What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2026-02-27 compared with 2025-02-28 · 444 added, 488 removed, 190 unchanged (83% of the section changed)

3 unchanged sentences

Management's Discussion and Analysis of Financial Condition, and Results of Operations in our 202 4 Form 10-K for a discussion of our financial condition and results of operations for the year ended December 31, 2023 and for the year ended December 31, 2024 compared to the year ended December 31, 2023, which is incorporated here by reference.

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

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.

Key Financial Results

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

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

• We continued to execute our integrated business model, delivering strong operational and financial performance while responding effectively to market opportunities.

Our ability to combine a diversified and dependable generation fleet with a scaled retail platform and disciplined wholesale risk management capabilities remains a core competitive advantage and supports more stable and predictable cash flows across commodity price cycles.

• Long-term contracts entered in 2025 underwrite higher base profitability in the future.

◦ In September 2025, we announced that we had entered into a 20-year power purchase agreement (PPA) (with options to extend for up to an additional 20 years) with Amazon Web Services (AWS) to supply 1,200 MW of carbon-free power from our Comanche Peak Nuclear Power Plant.

We anticipate power delivery to begin in the fourth quarter of 2027 and ramp to full capacity by 2032.

◦ In January 2026, we announced that we had entered into 20-year PPAs with Meta Platforms, Inc.

(Meta) to supply 2,609 MW of carbon-free power and capacity from our PJM nuclear power plants, including 2,176 MW of operating energy and capacity and 433 of uprate energy and capacity to be constructed.

We anticipate commencing delivery on a portion of the operating energy and capacity in late 2026 and full delivery by year end 2027.

We anticipate commencing delivery on a portion of the uprate energy and capacity by 2031 and full delivery by year end 2034.

Disciplined capital allocation.

• Executed disciplined capital allocation through targeted natural gas expansion, including the development of an 860 MW facility in West Texas and the acquisition of 2,600 MW of natural gas generation capacity from Lotus.

• In December 2025, we executed definitive agreements to acquire Cogentrix Energy, consisting of 10 natural gas generation facilities totaling approximately 5,500 MW of capacity.

The transaction is expected to close in mid-to-late 2026.

• During the year ended December 31, 2025, we paid dividends to common stockholders totaling $306 million.

• In October 2025, the Board authorized an incremental amount of $1.0 billion under our stock repurchase program established in October 2021.

During the year ended December 31, 2025, we repurchased 6.6 million shares for approximately $1.0 billion under the program.

Through February 18, 2026, total shares repurchased under the program totaled 167 million shares for $5.9 billion, and we have $1.8 billion available for additional repurchases under the program.

• In December 2025, S&P raised its issuer credit rating on Vistra to investment grade from BB+ to BBB-.

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) extending the maturity of the Commodity-Linked Facility to September 2026, (ii) increasing the commitment cap under the alternative letter of credit facility from $500 million to $800 million, and (iii) expanding and extending the Receivables Facility purchase limit by $100 million and extended the term to July 2026.

• In October 2025, we issued $750 million of 4.300% senior secured notes due 2028, $500 million of 4.600% senior secured notes due 2030, and $750 million of 5.250% senior secured notes due 2035.

The net proceeds from these issuances were used to refinance senior unsecured debt maturities in September 2026 and for general corporate purposes, including to fund a portion of the Lotus Acquisition.

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

• Planned uprates at the Company's operating Perry Nuclear Power Plant (Perry), Davis-Besse Nuclear Power Plant (Davis-Besse), and Beaver Valley Nuclear Power Plant (Beaver Valley) would add 433 MW of incremental carbon-free nuclear energy and capacity to the PJM region commencing delivery on a portion of the uprate energy and capacity by 2031 and full delivery of the uprate energy and capacity by year end 2034.

• We reached commercial operations at the Oak Hill solar facility in Texas totaling 200 MW of capacity and continued development and construction activities on additional facilities at retired or to-be-retired plant sites in Illinois.

• We announced plans to repower the Coleto Creek and Miami Fort coal generation facilities as natural gas-fueled facilities upon their retirement no later than 2027 and the middle of 2028, respectively.

Business Environment and Outlook

Electricity Demand

Electricity demand drivers including the rise of large scale data centers, the electrification of oil field operations, and electric vehicle load building are contributing to a projected fast paced load growth in the regions we serve.

Our integrated retail electricity and power generation operations allows us to quickly respond to electricity demand changes.

To support growing demand from large‑scale electricity consumers, we continue to engage in discussions with various counterparties regarding the potential long-term sale of power from our generation facilities, and we are progressing a series of development initiatives across our generation portfolio, including nuclear uprates and other capacity expansions.

Supply Chain Constraints

Our industry continues to face ongoing supply chain constraints and labor shortages, which have reduced the availability of essential equipment and supplies for constructing new generation facilities, increased the lead times for procuring materials, and raised labor costs associated with maintaining our natural gas, nuclear, and coal fleet.

We are proactively managing these constraints by continuously re-evaluating the business cases and timing of our planned development projects.

This has led to the deferral or abandonment of some planned capital expenditures for our solar and battery projects and could impact the economic feasibility of additional projects in our new generation development pipeline.

We are engaging with suppliers to secure key materials needed to maintain our existing generation facilities before future planned outages.

Russia/Ukraine Conflict

We are closely monitoring developments in the Russia and Ukraine conflict, specifically sanctions (or potential sanctions) against Russian energy exports and Russian nuclear fuel supply and enrichment activities, and 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), which was signed into law on August 11, 2024, prohibits importation of Russian uranium;

however, the DOE 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 2026 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.

All nuclear fuel requirements for 2026 are either in inventory or are onshore.

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 2030 without any additional Russian deliveries.

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.

Noteworthy Developments

PJM Nuclear Power Purchase Agreements and Uprates

In January 2026, Vistra announced it had entered into 20-year PPAs with Meta, pursuant to which the Company has agreed to supply Meta with a total of 2,609 MW of carbon-free power and capacity from the Company's PJM nuclear power plants as follows:

• 1,268 MW of energy and capacity from Perry and 908 MW of energy and capacity from Davis-Besse;

• 213 MW of uprate energy and capacity from Perry, 80 MW of uprate energy and capacity from Davis-Besse, and 140 MW of uprate energy and capacity from Beaver Valley.

Under the terms of the PPAs, the Company anticipates commencing delivery on a portion of the operating energy and capacity in late 2026 and full delivery of the operating energy and capacity by year end 2027.

Additionally, the Company anticipates commencing delivery on a portion of the uprate energy and capacity by 2031 and full delivery of the uprate energy and capacity by year end 2034.

To achieve the uprates, the Company expects to incur capital expenditures commencing in 2026 and extending through 2034, with less than 20% of the aggregate spend projected to occur by year end 2028.

The timing and amount of our planned uprate expenditures will depend on a range of factors, including regulatory approvals, engineering evaluations and capital allocation decisions.

Cogentrix Transaction

On December 31, 2025, Vistra executed definitive agreements to acquire Cogentrix Energy which consists of 10 modern natural gas generation facilities totaling approximately 5,500 MW of capacity (Cogentrix Transaction).

The facilities include three combined cycle gas turbine facilities and two combustion turbine facilities located across PJM, four combined cycle gas turbine facilities in ISO-NE, and one cogeneration facility in ERCOT.

Aggregate consideration at closing will consist of approximately (i) $2.3 billion in cash, net of adjustments for the assumption of an estimated $1.5 billion of outstanding indebtedness of Cogentrix as of the closing date, and (ii) 5,000,000 shares of Vistra common stock, par value $0.01, to be issued to the seller, at a mutually agreed-upon value of $185 per share.

Consummation of the Cogentrix Transaction is subject to customary closing conditions, including receipt of all requisite regulatory approvals, including approvals of FERC and the expiration or termination of all applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.

The Cogentrix Transaction is expected to close in mid-to-late 2026.

Lotus Acquisition

On October 22, 2025, pursuant to a purchase and sale agreement dated May 15, 2025, Vistra Operations acquired 100% of the membership interests of certain subsidiaries of Lotus (Lotus Acquisition).

The Lotus Acquisition resulted in the addition of seven natural gas generation facilities totaling 2,600 MW in Delaware and Pennsylvania (PJM), Rhode Island (ISO-NE), New York (NYISO), and California (CAISO), further geographically diversifying Vistra's natural gas fleet.

The aggregate purchase price consisted of a base purchase price of $1.9 billion, subject to certain customary adjustments, including the acquired companies' working capital, cash, indebtedness, and certain other adjustments.

Vistra Operations funded the Lotus Acquisition with a combination of cash and the assumption of the acquired companies' indebtedness which consisted of a senior secured credit facility, including an existing term loan with approximately $800 million principal outstanding, which reduced the cash consideration payable at closing.

Cash consideration payable at closing, excluding adjustments for the acquired companies' working capital, cash, and certain other adjustments, was $1.1 billion.

See Note 2 to the Financial Statements for additional information.

Comanche Peak Power Purchase Agreement

In September 2025, Vistra announced that it had entered into a 20-year PPA (with options to extend for up to an additional 20 years) with AWS, pursuant to which we have agreed to supply to AWS 1,200 MW of carbon-free power from the Comanche Peak Nuclear Power Plant.

Vistra anticipates power delivery to begin in the fourth quarter of 2027 and ramp to full capacity by 2032.

Nuclear Plant License Renewal

In July 2025, our application for license renewal at our Perry Nuclear Plant was approved by the NRC.

The license now extends through 2046.

OBBBA and CAMT

In July 2025, the legislation known as the OBBBA was signed into law and we have accounted for the effects in our consolidated financial statements.

Key changes include the immediate expensing of domestic research and development costs, the reinstatement of 100% bonus depreciation, and increases in the limitation of interest deductibility.

Certain provisions of the OBBBA will change the timing of cash tax payments in the current fiscal year and future year periods, however the legislation did not have a material impact on our consolidated financial statements.

We do not expect Vistra to be subject to the corporate alternative minimum tax (CAMT) in the 2025 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 forecasted OBBBA impacts into account when forecasting cash taxes.

Moss Landing 300 Incident

On January 16, 2025, we detected a fire at our Moss Landing 300 MW energy storage facility at the Moss Landing Power Plant site (the Moss Landing Incident) that resulted in ceasing operations at all facilities at the Moss Landing complex until the fire was contained.

No injuries occurred due to the fire or the Company's response.

The Moss Landing complex includes two other battery facilities and a gas plant.

The gas plant returned to service in February 2025.

The Moss Landing 350 MW battery facility has a net book value of approximately $320 million as of December 31, 2025.

We are working towards a return to service in mid-2026, but we will continue to evaluate our restart plans following completion of our investigation into the cause of the fire.

After further consideration, management determined it would not return the Moss Landing 100 MW battery to service.

As a result of the damage caused by the Moss Landing Incident, during the three months ended March 31, 2025, we wrote-off the net book value of Moss Landing 300 of approximately $400 million to depreciation expense and moved the asset to the Asset Closure segment as we have no plans to return the Moss Landing 300 facility to operations.

See Notes 7 and 21 to the Financial Statements for additional information.

As a result of the decision to not return the Moss Landing 100 MW battery to service, we performed an assessment of the recoverability of the facility's carrying value and, during the three months ended December 31, 2025, we recognized an impairment loss of approximately $155 million and moved the asset to the Asset Closure segment (see Notes 7 and 21 to the Financial Statements for additional information.

In July 2025, we entered into an Administrative Settlement Agreement and Order on Consent (ASAOC) with the EPA related to the Moss Landing 300 site.

Under the ASAOC, we are required to perform specific battery removal and remediation activities, including battery removal and disposal, building demolition, and air and water monitoring.

We estimate the total cost of these activities to be approximately $110 million.

We have incurred expenses of approximately $49 million on ASAOC activities through December 31, 2025.

As of December 31, 2025, our accrual for estimated future costs for the ASAOC activities is approximately $61 million, which is reflected in other current liabilities in the consolidated balance sheets.

This estimate assumes the ASAOC activities will be completed by the end of 2026.

Aside from battery removal and disposal, our estimate does not reflect costs associated with removal of other hazardous waste that could be identified as the demolition progresses as we are unable to estimate such costs until sampling of waste material is complete.

We will account for any adjustments to the accrual as a change in estimate in the period new information becomes available.

Additional impacts from the Moss Landing Incident include loss of revenue from the facilities being offline and may include litigation costs, other negotiated settlements of contracts with counterparties, and additional non-cash impairment losses.

We are currently unable to estimate the full impact the Moss Landing Incident will have on us as our estimate will evolve as demolition progresses.

See Note 18 to the Financial Statements for additional information.

We have filed insurance claims against applicable insurance policies with combined business interruption and property loss limits of $500 million, net of deductibles, of which approximately $500 million has been collected through February 2026.

See Note 8 to the Financial Statements for additional information.

While we expect future revenues in the West segment to decrease relative to 2024 revenues with the Moss Landing 300 and 100 MW battery facilities not returning to service, given the uncertainty in the timing of the restart of the Moss Landing 350 MW battery facility and additional expenses that could be incurred related to the Moss Landing Incident, we cannot predict the full impact this event will have on our 2026 financial statements.

Martin Lake Unit 1 Incident

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

We wrote-off the unit's net book value of less than $1 million to depreciation expense in December 2024.

The unit returned to service in February 2026.

We estimate total cash capital expenditures required to restore the unit to service was approximately $384 million, of which approximately $271 million in cash capital expenditures have been incurred as of December 31, 2025.

We expect to recover a majority of the expenditures associated with the Martin Lake Incident through property damage insurance and to receive additional business interruption proceeds.

See Note 8 to the Financial Statements for additional information.

Given uncertainty in timing of remaining insurance recoveries, we cannot predict the full impacts this event will have on our 2026 financial statements.

Acquisition of Noncontrolling Interest

1 unchanged sentence

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.

See Notes 2 and 11 to the Financial Statements for additional information.

Planned Gas-Fueled Dispatchable Power in ERCOT

3 unchanged sentences

• 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.

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.

Both projects were selected for due diligence as part of the Texas Energy Fund loan program.

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.

Due diligence is progressing and we are in the final stages.

In September 2025, we announced we will move forward with construction of the 860 MW peaking plants discussed above.

Early development work is underway, and we anticipate the units will be online in 2028.

Merger with Energy Harbor

On March 1, 2024 (Merger Date), pursuant to a transaction agreement dated March 6, 2023, (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 and 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).

See Note 2 to the Financial Statements for additional information.

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 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.

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, new technology-neutral ITCs and PTCs that apply to various different clean energy technologies, and a first-time stand-alone battery storage ITC.

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

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

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

• We continued to execute our integrated business model through exceptional operational performance 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.

• 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, growth of our retail business and the effectiveness of our comprehensive hedging strategy.

Macroeconomic Conditions

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.

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 and could impact the feasibility of additional projects.

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 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.

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 when annual gross receipts are between $25.00 per MWh and 43.75 per MWh and $26.00 per MWh and $44.75 per MWh for 2024 and 2025, respectively (each subject to annual inflation adjustments).

The Company accounts for transferable ITCs and PTCs we expect to receive by analogy to ASC 832, Government Grants as amended by Accounting Standards Update 2025-10 (ASC 832).

As discussed in Note 5, we recognized transferable nuclear PTC revenues of $220 million and $545 million in the years ended December 31, 2025 and 2024, respectively.

Treasury regulations are expected to further define the scope of the legislation in many important respects, including interpretive guidance on the definition of gross receipts for the nuclear PTC.

Any interpretive guidance on the definition of gross receipts that differs from the interpretation used in our estimates could result in a material change to PTC revenues recorded in 2024 and 2025 and would be reflected as a change in estimate in the period in which the guidance is received.

Factors Affecting Our Financial Condition and Results of Operations

Commodity Prices

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

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

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

Wholesale electricity prices generally move with natural gas prices, except in certain circumstances, such as when ERCOT power prices increase significantly during extreme weather events due to generation scarcity.

Because natural gas prices are volatile, the operating costs of our natural gas‑fueled generation facilities can also be volatile.

While changes in natural gas prices do not materially affect the cost of generation at our nuclear‑, lignite‑, and coal‑fueled facilities, such changes generally influence electricity prices and, therefore, the operating margins of these facilities.

Other factors that may affect electricity prices include fuel costs, regional generation supply, weather conditions, competitive dynamics, emerging technologies, and macroeconomic and regulatory developments.

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

Market Heat Rate can be affected by a number of factors, including generation availability, mix of assets and the efficiency of the marginal supplier (generally natural gas-fueled generation facilities) in generating electricity.

Our Market Heat Rate exposure is impacted by changes in the availability of generation resources, such as additions and retirements of generation facilities, and mix of generation assets.

For example, increasing renewable (wind and solar) generation capacity generally depresses Market Heat Rates, particularly during periods when total demand is relatively low.

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

Due to our exposure to variability in natural gas prices and Market Heat Rates, retail sales and hedging activities are critical to our operating results and cash flow stability.

Our integrated power generation and retail electricity business provides flexibility to hedge our generation position by utilizing retail markets as an effective sales channel.

As we entered the 2025 and 2024 calendar years, substantially all of our expected generation volumes were hedged.

This disciplined hedging strategy supports margin protection and contributes to more stable and predictable earnings.

As a result of our hedging strategy, the net income of our segments can be significantly impacted by changes in unrealized gains and losses on commodity derivative instruments which are driven by changes in forward power prices.

When power prices increase or decrease compared to what our generation segments have sold forward, the generation segments recognize unrealized losses or gains, respectively.

Conversely, the retail segment, which procures power from the generation segments to meet future load obligations, experiences an inverse effect on unrealized mark-to-market valuations compared to the generation segments.

The below tables summarize the average around the clock settled prices for the periods presented and does not necessarily reflect prices we realized or costs incurred by us.

Year Ended December 31, Year Ended December 31,

2025 2024 2025 2024

Average Power Price

Average Natural gas price

ERCOT North Hub $ 32.01 $ 25.89 NYMEX Henry Hub $ 3.53 $ 2.25

ERCOT West Hub $ 32.87 $ 27.45 Houston Ship Channel $ 3.01 $ 1.87

PJM AEP Dayton Hub $ 45.13 $ 30.74 Permian Basin $ 0.62 $ 0.08

PJM Northern Illinois Hub $ 36.65 $ 25.46 Dominion South $ 2.78 $ 1.67

PJM Western Hub $ 50.25 $ 33.83 Tetco ELA $ 3.30 $ 2.08

MISO Indiana Hub $ 43.73 $ 31.36 Chicago Citygate $ 3.25 $ 2.12

ISONE Massachusetts Hub $ 67.86 $ 41.47 TetcoM3 $ 3.69 $ 2.07

New York Zone A $ 52.88 $ 32.66 Algonquin Citygates $ 6.23 $ 3.03

CAISO NP15 $ 38.22 $ 40.67 PG&E Citygate $ 3.39 $ 3.09

Estimated hedging levels for generation volumes in our Texas, East and West segments as of December 31, 2025 were as follows:

Nuclear/Renewable/Coal Generation:

Texas 100 % 100 %

East 89 % 65 %

Natural Gas Generation:

Texas 92 % 43 %

East 98 % 72 %

West 100 % 42 %

The demand for and market prices of electricity and natural gas are affected by weather.

As a result, our operating results are impacted by extreme or sustained weather conditions and may fluctuate on a seasonal basis.

Typically, demand for and the price of electricity is higher in the summer and winter seasons, when the temperatures are more extreme, and the demand for and price of natural gas is also generally higher in the winter.

More severe weather conditions such as heat waves or extreme winter weather have made, and may make, such fluctuations more pronounced.

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

To illustrate the impact of weather variability on our operating results, the following table presents cooling and heating degree days relative to normal levels by segment in 2025 and 2024.

Year Ended December 31,

Retail Texas East West

2025 2024 2025 2024 2025 2024 2025 2024

Weather - percent of normal (a):

Cooling degree days 104 % 112 % 108 % 112 % 94 % 103 % 88 % 90 %

Heating degree days 94 % 78 % 99 % 77 % 104 % 88 % 113 % 119 %

(a) Reflects cooling degree or heating degree days 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.

Retail amounts represent weather data for the Dallas-Fort Worth area.

Capacity Markets

12 unchanged sentences

DEOK zone 269.92 329.17 333.44

Our capacity sales in PJM, net of purchases, aggregated by planning year and capacity type through planning year 2025-2026, are as follows:

DOM zone 444.26 329.17 333.44

Our auction and bilateral capacity sales in PJM, net of purchases, aggregated by planning year through planning year 2027-2028, are as follows:

2025-2026 2026-2027 2027-2028

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

Bilateral capacity sold, net (MW) 2,127 330

Total segment capacity sold, net (MW)

Capacity sold, net (MW)

11,259 11,527 10,566

Average price per MW-day $ 41.38 $ 267.12

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

1 unchanged sentence

Due to the short-term, seasonal nature of the NYISO capacity auctions, we monetize the majority of our capacity through bilateral trades.

Our capacity sales, aggregated by season through winter 2026-2027, are as follows:

Our auction and bilateral capacity sales, aggregated by season through winter 2027-2028, are as follows:

2025 - 2026 Summer

2026 - 2027 Summer

Auction capacity sold (MW) 77 — — — —

Bilateral capacity sold (MW) 943 550 268 — —

Total capacity sold (MW)

Capacity sold (MW)

909 296 174 195 75

Average price per kW-month $ 3.09 $ 4.51 $ 4.10 $ — $ —

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

3 unchanged sentences

2025-2026 2026-2027 2027-2028

Auction capacity sold (MW) 3,221 3,032 2,960 3,261

Bilateral capacity sold (MW) 78 78 58 8

Total capacity sold (MW)

Capacity sold (MW)

3,453 3,500 3,750

Average price per kW-month $ 3.10 $ 2.72 $ 2.60 $ 3.58

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

Price per MW-day $ 20.08

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

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

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

Bilateral capacity sold (MW)

Price per kW-month

MISO auction and bilateral capacity sales through planning year 2028-2029 are as follows:

2025-2026 2026-2027 2027-2028 2028-2029

Total MISO segment capacity sold (MW)

Capacity sold (MW)

1,710 1,418 239 5

Average price per kW-month $ 3.02 $ 4.52 $ 4.44 $ 4.96

Our capacity sales as part of the California Public Utilities Commission Resource Adequacy (RA) Program in California, aggregated by calendar year for 2026 through 2029 for Moss Landing, are as follows:

2026 2027 2028 2029

Bilateral capacity sold (Avg MW) 1,415 1,265 350 350

Electricity Prices

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

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

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

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

The price of natural gas is volatile;

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

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

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

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

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

Our Market Heat Rate exposure is impacted by changes in the availability of generation resources, such as additions and retirements of generation facilities, and mix of generation assets.

For example, increasing renewable (wind and solar) generation capacity generally depresses Market Heat Rates, particularly during periods when total demand is relatively low.

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

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

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

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

• continuing focus on cost management to better withstand gross margin volatility;

• following a retail pricing strategy that appropriately reflects the value of our product offering to customers, the magnitude and costs of commodity price, liquidity risk and retail demand variability;

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

Critical Accounting Estimates

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, 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.

Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as market prices change.

Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net income with an offset to derivative assets and liabilities.

The availability of quoted market prices in energy markets is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point.

Where quoted market prices are not available, the fair value is based on unobservable inputs, which require significant judgment.

Derivative instruments valued based on unobservable inputs primarily include (i) forward sales and purchases of electricity (including certain retail contracts), natural gas and coal, (ii) electricity, natural gas and coal options, and (iii) financial transmission rights.

In computing fair value for derivatives, each forward pricing curve is separated into liquid and illiquid periods.

The liquid period varies by delivery point and commodity.

Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity.

For illiquid periods, fair value is estimated based on forward price curves developed using proprietary modeling techniques that take into account 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 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 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, 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

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

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

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

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

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

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

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

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

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

Income tax returns are regularly subject to examination by applicable tax authorities.

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

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

Asset Retirement Obligations (ARO)

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.

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 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

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.

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 given the diverse fuel mix and output rates of our generation asset groups.

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.

If an asset group carrying value is determined to be unrecoverable, fair value will be calculated based on a market participant view and a loss will be recorded for the amount the carrying value exceeds the fair value.

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

The income approach involves estimates of future performance 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.

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 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.

EBITDA and Adjusted EBITDA

The tables and discussion that follows present period‑over‑period changes in our results of operations and highlight the primary drivers of those variances for the periods presented.

In analyzing and planning for our business, we supplement our use of GAAP financial measures with non-GAAP financial measures, including EBITDA and Adjusted EBITDA as performance measures.

6 unchanged sentences

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).

Vistra Consolidated Financial Results — Year Ended December 31, 2024 Compared to Year Ended December 31, 2023

The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the year ended December 31, 2024:

Consolidated Results of Operations

The following table presents Net income (loss), EBITDA and Adjusted EBITDA:

Year Ended December 31, 2025

4 unchanged sentences

Fuel, purchased power costs, and delivery fees (11,686) (1,990) (3,807) (149) — 8,531 (9,101)

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

Operating costs (168) (1,050) (1,381) (59) (154) 9 (2,803)

1 unchanged sentence

Selling, general, and administrative expenses (1,035) (180) (235) (14) (66) (184) (1,714)

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

Impairment of long-lived assets — (68) (5) — (155) — (228)

Operating income (loss) 1,357 1,427 (374) 42 (299) (247) 1,906

Other income 1 39 181 3 16 72 312

Other deductions (2) (4) (4) (6) (2) (3) (21)

Other income, net

— 124 234 5 24 7 394

Interest expense and related charges (67) 53 50 7 (4) (1,218) (1,179)

9 unchanged sentences

EBITDA before Adjustments 1,451 2,322 1,334 108 (277) (163) 4,775

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 148 (479) 1,013 128 (2) — 808

Purchase accounting impacts 17 1 33 — — — 51

— 1 (12) — — (14) (25)

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

Non-cash compensation expenses — — — — — 113 113

Transition and merger expenses 6 (1) 3 — — 67 75

Decommissioning-related activities (d)

Impairment of long-lived assets — 68 5 — 155 — 228

Insurance income (c)

— (120) — — (71) — (191)

Decommissioning-related activities (d) — 15 (127) 1 116 — 5

ERP system implementation expenses 3 3 4 — 1 — 11

(3) 25 17 7 4 (87) (37)

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

Adjusted EBITDA $ 1,622 $ 1,834 $ 2,282 $ 244 $ (74) $ (70) $ 5,838

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

(a) Corporate and Other includes $67 million of unrealized mark-to-market net losses on interest rate swaps.

(b) Includes nuclear fuel amortization of $133 million and $354 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:

(c) Includes involuntary conversion gain recognized from Martin Lake Incident property damage insurance in the Texas segment and revenues from Moss Landing Incident business interruption proceeds in the Asset Closure segment.

(d) Represents net of all NDT (income) loss of the PJM nuclear facilities and all ARO and environmental remediation expenses and other expenses associated with the Moss Landing Incident.

Year Ended December 31, 2024

7 unchanged sentences

Selling, general, and administrative expenses (977) (169) (148) (20) (48) (239) (1,601)

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

Operating income (loss) 1,271 2,052 716 491 (144) (305) 4,081

Other income 1 35 4 21 110 86 257

Other deductions — (2) (5) — — (7) (14)

Other income, net

(1) 35 177 (6) 17 69 291

Interest expense and related charges (54) 46 9 1 (4) (898) (900)

10 unchanged sentences

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

Year Ended December 31, 2023

Retail Texas East West Asset

Closure Eliminations / Corporate and Other Vistra Consolidated

Purchase accounting impacts

— 1 (12) — — (14) (25)

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

1 unchanged sentence

Transition and merger expenses 2 1 22 — — 111 136

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

PJM capacity performance default impacts (d) — — 9 — — — 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 $ 225 $ (104) $ (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.

(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) 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.

• 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.

(a) Corporate and Other 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, ARO accretion expense for operating assets, and ARO remeasurement impacts for operating assets.

Net income for the year ended December 31, 2025 compared to the year ended December 31, 2024 decreased by $1.868 billion.

Adjusted EBITDA for the year ended December 31, 2025 compared to the year ended December 31, 2024 increased by $299 million.

The primary drivers for the decrease in net income and the increase in Adjusted EBITDA include:

Year Ended December 31, 2025 Compared to 2024

(in millions)

Favorable change in realized revenue net of fuel driven primarily by a full year of Energy Harbor results and higher realized energy and capacity prices partially offset by a decrease in nuclear PTC revenue and a decrease in energy revenues due to the Martin Lake Incident

Higher retail margins driven by strong counts and one-time gains from supply cost management

Favorable change in retail customer consumption primarily due to weather

Increase in plant operating costs due primarily to inclusion of a full year of Energy Harbor results

Increase in SG&A and other primarily due to inclusion of a full year of Energy Harbor results and higher technology costs

Change in Adjusted EBITDA $ 299

Change in depreciation and amortization, including nuclear fuel amortization, driven primarily by a full year of Energy Harbor assets in East

Change in unrealized net gain (loss) resulting from commodity hedging transactions

Impairment of long-lived assets

Increase in insurance income

Decommissioning-related activities

Other (including interest expense and income tax expense)

Change in Net income $ (1,868)

Results of Operations by Segment

The following section presents the results of operations and net income of Vistra's reportable business segments.

See Note 21 of the Financial Statements for a discussion of the Company's segments as defined under the accounting standards for segment reporting.

Year Ended December 31,

Retail Texas East West

(in millions)

$ 1,290 $ 1,216

Adjusted EBITDA

$ 1,622 $ 1,463

Retail electricity sales volumes (GWh):

2 unchanged sentences

Total retail electricity sales volumes 139,139 133,361

Retail net income increased due to higher retail margins driven by strong counts and one-time gains from supply cost management and an increase in customer consumption primarily due to weather, partially offset by a $96 million increase in unrealized mark-to-market losses on commodity derivative positions.

Year Ended December 31,

(in millions)

$ 1,604 $ 2,133

Adjusted EBITDA

$ 1,834 $ 2,032

Production volumes (GWh):

7 unchanged sentences

Nuclear facilities 95.4 % 93.3 %

Weather - percent of normal (a):

Cooling degree days 112 % 115 % 112 % 112 % 103 % 96 % 90 % 79 %

Heating degree days 78 % 85 % 77 % 88 % 88 % 87 % 119 % 125 %

(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

Average Power Price

Average Natural gas price

($/MMBtu) (b):

ERCOT North Hub

$ 25.89 $ 48.30 NYMEX Henry Hub

$ 2.25 $ 2.53

ERCOT West Hub

$ 27.45 $ 49.45 Houston Ship Channel

$ 1.87 $ 2.20

PJM AEP Dayton Hub $ 30.74 $ 30.81 Permian Basin

$ 0.08 $ 1.53

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)

Texas net income decreased primarily due to a $311 million decrease in unrealized mark-to-market gains on commodity derivative positions, a decrease in energy revenues due to the Martin Lake Incident, a $68 million impairment of long-lived assets related to certain development projects, and a $60 million reduction in nuclear PTC revenue, partially offset by higher realized energy prices and $120 million of involuntary conversion gains on property damage insurance from the Martin Lake Incident.

Year Ended December 31,

(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.

Net income (loss)

Adjusted EBITDA

$ 2,282 $ 2,017

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

Production volumes (GWh):

Natural gas facilities 62,870 60,279

Lignite and coal facilities 19,505 16,938

Nuclear facilities 32,203 26,540

Solar facilities 227 —

Capacity factors:

CCGT facilities 63.0 % 62.0 %

Lignite and coal facilities 56.7 % 49.1 %

Nuclear facilities 90.8 % 89.3 %

East net income decreased primarily due to a $1.1 billion increase in unrealized mark-to-market losses on commodity derivative positions and a $264 million reduction in nuclear PTC revenue, partially offset by inclusion of twelve months of Energy Harbor in 2025 compared to ten months in 2024 and higher realized energy and capacity prices.

Year Ended December 31,

(in millions)

Adjusted EBITDA

Production volumes (GWh):

Natural gas facilities 2,092 4,175

Capacity factors:

CCGT facilities 23.0 % 46.5 %

West net income decreased primarily due to a $460 million increase in unrealized mark-to-market losses on commodity derivative positions.

Asset Closure Segment

Year Ended December 31,

(in millions)

$ (279) $ (131)

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

Asset Closure net loss increased primarily due to a $155 million impairment expense for the Moss Landing 100 MW battery facility and costs associated with the Moss Landing Incident, net of insurance receivables, partially offset by business interruption insurance revenue.

Disaggregated Consolidated Statement of Operations Results

Explanations of variations between periods for selected income statement categories are provided below:

Year Ended December 31,

(in millions)

Operating revenues

$ 17,738 $ 17,224

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

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

Operating revenues increased primarily due to an increase in retail revenue rates, an increase in retail customer consumption primarily due to weather, inclusion of a full year of Energy Harbor retail and wholesale revenues for 2025 compared to ten months in 2024, a $312 million increase in retail transmission charges (offset in fuel, purchased power costs, and delivery fees), and business interruption insurance revenue related to the Martin Lake Incident and Moss Landing Incident, partially offset by an increase of $1.8 billion of unrealized mark-to-market losses on commodity derivative positions and a decrease in nuclear PTC revenues.

Year Ended December 31,

(in millions)

Fuel, purchased power costs, and delivery fees

$ (9,101) $ (7,285)

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

Fuel, purchased power costs, and delivery fees increased primarily due to an $1.219 billion increase in realized fuel costs, a $312 million increase in retail transmission charges (offset in operating revenues) and an increase of $184 million in unrealized mark-to-market losses on commodity derivative positions.

Year Ended December 31,

(in millions)

Operating costs

$ (2,803) $ (2,414)

Impairment of long-lived assets — — 49 —

Decommissioning related activities

Operating costs increased primarily due to the inclusion of a full year of Energy Harbor operating costs for 2025 compared to 10 months in 2024 of $198 million, higher maintenance and outage costs of $62 million, $77 million in operating costs due to the Moss Landing Incident, net of expected insurance recoveries and higher ARO accretion of $18 million.

Year Ended December 31,

(in millions)

Depreciation and amortization

$ (1,986) $ (1,843)

PJM capacity performance default impacts — — 9 —

Winter Storm Uri impact

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

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

(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)

Depreciation and amortization increased primarily due to a $50 million increase in depreciation expense due to the inclusion of a full year of Energy Harbor depreciation expense for 2025 compared to 10 months in 2024 and increased capital expenditures in the Texas and East segments.

Year Ended December 31,

(in millions)

Operating revenues $ 1 $ — $ 1

Fuel, purchased power costs, and delivery fees

Operating costs (81) (74) (7)

Selling, general, and administrative expenses

$ (1,714) $ (1,601)

Operating loss (126) (111) (15)

Other income 16 110 (94)

Other deductions (2) — (2)

Selling, general, and administrative expenses increased primarily due to the inclusion of a full year of Energy Harbor selling, general, and administrative expenses for 2025 compared to 10 months in 2024 and an increase in technology costs.

Year Ended December 31,

(in millions)

Other income, net

Other income, net increased primarily due to higher insurance income primarily due to involuntary conversion gains from Martin Lake Incident insurance proceeds and NDT net income, partially offset by lower interest income.

Year Ended December 31,

(in millions)

Interest expense and related charges

Income (loss) before income taxes

$ (1,179) $ (900)

$ (116) $ (6) $ (110)

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

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

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.

As power prices increase/decrease in comparison to what our generation segments have sold forward, the generation segments recognize unrealized losses/gains.

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.

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 $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.

Interest expense and related charges increased due to higher average borrowings and decrease in unrealized mark-to-market gains on interest rate swaps of $120 million.

Year Ended December 31,

(in millions)

Commodity contract net liability as of January 1

Income tax expense

$ (179) $ (655)

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

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

Acquired commodity contracts (c) (50) —

Other activity (d)

Commodity contract net liability as of December 31

Effective tax rate

15.9 % 18.9 %

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

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.

(b) Represents unrealized net gains/(losses) recognized, reflecting the effect of changes in fair value.

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

(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 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

1 year 1-3 years 4-5 years Excess of

5 years Total

Income tax expense decreased due to lower pre-tax book income in 2025 and a lower effective tax rate.

Liquidity and Capital Resources

Our primary sources of liquidity and capital consist of (i) cash and cash equivalents, (ii) net cash provided by operating activities, (iii) available capacity under our credit facilities, and (iv) access to the debt and equity capital markets.

Within the bounds of our risk management program and policies, we use a variety of derivative instruments to enhance the stability of future cash flows to maintain sufficient financial resources for working capital, debt service, capital expenditures, debt covenant compliance, and (or) other needs.

Our hedging strategy is designed to preserve cash flow certainty while maintaining appropriate risk tolerances across our generation portfolio.

We complement our hedging strategy with long‑term contracted revenues, including power purchase agreements, to lower our overall hedging requirements.

Sources and Uses of Cash

Year Ended December 31,

2025 2024 Change

(in millions)

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

Prices provided by other external sources (423) (91) 1 — (513)

Prices based on models (162) (507) (75) (8) (752)

Total $ (790) $ (587) $ (75) $ (8) $ (1,460)

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

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

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

Nuclear/Renewable/Coal Generation:

Texas 100 % 100 %

Natural Gas Generation:

Texas 100 % 57 %

East 100 % 77 %

West 100 % 37 %

Financial Condition

Net cash provided by operating activities $ 4,070 $ 4,563 $ (493)

Net cash used in investing activities $ (4,396) $ (5,276) $ 880

Net cash used in financing activities $ (74) $ (1,604) $ 1,530

Operating Cash Flows

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).

The change in net cash provided by operating activities is primarily due to a $1.611 billion increase in net margin deposits as $769 million in net margin deposits supporting our hedging strategy were posted for the year ended December 31, 2025 as compared to $842 million in net margin deposits returned for the year ended December 31, 2024, partially offset by an increase in cash from nuclear PTC sales of $469 million, realized operating income primarily due to the addition of Energy Harbor, and higher realized energy and capacity prices.

Investing Cash Flows

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)

Nuclear fuel purchases (477) (214) (263)

Growth and development expenditures (800) (698) (102)

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, including nuclear fuel 196 115 81

Proceeds from sales of transferable ITCs 150 — 150

Other investing activity (3) 10 (13)

Cash used in investing activities $ (5,276) $ (2,145) $ (3,131)

The change in net cash used in investing activities is primarily due (i) to the purchase of Energy Harbor for $3.1 billion in March 2024 and (ii) $325 million of insurance proceeds received in 2025 for recovery of damaged property, plant, and equipment associated with the Moss Landing and Martin Lake Incidents, partially offset by (i) the Lotus Acquisition for $1.1 billion in October 2025, (ii) $674 million in higher capital expenditures associated with the Martin Lake Incident and development projects, and (iii) $461 million in higher net purchases of environmental allowances in 2025.

Financing Cash Flows

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 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

Net borrowings (repayments) under the accounts receivable financing facilities 750 (425) 1,175

Dividends paid to common stockholders (305) (313) 8

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)

Debt Activity

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 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

Our significant financing activities during the years ended December 31, 2025 and 2024 are as follows:

• In 2025, we paid (i) $1.744 billion to redeem senior secured and unsecured notes, (ii) $1.028 billion to repurchase common stock, (iii) $803 million to repay debt assumed in the Lotus Acquisition, (iv) $703 million installment payment to Nuveen to purchase the noncontrolling interest in Vistra Vision, and (v) $498 million in dividends to common and preferred shareholders.

In 2025, we (i) issued $2.0 billion in senior secured notes, (ii) borrowed $1.8 billion under the Vistra Operations Credit Facilities and the Commodity-Linked Facility, (iii) borrowed $506 million of project-level debt under the BCOP Credit Facility, and (iv) borrowed $475 million under the accounts receivable financing facilities.

• In 2024, we paid (i) $2.247 billion to redeem senior secured notes, (ii) $1.748 billion to purchase the noncontrolling interests in Vistra Vision from Avenue and Nuveen and $180 million in dividends to them, (iii) $1.266 billion to repurchase common stock, and (iv) $478 million in dividends to common and preferred shareholders.

In 2024, we (i) issued $2.750 billion in senior secured notes, (ii) borrowed $1.067 billion of project-level debt under the Vistra Zero and BCOP Credit Facility, and (iii) borrowed $750 million under the accounts receivable financing facilities.

The following table summarizes changes in available liquidity for the year ended December 31, 2025:

6 unchanged sentences

(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, 2025.

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.

(b) The decrease in availability for the year ended December 31, 2025 was driven by a $380 million increase in cash borrowings, partially offset by a $214 million decrease in letters of credit outstanding under the facility.

As of December 31, 2025, available capacity reflects the borrowing base of $1.422 billion and $1.420 billion in cash borrowings.

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.

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

2 unchanged sentences

See Note 11 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.

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 consummation of the Cogentrix Transaction, the maturity of 2026 debt obligations, including the 5.050% Senior Secured Notes due December 2026, and the upcoming payments associated with the acquisition of Nuveen's noncontrolling interest in Vistra Vision discussed in Note 11 to the Financial Statements.

In January 2026, Vistra further increased its available liquidity through the issuance by Vistra Operations of $2.25 billion aggregate principal amount of senior secured notes, consisting of $1.0 billion aggregate principal amount of 4.700% senior secured notes due 2031 and $1.25 billion aggregate principal amount of 5.350% senior secured notes due 2036.

Net proceeds will be used to (i) fund a portion of the consideration for the Cogentrix Transaction (see Note 2 to the Financial Statements for additional Information), (ii) for general corporate purposes, including to repay existing indebtedness, and (iii) to pay fees and expenses related to the offering.

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

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.

Interest Payments

Interest payments on long-term debt, after taking into account interest rate swaps, are expected to total approximately $930 million in 2026, $1.560 billion in 2027-2028, $1.230 billion in 2029-2030 and $995 million thereafter.

See Note 11 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.

Commodity Purchase and Services Agreements

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 $3.630 billion in 2026, $2.990 billion in 2027-2028, $1.730 billion in 2029-2030 and $1.420 billion thereafter.

See Notes 12 and 18 to the Financial Statements for additional information.

1 unchanged sentence

Estimated 2026 capital expenditures and nuclear fuel purchases as of December 31, 2025 total approximately $2.587 billion and include:

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

• $1.087 billion for investments in generation and mining facilities inclusive of LTSA prepayments;

• $300 million for solar and energy storage development;

• $475 million for nuclear fuel purchases

• $325 million for other growth expenditures.

• $900 million for other growth expenditures, and

• $(175) million of nonrecurring items, including insurance proceeds expected to be received for property damage partially offset by capital expenditures for investment technology, corporate, insurance proceeds, and other.

Liquidity Effects of Commodity Hedging and Trading Activities

We have entered into commodity hedging and trading transactions that require us to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument we hold has declined in value.

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

We use cash, letters of credit, Eligible Assets (see Note 10 to the Financial Statements for additional information) and other forms of credit support to satisfy such collateral posting obligations.

See Note 11 to the Financial Statements for additional information.

8 unchanged sentences

As of December 31, 2025, we received or posted cash, letters of credit and Eligible Assets for commodity hedging and trading activities as follows:

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

• $1.577 billion in cash and Eligible Assets has been posted with counterparties as compared to $841 million posted as of December 31, 2024;

• $7 million in cash has been received from counterparties as compared to $49 million received as of December 31, 2024;

• $2.560 billion in letters of credit have been posted with counterparties as compared to $2.408 billion posted as of December 31, 2023;

• $131 million in letters of credit have been received from counterparties as compared to $143 million received as of December 31, 2023.

See Collateral Support Obligations below for information related to collateral posted in accordance with the PUCT and ISO/RTO rules.

• $2.489 billion in letters of credit has been posted with counterparties as compared to $2.560 billion posted as of December 31, 2024;

• $162 million in letters of credit has been received from counterparties as compared to $131 million received as of December 31, 2024.

See Note 18 to the Financial Statements for information related to collateral posted in accordance with the PUCT and ISO/RTO rules.

Income Tax 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

Our capitalization ratios consisted of 73% and 70% long-term debt (less amounts due currently) and 27% and 30% stockholders' equity at December 31, 2024 and 2023, respectively.

Total long-term debt (including amounts due currently) to capitalization was 75% and 73% at December 31, 2024 and 2023, respectively.

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 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).

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.

In the next 12 months, we expect to make approximately $21 million in federal income tax payments, $66 million in state income tax payments and no material TRA payments, offset by $3 million in federal income tax refunds and $19 million in state tax refunds.

For the year ended December 31, 2025, there were $11 million federal income tax payments, $86 million in state income tax payments, and $1 million in TRA payments.

Financial Covenants and Cross-Default Provisions

The Vistra Operations Credit Agreement, Vistra Operations Commodity-Linked Credit Agreement, and Secured LOC Facilities each include a financial covenant.

The Vistra Operations Credit Agreement, Vistra Operations Commodity-Linked Credit Agreement, Secured LOC Facilities, and certain of our other financing arrangements include cross-default provisions that could result in an event of default if there were a failure under financing arrangements to meet payment terms or to observe covenants that could result in an acceleration of payments due.

See Note 11 to the Financial Statements for additional information.

Collateral Support Obligations

The RCT has rules in place to assure that parties can meet their mining reclamation obligations.

In September 2016, the RCT agreed to a collateral bond of up to $975 million to support Luminant's reclamation obligations.

The collateral bond is effectively a first lien on all of Vistra Operations' assets (which ranks pari passu with the Vistra Operations Credit Facilities) that contractually enables the RCT to be paid (up to $975 million) before the other first-lien lenders in the event of a liquidation of our assets.

Collateral support relates to land mined or being mined and not yet reclaimed as well as land for which permits have been obtained but mining activities have not yet begun and land already reclaimed but not released from regulatory obligations by the RCT, and includes cost contingency amounts.

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, 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 $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

Certain of our contractual arrangements contain provisions that could result in an event of default if there were a failure under financing arrangements to meet payment terms or to observe covenants that could result in an acceleration of payments due.

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 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.

Each of Vistra Operations' (or its subsidiaries') commodity hedging agreements and interest rate swap agreements that are secured with a lien on its assets on a pari passu basis with the Vistra Operations Credit Facilities lenders contains a cross-default provision.

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

Under the Vistra Operations Senior Unsecured Indentures, the Vistra Operations Senior Secured Indenture and the Indenture governing the 7.233% 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 of $300 million or more may result in a cross default under the Vistra Operations Senior Unsecured Notes, the Senior Secured Notes, the 7.233% Senior Secured Notes, the Vistra Operations Credit Facilities, the Receivables Facility, the Commodity-Linked Facility and other current or future documents evidencing any indebtedness for borrowed money by the applicable borrower or issuer, as the case may be, and the applicable Guarantor Subsidiaries party thereto.

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

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, 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.

The Repurchase Facility contains a cross-default provision.

The cross-default provision applies, among other instances, if an event of default (or similar event) occurs under the Receivables Facility or the Vistra Operations Credit Facilities.

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

Under the Secured 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 $300 million may result in a cross default under the Secured 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 of $300 million or more, may result in a termination of the Secured LOC Facilities.

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 18 to the Financial Statements for additional information.

1 unchanged sentence

See Note 18 to the Financial Statements for additional information.

Critical Accounting Estimates

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 and Lotus Acquisition requires significant estimates and judgments.

See Note 2 to the Financial Statements for additional information.

The determination of the fair value of property, plant, and equipment contributed and acquired, commodity derivative instruments, and the nuclear decommissioning asset retirement obligations assumed in the Energy Harbor Merger required the most significant level of estimation uncertainty.

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

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

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.

See Derivative Instruments and Mark-to-Market Accounting critical accounting estimate for methodology and assumptions used to estimate the fair value of acquired commodity derivatives.

Derivative Instruments and Mark-to-Market Accounting

Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as market prices change.

Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net income with an offset to derivative assets and liabilities.

The availability of quoted market prices in energy markets is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point.

Where quoted market prices are not available, the fair value is based on unobservable inputs, which require significant judgment.

In computing fair value for derivatives, each forward pricing curve is separated into liquid and illiquid periods.

The liquid period varies by delivery point and commodity.

Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity.

See Notes 13 and 14 to the Financial Statements for additional information.