Vistra Corp.
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Item 1.BUSINESS
References in this report to "we," "our," "us," and "the Company" are to Vistra and/or its subsidiaries, as apparent in the context. See Glossary of Terms and Abbreviations for defined terms.
General
Vistra is an integrated retail electricity and power generation company that provides essential power resources to customers, businesses, and communities from California to Maine. We combine an innovative, customer-centric approach to retail sales with safe, reliable, diverse, and efficient power generation. Our integrated power generation and wholesale operation allows us to efficiently obtain the electricity needed to serve our customers at the lowest cost. The integrated model enables us to structure products and contracts in a way that offers significant value compared to stand-alone retail electric providers.
The Company brings its products and services to market in 18 states and the District of Columbia, including all major competitive wholesale power markets in the U.S. We serve approximately 5 million residential, commercial, and industrial retail customers with electricity and natural gas. Our generation fleet totals approximately 44,000 megawatts of generation capacity powered by a diverse portfolio, including natural gas, nuclear, coal, solar, and battery energy storage facilities.
Market Discussion
The operations of Vistra are aligned into five reportable business segments: (i) Retail, (ii) Texas, (iii) East, (iv) West, and (v) Asset Closure. Our Texas, East, and West segments include our electricity generation operations, and our Asset Closure segment is engaged in the decommissioning and reclamation of retired generation facilities, including mines, and battery removal and remediation activities. See Note 21 to the Financial Statements for additional information.
Retail Operations
Vistra is one of the largest competitive residential retail electricity providers in the U.S. Our retail operations are engaged in retail sales of electricity, natural gas, and related services to approximately 5 million customers. Substantially all of our retail activities are conducted by TXU Energy, Ambit Energy, Dynegy Energy Services, Homefield Energy, Energy Harbor, and U.S. Gas & Electric across 16 U.S. states and the District of Columbia. The largest portion of our retail operations are in Texas, where we provide retail electricity to approximately 2.6 million customers.
Our TXU Energy brand, which has been used to sell electricity to customers in the competitive retail electricity market in Texas for over 20 years, is registered and protected by trademark law. We also own the trade names for Ambit Energy, Dynegy Energy Services, Homefield Energy, TriEagle Energy, Public Power, and U.S. Gas & Electric.
We believe that we have differentiated ourselves by providing a distinctive customer experience predicated on delivering reliable and innovative power products and solutions to our customers, including 100% wind and solar options, as well as thermostats, dashboards, and other programs designed to encourage reduced electricity consumption and increased energy efficiency. Our distinctive power products give our customers choice, convenience, and control over how and when they use electricity and related services.
Electricity Generation Operations
Vistra is one of the largest competitive power generators in the U.S. as measured by MWh of generation capacity. At December 31, 2025, our generating capacity was powered by the following fuels and technologies:
| Primary Fuel | Technology | Net Capacity (MW) | % of Net Capacity | ||||||||||||||
| Natural Gas | CCGT, CT or ST | 26,989 | 62% | ||||||||||||||
| Coal | ST | 8,743 | 20% | ||||||||||||||
| Uranium | Nuclear | 6,448 | 15% | ||||||||||||||
| Renewable | Solar/Battery | 1,274 | 3% | ||||||||||||||
| Fuel Oil | CT | 187 | —% | ||||||||||||||
| Total | 43,641 | 100% | |||||||||||||||
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VISTRA CORP.
Our natural gas-fueled generation fleet is comprised of 28 CCGT generation facilities totaling 22,167 MW and 12 peaking generation facilities totaling 4,822 MW. We satisfy our fuel requirements at these facilities through a combination of spot market and near-term purchase contracts. Additionally, we have near-term natural gas transportation agreements and natural gas storage agreements in place to ensure fleet reliability.
Our coal/lignite-fueled generation fleet is comprised of seven generation facilities totaling 8,743 MW of generation capacity. We meet our fuel requirements at our coal-fueled generation facilities in PJM and MISO with coal purchased from multiple suppliers under contracts of various lengths and transported to the facilities by either railcar or barges. We meet our fuel requirements in ERCOT using lignite that we mine at our generation facilities and coal purchased and transported by railcar.
We own and operate six nuclear generation units at four different facilities:
| Unit | ISO | Net Capacity (MW) | Refueling Outage Frequency | License Expiration Date | ||||||||||||||||||
| Comanche Peak Unit 1 | ERCOT | 1,200 | 18 Months | 2050 | ||||||||||||||||||
| Comanche Peak Unit 2 | ERCOT | 1,200 | 18 Months | 2053 | ||||||||||||||||||
| Beaver Valley Unit 1 | PJM | 939 | 18 Months | 2036 | ||||||||||||||||||
| Beaver Valley Unit 2 | PJM | 933 | 18 Months | 2047 | ||||||||||||||||||
| Perry | PJM | 1,268 | 24 Months | 2046 | ||||||||||||||||||
| Davis-Besse | PJM | 908 | ||||||||||||||||||||
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Financial statements
data from SEC XBRL filings. Values are as-reported; restatements supersede originals. Values reported in .
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VISTRA CORP.
Item 2.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read together with the condensed consolidated financial statements and related notes included in Part I, Item 1. Financial Statements.
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.
Iran Conflict
We are monitoring the conflict involving the United States, Israel, and Iran and related instability in the Middle East, including the potential for further escalation and disruption. Although the Company does not conduct operations in the affected region, prolonged or expanded instability could indirectly affect the Company through broader macroeconomic and commodity-market impacts, including changes in natural gas and power prices, supply-chain disruptions, construction delays, increased inflationary pressures, and capital-market volatility, which could impact our future results of operations. See Factors Affecting Our Financial Condition and Results of Operations — Commodity Prices for additional information on our commodity hedging strategy and estimated hedging levels for the balance of 2026 and 2027.
Russia/Ukraine Conflict
We are monitoring developments in the Russia and Ukraine conflict, specifically sanctions (or potential sanctions) against Russian nuclear fuel supply and enrichment activities 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 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 2026 and 2027 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 and 2027 is onshore and in our inventory. 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.
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Noteworthy Developments
Collateral Release
On December 2, 2025, S&P upgraded Vistra Operations' issuer credit rating from BB+ to BBB- and revised its outlook from Positive to Stable, and on March 20, 2026, S&P upgraded the Senior Unsecured Notes rating from BB+ to BBB-. On March 16, 2026, Fitch upgraded Vistra Operations' issuer default rating and the Senior Unsecured Notes rating from BB+ to BBB- and revised its outlook from Positive to Stable. As a result of these investment-grade ratings and the satisfaction of certain other conditions specified in the Vistra Operations Senior Secured Indenture, an investment grade event was deemed to have occurred, and the liens on the collateral securing the Senior Secured Notes were automatically terminated and released in full on April 2, 2026 (Collateral Release).
The Collateral Release represents the elimination of the collateral and related lien provisions under the Vistra Operations Senior Secured Indenture only and did not modify, refinance, extinguish, or otherwise change the outstanding principal amount, maturity, interest rates, or other material terms of the Senior Secured Notes. Following the Collateral Release, the Senior Secured Notes are effectively unsecured and rank pari passu with the Senior Unsecured Notes. The Collateral Release is subject to reversion if the applicable rating agencies withdraw the investment-grade ratings or downgrade the ratings below investment grade, subject to a 60-day grace period.
Additionally, Vistra Operations repaid $2.444 billion in outstanding borrowings under the Term Loan B-3 facility in April 2026, and in coordination with the investment-grade ratings, met the collateral suspension provisions of the Vistra Operations Credit Agreement and Commodity-Linked Credit Agreement releasing all liens securing the Vistra Operations Credit Facilities and the Vistra Operations Commodity-Linked Credit Facility (Credit Facility Collateral Suspension). The Credit Facility Collateral Suspension is subject to reversion if the applicable rating agencies withdraw the investment-grade ratings or downgrade the ratings below investment grade, subject to a 60-day grace period.
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; and
•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.
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VISTRA CORP.
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 the second half of 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 of $137 million, 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 we entered into a 20-year PPA (with options to extend for up to an additional 20 years) with AWS, pursuant to which we agreed to supply 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 2026 tax year. 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. See Note 8 to the Financial Statements for additional information.
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. See Note 8 to the Financial Statements for additional information.
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Planned Gas-Fueled Dispatchable Power in ERCOT
In May 2024, we announced our intention to add up to 2,000 MW of dispatchable, natural gas-fueled electricity capacity in west, central, and north Texas consisting of the following projects:
•Building up to 860 MW of advanced simple-cycle peaking plants to be located in west Texas to support the increasing power needs of the region, including the state's oil and gas industry. Early development work is underway on this project which we anticipate will be online in 2028.
•Repowering the coal-fueled Coleto Creek Power Plant near Goliad, Texas, set to retire in 2027 to comply with EPA rules, as a natural-gas fueled plant with up to 600 MW of capacity.
•Completing upgrades at existing natural gas-fueled plants that will add more than 500 MW of summer capacity and 100 MW of winter capacity.
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. Due diligence is progressing and we are in the final stages.
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, 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 MWh, subject to an annually inflated gross-receipts based phase out. As discussed in Note 5 to the Financial Statements in our 2025 Form 10-K, we recognized transferable nuclear PTC revenues of $220 million and $545 million in the years ended December 31, 2025 and 2024, respectively. U.S. 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, load growth, 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.
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VISTRA CORP.
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 2026 calendar years, substantially all of our expected generation volumes for these years 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 table below summarizes the average around-the-clock settled prices for the periods presented and does not necessarily reflect prices we realized or costs we incurred.
| Three Months Ended March 31, | |||||||||||||||||||
| 2026 | 2025 | ||||||||||||||||||
Average Power Price ($/MWh): | |||||||||||||||||||
| ERCOT North Hub | $ | 32.18 | $ | 30.91 | |||||||||||||||
| ERCOT West Hub | $ | 29.56 | $ | 30.13 | |||||||||||||||
| PJM AEP Dayton Hub | $ | 70.66 | $ | 47.91 | |||||||||||||||
| PJM Northern Illinois Hub | $ | 51.08 | $ | 35.19 | |||||||||||||||
| PJM Western Hub | $ | 97.41 | $ | 53.91 | |||||||||||||||
| MISO Indiana Hub | $ | 67.25 | $ | 44.84 | |||||||||||||||
| ISONE Massachusetts Hub | $ | 117.31 | $ | 102.77 | |||||||||||||||
| New York Zone A | $ | 100.48 | $ | 68.63 | |||||||||||||||
| CAISO NP15 | $ | 29.01 | $ | 40.89 | |||||||||||||||
Average Natural Gas Price ($/MMMBtu) | |||||||||||||||||||
| NYMEX Henry Hub | $ | 4.90 | $ | 4.28 | |||||||||||||||
| Houston Ship Channel | $ | 3.26 | $ | 3.46 | |||||||||||||||
| Permian Basin | $ | (1.05) | $ | 1.83 | |||||||||||||||
| Dominion South | $ | 4.73 | $ | 3.74 | |||||||||||||||
| Tetco ELA | $ | 4.91 | $ | 4.06 | |||||||||||||||
| Chicago Citygate | $ | 5.34 | $ | 4.00 | |||||||||||||||
| Tetco M3 | $ | 9.61 | $ | 6.42 | |||||||||||||||
| Algonquin Citygates | $ | 14.08 | $ | 11.83 | |||||||||||||||
| PG&E Citygate | $ | 2.07 | $ | 3.71 | |||||||||||||||
Estimated hedging levels for generation volumes in our Texas, East, and West segments as of March 31, 2026 were as follows:
Balance of 2026 | 2027 | |||||||||
| Nuclear/Renewable/Coal Generation: | ||||||||||
| Texas | 100 | % | 100 | % | ||||||
| East | 98 | % | 68 | % | ||||||
| Natural Gas Generation: | ||||||||||
| Texas | 100 | % | 59 | % | ||||||
| East | 99 | % | 90 | % | ||||||
| West | 100 | % | 56 | % | ||||||
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Seasonality
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 the three months ended March 31, 2026 and 2025.
| Three Months Ended March 31, | |||||||||||||||||||||||||||||||||||||||||||||||
| Retail | Texas | East | West | ||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||||||||||||||||||||||
| Weather - percent of normal (a): | |||||||||||||||||||||||||||||||||||||||||||||||
| Heating degree days | 73% | 105% | 77 | % | 113 | % | 107 | % | 101 | % | 64 | % | 124% | ||||||||||||||||||||||||||||||||||
(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.
Results of Operations
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. These non-GAAP financial measures reflect an additional way of viewing aspects of our business that, when viewed (i) with our GAAP results and (ii) the accompanying reconciliations to corresponding GAAP financial measures may provide a more complete understanding of factors and trends affecting our business. Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers, and evaluate overall financial performance, we believe they provide useful information for investors.
These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are, by definition, an incomplete understanding of Vistra and must be considered in conjunction with GAAP measures. In addition, non-GAAP financial measures are not standardized; therefore, it may not be possible to compare these financial measures with other companies' non-GAAP financial measures having the same or similar names. We strongly encourage investors to review the condensed consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.
When EBITDA or Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss).
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Consolidated Results of Operations
Three Months Ended March 31, 2026 Compared to the Three Months Ended March 31, 2025
The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the three months ended March 31, 2026:
| Three Months Ended March 31, 2026 | ||||||||||||||||||||||||||||||||||||||||||||||
| Retail | Texas | East | West | Asset Closure | Eliminations / Corporate and Other | Vistra Consolidated | ||||||||||||||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||||||||||||||||
| Operating revenues | $ | 3,689 | $ | 2,987 | $ | 2,260 | $ | 89 | $ | 6 | $ | (3,391) | $ | 5,640 | ||||||||||||||||||||||||||||||||
| Fuel, purchased power costs, and delivery fees | (4,097) | (416) | (1,384) | (25) | — | 3,392 | (2,530) | |||||||||||||||||||||||||||||||||||||||
| Operating costs | (38) | (261) | (373) | (16) | (12) | — | (700) | |||||||||||||||||||||||||||||||||||||||
| Depreciation and amortization | (10) | (174) | (265) | (14) | (3) | (18) | (484) | |||||||||||||||||||||||||||||||||||||||
| Selling, general, and administrative expenses | (256) | (59) | (50) | (3) | (15) | (44) | (427) | |||||||||||||||||||||||||||||||||||||||
| Operating income (loss) | (712) | 2,077 | 188 | 31 | (24) | (61) | 1,499 | |||||||||||||||||||||||||||||||||||||||
Other income (deductions), net | 1 | — | (34) | — | 4 | 5 | (24) | |||||||||||||||||||||||||||||||||||||||
| Interest expense and related charges | (13) | 14 | 22 | 3 | — | (289) | (263) | |||||||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes | (724) | 2,091 | 176 | 34 | (20) | (345) | 1,212 | |||||||||||||||||||||||||||||||||||||||
| Income tax expense | — | — | — | — | — | (183) | (183) | |||||||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | (724) | $ | 2,091 | $ | 176 | $ | 34 | $ | (20) | $ | (528) | $ | 1,029 | ||||||||||||||||||||||||||||||||
| Income tax expense | — | — | — | — | — | 183 | 183 | |||||||||||||||||||||||||||||||||||||||
| Interest expense and related charges (a) | 13 | (14) | (22) | (3) | — | 289 | 263 | |||||||||||||||||||||||||||||||||||||||
| Depreciation and amortization (b) | 10 | 211 | 355 | 14 | 3 | 18 | 611 | |||||||||||||||||||||||||||||||||||||||
| EBITDA before Adjustments | (701) | 2,288 | 509 | 45 | (17) | (38) | 2,086 | |||||||||||||||||||||||||||||||||||||||
| Unrealized net (gain) loss resulting from commodity hedging transactions | 765 | (1,722) | 225 | 9 | — | — | (723) | |||||||||||||||||||||||||||||||||||||||
| Purchase accounting impacts | — | — | (1) | — | — | — | (1) | |||||||||||||||||||||||||||||||||||||||
| Non-cash compensation expenses | — | — | — | — | — | 32 | 32 | |||||||||||||||||||||||||||||||||||||||
| Transition and merger expenses | (1) | — | — | — | — | 12 | 11 | |||||||||||||||||||||||||||||||||||||||
| Insurance income (c) | — | — | — | — | (6) | — | (6) | |||||||||||||||||||||||||||||||||||||||
| Decommissioning-related activities (d) | — | 4 | 60 | — | 2 | — | 66 | |||||||||||||||||||||||||||||||||||||||
Other, net | 5 | 16 | 8 | 2 | 2 | (23) | 10 | |||||||||||||||||||||||||||||||||||||||
| Adjusted EBITDA | $ | 68 | $ | 586 | $ | 801 | $ | 56 | $ | (19) | $ | (17) | $ | 1,475 | ||||||||||||||||||||||||||||||||
____________
(a)Corporate and Other includes $16 million of unrealized mark-to-market net gains on interest rate swaps.
(b)Includes nuclear fuel amortization of $36 million and $90 million, respectively, in the Texas and East segments.
(c)Includes revenues from Moss Landing Incident business interruption proceeds in the Asset Closure segment.
(d)Includes NDT (income) loss of the PJM nuclear facilities, ARO and environmental remediation expenses, and other expenses associated with the Moss Landing Incident.
53
VISTRA CORP.
The following table presents Net income (loss), EBITDA and Adjusted EBITDA for the three months ended March 31, 2025:
| Three Months Ended March 31, 2025 | |||||||||||||||||||||||||||||||||||||||||
| Retail | Texas | East | West | Asset Closure | Eliminations / Corporate and Other | Vistra Consolidated | |||||||||||||||||||||||||||||||||||
| (in millions) | |||||||||||||||||||||||||||||||||||||||||
| Operating revenues | $ | 3,168 | $ | 210 | $ | ||||||||||||||||||||||||||||||||||||
Recent insider activity
| Date | Insider | Role | Action | Shares | Price | Value |
|---|---|---|---|---|---|---|
| 2026-06-02 | Montemayor Margaret | SVP, Chief Accounting Officer | Sell | -4,600 | $160.00 | -$736,000 |
| 2026-05-27 | Montemayor Margaret | SVP, Chief Accounting Officer | Sell | -5,000 | $164.96 | -$824,800 |
Source: SEC Form 4 filings.
Next expected filings
- ~2026-08-09 10-Q expected by 2026-08-11 (in 55 days)
- ~2026-11-08 10-Q expected by 2026-11-10 (in 146 days)
- ~2027-02-27 10-K expected by 2027-02-28 (in 257 days)
- ~2027-05-09 10-Q expected by 2027-05-11 (in 328 days)
Predicted from historical filing cadence; not an SEC commitment.
Recent SEC filings
- 2026-05-08 10-Q Quarterly Report
- 2026-05-07 8-K Earnings Release; Financial Statements and Exhibits
- 2026-04-28 8-K Material Agreement Entered; Material Financial Obligation; Financial Statements and Exhibits
- 2026-02-27 10-K Annual Report
- 2026-02-26 8-K Earnings Release; Financial Statements and Exhibits
- 2026-01-27 8-K Material Agreement Entered; Material Financial Obligation; Financial Statements and Exhibits
- 2026-01-05 8-K Material Agreement Entered; Unregistered Equity Sale; Regulation FD Disclosure; Financial Statements and Exhibits
- 2025-12-17 8-K Other Events
- 2025-11-07 10-Q Quarterly Report
- 2025-11-06 8-K Earnings Release; Financial Statements and Exhibits
- 2025-10-28 8-K Completion of Acquisition/Disposition; Regulation FD Disclosure; Financial Statements and Exhibits
- 2025-10-15 8-K Material Agreement Entered; Material Financial Obligation; Financial Statements and Exhibits
- 2025-10-06 8-K Material Agreement Entered; Material Financial Obligation; Financial Statements and Exhibits
- 2025-09-29 8-K Other Events
- 2025-08-08 10-Q Quarterly Report