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Item 7. Management’s Discussion and Analysis

2025-02-28 compared with 2024-02-29 · 336 added, 292 removed, 342 unchanged (65% of the section changed)

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

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.

The following discussion and analysis of our financial condition and results of operations should be read together with the 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 3 Form 10-K for a discussion of our financial condition and results of operations for the year ended December 31, 2022 and for the year ended December 31, 2023 compared to the year ended December 31, 2022, 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.

The Sunset segment was eliminated in the fourth quarter of 2024, resulting in the recast of results for four coal facilities to the East segment and one coal facility to the Texas segment (see Note 19 to the Financial Statements).

The recast is reflected in the results of operations for the years ended December 31, 2024 and 2023.

The re-segmentation did not result in a material change in the reported results for the East and Texas segments for the year ended December 31, 2023 compared to the year ended December 31, 2022.

Significant Activities and Events, and Items Influencing Future Performance

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

Merger with Energy Harbor

On March 1, 2024 (Merger Date), pursuant to a transaction agreement dated March 6, 2023 (Transaction Agreement), (i) Vistra Operations transferred certain of its subsidiary entities into Vistra Vision, (ii) Black Pen Inc., a wholly owned subsidiary of Vistra, merged with and into Energy Harbor, (iii) Energy Harbor became a wholly-owned subsidiary of Vistra Vision, and (iv) affiliates of Nuveen Asset Management, LLC (Nuveen) and Avenue Capital Management II, L.P.

(Avenue) exchanged a portion of the Energy Harbor shares held by Nuveen and Avenue for a 15% equity interest of Vistra Vision (collectively, Energy Harbor Merger).

The Energy Harbor Merger combined Energy Harbor's and Vistra's nuclear and retail businesses and certain Vistra Zero renewables and energy storage facilities to provide diversification and scale across multiple carbon-free technologies (dispatchable and renewables/storage) and the retail business.

The cash consideration for Energy Harbor Merger was funded by Vistra Operations using a combination of cash on hand and borrowings under the Commodity-Linked Facility, the Receivables Facility and the Repurchase Facility.

See Note 2 to the Financial Statements.

Acquisition of Noncontrolling Interest

On September 18, 2024 (the UPA Transaction Date), Vistra Operations and Vistra Vision Holdings I LLC, an indirect subsidiary of Vistra Operations (Vistra Vision Holdings), entered into separate Unit Purchase Agreements (as amended, the UPAs) with each of Nuveen and Avenue, pursuant to which Vistra Vision Holdings agreed to purchase each of Nuveen's and Avenue's combined 15% noncontrolling interest in Vistra Vision for approximately $3.2 billion in cash (collectively, the Transaction).

The Transaction closed on December 31, 2024 (the Closing Date) and Vistra Vision Holdings now owns 100% of the equity interests in Vistra Vision.

See Note 9 to the Financial Statements.

Nuclear Plant License Renewals

In July 2024, our application for license renewal at our two-unit Comanche Peak Nuclear Plant was approved by the NRC.

The licenses for Units 1 and 2 now extend into 2050 and 2053, respectively, an additional 20 years beyond our original licenses.

In 2023, the Perry Nuclear Plant filed a license extension application to operate through 2046, an additional 20 years beyond the existing license.

A decision from the NRC is expected in late 2025.

Planned Gas-Fueled Dispatchable Power in ERCOT

In May 2024, we announced our intention to add up to 2,000 MW of dispatchable, natural gas-fueled electricity capacity in west, central, and north Texas consisting of the following projects:

• Building up to 860 MW of advanced simple-cycle peaking plants to be located in west Texas to support the increasing power needs of the region, including the state's oil and gas industry.

• Repowering the coal-fueled Coleto Creek Power Plant near Goliad, Texas, set to retire in 2027 to comply with EPA rules, as a natural-gas fueled plant with up to 600 MW of capacity.

• Completing upgrades at existing natural gas-fueled plants that will add more than 500 MW of summer capacity and 100 MW of winter capacity.

Our announced plan is based on market reforms that policymakers passed in the 2023 Texas legislative session, which ERCOT and the PUCT are currently implementing.

These market reforms are focused on grid reliability and proper market signals.

If successfully implemented, they could offer the regulatory framework necessary for Vistra to confidently make the long-term investments in these capacity projects.

In addition, in July 2024, we filed applications with the PUCT under the Texas Energy Fund loan program seeking financing for the 860 MW of new advanced simple-cycle peaking plants referenced above.

In August 2024, the PUCT notified Vistra that an application for one of its west Texas advanced simple-cycle peaking plants was selected for due diligence as part of the Texas Energy Fund loan program, which is ongoing.

Vistra's other application for a second west Texas gas plant remains active.

An invitation to due diligence does not mean an applicant is awarded a loan.

Vistra's decision to move forward with the new west Texas gas plant project is contingent upon supportive market reforms, approval of our Texas Energy Fund loan application, and other factors, including state and federal environmental regulations and long-term wholesale trends that continue to support gas generation.

Moss Landing 300 Battery and Martin Lake Unit 1 Updates

In January 2025, a fire occurred at our Moss Landing 300 MW battery energy storage facility in CAISO.

We are still investigating the cause and impacts, but expect to write off approximately $400 million of plant value to depreciation expense in the first quarter of 2025, representing the facility's remaining net book value.

Moss Landing 300 is part of the Moss Landing complex, which includes two other battery facilities and a gas plant, with an aggregate book value of approximately $1 billion including Moss Landing 300.

While the gas plant is operational, the other two battery facilities remain offline as we investigate the fire.

Additional costs incurred from the events include loss of revenue from the facilities being offline, and may include litigation costs and penalties under contracts.

We will continue to assess if a triggering event has occurred to evaluate impairment for the other complex assets.

On November 27, 2024, we experienced a fire at Unit 1 of our Martin Lake facility in ERCOT, an 815 MW unit.

The depreciation expense associated with the damaged property was less than $1 million.

We currently expect the unit to return to service in June 2025.

We expect to recover a significant portion of the direct losses incurred from each event through property damage insurance and business interruption insurance.

However, given uncertainty in timing of recoveries and potential indirect impacts to other facilities, we cannot predict the net impact these events will have on our results of operations for 2025.

Inflation Reduction Act of 2022 (IRA)

In August 2022, the U.S.

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.

enacted the IRA, which, among other things, implements substantial new and modified energy tax credits, including recognizing the value of existing carbon-free nuclear power by providing for a nuclear PTC, a solar PTC, and a first-time stand-alone battery storage investment tax credit.

The IRA also implements a 15% corporate alternative minimum tax (CAMT) on book income of certain large corporations, and a 1% excise tax on net stock repurchases.

The section 45U nuclear PTC is available to existing nuclear facilities from 2024 through 2032 and provides a federal tax credit of up to $15 per MWh, subject to phase out as power prices increase above $25 per MWh (each subject to annual inflation adjustments).

The Company accounts for transferable ITCs and PTCs we expect to receive by analogy to the grant model within International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance .

As discussed in Note 4, we recognized transferable nuclear PTC revenues of $545 million in the year ended December 31, 2024.

Treasury regulations are expected to further define the scope of the legislation in many important respects, including critical guidance interpreting the nuclear PTC.

This guidance could have a material impact on our estimate and would be reflected as a change in estimate in the period in which the guidance is received.

We do not expect Vistra to be subject to the CAMT in the 2024 tax year as it applies only to corporations with 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.

Financial and Operating Performance

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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.

• We continued to execute our integrated business model through exceptional operational performance by capitalizing on market opportunities that drove strong earnings for the year ended December 31, 2024.

This highlights 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 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 with products and solutions that differentiates Vistra from our competitors.

Disciplined capital allocation.

• During the year ended December 31, 2024, we paid dividends to common stockholders totaling $305 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.

• In February 2024 and October 2024, the Board authorized incremental amounts of $1.5 billion and $1.0 billion, respectively, under our stock repurchase program established in October 2021.

During the year ended December 31, 2024, we repurchased 16.6 million shares for $1.2 billion under the program.

Through February 24, 2025, total shares repurchased under the program totaled 160 million shares for $4.9 billion, and we have $1.9 billion available for additional repurchases under the program (see Note 16 to the Financial Statements).

Maintaining a resilient balance sheet.

• We further diversified our sources of liquidity and improved associated borrowing costs and credit terms through a number of enhancements and amendments to our facilities throughout the year, including (i) the expansion and extension of both our Revolving Credit Facility (expanded by $265 million and extended to 2029) and our Commodity-Linked Facility (expanded facility limit by $175 million and extended to October 2025), (ii) amending both the Vistra Operations Term Loan B-3 Facility and the Vistra Zero Term Loan B Facility to reduce the fixed spread interest by 25 and 75 basis points, respectively, (iii) establishing a $500 million alternative letter of credit facility, and (iv) expanding and extending the Receivables Facility (expanded the purchase limit by $250 million and extended to July 2025).

• In April 2024, we issued $500 million of 6.000% senior secured notes due 2034 and $1.0 billion of 6.875% senior unsecured notes due 2032.

The net proceeds from these issuances were used to refinance senior secured debt maturities in May 2024 and July 2024 and for general corporate purposes.

• In December 2024, we issued $500 million of 5.050% senior secured notes due 2026 and $750 million of 5.700% senior secured notes due 2034.

The net proceeds from these issuances were or will be used for general corporate purposes, including to refinance senior secured debt maturities in May 2025 and payments associated with the Transaction for the purchase of the remaining interest in Vistra Vision.

• In December 2024, we entered into the BCOP Credit Agreement to fund the development of solar generation and battery ESS facilities in Illinois and Texas.

Strategic energy transition focused on the reliability, affordability, and sustainability of electric grid.

• In March 2024, we completed the acquisition of Energy Harbor, adding an additional 4,048 MW of nuclear generation to our fleet.

• We reached commercial operations for two solar facilities totaling 112 MW of capacity at retired plant sites in Illinois and continued development and construction activities on additional facilities in Texas and at retired or to-be-retired plant sites in Illinois.

• We announced plans to repower the Coleto Creek coal generation facility as a natural gas-fueled facility upon its retirement no later than 2027.

During the year ended December 31, 2024, 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.

Our performance reflected strong plant operating performance, growth of our retail business and the effectiveness of our comprehensive hedging strategy.

Macroeconomic Conditions

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.

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.

Historically, the base case assumption for U.S.

electricity demand was for modest growth driven by the interplay of growth in population, industrial activity (such as an on-shore manufacturing) and new demand sources (such as electric vehicles), partially offset by continued advancements in energy efficiency.

Multiple demand drivers such as emergence of large load data centers and electrification of oil field operations (specifically in the Permian Basin of west Texas), are expected to continue to accelerate load growth in the geographic regions we serve.

We are in various discussions with interested counterparties for the potential sale of power from our nuclear and gas facilities pursuant to long-term agreements to supply large load facilities.

Such potential transactions are subject to certain risks and uncertainties, including potential regulatory review and/or approval and adverse legislative action, which could impact the timing of, and our ability to consummate, any potential transaction.

The industry continues to experience supply chain constraints and labor shortages that have reduced the availability of certain equipment and supply relevant to construction of new generation facilities, and increased (i) the lead time to procure certain materials necessary to maintain, and (ii) the labor costs associated with maintenance activity on our natural gas, nuclear and coal fleet.

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 IRA.

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.

The inflationary environment continues to drive elevated interest rates, resulting in increased refinancing or borrowing costs, including future non-recourse financing for our development projects and future refinancing expected in connection with future debt maturities.

We continue to closely monitor 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.

The Prohibiting Russian Uranium Imports Act (PRUI Act) was approved by Congress, signed into law by President Biden, and took effect on August 11, 2024.

The PRUI Act prohibits importation of Russian uranium;

however, the Department of Energy can issue waivers (subject to decreasing annual caps) until December 31, 2027 if there is no alternate source of low-enriched uranium available to keep U.S.

nuclear reactors operating or is in the national interest.

Additionally, passage of the PRUI Act enabled the allocation of $2.72 billion in federal funding to ramp up production of domestic uranium fuel.

On November 15, 2024, the Russian Federation temporarily suspended shipments of uranium to the U.S., stating that they would grant future export licenses on a case-by-case basis.

Our 2024 and 2025 refueling plans have not been affected by the Russia and Ukraine conflict, nor have we seen any disruption to the delivery of nuclear fuel impacting our refueling schedules.

We work with a diverse set of global nuclear fuel cycle suppliers to procure our nuclear fuel years in advance.

We have nuclear fuel contracted to support all our refueling needs through 2029.

We continue to take 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 facilities through potential Russian supply disruption.

Capacity Markets

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.

We participate in these capacity market auctions and also enter into bilateral capacity sales, and a portion of our East, and West 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.

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2024-2025 2025-2026

Segment Sunset Segment East

Segment Sunset Segment

CP auction capacity sold, net (MW) 9,935 10,255

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MISO capacity sales through planning year 2027-2028 are as follows:

Sunset Segment

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

Bilateral capacity sold in MISO (MW) 1,702 984 423 101

Auction capacity sold (MW) 1,095 — — —

Bilateral capacity sold (MW)

682 891 515 24

Total MISO segment capacity sold (MW)

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Our capacity sales as part of the California Public Utilities Commission Resource Adequacy (RA) Program in California, aggregated by calendar year for 2025 through 2028 for Moss Landing, are as follows:

2024 2025 2026 2027

Bilateral capacity sold (Avg MW) 1,816 1,575 1,275 750

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Critical Accounting Estimates

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

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

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

See Note 1 of the consolidated financial statements for a description of our accounting policies.

The following is a discussion of our most critical accounting estimates, judgments and uncertainties that are inherent in our application of GAAP.

Business Combinations

Determining fair values of assets acquired and liabilities assumed in the Energy Harbor Merger requires significant estimates and judgments.

We determined fair value based on the estimated price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

See Note 2 to the Financial Statements.

The determination of the fair value of property, plant, and equipment contributed and acquired, as well as nuclear decommissioning asset retirement obligations required the most significant level of estimation uncertainty.

The fair value of each power plant acquired in the Energy Harbor Merger and the fair value of the contributed nuclear business was estimated using a combination of the income approach and the market approach.

The income approach was based on the discounted cash flow method, incorporating (i) our estimates of forecasted future growth and long-term prices of electricity, capacity, and nuclear fuel, and (ii) financial performance including revenues, gross margins, operating expenses, taxes, working capital, and capital asset requirements.

Projected cash flows were then discounted to a present value employing a discount rate that accounts for the estimated market weighted-average cost of capital, along with any risks unique to the subject cash flows.

These estimates are subjective in nature and require judgment to interpret market data.

The market valuation method utilized prices paid for reasonably similar assets by other purchasers in the relevant market, with adjustments relating to physical differences in the asset as well as their locations.

See Asset Retirement Obligations (ARO) critical accounting estimate for methodology and assumptions used to estimate the nuclear decommissioning ARO acquired in the Energy Harbor Merger.

Derivative Instruments and Mark-to-Market Accounting

We enter into contracts for the purchase and sale of energy-related commodities, and also enter into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks.

We enter into contracts for the purchase and sale of energy-related commodities, as well as other derivative instruments such as options, swaps, futures, and forwards, primarily to manage commodity price and interest rate risks.

Under accounting standards related to derivative instruments and hedging activities, these instruments are subject to mark-to-market accounting, and the determination of market values for these instruments is based on numerous assumptions and estimation techniques.

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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 16 to the Financial Statements.

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

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 17 to the Financial Statements for further discussion regarding derivative instruments.

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

See Notes 11 and 12 to the Financial Statements for additional information.

Accounting for Income Taxes

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In management's opinion, the liability recorded pursuant to income tax accounting guidance related to uncertain tax positions reflects future taxes that may be owed as a result of any examination.

See Notes 1 and 7 to the Financial Statements for further discussion of income tax matters.

Accounting for Tax Receivable Agreement (TRA)

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

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

Vistra reflected the obligation associated with TRA Rights at fair value in the amount of $574 million as of the Effective Date related to these future payment obligations.

In December 2023, we repurchased approximately 74% of the TRA Rights to receive payments under the TRA from a select group of registered holders of the TRA Rights.

Also, during the year ended December 31, 2023, we recorded an increase to the carrying value of the TRA obligation totaling $82 million as a result of adjustments to forecasted taxable income due to increases in longer-term commodity price forecasts.

As of December 31, 2023, the TRA obligation has been adjusted to $171 million, and the expected undiscounted federal and state payments under the TRA is estimated to be approximately $350 million.

After giving effect to the January 2024 additional repurchases and the January and February 2024 early tender offer repurchases, we have repurchased an aggregate 98% of the original outstanding TRA Rights, of which 10,430,083 TRA Rights remain outstanding as of the Early Tender Date.

The TRA obligation value is the discounted amount of projected payments to be made each year under the TRA, based on certain assumptions, including but not limited to:

• the amount of tax basis related to (i) the Lamar and Forney acquisition and (ii) step-up resulting from the PrefCo Preferred Stock Sale (which is estimated to be approximately $5.5 billion) and the allocation of such tax basis step-up among the assets subject thereto;

• the depreciable lives of the assets subject to such tax basis step-up, which generally is expected to be 15 years for most of such assets;

• a blended federal/state corporate income tax rate in all future years of 23.2%;

• future taxable income by year for future years;

• the Company generally expects to generate sufficient taxable income to be able to utilize the deductions arising out of (i) the tax basis step up attributable to the PrefCo Preferred Stock Sale, (ii) the entire tax basis of the assets acquired as a result of the Lamar and Forney Acquisition, and (iii) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA in the tax year in which such deductions arise;

• a discount rate of 15%, which represented our view at the Effective Date of the rate that a market participant would use based on the risk associated with the uncertainty in the amount and timing of the cash flows, at the time of Emergence;

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

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

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

See Note 8 to the Financial Statements.

See Notes 1 and 5 to the Financial Statements for additional information.

Asset Retirement Obligations (ARO)

As part of business combination accounting, new fair values were established for all AROs assumed in the Dynegy Merger.

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

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

An ARO liability is initially recorded at fair value when it is initially incurred and the amount of the liability can be reasonably estimated.

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.

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

On the Merger Date, we recognized ARO liabilities for the Beaver Valley, Perry and Davis-Besse nuclear plants acquired from Energy Harbor.

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 and estimates of the timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates.

We consider the following decommissioning scenarios:

(i) DECON, which assumes major decommissioning activities begin shortly after the facility ceases operations, and (ii) SAFSTOR, which assumes the nuclear facility is placed and maintained in a condition during decommissioning that allows the nuclear facility to be safely stored until subsequently decontaminated within 60 years after the facility ceases operations.

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, 2023, 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.

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 $516 million (on a nominal basis) to achieve its mining reclamation and other coal ash remediation objectives.

During the years ended December 31, 2023, 2022 and 2021, we transferred zero, $61 million and zero, respectively, in ARO obligations to third parties for remediation.

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

See Note 22 to the Financial Statements for additional discussion of ARO obligations and adjustments made to the ARO obligation estimates during the years ended December 31, 2023, 2022 and 2021.

In estimating the liability assumed in the Energy Harbor Merger, we have included an assumption that Vistra receives a license extension of 20 years from the NRC to continue to operate the Perry Nuclear Plant through 2046.

The estimates and assumptions required for the lignite mining land reclamation include, estimates such as costs to fill in mining pits and interpretation of the mining permit closure requirements.

We estimate the costs to fill in mining pits utilizing a proprietary model to determine the volume of the pit.

Our AROs are adjusted on a regular basis to reflect the passage of time and to incorporate revisions to estimates and judgments including, planned plant retirement dates, amounts and timing of future cash expenditures, discount rates, cost escalation factors, market risk premiums, inflation rates, and if applicable, experience with government regulators regarding similar obligations.

See Note 13 to the Financial Statements for additional information.

Impairment of Goodwill and Other Long-Lived Assets

We evaluate long-lived assets (including intangible assets with finite lives) for impairment, in accordance with accounting standards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances indicate that their carrying amount may not be recoverable.

For our generation assets, possible indications include an expectation of continuing long-term declines in natural gas prices and/or Market Heat Rates or an expectation that "more likely than not" a generation asset will be sold or otherwise disposed of significantly before the end of its estimated useful life.

The determination of the existence of these and other indications of impairment involves judgments that are subjective in nature and may require the use of estimates in forecasting future results and cash flows related to an asset or group of assets.

Further, the unique nature of our property, plant and equipment, which includes a fleet of generation assets with a diverse fuel mix and individual generation units that have varying production or output rates, requires the use of significant judgments in determining the existence of impairment indications and the grouping of assets for impairment testing.

See Note 22 to the Financial Statements for discussion of impairments of long-lived assets recorded in the years ended December 31, 2022, 2021 and 2020.

Recoverability of long-lived assets is determined by a comparison of the carrying amount of the long-lived asset group to the net cash flows expected to be generated by the asset group, through considering specific assumptions for forward natural gas and electricity prices, forward capacity prices, the effects of enacted environmental rules, generation plant performance, forecasted capital expenditures, forecasted fuel prices and forecasted operating costs.

Goodwill and Intangible Assets with Indefinite Useful Lives

Goodwill and intangible assets with indefinite useful lives, such as the intangible asset related to the our retail trade names are not amortized and are subject to impairment testing annually, or when events or changes in the business environment indicate that the carrying value of the reporting unit may exceed its fair value.

Evaluating goodwill and intangible assets with indefinite useful lives involves applying significant assumptions including discount rates, forecasted results for the applicable reporting unit and retail trade name, market multiples, and growth rates.

These assumptions are forward looking and could be affected by future economic and market conditions.

Accounting standards allow a company to qualitatively assess if the carrying value of a reporting unit with goodwill and retail trade name intangible asset is more likely than not less than the fair value.

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

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 reporting units and retail trade names exceeded their carrying value.

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

See Note 7 to the Financial Statements for additional information.

Long-Lived Assets

We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable.

Indicators of impairment for our generation facilities include an expectation of continuing long-term declines in natural gas prices and/or Market Heat Rates, an expectation that "more likely than not" a generation asset will be sold or otherwise disposed of significantly before the end of its estimated useful life, or additional environmental regulations significantly decrease the cash flows expected from the associated assets.

See Note 20 to the Financial Statements for additional information.

After identifying an indicator of impairment, recoverability of long-lived assets is determined by a comparison of the carrying amount of the long-lived asset group to the net cash flows expected to be generated by the asset group.

Assumptions used in our estimate of net cash flows of the asset group include, forward natural gas and electricity prices, forward capacity prices, the effects of enacted environmental rules, generation plant performance, forecasted capital expenditures, forecasted fuel prices, and forecasted operating costs.

The carrying value of such asset groups is determined to be unrecoverable if the projected undiscounted cash flows are less than the carrying value.

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Fair value is determined primarily by discounted cash flows (income approach) and supported by available market valuations, if applicable.

The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity prices, forward capacity prices, Market Heat Rates, the effects of enacted environmental rules, generation plant performance, forecasted capital expenditures and forecasted fuel prices.

Another key assumption in the income approach is the discount rate applied to the forecasted cash flows.

The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward electricity prices, forward capacity prices, Market Heat Rates, the effects of enacted environmental rules, generation plant performance, forecasted capital expenditures, forecasted fuel prices, and the discount rate applied to the forecasted cash flows.

Any significant change to one or more of these factors can have a material impact on the fair value measurement of our long-lived assets.

Additional material impairments related to our generation facilities may occur in the future if forward wholesale electricity prices decline in the markets in which we operate in or if additional environmental regulations increase the cost of producing electricity at our generation facilities.

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

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

As of December 31, 2023, our goodwill balances totaled $2.461 billion and $122 million for our Retail reporting unit and Texas Generation reporting unit, respectively.

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

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

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

On the most recent goodwill testing date, we performed a qualitative assessment and determined that it was more likely than not that the fair value of our Retail and Texas Generation reporting units exceeded their carrying value at October 1, 2023.

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, 2023, 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, 2023.

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

Nuclear PTC Revenues

Nuclear PTC revenues are accounted for by analogy to the grant model within International Accounting Standards 20, Accounting for Government Grants and Disclosures of Government Assistance.

Nuclear PTC revenues are based on annual gross receipts generated from qualifying nuclear production in the calendar year.

Treasury regulations are expected to further provide interpretive guidance on the definition of gross receipts over the next year.

Given the lack of guidance to date, we recognized 2024 nuclear PTC revenues based on our best estimate and interpretation of gross receipts which includes settled spot energy revenues and capacity revenues at each nuclear unit, and excludes any hedges.

Any interpretive guidance on the definition of gross receipts which differs from the interpretation used in our estimate could result in a material change to PTC revenues attributable to 2024 and would be reflected as a change in estimate in the period in which the guidance is received.

We have determined that we will meet the prevailing wage requirements at all our nuclear units and are eligible for the five times multiplier, which is reflected in the amount of nuclear PTC revenue recognized in 2024.

Results of Operations

Net income (loss) attributable to Vistra common stock increased $2.6 billion to income of $1.5 billion for the year ended December 31, 2023 from a loss of $1.2 billion for the year ended December 31, 2022.

Net income increased $1.32 billion to Net income of $2.812 billion for the year ended December 31, 2024 compared to the year ended December 31, 2023.

For additional information see the following discussion of our results of operations.

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therefore, it may not be possible to compare these financial measures with other companies' non-GAAP financial measures having the same or similar names.

We strongly encourage investors to review our consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

We strongly encourage investors to review the consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

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).

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Year Ended December 31, 2024

Retail Texas East West Sunset Asset

Retail Texas East West Asset

Closure Eliminations / Corporate and Other Vistra Consolidated

(in millions)

Operating revenues $ 12,797 $ 5,394 $ 5,661 $ 877 $ 1 $ (7,506) $ 17,224

Fuel, purchased power costs, and delivery fees

(10,276) (1,596) (2,698) (221) (3) 7,509 (7,285)

Operating costs (159) (996) (1,103) (72) (81) (3) (2,414)

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Selling, general, and administrative expenses

Impairment of long-lived assets — — — — (49) — — (49)

(977) (169) (148) (25) (43) (239) (1,601)

Operating income (loss) 1,271 2,052 716 473 (126) (305) 4,081

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$ 1,216 $ 2,133 $ 902 $ 471 $ (116) $ (1,794) $ 2,812

Year Ended December 31, 2023

Retail Texas East West Sunset Asset

Closure Eliminations / Corporate and Other Vistra Consolidated

Income tax expense — — — — — 655 655

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Depreciation and amortization (b) 114 686 1,278 86 — 66 2,230

102 635 647 79 62 — 68 1,593

EBITDA before Adjustments 1,384 2,773 2,171 556 (112) (175) 6,597

Year Ended December 31, 2024

Retail Texas East West Asset

Closure Eliminations / Corporate and Other Vistra Consolidated

Unrealized net (gain) loss resulting from commodity hedging transactions 52 (790) (76) (332) (9) — (1,155)

Purchase accounting impacts

— 1 (12) — — (14) (25)

Impacts of Tax Receivable Agreement (c) — — — — — (5) (5)

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Transition and merger expenses 2 1 22 — — 111 136

Impairment of long-lived assets — — — — 49 — — 49

PJM capacity performance default impacts (d) — — 3 — 6 — — 9

Winter Storm Uri impacts (e) (52) 4 — — — — — (48)

Decommissioning-related activities (d)

— 26 (91) 2 — — (63)

ERP system implementation expenses

8 7 5 1 2 — 23

Other, net 17 14 (2) 11 2 (111) (69)

Adjusted EBITDA $ 1,463 $ 2,032 $ 2,017 $ 238 $ (117) $ (94) $ 5,539

(a) Includes $36 million of unrealized mark-to-market net losses on interest rate swaps.

(b) Includes nuclear fuel amortization of $91 million in the Texas segment.

(c) Includes $29 million gain recognized on the repurchase of TRA Rights in December 2023 (see Note 8 to the Financial Statements).

(d) Represents estimate of anticipated market participant defaults or settlements on initial PJM capacity performance penalties due to extreme magnitude of penalties associated with Winter Storm Elliott.

(e) Includes the application of bill credits.

The Company incentivized certain large commercial and industrial customers to curtail their usage during Winter Storm Uri by providing bill credits for use in future periods.

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.

We estimate remaining bill credit amounts to be applied in future periods for 2024 (approximately $11 million) and 2025 (approximately $26 million).

(a) Includes $53 million of unrealized mark-to-market net gains on interest rate swaps.

(b) Includes nuclear fuel amortization of $105 million and $282 million, respectively, in the Texas and East segments.

(d) Represents net of all NDT (income) loss of the PJM nuclear facilities, ARO accretion expense for operating assets and ARO remeasurement impacts for operating assets.

For the year ended December 31, 2024, the Texas and East segments include nuclear PTC revenue estimates of $281 million and $264 million, respectively.

See Note 4 to the Financial Statements for additional information.

The following table presents Net income (loss), EBITDA, and Adjusted EBITDA for the year ended December 31, 2023:

Year Ended December 31, 2023

Retail Texas East West Sunset Asset

Retail Texas East West Asset

Closure Eliminations / Corporate and Other Vistra Consolidated

(in millions)

Operating revenues $ 10,572 $ 3,979 $ 5,890 $ 914 $ — $ (6,576) $ 14,779

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Operating income (loss) 443 344 1,753 425 (111) (193) 2,661

Year Ended December 31, 2022

Retail Texas East West Sunset Asset

Closure Eliminations / Corporate and Other Vistra Consolidated

Other income 1 35 4 21 110 86 257

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424 398 1,750 454 (6) (1,020) 2,000

Income tax benefit — — — — — — 350 350

Income tax expense — — (1) — — (507) (508)

Net income (loss)

$ 424 $ 398 $ 1,749 $ 454 $ (6) $ (1,527) $ 1,492

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

Income tax expense — — 1 — — 507 508

Interest expense and related charges (a) 20 (21) 2 (8) 5 742 740

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Unrealized net (gain) loss resulting from commodity hedging transactions 586 813 (1,586) (267) (36) — (490)

Generation plant retirement expenses — — — — 7 (3) — 4

Fresh start/purchase accounting impacts — (2) (1) — 9 — — 6

Impacts of Tax Receivable Agreement — — — — — — 128 128

Year Ended December 31, 2023

Retail Texas East West Asset

Closure Eliminations / Corporate and Other Vistra Consolidated

Impacts of Tax Receivable Agreement (c) — — — — — 135 135

Non-cash compensation expenses — — — — — 78 78

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Impairment of long-lived assets — — 49 — — — 49

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

PJM capacity performance default impacts (d) — — 9 — — — 9

Winter Storm Uri impacts (e) (52) 4 — — — — (48)

Other, net 25 (2) 72 5 (2) (113) (15)

Adjusted EBITDA $ 1,105 $ 1,834 $ 1,001 $ 263 $ (39) $ (63) $ 4,101

(a) Includes $250 million of unrealized mark-to-market net gains on interest rate swaps.

(a) Includes $36 million of unrealized mark-to-market net losses on interest rate swaps.

(b) Includes nuclear fuel amortization of $91 million in the Texas segment.

(c) Adjusted EBITDA impacts of Winter Storm Uri reflects $183 million related to 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 and $144 million related to the application of bill credits to large commercial and industrial customers that curtailed their usage during Winter Storm Uri.

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.

Operating income increased $3.838 billion to $2.661 billion in the year ended December 31, 2023 compared to the year ended December 31, 2022.

Results for the year ended December 31, 2023 were favorably impacted by $490 million in pre-tax unrealized mark-to-market gains on derivative positions due to power and natural gas forward market curves moving down in the year ended December 31, 2023 compared to $2.510 billion in pre-tax unrealized mark-to-market losses on commodity derivative positions due to power and natural gas forward market curves moving up materially in the year ended December 31, 2022.

(e) Adjusted EBITDA impacts of Winter Storm Uri reflects 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.

GAAP net income increased $1.32 billion to net income of $2.812 billion in the year ended December 31, 2024 compared to the year ended December 31, 2023.

The primary drivers for the increase in GAAP net income include:

Favorable impacts:

• An increase of $665 million in unrealized mark-to-market gains on derivative positions due to power and natural gas forward market curves moving down more significantly in Texas relative to our hedge positions in the year ended December 31, 2024 as compared to the year ended December 31, 2023.

See further information on our derivative results in Energy-Related Commodity Contracts and Mark-to-Market Activities below.

Operating results for the year ended December 31, 2023, compared to the year ended December 31, 2022 were favorably impacted by strong plant operating performance allowing us to realize the value created by our comprehensive hedging strategy, partially offset by lower than expected retail sales volumes due to unfavorable weather.

The following table presents operational performance of our retail and generation segments.

• Addition of Energy Harbor in March 2024 with results reflected in the East and Retail segments.

• An increase of $545 million in PTC revenues due to the nuclear PTC established by the IRA including $281 million and $264 million recognized in Texas and East, respectively.

See Note 4 for additional information.

• An increase in retail income driven by an increase in customer counts and higher margins.

• Expiration of legacy Vistra default service contracts in the East segment which resulted in higher-than-expected migration of customers at rates below prevailing wholesale market prices in the year ended December 31, 2023.

• A decrease of approximately $160 million of accretion and remeasurement expenses associated with the TRA obligation driven by the acquisition of substantially all TRA rights between December 2023 and February 2024.

Unfavorable impacts:

• Increase in depreciation and amortization expense driven by addition of assets acquired from Energy Harbor and reflected in East.

• Increase in interest expense driven by higher average borrowings and unrealized mark to market losses on interest rate swaps.

• Increase in selling, general, and administrative expenses in Retail segment and Corp.

and Other driven primarily by the addition of Energy Harbor.

• Increase in income tax expense driven by higher income.

Year Ended December 31,

Retail Texas East West Sunset

Retail Texas East West

2024 2023 2024 2023 2024 2023 2024 2023

Retail sales volumes (GWh):

Retail electricity sales volumes:

Retail electricity sales volumes (GWh):

Sales volumes in ERCOT 74,295 70,275

70,275 65,207

Sales volumes in Northeast/Midwest 59,066 27,147

27,147 32,882

Total retail electricity sales volumes 133,361 97,422

97,422 98,089

Production volumes (GWh):

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

A degree day compares the average of the hourly outdoor temperatures during each day to a 65° Fahrenheit base temperature.

Year Ended December 31, Year Ended December 31,

2024 2023 2024 2023

Market pricing Average Market On-Peak Power Prices ($MWh) (b):

Average ERCOT North power price ($/MWh) $ 48.30 $ 62.17 PJM West Hub $ 39.22 $ 83.59

AEP Dayton Hub $ 36.22 $ 79.51

Average NYMEX Henry Hub natural gas price ($/MMBtu) $ 2.53 $ 6.39 NYISO Zone C $ 30.38 $ 65.54

Massachusetts Hub $ 41.02 $ 92.17

Average natural gas price (a):

Indiana Hub $ 38.92 $ 82.03

TetcoM3 ($/MMBtu) $ 1.90 $ 6.81 Northern Illinois Hub $ 32.67 $ 71.76

Algonquin Citygates ($/MMBtu) $ 2.94 $ 9.16 CAISO NP15 $ 63.92 $ 93.12

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

(b) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

For the year ended December 31, 2023, other income totaled $257 million driven by a gain of $89 million from the sale of property in Freestone County, Texas recorded in the Asset Closure Segment and $86 million in interest income due to holding a material cash balance anticipating the Energy Harbor transaction closing.

For the year ended December 31, 2022, other income totaled $117 million driven by insurance proceeds of $70 million which primarily consists of business interruption claim proceeds recorded in the Texas segment.

See Note 22 to the Financial Statements.

The increase in consolidated interest expense and related charges of $372 million for the year ended December 31, 2023, compared to the year ended December 31, 2022, is primarily due to (a) unrealized mark-to-market losses on interest rate swaps of $36 million in 2023 compared to unrealized mark-to-market gains on interest rate swaps of $250 million in 2022 due to less volatility in interest rates in the year ended December 31, 2023 compared to the year ended December 31, 2022, (b) an increase in interest paid/accrued of $63 million driven by higher effective interest rates in 2023 and (c) $21 million of commitment fees related to the Commitment Letter in the year ended December 31, 2023.

See Note 22 to the Financial Statements.

The following table presents additional changes to net income (loss) and Adjusted EBITDA for the year ended December 31, 2023 compared to the year ended December 31, 2022.

Year Ended December 31, 2023 Compared to 2022

Texas East West Sunset

Favorable change in realized revenue net of fuel driven by effectiveness of comprehensive hedging

Average Power Price

Average Natural gas price

($/MMBtu) (b):

ERCOT North Hub

$ 25.89 $ 48.30 NYMEX Henry Hub

$ 2.25 $ 2.53

Higher margins driven by increase in customers and interyear timing of power supply costs

Winter Storm Uri bill credit runoff

Impacts of mild weather in 2023

ERCOT West Hub

$ 27.45 $ 49.45 Houston Ship Channel

$ 1.87 $ 2.20

Change in operating costs due primarily to change in generation volumes

PJM AEP Dayton Hub $ 30.74 $ 30.81 Permian Basin

$ 0.08 $ 1.53

Change in SG&A and other

PJM Northern Illinois Hub $ 25.46 $ 26.64 Dominion South

$ 1.67 $ 1.63

PJM Western Hub

$ 33.83 $ 33.07 Tetco ELA

$ 2.08 $ 2.27

MISO Indiana Hub $ 31.36 $ 32.98 Chicago Citygate

$ 2.12 $ 2.30

ISONE Massachusetts Hub $ 41.47 $ 36.82 TetcoM3

$ 2.07 $ 1.90

New York Zone A $ 32.66 $ 25.68 Algonquin Citygates

$ 3.03 $ 2.94

CAISO NP15 $ 40.67 $ 61.37 PG&E Citygate

$ 3.09 $ 6.09

(a) Reflects the average around-the-clock settled prices for the periods presented and does not necessarily reflect prices we realized.

(b) Reflects the average around-the-clock settled prices for the periods presented and does not reflect costs incurred by us.

Adjusted EBITDA for the year ended December 31, 2024 compared to the year ended December 31, 2023 increased by $1.438 billion.

The primary drivers for the increase include:

Year Ended December 31, 2024 Compared to 2023

Texas East (a)

(in millions)

Favorable change in realized revenue net of fuel driven by addition of Energy Harbor, including nuclear PTC revenues from the acquired nuclear facilities and rolloff of negative margin defaults service contracts in East.

Favorable change in Texas is driven by nuclear PTC revenues.

$ — $ 257 $ 1,570 $ 6

Higher retail margins driven by favorable power supply costs, customer count growth and addition of energy Harbor retail contracts, including acquired default service contracts

Favorable impact of less Winter Storm Uri bill credits applied

Increase in plant operating costs due primarily to addition of Energy Harbor in East

— (52) (490) (11)

Change in SG&A and other primarily due to increase in costs related to addition of Energy Harbor in Retail and East

(109) (7) (64) (20)

Change in Adjusted EBITDA $ 358 $ 198 $ 1,016 $ (25)

Favorable/(unfavorable) change in depreciation and amortization 43 (12) 59 (37) 4

Change in unrealized net gains (losses) on hedging activities

Increase in depreciation and amortization driven primarily by addition of Energy Harbor assets in East

(12) (45) (575) (7)

Change in unrealized net gains (losses) on hedging activities (b)

534 1,603 (1,510) 65

Impairment of long-lived assets — — 49 —

Decommissioning related activities

— (26) 91 (2)

PJM capacity performance default impacts — — 9 —

Winter Storm Uri impact (ERCOT default uplift) (89) (182) — — —

Winter Storm Uri impact

Other (including interest expenses) (36) 1 73 (14)

Change in Net income $ 792 $ 1,735 $ (847) $ 17

To supplement the amounts and explanations noted above, primary drivers of results for the year ended December 31, 2023 compared to the year ended December 31, 2022 include:

• Comprehensive hedging strategy .

See Energy-Related Commodity Contracts and Mark-to-Market Activities below.

• Winter Storm Uri impacts .

2022 GAAP and Adjusted EBITDA results continued to be materially impacted by Winter Storm Uri.

In 2022, a $189 million default uplift liability to ERCOT was extinguished and resulted in net income during the year, but had no impact on Adjusted EBITDA in 2022 as the initial liability incurred in 2021 was excluded from Adjusted EBITDA.

• SG&A expenses and other .

2023 is unfavorable compared to 2022 driven primarily by higher incentive compensation in 2023 and insurance recoveries recorded in Texas in 2022.

(a) Includes amounts associated with operations acquired in the Energy Harbor Merger beginning March 1, 2024.

(b ) See Energy-Related Commodity Contracts and Mark-to-Market Activities below for analysis of hedging strategy.

Asset Closure Segment — Year Ended December 31, 2024 Compared to Year Ended December 31, 2023

Year Ended December 31, Favorable (Unfavorable)

(in millions)

Operating revenues $ 1 $ — $ 1

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Operating costs (81) (74) (7)

Depreciation and amortization — (31) 31

Selling, general, and administrative expenses

(43) (34) (9)

Operating loss (126) (111) (15)

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Adjusted EBITDA $ (117) $ (39) $ (78)

Production volumes (GWh) — 9,401 (9,401)

For the year ended December 31, 2022, results and volumes for the Asset Closure segment include those from Edwards generation plant that we retired on January 1, 2023 and include unrealized hedging gains related to coal and power derivatives of $19 million.

Operating costs for the years ended December 31, 2023 and 2022 also include ongoing costs associated with the decommissioning and reclamation of retired plants and mines.

GAAP and Adjusted EBITDA results for 2023 are favorable to 2022 primarily due to the $89 million gain on sale of land in Freestone County, Texas.

GAAP and Adjusted EBITDA results for the year ended December 31, 2024 are unfavorable compared to the year ended December 31, 2023 primarily due to other income of $89 million from the gain on sale of property in Freestone County, Texas in 2023.

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

As forward power prices materially increased in 2022, our generation segments (Texas, East, West and Sunset) aggressively sold forward power for 2023 and future years.

While settled power prices in 2023 are lower than 2022, the strategic hedging allowed us to lock in margins for 2023 which resulted in realized revenue net of fuel above what we were able to recognize in 2022 (were mostly hedged going into 2022 so did not recognize the full benefit of settled prices).

We entered the 2023 and 2024 calendar years with more than 99% of our expected generation volumes hedged.

While settled power prices in 2024 are lower than historical averages, the strategic hedging allowed us to lock in margins above what we would have been able to realize if unhedged and are higher than the margins from hedging for the year ended December 31, 2023, which is driving the increase in realized revenue net of fuel in the generation segments along with the addition of Energy Harbor.

The forward power sales are also the drivers of the changes in unrealized gains/losses on hedging activities.

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The retail segment procures power from the generation segments to serve future load obligations and thus changes in forward power prices have an inverse effect on unrealized mark to market for the retail segment as compared to the generation segments.

This is evident in 2022 as material increase in forward power prices drove material unrealized losses in our generation segment, partially offset by unrealized gains in our retail segment.

In 2023, forward power prices decreased slightly which resulted in unrealized gains in our generation segments which is partially offset by unrealized losses in our retail segment.

In 2024, we saw a decrease in forward power prices in all our generation segments compared to our hedged positions which drove material unrealized gains in those segments, partially offset by unrealized losses in our retail segment.

In 2023, the non-Texas generation segments also experienced a decrease in forward power prices compared to our hedged positions, which resulted in unrealized gains in those segments partially offset by unrealized losses in our retail segment.

In the Texas segment, forward power prices materially increased in the year ended December 31, 2023, which resulted in unrealized losses partially offset by unrealized gains in the Retail segment.

The table below summarizes the changes in commodity contract assets and liabilities for the years ended December 31, 2024 and 2023.

The net change in these assets and liabilities, excluding "other activity" as described below, reflects $490 million in unrealized net gains and $2.51 billion in unrealized net losses for the years ended December 31, 2023 and 2022, 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 $1.155 billion and $490 million in unrealized net gains for the years ended December 31, 2024 and 2023, respectively, arising from mark-to-market accounting for positions in the commodity contract portfolio.

Year Ended December 31,

Commodity contract net liability at beginning of period $ (3,148) $ (866)

(in millions)

Commodity contract net liability as of January 1

$ (2,740) $ (3,148)

Settlements/termination of positions (a) 1,213 1,643

Changes in fair value of positions in the portfolio (b) (58) (1,153)

Other activity (c) (82) 228

Commodity contract net liability at end of period $ (2,740) $ (3,148)

Acquired commodity contracts (c) (50) —

Other activity (d)

Commodity contract net liability as of December 31

$ (1,460) $ (2,740)

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

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

(c) Represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses.

(c) Includes fair value of commodity contracts acquired in the Energy Harbor Merger (see Note 2 to the Financial Statements).

(d) Primarily represents changes in fair value of positions due to receipt or payment of cash not reflected in unrealized gains or losses.

Amounts are generally related to premiums related to options purchased or sold as well as certain margin deposits classified as settlement for certain transactions executed on the CME.

The following maturity table presents the net commodity contract liability arising from recognition of fair values at December 31, 2023, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

Maturity dates of unrealized commodity contract net liability at December 31, 2023

The following maturity table presents the net commodity contract liability arising from recognition of fair values as of December 31, 2024, scheduled by the source of fair value and contractual settlement dates of the underlying positions.

Maturity dates of unrealized commodity contract net liability as of December 31, 2024

Source of Fair Value Less than

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5 years Total

(in millions)

Prices actively quoted $ (205) $ 11 $ (1) $ — $ (195)

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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, 2023 were as follows:

Estimated hedging levels for generation volumes in our Texas, East and West segments as of December 31, 2024 were as follows:

Nuclear/Renewable/Coal Generation:

Texas 100 % 100 %

Sunset 96 % 58 %

Natural Gas Generation:

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Operating Cash Flows

Year Ended December 31, 2023 Compared to Year Ended December 31, 2022 — Cash provided by operating activities totaled $5.453 billion and $485 million in the years ended December 31, 2023 and 2022, respectively.

The favorable change of $4.968 billion was primarily driven by (a) a decrease in net margin deposits (return of cash) of $1.899 billion in the year ended December 31, 2023 as compared to an increase in net margin deposits of $1.874 billion in the year ended December 31, 2022 related to commodity contracts which support our comprehensive hedging strategy, including the impacts of cash margin deposits returned and replaced with amounts posted under an affiliate financing agreement (see Note 11 to the Financial Statements) and (b) an increase in cash from operating income exclusive of net margin deposits, partially offset by $544 million of securitization proceeds from ERCOT in the year ended December 31, 2022 (see Note 1 to the Financial Statements).

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 $454 million, $451 million and $297 million for the years ended December 31, 2023, 2022 and 2021, respectively.

The difference represents amortization of nuclear fuel, which is reported as fuel costs in the consolidated statements of operations consistent with industry practice, and amortization of intangible net assets and liabilities that are reported in various other consolidated statements of operations line items including operating revenues and fuel and purchased power costs and delivery fees (see Note 6 to the Financial Statements).

Cash provided by operating activities totaled $4.563 billion and $5.453 billion for the years ended December 31, 2024 and 2023, respectively.

The unfavorable change of $890 million was primarily driven by $1.06 billion less of a decrease in net margin deposits (returns of cash deposits related to commodity contracts which support our hedging strategy) in the year ended December 31, 2024 as compared to the year ended December 31, 2023.

The unfavorable change in margin deposits is partially offset by an increase in cash from realized operating income primarily due to the addition of Energy Harbor.

Depreciation and amortization — Depreciation and amortization expense, as reported as a reconciling adjustment in the consolidated statements of cash flows, exceeded the amount reported in the consolidated statements of operations by $788 million, $454 million, and $451 million for the years ended December 31, 2024, 2023, and 2022, respectively.

This difference represents amortization of nuclear fuel, which is reported as fuel costs in the consolidated statements of operations consistent with industry practice, as well as the amortization of intangible net assets and liabilities.

These are reported under various other line items in the consolidated statements of operations, including operating revenues, fuel and purchased power costs, and delivery fees (see Note 7 to the Financial Statements).

Investing Cash Flows

Year Ended December 31, 2023 Compared to Year Ended December 31, 2022 — Cash used in investing activities totaled $2.145 billion and $1.239 billion in the years ended December 31, 2023 and 2022, respectively.

The increase of $906 million was driven by (a) $543 million in higher net purchases of environmental allowances and (b) a $375 million increase in capital expenditures due primarily to continued development of our solar and energy storage generation facilities (see Note 3 to the Financial Statements), partially offset by $37 million in higher proceeds from the sale of assets driven by our sale of property in Freestone County, Texas in the year ended December 31, 2023.

Cash used in investing activities totaled $5.276 billion and $2.145 billion for the years ended December 31, 2024 and 2023, respectively.

The increase of $3.131 billion was driven primarily by the $3.1 billion used to fund the Energy Harbor Merger.

Year Ended December 31, Increase (Decrease)

(in millions)

Capital expenditures, including LTSA prepayments $ (801) $ (764) (37)

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Total capital expenditures (2,078) (1,676) (402)

Energy Harbor acquisition (net of cash acquired) (3,065) — (3,065)

Net sales (purchases) of environmental allowances (453) (571) 118

Net sales of (investments in) nuclear decommissioning trust fund securities (23) (23) 0

Proceeds from sales of property, plant and equipment 115 78 37

Proceeds from sales of property, plant, and equipment, including nuclear fuel 196 115 81

Proceeds from sales of transferable ITCs 150 — 150

Other investing activity (3) 10 (13)

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Financing Cash Flows

Year Ended December 31, 2023 Compared to Year Ended December 31, 2022 — Cash used in financing activities totaled $294 million and $80 million in the years ended December 31, 2023 and 2022, respectively.

The $214 million increase in cash used was driven by (a) the net repayment of $1.075 billion in the year ended December 31, 2023 of short-term debt and accounts receivable financing amounts borrowed in the year ended December 31, 2022 driven by changes in collateral posting requirements and (b) $1.5 billion principal amount of senior secured notes issued in May 2022, partially offset by (1) $2.5 billion principal amount of senior secured and senior unsecured notes issued in September 2023 and December 2023, of which $750 million will be used to fund cash tender offers in January 2024, and (2) lower share repurchases in 2023.

Cash used in financing activities totaled $1.604 billion and $294 million for the year ended December 31, 2024 and 2023, respectively.

The increase of $1.31 billion was primarily driven by the $1.748 billion paid to Avenue and Nuveen in connection with the purchase of their noncontrolling interests in Vistra Vision and the $180 million of dividends we paid to them.

These cash outflows were partially offset by an $890 million increase in net new borrowings, as detailed below.

Year Ended December 31, Increase (Decrease)

(in millions)

Share repurchases $ (1,266) $ (1,245) $ (21)

Issuances of senior notes 2,498 1,498 1,000

Other net long-term borrowings (repayments), including the forward capacity agreements (33) (251) 218

Issuances of long-term debt 3,817 2,498 1,319

Other net long-term borrowings (repayments) (2,287) (33) (2,254)

Net short-term borrowings (repayments) — (650) 650

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Dividends paid to preferred stockholders (173) (150) (23)

Dividends paid to noncontrolling and redeemable noncontrolling interest holders (180) — (180)

Payment for acquisition of noncontrolling interest (1,748) — (1,748)

TRA Repurchase and tender offer — return of capital (122) — (122)

Other financing activity (90) 24 (114)

Cash used in financing activities $ (1,604) $ (294) $ (1,310)

Collateral Financing Agreement With Affiliate

On June 15, 2023, Vistra Operations entered into a facility agreement (Facility Agreement) with a Delaware trust formed by the Company that sold 450,000 pre-capitalized trust securities (P-Caps) redeemable May 17, 2028 for an initial purchase price of $450 million.

The Trust is not consolidated by Vistra.

The Trust invested the proceeds from the sale of the P-Caps in a portfolio of either (a) U.S.

Treasury securities (Treasuries) or (b) Treasuries and/or principal and interest strips of Treasuries (Treasury Strips, and together with the Treasuries and cash denominated in U.S.

dollars, the Eligible Assets).

At the direction of Vistra Operations, the Eligible Assets held by the Trust will be (i) delivered to one or more designated subsidiaries of Vistra Operations in order to allow such subsidiaries to use the Eligible Assets to meet certain posting obligations with counterparties, and/or (ii) pledged as collateral support for a letter of credit program.

Under the Facility Agreement, Vistra Operations will have the right (Issuance Right), from time to time, to require the Trust to purchase from Vistra Operations up to $450 million aggregate principal amount of Vistra Operations' 7.233% senior secured notes due 2028 (7.233% Senior Secured Notes) in exchange for the delivery of all or a portion of the Treasuries and Treasury Strips corresponding to the portion of the issuance right exercised at such time.

As of December 31, 2023, all of the Eligible Assets were being utilized to meet a portion of our current and future collateral posting obligations.

The Trust will terminate at any time prior to May 17, 2028 and distribute the 7.233% Senior Secured Notes to the holders of the P-Caps if its sole assets consist of 7.233% Senior Secured Notes that Vistra Operations is no longer entitled to repurchase.

See Note 11 for additional details of the collateral financing agreement with affiliate.

Debt Activity

We remain committed to a strong balance sheet and have continued to state our objective to reduce our consolidated net leverage.

We remain committed to a strong balance sheet and have continued to state our objective to reduce consolidated net leverage.

We also intend to maintain adequate liquidity and pursue opportunities to refinance our long-term debt to extend maturities.

In May 2024 and July 2024, after taking into account the Senior Secured Notes Tender Offer settled in January 2024, $342 million of 4.875% Senior Secured Notes and $1.155 billion of 3.550% Senior Secured Notes, respectively, will reach maturity.

We plan to fund these upcoming principal payments using a combination of cash on hand and new debt issuances.

Increases in interest rates will likely result in increased borrowing costs.

See Note 10 to the Financial Statements for details of the Receivables Facility and Repurchase Facility and Note 12 to the Financial Statements for details of the Vistra Operations Credit Facilities, the Commodity-Linked Facility and other long-term debt.

In May 2025, $744 million of 5.125% Senior Secured Notes will reach maturity.

We plan to fund this upcoming principal payment using a combination of proceeds from the senior secured notes issued in December 2024 and cash on hand.

Increases in interest rates have resulted in, and will likely continue to result in, increased borrowing costs.

See Note 9 to the Financial Statements for additional information.

Available Liquidity

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December 31, 2024 December 31, 2023 Change

(in millions)

Cash and cash equivalents (a) $ 1,188 $ 3,485 $ (2,297)

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Total available liquidity (d)(e) $ 4,121 $ 5,799 $ (1,678)

(a) See the Consolidated Statements of Cash Flows in the Financial Statements and Cash Flows above for details of the increase in cash and cash equivalents for the year ended December 31, 2023.

The increase includes proceeds from the issuance of $1.75 billion and $750 million principal amount of Vistra Operations senior secured and senior unsecured notes in September 2023 and December 2023, respectively.

Proceeds from the September 2023 issuance are expected to be used, together with cash on hand, to fund the Transactions.

Proceeds from the December 2023 issuance were used to settle the Senior Secured Notes Tender Offers in January 2024.

(b) The decrease in availability for the year ended December 31, 2023 was driven by a $73 million increase in letters of credit outstanding under the facility and the maturity of $200 million of commitments under the Non-Extended Revolving Credit Facility, partially offset by $250 million in net repayments of borrowings under the facility.

(c) As of December 31, 2023 and 2022, the borrowing bases are less than the facility limits of $1.575 billion and $1.35 billion, respectively.

(a) See the consolidated statements of cash flows in the Financial Statements and Cash Flows above for details of the decrease in cash and cash equivalents for the year ended December 31, 2024.

The decrease includes $3.1 billion that was used to fund the Energy Harbor Merger.

(b) The increase in availability for the year ended December 31, 2024 was driven by a $684 million decrease in letters of credit outstanding under the facility and the October 2024 amendment to the Revolving Credit Facility which, among other things, increased the revolving credit commitments by $265 million (see Note 9 to the Financial Statements).

(c) As of December 31, 2024 and 2023, the borrowing bases were less than the facility limits of $1.75 billion and $1.575 billion, respectively.

As of December 31, 2024, available capacity reflects the borrowing base of $771 million and no cash borrowings.

As of December 31, 2023, available capacity reflects the borrowing base of $1.101 billion and no cash borrowings.

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

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

See Note 10 to the Financial Statements for detail on our accounts receivable financing.

(e) Excludes any additional letters of credit that may be issued under the Secured LOC Facilities.

See Note 12 to the Financial Statements for detail on our Secured LOC Facilities.

We expect to use cash on hand and borrowings under the Receivables Facility and Repurchase Facility and other liquidity facilities to fund the approximately $3.1 billion cash necessary to close the Energy Harbor acquisition.

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

See Note 9 to the Financial Statements for additional information.

(e) Excludes any additional letters of credit that may be issued under the Secured LOC Facilities or the Alternative LOC Facilities.

See Note 9 to the Financial Statements for additional information.

We believe that we will have access to sufficient liquidity to fund our anticipated cash requirements through at least the next 12 months, including the upcoming payments associated with the acquisition of Nuveen's noncontrolling interest in Vistra Vision discussed in Note 9 to the Financial Statements.

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

Interest payments on long-term debt are expected to total approximately $744 million in 2024, $1.293 billion in 2025-2026, $955 million in 2027-2028 and $1.052 billion thereafter.

See Note 12 to the Financial Statements for details of our long-term debt maturities.

Our obligations under commodity purchase and services agreements, including capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase commitments, are expected to total approximately $2.615 billion in 2024, $2.192 billion in 2025-2026, $982 million in 2027-2028 and $437 million thereafter.

See Note 13 to the Financial Statements for maturities of lease liabilities and Note 14 to the Financial Statements for commitments related to long-term service and maintenance contracts.

Interest payments on long-term debt, after taking into account interest rate swaps, are expected to total approximately $905 million in 2025, $1.595 billion in 2026-2027, $1.180 billion in 2028-2029 and $1.305 billion thereafter.

See Note 9 to the Financial Statements for additional information.

Our obligations under commodity purchase and services agreements, including capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase commitments, are expected to total approximately $3.270 billion in 2025, $2.650 billion in 2026-2027, $1.490 billion in 2028-2029 and $450 million thereafter.

See Notes 10 and 15 to the Financial Statements for additional information.

Capital Expenditures

Estimated 2025 capital expenditures and nuclear fuel purchases as of December 31, 2024 total approximately $2.275 billion and include:

• $745 million for solar and energy storage development;

• $925 million for investments in generation and mining facilities;

• $725 million for solar and energy storage development;

• $300 million for nuclear fuel purchases;

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We use cash, letters of credit, Eligible Assets (see Note 8 to the Financial Statements) and other forms of credit support to satisfy such collateral posting obligations.

See Note 12 to the Financial Statements for discussion of the Vistra Operations Credit Facilities and the Commodity-Linked Facility.

See Note 9 to the Financial Statements for additional information.

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

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As of December 31, 2024, we received or posted cash, letters of credit and Eligible Assets for commodity hedging and trading activities as follows:

• $1.244 billion in cash and Eligible Assets has been posted with counterparties as compared to $3.137 billion posted as of December 31, 2022;

• $841 million in cash and Eligible Assets has been posted with counterparties as compared to $1.244 billion posted as of December 31, 2023;

• $49 million in cash has been received from counterparties as compared to $45 million received as of December 31, 2023;

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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 NOL carryforwards.

We expect to make approximately $35 million in state income tax payments offset by $10 million in state tax refunds.

For the year ended December 31, 2023, there were no federal income tax payments, $44 million in state income tax payments, $13 million in state income tax refunds and $9 million in TRA payments.

In the next 12 months, we expect to make approximately $31 million in federal income tax payments, $81 million in state income tax payments and $2 million in TRA payments, offset by $14 million in state tax refunds.

For the year ended December 31, 2024, there were $5 million federal income tax payments, $59 million in state income tax payments, $9 million in state income tax refunds and no TRA payments.

Capitalization

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Financial Covenants

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

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 revolving letters of credit outstanding (excluding all undrawn revolving letters of credit and cash collateralized backstopped revolving letters of credit) exceed 35% of the revolving commitments), that requires the consolidated first-lien net leverage ratio not to exceed 4.25 to 1.00 (or, during a collateral suspension period, the consolidated total net leverage ratio 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, the consolidated total net leverage ratio not to exceed 5.50 to 1.00).

As of December 31, 2023, we were in compliance with the Vistra Operations Credit Agreement, Vistra Operations Commodity-Linked Credit Agreement and Secured LOC Facilities financial covenants.

See Note 12 to the Financial Statements for discussion of other covenants related to the Vistra Operations Credit Facilities.

Although the period ended December 31, 2024 was not a compliance period, we would have been in compliance with the Vistra Operations Credit Agreement, Vistra Operations Commodity-Linked Credit Agreement and Secured LOC Facilities financial covenants if they were required to be tested at such time.

See Note 9 to the Financial Statements for additional information.

Collateral Support Obligations

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The PUCT has rules in place to assure adequate creditworthiness of each REP, including the ability to return customer deposits, if necessary.

Under these rules, at December 31, 2023, Vistra has posted letters of credit in the amount of $91 million with the PUCT, which is subject to adjustments.

Under these rules, as of December 31, 2024, Vistra has posted letters of credit in the amount of $86 million with the PUCT, which is subject to adjustments.

The ISOs/RTOs we operate in have rules in place to assure adequate creditworthiness of parties that participate in the markets operated by those ISOs/RTOs.

Under these rules, Vistra has posted collateral support totaling $554 million in the form of letters of credit, $30 million in the form of a surety bond and $3 million of cash at December 31, 2023 (which is subject to daily adjustments based on settlement activity with the ISOs/RTOs).

Under these rules, Vistra has posted collateral support totaling $960 million in the form of letters of credit, $70 million in the form of a surety bond and $3 million of cash as of December 31, 2024 (which is subject to daily adjustments based on settlement activity with the ISOs/RTOs).

Material Cross Default/Acceleration Provisions

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Such provisions are referred to as "cross default" or "cross acceleration" provisions.

A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greater of $300 million and 17.5% of Consolidated EBITDA may result in a cross default under the Vistra Operations Credit Facilities and the Commodity-Linked Facility.

A default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greatest of $1.0 billion, 17.5% of Consolidated EBITDA and 2.50% of Consolidated Total Assets, may result in a cross default under the Vistra Operations Credit Facilities and the Commodity-Linked Facility.

Such a default would allow the lenders under each such facility to accelerate the maturity of outstanding balances under such facilities, which totaled approximately $2.475 billion and zero, respectively, as of December 31, 2024.

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The Receivables Facility contains a cross-default provision.

The cross-default provision applies, among other instances, if TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands, TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), and Vistra or any of their respective subsidiaries fails to make a payment of principal or interest on any indebtedness that is outstanding in a principal amount of at least $300 million, in the case of Vistra, and in a principal amount of at least $50 million, in the case of TXU Energy or any of the other Originators, after the expiration of any applicable grace period, or if other events occur or circumstances exist under such indebtedness which give rise to a right of the debtholder to accelerate such indebtedness, or if such indebtedness becomes due before its stated maturity.

The cross-default provision applies, among other instances, if TXU Energy, Dynegy Energy Services, Ambit Texas, Value Based Brands, Energy Harbor LLC, TriEagle Energy, each indirect subsidiaries of Vistra and originators under the Receivables Facility (Originators), and Vistra or any of their respective subsidiaries fails to make a payment of principal or interest on any indebtedness that is outstanding in a principal amount of at least $300 million, in the case of Vistra Operations, and in a principal amount of at least $50 million, in the case of TXU Energy or any of the other Originators, after the expiration of any applicable grace period, or if other events occur or circumstances exist under such indebtedness which give rise to a right of the debtholder to accelerate such indebtedness, or if such indebtedness becomes due before its stated maturity.

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

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

Under the Vistra Operations Senior Unsecured Indenture and the Vistra Operations Senior Secured Indenture governing the 7.750% Senior Unsecured Notes and 6.950% Senior Secured Notes, respectively, 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 that exceeds the greater of 1.5% of total assets and $600 million may result in a cross default under the respective notes 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.

See Note 14 to the Financial Statements for discussion of guarantees.

Under the Alternative LOC Facilities, a default by Vistra Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greater of $300 million and 17.5% of Consolidated EBITDA may result in a cross default under the Alternative LOC Facilities.

In addition, 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 exceeding the threshold above, may result in a termination of the Alternative LOC Facilities.

Under the Vistra Operations Senior Unsecured Indenture and the Vistra Operations Senior Secured Indenture governing the 7.750% Senior Unsecured Notes, the 6.875% Senior Unsecured Notes, the 6.950% Senior Secured Notes and the 6.000% Senior Secured Notes, 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 that exceeds the greater of 1.5% of total assets and $600 million may result in a cross default under the respective notes 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.

A default by Vistra Zero Operations or any of its restricted subsidiaries in respect of certain specified indebtedness in an aggregate amount in excess of the greatest of $100 million, 75% of Consolidated EBITDA and 6% of Consolidated Total Assets, may result in a cross default under the Vistra Zero Credit Agreement.

Such a default would allow the lenders under such facility to accelerate the maturity of outstanding balances under such facility, which totaled approximately $697 million as of December 31, 2024.

A default by BCOP or any of its subsidiary guarantors in respect of certain provisions defined in the applicable agreement may result in a cross default under the BCOP Credit Agreement.

Such a default would allow the lenders under such facility to accelerate the maturity of outstanding balances under such facility.

In addition, the interest rate swap agreements that are secured with a lien on BCOP and its subsidiary guarantors' assets on a pari passu basis with the BCOP Credit Agreement contain cross-default provisions, where an event of a default by BCOP or any of its subsidiary guarantors 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 BCOP and require all outstanding obligations under such agreement to be settled.

Under the Nuveen UPA, a default under any document evidencing indebtedness for borrowed money by Vistra Operations or any Guarantor Subsidiary that results in the acceleration of such indebtedness in an aggregate amount that exceeds the greater of 1.5% of total assets and $600 million may result in a cross default under the UPA.

Such a default would result in the payment obligations under the Nuveen UPA of Vistra Vision Holdings and/or any guarantor thereunder becoming immediately due and payable.

See Note 15 to the Financial Statements for additional information.

Commitments and Contingencies

See Note 14 to the Financial Statements for discussion of commitments and contingencies.

See Note 15 to the Financial Statements for additional information.

Changes in Accounting Standards

See Note 1 to the Financial Statements for discussion of changes in accounting standards.

See Note 1 to the Financial Statements for additional information.

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