Vistra (VST) Q3 2026 Earnings Call Transcript

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DATE

Friday, Nov. 6, 2026

CALL PARTICIPANTS

• Vice President of Investor Relations – Eric Micek
• President and Chief Executive Officer – James Burke
• Executive Vice President and Chief Financial Officer – Kristopher Moldovan
• President, Vistra Retail – Stacey Dore

TAKEAWAYS

• Ongoing Operations Adjusted EBITDA — $2.378 billion for the third quarter, representing a more than 50% increase compared to $1.581 billion in the third quarter 2025.
• Net Income — $1,140 million for the third quarter, driven by higher EBITDA and a $375 million increase in unrealized mark-to-market gains on derivative positions.
• 2026 Adjusted EBITDA Guidance — $7.1 billion to $7.5 billion, narrowed from previous ranges to reflect higher midpoints following record performance and the Cogentrix acquisition.
• 2026 Adjusted FCFbG — $4.3 billion to $4.7 billion, with the midpoint raised due to strong year-to-date results.
• 2027 Adjusted EBITDA Guidance — $7.7 billion to $8.5 billion, including contributions from the Cogentrix assets and the Meta power purchase agreement.
• 2027 Adjusted FCFbG Guidance — $4.3 billion to $5.1 billion, reflecting structurally improved demand and multiyear profitability trends.
• Texas Segment Adjusted EBITDA — $1,227 million for the quarter, compared to $784 million in the prior year period.
• East Segment Adjusted EBITDA — $979 million for the quarter, compared to $719 million in the third quarter 2025.
• Retail Segment Adjusted EBITDA — $98 million, driven by favorable margins and higher customer volumes resulting from record-hot weather.
• Cogentrix Acquisition — $4 billion net purchase price for approximately 5,500 megawatts of capacity, closed on Oct. 30, 2026.
• Acquisition Multiples — less than 7x forward EBITDA on average across more than 12 gigawatts of acquisitions including Energy Harbor, Lotus, and Cogentrix.
• Share Repurchases — approximately $1 billion completed in 2026 through Nov. 2, part of a $6.7 billion total program since Nov. 2021.
• Share Repurchase Authorization — $1.5 billion in additional authorization approved by the board, leaving a total of $2.5 billion remaining.
• Leverage Ratio — 2.8x net debt to adjusted EBITDA on a pro forma basis following the Cogentrix closing and preferred stock redemption.
• Thermal Fleet Availability — nearly 95% during the third quarter, reflecting successful spring maintenance despite record summer demand peaks.
• ERCOT Load Growth — 4% to 6% projected through 2030, driven by industrial activity, population growth, and data center demand.
• PJM Load Growth — 2% to 3% projected through 2030, supported by ongoing electrification and robust energy demand.
• Generation Capacity — approximately 50,000 megawatts total, including 25,000 megawatts of modern combined cycle gas generation.
• Free Cash Flow Per Share — projected to grow from approximately $10.50 in 2025 to $14 in 2027.
• Odessa PPA — 20-year agreement for 207 megawatts with New Era Energy and Digital at the Odessa combined cycle gas plant.
• Available Liquidity — $8.923 billion as of Sept. 30, 2026, though pro forma liquidity is approximately $5.4 billion following the Cogentrix acquisition.
• Meta PPA — 20-year agreement for operating capacity at the Perry nuclear plant, expected to contribute to 2027 results.
• Illinois Solar Operations — 405 megawatts at the Pulaski Solar Facility commenced operations under a power purchase agreement with Microsoft.
• Generation Hedges — 98% of expected volumes for 2027 and 78% for 2028 are hedged as of Oct. 30, 2026.
• Capital Return Target — at least $300 million in annual dividends alongside a target of at least $1 billion in annual share repurchases through 2028.

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RISKS

• Burke noted that “ERCOT prices, however, have been trending lower,” citing factors such as the conversion of crypto mining facilities to data centers and a pause in permitting.
• Burke indicated that load interconnect queues were “overstated across the country and especially in ERCOT,” due to speculative developers keeping options open.
• Dore stated that the “load interconnection process does continue to be a timing constraint” for gas asset projects, as customers typically require grid connections.

SUMMARY

Vistra Corp. (VST +10.61%) reported record third-quarter performance for 2026, highlighted by a 50% increase in adjusted EBITDA and the strategic expansion of its generation portfolio through the close of the Cogentrix acquisition. Management reported that the company achieved nearly 95% availability across its thermal fleet during a quarter marked by record peak demand in both PJM and ERCOT markets. The company stated that its multiyear profitability trajectory is supported by structurally improved demand from industrial activity and data centers, leading to the initiation of 2027 guidance and a significant expansion of its share repurchase program. Management confirmed its focus on maintaining investment-grade credit metrics while executing on a diversified growth strategy that includes nuclear uprates, gas-to-coal conversions, and new gas-fired generation in the Permian Basin.

• The Cogentrix transaction is expected to deliver high single-digit free cash flow accretion in the near term, rising to double-digit accretion starting in 2029.
• Management cited line of sight to approximately 70% growth in adjusted free cash flow before growth per share from 2027 to 2030, assuming consistent capital allocation to share repurchases.
• The company stated it is advocating for higher collateral requirements and take-or-pay agreements in load interconnection queues to focus on high-quality projects.
• Burke stated that the recent election results preserve the company’s fundamental view of market opportunities, noting, “our team is prepared to continue executing.”
• Dore indicated that the elimination of the IRAS proposal in PJM has provided customers with more clarity on how to satisfy resource adequacy requirements through bilateral contracts.
• The company anticipates that PJM nuclear uprates will begin contributing to earnings in 2031, following capital expenditures during the current planning period.
• Management reported that the board authorized an additional $1.5 billion for share repurchases, with the full $2.5 billion remaining authorization expected to be utilized by the end of 2028.

INDUSTRY GLOSSARY

• ARO: Asset Retirement Obligation, a legal obligation associated with the retirement of a tangible long-lived asset.
• CCGT: Combined Cycle Gas Turbine, a highly efficient form of power generation that uses both gas and steam turbines.
• ERCOT: Electric Reliability Council of Texas, the organization that manages the flow of electric power to 26 million Texas customers.
• FCFbG: Ongoing Operations Adjusted Free Cash Flow before Growth, a non-GAAP measure of liquidity excluding certain growth-related capital expenditures.
• IRAS: Interconnection Reform and Analysis Study, a proposed regulatory framework for managing new load interconnections.
• MW: Megawatt, a unit of power equal to one million watts.
• NDT: Nuclear Decommissioning Trust, a fund set aside for the future dismantling and decontamination of nuclear power plants.
• PJM: A regional transmission organization that coordinates the wholesale electricity market across 13 U.S. states and the District of Columbia.
• PPA: Power Purchase Agreement, a long-term contract for the sale of electricity between a power producer and a customer.
• RBP: Reliability Benchmark Procurement, a process used in power markets to ensure sufficient generation capacity.

Full Conference Call Transcript

Operator: Good day, everyone. Welcome to the Vistra Corp. Third Quarter 2026 Earnings Call. [Operator Instructions] This call is being recorded. If you have any objections, please disconnect at this time. I would now like to turn the call over to Eric Micek, Vice President of Investor Relations. Please go ahead.

Eric Micek: Good morning, and thank you for joining Vistra’s investor webcast discussing our third quarter 2026 results. Our discussion today is being broadcast live from the Investor Relations section of our website at www.vistracorp.com. There, you can also find copies of today’s investor presentation and earnings release. Providing our prepared remarks today are Jim Burke, Vistra’s President and Chief Executive Officer; and Kris Moldovan, Vistra’s Executive Vice President and Chief Financial Officer. Other senior Vistra executives will be available to address questions during the second part of today’s call as necessary. Earnings release, presentation and other matters discussed on the call today include references to certain non-GAAP financial measures.

All references to adjusted EBITDA and adjusted free cash flow before growth throughout this presentation refer to ongoing operations adjusted EBITDA and ongoing operations adjusted free cash flow before growth. Reconciliations to the most directly comparable GAAP measures are provided in the earnings release and in the appendix to the investor presentation available in the Investor Relations section of Vistra’s website. Also, today’s discussion contains forward-looking statements, which are based on assumptions we believe to be reasonable only as of today’s date. Such forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those projected or implied. We assume no obligation to update our forward-looking statements.

I encourage all listeners to review the safe harbor statements included on Slide 2 of the investor presentation on our website that explain the risks of forward-looking statements, the limitations of certain industry and market data included in the presentation and the use of non-GAAP financial measures. I will now turn the call over to our President and CEO, Jim Burke.

James Burke: Thank you, Eric. Good morning, and thank you all for joining us today to discuss our third quarter 2026 results. Before we jump into our performance, I recognize there is interest in the election results and any anticipated impacts for our business. I am sure we will discuss this more in Q&A, but just a few opening thoughts. Given our company has a very long history of serving customers and operating in our communities, we constantly work with policymakers of both parties at local, state and federal levels. We offer an essential service, and our focus remains the same after the election, providing reliable and affordable power to our customers.

We operate a diversified fleet of assets across the country while serving retail customers in 16 states plus D.C. We believe we are in some of the most attractive states for growth, and we expect policymakers to remain focused on economic opportunities in ensuring load growth is managed in a constructive manner for all customers. To be clear, the pacing was already being impacted ahead of the election, but our plans have always had a more conservative view of the AI build-out. Stated more simply, the election results do not change our fundamental view of the opportunities Vistra has, and our team is prepared to continue executing. Starting on Slide 5.

Vistra delivered approximately $2.4 billion of adjusted EBITDA in the third quarter, a record for the company. Our generation team performed very well, delivering commercial availability approaching 95% across the thermal fleet despite the elevated demand from the record third quarter weather. This impressive operational performance was complemented by the results delivered by our commercial team through execution of our comprehensive hedging program and our retail team, which continues to deliver strong results.

With this record third quarter performance, combined with our results year-to-date and the recent closing of the Cogentrix acquisition, we are narrowing our guidance ranges for our 2026 adjusted EBITDA to $7.1 billion to $7.5 billion and our 2026 adjusted free cash flow before growth to $4.3 billion to $4.7 billion, with each reflecting a higher midpoint than the original ranges. Importantly, this marks the fifth consecutive year we expect to finish above the midpoint of our original guidance range. Moving to the near-term outlook.

We are introducing guidance ranges for 2027 adjusted EBITDA of $7.7 billion to $8.5 billion and 2027 adjusted free cash flow before growth of $4.3 billion to $5.1 billion, including the expected contribution from the Cogentrix acquisition and the power purchase agreement with Meta for the operating capacity at our Perry nuclear plant. Moving to Slide 6. We closed the Cogentrix acquisition on October 30, and we are excited to welcome our new team members to the Vistra family. As we’ve said before, we believe integrating and operating generation assets at scale is a core competency of Vistra. We’ve demonstrated this with Dynegy, Energy Harbor and most recently the assets acquired from Lotus. We see similar opportunities with Cogentrix.

These assets are a strong complement to our existing fleet, expanding our presence in key markets and our ability to serve growing customer demand with reliable, flexible power. They also fit with our core strategy of owning and operating dispatchable generation assets, which we believe will continue to play a critical role in delivering reliable, affordable and flexible power to U.S. electricity markets. With Cogentrix, Vistra now owns a generation portfolio of approximately 50,000 megawatts, including approximately 25,000 megawatts of modern combined cycle gas generation across all the major competitive markets. In early 2018, 100% of our generation earnings came from Texas.

However, today, just under 40% of our generation earnings comes from the Texas fleet, reflecting the diversification of our business across markets, technologies and customer classes. From a financial perspective, the Cogentrix deal economics were even more attractive. We acquired approximately 5,500 megawatts for a net purchase price of approximately $4 billion, including 5 million shares of common stock at an agreed value of $185 per share, equating to a value of approximately $729 per kilowatt of capacity. Since the announcement of the transaction, our forecast for the earnings contribution of the Cogentrix assets has meaningfully improved.

Accordingly, we now expect the transaction to deliver high single-digit adjusted free cash flow accretion over the near term, increasing to double-digit accretion beginning in 2029. Turning to Slide 7. Actualized data continues to confirm the structurally improved demand environment we’ve talked about for our core markets. In 2026, both PJM and ERCOT set new all-time peak load records with PJM reaching approximately 168 gigawatts and ERCOT approximately 91 gigawatts. And importantly, the power markets performed well during these peaks, demonstrating that competitive power markets can respond effectively as demand grows. Growth in energy continues to be robust, and it’s coming from multiple sources, increased industrial activity, population growth, particularly in Texas, ongoing electrification and data centers.

You see these strong demand trends playing out in PJM with higher forward prices. ERCOT prices, however, have been trending lower. We believe this is due to several factors, including some crypto mining facilities coming offline so they can convert into data centers as well as the data center audit and permitting pause. We do not see this as a long-term impact. As we’ve said for some time, load interconnect queues were overstated across the country and especially in ERCOT, driven by speculation from developers who are keeping options open to see where progress can be made. Residents in some communities are understandably concerned about the level of proposed development activity and policymakers are working on longer-term solutions.

As we’ve advocated in multiple forums, raising the bar on these projects can go a long way towards identifying the ones that are likely to move forward. This includes higher collateral requirements for interconnect requests, committing the take-or-pay agreement for the incremental wires charges, line of sight to equipment and an agreement with an end-use customer. Aspects of this have been done effectively in other states, and it has helped to focus on the real projects that are ready to move forward. Despite the recent political and regulatory activity, our outlook has not changed. We still see load growth of 4% to 6% in ERCOT and 2% to 3% in PJM through 2030.

Vistra with its large diversified fleet is well equipped to meet this growth. Our flexible combined cycle gas plants and quick-start peaking plants can operate at higher utilizations and that remains the cheapest and quickest source of incremental generation. Turning to Slide 8. You can see how the load growth fundamentals support Vistra’s multiyear improvement in profitability levels. At the center of this forecast is the day-to-day execution by the teams in our base business, which continues to perform very well across generation, retail and our commercial activities. Moving beyond operational excellence, the team has already made substantial progress on several major initiatives that underpin the significant growth forecasted for our business.

We’ve now successfully closed on over 12 gigawatts of acquisitions through Energy Harbor, Lotus and Cogentrix at attractive acquisition multiples of less than 7x forward EBITDA on average. Additionally, the development team has delivered over 4 gigawatts of long-term power purchase agreements across both our nuclear and gas sites, some of which like the Perry nuclear contract with Meta will begin contributing to our 2027 results. We also see an extensive list of near-term initiatives and development opportunities like the coal-to-gas conversions and Permian Peaker new build that will begin contributing in 2028. Looking longer term, customer conversations and activity levels remain high.

We’re in active discussions with large load customers in both PJM and ERCOT on existing and new build assets, addressing both short-term and long-term power needs. Customers would prefer to have clarity, but working together, we are finding ways to work through the uncertainty, and our team remains engaged on multiple projects to help customers develop solutions to meet their power needs. We see pathways to realize multiple additional contracting opportunities across our large and diversified fleet of approximately 50,000 megawatts of nuclear, gas, coal and renewable generation. Our expanded development team continues to work through these opportunities, and we are encouraged by the significant progress achieved to date.

Now I’ll turn it over to Kris to provide more details on our third quarter results, our capital allocation priorities and our adjusted free cash flow per share growth expectations. Kris?

Kristopher Moldovan: Thank you, Jim. Turning to Slide 10. Vistra delivered adjusted EBITDA of $2.378 billion, a company record that represents a more than 50% increase compared to the third quarter of 2025. Our Generation business delivered $2.280 billion of adjusted EBITDA in the quarter compared to $1.544 billion in the third quarter of 2025. The year-over-year improvement was primarily driven by average realized prices that were more than 10% higher on a per megawatt hour basis compared to the same quarter last year, higher capacity revenue, optimizing the dispatch of our flexible gas generation assets in response to market conditions, the restart of Martin Lake Unit 1 and the contribution from assets acquired from Lotus in the fourth quarter of 2025.

Retail also had a strong quarter, contributing approximately $98 million of adjusted EBITDA. As a reminder, we expect lower profitability in the first and third quarters due to the shape and level of supply cost. Despite the higher summer costs, retail performed very well, driven by favorable margins and strong customer volumes, largely due to the hotter-than-normal weather in the quarter. Moving to our year-to-date results. Adjusted EBITDA totaled approximately $5.639 billion, representing a more than 35% increase over the prior year period.

Similar to the quarter, the year-to-date improvement was largely driven by higher average realized prices across our fleet, higher capacity payments in PJM, the return of Martin Lake Unit 1, fleet dispatch optimization and the contribution from the assets acquired from Lotus. Moving to Slide 11. We continue to take a disciplined approach to capital allocation, prioritizing a strong balance sheet, return of capital and strategic growth opportunities. Beginning with the balance sheet, the diversification of our business and a significantly higher and more contracted earnings outlook have driven the derisking of our credit profile, which contributed to us achieving investment-grade credit ratings from 2 of the 3 major credit rating agencies.

Pro forma for the closing of the Cogentrix acquisition and the redemption of our Series A preferred stock with proceeds from the issuance of junior subordinated notes, our net debt to adjusted EBITDA ratio is approximately 2.8x. Going forward, we expect our leverage ratio to continue to decline, resulting in credit metrics consistent with our target credit ratings of BBB flat and Baa2. Moving to capital return. Our share repurchase program continues to create significant value. Since initiating the program in November 2021, we have retired approximately 172 million shares at an average cost of approximately $39 per share, including the approximately $1 billion in share repurchases already completed this year through November 2.

With the additional Board authorization this quarter, we now have approximately $2.5 billion of share repurchase authorization, which we currently expect to fully utilize by no later than the end of 2028. This additional authorization provides us flexibility to purchase more than our annual target of at least $1 billion of share repurchases in 2026, 2027 and/or 2028 as market conditions warrant. And of course, we continue to target at least $300 million of annual dividends. Finally, turning to growth. As Jim outlined, the improved power demand backdrop has increased the number of available growth opportunities we have.

Some of these growth opportunities such as contracts with existing assets would result in little to no incremental capital requirements, leading to high rates of return. Other opportunities like our Permian Peakers and nuclear uprates as well as potential contracted new build do require incremental capital. Importantly, we have the opportunity to work with strategic partners like Helix Digital Infrastructure that can expand our access to long-term capital. Finally, M&A continues to be a strong driver of value for the business. We will continue to be opportunistic, looking to strategically add assets that are complementary to our existing fleet. As always, we will be disciplined in the deployment of capital to growth investments, whether organic or inorganic.

For all investment decisions, our target return threshold remains consistent at mid-teens or higher on a levered basis. Finally, moving to Slide 12. As we discussed earlier this year, we believe adjusted free cash flow before growth per share is an important indicator of long-term value creation for shareholders as it captures not only the sustainably higher level of cash flow generation of the business, but also the benefits of our consistent allocation of a significant portion of our available cash to share repurchases.

You can see from the chart that we are already well underway to delivering on a compelling growth trajectory over the next several years with adjusted free cash flow per share growing from just under $10.5 in 2025 to approximately $14 in 2027, assuming the midpoint of our adjusted free cash flow before growth guidance and the deployment of capital to share repurchases at the November 2 share price. Looking beyond 2027, the actions we’ve already taken to date, including our agreement with AWS at Comanche Peak, our agreement with Meta for operating capacity at Davis-Besse and the completion of our Permian Peakers provide line of sight to continued growth through the end of the decade.

Combined with the current forward curves and a simplifying assumption with respect to the deployment of our excess cash available for allocation to share repurchases. We have line of sight to approximately 70% growth in adjusted free cash flow before growth per share from 2027 to 2030, while achieving leverage metrics meaningfully below what we believe would be required for us to be at our target ratings of BBB flat and Baa2.

We think that the level of growth is compelling, particularly when you consider the additional opportunities that are not fully reflected in that outlook, including the final ramp of the AWS Comanche Peak agreement assumed in 2032 and the contributions from the PJM nuclear uprates, which are expected to begin in 2031. Additionally, we believe we can execute on additional growth opportunities that would provide higher returns than repurchasing our shares. As Jim outlined earlier, the level of customer engagement across our portfolio remains robust, and we remain optimistic in our ability to deliver additional long-term contracts across both our nuclear and gas fleets.

We also see continued improvement in power market fundamentals that is not fully reflected in market curves today. These opportunities vary in timing, but we believe they have the potential to drive meaningful additional growth beyond what is reflected in this outlook. Our objective remains the same to allocate capital to opportunities that we believe create the highest long-term value for our shareholders. In closing, we believe we have a clear and tangible path to substantial per share free cash flow growth with a number of additional opportunities to build on that trajectory over time. Our team remains focused on finishing the year strong, including finishing the preparation of our fleet to deliver reliable performance through the winter months ahead.

With that, operator, we’re ready to open the line for questions.

Operator: [Operator Instructions] Our first question will come from the line of Shar Pourreza with Wells Fargo.

Shahriar Pourreza: Eric got a little technological this morning. It’s throwing me off.

James Burke: I hope it’s working.

Shahriar Pourreza: It’s working great. It’s working great. So just Jim, on the 2030 free cash flow per share outlook of $24, obviously, there’s a disconnect between sort of the forwards and fundamentals, especially if all the battery capacity goes away with the Batch Zero projects post ’28 alone in ERCOT. Can you just comment on what is embedded in that number from a market perspective? What inorganic assumptions are in there? It seems like maybe there’s some placeholders for that. And is there continued buybacks in there, et cetera. So maybe just elaborate on the $24 because that’s a lot of growth.

James Burke: Yes. I will start, Shar. First of all, we have seen some depression in ERCOT forwards. Obviously, the ’26 settles and even where ’27 is trading, I think, is a function of some of the slower load growth that we’ve seen, and we reflected that in our charts, still robust growth, but not at the levels that we would have expected. When we do this analysis out to 2030, we’re still reflecting kind of the market forward. So we’re not making an assumption that there’s going to be some big recovery in ERCOT.

However, we think things will tighten if the load starts to get hooked up, which we think Texas is going to be in a position to do it. So there’s not an assumption here of some recovery, Shar. I think that is — that is something that we would expect to get more clarity on as we work through the details with PUC and ERCOT and obviously, this new administration for the state. And then I’ll let Kris comment here. But then we always make choices about capital allocation. We like the growth projects that we’ve already got announced. We still think there are growth projects to come that we haven’t yet announced.

But this assumes that if some of those growth projects don’t come, we could lean in a little bit harder on the buyback program because that’s always an opportunity for us. Clearly, where we’re trading, we think that’s a pretty nice return for us to go in harder on the buyback. But we also think there’s great growth opportunities on top of that. That’s not assumed in here. So Kris, you might want to just share a little bit about the magnitude of how we’re thinking about this capital allocation that drives the $24.

Kristopher Moldovan: Thanks, Jim, and thanks for the question, Shar. I want to start by reiterating what, as Jim said, even at current market curves, we continue to project that we are going to produce a significant amount of cash on an annual basis. So what is in here, as Jim said, what we start with is the $1 billion a year in share repurchases, the $300 million a year in dividends. And then we only have the spend that we have from projects and growth projects that we’ve already announced. We have the spend and the earnings from those, but we haven’t done a pro forma.

So for instance, on the growth projects, that includes the Permian Peakers and the nuclear uprates in PJM, but the nuclear uprates, the spend is happening during this period, but we aren’t getting the earnings until after the period, and we’re not bringing those earnings in. So it’s really just how we see the earnings going through 2030. Even after you account for all those commitments that we’ve announced and we have committed to, we still have roughly $2 billion a year to allocate. And that can go to additional share repurchases or growth projects. For the purposes of this chart, we’ve made a simplifying assumption that we’ll allocate that to share repurchases.

Of course, right now, the Board has just recently upped the authorization. So approximately $500 million of that is already allocated to share repurchases. But it’s also important to know that, that number I’m giving you assumes, as I said in the opening remarks, assumes that we are at a leverage ratio that’s well below what would be required for BBB flat and Baa2. It’s actually more approaching BBB+ and Baa1. So after that simplifying assumption, again, to be clear, that’s $2 billion extra per year. So we’re effectively in this chart, assuming a roughly $3 billion a year of share repurchases. And as Jim noted, we would expect to beat those returns.

We’re hoping to find growth projects that will meet the returns that we’re showing from share repurchases.

Shahriar Pourreza: Got it. Perfect. And then just lastly, it is good to see the upsized buyback, the $1.5 billion. And obviously, you’ve got cash flows there to reallocate to additional buybacks. But I’m just curious, like you guys closed Cogentrix, you have Lotus. Is there opportunities to potentially look at any single noncore assets within those deals to capitalize on the delta — valuation delta between the public and private side? Or are you comfortable with all the assets that you’ve acquired between the 2 Cogentrix and Lotus.

James Burke: Sure. We — first of all, we like the portfolio a lot. We have agreed to sell Rumford. So there’s going to be a divestiture that’s just part of how we were able to get to the close. We had sold some other assets you’ve read about recently, the notable one in Maine, Casco Bay. We will continue to look at the portfolio, but we think a core competency of what we bring to the table is the integration and the synergies and the operating performance improvements. And we think on the Cogentrix portfolio, we think there’s upside to even what we’ve put into this forecast. It takes time to get to that work.

So it isn’t just day 1 synergies, which we did capture, but the ongoing improvements. We also like the flexibility of these assets. This is a heavy CCGT portfolio. There are also some peakers in it. We think as renewable penetration continues throughout the country, you’re seeing these assets get called on more. And you see that even in the appendix where you look at the CCGT capacity factors across our fleet, they’re all up in Q3 relative to prior years. So we’ve been bullish on dispatchable. We’ve been bullish on flexibility. So I think we’re going to continue to see that not getting the value in today’s market, but we think it’s going to show up over time.

So as a long-term owner operator, we like the fleet.

Operator: Your next question will come from the line of James West with Melius Research.

James West: A quick one for me really to address kind of the elephant in the room, I guess, from this week with the midterms and what happened there. I’d love to get your thoughts on kind of Texas and what could unfold. Also PJM. I mean, our view is not consistent with what the market sell-off showed, but you’re obviously in conversations with leadership in both markets. And I just wanted to get your kind of high-level thoughts on — has there been a real change on kind of the more so on the data center development side, which is what seemed to be one of the things put out or in advanced manufacturing.

James Burke: Yes. James, thank you for the question. So a couple of thoughts there. Before the elections, in many markets, we were seeing concerns about data centers in the way that the public was reacting to the pace of development, who had control over those decisions, what impact could it have on electric prices, water, all of that. And that was a bipartisan issue. So I think that issue was already showing itself, and it obviously was a topic in the midterms and probably not the single most important topic, but it was a topic for the midterms.

I believe in any of our markets that we’re in, moving past this election is a positive just in terms of being able to understand what’s at stake and now how do we move forward. Clearly, most states we’re operating in have had changes in leadership in terms of party leadership with some frequency and Texas is not. So this was a bigger shift for Texas, no doubt in terms of the pattern. But the key messages that have come from Governor-elect Hinojosa have been actually very similar to some of the key messages that Governor Abbott had expressed and frankly, consistent with messages we’ve been expressing, which is — there has to be some guardrails on this development.

The queues are overstated. The public is concerned. When they talk about 75% of people don’t want a data center developed in their community, I don’t even know what the question really means because the community might mean next door. But if they’re developed by our power plant like the one that we’re developing next to our Comanche Peak plant, there was a town hall held this week with Amazon and members of our site, and it was very well received. That’s a data center going next to an industrial facility, obviously, our nuclear power plant. The public, I don’t think has a strong reaction against data centers being next to power plants.

The other thing the public struggles with is it’s different to have one data center somewhere in the area. But if you think 10 are coming to your area, which is what happens with these overstated queues, you get a reaction. So I think we’re all on the same page with respect to raising the bar, fitting the queues and getting to the real projects that are going to move it forward. And Governor-elect Hinojosa on new circuits and some of her early commentary wants to see Texas grow. She just wants to see the benefits of that growth be evenly distributed as do we.

So I actually view where we sit today is just clarity of some sort, not having it tied us directly to an election season is going to be beneficial to taking some of the noise. I think it’s been overdone, as you mentioned, James, in the last couple of days. That doesn’t change our outlook. In fact, if anything, you heard Kris talk about the buyback and leaning in there, it can create opportunities for Vistra. Our customer conversations, and I’ll give Stacey a chance to comment on a later question because I’m sure we’re going to get it. Customer conversations have been consistent throughout.

And I actually think this is going to provide some opportunities to bring some of these to completion. So overall, we’re positive on the trajectory of where we can go as it relates to our business opportunities.

Operator: Next up will be Michael Sullivan with Wolfe.

Michael Sullivan: I want to appreciate the kind of updated free cash flow per share outlook and understand there’s a bunch of assumptions. But maybe can you just help us with thinking about kind of the core power price outlook there, like just given you’re hedged near term, ERCOT is in pretty steep contango. So just thinking about the puts and the takes of what power prices are doing to that outlook as you step from ’27 to ’30.

James Burke: Yes. And Michael, I was trying to — maybe I wasn’t as clear as I needed to be. We are not making any assumptions about power price recoveries. It reflects the curves as you see them as noted in our hedge profiles and just kind of stepping that forward based off public available information. Now we think the near term on this is really going to be a function of how does Texas get back into gear in terms of hooking up load. We know there is load that’s approved to energize, but it has not been allowed to energize. There’s been the audits. As you know, there’s been some permit holds at TCEQ.

We think by the long term, the ’29, ’30 period, we think we still end up in a similar place for ERCOT. So I think it’s more about this near term where we see a little bit more of this pricing pressure. There’s a chance for ERCOT to even go better than where the curves are even out, even though it is contango to go better than that from a pricing standpoint if we kind of get our mojo back, and I think we can. And so — but we’re not making any special assumptions as it relates to get to that $24.

Michael Sullivan: Okay. Great. That’s very helpful. And then I just wanted to ask the latest on the contracting environment for you all, given what we’ve seen from some peers, like on the nuclear front, we’ve seen Constellation continue to leverage uprates. You have a couple of those still available yourself. And then just today, some news on gas finally from someone. So just how you’re thinking about puts and takes there.

James Burke: Sure, sure. Michael, I’m going to let Stacey jump in because I’m going to send it to the person who’s doing the bulk of these negotiations on a daily basis. And thanks for your question on that.

Stacey Dore: Yes. Michael, thanks for the question. We — we’ve said this for a while, but we just continue to see interest in Vistra’s assets and Vistra’s capabilities, and we’re involved in multiple conversations around our existing assets, around new build. We continue to just see a large appetite for these kinds of projects. And I think you’ve continued to see the hyperscalers, as an example, talk about increasing their CapEx spend. So there certainly is no slowdown on that front. As typical, we’re not going to comment on the timing of new deals, but we’re confident in our ability to execute additional nuclear PPAs. We still have not contracted Beaver Valley.

We still have not contracted the second part of Comanche Peak. There’s an upgrade potential at Comanche Peak as well. So we have a lot of megawatts still to contract on nuclear. We’re in a number of conversations about our existing gas plants as well as new gas build, and we feel confident on our ability to execute there. And in fact, in this quarter, we announced a PPA for our existing Odessa gas plant in Texas. So I think we’ve demonstrated an ability to execute on existing gas plants, and we believe there’s more to come on that front as well.

The load interconnection process does continue to be a timing constraint on particularly the gas asset projects because for those types of PPAs, the customer does typically want a grid connection. And so that’s why we continue to advocate for thinning the queues and raising the bar on the load interconnection queue so that we can begin to get approval for load interconnections that would support additional gas plant deals as well. So we just feel really good about our opportunity set. It’s busier than ever.

And it allows — the fact that we have so many opportunities in our pipeline allows us to also be selective about the counterparties that we work with, about the projects that we work on. And so we really prioritize the opportunities that we have the best chance of execution on as well as the ones that meet, of course, our return targets and our economic objectives. So we feel really good about it. We’re excited about the months and years to come to serve these customers.

James Burke: Yes. And Michael, I’m just going to add real quick as a supportive point to what Stacey is saying is that over the course of the year, there’s also been a lot of concern about how will the PJM rules evolve and is that going to limit our ability to do contracting with existing or even colocation. We’ve seen through time, these things never play out at the level that the initial concern is. So there’s usually an immediate reaction and then we work our way through it. I think that’s happening right now in PJM.

And so I do think that the opportunity set with existing assets, even though it does still take time to get through the study process, but FERC is trying to accelerate that as well. So I do think it’s been choppy. It’s probably choppier than anybody would like. But when you see that settle, the dust settle, the opportunity set continues to be clear, and that’s why we’re bullish about being able to bring some of these across the finish line.

Operator: Your next question will come from the line of Rinny Singh with Bank of America.

Rinny Singh: I guess to just add on to the previous question. As you think about these customer negotiations, and you mentioned that grid interconnection is a key constraint. How do you think about the economics for them and then the willingness to be flexible or add additionality? What’s, I guess, the bars that — and the conversations you’re having on that front?

James Burke: Yes, Stacey?

Stacey Dore: Yes. Thanks, Rinny, for the question. So these customers are the hyperscalers as well as the model companies and other data center and developers. They’re all somewhat unique in their priorities and their wishes for the types of projects that they want to work on. So it’s really hard to just group it all into one bucket. But I would say — they all — one consistent theme is they all really do want to be on the grid as quickly as they can. But I think the grid interconnection process across our markets, which has been slower than anyone wants it to be, does — has resulted in customers expressing a lot of interest in bridge solutions.

And so you will see and you have seen projects that will start with a behind-the-meter solution until there can be a grid connection. And so that obviously is an expensive — a more expensive solution for these customers than just starting with the grid connection. And so they certainly are showing a willingness to pay for that. From Vistra’s perspective, any project that we do really just needs to — needs to meet our return thresholds, which we’ve expressed as mid-teens returns and/or higher. And that’s what we go after, and that’s what we’ve been able to achieve and better. So that’s how we think about the economic opportunity there.

In terms of flexibility, the customers have really come a long way in being willing and able to consider being flexible. We were very pleased to see that FERC struck down PJM’s IRAS proposal, which was going to require customers to bring brand-new generation capacity, megawatt for megawatt for any new load that they brought. And we consistently said over time that, that’s not the right way to approach the flexibility question. These customers are willing to be flexible. But as FERC recognized, discriminating against existing resources on the grid by requiring a strict BYOG policy is not really the right way to encourage resource adequacy and reliability on the grid today.

And so we think the elimination of the IRS proposal really has given customers the additional clarity that they need to move forward with projects where — they have a variety of options. They can bring some additionality with new generation. They can choose instead to just bring backup generation and connect to an existing plant so that they can be available during emergencies for the grid, which is what Amazon is doing at Comanche Peak. They can also choose to just curtail their load. And so they — those choices should be theirs to make.

And the markets, in our view, should support the customer choice as to how to make sure that they can be flexible and support the grid during times of need.

Rinny Singh: Very helpful. And then I guess, can I just ask on the Texas legislature. Jim, I think you mentioned that all these governors and they just kind of want these deals to be done right in a respectable way and benefiting the community. So as we get to the Texas legislative process, what do you think is kind of going to be addressed? And what do you expect, I guess, to see to, I guess, get to this more realistic view of what can actually come on the grid?

James Burke: Yes, Rinny, thank you. I think, well, before we even get to the leg session, there’s a process underway, which we expect will continue, which is the audit process that Governor Abbott started, and there’s been some additional RFIs issued to large loads to complete the questions and complete the information being sought. Whether that leads to some of these projects dropping out of the queue or not, I don’t know. But the intent, I think, of that audit and ultimately, the review that’s being done is to make sure that complete applications are being used to then establish this Batch Zero.

Obviously, the permit hold that’s been in place, we expect when it was initially put in place that it might be lifted as part of the sort of mid-December timing for completing the audit work. Again, back to the comments we’ve made on this call and previous calls, we would be comfortable if the bar continue to be raised on projects so that doing projects the right way is rewarded and that those projects get higher allocations and they get moved to earlier in the interconnection process. So even before we get into the session, I think the business as usual could potentially thin some of this by this mid-December time frame.

I think the 765 kV projects are going to continue to move forward. I think that’s important because that’s part of the backbone of being able to energize some of the Batch Zero, not all of them, but some of the Batch Zero projects. I think if the 765s keep moving forward, and I think the third East-West line has a chance to be approved here by the end of the year by the PUC. That now establishes the foundation for the load being able to be hooked up and served with existing generation on the system as some new generation continues to be built out.

You’re then going to want that load to come on to the system and share in the cost of the 765. And that’s also part of the focus of the Public Utility Commission is to create a tariff that large loads would be committing to that would have some minimum take requirements and a duration requirement so that costs don’t get pushed on to residential customers. So there’s actually a lot already underway with the PUC and ERCOT that I think is going to set the stage heading into the legislative session that I think will give some comfort to lawmakers and the governor elect that the PUC and ERCOT are thinking about some of these issues.

And then what the legislature ends up deciding to do is hard to say. We don’t have a crystal ball. Obviously, with sort of a split House and Senate, it’s unclear what legislative environment we’re going to actually be in. But what I like about this issue is there’s not really that much of an argument happening between Republicans and Democrats on this issue. This issue has general concern for both parties to get it right. And so whether they let PUC and ERCOT more manage that or they decide to be a little bit more hands-on during the legislative session, I think it’s too early to call.

But the direction of travel is to raise the bar and do high-quality projects. And we’re supportive of that. And I think the legislature is going to look for ways to add to what the PUC and ERCOT are doing if they don’t think it’s sufficient. But we’re supportive. We’re supportive and we’ve been supportive of raising the bar.

Operator: Your next question will come from David Arcaro with Morgan Stanley.

David Arcaro: Maybe a little bit following on that line of questions. I was curious to the extent there is any effort to move forward with something like a moratorium on data centers next year in Texas. I was wondering how you’re thinking about whether there could be any risk to the Comanche Peak contract and construction that’s going on there? And maybe more broadly, whether that could impact some of your efforts in the Batch Zero process if there’s potential risk of delay or push out there.

James Burke: Yes. David, I’ll tell you, if Texas decides to just go down a moratorium, it would be problematic, I think, for lots of customers, not just our Comanche Peak project. I don’t know what form that would actually take. So that would take some potential legislative activity, I think, to have something that would create that type of a significant limiter. As we noted, construction has started with Comanche Peak, and we expect high-quality projects to move forward. So I think it’s more about raising the bar than I think the conceptual moratorium. I mean you heard the Governor-elect say she wants Texas to grow.

The moratorium, I think where this language has come in, obviously, even audits were kind of viewed as a moratorium. Any time you’ve got to study something and clear a bar, it does take some time to do that. But I have not heard, I have not heard the Governor-elect, and I haven’t heard the legislature say they do not want Texas to have any of this load. So clearly, if someone changed their mind and the whole legislature decided to go along with it, that would be difficult, right, for us as a power company, but certainly difficult for people that are bringing hundreds of billions of dollars of capital to the state of Texas.

And I just think that is where the conversations just kind of continue to sort of fester a little bit out of concern. That is not the conversations we’re having with leaders, and it’s not the conversations we’re having with members that are returning for this upcoming session. So I just don’t entertain that, David, because I really just think that’s a bridge too far from where the dialogue is at this point.

David Arcaro: Got it. Yes. That’s helpful. That makes sense. And then maybe shifting over to PJM. I was wondering if you might be able to give your latest maybe progress and thinking around the RBP and some of your bilateral efforts there. What’s — what are the prospects for those? Have those changed as the timing has shifted kind of into next year?

James Burke: Sure. I’m going to let Stacey comment on that, David. I think the — I’ll just say that at the highest level, we’ve been supportive of the emphasis on bilaterals and markets moving towards contracting for capacity and energy and not being as dependent on a single clearing price of a centralized auction. And I think the pushout of the RBP a little bit from a timing standpoint can help facilitate some of those bilateral conversations. But even if it’s not to new projects, just what we’ve already done with Meta, what we’re doing with other conversations is contracting even with existing. I just think that starts to put the onus on the load-serving entities like Vistra.

And I think that’s a responsibility that we accept in serving customers from residential to large commercial industrial and data centers. So all of that from a theme standpoint, we’re supportive of. And Stacey, I’ll let you comment about how we’re thinking about the bilateral process.

Stacey Dore: Yes. thanks for the question. We continue — we do continue to have a lot of bilateral discussions in PJM. As I mentioned earlier, I think the FERC striking down the IRAS proposal actually was helpful in that it kind of removed one layer of uncertainty for customers about how they might want to contract and kind of what the rules of the road might be around that. And so I think that was helpful.

Pushing out the RBP to next year is also helpful because it just gives more time for those bilateral discussions to really result in agreements and also more time, frankly, for anyone who’s thinking about building new generation in PJM to understand what the network upgrade costs might be and the generation interconnection costs might be, which was a concern we had expressed about the timing — the previous timing of the RBP being in September is that there just wasn’t a lot of certainty about what those costs are. So it’s hard to build into your contracting process when you don’t know what those costs are. So I think all of that is positive.

I do think that customers still have a big incentive to do bilateral contracts in relation to the RBP because, as you know, if you have a bilateral contract, you can present it to PJM as a means of reducing the ultimate procurement target for the RBP and therefore, reducing a customer’s cost allocation responsibility as well for the RBP. So I think we’ll — we’re optimistic that we’ll see a number of bilateral contracts in the market that are presented to reduce the ultimate RBP target.

And frankly, the smaller the target is the better because it means that the bilateral contracts have really satisfied the forecasted need as opposed to using this kind of bifurcated RBP process, which, as a matter of principle, we typically wouldn’t support, but we think it’s going to end up being small enough that it mitigates that risk. So we continue to have active conversations about uprates and other opportunities across our fleet as a means to reduce that RBP ultimate target. So we feel good about that.

Operator: Next question will come from Paul Zimbardo with Jefferies.

Paul Zimbardo: Apologies if I missed it earlier. The timing change on Helix investment potential, if you could discuss that a little bit. And I know you’ve mentioned a few times the mid-teens target returns. And I know IRRs are not the same as free cash flow yield, but just using your $24 in the stock price, you get to a number higher than mid-teens on buying back your stock. So just curious if kind of your return thresholds have changed with the stock price.

Kristopher Moldovan: Yes. On the second one, I think — we view the $1 billion a year, obviously, that’s something that we view as a commitment that we’ve made. Obviously, it’s not set in stone, but I would say it’s pretty close. We continue to weigh all projects against our share buybacks. And so as our stock price has come under — has been challenged the last couple of days, I mean, that moves the needle. But we also have a lot of projects, as we said in the prepared remarks, that are with existing assets that have little cost for us and have extremely high returns.

Some of the deals that we’ve struck have almost 0 or basically 0 cost, and we get premium on those transactions. So we’re going to continue to look at opportunities. We’re going to still try to stay relatively balanced, but we do compare all opportunities against share buybacks.

James Burke: And Paul, what I would add is these customer conversations, they can be 6 months, 12 months in duration. Our stock might move $30 in 2 days. We’re not going to work with long-term customer relationships and negotiate around $1 or $2 a megawatt hour trying to just react to the stock buyback opportunity in the moment. This is a franchise, and we have a reputation, and we’re going to build a book of business that will also be a contracted book of business, which I think also lowers the discount rate ultimately. So it’s a little different in horizon to be thinking about it relative to our free cash flow yield and a buyback at a point in time.

Having said that, you can bet that’s the conversation we have as a management team and with our Board, and that’s why the Board was comfortable authorizing a larger share repurchase to take us through that 2028 period because it’s not lost on us that as we think about what are we going to do to build that next incremental value, the hurdles do rise when you have this kind of an alternative for the cash. So it’s — there’s a tension there. The last thing I’ll say is on Helix, that’s really about a draw schedule. So Helix is not about us just pushing cash to them to sit.

It’s what are the projects that Helix is driving where they’re going to have a capital call. We’re working with Helix on a number of projects. So we’re just assuming that from a timing standpoint, it’s going to fall more into next year than this year. But that’s not surprising just given all the things we’ve been talking about how the political environment has slowed down some of the activities in any of the markets really. And we see that picking back up, and that’s why we moved the capital assumption.

Paul Zimbardo: Okay. No, that’s very helpful. And I know it’s a tougher one to answer, just given the volatility. I appreciate that. And then the last one, just to check in. I know you kind of — I don’t want to put words in your mouth, it sounds like you acknowledge maybe softer power pricing dynamic in Texas in the near-term years. Does that influence kind of the hedging profile that you pursue, whether kind of more hedges in — I know you have a lot in ’27, but maybe a ’28, ’29.

James Burke: It does, Paul. In fact, with the 78% hedged for ’28, we are much less hedged in ERCOT than the 78%. So we do not look at the curves for 2028 and feel a need to be moving a lot of power at this point in time. And I do think as we see what the pace of play is for hooking up load in 2027 and seeing what the pent-up demand is because the utilities are reporting on their calls the pent-up demand that they see. Some of it is actually not AI related. It’s manufacturing, it’s government, it’s oil and gas.

If we start to see that pick up pace, then I think you might see some response in 2028, and we’re certainly more open in 2028 in ERCOT than we are in the other markets.

Operator: Our next question will come from Jeremy Tonet with JPMorgan.

Vrathan Reddy: This is Vrathan Reddy on for Jeremy. I think it’s been hit on a couple of times, but I just wanted to ask, PJM versus ERCOT, is there any change you’re seeing in terms of the customer interest, one versus the other? And if that’s — I guess, just broadly how that’s evolved post election?

James Burke: Well, I’m going to let Stacey take that one. It’s a lot to digest just postelection. But maybe leading into the election and post election, Stacey, can you provide some context on the relative attractiveness.

Stacey Dore: Yes. Look, Texas continues to be attractive to these customers. Any given day, of course, they’re looking at the political environment. They’re looking at some of the guardrail proposals and they’re trying to decide what the risk profile is across these different markets. But frankly, almost every market and every state that we’re operating in as well as states we’re not operating in where they may be pursuing projects has been looking at these similar types of guardrails. So across the country, states and local bodies are looking at things like water usage and land usage and tax incentives. So I really think — I know the election was a surprise to some in Texas, in particular.

But I really think if you take a step back, there’s not a higher risk profile in Texas versus other places that are considering these same types of guardrails. And in fact, we believe Texas continues to be one of the easiest places to get things built and will continue to be so in the long run. So leading up to the election, we did not see a change in customer behavior of Texas versus PJM. We just got questions about both, and we continue to get questions about both. Ohio, as an example, had a change of administration as well, and they’re in PJM. So again, I don’t see Texas as standing out as peculiar in this regard.

And I think customers across the country are just looking at their opportunities, looking at, number one, speed to power; number two, where can they be welcomed into the communities; and number three, how much political support are they going to get. And so I think that continues to be the case and everybody is trying to assess their alternatives. But for Vistra, the good news is we operate across almost 20 states in all of the competitive markets, and we have opportunities in all of those markets to serve these customers. So we really try to follow their lead and also help them navigate some of these political and regulatory hurdles that we’ve all been dealing with.

I think the fact that we had the election and it’s now over and the results are clear, as Jim referenced earlier, is actually a help to us, and it will be a help to us in getting a lot of our projects across the finish line because we can now kind of understand a little bit more about what the rules of the road are. But to have — we’ll continue to have regulation that comes into play. And the kinds of customers that we deal with, and this is kind of with reference to my earlier comment about us being able to be a bit choosy about the customers we work with.

The customers that we work with, they’re going to clear this higher bar that policymakers are putting into place. And that’s one reason we advocate to raise the bar because our projects like the one we have with Amazon, the one we have with Meta, the PPAs that we have with Meta, our projects clear those — all of those bars by far. And so we’re not concerned about the regulation. We just want certainty and clarity to continue to come and then our projects will be able to move forward.

Operator: This concludes our Q&A session. I will now turn the call back to Jim Burke for closing remarks.

James Burke: Yes. Thank you, everybody, for joining. I especially want to thank our Vistra team for their continued execution and service to our customers and communities. Once again, we want to welcome the Cogentrix team. And for our investors, we know this is a very dynamic time, and our team is very focused on delivering. We do appreciate your interest in Vistra, and we hope to see you in person soon. Have a great rest of your day and a nice weekend.

Operator: The call has concluded. Thank you for joining. You may now disconnect.