What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2023-03-01 compared with 2022-02-25 · 290 added, 276 removed, 578 unchanged (49% of the section changed)

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See Note 19 to the Financial Statements for further information concerning our reportable business segments.

CEO Transition

In March 2022, Vistra announced that the Board had named Jim Burke as its next Chief Executive Officer (CEO), effective August 1, 2022.

Burke, who previously served as President and Chief Financial Officer, also joined the Company's Board upon assuming his new role.

Vistra's previous CEO and director, Curt Morgan, will serve as a special advisor to Mr.

Burke and the Board until April 30, 2023.

The transition from Mr.

Morgan to Mr.

Burke was a product of the Company's formal succession planning process.

In July 2022, the Company announced the appointment of Kris Moldovan as the Company's Executive Vice President and Chief Financial Officer, effective August 1, 2022.

Significant Activities and Events and Items Influencing Future Performance

Winter Storm Uri

In February 2021, the U.S.

experienced an unprecedented Winter Storm Uri, bringing extreme cold temperatures to the central U.S., including Texas.

On February 12, 2021, the Governor of Texas declared a state of disaster for all 254 counties in the State in response to the then-forecasted weather conditions.

The declaration certified that severe winter weather posed an imminent threat due to prolonged freezing temperatures, heavy snow, and freezing rain statewide.

On February 14, 2021, President Biden issued a federal emergency declaration for all 254 Texas counties.

As part of its annual winter season preparations, our power plant teams executed a significant winter preparedness strategy, which included installing windbreaks and large radiant heaters to supplement existing freeze protection and insulation and performing preventative maintenance on freeze protection equipment such as the insulation and automatic circuitry designed to keep pipes at the power plants from freezing.

In addition, in anticipation of Winter Storm Uri we took additional steps to prepare, including procuring additional demineralized water supply trailers to ensure sufficient water availability to run for extended periods and verifying that freeze protection circuits were operational.

This severe weather resulted in surging demand for power, gas supply shortages, operational challenges for generators, and a significant load shed event ( i.e.

, involuntary outages to customers across the system for varying periods of time) that was ordered by ERCOT beginning on February 15, 2021 and continuing through February 18, 2021.

Despite these challenges, we estimate that our fleet generated approximately 25 to 30% of the power on the grid during the height of the outages, as compared to our approximately 18% market share.

The weather event resulted in a $2.2 billion negative impact on the Company's pre-tax earnings in the year ended December 31, 2021 (see Note 1 to the Financial Statements), after taking into account approximately $544 million in securitization proceeds Vistra expects to receive from ERCOT as further described below.

The primary drivers of the loss were the need to procure power in ERCOT at market prices at or near the price cap due to lower output from our natural gas-fueled power plants driven by natural gas deliverability issues and our coal-fueled power plants driven by coal fuel handling challenges, high fuel costs, and high retail load costs.

As part of the 2021 regular Texas legislative sessions and in response to extraordinary costs incurred by electricity market participants during Winter Storm Uri, the Texas legislature passed House Bill (HB) 4492 for ERCOT to obtain financing to distribute to load-serving entities (LSEs) that were charged and paid to ERCOT exceptionally high price adders and ancillary service costs during Winter Storm Uri.

In October 2021, the PUCT issued a debt obligation order approving ERCOT's $2.1 billion financing and the methodology for allocation of proceeds to the LSEs.

In December 2021, ERCOT finalized the amount of allocations to the LSEs, and we expect to receive $544 million in proceeds from ERCOT in the second quarter of 2022.

We concluded that the threshold for recognizing a receivable was met in December 2021 as the amounts to be received are determinable and ERCOT was directed by its governing body, the PUCT, to take all actions required to effectuate the $2.1 billion funding approved in the debt obligation order.

Accordingly, we recognized the $544 million in expected proceeds as an expense reduction in the fourth quarter of 2021 within fuel, purchased power costs and delivery fees in our consolidated statements of operation.

We continue to be subject to the outcome of potential litigation arising from this event (including any litigation that we may pursue or be a party to);

or any corrective action taken by the State of Texas, ERCOT, the RCT, or the PUCT to resettle pricing across any portion of the supply chain that is currently being considered or may be considered by any such parties.

The Texas legislature also continues to consider potential legislation, such as Senate Bill (SB) 1580, which was passed in May 2021.

SB 1580 may impact the total amount of balances owed by electric cooperatives to the market.

The potential impact of this legislation is uncertain as the final details will be specific to each electric cooperative.

There have been several announced efforts by the state and federal governments and regulatory agencies to investigate and determine the causes of this event and its impact on consumers.

We have received a civil investigative demand from the Attorney General of Texas as well as requests for information from ERCOT, NERC and other regulatory bodies related to this event and may receive additional inquiries.

We are cooperating with these entities and have responded to these requests.

Those efforts may result in changes in regulations that impact our industry including but not limited to additional requirements for winterization of various facets of the electricity supply chain including generation, transmission, and fuel supply;

improvements in coordination among the various participants in the electricity and natural gas supply chains during any future event;

potential revisions to the method or calculation of market compensation and incentives relating to the continued operation of assets that only run periodically, including during extreme weather events or other times of scarcity;

and restrictions or limitations on the types of plans permitted to be offered to customers.

We are continuing to monitor this situation as it develops.

The full impact of litigation or any impacts of any legislative or regulatory changes or actions (including enforcement actions that may be brought against various market participants) that may occur as a result of the event could have a material impact on our business, financial condition, results of operations, or cash flows, but cannot be estimated at this time.

See Note 13 to the Financial Statements for further discussion of these matters.

In response to the storm, Vistra committed to donate $5 million to assist Texas communities and individuals meet their most pressing needs, including support for food banks and food pantries, critical needs, bill payment assistance, and more.

Vistra also assured residential customers across its retail brands that they would not see any near-term impact on their rates due to the winter weather event, though bills could increase due to high usage during the cold weather period in February 2021.

Furthermore, Vistra has taken or intends to take various actions to improve its risk profile for future weather-driven volatility events, including investing in improvements to further harden its coal fuel handling capabilities and to further weatherize its ERCOT fleet for even colder temperatures and longer durations;

carrying more backup generation into the peak seasons after accounting for weatherization investments and ERCOT market improvements implemented going forward;

contracting for incremental gas storage to support its gas fleet;

adding additional dual fuel capabilities at its gas steam units and increasing fuel oil inventory at its existing dual fuel sites;

participating in processes with the PUCT and ERCOT for registration of gas infrastructure as critical resources with the transmission and distribution utilities and for enhanced winterization of both gas and power assets in the state;

and engaging in processes to evaluate potential market reforms.

Climate Change, Investments in Clean Energy and CO 2 Reductions

Environmental Regulations — We are subject to extensive environmental regulation by governmental authorities, including the EPA and the environmental regulatory bodies of states in which we operate.

Environmental regulations could have a material impact on our business, such as certain corrective action measures that may be required under the CCR rule and the ELG rule.

Environmental regulations could have a material impact on our business, such as certain corrective action measures that may be required under the CCR rule and the Effluent Limitation Guidelines (ELG) rule.

Business – Environmental Regulations and Related Considerations , and Item 1A.

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In furtherance of Vistra's efforts to meet its net-zero target, Vistra expects to deploy multiple levers to transition the Company to operating with net-zero emissions.

Green Finance Framework — In December 2021, we announced the publication of our Green Finance Framework, which allows us to issue green financial instruments to fund new or existing projects that support renewable energy and energy efficiency with alignment to our ESG initiatives.

See Preferred Stock Offerings below for discussion of the Series B Preferred Securities issued under our Green Finance Framework.

Solar Generation and Energy Storage Projects — In January 2022, we announced that, subject to approval by the CPUC, we would enter into a 15-year resource adequacy contract with PG&E to develop an additional 350 MW battery ESS at our Moss Landing Power Plant site.

In September 2021, we announced the planned development, at a cost of approximately $550 million, of up to 300 MW of solar photovoltaic power generation facilities and up to 150 MW of battery ESS at retired or to-be-retired plant sites in Illinois, based on the passage of Illinois Senate Bill 2408, the Energy Transition Act.

Solar Generation and Energy Storage Projects —

• In September 2020, we announced the planned development, at a cost of approximately $850 million, of up to 668 MW of solar photovoltaic power generation facilities and 260 MW of battery ESS in Texas.

Of this planned development in Texas, 158 MW of solar generation and the 260 MW of battery ESS came online in 2022.

• In September 2021, we announced the planned development, at a cost of approximately $550 million, of up to 300 MW of solar photovoltaic power generation facilities and up to 150 MW of battery ESS at retired or to-be-retired plant sites in Illinois, based on the passage of Illinois Senate Bill 2408, the Energy Transition Act.

• In January 2022, we announced that, subject to approval by the CPUC, we would enter into a 15-year resource adequacy and energy settlement contract with PG&E to develop an additional 350 MW battery ESS at our Moss Landing Power Plant site.

The CPUC approved the resource adequacy and energy settlement contract in April 2022.

We will only invest in these growth projects if we are confident in the expected returns.

See Note 3 to the Financial Statements for a summary of our solar and battery energy storage projects.

See Note 2 to the Financial Statements for a summary of our solar and battery ESS projects.

CO 2 Reductions — In September 2020 and December 2020, we announced our intention to retire (a) all of our remaining coal generation facilities in Illinois and Ohio, (b) one coal generation facility in Texas and (c) one natural gas facility in Illinois no later than year-end 2027 due to economic challenges, including incremental expenditures that would be required to comply with the CCR rule and ELG rule (see Note 12 to the Financial Statements), and in furtherance of our efforts to significantly reduce our carbon footprint.

In 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.

In June 2022, September 2022 and January 2023, we retired the Zimmer coal-fueled generation facility, the Joppa generation facilities and the Edwards coal-fueled generation facility, respectively.

See Note 3 to the Financial Statements for a summary of these planned generation retirements.

Moss Landing Outages

In September 2021, Moss Landing Phase I experienced an incident impacting a portion of the battery ESS.

A review found that only a small, single digit-percentage of batteries at the facility were impacted and that the root cause originated in systems separate from the battery system.

The facility will be offline as we perform the work necessary to return the facility to service.

Moss Landing Phase II was not affected by this incident.

In February 2022, Moss Landing Phase II experienced an incident impacting a portion of the Battery ESS.

An investigation is underway to determine the root cause of the incident.

The facility will be offline as we perform the work necessary to return the facility to service.

Moss Landing Phase I was not affected by the incident, but the facility will remain offline during the assessment stage of the Moss Landing Phase II incident.

We do not expect these incidents to have a material impact on our results of operations.

Mining Reclamation Award

In October 2021, the Office of Surface Mining Reclamation and Enforcement (OSM) announced Luminant as a recipient of its 2021 Excellence in Surface Coal Mining Reclamation Award for the work done to reclaim and restore previously mined land at its Monticello-Winfield Mine.

The award recognizes companies that achieve the most exemplary coal mine reclamation in the nation.

Luminant has a long history of environmental stewardship, reclaiming land long before being required under federal or state law.

COVID-19 Pandemic

With the global outbreak of the novel coronavirus (COVID-19) and the declaration of a pandemic by the World Health Organization on March 11, 2020, the U.S.

government has deemed electricity generation, transmission and distribution as "critical infrastructure" providing essential services during this global emergency.

As a provider of critical infrastructure, Vistra has an obligation to provide critically needed power to homes, businesses, hospitals and other customers.

Vistra remains focused on protecting the health and well-being of its employees and the communities in which it operates while assuring the continuity of its business operations.

We have updated and implemented our company-wide pandemic plan to address specific aspects of the COVID-19 pandemic to guide our emergency response, business continuity, and the precautionary measures we are taking on behalf of employees and the public.

We will continue to monitor developments affecting both our workforce and our customers, and we have taken, and will continue to take, health and safety measures that we determine are necessary in order to mitigate the impacts.

To date, as a result of these business continuity measures, the Company has not experienced material disruptions in our operations due to COVID-19.

See Note 7 to the Financial Statements for a summary of certain tax-related impacts of the CARES Act to the Company.

The COVID-19 pandemic has presented potential new risks to the Company's business.

Although there have been logistical and other challenges to date, there has been no material adverse impact on the Company's results of operations for the years ended December 31, 2021 and 2020.

The situation surrounding COVID-19 remains fluid and the potential for a material impact on the Company's results of operations, financial condition and liquidity increases the longer the virus impacts the level of economic activity in the U.S.

and globally.

As a result, COVID-19 may have a range of impacts on the Company's operations, the full extent and scope of which are currently unknown.

See Part I, Item 1A Risk Factors — The outbreak of COVID-19, or the future outbreak of any other highly infectious or contagious diseases, could have a material and adverse effect on our business, financial condition, and results of operations .

Comanche Peak Nuclear Plant License Renewal

In October 2022, we announced the submission of our application to the NRC for license renewal at our two-unit Comanche Peak Nuclear Plant.

The current licenses for Units 1 and 2 extend into 2030 and 2033, respectively, and we are applying to renew the licenses into 2050 and 2053, respectively.

Inflation Reduction Act of 2022

In August 2022, the U.S.

enacted the Inflation Reduction Act of 2022 (IRA), which, among other things, implements substantial new and modified energy tax credits, including a nuclear production tax credit (PTC), a solar PTC, a first-time stand-alone battery storage investment tax credit, a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases.

Treasury regulations are expected to define the scope of the legislation in many important respects over the next twelve months.

Vistra is not subject to the CAMT in the next fiscal year since it applies only to corporations that have a three-year average annual adjusted financial statement income in excess of $1 billion.

The excise tax is not expected to have a material impact on our financial statements.

As of December 31, 2022, we have taken the CAMT and relevant extensions or expansions of existing tax credits applicable to projects in our immediate development pipeline into account when forecasting cash taxes for periods after the law takes effect and for estimating the TRA liability.

Macroeconomic Conditions

Global market demand, geopolitical events and high natural gas price volatility have resulted in increased market prices for energy and other commodities, and we expect these conditions to persist, in particular in the near term.

Due in large part to the Russia and Ukraine conflict as well as other factors, we have experienced substantial shifts in commodity prices, which in turn have (i) facilitated our comprehensive hedging strategy which we believe has positioned us to lock in significant revenues and Adjusted EBITDA opportunities in 2023 through 2025, (ii) led to significant mark-to-market impacts on forward commodity derivative instruments, and (iii) combined with our comprehensive hedging strategy, resulted in significant increases in our collateral posting obligations and required substantial liquidity to support such obligations.

Additionally, we continue to monitor domestic drivers of gas prices, including the pace of investment and buildout of liquefied natural gas (LNG) export capabilities, which have the potential to more closely align U.S.

natural gas pricing with the further elevated international gas markets over the next couple of years.

See also Financial Condition for further discussion of our collateral posting obligations and liquidity management activities.

We continue to monitor the impacts of energy volatility on the retail and associated default service markets.

As electricity pricing trended higher in 2022, we experienced increased customer migration to the default service provider in territories outside of Texas, where default service rates do not yet fully reflect the higher commodity pricing environment.

Generators (including Vistra) with contracts to serve a percentage of the resultingly higher than planned default service load (previously awarded through the default service auction process) are likely to incur losses on these particular default service contracts, as estimates of the potential migration were lower than the level of migration that was realized and the underlying cost to provide the incremental power rose above the contracted revenue rate.

As a result of this customer migration, we incurred losses in 2022 and anticipate these losses will continue to have a negative impact on our East segment through the end of these default service contracts in mid-2023.

With forward power and natural gas curves increasing materially in 2022, we have increased our hedging for future periods.

As of December 31, 2022, we have hedged approximately 73% of our expected generation volumes on average for the three-year period 2023 to 2025 (with approximately 90% hedged for 2023 and approximately 76% hedged for 2024).

Changes to the geopolitical situation and the inflationary environment, among other factors, have also created supply chain constraints that have reduced the availability and increased the costs of certain fuels, such as coal, reduced the availability of certain equipment and supply relevant to construction of renewables projects, and increased the lead time to procure certain materials necessary to maintain our natural gas, nuclear and coal fleet.

We are proactively managing the increased costs of materials and supply chain disruptions and continuing to prudently re-evaluate the business cases and timing of our planned development projects, which has resulted in a deferral of some of our planned capital spend for our renewables projects from 2022 to 2023 and beyond.

In addition, we have proactively engaged our suppliers to secure key materials needed to maintain our existing generation facilities prior to future planned outages, and our Vistra Zero operational and development projects are anticipated to benefit from the impact of the recently passed IRA.

The inflationary environment has also led to, and is expected to cause further increases in, interest rates, resulting in increased refinancing or borrowing costs, including project financing for our development projects.

Additionally, we have been monitoring, and will continue to closely monitor, developments of the Russia and Ukraine conflict, including sanctions (or potential sanctions) against Russian energy exports and Russian nuclear fuel supply and enrichment activities, as well as actions by Russia to limit energy deliveries, which may further impact commodity prices in Europe and globally.

Our 2022 refueling has not been affected by the Russia and Ukraine conflict.

We work with a diverse set of global nuclear fuel cycle suppliers to procure our nuclear fuel, and therefore, we expect to have enough nuclear fuel to support all our refueling needs through 2025.

We are taking affirmative action by including mitigating strategies in our procurement portfolio to ensure we can secure the nuclear fuel needed to continue to operate our nuclear facility.

If imports from Russia were restricted, U.S.

merchant nuclear power generators could be challenged in their refueling operations in future years.

Winter Storm Uri

In February 2021, a severe winter storm with extremely cold temperatures affected much of the U.S., including Texas.

This severe weather resulted in surging demand for power, gas supply shortages, operational challenges for generators, and a significant load shed event that was ordered by ERCOT beginning on February 15, 2021 and continuing through February 18, 2021.

Winter Storm Uri had a material adverse impact on our results of operations and operating cash flows.

The weather event resulted in a $2.2 billion negative impact on the Company's pre-tax earnings in the year ended December 31, 2021 after taking into account approximately $544 million in securitization proceeds Vistra received from ERCOT as further described below.

In October 2021, the PUCT issued a debt obligation order approving ERCOT's $2.1 billion financing and the methodology for allocation of proceeds to the LSEs.

In December 2021, ERCOT finalized the amount of allocations to the LSEs, and we received $544 million in proceeds from ERCOT in the second quarter of 2022.

We concluded that the threshold for recognizing a receivable was met in December 2021 as the amounts to be received were determinable and ERCOT was directed by its governing body, the PUCT, to take all actions required to effectuate the $2.1 billion funding approved in the debt obligation order.

The final financial impact of Winter Storm Uri continues to be subject to the outcome of litigation arising from the event.

Vistra has taken various actions to improve its risk profile for future weather-driven volatility events, including investing in improvements to further harden its coal fuel handling capabilities and to further weatherize its ERCOT fleet for even colder temperatures and longer durations;

carrying more backup generation into the peak seasons after accounting for weatherization investments and ERCOT market improvements implemented going forward;

contracting for incremental gas storage to support its gas fleet;

adding additional dual fuel capabilities at its gas steam units and increasing fuel oil inventory at its existing dual fuel sites;

and engaging in processes to evaluate potential market reforms.

Dividend Program

In November 2018, we announced that the Board had adopted a dividend program which we initiated in the first quarter of 2019.

During the years ended December 31, 2022, 2021 and 2020, we paid dividends to common stockholders totaling $302 million, $290 million and $266 million, respectively.

See Note 13 to the Financial Statements for more information about our dividend program.

Share Repurchase Program

In October 2021, we announced that the Board had authorized a share repurchase program (Share Repurchase Program) under which up to $2.0 billion of our outstanding common stock may be repurchased.

The Share Repurchase Program became effective on October 11, 2021.

In August 2022, the Board authorized an incremental $1.25 billion for repurchases to bring the total authorized under the Share Repurchase Program to $3.25 billion.

We expect to complete repurchases under the current $3.25 billion Share Repurchase Program by the end of 2023.

$3.25 Billion Board Authorization

Total Number of Shares Repurchased Average Price Paid

Per Share Amount Paid for Shares Repurchased Amount Available for Additional Repurchases at the End of the Period

Year Ended December 31, 2021

19,330,365 $ 21.16 $ 409

Year Ended December 31, 2022

78,470,547 23.40 1,836

Total repurchased through December 31, 2022

97,800,912 $ 22.96 $ 2,245 $ 1,005

January 1, 2023 through February 23, 2023 8,824,640 22.72 201

Total repurchased through February 23, 2023 106,625,552 $ 22.94 $ 2,446 $ 804

See Note 13 to the Financial Statements for more information concerning the Share Repurchase Program.

Preferred Stock Offerings

On October 15, 2021, we issued 1,000,000 shares of Series A Preferred Stock in a private offering (Offering).

In October 2021, we issued 1,000,000 shares of Series A Preferred Stock in a private offering (Offering).

The net proceeds of the Offering were approximately $990 million, after deducting underwriting commissions and offering expenses.

We intend to use the net proceeds from the Offering to repurchase shares of our outstanding common stock under the Share Repurchase Program (discussed 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.

We intend to use the net proceeds from the Offering to repurchase shares of our outstanding common stock under the Share Repurchase Program (discussed above).

In December 2021, we issued 1,000,000 shares of Series B Preferred Stock in a private offering (Series B Offering) under our Green Finance Framework.

The net proceeds of the Series B Offering were approximately $985 million, after deducting underwriting commissions and offering expenses.

We intend to use the proceeds from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments.

We have used and will continue to use an amount equal to the net proceeds from the Series B Offering to pay for or reimburse existing and new eligible renewable and battery ESS developments in accordance with the Green Finance Framework.

See Note 13 to the Financial Statements for more information concerning the Series A Preferred Stock and the Series B Preferred Stock.

Share Repurchase Program

In October 2021, we announced that the Board had authorized a new share repurchase program (Share Repurchase Program) under which up to $2.0 billion of our outstanding common stock may be repurchased.

The Share Repurchase Program became effective on October 11, 2021.

The Share Repurchase Program supersedes the $1.5 million share repurchase program previously announced in September 2020 (2020 Share Repurchase Program).

In the three months ended December 31, 2021, 19,330,365 shares of our common stock were repurchased under the Share Repurchase Program for approximately $409 million at an average price of $21.16 per share of common stock.

As of December 31, 2021, approximately $1.591 billion was available for additional repurchases under the Share Repurchase Program.

From January 1, 2022 through February 22, 2022, 16,059,290 shares of our common stock had been repurchased under the Share Repurchase Program for $355 million at an average price per share of common stock of $22.07, and at February 22, 2022, $1.236 billion was available for repurchase under the Share Repurchase Program.

See Note 14 to the Financial Statements for more information concerning the Share Repurchase Program and the 2020 Share Repurchase Program.

Debt Activity

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We also intend to continue to simplify and optimize our capital structure, maintain adequate liquidity and pursue opportunities to refinance our long-term debt to extend maturities and/or reduce ongoing interest expense.

While the financial impacts resulting from Winter Storm Uri caused an increase in our consolidated net leverage, the Company remains committed to a strong balance sheet, and the anticipated securitization proceeds from ERCOT are expected to enable us to further execute this objective.

See Note 1 to the Financial Statements for details of the securitization proceeds receivable from ERCOT, Note 11 to the Financial Statements for details of our long-term debt activity, and Note 10 to the Financial Statements for details of our accounts receivable financing.

Commodity-Linked Revolving Credit Facility

On February 4, 2022, Vistra Operations entered into a credit agreement by and among Vistra Operations, Vistra Intermediate, the lenders, joint lead arrangers and joint bookrunners party thereto, and Citibank, N.A., as administrative agent and collateral agent.

The Credit Agreement provides for a $1.0 billion senior secured commodity-linked revolving credit facility (the Commodity-Linked Facility).

While the financial impacts resulting from Winter Storm Uri and higher margining requirements as a result of increasing power and natural gas prices have caused an increase in our consolidated net leverage, the Company remains committed to a strong balance sheet.

See Note 10 to the Financial Statements for details of our debt activity and Note 9 to the Financial Statements for details of our accounts receivable financing.

Vistra Operations Credit Agreement Amendments — In April 2022 and July 2022, the Vistra Operations Credit Agreement was amended to, among other things, (i) establish new classes of extended revolving credit commitments maturing in April 2027 in aggregate amounts of $2.8 billion and $725 million as of April 2022 and July 2022, respectively, (ii) appoint certain additional revolving letter of credit issuers, and (iii) require Vistra Operations to terminate at least $350 million in revolving commitments maturing April 29, 2027 by December 30, 2022 or earlier if Vistra Operations or any guarantor receives proceeds from any capital markets transaction whose primary purpose is designed to enhance the liquidity of Vistra Operations and its guarantors.

In accordance with this requirement, effective December 30, 2022, Vistra Operations terminated $350 million in revolving commitments.

After giving effect to the reduction, Vistra Operations has $3.175 billion of revolving credit commitments maturing in April 2027.

See Note 10 to the Financial Statements for details of the Vistra Operations Credit Agreement amendments.

Commodity-Linked Revolving Credit Facility — In February 2022, Vistra Operations entered into a credit agreement by and among Vistra Operations, Vistra Intermediate, the lenders, joint lead arrangers and joint bookrunners party thereto, and Citibank, N.A., as administrative agent and collateral agent.

The Credit Agreement provides for a senior secured commodity-linked revolving credit facility (the Commodity-Linked Facility).

Vistra Operations intends to use the liquidity provided under the Commodity-Linked Facility to make cash postings as required under various commodity contracts to which Vistra Operations and its subsidiaries are parties as power prices increase from time-to time and for other working capital and general corporate purposes.

In May 2022, June 2022 and October 2022, the Credit Agreement was amended to, among other things, (i) effect certain additions and reductions (as applicable) to the revolving commitments of certain lenders, and extend the maturity date thereof, (ii) modify certain pricing provisions, financial covenants and provisions related to the collateral, and (iii) adjust certain borrowing and repayment provisions, including the calculation of the borrowing base.

See Note 10 to the Financial Statements for more information concerning the Commodity-Linked Facility.

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2022-2023 2023-2024 2024-2025

East Segment Sunset Segment East Segment Sunset Segment

East Segment Sunset Segment East Segment Sunset Segment East Segment Sunset Segment

CP auction capacity sold, net (MW) 5,964 1,519 5,538 1,332 5,567 1,338

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NYISO — The most recent seasonal auction results for NYISO's Rest-of-State zones, in which the capacity for our Independence plant clears, are as follows for each planning period:

2021 - 2022 Summer

Price per kW-month $ 1.18

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The price of power is typically set by natural gas-fueled generation facilities, with wholesale prices generally tracking increases or decreases in the price of natural gas, with exceptions such as those periods during which ERCOT power prices rise significantly as a result of the scarcity of available generation resources relative to power demand.

In recent years, natural gas supply has outpaced demand primarily as a result of development and expansion of hydraulic fracturing in natural gas extraction;

this supply/demand environment has resulted in historically low natural gas prices, and such prices have historically been volatile.

Natural gas prices have historically been volatile.

In contrast to our natural gas-fueled generation facilities, changes in natural gas prices have no significant effect on the cost of generating power at our nuclear-, lignite- and coal-fueled facilities.

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• improving retail customer service to attract and retain high-value customers.

We have engaged in natural gas hedging activities to mitigate the risk of lower wholesale electricity prices that have corresponded to declines in natural gas prices.

When natural gas prices are depressed, we continue to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward wholesale and retail electricity sales.

We have engaged in natural gas hedging activities to mitigate the risk of higher or lower wholesale electricity prices that have corresponded to increases or declines in natural gas prices.

When natural gas prices are elevated or depressed, we continue to seek opportunities to manage our wholesale power price exposure through hedging activities, including forward wholesale and retail electricity sales.

Estimated hedging levels for generation volumes in our Texas, East, West and Sunset segments as of December 31, 2022 were as follows:

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and second, calculating the residual natural gas exposure that is not already included in the gas generation spark spread sensitivity shown in the table below.

The estimates related to price sensitivity are based on our expected generation, related hedges and forward prices at December 31, 2021.

The estimates related to price sensitivity are based on our expected generation, related hedges and forward prices as of December 31, 2022.

Nuclear/Renewable/Coal Generation:

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$2.50/MWh decrease in power price $ (7) $ (32)

Residual Natural Gas Position:

$0.25/MMBtu increase in natural gas price $ (6) $ (12)

Residual Natural Gas Position:

$0.25/MMBtu decrease in natural gas price $ 6 $ 12

Competitive Retail Markets and Customer Retention

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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.

Breaches and threats are becoming increasingly sophisticated, complex, change frequently and may be difficult to detect.

Any loss of confidential or proprietary data through a breach could materially affect our reputation, including our TXU Energy, Ambit Energy, Value Based Brands, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power and U.S.

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We have controls in place designed to protect our infrastructure, provide our employees awareness training of cybersecurity threats, routinely utilize information technology security experts to assist us in our evaluations of the effectiveness of our information technology systems and controls, and we regularly enhance our security measures to protect our systems and data, including encryption, tokenization and authentication technologies to mitigate cybersecurity risks and increasing our monitoring capabilities to enhance early detection and rapid response to potential cyber threats.

In response to the fact that a portion of our workforce continues to work remotely and within a hybrid work environment, we have reduced our attack surface process and technology, which removes remote network risk from our internal systems, assets, or data.

In response to the fact that a portion of our workforce operates within a hybrid work environment, we have reduced our attack surface process and technology, which removes remote network risk from our internal systems, assets, or data.

We also apply the knowledge gained through industry and government organizations, external partner cyber risk and maturity assessments to continuously improve our technology, processes and services to detect, mitigate and protect our cyber and data assets.

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The pattern of this fluctuation may change depending on, among other things, the retail load served and the terms of contracts to purchase or sell electricity.

Application of Critical Accounting Policies and Estimates

Our significant accounting policies are discussed in Note 1 to the Financial Statements.

Critical Accounting Estimates

We follow accounting principles generally accepted in the U.S.

Application of these accounting policies in the preparation of our consolidated financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and revenues and expenses during the periods covered.

The following is a summary of certain critical accounting policies that are impacted by judgments and uncertainties and under which different amounts might be reported using different assumptions or estimation methodologies.

The following is a summary of certain critical accounting estimates that are impacted by judgments and uncertainties and under which different amounts might be reported using different assumptions or estimation methodologies.

Derivative Instruments and Mark-to-Market Accounting

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For illiquid periods, fair value is estimated based on forward price curves developed using proprietary modeling techniques that take into account available market information and other inputs that might not be readily observable in the market.

Any significant changes to these inputs could result in a material change to the value of the assets or liabilities recorded on our consolidated balance sheets and could result in a material change to the unrealized gains or losses recorded in our consolidated statements of operations.

We estimate fair value as described in Note 14 to the Financial Statements.

Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections 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.

Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections, which generally eliminate the requirement for mark-to-market recognition in net income.

Normal purchases and sales (NPNS) are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business and are not subject to mark-to-market accounting if the NPNS election is made and are accounted for on an accrual basis.

Determining whether a contract qualifies for the normal purchase or sale election requires judgment as to whether or not the contract will physically deliver and requires that management ensure compliance with all associated qualification and documentation requirements.

If it is determined that a transaction designated as a normal purchase or sale no longer meets the scope exception due to changes in estimates, the related contract would be recorded on the balance sheet at fair value with immediate recognition through earnings.

See Note 15 to the Financial Statements for further discussion regarding derivative instruments.

Accounting for Income Taxes

Vistra files a U.S.

federal income tax return that includes the results of its consolidated subsidiaries.

Vistra is the corporate parent of the Vistra consolidated group.

Pursuant to applicable U.S.

Department of the Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group.

Our income tax expense and related consolidated balance sheet amounts involve significant management estimates and judgments.

Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve estimates and judgments of the timing and probability of recognition of income and deductions by taxing authorities.

In assessing the likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future taxable income.

Further, we assess the likelihood that we will be able to realize or utilize our deferred tax assets.

If realization is not more likely than not, we would record a valuation allowance against such deferred tax assets for the amount we would not expect to utilize, which would reduce the carrying value of the deferred tax amounts.

When evaluating the need for a valuation allowance, we consider all available positive and negative evidence, including the following:

• the creation and timing of future income associated with the reversal of deferred tax liabilities in excess of deferred tax assets;

• the existence, or lack thereof, of statutory limitations on the period that net operating losses may be carried forward;

• the amounts and history of income or losses, adjusted for certain non-recurring items.

Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, our forecasted financial condition and results of operations in future periods, as well as final review of filed tax returns by taxing authorities.

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See Notes 1 and 6 to the Financial Statements for further discussion of income tax matters.

Accounting for Tax Receivable Agreement

On the Effective Date, Vistra entered into a tax receivable agreement (the TRA) with a transfer agent.

Accounting for Tax Receivable Agreement (TRA)

On the Effective Date, Vistra entered into the TRA with a transfer agent.

Pursuant to the TRA, we issued the TRA Rights for the benefit of the first-lien creditors of TCEH entitled to receive such TRA Rights under the Plan of Reorganization.

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As of December 31, 2022, the TRA obligation has been adjusted to $522 million.

During the year ended December 31, 2021, we recorded a decrease to the carrying value of the TRA obligation totaling $115 million as a result of adjustments to forecasted taxable income, including the financial impacts of Winter Storm Uri, and anticipated tax benefits available under current tax laws for planned additional renewable development projects.

During the year ended December 31, 2022, we recorded an increase to the carrying value of the TRA obligation totaling $64 million as a result of adjustments to forecasted book and taxable income due to increases in commodity price forecasts.

As of December 31, 2022, expected undiscounted federal and state payments under the TRA is estimated to be approximately $1.4 billion.

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• additional states that Vistra now operates in, the relevant tax rates of those states and how income will be apportioned to those states.

We recognize accretion expense over the life of the TRA Rights liability as the present value of the liability is accreted up over the life of the liability.

This noncash accretion expense is reported in the consolidated statements of operations as Impacts of Tax Receivable Agreement.

Further, there may be significant changes, which may be material, to the estimate of the related liability due to various reasons including changes in federal and state tax laws and regulations, changes in estimates of the amount or timing of future consolidated taxable income, utilization of acquired net operating losses, reversals of temporary book/tax differences and other items.

There may be significant changes, which may be material, to the estimate of the related liability due to various reasons including changes in federal and state tax laws and regulations, changes in estimates of the amount or timing of future consolidated taxable income, utilization of acquired net operating losses, reversals of temporary book/tax differences and other items.

Changes in those estimates are recognized as adjustments to the related TRA Rights liability, with offsetting impacts recorded in the consolidated statements of operations as Impacts of Tax Receivable Agreement.

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A liability is initially recorded at fair value for an ARO associated with the legal obligation associated with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets.

Changes to the estimate of the ARO requires us to make significant estimates and assumptions.

Specifically, the estimates and assumptions required for the mining land reclamation related to lignite mining, such as the costs to fill in mining pits and interpreting the mining permit closure requirements, are complex and require a significant amount of judgment.

To develop the estimate associated with the costs to fill in mining pits, we utilize a complex proprietary model to estimate the volume of the pit.

These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, and remediation or closure of coal ash basins.

In estimating the ARO liability, we are required to make significant estimates and assumptions.

For the estimates and assumptions of the nuclear generation plant decommissioning, we use unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs (in current year dollars) and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates.

Decommissioning cost studies are updated for each of our nuclear units at least every five years unless circumstances warrant a more frequent update.

In estimating the liability for December 31, 2022, we have included an assumption that Vistra receives a license extension of 20 years from the NRC to continue to operate Comanche Peak Units 1 and 2 through 2050 and 2053, respectively.

The costs to ultimately decommission the facility are recoverable through the regulatory rate making process as part of Oncor's delivery fees and therefore changes in estimates of the ARO do not impact Vistra's earnings.

The estimates and assumptions required for the mining land reclamation related to lignite mining, such as costs to fill in mining pits and interpretation of the mining permit closure requirements, are complex and require a significant amount of judgment.

To develop the estimate of costs to fill in mining pits, we utilize a complex proprietary model to estimate the volume of the pit.

A significant portion of the estimate is associated with the Asset Closure segment, thus related to closed facilities with changes in the estimate recorded to our consolidated statements of operations.

For the next five years, Vistra is projected to spend approximately $265 million (on a nominal basis) to achieve its reclamation objectives.

During the years ended December 31, 2020 and 2019, we transferred $15 million and $135 million, respectively, in ARO obligations to third parties for remediation.

These obligations are adjusted on a regular basis to reflect the passage of time and to incorporate revisions to the following significant estimates and assumptions:

• estimation of dates for retirement, which can be dependent on environmental and other legislation;

• amounts and timing of future cash expenditures associated with retirement, settlement or remediation activities;

• discount rates;

• cost escalation factors;

• market risk premium;

• inflation rates;

• if applicable, past experience with government regulators regarding similar obligations.

For the next five years, Vistra is projected to spend approximately $432 million (on a nominal basis) to achieve its mining reclamation and other coal ash remediation objectives.

During the years ended December 31, 2022, 2021 and 2020, we transferred $61 million, zero and $15 million, respectively, in ARO obligations to third parties for remediation.

Any remaining unpaid third-party obligation was reclassified to other current liabilities and other noncurrent liabilities and deferred credits in our consolidated balance sheets.

As of December 31, 2021, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.635 billion and includes an assumption that Vistra receives a license extension of 20 years from the NRC to continue to operate the Comanche Peak facility.

The costs to ultimately decommission that facility are recoverable through the regulatory rate making process as part of Oncor's delivery fees and therefore changes in estimates of the ARO do not impact Vistra's earnings.

See Note 20 to the Financial Statements for additional discussion of ARO obligations and adjustments made to the ARO obligation estimates during the years ended December 31, 2022, 2021 and 2020.

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Goodwill and intangible assets with indefinite useful lives, such as the intangible asset related to the trade names of TXU Energy TM , Ambit Energy, 4Change Energy TM , Homefield, Dynegy Energy Services, TriEagle Energy, Public Power and U.S.

Gas & Electric, respectively, are required to be evaluated for impairment at least annually (we have selected October 1 as our annual goodwill test date) or whenever events or changes in circumstances indicate an impairment may exist, such as the indicators used to evaluate impairments to long-lived assets discussed above or declines in values of comparable public companies in our industry.

Gas & Electric, respectively, are required to be evaluated for impairment at least annually (we have selected October 1 as our annual impairment test date) or whenever events or changes in circumstances indicate an impairment may exist, such as the indicators used to evaluate impairments to long-lived assets discussed above or declines in values of comparable public companies in our industry.

As of December 31, 2022, our goodwill balances totaled $2.461 billion and $122 million for our Retail reporting unit and Texas Generation reporting unit, respectively.

Under this goodwill impairment analysis, if at the assessment date, a reporting unit’s carrying value exceeds its estimated fair value, the excess carrying value is written off as an impairment charge.

Accounting standards allow a company to qualitatively assess if the carrying value of a reporting unit with goodwill is more likely than not less than the fair value of that reporting unit.

If the entity determines the carrying value, including goodwill, is not more likely greater than the fair value, no further testing of goodwill for impairment is required.

On the most recent goodwill testing date, we 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.

Accounting guidance requires goodwill to be allocated to our reporting units, and at December 31, 2021, $2.461 billion of our goodwill was allocated to our Retail reporting unit and $122 million was allocated to our Texas Generation reporting unit.

Goodwill impairment testing is performed at the reporting unit level.

Under this goodwill impairment analysis, if at the assessment date, a reporting unit's carrying value exceeds its estimated fair value (enterprise value), the excess carrying value is written off as an impairment charge.

The determination of enterprise value of a reporting unit involves a number of assumptions and estimates.

We use a combination of fair value measurements to estimate enterprise values of our reporting units including:

internal discounted cash flow analyses (income approach), and comparable publicly traded company values (market approach).

The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity prices, market heat rates, the effects of environmental rules, generation plant performance, forecasted capital expenditures and retail sales volume trends, as well as determination of a terminal value.

Another key variable in the income approach is the discount rate, or weighted average cost of capital, applied to the forecasted cash flows.

The determination of the discount rate takes into consideration the capital structure, credit ratings and current debt yields of comparable publicly traded companies as well as an estimate of return on equity that reflects historical market returns and current market volatility for the industry.

The market approach involves using trading multiples of EBITDA of those selected publicly traded companies to derive appropriate multiples to apply to the EBITDA of our reporting units.

Critical judgments include the selection of publicly traded comparable companies and the weighting of the value metrics in developing the best estimate of enterprise value.

On the most recent goodwill testing date, we performed a qualitative assessment and determined that it was more likely than not that the fair value of our Retail and Texas Generation reporting units exceeded their carrying value at October 1, 2022.

Significant qualitative factors evaluated included reporting unit financial performance and market multiples, general macroeconomic, industry, and market conditions, cost factors, customer attrition, interest rates and changes in reporting unit book value.

As of December 31, 2022, intangible assets with indefinite useful lives related to our retail trade names totaled $1.341 billion.

Under this impairment analysis, if at the assessment date, a retail trade name's carrying value exceeds its estimated fair value, the excess carrying value is written off as an impairment charge.

Accounting standards allow a company to qualitatively assess if the carrying value of our retail trade name intangible assets is more likely than not less than the fair value.

On the most recent testing date, we performed a qualitative assessment and determined that it was more likely than not that the fair value of our retail trade names exceeded their carrying value at October 1, 2022.

Significant qualitative factors evaluated included trade name financial performance, general macroeconomic, industry, and market conditions, customer attrition and interest rates.

RESULTS OF OPERATIONS

In the year ended December 31, 2022, our operating segments delivered strong operating performance with a disciplined focus on cost management, while generating and selling essential electricity in a safe and reliable manner.

Our performance reflected the stability of our integrated model, including a diversified generation fleet, retail and commercial and hedging activities in support of our integrated business.

As part of our comprehensive hedging strategy, we hedged longer-dated revenues and fuel costs to reduce risk and lock in value as forward power and gas curves moved up materially, and we believe this has positioned us to significantly benefit operating results in 2023 and beyond.

In addition, we executed on our share repurchase strategy.

Vistra Consolidated Financial Results — Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

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Impairment of long-lived and other assets (74) (71) (3)

Operating income (loss)

Operating loss

(1,177) (1,515) 338

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Impacts of Tax Receivable Agreement (128) 53 (181)

Equity in earnings of unconsolidated investment — 4 (4)

Income (loss) before income taxes

Loss before income taxes

(1,560) (1,722) 162

Income tax (expense) benefit 458 (266) 724

Net income (loss)

Income tax benefit 350 458 (108)

$ (1,210) $ (1,264) $ 54

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1,158 (615) (868) (238) (258) (119) (620) (1,560)

Income tax benefit (expense) (2) — — — — — 460 458

Income tax benefit — — — — — — 350 350

Net income (loss)

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Impacts of Tax Receivable Agreement — — — — — — 53 53

Equity in earnings of unconsolidated investment — — 4 — — — — 4

Income (loss) before income taxes

2,198 (2,512) (567) 1 (137) (298) (407) (1,722)

Income tax expense — — — — — — (266) (266)

Income tax benefit (expense) (2) — — — — — 460 458

Net income (loss)

$ 2,196 $ (2,512) $ (567) $ 1 $ (137) $ (298) $ 53 $ (1,264)

In February 2021, Winter Storm Uri resulted in a $2.2 billion negative impact on the Company's pre-tax earnings in the year ended December 31, 2021, after taking into account approximately $544 million in securitization proceeds Vistra expects to receive from ERCOT as further described in Note 1 to the Financial Statements.

For the remainder of 2021, our operating segments delivered strong operating performance with a disciplined focus on cost management and self-help activities while generating and selling essential electricity in a safe and reliable manner.

Consolidated results decreased $3.034 billion to a net operating loss of $1.515 billion in the year ended December 31, 2021 compared to the year ended December 31, 2020.

The change in results was driven by the Winter Storm Uri impacts, including the need to procure power in ERCOT at market prices at or near the price cap due to lower output from our natural gas-fueled power plants driven by natural gas deliverability issues and our coal-fueled power plants driven by coal fuel handling challenges, high fuel costs, and high retail load costs including ancillary service costs and reliability deployment price adders.

Results were adversely impacted by $759 million in pre-tax unrealized losses on commodity hedging transactions in 2021 compared to $231 million in pre-tax unrealized gains on commodity hedging transactions in 2020.

Power, natural gas and coal forward market curves moved up during the year ended December 31, 2021, driving these net pre-tax unrealized losses on commodity hedging transactions.

Operating costs decreased $63 million to $1.559 billion in the year ended December 31, 2021 compared to the year ended December 31, 2020 primarily driven by lower LTSA costs and lower property taxes.

Interest expense and related charges decreased $246 million to $384 million in the year ended December 31, 2021 compared to the year ended December 31, 2020 driven by $134 million in unrealized mark-to-market gains on interest rate swaps in 2021 compared to $155 million in unrealized mark-to-market losses on interest rate swaps in 2020.

Consolidated operating loss decreased $338 million to $1.177 billion in the year ended December 31, 2022 compared to the year ended December 31, 2021.

The change in results was primarily driven by the $2.2 billion negative impact on our pre-tax earnings associated with Winter Storm Uri in the year ended December 31, 2021.

Partially offsetting the 2021 Winter Storm Uri impact, results for the year ended December 31, 2022 were unfavorably impacted by a $1.75 billion increase in pre-tax unrealized mark-to-market losses on derivative positions.

Power and natural gas forward market curves moved up during the year ended December 31, 2022 driving the pre-tax unrealized mark-to-market losses on commodity hedging transactions.

Included within these unrealized mark-to-market changes are pre-tax net unrealized losses of $544 million and $298 million recorded in the years ended December 31, 2022 and 2021, respectively, due to the discontinuance of NPNS accounting on retail electric contract portfolios where physical settlement is no longer considered probable throughout the contract term.

We believe the overall increase in forward power and natural gas prices during 2022 has positioned us to significantly benefit operating results in 2023 and beyond.

Interest expense and related charges decreased $16 million to $368 million in the year ended December 31, 2022 compared to the year ended December 31, 2021 driven by unrealized mark-to-market gains on interest rate swaps of $250 million in 2022 compared to $134 million in 2021 due to a more significant rise in interest rates in 2022.

The favorable variance is partially offset by an increase in interest paid/accrued of $111 million driven by higher average borrowings during the year ended December 31, 2022 as compared to the year ended December 31, 2021, reflecting costs associated with increased collateral posting obligations supporting our comprehensive hedging strategy.

See Note 20 to the Financial Statements.

For the years ended December 31, 2021 and 2020, the impacts of the TRA totaled income of $53 million and $5 million, respectively.

For the years ended December 31, 2022 and 2021, the impacts of the TRA totaled expense of $128 million and income of $53 million, respectively.

See Note 7 to the Financial Statements for discussion of the impacts of the TRA obligation.

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federal statutory rate.

Consolidated cash flows used in operations totaled $206 million for the year ended December 31, 2021 compared to consolidated cash flows provided by operations of $3.337 billion for the year ended December 31, 2020.

The unfavorable change of $3.543 billion was primarily driven by lower cash from operations due to Winter Storm Uri impacts and higher cash margin deposits posted with third-parties.

Cash margin deposits posted were driven by net pre-tax unrealized losses on commodity hedging transactions reflecting power, natural gas and coal forward market curves that moved up during the year ended December 31, 2021.

Discussion of Adjusted EBITDA

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We define EBITDA as earnings (loss) before interest expense, income tax expense (benefit) and depreciation and amortization expense.

We define Adjusted EBITDA as EBITDA adjusted to exclude (i) gains or losses on the sale or retirement of certain assets, (ii) the impacts of mark-to-market changes on derivatives, (iii) the impact of impairment charges, (iv) certain amounts associated with fresh-start reporting, acquisitions, dispositions, transition costs or restructurings, (v) non-cash compensation expense, (vi) impacts from the Tax Receivable Agreement and (vii) other material nonrecurring or unusual items.

Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers, and evaluate overall financial performance, we believe they provide useful information for investors.

When EBITDA or Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss).

Adjusted EBITDA — Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

Vistra Adjusted EBITDA — Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

Year Ended December 31, Favorable (Unfavorable)

Net income (loss) $ (1,264) $ 624 $ (1,888)

Income tax expense (benefit) (458) 266 (724)

Net loss $ (1,210) $ (1,264) $ 54

Income tax benefit (350) (458) 108

Interest expense and related charges (a) 368 384 (16)

Depreciation and amortization (b) 1,682 1,831 (149)

EBITDA 493 3,332 (2,839)

Unrealized net (gain) loss resulting from commodity hedging transactions 759 (231) 990

EBITDA before Adjustments 490 493 (3)

Unrealized net loss resulting from commodity hedging transactions (c) 2,510 759 1,751

Generation plant retirement expenses 4 18 (14)

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Transition and merger expenses 13 (8) 21

Other, including impairment of long-lived and other assets 80 375 (295)

Loss on disposal of investment in NELP — 29 (29)

COVID-19-related expenses (c) 8 25 (17)

Impairment of long-lived and other assets 74 71 3

Winter Storm Uri impacts (d) (319) 698 (1,017)

Other, net 23 17 6

Adjusted EBITDA $ 2,994 $ 1,908 $ 1,086

(a) Includes unrealized mark-to-market net gains on interest rate swaps of $134 million and unrealized mark-to-market net losses on interest rate swaps of $155 million for the years ended December 31, 2021 and 2020, respectively.

(a) Includes unrealized mark-to-market net gains on interest rate swaps of $250 million and $134 million for the years ended December 31, 2022 and 2021, respectively.

(b) Includes nuclear fuel amortization in the Texas segment of $86 million and $78 million for the years ended December 31, 2022 and 2021, respectively.

(d) For the year ending December 31, 2021, includes the following of the Winter Storm Uri impacts, which we believe are not reflective of our operating performance:

allocation of ERCOT default uplift charges which are expected to be paid over more than 90 years under current protocols;

accrual of Koch earn-out amounts that the Company will pay by the end of the second quarter of 2022;

future bill credits related to Winter Storm Uri (as further described below);

and Winter Storm Uri related legal fees and other costs.

(c) Net pre-tax unrealized mark-to-market losses on commodity and hedging transactions were driven by an increase in power and natural gas price curves during the year ended December 31, 2022.

Additionally, we recorded pre-tax net unrealized losses of $544 million and $298 million in the years ended December 31, 2022 and 2021, respectively, due to the discontinuance of NPNS accounting on retail electric contract portfolios where physical settlement is no longer considered probable throughout the contract term.

(d) For the year ended December 31, 2021, includes the following of the Winter Storm Uri impacts, which we believe are not reflective of our normal operating performance:

the allocation of ERCOT default uplift charges which were expected to be paid over several decades under protocols existing at the time of the storm, accrual of Koch earn-out amounts that we paid in the second quarter of 2022 (see Note 12 to the Financial Statements), future bill credits related to Winter Storm Uri and Winter Storm Uri related legal fees and other costs.

For the year ended December 31, 2022, includes reductions to Adjusted EBITDA reflecting ERCOT default uplift charges of $183 million and bill credit applications of $144 million.

The adjustment for ERCOT default uplift charges relates to (i) ERCOT receiving payments that reduced the market wide default balance and (ii) the fourth quarter 2022 derecognition of the remaining default balance in connection with a settlement between Brazos and ERCOT (see Note 12 to the Financial Statements).

The adjustment for future bill credits relates to large commercial and industrial customers that curtailed their usage during Winter Storm Uri and will reverse and impact Adjusted EBITDA in future periods as the credits are applied to customer bills.

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.

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Net income (loss) $ 1,158 $ (615) $ (868) $ (238) $ (258) $ (119) $ (270) $ (1,210)

Income tax expense (benefit) 2 — — — — — (460) (458)

Income tax benefit — — — — — — (350) (350)

Interest expense and related charges (a) 14 (20) 3 (6) 3 3 371 368

Depreciation and amortization (b) 145 623 706 42 76 21 69 1,682

EBITDA 2,419 (1,840) 146 52 (272) (21) 9 493

EBITDA before Adjustments 1,317 (12) (159) (202) (179) (95) (180) 490

Unrealized net (gain) loss resulting from commodity hedging transactions (291) 1,610 759 351 112 (31) — 2,510

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Transition and merger expenses 7 — 1 — — — 5 13

Other, including impairment of long-lived and other assets 57 18 9 3 33 3 (43) 80

COVID-19-related expenses (c) — 4 1 — 2 — 1 8

Winter Storm Uri impacts (d) 239 457 — — 1 — 1 698

Impairment of long-lived and other assets — — — — 74 — — 74

Winter Storm Uri impacts (c) (141) (178) — — — — — (319)

Other, net 31 20 8 3 15 8 (62) 23

Adjusted EBITDA $ 923 $ 1,438 $ 608 $ 152 $ 38 $ (121) $ (44) $ 2,994

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(b) Includes nuclear fuel amortization of $86 million in the Texas segment.

(d) Includes the following of the Winter Storm Uri impacts, which we believe are not reflective of our operating performance:

allocation of ERCOT default uplift charges which are expected to be paid over more than 90 years under current protocols;

accrual of Koch earn-out amounts that the Company will pay by the end of the second quarter of 2022;

future bill credits related to Winter Storm Uri (as further described below);

and Winter Storm Uri related legal fees and other costs.

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.

(c) Includes the application of bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri and a reduction in the allocation of ERCOT default uplift charges which were expected to be paid over several decades under protocols existing at the time of the storm.

We estimate remaining bill credit amounts to be applied in future periods are for 2023 (approximately $54 million), 2024 (approximately $6 million) and 2025 (approximately $28 million).

Year Ended December 31, 2021

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Net income (loss) 2,196 (2,512) (567) 1 (137) (298) 53 $ (1,264)

Income tax expense — — — — — — 266 266

Income tax expense (benefit) 2 — — — — — (460) (458)

Interest expense and related charges (a) 9 (14) 15 (9) 3 — 380 384

Depreciation and amortization (b) 212 686 698 60 104 35 36 1,831

EBITDA 622 2,302 769 59 (279) (79) (62) 3,332

EBITDA before Adjustments 2,419 (1,840) 146 52 (30) (263) 9 493

Unrealized net (gain) loss resulting from commodity hedging transactions (1,403) 1,139 655 38 211 119 — 759

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Transition and merger expenses (2) — — — — (15) 9 (8)

Other, including impairment of long-lived and other assets 11 26 10 4 359 1 (36) 375

Loss on disposal of investment in NELP — — 29 — — — — 29

COVID-19-related expenses (c) — 15 3 — 5 — 2 25

Impairment of long-lived and other assets 33 — — — — 38 — 71

Winter Storm Uri (c) 239 457 — — 1 — 1 698

Other, net 24 22 10 3 (5) 5 (42) 17

Adjusted EBITDA $ 1,312 $ (236) $ 737 $ 93 $ 148 $ (121) $ (25) $ 1,908

(a) Includes $155 million of unrealized mark-to-market net losses on interest rate swaps.

(a) Includes $134 million of unrealized mark-to-market net gains on interest rate swaps.

(b) Includes nuclear fuel amortization of $78 million in the Texas segment.

(c) Includes the following of the Winter Storm Uri impacts, which we believe are not reflective of our operating performance:

the allocation of ERCOT default uplift charges which were expected to be paid over several decades under protocols existing at the time of the storm, accrual of Koch earn-out amounts that we paid in the second quarter of 2022, future bill credits related to Winter Storm Uri and Winter Storm Uri related legal fees and other costs.

The adjustment for future bill credits relates to large commercial and industrial customers that curtailed their usage during Winter Storm Uri and reverse and impact Adjusted EBITDA in future periods as the credits are applied to customer bills.

The Company believes the inclusion of the bill credits as a reduction to Adjusted EBITDA in the years in which such bill credits are applied more accurately reflects its operating performance.

Retail Segment — Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

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Purchases from affiliates (5,572) (4,002) (1,570)

Unrealized net gains (losses) on hedging activities with affiliates 1,719 (329) 2,048

Unrealized net gains on hedging activities with affiliates (b) 819 1,719 (900)

Unrealized net gains on hedging activities 4 9 (5)

Delivery fees (2,285) (1,937) (348)

Other costs (b) (357) (69) (288)

Other costs (c) (135) (357) 222

Total fuel, purchased power costs and delivery fees $ (7,169) $ (4,568) $ (2,601)

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Total retail electricity sales volumes 98,089 93,103 4,986

Weather (North Texas average) - percent of normal (c):

Weather (North Texas average) - percent of normal (d):

Cooling degree days 111 % 93 %

Heating degree days 108 % 92 %

(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.

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.

(a) Includes pre-tax unrealized net losses of $544 million and $298 million for the years ended December 31, 2022 and 2021, recognized due to the discontinuance of NPNS accounting on a retail electric contract portfolio where physical settlement is no longer considered probable throughout the contract term.

(b) Includes unrealized net gains/(losses) from mark-to-market valuations of commodity positions with the Texas, East and Sunset segments.

(c) For the year ended December 31, 2021, includes $153 million of future bill credits to large commercial and industrial customers.

(d) Reflects cooling degree or heating degree days for the region based on Weather Services International (WSI) data.

The following table presents changes in net income (loss) and Adjusted EBITDA for the year ended December 31, 2022 compared to the year ended December 31, 2021.

Year Ended December 31, 2022 Compared to 2021

Winter Storm Uri, including securitization proceeds receivable from ERCOT and bill credits $ (75)

Monetization of certain commercial positions 207

Higher margins 228

Other driven by higher SG&A expense

Timing of power costs, including self-help gains in 2021 and multi-year customer contracts in a backwardated market $ (248)

Winter Storm Uri impact primarily driven by 2022 bill credits issued exceeding the net impact of the storm in 2021 (63)

Higher margins reflecting favorable weather in 2022 and ERCOT performance, partially offset by pressure in Midwest and Northeast markets 30

Other primarily driven by higher bad debt expense due to higher revenues in 2022

Change in Adjusted EBITDA $ (389)

Favorable impact of higher unrealized net gains on commodity hedging activities 1,743

Future bill credits and other costs related to Winter Storm Uri (245)

Decrease in unrealized net gains on hedging activities (1,112)

Bill credits and other costs related to Winter Storm Uri 380

Decrease in depreciation and amortization expenses 67

Other, including impairment of long-lived and other assets (31)

Change in transition and merger and other expenses 16

Change in Net income $ (1,038)

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Nuclear facilities 19,688 19,402

Solar/Battery facilities 454 432 4

Solar facilities 822 454

Capacity factors:

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TetcoM3 ($/MMBtu) $ 6.81 $ 3.40 Northern Illinois Hub $ 71.76 $ 41.10

Algonquin Citygates ($/MMBtu) $ 4.51 $ 2.00

Algonquin Citygates ($/MMBtu) $ 9.16 $ 4.51 CAISO NP15 $ 93.12 $ 56.37

(a) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.

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Winter Storm Uri impact 1,535 (50) — (17)

Favorable/(unfavorable) change in other operating costs 19 8 (7) (39)

Unfavorable change in other operating costs (114) (12) (6) (38)

Favorable/(unfavorable) change in selling, general and administrative expenses (37) 9 16 (15)

Other (including other income and other deductions) (a) 81 (5) (1) 10

Other (19) — — 5

Change in Adjusted EBITDA $ 1,674 $ (129) $ 59 $ (110)

Favorable/(unfavorable) change in depreciation and amortization 63 (8) 18 28

Change in unrealized net losses on hedging activities (1,830) (640) (28) (235)

Other, including impairment of long-lived and other assets 25 (5) — 329

Generation plant retirement expenses — — — 25

Change in unrealized net gains/(losses) on hedging activities (471) (104) (313) 99

Impairment of long-lived and other assets — — — (74)

Generation plant retirement, transition and merger expenses — (1) — (8)

Fresh start/purchase accounting impacts (12) (73) — (37)

Transition and merger expenses 2 1 — —

Winter Storm Uri impact (ERCOT default uplift and legal disputes) 635 — — 1

Loss on disposal of investment in NELP — 29 — —

Other (including interest and COVID-19 related expenses) 8 14 (3) (20)

Change in Net income (loss) $ 1,897 $ (301) $ (239) $ (121)

(a) For the year ended December 31, 2021, includes insurance proceeds of $80 million in the Texas segment and $7 million in the Sunset segment.

The change in Texas segment results was primarily driven by the Winter Storm Uri impacts, including the need to procure power in ERCOT at market prices at or near the price cap due to lower output from our natural gas-fueled power plants driven by natural gas deliverability issues, lower margins from our natural gas-fueled power plants due to extremely high fuel costs, and, to a lesser extent, operational challenges associated with Winter Storm Uri, and unrealized hedging losses in the year ended December 31, 2021 versus unrealized hedging gains in the year ended December 31, 2020, partially offset by insurance proceeds received in 2021.

The change in East segment results was driven by lower revenue net of fuel and larger unrealized hedging losses in the year ended December 31, 2021 versus the year ended December 31, 2020, partially offset by loss on disposal of equity method investment in NELP for 100% ownership of NJEA (see Note 21 to the Financial Statements) in 2020.

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.

The change in Texas segment results was primarily driven by the Winter Storm Uri impacts in 2021.

The increases in revenue net of fuel and operating costs are due to strong generation fleet performance during periods of higher pricing and inflationary pressures, respectively, in the year ended December 31, 2022.

Additionally, unrealized hedging losses increased in the year ended December 31, 2022 compared to the year ended December 31, 2021 due to increases in forward power prices in the year ended December 31, 2022.

The change in East segment results was primarily driven by (i) higher unrealized hedging losses in the year ended December 31, 2022 compared to the year ended December 31, 2021 due to increases in forward power prices in the year ended December 31, 2022 (ii) lower revenue net of fuel in the year ended December 31, 2022 compared to the year ended December 31, 2021 due primarily to higher-than-expected migration of customers to default service providers at rates below prevailing wholesale market prices and lower capacity revenue and (iii) termination of an unfavorable acquired contract in 2021 which resulted in derecognition of an intangible liability.

The change in West segment results was driven by higher unrealized hedging losses in the year ended December 31, 2022 as compared to the year ended December 31, 2021 as forward power prices increased more in the year ended December 31, 2022 compared to the year ended December 31, 2021.

Additionally, revenue net of fuel is higher in the year ended December 31, 2022 as compared to the year ended December 31, 2021 reflecting higher realized margins from our battery ESS projects (see Note 2 to the Financial Statements).

The change in Sunset segment results was driven by an unfavorable change in revenue net of fuel due primarily to lower generation volumes from coal plants due to industry-wide fuel delivery challenges in the year ended December 31, 2022 and the impairment of assets related to our Miami Fort generation facility (see Note 20 to the Financial Statements).

Asset Closure Segment — Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

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Operating revenues $ 296 $ 86 $ 210

Fuel, purchased power costs and delivery fees (249) (111) (138)

Operating costs (116) (193) 77

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Selling, general and administrative expenses (40) (50) 10

Impairment of long-lived assets — (38) 38

Operating loss (130) (341) 211

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Adjusted EBITDA $ (121) $ (121) $ —

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).

Production volumes (GWh) 6,670 9,706 (3,036)

Results and volumes for the Asset Closure segment include those from the Zimmer and Joppa generation plants that we retired in May 2022 and September 2022, respectively.

Operating costs for the years ended December 31, 2022 and 2021 also include ongoing costs associated with the decommissioning and reclamation of retired plants and mines.

The change in Asset Closure segment results for the year ended December 31, 2022 is primarily due to (i) unrealized hedging gains of $31 million related to coal and power derivatives in the year ended December 31, 2022 compared to unrealized losses of $119 million in the year ended December 31, 2021 and (ii) severance and impairment expense recorded in the year ended December 31, 2021, in connection with plant closure announcements (see Note 3 to the Financial Statements).

Energy-Related Commodity Contracts and Mark-to-Market Activities

The table below summarizes the changes in commodity contract assets and liabilities for the years ended December 31, 2022 and 2021.

The net change in these assets and liabilities, excluding "other activity" as described below, reflects $759 million in unrealized net losses and $231 million in unrealized net gains for the years ended December 31, 2021 and 2020, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.

The net change in these assets and liabilities, excluding "other activity" as described below, reflects $2.51 billion and $759 million in unrealized net losses for the years ended December 31, 2022 and 2021, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.

Year Ended December 31,

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(a) Represents reversals of previously recognized unrealized gains and losses upon settlement/termination (offsets realized gains and losses recognized in the settlement period).

The years ended December 31, 2021 and 2020 also include reversals of $3 million and $12 million, respectively, of previously recorded unrealized losses related to commodity contracts acquired in the Merger, Crius Transaction and Ambit Transaction.

The year ended December 31, 2020 includes reversals of $1 million of previously recorded unrealized losses related to Vistra beginning balances.

Excludes changes in fair value in the month the position settled as well as amounts related to positions entered into, and settled, in the same month.

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Operating Cash Flows

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020 — Cash used in operating activities totaled $206 million in the year ended December 31, 2021 compared to cash provided by operating activities of $3.337 billion in the year ended December 31, 2020.

The unfavorable change of $3.543 billion was primarily driven by lower cash from operations due to Winter Storm Uri impacts and higher cash margin deposits posted with third-parties.

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021 — Cash provided by operating activities totaled $485 million in the year ended December 31, 2022 compared to cash used in operating activities of $206 million in the year ended December 31, 2021.

The favorable change of $691 million was primarily driven by lower cash from operations in 2021 due to Winter Storm Uri impacts and $544 million of securitization proceeds from ERCOT in 2022 (see Note 1 to the Financial Statements), partially offset by margin deposits of $1.874 billion in 2022 as compared to $1.0 billion in 2021 related to commodity contracts which support our comprehensive hedging strategy.

Depreciation and amortization — Depreciation and amortization expense reported as a reconciling adjustment in the consolidated statements of cash flows exceeds the amount reported in the consolidated statements of operations by $451 million, $297 million and $311 million for the year ended December 31, 2022, 2021 and 2020, respectively.

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Year Ended December 31, 2022 Compared to Year Ended December 31, 2021 — Cash used in investing activities totaled $1.239 billion and $1.153 billion in the years ended December 31, 2022 and 2021, respectively.

Capital expenditures totaled $1.033 billion and $1,259 million in the years ended December 31, 2021 and 2020, respectively, and.

consisted of the following:

Year Ended December 31,

The increase of $86 million was driven by a $268 million increase in capital expenditures and $50 million in lower insurance proceeds received, partially offset by $185 million in lower net purchases of environmental allowances and $57 million in proceeds from the sale of nuclear fuel.

Year Ended December 31, Increase (Decrease)

Capital expenditures, including LTSA prepayments $ (628) $ (549) (79)

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Growth and development expenditures (475) (440) (35)

Capital expenditures 1,033 $ 1,259

Cash used in investing activities in the year ended December 31, 2021 and 2020 also reflected net purchases of environmental allowances of $213 million and $339 million, respectively.

In the year ended December 31, 2021 and 2020, we received insurance proceeds of $89 million and $35 million, respectively.

Total capital expenditures (1,301) (1,033) (268)

Net sales (purchases) of environmental allowances (28) (213) 185

Net sales of (investments in) nuclear decommissioning trust fund securities (23) (22) (1)

Insurance proceeds related to capital activity 39 89 (50)

Proceeds from sale of nuclear fuel 57 — 57

Other investing activity 17 26 (9)

Cash used in investing activities $ (1,239) $ (1,153) $ (86)

Financing Cash Flows

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020 — Cash provided by financing activities totaled $2.274 billion in the year ended December 31, 2021 and cash used in financing activities totaled $1.796 billion in the year ended December 31, 2020.

The change was primarily driven by:

• proceeds of $1.975 billion from the issuance of preferred stock in 2021;

• the issuance of $1.250 billion principal amount of Vistra Operations senior unsecured notes in 2021;

• $500 million in cash received from the sale of a portion of the PJM capacity that cleared for Planning Years 2021-2022 in 2021;

• redemption of $747 million principal amount of outstanding of Vistra unsecured senior notes in 2020;

• net repayment of $350 million in short-term borrowings under the Revolving Credit Facility in 2020;

• repayment of $100 million of term loans under the Vistra Operations Credit Facilities in 2020;

partially offset by:

• $471 million in cash paid for share repurchases in 2021;

• net repayments of $300 million under the Receivables Facility in 2021 compared to net repayments of $150 million in 2020.

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021 — Cash used in financing activities totaled $80 million in the year ended December 31, 2022 compared to cash provided by financing activities of $2.274 billion in the year ended December 31, 2021.

The change of $2.354 billion was driven by the issuance of preferred stock in 2021 and higher share repurchases in 2022, partially offset by increases in net borrowings under our accounts receivable financing facilities and net short-term borrowings in 2022.

Year Ended December 31, Increase (Decrease)

Issuances of preferred stock in 2021 $ — $ 2,000 $ (2,000)

Share repurchases (1,949) (471) (1,478)

Other net borrowings (repayments), including the forward capacity agreements (251) 119 (370)

Dividends paid to common stockholders (302) (290) (12)

Dividends paid to preferred stockholders (151) — (151)

Issuance of senior secured (2022) and senior unsecured (2021) notes 1,498 1,250 248

Net borrowings (repayments) under the accounts receivable financing facilities 425 (300) 725

Net short-term borrowings (repayments) 650 — 650

Other financing activity — (34) 34

Cash provided by (used in) financing activities $ (80) $ 2,274 $ (2,354)

Debt Activity

See Note 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.

See Note 9 to the Financial Statements for details of the Receivables Facility and Repurchase Facility and Note 10 to the Financial Statements for details of the Vistra Operations Credit Facilities, the Commodity-Linked Facility and other long-term debt.

Available Liquidity

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Vistra Operations Credit Facilities — Revolving Credit Facility 1,236 1,254 (18)

Vistra Operations — Alternate Letter of Credit Facility — 5 (5)

Total available liquidity (a) $ 2,579 $ 2,399 $ 180

(a) Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively.

Vistra Operations — Commodity-Linked Facility (a) 808 — 808

Total available liquidity (b) $ 2,499 $ 2,579 $ (80)

(a) As of December 31, 2022, available capacity reflects the borrowing base of $1.208 billion less $400 million in cash borrowings.

The borrowing base is less than the facility limit of $1.35 billion.

(b) Excludes amounts available to be borrowed under the Receivables Facility and the Repurchase Facility, respectively.

See Note 9 to the Financial Statements for detail on our accounts receivable financing.

The $180 million increase in available liquidity for the year ended December 31, 2021 was primarily driven by proceeds of $1.975 billion from the issuance of preferred stock in 2021, cash received from the issuance of $1.250 billion principal amount of Vistra Operations senior unsecured notes in May 2021 and $500 million in cash received from the sale of a portion of the PJM capacity that cleared for Planning Years 2021-2022, partially offset by cash used in operations, including higher cash margin deposits posted with third parties, $1.033 billion of capital expenditures (including LTSA prepayments, nuclear fuel and development and growth expenditures), a $734 increase in letters of credit outstanding under the Revolving Credit Facility, $290 million in dividends paid to stockholders, $471 million in cash paid for share repurchases, $300 million in net cash repayments under the accounts receivable financing facilities and the maturity of a $250 million Alternate LOC Facility.

Additionally, in February 2022, we entered into a $1.0 billion senior secured commodity-linked revolving credit facility (the Commodity-Linked Facility) (see Note 11 to the Financial Statements).

Based upon our current internal financial forecasts, we believe that we will have sufficient liquidity to fund our anticipated cash requirements through at least the next 12 months.

The $80 million decrease in available liquidity for the year ended December 31, 2022 was primarily driven by $1.949 billion in cash paid for share repurchases, $1.301 billion of capital expenditures (including LTSA prepayments, nuclear fuel and development and growth expenditures), a $418 million increase in letters of credit outstanding under the Revolving Credit Facility, $302 million in dividends paid to common stockholders and $151 million in dividends paid to preferred stockholders, partially offset by cash provided by operations, cash received from the issuance of $1.5 billion principal amount of Vistra Operations senior secured notes issued, $808 million in available capacity under the Commodity-Linked Facility under the aggregate commitments in effect as of December 31, 2022, $650 million in additional aggregate commitments under the Revolving Credit Facility resulting from the Credit Agreement Amendments and $425 million in net cash borrowings under the accounts receivable financing facilities.

We believe that we will have access to sufficient liquidity to fund our anticipated cash requirements through at least the next 12 months.

Our operational cash flows tend to be seasonal and weighted toward the second half of the year.

If the Company experienced a significant reduction in revenues or increases in costs or collateral requirements, such as a result of Winter Storm Uri, the Company believes it would have additional alternatives to maintain access to liquidity, including drawing upon available liquidity, accessing additional sources of capital or reducing capital expenditures, planned voluntary debt repayments or operating costs.

Higher commodity market prices combined with our comprehensive hedging strategy have resulted in significantly increased collateral posting obligations during the year ended December 31, 2022.

The majority of this collateral relates to hedges in place through 2023 and is expected to be returned as we satisfy our obligations under those contracts.

As of February 23, 2023, Vistra had approximately $2.8 billion of cash and availability under its credit facilities to meet its liquidity needs.

The Company believes it has additional alternatives to maintain access to liquidity, including drawing upon available liquidity, accessing additional sources of capital or reducing capital expenditures, planned voluntary debt repayments or operating costs.

The maturities of our long-term debt are relatively modest until 2024.

Interest payments on long-term debt are expected to total approximately $499 million in 2022, $946 million in 2023-2024, $753 million in 2025-2026 and $372 million thereafter.

Interest payments on long-term debt are expected to total approximately $596 million in 2023, $1.082 billion in 2024-2025, $552 million in 2026-2027 and $165 million thereafter.

See Note 10 to the Financial Statements for details of our long-term debt maturities.

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• $139 million for nuclear fuel purchases;

• $72 million for information technology and other corporate investments;

• $12 million for plant winterization investment, information technology and other corporate investments;

• $151 million for other growth expenditures.

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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.

See Note 10 to the Financial Statements for discussion of the Vistra Operations Credit Facilities and the Commodity-Linked Facility.

Exchange cleared transactions typically require initial margin ( i.e.

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As of December 31, 2022, 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;

• $3.137 billion in cash has been posted with counterparties as compared to $1.263 billion posted at December 31, 2021;

• $39 million in cash has been received from counterparties as compared to $39 million received at December 31, 2021;

• $1.558 billion in letters of credit have been posted with counterparties as compared to $878 million posted at December 31, 2020;

• $2.314 billion in letters of credit have been posted with counterparties as compared to $1.558 billion posted at December 31, 2021;

• $74 million in letters of credit have been received from counterparties as compared to $35 million received at December 31, 2021.

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Income Tax Payments

In the next 12 months, we do not expect to make federal income tax payments due to Vistra's loss position in 2021 and use of NOL carryforwards.

We expect to make approximately $35 million in state income tax payments, offset by $11 million in state tax refunds, and less than $1 million in TRA payments in the next 12 months.

For the year ended December 31, 2021, there were no federal income tax payments, $52 million in state income tax payments, $2 million in state income tax refunds and $2 million in TRA payments.

In the next 12 months, we do not expect to make federal income tax payments due to Vistra's NOL carryforwards.

We expect to make approximately $27 million in state income tax payments, offset by $13 million in state tax refunds, and $8 million in TRA payments in the next 12 months.

For the year ended December 31, 2022, there was $1 million in federal income tax payments, $33 million in state income tax payments, $8 million in state income tax refunds and $1 million in TRA payments.

Capitalization

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Financial Covenants

The Credit Facilities Agreement includes a covenant, solely with respect to the Revolving Credit Facility and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $300 million) exceed 30% of the revolving commitments), that requires the consolidated first-lien net leverage ratio not exceed 4.25 to 1.00.

As of December 31, 2021, we were in compliance with this financial covenant.

The Vistra Operations Credit Agreement and the Vistra Operations Commodity-Linked Credit Agreement each includes a covenant, solely with respect to the Revolving Credit Facility and the Commodity-Linked Facility and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit exceed 30% of the revolving commitments, provided that solely with respect to the Revolving Credit Facility only such amounts in excess of $300 million are taken into account for purposes of determining whether a compliance period is in effect), that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, during a collateral suspension period, not to exceed 5.50 to 1.00).

In addition, each of the Secured LOC Facilities includes a covenant that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, for certain facilities that include a collateral suspension mechanism, during a collateral suspension period, not to exceed 5.50 to 1.00).

As of December 31, 2022, we were in compliance with the Vistra Operations Credit Agreement and Secured LOC Facilities financial covenants.

Although the period ended December 31, 2022 was not a compliance period for the Vistra Operations Commodity-Linked Credit Agreement, we would have been in compliance with this financial covenant if it was required to be tested at such time.

See Note 10 to the Financial Statements for discussion of other covenants related to the Vistra Operations Credit Facilities.

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An event of a default by Vistra Operations or any of its subsidiaries relating to indebtedness equal to or above a threshold defined in the applicable agreement that results in the acceleration of such debt, would give such counterparty under these hedging agreements the right to terminate its hedge or interest rate swap agreement with Vistra Operations (or its applicable subsidiary) and require all outstanding obligations under such agreement to be settled.

Under the Vistra Operations Senior Unsecured Indentures and the Vistra Operations Senior Secured Indenture, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more may result in a cross default under the Vistra Operations Senior Unsecured Notes, the Senior Secured Notes, the Vistra Operations Credit Facilities, the Receivables Facility, the Alternate LOC Facilities, and other current or future documents evidencing any indebtedness for borrowed money by the applicable borrower or issuer, as the case may be, and the applicable Guarantor Subsidiaries party thereto.

Under the Vistra Operations Senior Unsecured Indentures and the Vistra Operations Senior Secured Indenture, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more may result in a cross default under the Vistra Operations Senior Unsecured Notes, the Senior Secured Notes, the Vistra Operations Credit Facilities, the Receivables Facility, the Commodity-Linked Facility and other current or future documents evidencing any indebtedness for borrowed money by the applicable borrower or issuer, as the case may be, and the applicable Guarantor Subsidiaries party thereto.

Additionally, we enter into energy-related physical and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess of thresholds, which may vary by contract.

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If this cross-default provision is triggered, a termination event under the Repurchase Facility would occur and the Repurchase Facility may be terminated.

Under the Alternate LOC Facilities, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more, may result in a termination of the Alternate LOC Facilities.

Under the Secured LOC Facilities, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary for failure to pay principal when due at final maturity or that results in the acceleration of such indebtedness in an aggregate amount of $300 million or more, may result in a termination of the Secured LOC Facilities.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis