, cash equivalents and restricted cash December 31, 2021 2020 $ $ 1,325 21 13 1,359 $ $ 406 19 19 444 162 The folff lowing table summarizes our supplemental cash flowff information for the years ended December 31, 2021, 2020 and 2019, respectively. Cash payments related to: Interest paid Capita alized interest Interest paid (net of capitalized interest) Income taxes paid / (refunds received) (a) ncing activities: Noncash investing and finaff Accrued property, plant and equipment additions (b) Disposition of investment in NELP Acquisition of investment in NJEA Shares issued for tangible equity unit contracts (Note 14) Land transferred with liabia lity transfers Year Ended December 31, 2021 2020 2019 $ $ $ $ $ $ $ $ $ 482 (26) 456 $ (50) $ $ 171 — $ — $ — $ — $ $ 503 (21) 482 $ (140) $ $ 19 $ 123 90 $ — $ — $ 525 (12) 513 (76) 67 — — 446 16 ____________ (a) For the years ended December 31, 2021, 2020 and 2019, we paid state income taxes of $52 million, $40 million and $42 of zero, $170 million and $115 million, respectively, and received state ff million, respectively, received federal tax refunds tax refunds of $2 million, $10 million and $3 million, respectively. (b) Represents property, plant and equipment accruals during the period for which cash has not been paid as of the end of the period. 163 Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. Item 9A. CONTROLS AND PROCEDURES An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal finaff ncial officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15a-15(e) of the Exchange Act) in effect at December 31, 2021. Based on the evaluation performed, our principal executive officer and principal finaff ncial officer concluded that the disclosure controls and procedures were effecff tive as of that date. There have been no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(e) and 15a-15(e) of the Exchange Act) during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. VISTRA CORP. MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING shing and maintaining adequate internal control over financial The management of Vistra Corp. is responsible for establia reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) for the company. Vistra Corp.'s internal control over financial reporting is designed to provide reasonable assurance regarding the reliabia lity of financial reporting and the preparation of financial statements forff external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in condition or the deterioration of compliance with procedures or policies. The management of Vistra Corp. performed an evaluation of the effectiveness of the company's internal control over financial reporting as of December 31, 2021 based on the Committee of Sponsoring Organizations of the Treadway Commission's (COSO's) Internal Control - InteII Framework (2013). Based on the review perforff med, management believes that as of e grated December 31, 2021 Vistra Corp.'s internal control over finaff ncial reporting was effective. The independent registered public accounting firm of Deloitte & Touche LLP as auditors of the consolidated finaff statements of Vistra Corp. has issued an attestation report on Vistra Corp.'s internal control over finaff ncial reporting. ncial /s/ CURTIS A. MORGAN Curtis A. Morgan Chief Executive Officer (Principal Executive Officer) February 25, 2022 /s/ JAMES A. BURKE James A. Burke President and Chief Financial Officer (Principal Financial Officer) 164 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To hthe sto khckh ldolders dand hthe Boa drd of iDirectors of iVistra Corp. O iOpi inion on Internal CControl over Fiinan icial Reportinging audit ded hthe iinte control over fifina l We hhave l rnal di icrite iria establiblia Dece bmber 31, 2021, bbas ded on of i respects, effectiive iinte Control gOrga inizatiions of hthe Treaddwayy Com imi control over ifina l ework (2013) iiss dued byby COSO. l rnal d FramFF e t — InteII grate h dshed iin InteI Sponsori gng inci lal inci lal i reporti gng of rnal Control iVistra Corp. e grate tt — InteII ission ((CO )SO). In our i i i dand iits s b idi d FramFF ubsidia irie (s ( hthe “Company”)ny”) as of ework (2013) iissued bd byy thhe Commiittee opinion, hthe Compa yny maiint iai dned, iin lalll materiiall rnal reporti gng as of Dece bmber 31, 2021, bbas ded on ished iin InteI establi h d bl icrite iria di auditedd, iin ac We hhave lalso consoliddat ded fifina ((PCAOB)), hthe li bruary 25, 2022, expressedd an unqualilififiedd o i ipinion on hthose fifina report ddat ded February iwithh thhe sta d d inci lal statements as of ndards of hthe dcordance dand for hthe yyear e d dnded Dece bmber 31, 2021, of hthe Compa yny inci lal statements. Public Com ypany Accountinging Ove irsightght Boa drd ( bli (Unitedd States)) dand our i Basiis ffor O ipi inion ibl hThe Compa yny’s ma gnagement iis res assessment of hthe effec itiveness of iinternall cont l Annuall Report on Inte rnal iinternall cont inci lal requi dred to bbe i dinde lrules a dnd regul regulatiions of hthe Sec iuritiies a dnd Exchange reporti gng bbas ded on our Control over l lrol over fifina dpendent iFina i i inci lal Re ponsible forff maiint iainingning effectiive iinte lrol over fifina control over fifina reporti gng, iincl dluded id in thhe accompanying inci lal rnal l i l i porti gng. Our res di audit. We are a p bliublic accountinging fifirm regi ponsibilili yty iis to express an ibi i inci lal reporti gng dand for iits nying Ma gnagement’s opinion on hthe Compa yny’s register ded i hwith hthe PCAOB a dnd are applicablblea li i i iwithh respect to thhe Compa yny iin ac dcordance iwithh thhe U.S. f dfede lral securi iities llaws a dnd hthe hange Com imi ission dand hthe PCAOB. di dconduct ded our audi it in acc dordance We audit to obbtaiin reasonablblea di mate iriall respects. Our audi di hthat a materi lial weakkness e ixists, tes iti gng assessedd ri kisk, provides a reasonablblea provide bbasiis for our opinion. i i dunderstanding dand evallua iti gng hthe ddesignign id assurance babout it incl dludedd obbtai iini gng an iwithh thhe sta d d hwhe hther effectiive iinte ndards of hthe PCAOB. hThose sta d d ndards control over fifina rnal l nding of iinternall cont inci lal lrol over fifina l i i require hthat we lplan a dnd perform hthe reporti gng was m iaint iai dned iin lalll reporti gng, asse issi gng hthe iriskk inci lal lrol bbas ded on hthe audit di i dand performinging suchh o hther proceddures as we conside dred necessa yry iin hthe icircumstances. We b lbeliieve hthat our dand opera iti gng effectiiveness of if internall cont Defi fini ition and Li tations fof Internal CControl over Fiinan icial Reportinging i imi i i i l i inci lal iunti gng iityy of fiinaff l rnal inci lal dand hthe preparatiion of fifina iprinci liples. A com ypany’s iinte reporti gng iis a process d idesignedgned to control over fifina reporti gng A com ypany’s iinte lreliiabilbila accep dted acco htha (t ( )1) pert iain to thhe maiintenance of rec dords hthat, iin reasonablblea didisposiitiions of hthe assets of hthe compa yny; ( )(2) ppreparatiion of fifina expe dinditures com ypany; didisposiitiion of hthe compa yny’s assets hthat c of hthe compa yny are b ibei gng madde onlyonly iin ac gregarding bl sonable assurance inci lal statements for externall purpose is in acc dordance lipoli icies gregarding rding hthe iwi hth ggene lrallyly dand proceddures dand sonable assurance hthat transac itions are record dded as necessa yry to permiit dand dand didirectors of hthe quisitiion, use, or reporti gng iincl dludes thhose fl rding preve intion or itimelyly ddetec ition of unauth ihoriz ded ac iwi hth ggene lrallyly accep dted acco uthoriza itions of ma gnagement iprinci liples, a dnd hthat rec ieipts id provide rea dcordance ddet iaill, accuratelytely and fd f iaifff inci lal statements iin ac reflect thhe transac itions ieri lal effect on hthe fifina sonable assurance control over fifina inci lal statements. lould hd have a mat iwithh a h i provide rea id provide rea id dcordance dand ( )(3) iunti gng inci lal rnal l rlyrly i i bl bl t l i is i hnherent lili Because of iit proje projectiions of becbecause of change yany evallua ition of effectiiveness to future imitations, iinternall cont i inci lal iperi dods are subje onditiions, or hthat thhe ddeggree of com lipliance wi hith hthe lrol over fifina hange is in c di i reporti gng mayy not prevent or ddetect miisstatements. subject to hthe i krisk hthat cont lAlso, lrols may by become iin dadequate lipoli icies or proceddures may dy det ieriorate. / //s/ Del iloitte & Touchhe LLP Dallllas, Texas February bruary 25, 2022 165 Item 9B. OTHER INFORMATION On February 2rr 3, 2022, our board of directors (Board) approved our amended and restated bylaws (A&R Bylaws) effective immediately. The A&R Bylaws were amended and restated, among other things, to amend advance notice requirements forff stockholders to bring proposed director nominees or other items of business before a special or annual stockholders meeting, and to allow annual meetings of stockholders to be held by means of remote communication in addition to being held at any place, as determined by our Board in its sole discretion. The A&R Bylaws also reflect other technical and administrative changes. The foregoing description of our A&R Bylaws is qualified in its entirety by the full text of the A&R Bylaws, a copy of which is included as Exhibit 3.5 to this Annual Report on Form 10-K. Item 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS None. 166 Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE Code of Ethics PART III Vistra has adopted a code of ethics entitled "Vistra Code of Conduct" that applies to directors, officers and employees, e It may be accessed through the "Corporat including the chief executive officer and senior financial officers of Vistra. Governance" section of the Company's website at www.vistracorp.com. Vistra also elects to disclose the information required by Form 8-K, Item 5.05, "Amendments to the Registrant's Code of Ethics, or Waiver of a Provision of the Code of Ethics," through the Company's website and will disclose such events within four business days following the date of the amendment or on this website for at least a 12-month period. A copy of the "Vistra Code waiver, and such information will remain availablea of Conduct" is availablea in print to any stockholder who requests it. r ff Other information required by this Item is incorporated by reference to the similarly named section of Vistra Definitive Proxy Statement for its 2022 Annual Meeting of Stockholders. Item 11. EXECUTIVE COMPENSATION Information required by this Item is incorporated by reference to the similarly named section of Vistra's Definitive Proxy Statement for its 2022 Annual Meeting of Stockholders. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS Information required by this Item is incorporated by reference to the sections entitled "Beneficial Ownership of Common Stock of the Company" in Vistra's Definff itive Proxy Statement for its 2022 Annual Meeting of Stockholders. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACT RR IONS, AND DIRECTOR INDEPENDENCE Information required by this Item is incorporated by reference to the sections entitled "Business Relationships and Related Person Transactions Policy" and "Director Independence" in Vistra's Definitive Proxy Statement for its 2022 Annual Meeting of Stockholders. Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES Information required by this Item is incorporated by reference to the sections entitled "Principal Accounting Fees" in Vistra's Definitive Proxy Statement for its 2022 Annual Meeting of Stockholders. Deloitte & Touche LLP's PCAOB ID Number is 34. 167 Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES PART IV (a) Our financial statements and financial statement schedules are incorporated under Part II, Item 8 of this annual report on Form 10-K. (b) SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT VISTRA CORP. (PARENT) SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENTS OF OPERATIONS (Millions of Dollars) RR Depreciation and amortization Selling, general and administrative expenses Operating loss Other income Interest expense and related charges Impacts of Tax Receivable Agreement Loss before income tax benefit Income tax benefit Equity in earnings of subsidiaries, net of tax Net income (loss) See Notes to the Condensed Financial Statements. Year Ended December 31, 2021 2020 2019 $ $ (17) $ (53) (70) 3 — 53 (14) 4 (1,264) (1,274) $ (15) $ (72) (87) 5 (7) 5 (84) 25 695 636 $ (7) (62) (69) 12 (88) (37) (182) 42 1,068 928 VISTRA CORP. (PARENT) SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENTS OF CASH FLOWS (Millions of Dollars) Cash flows — operating activities: Cash used in operating activities Ended December 31, 2021 2020 2019 $ (38) $ (86) $ (58) Cash flows — investing activities: t al expenditures Capita Dividend received fromff Equity contribution to subsidiaries subsidiaries Cash provided by investing activities Cash flows — finaff ncing activities: Issuances of preferred stock Repayments/repurchases of debt Debt tender offer and other debt financing fees Stock repurchases Dividends paid to stockholders Other, net Cash used in financing activities Net change in cash, cash equivalents and restricted cash Cash, cash equivalents and restricted cash — beginning balance Cash, cash equivalents and restricted cash — ending balance $ — 405 (988) (583) 2,000 — — (471) (290) (23) 1,216 595 73 668 $ (15) 1,105 — 1,090 — (747) (17) — (266) — (1,030) (26) 99 73 $ (36) 3,890 — 3,854 — (2,903) (123) (656) (243) — (3,925) (129) 228 99 See Notes to the Condensed Financial Statements. VISTRA CORP. (PARENT) SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED BALANCE SHEETS (Millions of Dollars) ASSETS Cash and cash equivalents Trade accounts receivablea — net Income taxes receivable Prepaid expense and other current assets Total current assets iated companies Investment in affilff Property, plant and equipment — net Identifiable intangible assets — net Accumulated deferred income taxes Other noncurrent assets Total assets LIABILITIES AND EQUITY Trade accounts payable Accounts payablea —affiliates Accrued taxes Other current liabilities Total current liabilities Tax Receivablea Other noncurrent liabilities and deferred debits Agreement obligations Total liabilities Total stockholders' equity Total liabilities and equity See Notes to the Condensed Financial Statements. December 31, 2021 2020 $ $ $ $ 668 8 15 1 692 7,157 3 31 1,016 1 8,900 114 72 — 3 189 394 25 608 8,292 8,900 $ $ $ $ 73 7 — 5 85 8,005 3 47 783 2 8,925 2 74 14 4 94 447 23 564 8,361 8,925 NOTES TO CONDENSED FINANCIAL STATEMENTS 1. BASIS OF PRESENTATION The accompanying unconsolidated condensed balance sheets, statements of net loss and cash flows present results of ncial operations and cash flows of Vistra Corp. (Parent). Certain information and footnote disclosures normally included in finaff statements prepared in accordance with U.S. GAAP have been omitted pursuant to the rules of the SEC. Because the unconsolidated condensed financial statements do not include all of the information and footnotes required by U.S. GAAP, they should be read in conjunction with the financial statements and related notes of Vistra Corp. and Subsidiaries included in the under annual report on Form 10-K for the year ended December 31, 2020. Vistra Corp.'s subsidiaries have been accounted forff the equity method. All dollar amounts in the financial statements and tablea s in the notes are stated in millions of U.S. dollars unless otherwise indicated. Vistra Corp. (Parent) filff es a consolidated U.S. federal income tax return. Consolidated tax expenses or benefits and deferred tax assets or liabilities have been allocated to the respective subsidiaries in accordance with the accounting rules that apply to separate finff ancial statements of subsidiaries. t 169 2. RESTRICTIONS ON SUBSIDIARIES a The Credit Facilities Agreement generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of December 31, 2021, Vistra Operations can distribute approxi mately $7.3 billion to Vistra Corp. (Parent) under the Credit Facilities Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to Parent was partially reduced by distributions made by Vistra Operations to Vistra Corp. (Parent) of approxi mately $405 million, $1.1 billion and $3.9 billion during the years ended December 31, 2021, 2020 and 2019, respectively. Additionally, Vistra Operations may make distributions to Vistra Corp. (Parent) in amounts sufficient for Vistra Corp. (Parent) to make any payments required under the TRA oRR r the Tax Matters Agreement or, to the extent arising out of Vistra Corp. (Parent)'s ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses. As of December 31, 2021, all of the restricted net assets of Vistra Operations may be distributed to Vistra Corp. (Parent). a 3. GUARANTEES Vistra Corp. (Parent) has entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. As of December 31, 2021, there are no material outstanding claims related to guarantee obligations of Vistra Corp. (Parent), and Vistra Corp. (Parent) does not anticipate it will be required to make any material payments under these guarantees in the near term. 4. DIVIDEND RESTRICTIONS Under applicable law, Vistra Corp. (Parent) is prohibited fromff paying any dividend to the extent that immediately following payment of such dividend there would be no statutt ory surplus or Vistra Corp. (Parent) would be insolvent. Vistra Corp. (Parent) received $405 million, $1.105 billion and $3.890 billion in dividends from its consolidated subsidiaries in the years ended December 31, 2021, 2020 and 2019, respectively. In the year ended December 31, 2021, Vistra Corp. (Parent) made an equity contribution to Vistra Operation of $988 million. (c) EXHIBITS: Vistra Corp. Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2021 Exhibits Previously Filed With File Number* As Exhibit (2) 2.1 2.2 (3(i)) 3.1 3.2 3.3 3.4 Plan of Acquisition, Reorganization, Arrangement, Liquidation, or Succession 333-215288 Form S-1 (filed December 23, 2016) 001-38086 Form 8-K (filed October 31, 2017) Articles of Incorporation 001-38086 Form 8-K (filed May 4, 2020) 001-38086 Form 8-K (filed June 29, 2020) 001-38086 Form 8-K (filed on October 15, 2021) 001-38086 Form 8-K (filed on December 13, 2021) 2.1 2.1 — Order of the United States Bankruptcy Court for the District of Delaware Confirming the Third Amended Joint Plan of Reorganization — Agreement and Plan of Merger, dated as of October 29, 2017, by and between Vistra Energy Corp. (now known as Vistra Corp.rr ) and Dynegy, Inc. 3.1 — Restated Certificate of Incorporation of Vistra Energy Corp. (now known as Vistra Corp.) 3.1 — Certificate of Amendment of of Incorporation of Vistra Energy Corp. (now known as Vistra Corp.) , effeff ctive July 2, 2020 the Restated Certificate rr ff 3.1 — Series A Preferred Stock Certificate of Designation, filed with the Secretary of State of Delaware on October 14, 2021 3.1 — Series B Preferred Stock Certificate of Designation, filed with the Secretary of State of Delaware on December 9, 2021 (3(ii)) By-laws 170 3.5 (4) 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 4.9 4.10 Exhibits Previously Filed With File Number* As Exhibit ** — Amended and Restated Bylaws of Vistra Corp., effective Februarr ryrr 23, 2022 Instruments Defining the Rights of Security Holders, Including Indentures 001-38086 Form 8-K (filed on August 23, 2018) 4.1 — Indenturet for 5.500% Senior Note due 2026, dated as of August 22, the 2018, among Vistra Operations Company LLC, as issuer, Subsidiary Guarantors (as defined therein), and Wilmington Trust, National Association, as Trustee 001-38086 Form 8-K (filed on August 23, 2018) 001-38086 Form 8-K (filed on August 23, 2018) 001-38086 Form 10-Q (Quarter ended September 30, 2019) (filed on November 5, 2019) 001-38086 Form 10-K (Year ended December 31, 2019) (filed on February 28, 2020) 001-38086 Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020) 001-38086 Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020) 001-38086 Form 10-K (Year ended December 31, 2020) (filed on February 26, 2021) 001-38086 Form 10-K (Year ended December 31, 2020) (filed on February 26, 2021) 001-38086 Form 10-Q (Quarter ended September 30, 2021) (filed on November 5, 2021) 4.2 — Form of Rule 144A Global Security for 5.500% Senior Note due 2026 (included in Exhibit 4.1) 4.3 — Form of Regulation S Global Security for 5.500% Senior Note due 2026 (included in Exhibit 4.1) 4.5 — First Supplemental Indenturet for the 5.500% Senior Notes due 2026, dated August 30, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee 4.36 — Second Supplemental Indenturet 2026, dated October 25, 2019, Subsidiaries, Trustee the Company, for the 5.500% Senior Notes dued among the Guaranteeing the Subsidiary Guarantors and the 4.5 4.6 4.8 4.9 4.3 — Third Supplemental Indenturet 2026, dated January 31, 2020, Subsidiaries, Trustee the Company, for the 5.500% Senior Notes due among the Guaranteeing the Subsidiary Guarantors and the — Fourth Supplemental Indenturet for the 5.500% Senior Notes dued 2026, dated March 26, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee — Fifth Supplemental Indenturet for the 5.500% Senior Notes due 2026, dated October 7, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee — Sixth Supplemental Indenturet for the 5.500% Senior Notes due 2026, dated January 8, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee — Seventh Supplemental Indenturet for the 5.500% Senior Notes dued 2026, dated July 29, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee — Eighth Supplemental Indenturet for the 5.500% Senior Notes due 2026, dated December 28, 2021, among the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee the Company, 4.11 ** 4.12 4.13 001-38086 Form 8-K (filed on February 6, 2019) 4.1 — Indenturet for 5.625% Senior Note due 2027, dated as of February 6, 2019, among Vistra Operations Company LLC, as issuer, the Subsidiary Guarantors (as defined therein), and Wilmington Trust, National Association, as Trustee rr 001-38086 Form 8-K (filed on February 6, 2019) 4.2 — Form of Rule 144A Global Security for 5.625% Senior Note due 2027 (included in Exhibit 4.1) 171 Exhibits 4.14 4.15 4.16 4.17 4.18 4.19 4.20 4.21 Previously Filed With File Number* 001-38086 Form 8-K (filed on February 6, 2019) 001-38086 Form 10-Q (Quarter ended September 30, 2019) (filed on November 5, 2019) 001-38086 Form 10-K (Year ended December 31, 2019) (filed on February 28, 2020) 001-38086 Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020) 001-38086 Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020) 001-38086 Form 10-K (Year ended December 31, 2020) (filed on February 26, 2021) 001-38086 Form 10-K (Year ended December 31, 2020) (filed on February 26, 2021) 001-38086 Form 10-Q (Quarter ended September 30, 2021) (filed on November 5, 2021) 4.22 ** As Exhibit 4.3 4.6 — Form of Regulation S Global Security for 5.625% Senior Note due 2027 (included in Exhibit 4.1) — First Supplemental Indenturet for the 5.625% Senior Notes due 2027, dated August 30, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee 4.41 — Second Supplemental Indenturet 2027, dated October 25, 2019, Subsidiaries, Trustee the Company, for the 5.625% Senior Notes dued among the Guaranteeing the Subsidiary Guarantors and the 4.7 4.8 — Third Supplemental Indenturet 2027, dated January 31, 2020, Subsidiaries, Trustee the Company, for the 5.625% Senior Notes due among the Guaranteeing the Subsidiary Guarantors and the — Fourth Supplemental Indenturet for the 5.625% Senior Notes dued 2027, dated March 26, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee 4.17 — Fifth Supplemental Indenturet for the 5.625% Senior Notes due 2027, dated October 7, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee 4.18 — Sixth Supplemental Indenturet for the 5.625% Senior Notes due 2027, dated January 8, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee 4.4 — Seventh Supplemental Indenturet for the 5.625% Senior Notes dued 2027, dated July 29, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee — Eighth Supplemental Indenturet for the 5.625% Senior Notes due 2027, dated December 28, 2021, among the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee the Company, 4.23 4.24 4.25 4.26 4.27 001-38086 Form 8-K (filed on June 24, 2019) 4.1 — Indenturet for 5.00% Senior Notes dued 2027, dated as of June 21, 2019, among Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors (as defined therein), and Wilmington Trust, National Association, as Trustee 001-38086 Form 8-K (filed on June 24, 2019) 001-38086 Form 8-K (filed on June 24, 2019) 001-38086 Form 10-Q (Quarter ended September 30, 2019) (filed on November 5, 2019) 001-38086 Form 10-K (Year ended December 31, 2019) (filed on February 28, 2020) 4.2 — Form of Rule 144A Global Security for 5.00% Senior Notes due 2027 (included in Exhibit 4.1) 4.3 — Form of Regulation S Global Security for 5.00% Senior Notes due 2027 (included in Exhibit 4.1) 4.7 — First Supplemental Indenturet for the 5.000% Senior Notes due 2027, dated August 30, 2019, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee 4.46 — Second Supplemental Indenturet 2027, dated October 25, 2019, Subsidiaries, Trustee the Company, for the 5.000% Senior Notes dued among the Guaranteeing the Subsidiary Guarantors and the 172 Exhibits 4.28 4.29 4.30 4.31 4.32 Previously Filed With File Number* 001-38086 Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020) 001-38086 Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020) 001-38086 Form 10-K (Year ended December 31, 2020) (filed on February 26, 2021) 001-38086 Form 10-K (Year ended December 31, 2020) (filed on February 26, 2021) 001-38086 Form 10-Q (Quarter ended September 30, 2021) (filed on November 5, 2021) 4.33 ** As Exhibit 4.9 — Third Supplemental Indenturet 2027, dated January 31, 2020, Subsidiaries, Trustee the Company, for the 5.000% Senior Notes due among the Guaranteeing the Subsidiary Guarantors and the 4.10 — Fourth Supplemental Indenturet for the 5.000% Senior Notes dued 2027, dated March 26, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee 4.26 — Fifth Supplemental Indenturet for the 5.000% Senior Notes due 2027, dated October 7, 2020, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee 4.27 — Sixth Supplemental Indenturet for the 5.000% Senior Notes due 2027, dated January 8, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee 4.5 — Seventh Supplemental Indenturet for the 5.000% Senior Notes dued 2027, dated July 29, 2021, among the Guaranteeing Subsidiaries, the Company, the Subsidiary Guarantors and the Trustee — Eighth Supplemental Indenturet for the 5.000% Senior Notes due 2027, dated December 28, 2021, among the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee the Company, 4.34 4.35 4.36 4.37 4.38 4.39 4.40 4.41 001-38086 Form 8-K (filed on June 17, 2019) 001-38086 Form 8-K (filed on June 17, 2019) 001-38086 Form 8-K (filed on June 17, 2019) 001-38086 Form 8-K (filed on June 17, 2019) 001-38086 Form 8-K (filed on June 17, 2019) 001-38086 Form 8-K (filed on June 17, 2019) 4.1 — Indenture, t dated as of June 11, 2019, between Vistra Operations Issuer, and Wilmington Trust, National Company LLC, as Association, as Trustee 4.2 — Supplemental Indenturet for 3.55% Senior Secured Notes due 2024 and 4.30% Senior Secured Notes Due 2029, dated as of June 11, 2019, among Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors (as defined therein), and Wilmington Trust, National Association, as Trustee 4.3 — Form of Rule 144A Global Security for 3.55% Senior Notes due 2024 (included in Exhibit 4.2) 4.4 — Form of Rule 144A Global Security for 4.30% Senior Notes due 2029 (included in Exhibit 4.2) 4.5 — Form of Regulation S Global Security for 3.55% Senior Notes due 2024 (included in Exhibit 4.2) 4.6 — Form of Regulation S Global Security for 4.30% Senior Notes due 2029 (included in Exhibit 4.2) 001-38086 Form 10-Q (Quarter ended September 30, 2019) (filed on November 5, 2019) 001-38086 Form 8-K (filed on November 21, 2019) 4.8 4.1 — Second Supplemental Indenturet for 3.55% Senior Secured Notes 2029, dated as of due 2024 and 4.30% Senior Secured Notes dued August 30, 2019, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee — Third Supplemental Indenturet for 3.55% Senior Secured Notes dued 2024 and 4.30% Senior Secured Notes dued 2029, dated as of October 25, 2019, among Vistra Operations Company LLC, as Issuer, the Guaranteeing Subsidiaries, Subsidiary Guarantors and the Trustee 173 Exhibits 4.42 Previously Filed With File Number* 001-38086 Form 8-K (filed on November 21, 2019) As Exhibit 4.2 — Fourth Supplemental Indenture, dated as of November 15, 2019, among Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors (as defined therein), and Wilmington Trust, National Association, as Trustee t 4.43 4.44 4.45 4.46 4.47 4.48 4.49 001-38086 Form 8-K (filed on November 21, 2019) 001-38086 Form 8-K (filed on November 21, 2019) 001-38086 Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020) 001-38086 Form 10-Q (Quarter ended March 31, 2020) (filed on May 5, 2020) 001-38086 Form 10-K (Year ended December 31, 2020) (filed on February 26, 2021) 001-38086 Form 10-K (Year ended December 31, 2020) (filed on February 26, 2021) 001-38086 Form 10-Q (Quarter ended September 30, 2021) (filed on November 5, 2021) 4.50 ** 001-38086 Form 8-K (filed on May 11, 2021) 001-38086 Form 8-K (filed on May 11, 2021) 001-38086 Form 8-K (filed on May 11, 2021) 4.51 4.52 4.53 4.54 4.3 — Form of Rule 144A Global Security for 3.70% Senior Note due 2027 (included in Exhibit 4.2) 4.4 — Form of Regulation S Global Security for 3.70% Senior Note due 2027 (included in Exhibit 4.2) 4.11 — Fifth Supplemental Indenturet 2024, 3.70% Senior Secured Notes dued Secured Notes dued Vistra Operations Company LLC, as Issuer, Subsidiaries, the Subsidiary Guarantors and the Trustee for 3.55% Senior Secured Notes dued 2027 and 4.30% Senior 2029, dated as of January 31, 2020, among the Guaranteeing 4.12 — Sixth Supplemental Indenturet for 3.55% Senior Secured Notes dued 2024, 3.70% Senior Secured Notes dued 2027 and 4.30% Senior Secured Notes due 2029, dated as of March 26, 2020, among Vistra Operations Company LLC, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee Issuer, as 4.41 — Seventh Supplemental Indenturet for 3.55% Senior Secured Notes due 2024, 3.70% Senior Secured Notes due 2027 and 4.30% Senior 2029, dated as of October 7, 2020, among Vistra Secured Notes dued Operations Company LLC, the Guaranteeing Issuer, Subsidiaries, the Subsidiary Guarantors and the Trustee as 4.42 — Eighth Supplemental Indenturet for 3.55% Senior Secured Notes due 2024, 3.70% Senior Secured Notes due 2027 and 4.30% Senior Secured Notes due 2029, dated as of January 8, 2021, among Vistra Operations Company LLC, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee Issuer, as 4.6 4.1 — Ninth Supplemental Indenturet for 3.55% Senior Secured Notes due 2024, 3.70% Senior Secured Notes dued 2027 and 4.30% Senior Secured Notes due 2029, dated as of July 29, 2021, among Vistra Operations Company LLC, the Guaranteeing Subsidiaries, the Subsidiary Guarantors and the Trustee Issuer, as — Tenth Supplemental Indenturet 2024, 3.70% Senior Secured Notes dued Secured Notes dued Vistra Operations Company LLC, as Issuer, Subsidiaries, the Subsidiary Guarantors and the Trustee for 3.55% Senior Secured Notes due 2027 and 4.30% Senior 2029, dated as of December 28, 2021, among the Guaranteeing — Indenturet for 4.375% Senior Notes due 2029, dated as of May 10, 2021, between Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors, Trust, National Association, as Trustee and Wilmington 4.2 — Form of Rule 144A Global Security for 4.375% Senior Notes dued 2029 (included in Exhibit 4.1) 4.3 — Form of Regulation S Global Security for 4.375% Senior Notes due 2029 (included in Exhibit 4.1) 001-38086 Form 10-Q (Quarter ended September 30, 2021) (filed on November 5, 2021) 4.7 — First Supplemental Indenturet for the 4.375% Senior Notes due 2029, dated July 29, 2021, among Vistra Operations Company LLC, as Issuer, the Subsidiary the Guaranteeing Subsidiaries, Guarantors and the Trustee 174 Previously Filed With File Number* As Exhibit Exhibits 4.55 ** — Second Supplemental Indenturet for the 4.375% Senior Notes dued 2029, dated December 28, 2021, among Vistra Operations Company LLC, as Issuer, the Subsidiary Guarantors and the Trustee the Guaranteeing Subsidiaries, 4.56 4.57 4.58 4.59 4.60 4.61 4.62 4.63 4.64 4.65 001-38086 Form 8-K (filed on August 23, 2018) 001-38086 Form 8-K (filed on August 23, 2018) 001-38086 Form 8-K (filed on April 5, 2019) 4.7 4.8 4.1 — Purchase and Sale Agreement dated as of August 21, 2018, between TXU Energy Retail Company LLC as originator, and TXU Energy Receivablea s Company LLC, as purchaser — Receivablea Purchase Agreement dated as of August 21, 2018, among TXU Energy Receivablea s Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as perforff mance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator — First Amendment to Purchase and Sale Agreement, dated as of April 1, 2019, among TXU Energy Retail Company LLC, Dynegy Energy Services, LLC, and Dynegy Energy Services (East), LLC, each as an originator, and TXU Energy Receivablea s Company LLC, as purchaser 001-38086 Form 10-Q (Quarter ended June 30, 2019) (filed on August 2, 2019) 4.12 — Second Amendment to Purchase and Sale Agreement, dated as of June 3, 2019, among TXU Energy Retail Company LLC, Dynegy Energy Services, LLC, and Dynegy Energy Services (East), LLC, each as an originator, and TXU Energy Receivablea s Company LLC, as purchaser 001-38086 Form 8-K (filed on July 19, 2019) 001-38086 Form 8-K (filed on October 16, 2020) 001-38086 Form 8-K (filed on December 28, 2020) 001-38086 Form 8-K (filed on April 5, 2019) 4.1 4.1 4.1 4.2 — Third Amendment to Purchase and Sale Agreement, dated as of July 15, 2019, among TXU Energy Retail Company LLC, Dynegy Energy Services, LLC, and Dynegy Energy Services (East), LLC, s Company LLC, each as an originator, and TXU Energy Receivablea as purchaser — Fourth Amendment to Purchase and Sale Agreement, dated as of October 9, 2020, among TXU Energy Retail Company LLC, as an originator and servicer, the other originators named therein, and TXU Energy Receivables Company LLC, as purchaser — Fifth Amendment to Purchase and Sale Agreement, dated as of December 21, 2020, among TXU Energy Retail Company LLC, certain originators named therein, and TXU Energy Receivablea s Company LLC, as purchaser — First Amendment to Receivablea s Purchase Agreement, dated as of April 1, 2019, among TXU Energy Receivablea s Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as perforff mance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator 001-38086 Form 10-Q (Quarter ended June 30, 2019) (filed on August 2, 2019) 4.13 — Second Amendment to Receivablea s Purchase Agreement, dated as s Company LLC, of June 3, 2019, among TXU Energy Receivablea as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as perforff mance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator 001-38086 Form 8-K (filed on July 19, 2019) 4.2 — Third Amendment to Receivablea s Purchase Agreement, dated as of July 15, 2019, among TXU Energy Receivablea s Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as perforff mance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator 175 Exhibits 4.66 Previously Filed With File Number* 001-38086 Form 8-K (filed on July 16, 2020) As Exhibit 4.1 — Fifth Amendment to Receivablea s Purchase Agreement, dated as of s Company LLC, as July 13, 2020, among TXU Energy Receivablea seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as perforff mance guarantor, certain purchaser agents and purchasers named therein and Credit Agricole Corporate and Investment Bank, as administrator — Sixth Amendment to Receivablea s Purchase Agreement, dated as of October 9, 2020, among TXU Energy Receivablea s Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as perforff mance guarantor, certain purchaser agents and purchasers named therein, and Credit Agricole Corporate and Investment Bank, as administrator — Seventh Amendment to Receivablea s Purchase Agreement, dated as of December 21, 2020, among TXU Energy Receivablea s Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as perforff mance guarantor, certain purchaser agents and purchasers named therein, and Credit Agricole Corporate and Investment Bank, as administrator 4.2 4.2 4.56 — Eighth Amendment to Receivablea s Purchase Agreement, dated as of February 19, 2020, among TXU Energy Receivablea s Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as perforff mance guarantor, certain purchaser agents and purchasers named therein, and Credit Agricole Corporate and Investment Bank, as administrator 4.6 4.1 4.2 4.1 — Ninth Amendment to Receivablea s Purchase Agreement, dated as of March 26, 2021, among TXU Energy Receivablea s Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as perforff mance guarantor, certain purchaser agents and purchasers named therein, and Credit Agricole Corporate and Investment Bank, as administrator — Tenth Amendment to Receivablea s Purchase Agreement, dated as of s Company LLC, as July 9, 2021, among TXU Energy Receivablea seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as perforff mance guarantor, certain purchaser agents and purchasers named therein, and Credit Agricole Corporate and Investment Bank, as administrator — Eleventh Amendment to Receivablea s Purchase Agreement, dated as of July 16, 2021, among TXU Energy Receivablea s Company LLC, as seller, TXU Energy Retail Company LLC, as servicer, Vistra Operations Company LLC, as perforff mance guarantor, certain purchaser agents and purchasers named therein, and Credit Agricole Corporate and Investment Bank, as administrator — Warrant Agreement, dated February 2, 2017, by and among r Dynegy, Computershare Inc. and Computershare Trust Company, N.A., as warrant agent 4.2 — Supplemental Warrant Agreement, dated as of April 9, 2018 among the Company and the Warrant Agent 4.1 — Form of Warrant 001-38086 Form 8-K (filed on October 16, 2020) 001-38086 Form 8-K (filed on December 28, 2020) 001-38086 Form 10-K (Year ended December 31, 2020) (filed on February 26, 2021) 001-38086 Form 10-Q (Quarter ended March 31, 2021) (filed on May 4, 2021) 001-38086 Form 8-K (filed on July 15, 2021) 001-38086 Form 10-Q (Quarter ended September 30, 2021) (filed on November 5, 2021) 001-33443 Form of 8-K (filed on February 7, 2017) 001-38086 Registration Statement on Form 8-A (filed on April 9, 2018) 001-33443 Form of 8-K (filed on February 7, 2017) 333-215288 Form S-1 (fileff d December 23, 2016) 4.1 ** Material Contracts — Registration Rights Agreement, by and among TCEH Corp.rr (now ) and the Holders party thereto, dated as of known as Vistra Corp.rr October 3, 2016 — Description of Capia tal Stock 176 4.67 4.68 4.69 4.70 4.71 4.72 4.73 4.74 4.75 4.76 4.77 (10) Exhibits Previously Filed With File Number* As Exhibit Management Contracts; Compensatory Plans, Contracts and Arrangements 10.1 10.2 10.3 10.4 10.5 10.6 10.7 10.8 10.9 10.10 10.11 10.12 10.13 333-215288 Amendment No. 2 to Form S-1 (filed April 5, 2017) 333-215288 Amendment No. 2 to Form S-1 (filed April 5, 2017) 333-215288 Amendment No. 2 to Form S-1 (filed April 5, 2017) 001-33443 Form10-K (Year ended December 31, 2017) (filed on February 26, 2018) 001-38086 Form 10-K (Year ended December 31, 2020) (filed on February 26, 2021) 001-38086 Form 10-K (Year ended December 31, 2020) (filed on February 26, 2021) 001-38086 Form 10-K (Year ended December 31, 2020) (filed on February 26, 2021) 001-38086 Form 10-K (Year ended December 31, 2020) (filed on February 26, 2021) 333-215288 Amendment No. 2 to Form S-1 (filed April 5, 2017) 001-38086 Form 8-K (filed on May 23, 2019) 001-33443 Form10-K (Year ended December 31, 2018) (filed on February 28, 2019) 001-38086 Form 10-K (Year ended December 31, 2020) (filed on February 26, 2021) 001-38086 Form 8-K (filed May 4, 2018) 10.6 — 2016 Omnibus Incentive Plan 10.7 — Form of Option Award Agreement (Management) Omnibus Incentive Plan (pre-2021 awards) for 2016 10.8 — Form of Restricted Stock Unit Award Agreement (Management) for 2016 Omnibus Incentive Plan (pre-2021 awards) 10(d) — Form of Performance Stock Unit Award Agreement for 2016 Omnibus Incentive Plan (pre-2021 awards) 10.5 — Form of Option Award Agreement Omnibus Incentive Plan (Management) for 2016 10.6 — Form of Restricted Stock Unit Award Agreement (Management) for 2016 Omnibus Incentive Plan 10.7 — Form of Restricted Stock Unit Award Agreement (Director) for 2016 Omnibus Incentive Plan 10.8 — Form of Performance Stock Unit Award Agreement for 2016 Omnibus Incentive Plan 10.9 — Vistra Corp. Executive Annual Incentive Plan 10.1 — Amended and Restated 2016 Omnibus Incentive Plan, effective as of May 20, 2019 10.7 — Vistra Equity Deferred Compensation Plan forff Certain Directors, effective as of January 1, 2019 10.13 — Amendment No. 1 to the Vistra Equity Deferre ff d Compensation Plan, dated effecff tive as of February rr 24, 2021 10.1 — Amended and Restated Employment Agreement, dated as of May 1, 2018, between Curtis A. Morgan and Vistra Energy Corp. (now known as Vistra Corp.) 177 Exhibits 10.14 Previously Filed With File Number* 001-33443 Form 10-Q (Quarter ended March 31, 2019) (filed on May 3, 2019) As Exhibit 10.5 — Amended and Restated Employment Agreement, dated May 1, 2019, between James A. Burke and Vistra Energy Corp. (now known as Vistra Corp.) 10.15 10.16 10.17 10.18 10.19 10.20 333-215288 Amendment No. 2 to Form S-1 (filed April 5, 2017) 333-215288 Amendment No. 2 to Form S-1 (filed April 5, 2017) 10.22 — Employment Agreement between Stephanie Zapata Moore and Vistra Energy Corp. (now known as Vistra Corp.) 10.23 — Employment Agreement between Carrie Lee Kirby and Vistra Energy Corp. (now known as Vistra Corp.) 001-38086 Form 8-K (filed February 27, 2020) 10.2 — Employment Agreement between Scott A. Hudson, Vistra Energy ) and TXU Retail Service Corp. (now known as Vistra Corp.rr Company 001-38086 Form 8-K (filed February 27, 2020) 333-215288 Amendment No. 2 to Form S-1 (filed April 5, 2017) 333-215288 Amendment No. 2 to Form S-1 (filed April 5, 2017) 10.1 — Employment Agreement between Stephen J. Muscato, Vistra ) and Luminant Energy (now known as Vistra Corp.rr Energy Corp.rr Company LLC 10.26 — Form of indemnification agreement with directors 10.29 — Stock Purchase Agreement, dated as of October 25, 2016, by and ) and Curtis A. (now known as Vistra Corp.rr between TCEH Corp.rr Morgan 10.21 Credit Agreements and Related Agreements 333-215288 Form S-1 (fileff d December 23, 2016) 333-215288 Form S-1 (fileff d December 23, 2016) 333-215288 Amendment No. 1 to Form S-1 (filed February 14, 2017) 333-215288 Amendment No. 2 to Form S-1 (filed April 5, 2017) 001-38086 Form 8-K (filed August 17, 2017) 001-38086 Form 8-K (filed December 14, 2017) 10.22 10.23 10.24 10.25 10.26 10.1 — Credit Agreement, dated as of October 3, 2017 10.2 — Amendment to Credit Agreement, dated December 14, 2016, by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto. 10.3 — Second Amendment to Credit Agreement, dated February 1, 2017, by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto. rr 10.4 — Third Amendment to Credit Agreement, dated February 28, 2017, by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto. rr 10.1 — Fourth Amendment to Credit Agreement, dated as of August 17, 2017 (effective August 17, 2017), by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto. 10.1 — Fifth Amendment to Credit Agreement, dated as of December 14, 2017 (effective December 14, 2017), by and among Deutsche Bank AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto. 178 Exhibits 10.27 Previously Filed With File Number* 001-38086 Form 8-K (filed February 22, 2018) 10.28 001-38086 Form 8-K (filed June 15, 2018) 10.29 001-38086 Form 8-K (filed April 4, 2019) 10.30 001-38086 Form 8-K (filed May 29, 2019) 10.31 001-38086 Form 8-K (filed on November 21, 2019) As Exhibit 10.1 — Sixth Amendment to Credit Agreement, dated as of February 20, 0, 2018), by and among Deutsche Bank 2018 (effective Februarr AG New York Branch, Vistra Operations Company LLC, Vistra Intermediate Company LLC and the other Credit Parties and Lenders party thereto. ry 2rr 10.1 — Seventh Amendment to Credit Agreement, dated as of June 14, 2018, by and among Vistra Operations Company LLC, Vistra Intermediate Company LLC, the other Credit Parties party thereto, Credit Suisse and Citibank, N.A. as the 2018 Incremental Term Loan Lenders, the various other Lenders party thereto, Credit Suisse as Successor Administrative Agent and as Successor Collateral Agent, and Delaware Trust Company, as Collateral Trustee. 10.4 — Eighth Amendment to Credit Agreement, dated March 29, 2019, by and among Vistra Operations Company LLC, Vistra Intermediate Company LLC, the other Credit Parties (as defined in the Vistra Operations Credit Agreement) party thereto, Bank of Montreal, Chicago Branch, as new Revolving Loan Lender, Revolving Letter of Credit Issuer and Joint Lead Arranger, the various other Lenders and Letter of Credit Issuers party thereto, and Credit Suisse as Administrative Agent and Collateral Agent 10.1 — Ninth Amendment to Credit Agreement, dated May 29, 2019, by and among Vistra Operations Company LLC, Vistra Intermediate Company LLC, the other Credit Parties (as defined in the Vistra Operations Credit Agreement) party thereto, Sun Trust Bank, as incremental Revolving Loan Lender, and Credit Suisse AG, Cayman Island Branch, as Administrative Agent and Collateral Agent 10.1 — Tenth Amendment to the Credit Agreement, dated November 15, 2019, by and among Vistra Operations Company LLC (as Borrower), Vistra Intermediate Company LLC (as Holdings), the other Credit Parties (as defined in the Credit Agreement) party (as defined in the Credit thereto, Agreement) party thereto, Credit Suisse AG, Cayman Islands Branch (as the 2019 Incremental Term Loan Lender and as Administrative Agent and as Collateral Agent), and the other Lenders party thereto the other Credit Parties 10.32 10.33 10.34 10.35 10.36 001-38086 Form 8-K (filed on August 7, 2018) 10.1 — Purchase Agreement, dated August 7, 2018, by and among Vistra Operations Company LLC and Citigroup Global Markets Inc., on behalf of itself and the several Initial Purchasers named in Schedule I to the Purchase Agreement 001-38086 Form 8-K (filed on January 24, 2019) 10.1 — Purchase Agreement, dated January 22, 2019, by and among Vistra Operations Company LLC and J.P. Morgan Securities LLC. On behalf of itself and the several Initial Purchasers named in Schedule I to the Purchase Agreement 001-38086 Form 8-K (filed on June 7, 2019) 001-38086 Form 8-K (filed on June 7, 2019) 001-38086 Form 8-K (filed on November 13, 2019) 10.1 — Purchase Agreement, dated June 4, 2019, by and among Vistra Operations Company LLC and Citigroup Global Markets Inc., on behalf of itself and the several Initial Purchasers named in Schedule I to the Purchase Agreement 10.2 — Purchase Agreement, dated June 6, 2019, by and among Vistra Operations Company LLC and Goldman Sachs & Co. LLC, on and behalf of itself and the several Initial Purchasers named in Schedule I to the Purchase Agreement 10.1 — Purchase Agreement, dated November 6, 2019, by and among Vistra Operations Company LLC and J.P. Morgan Securities LLC, on behalf of itself and the several Initial Purchases named in Schedule I to the Purchase Agreement 179 Exhibits 10.37 Previously Filed With File Number* 001-38086 Form 8-K (filed on May 11, 2021) 10.38 10.39 10.40 10.41 10.42 10.43 10.44 10.45 10.46 001-38086 Form 8-K (filed on October 15, 2021) 001-38086 Form 8-K (filed on December 13, 2021) 001-38086 Form 8-K (filed on April 2, 2021) 001-38086 Form 8-K (filed on April 2, 2021) 001-38086 Form 8-K (filed on April 9, 2018) 001-38086 Form 8-K (filed on April 9, 2018) 001-38086 Form 8-K (filed on April 9, 2018) 001-38086 Form 8-K (filed on April 9, 2018) Other Material Contracts 333-215288 Amendment No. 2 to Form S-1 (filed April 5, 2017) 10.47 001-38086 Form 8-K (filed on June 15, 2018) As Exhibit 10.1 — Purchase Agreement, dated May 5, 2021, by and among Vistra Operations Company LLC and J.P. Morgan Securities LLC. On behalf of itself and the several Initial Purchasers named in Schedule I to the Purchase Agreement 10.1 — Purchase Agreement, dated October 12, 2021, by and between Vistra Corp. and Goldman Sachs & Co. LLC 10.1 — Purchase Agreement, dated December 7, 2021, by and between Vistra Corp. and Goldman Sachs & Co. LLC 10.1 — Credit Agreement, dated as of March 29, 2021, among Vistra Operations Company LLC (as Borrower), Vistra Intermediate Company LLC (as Holdings), Royal Bank of Canada (as Administrative Agent and as Collateral Agent), and the 2021 Incremental Term Loan Lender (as definff ed therein) 10.2 — First Amendment to Credit Agreement, dated as of April 1, 2021, among Vistra Operations Company LLC (as Borrower), Vistra Intermediate Company LLC (as Holdings), Royal Bank of Canada (as Administrative Agent and as Collateral Agent), and the 2021 Incremental Term Loan Lender (as definff ed therein) 10.10 — Assumption Agreement, dated as of April 9, 2018, between Vistra ) (as successor by merger Energy Corp. (now known as Vistra Corp.rr to Dynegy Inc.), and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent and as Collateral Trustee. 10.11 — Guarantee and Collateral Agreement, dated as of April 23, 2013, among Dynegy Inc., the subsidiaries of the borrower fromff time to time party thereto and Credit Suisse AG, Cayman Islands Branch, as Collateral Trustee (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on April 24, 2013). 10.12 — Joinder, dated as of April 9, 2018, among Vistra Energy Corp. (now ), the subsidiary guarantors party thereto and known as Vistra Corp.rr Credit Suisse AG, Cayman Islands Branch, as Collateral Trustee. 10.13 — Collateral Trust and Intercreditor Agreement, dated as of April 23, 2013 among Dynegy, the Subsidiary Guarantors (as defined therein), Credit Suisse AG, Cayman Islands Branch and each person party thereto fromff rated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on April 24, 2013). time to time (incorpor 10.5 — Collateral Trust Agreement, dated as of October 3, 2016, by and among TEX Operations Company LLC (now known as Vistra Operations LLC), the Grantors from time to time thereto, Railroad Commission of Texas, as firff st-out representative, and Deutsche Bank AG, New York Branch, as senior credit agreement representative 10.2 — Amendment to Collateral Trust Agreement, effective as of June 14, 2018, among Vistra Operations Company LLC, the other Grantors from time to time party thereto, Railroad Commission of Texas, as first-out representative, and Credit Suisse AG, Cayman Islands Branch, as senior credit agreement agent, and Delaware Trust Company, as Collateral Trustee 180 Exhibits 10.48 Previously Filed With File Number* 001-38086 Form 8-K (filed on June 15, 2018) As Exhibit 10.3 — Collateral Trust Joinder, dated June 14, 2018, between the Additional Grantors party thereto and Delaware Trust Company, as Collateral Trustee, to the Collateral Trust Agreement, effective pursuant to the Seventh Amendment as of June 14, 2018, among Vistra Operations Company LLC, the other Grantors from time to time party thereto, Railroad Commission of Texas, as First-Out Representative, Credit Suisse AG, Cayman Islands Branch, as Senior Credit Agreement Agent, and Delaware Trust Company, as Collateral Trustee. 10.49 10.50 10.51 10.52 10.53 10.54 10.55 10.56 10.57 10.58 10.59 333-215288 Amendment No. 2 to Form S-1 (filed April 5, 2017) 333-215288 Amendment No. 2 to Form S-1 (filed April 5, 2017) 333-215288 Amendment No. 2 to Form S-1 (filed April 5, 2017) 333-215288 Amendment No. 2 to Form S-1 (filed April 5, 2017) 333-215288 Amendment No. 2 to Form S-1 (filed April 5, 2017) 333-215288 Amendment No. 2 to Form S-1 (filed April 5, 2017) 001-38086 Form 8-K (filed July 7, 2017) 10.13 — Tax Receivablea (now known as Vistra Corp.rr Company, as transfer agent, dated as of October 3, 2016 Agreement, by and between TEX Energy LLC ) and American Stock Transfer & Trust 10.14 — Tax Matters Agreement, by and among TEX Energy LLC (now ), EFH Corp., Energy Future Intermediate known as Vistra Corp.rr Holding Company LLC, EFI Finance Inc. and EFH Merger Co. LLC, dated as of October 3, 2016 10.15 — Transition Services Agreement, by and between Energy Future Holdings Corp. and TEX Operations Company LLC (now known as Vistra Operations Company LLC), dated as of October 3, 2016 10.16 — Separation Agreement, by and between Energy Future Holdings ) and TEX Corp., TEX Energy LLC (now known as Vistra Corp.rr Operations Company LLC (now known as Vistra Operations LLC), dated as of October 3, 2016 10.17 — Purchase and Sale Agreement, dated as of November 25, 2015, by and between La Frontera Ventures, LLC and Luminant Holding Company LLC 10.18 — Amended and Restated Split Participant Agreement, by and between Oncor Electric Delivery Company LLC (f/k/a TXU Electric Delivery Company) and TEX Operations Company LLC (now known as Vistra Operations Company LLC), dated as of October 3, 2016 10(a) — Asset Purchase Agreement, dated as of July 5, 2017, by and among Odessa-Ector Power Partners, L.P., La Frontera Holdings, LLC, Vistra Operations Company LLC, Koch Resources, LLC 001-38086 Form 8-K (filed on October 16, 2020) 10.1 — Master Framework Agreement, dated as of October 9, 2020, by and among TXU Energy Retail Company LLC, as seller and seller party agent, certain originators named therein, and MUFG Bank, Ltd., as buyer 001-38086 Form 8-K (filed on July 15, 2021) 001-38086 Form 10-Q (Quarter ended September 30, 2021) (filed on November 5, 2021) 001-38086 Form 8-K (filed on October 16, 2020) 10.1 — Amendment No. 1 to Master Framework Agreement, dated as of July 1, 2021, by and among TXU Energy Retail Company LLC, as seller and seller party agent, certain originators named therein, Vistra Operations Company LLC, as guarantor, and MUFG Bank, Ltd., as buyer 10.2 — Amendment No. 2 to Master Framework Agreement, dated as of August 3, 2021, by and among TXU Energy Retail Company LLC, as seller and seller party agent, certain originators named therein, Vistra Operations Company LLC, as guarantor, and MUFG Bank, Ltd., as buyer 10.2 — Master Repurchase Agreement, dated as of October 9, 2020, between TXU Energy Retail Company LLC and MUFG Bank, Ltd. 181 Exhibits 10.60 10.61 Previously Filed With File Number* 001-38086 Form 10-Q (Quarter ended September 30, 2021) (filed on November 5, 2021) As Exhibit 10.3 — Amendment No. 1 to Master Repurchase Agreement, dated as of August 3, 2021, between TXU Energy Retail Company LLC and MUFG Bank, Ltd. 001-38086 Form 8-K (filed on December 28, 2020) 10.1 — Joinder Agreement, dated as of December 21, 2020, among TXU seller party agent, Vistra Energy Retail company LLC, as Operations Company LLC, as guarantor, certain originators named therein, and MUFG Bank, Ltd., as buyer 10.62 ** 10.63 ** — Amendment No. 2 to Master Repurchase Agreement, dated as of December 30, 2021, between TXU Energy Retail Company LLC and MUFG Bank, Ltd. — Credit Agreement, dated as of February 4, 2022, among Vistra Operations Company LLC, as Borrower, Vistra Intermediate Company LLC, as Holdings, Citibank, N.A., as Administrative Agent and as Collateral Agent, and the other lenders party thereto. r Subsidiaries of the Registrant ** Consent of Experts ** — Significant Subsidiaries of Vistra Corp. — Consent of Deloitte & Touche LLP Rule 13a-14(a) / 15d-14(a) Certifications (21) 21.1 (23) 23.1 (31) 31.1 31.2 (32) 32.1 ** ** Section 1350 Certifications *** 32.2 *** (95) 95.1 Mine Safety Disclosures ** XBRL Data Files 101.INS ** 101.SCH ** 101.CAL ** 101.DEF ** 101.LAB ** 101.PRE ** — Certification of Curtis A. Morgan, principal executive officer of Vistra Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 — Certification of James A. Burke, principal finaff ncial officer of Vistra Corp., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 — Certification of Curtis A. Morgan, principal executive officer of Vistra Corp., pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 — Certification of James A. Burke, principal finaff ncial officer of Vistra Corp., pursuant to U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 — Mine Safety Dt isclosures — The following financial information from Vistra Corp.'s Annual Report on Form 10-K for the period ended December 31, 2021 formatted in Inline XBRL (Extensible Business Reporting Language) includes: (i) the Consolidated Statements of Operations, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) the Consolidated Statement of Changes in Equity and (vi) the Notes to the Consolidated Financial Statements. — XBRL Taxonomy Extension Schema Document — XBRL Taxonomy Extension Calculation Linkbase Document — XBRL Taxonomy Extension Definition Linkbase Document — XBRL Taxonomy Extension Labea l Linkbase Document — XBRL Taxonomy Extension Presentation Linkbase Document 182 — The Cover Page Interactive Data File does not appear in Exhibit 104 because its XBRL tags are embedded within the Inline XBRL document. Previously Filed With File Number* As Exhibit Exhibits 104 ____________________ * ** *** Incorporated herein by reference Filed herewith Furnished herewith Item 16. FORM 10-K SUMMARY None. 183 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Vistra Corp. has duly caused this report to be signed on its behalf by the undersigned, thereunto dulyd authorized. SIGNATURES Date: February 2rr 5, 2022 VISTRA CORP. By /s/ CURTIS A. MORGAN Curtis A. Morgan (Chief Executive Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following cities and on the date indicated. persons on behalf of Vistra Corp. and in the capaa Signature Title Date /s/ CURTIS A. MORGAN (Curtis A. Morgan, Chief Executive Officer) ff /s/ JAMES A. BURKE (James A. Burke, President and Chief Financial Officer) /s/ CHRISTY DOBRY (Christy Dobry, Senior Vice President and Controller) /s/ SCOTT B. HELM (Scott B. Helm, Chairman of the Board) /s/ HILARY E. ACKERMANN (Hilary E. Ackermann) Principal Executive Officer and Director February 25, 2022 Principal Financial Officer February 25, 2022 Principal Accounting Officer February 2rr 5, 2022 Chairman of the Board and Director February 25, 2022 Director February 25, 2022 /s/ ARCILIA C. ACOSTA (Arcilia C. Acosta) /s/ GAVIN R. BAIERARR (Gavin R. Baiera) /s/ PAUL M. BARBAS (Paul M. Barbas) /s/ LISA CRUTRR CHFIELD (Lisa Crutchfield) /s/ BRIAN K. FERRAIOL I (Brian K. Ferraioli) RR /s/ JEFF D. HUNTER (Jeff Dff . Hunter) /s/ JOHN R. SULT (John R. Sult) Director February 25, 2022 Director February 25, 2022 Director February 25, 2022 Director February 25, 2022 Director February 25, 2022 Director February 25, 2022 Director February 2rr 5, 2022 184 INFORMATION FOR STOCKHOLDERS Stock Exchange Listing NYSE: VST Corporate Headquarters Vistra Corp. 6555 Sierra Drive Irving, Texas 75039 Stock Transfer Agent and Registrar Please direct general questions about stockholder accounts, stock certiﬁcates, transfer of shares, or duplicate mailings to Vistra’s transfer agent: American Stock Transfer & Trust Company, LLC 6201 15th Avenue Brooklyn, NY 11219 Phone: (800) 937-5449 Email: info@amstock.com Board of Directors † Hilary E. Ackermann (4)* Arcilia C. Acosta (2,3) Gavin R. Baiera (2)* Paul M. Barbas (3)* Lisa Crutchﬁeld (3,4) Brian K. Ferraioli (1)* Scott B. Helm, Chairman of the Board of Directors Jeff D. Hunter (1,4) Curtis A. Morgan John R. Sult (1,2) 1 Audit Committee 2 Social Responsibility and Compensation Committee 3 Nominating and Governance Committee 4 Sustainability and Risk Committee Independent Registered Accounting Firm * Committee Chair † As of April 4, 2022. Besides Curtis A. Morgan, all members of the Vistra Board of Directors satisfy the independence requirements of the Securities and Exchange Commission and the NYSE. Deloitte & Touche LLP Officer Certiﬁcations Our Annual Report on Form 10-K ﬁled with the SEC is included herein, excluding all exhibits. We will send stockholders copies of the exhibits to our Annual Report on Form 10-K and any of our corporate governance documents, free of charge, upon request. Note that these documents, along with further information about our company, board of directors, management team and investor relations contact details, are available on our website at www.vistracorp.com. 6555 Sierra Drive, Irving, Texas 75039(cid:5)| www.vistracorp.com

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