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Item 7. Management’s Discussion and Analysis

2024-02-29 compared with 2023-03-01 · 270 added, 504 removed, 364 unchanged (68% of the section changed)

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, AND RESULTS OF OPERATIONS

The discussion below, as well as other portions of this annual report on Form 10-K, contain forward-looking statements within the meaning of Section 27A of the Securities Act, Section 21E of the Exchange Act and the Private Securities Litigation Reform Act of 1995.

In addition, management may make forward-looking statements orally or in other writing, including, but not limited to, in press releases, quarterly earnings calls, executive presentations, in the annual report to stockholders and in other filings with the SEC.

Readers can usually identify these forward-looking statements by the use of such words as “may,” “will,” “should,” “likely,” “plans,” “projects,” “expects,” “anticipates,” “believes” or similar words.

These statements involve a number of risks and uncertainties.

Actual results could materially differ from those anticipated by such forward-looking statements.

For more discussion about risk factors that could cause or contribute to such differences, see Part I, Item 1A "Risk Factors" and other risks discussed herein.

Forward-looking statements reflect the information only as of the date on which they are made.

The Company does not undertake any obligation to update any forward-looking statements to reflect future events, developments, or other information.

If Vistra does update one or more forward-looking statements, no inference should be drawn that additional updates will be made regarding that statement or any other forward-looking statements.

This discussion is intended to clarify and focus on our results of operations, certain changes in our financial position, liquidity, capital structure and business developments for the periods covered by the consolidated financial statements included under Part II, Item 8 of this annual report on Form 10-K for the year ended December 31, 2022.

This discussion should be read in conjunction with those consolidated financial statements and the related notes and is qualified by reference to them.

The following discussion and analysis of our financial condition and results of operations for the years ended December 31, 2022, 2021 and 2020 should be read in conjunction with our consolidated financial statements and the notes to those statements.

The discussion and analysis of our financial condition and results of operations for the year ended December 31, 2020 and for the year ended December 31, 2021 compared to the year ended December 31, 2020 are included in Item 7.

Management's Discussion and Analysis of Financial Condition and Results in our 202 1 Form 10-K and are incorporated herein by reference.

The following discussion and analysis of our financial condition and results of operations should be read together with our consolidated financial statements and related notes included in Item 8.

Financial Statements and Supplementary Data .

Management's Discussion and Analysis of Financial Condition, and Results of Operations in our 202 2 Form 10-K for a discussion of our financial condition and results of operations for the year ended December 31, 2021 and for the year ended December 31, 2022 compared to the year ended December 31, 2021, which is incorporated here by reference.

All dollar amounts in the tables in the following discussion and analysis are stated in millions of U.S.

dollars unless otherwise indicated.

Vistra is a holding company operating an integrated retail and electric power generation business primarily in markets throughout the U.S.

Through our subsidiaries, we are engaged in competitive energy market activities including electricity generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity and natural gas to end users.

Operating Segments

Vistra has six reportable segments:

(i) Retail, (ii) Texas, (iii) East, (iv) West, (v) Sunset and (vi) Asset Closure.

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

CEO Transition

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

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

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

Burke and the Board until April 30, 2023.

The transition from Mr.

Morgan to Mr.

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

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

Significant Activities and Events, and Items Influencing Future Performance

Climate Change, Investments in Clean Energy and CO 2 Reductions

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

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

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

Risk Factors – Regulatory and Legislative Risks and Note 12 to the Financial Statements.

However, such rules and the regulatory environment are continuing to evolve and change, and we cannot predict the ultimate effect that such changes may have on our business.

Emissions Reductions — Vistra is targeting to achieve a 60% reduction in Scope 1 and Scope 2 CO 2 equivalent emissions by 2030 as compared to a 2010 baseline with a long-term goal to achieve net-zero carbon emissions by 2050, assuming necessary advancements in technology and supportive market constructs and public policy.

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

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

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

Solar Generation and Energy Storage Projects —

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

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

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

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

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

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

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

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

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

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

Comanche Peak Nuclear Plant License Renewal

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

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

Proposed Merger with Energy Harbor

On March 6, 2023, Vistra Operations and its wholly-owned subsidiary (Merger Sub) entered into a Transaction Agreement with Energy Harbor pursuant to which, upon the terms and subject to the conditions thereof, Merger Sub will be merged with and into Energy Harbor, with Energy Harbor surviving as an indirect subsidiary of Vistra.

The Transaction Agreement, the Merger and the other Transactions were approved by each of Vistra's Board and Energy Harbor's board of directors.

On February 16, 2024, we received approval from FERC to acquire Energy Harbor.

FERC's approval was the last regulatory approval needed, and we anticipate closing on March 1, 2024.

See Note 2 to the Financial Statements for more information concerning the Transaction Agreement.

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.

enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, including a nuclear 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 further define the scope of the legislation in many important respects over the next twelve months.

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

Vistra is not subject to the CAMT in the 2023 tax year since it only applies to corporations that have a three-year average annual adjusted financial statement income in excess of $1 billion.

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.

See Note 1 for our accounting policy related to refundable and transferable PTCs and ITCs.

Repurchase of TRA Rights and Preferred Stock Issuance

On December 29, 2023, Vistra repurchased (Repurchase) approximately 74% of the outstanding beneficial interests in the TRA Rights to receive payments under the TRA from a select group of registered holders of the TRA Rights (Selling Holders) in exchange for consideration of $1.50 per repurchased TRA Right, totaling an aggregate purchase price for the Repurchase of approximately $476 million.

The shares of Series C Preferred Stock were issued (see Note 15 to the Financial Statements) to the Selling Holders in exchange for the TRA Rights in a transaction exempt from registration pursuant to Section 4(a)(2) of the Securities Act.

As part of the transaction, on January 29, 2024, the Company filed a shelf registration statement on Form S-3 registering the resale of the shares by the Selling Holders of Series C Preferred Stock from time to time under Rule 415 of the Securities Act.

If the Company repurchases TRA Rights at any time during the 180 days following December 29, 2023 at a price per TRA Right greater than $1.50, the Company will pay the Selling Holders an amount equal to such excess purchase price per TRA Right sold by the Selling Holders.

On January 11, 2024, Vistra repurchased an additional 43,494,944 TRA Rights from a select group of registered holders of TRA Rights in exchange for consideration of $1.50 per repurchased TRA Right.

Total consideration of $65 million was paid using cash on hand.

On January 31, 2024, Vistra announced a cash tender offer to purchase any and all outstanding TRA Rights in exchange for consideration of $1.50 per tendered TRA Right accepted for purchase prior to close of business on February 13, 2024 (Early Tender Date), which included an early tender premium of $0.05 per TRA Right accepted for purchase.

As of the Early Tender Date, 55,056,931 TRA Rights were accepted for purchase for total consideration of $83 million, which was paid using cash on hand.

TRA Rights accepted for purchase after the Early Tender Date, but prior to the close of business on February 28, 2024, will receive consideration of $1.45 per TRA Right accepted for purchase, which will be paid in March 2024 using cash on hand.

As of the Early Tender Date, we have repurchased an aggregate 98% of the original outstanding TRA Rights, of which 10,430,083 TRA Rights remain outstanding.

See Note 8 to the Financial Statements for details of the TRA and Note 15 to the Financial Statements for details of the Series C Preferred Stock.

Financial and Operating Performance

The following are financial and operating highlights we achieved in the execution of our four strategic priorities:

Long-term, attractive earnings profile through the integrated business model.

• We continued to execute our integrated business model through exceptional operational performance and capitalization of market opportunities which drove strong earnings during the year ended December 31, 2023, highlighting our competitive advantage of coupling retail with our reliable and efficient generation fleet and wholesale commodity risk management capabilities which reduces the effects of commodity price movements and contributes to the stability and predictability of our cash flows.

• Our commercial team focused on effectively and efficiently managing risk by opportunistically hedging for 2023 and beyond and optimizing our assets and business positions which led to strong plant operating performance and energy margins.

• Our retail brands served the retail electricity and natural gas needs of end-use residential, small business and commercial and industrial electricity customers through multiple sales and marketing channels through products and solutions that differentiate from our competitors leading to an increase in residential customer counts within markets we continue to operate.

Strategic energy transition that supports the reliability and affordability of electricity.

• In June 2023, an additional 350 MW battery ESS at our Moss Landing Power Plant site commenced commercial operations.

• As of June 30, 2023, the net proceeds of our Series B Preferred Stock were fully allocated to eligible solar and battery projects, pursuant to our Green Finance Framework.

• We continued development and construction activities on the planned development of up to 300 MW of solar photovoltaic power generation facilities and up to 150 MW of battery ESS at retired or to-be-retired plant sites in Illinois.

• We retired our Edwards coal generation plant on January 1, 2023.

Significant and consistent shareholder return of capital.

• During the year ended December 31, 2023, we paid dividends to common stockholders totaling $313 million.

• During the year ended December 31, 2023, we repurchased 45 million shares for $1.3 billion under our stock repurchase program.

Total shares repurchased under the program established in October 2021 are 143 million shares for $3.5 billion.

See Note 15 to the Financial Statements for more information about our dividend and Share Repurchase Program.

Maintaining a strong balance sheet.

• In December 2023, we issued $400 million of 6.950% Senior Secured Notes due 2033 and $350 million of 7.750% Senior Unsecured Notes due 2031 in which the net proceeds were used to fund the tender offer (Senior Secured Notes Tender Offer) to purchase for cash $759 million aggregate principal amount of certain notes in January 2024, including $58 million of 4.875% Senior Secured Notes due 2024, $345 million of 3.550% Senior Secured Notes due 2024 and $356 million of the 5.125% Senior Secured Notes due 2025.

During the year ended December 31, 2023, 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 strong plant operating performance, summer scarcity pricing events in Texas and effectiveness of our comprehensive hedging strategy and the value we were able to lock in as forward power and natural gas curves increased beginning in 2022.

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.

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 received $544 million in proceeds from ERCOT in the second quarter of 2022.

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

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

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

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

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

contracting for incremental gas storage to support its gas fleet;

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

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

and engaging in processes to evaluate potential market reforms.

Dividend Program

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

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

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

Share Repurchase Program

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

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

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

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

$3.25 Billion Board Authorization

Total Number of Shares Repurchased Average Price Paid

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

Year Ended December 31, 2021

19,330,365 $ 21.16 $ 409

Year Ended December 31, 2022

78,470,547 23.40 1,836

Total repurchased through December 31, 2022

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

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

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

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

Preferred Stock Offerings

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

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

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

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

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

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

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

Debt Activity

We have stated our objective to reduce our consolidated net leverage.

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

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

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

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

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

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

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

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

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

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

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

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

With forward power and natural gas curves increasing during 2022 and the continued volatility in 2023, we have increased our hedging for future periods.

As of December 31, 2023, we have hedged approximately 91% of our expected generation volumes on average for the two-year period 2024 through 2025 (with approximately 98% hedged for 2024 and approximately 83% hedged for 2025).

The industry continues to experience supply chain constraints that have 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.

The inflationary environment continues to drive elevated interest rates, resulting in increased expected refinancing or borrowing costs, including project financing for our development projects and refinancing expected in connection with debt due in 2024 and beyond.

We are closely monitoring developments in the Russia and Ukraine conflict, specifically with regards to, (i) sanctions (or potential sanctions) against Russian energy exports and Russian nuclear fuel supply and enrichment activities, and (ii) actions by Russia to limit energy deliveries, which may further impact commodity prices in Europe and globally.

In addition, current policies being considered by the U.S.

Congress, namely H.R.

1042 the Prohibiting Russian Uranium Imports Act, would restrict imports of uranium if signed into law.

The bill passed out of the House of Representatives in December 2023, and the future of the bill remains uncertain as it awaits consideration in the Senate.

Our 2024 refueling has not been affected by the Russia and Ukraine conflict, nor have we seen any disruption to the delivery of nuclear fuel.

We are taking affirmative action by building strategic inventory and deploying mitigating strategies in our procurement portfolio to ensure we can secure the nuclear fuel needed to continue to operate our nuclear facility through potential Russian supply disruption.

We work with a diverse set of global nuclear fuel cycle suppliers to procure our nuclear fuel years in advance, and therefore, we expect to have enough nuclear fuel to support all our refueling needs, including the Energy Harbor facilities following the expected closing of the Transactions, through 2027.

If imports from Russia are restricted, refueling operations of U.S.

merchant nuclear power generators could be challenged in future years.

Capacity Markets

PJM — Reliability Pricing Model (RPM) auction results, for the zones in which our assets are located, are as follows for each planning year:

PJM, NYISO, ISO-NE, MISO and CAISO ensure long-term grid reliability through monthly, semiannual, annual and multi-year capacity auctions or bilateral transactions where power suppliers commit to making the generation resources available to the ISO as needed for a specific time period.

We participate in these capacity market auctions and also enter into bilateral capacity sales, and a portion of our East, West and Sunset segment revenues are impacted by the capacity auction results or bilateral contracts.

The following information summarizes the auction pricing for zones in which we operate as well as our capacity auction and bilateral capacity sales by planning period.

Performance incentive rules increase capacity payments for those resources that are providing excess energy or reserves during a shortage event, while penalizing those that produce less than the required level.

Reliability Pricing Model (RPM) auction results, for the zones in which our assets are located, are as follows for each planning year:

2023-2024 2024-2025

8 unchanged sentences

2023-2024 2024-2025

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

Segment Sunset Segment East

Segment Sunset Segment

CP auction capacity sold, net (MW) 5,811 1,667 5,567 1,338

3 unchanged sentences

Average price per MW-day $ 38.61 $ 36.82 $ 36.80 $ 75.11

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:

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:

Price per kW-month $ 3.83

8 unchanged sentences

Average price per kW-month $ 2.27 $ 3.80 $ 3.44 $ 4.10 $ 4.10

ISO-NE — The most recent Forward Capacity Auction results for ISO-NE Rest-of-Pool, in which most of our assets are located, are as follows for each planning year:

The most recent Forward Capacity Auction results for ISO-NE Rest-of-Pool, in which most of our assets are located, are as follows for each planning year:

2023-2024 2024-2025 2025-2026 2026-2027 2027-2028

Price per kW-month $ 2.00 $ 2.61 $ 2.59 $ 2.59 $ 3.58

We continue to market and pursue longer term multi-year capacity transactions that extend through planning year 2027-2028.

5 unchanged sentences

Average price per kW-month $ 2.22 $ 3.12 $ 2.72 $ 2.60 $ 3.58

MISO — The capacity auction results for MISO Local Resource Zone 4, in which our assets are located, are as follows for each planning year:

The capacity auction results for MISO Local Resource Zone 4, in which our assets are located, are as follows for each planning year:

Price per MW-day $ 9.25

6 unchanged sentences

Average price per kW-month $ 4.36 $ 4.34 $ 4.94 $ 4.59

CAISO — Our capacity sales in CAISO, aggregated by calendar year for 2023 through 2024 for Moss Landing, are as follows:

Our capacity sales as part of the California Public Utilities Commission Resource Adequacy (RA) Program in California, aggregated by calendar year for 2024 through 2027 for Moss Landing, are as follows:

2024 2025 2026 2027

Bilateral capacity sold (Avg MW) 1,880 1,770 1,250 750

Key Operational Risks and Challenges

Following is a discussion of certain key operational risks and challenges facing management and the initiatives currently underway to manage such challenges.

These matters involve risks that could have a material effect on our business, results of operations, liquidity, financial condition, cash flows, reputation, prospects and the market price for our securities (including our common stock).

See also Item 1A.

Risk Factors in this annual report on Form 10-K for additional discussion on risks that could have a material effect on our results of operations, liquidity, financial condition, cash flows, reputation, prospects and the market price for our securities (including our common stock).

Natural Gas Price and Market Heat Rate Exposure

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

Natural gas prices have historically been volatile.

Electricity Prices

The price of electricity has a significant impact on our operating revenues and purchased power costs.

Electricity prices are typically set by the cost to fuel a generation facility and the amount of fuel needed to generate one unit of electricity (Heat Rate) from the generation facility.

Market Heat Rate is the implied relationship between wholesale electricity prices and the commodity price of the marginal supplier (generally natural gas plants).

Wholesale electricity prices generally track to increases or decreases in the price of natural gas, with exceptions such as when ERCOT power prices rise significantly during weather events as a result of the scarcity of available generation resources relative to power demand.

The price of natural gas is volatile;

therefore, the costs to operate a natural gas-fueled generation facility can be volatile as well.

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

Consequently, all other factors being equal, these nuclear-, lignite- and coal-fueled generation assets increase or decrease in value as wholesale electricity prices change either as a result of changes in natural gas prices or market heat rates, because of the effect on our operating margins.

A persistent decline in the price of natural gas, if not offset by an increase in market heat rates, would likely have a material adverse effect on our results of operations, liquidity and financial condition, predominantly related to the production of power generation volumes in excess of the volumes utilized to service our retail customer load requirements and wholesale hedges.

however, all other factors being equal, changes in natural gas prices affect our operating margins on these facilities as electricity prices generally track to natural gas prices.

Other variables that could impact electricity prices include, but are not limited to, the price of other fuels, generation resources in the region, weather, on-going competition, emerging technologies, and macroeconomic and regulatory factors.

The wholesale market price of electricity divided by the market price of natural gas represents the Market Heat Rate.

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However, increasing penetration of renewable generation capacity may also contribute to greater volatility of wholesale market prices independent of changes in the price of natural gas, given their intermittent nature.

Decreases in market heat rates decrease the value of our generation assets because lower market heat rates result in lower wholesale electricity prices, and vice versa.

As a result of our exposure to the variability of natural gas prices and Market Heat Rates, retail sales and hedging activities are critical to our operating results and maintaining consistent cash flow levels.

Our integrated power generation and retail electricity business provides us opportunities to hedge our generation position utilizing retail electricity markets as a sales channel.

In addition, our approach to managing electricity price risk focuses on the following:

Our approach to managing electricity price risk focuses on the following:

• employing disciplined, liquidity-efficient hedging and risk management strategies through physical and financial energy-related contracts intended to partially hedge gross margins;

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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 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:

Nuclear/Renewable/Coal Generation:

Texas 94 % 86 %

Sunset 88 % 47 %

Gas Generation:

Texas 83 % 58 %

East 91 % 72 %

West 91 % 79 %

The following sensitivity table provides approximate estimates of the potential impact of movements in power prices and spark spreads (the difference between the power revenue and fuel expense of natural gas-fired generation as calculated using an assumed heat rate of 7.2 MMBtu/MWh) on realized pre-tax earnings (in millions) taking into account the hedge positions noted above for the periods presented.

The residual gas position is calculated based on two steps:

first, calculating the difference between actual heat rates of our natural gas generation units and the assumed 7.2 heat rate used to calculate the sensitivity to spark spreads;

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

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

Nuclear/Renewable/Coal Generation:

$2.50/MWh increase in power price $ 8 $ 16

Nuclear/Renewable/Coal Generation:

$2.50/MWh decrease in power price $ (7) $ (16)

Gas Generation:

$1.00/MWh increase in spark spread $ 9 $ 19

Gas Generation:

$1.00/MWh decrease in spark spread $ (8) $ (18)