Title

Presentation

Vistra Corp. beats earnings expectations. Reported EPS is $2.18, expectations were $1.32.

Operator: Good day, and welcome to the Vistra Corp First Quarter 2026 Results Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Eric Micek. Please go ahead.

Eric Micek: Good morning, and thank you for joining Vistra’s investor webcast discussing our first 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. Our 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, and good morning, everyone. Thank you for joining us to discuss Vistra’s first quarter 2026 operational and financial results. 2026 is off to a fast start. As outlined on our year-end call, within the first week of the year, we announced the acquisition of the 5,500-megawatt Cogentrix natural gas generation portfolio as well as long-term power purchase agreements with Meta for approximately 2,600 megawatts of energy and capacity at our PJM nuclear sites. These actions further strengthen our generation footprint and enhance our ability to serve growing customer demand with high-quality dispatchable and zero carbon resources. The quarter also provided a good test for our generation fleet. Volatile weather created a dynamic backdrop that underscored the importance of operating assets safely and reliably, and I’m proud to say our team rose to the occasion.

Within the geographies we serve, we are seeing a structurally improved demand environment. Load growth remains elevated. Hyperscalers are executing on record CapEx spending plans and our conversations with large load customers continue to advance. All of this reinforces our view that power market fundamentals will continue to improve through the end of the decade and beyond. We remain excited about the growth opportunities for new and existing generation. We are working with policymakers, regulators, transmission providers and our customers to create innovative solutions that can support new load while preserving an affordable framework for existing customers. With our large, diversified and flexible fleet, our development capabilities, innovative retail franchise and experienced commercial team, we believe Vistra is uniquely positioned to deliver on these initiatives, and we look forward to building on our early momentum throughout the rest of this year and beyond.

Turning to Slide 5. Vistra delivered approximately $1.5 billion of adjusted EBITDA, a record result for a calendar first quarter. The strong financial performance is a direct result of the consistent execution of our generation, commercial and retail teams as well as diversification afforded by our integrated business model. This was particularly evident during the first quarter as we managed through a volatile weather backdrop. Weather was exceptionally mild across the geographies we serve for most of the period, especially in ERCOT, where the quarter was the second warmest first quarter since 1950, only to be interrupted by Fern, a protracted winter storm that brought significant snow and ice as well as below 0 temperatures to a significant portion of the country.

Despite those conditions, our generation team performed very well during Fern with our natural gas fleet performing at 97% commercial availability and our nuclear fleet at 100%. During the milder portions of the quarter, our commercial team successfully optimized the fleet, responding to market conditions by backing down assets when warranted and buying low-cost power in the market. Importantly, Martin Lake Unit 1 returned from an extended outage late in Q1 and has been running well since. Moving to the outlook. We are reaffirming the guidance ranges for 2026 adjusted EBITDA and adjusted free cash flow before growth, both of which we introduced on our third quarter 2025 call. We are also maintaining our 2027 adjusted EBITDA midpoint opportunity range.

Our confidence in the outlook continues to be supported by strong operational performance and our comprehensive hedging program, where we have successfully hedged a significant amount of our expected generation through the end of 2027. Our comprehensive hedging program, which focuses on opportunistically locking in value, ensures a more stable and resilient earnings stream across varying economic cycles. As a reminder, our outlook does not include any potential contribution from the pending Cogentrix acquisition nor does it include any uplift from the long-term power purchase agreements with Meta at our PJM nuclear sites. We expect to update our guidance ranges as well as our adjusted EBITDA midpoint opportunity following the closing of the Cogentrix acquisition.

Finally, the amount of capital we expect to generate over the coming years provides flexibility to execute on both organic and inorganic growth opportunities as well as return a meaningful amount of capital to our shareholders. We can do both. Our approach remains disciplined and opportunistic, and that was reflected again this quarter. Through the design of our share repurchase program and given our increasing free cash flow yield, we accelerated share repurchases during the first 4 months of the year, deploying approximately $525 million. Combined with our first quarter dividend of approximately $75 million, we have already returned approximately $600 million to our shareholders this year. Turning to Slide 6. As we have outlined for the last 2 years, we continue to see a structurally improved demand environment that supports our long-term outlook.

While large-scale data centers remain a key component of the expected growth, we expect incremental demand from multiple sources, including medium-sized data centers, increased industrial activity and ongoing electrification. In ERCOT, we believe annual load growth of at least 5% to 6% through 2030 is reasonable. And in PJM, 2% to 3% annual load growth appears likely to persist. Importantly, while these views remain below many third-party forecasts and ISO projections, they reflect what we believe to be the pace of physical development and are consistent with the perspective we shared nearly 2 years ago on our first quarter 2024 earnings call. While there are large interconnect queues in our major markets for both load and generation, we believe our estimates to be realistic load growth forecast that reinforce that competitive markets are ready to meet the coming demand.

Since we expect overall load growth to outpace peak demand growth, a dynamic that should result in higher utilization of the existing generation and transmission infrastructure, we believe the existing grids can handle this level of growth successfully, providing a helpful runway to bring on additional generation resources later this decade and beyond. Moreover, utilizing the existing infrastructure more efficiently is key to preserving affordability. With more power moving through the system, fixed costs are spread over more volumes, which should support lower unit costs for customers over time. And third-party research confirms this dynamic. A Lawrence Berkeley National Laboratory study demonstrated that states with positive load growth over the last 5 years experienced a decline in inflation-adjusted prices on average, while states with flat load growth or a decline in load experienced double-digit inflation-adjusted price increases.

Policymakers and industry participants, including large load customers are working on solutions to better manage the infrequent peak load and are willing to be creative. At Vistra, we remain focused on developing these solutions, including through the deployment of demand response capabilities or through distributed generation technologies as they could enable a faster time to power while awaiting a grid connection and help manage through super peak hours during the year, all while enhancing reliability and affordability. In summary, the load growth is real and is actualizing, and that creates meaningful opportunities for Vistra to support all its customers from residential to commercial and industrial, including data centers. Finally, turning to Slide 7.

As we have highlighted, the load growth developing across our markets creates significant opportunities to deploy capital towards organic development projects that can further increase the earnings power of our business. As you can see on the page, we currently have approximately 4,500 megawatts of organic development opportunities that were recently completed or in process across our portfolio. They include contracted renewables such as Oak Hill 1, the recently contracted Oak Hill 2, Pulaski and the recently energized Newton project, high-return thermal additions such as our coal-to-gas conversions at Coleto Creek and Miami Fort, Texas gas expansions, including gas plant augmentations in our Permian new build gas units and longer lead time projects such as the PJM nuclear upgrade supported by our long-term power purchase agreements with Meta.

These projects represent cost-effective and efficient ways to achieve incremental capacity with the majority expected to be online by 2028. At the same time, the development opportunity set is not limited to the projects shown here. The team remains hard at work advancing multiple additional gigawatts of opportunities across the generation spectrum. Uprates will continue to play an important role, and we see the opportunity for more than 200 megawatts at Comanche Peak and approximately 300 additional megawatts at our PJM gas sites. We see numerous development opportunities at existing coal and gas sites that provide options for meaningful contracts for existing capacity as well as capacity additions with favorable speed and cost profiles relative to greenfield projects.

As we advance these projects, the team will look for ways to partner on these investments through long-term power purchase agreements with creditworthy customers. Now I’ll turn it over to Kris to discuss our more recent financial results, outlook and capital allocation. Kris?

Kristopher Moldovan: Thank you, Jim. Turning to Slide 9. Vistra delivered $1.494 billion in adjusted EBITDA for the first quarter of 2026, up approximately 20% from the same quarter last year and up nearly 85% from Q1 2024. Generation, which delivered $1.426 billion of adjusted EBITDA in the quarter, benefited from strong realized revenue across the fleet, higher capacity revenues in PJM and the contribution from the assets we acquired in late 2025 from Lotus. Retail, which delivered $68 million of adjusted EBITDA in the quarter, continues to benefit from strong counts and margins, partially offsetting extremely mild weather in ERCOT. It is important to note that we expected a year-over-year decline in the first quarter results for retail, and we continue to project retail’s full year performance to moderate from the record result last year.

However, retail remains on track to achieve its medium-term adjusted EBITDA target this year. Turning to Slide 10. We are reaffirming both our 2026 guidance ranges and maintaining our 2027 adjusted EBITDA midpoint opportunity range. Our confidence in our outlook and cash generation is supported by our comprehensive hedging program, the long-term power purchase agreements we have executed and the downside protection of the nuclear PTC, resulting in a highly hedged position in 2026 and 2027. As Jim stated earlier, our financial guidance excludes any potential impacts from the pending acquisition of Cogentrix and the long-term power purchase agreements at our PJM nuclear sites with Meta. Cogentrix is on track to close in the second half of this year, and we plan to update our guidance ranges and 2027 midpoint opportunity range thereafter.

Importantly, we see multiple additional opportunities to further expand and stabilize our earnings potential. Customer engagement remains strong, and we are confident in our ability to create value and drive stronger financial results. Our near-term priorities include approximately 3.2 gigawatts of nuclear capacity at Beaver Valley and Comanche Peak that can be contracted on a long-term basis and ongoing opportunities with customers with respect to our existing gas plants as well as potential new construction. Finally, turning to Slide 11. Based on our outlook, we still have line of sight to more than $10 billion of cash generation over 2026 and 2027. After allocating approximately $3 billion to our equity holders through share repurchases and common and preferred dividends in 2026 and 2027, and approximately $4 billion towards accretive growth investments, including the Cogentrix acquisition, the development of the Permian gas units, the PJM nuclear uprate supported by PPAs with Meta and the development of Oak Hill 2 supported by a PPA with a large investment-grade counterparty, we continue to expect to have approximately $3 billion of additional capital available to allocate through year-end 2027.

As always, we will be disciplined in how we allocate this remaining capital, balancing return of capital to our shareholders, further strengthening our balance sheet and strategically investing in attractive organic and inorganic growth. Our share repurchase program continues to create significant value. Since initiating the program in November 2021, we have retired approximately 169 million shares at an average cost of approximately $37 per share. We currently have approximately $1.475 billion of share repurchase authorization remaining. Pursuant to the opportunistic design of our 10b5-1 plan, our repurchase activity was accelerated in the first 4 months of the year as our free cash flow yield increased. We will evaluate our share repurchase authorization and availability throughout the year with the option to continue to accelerate share repurchases should market conditions warrant.

Turning to the balance sheet. During the quarter, we received an upgrade of our corporate issuer rating to investment grade from Fitch Ratings. Combined with the upgrade from S&P Global Ratings late last year, we have now achieved investment-grade ratings from 2 rating agencies. We are pleased to see the recognition of our efforts to increase our earnings power, derisk our business model and execute on our disciplined capital allocation plan. With this milestone, the fallaway provisions in our senior secured debt agreements were triggered, releasing the liens on our assets under those documents. Achieving investment-grade ratings positions the company well to maintain financial flexibility and support long-term value creation. We will continue to target leverage metrics consistent with solid investment-grade credit ratings.

As for strategic investments, we remain opportunistic yet disciplined, maintaining our mid-teens levered return threshold across organic or inorganic growth investments. In closing, Vistra remains well-positioned to create long-term value for our stakeholders. The resilience of our business is evident in our strong results and reaffirmed earnings outlook despite a volatile weather backdrop during the quarter. We see load growth materializing in our primary markets, and the team remains focused on positioning Vistra to win in that environment. With that, operator, we’re ready to open the line for questions.

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Operator: [Operator Instructions] The first question comes from Shar Pourreza with Wells Fargo.

Unknown Analyst: It’s actually Constantine here for Shar. I appreciate the updates today. Maybe starting out on PJM. Do you anticipate the FERC PJM colocation rules to kind of start opening up more opportunities to do repeat deals like the Meta deal? Does the rule changes impact the framework of combining new capacity with contracting existing resources? And does this kind of, in your mind, extend beyond the nuclear assets over time?

James Burke: Yes. Constantine, this is Jim. I’ll start, and I’m sure we’ll talk a lot about policy and PJM. So you’ll hear from Stacey on a number of these topics. But we’re encouraged by the colocation recognition. I think we’re seeing in all markets, not just PJM that if we’re going to hook this load up quickly enough, colocation with existing and colocation with new needs to be supported. There’s obviously tariff work to be done and there’s — the details are going to need to continue to be worked out, and we hope PJM can move to support the colocation in the way that we think FERC was providing direction to support it. So we do think there’s opportunity to do additional deals like the one we did with Meta doesn’t need to just be with nuclear.

I think we have opportunities to do it with gas as well. But this is a process. And we’ve seen that there’s a back and forth on this, and there’s coming to a common understanding that’s needed. And so I can’t say it’s going to be quick or simple, but we’re optimistic that the logic around colocation continues to get more and more support. And then it’s just a matter of making sure we’ve got the avenues to be able to execute on it. I’m going to ask Stacey to share her perspective.

Stacey Dore: Yes. Thanks, Jim. FERC’s colocation order in December made it very clear that colocation is something that PJM must support. And so the filings are now just trying to sort through what the rules of the road are, and we do expect FERC to be motivated to act quickly on that. We’ve seen them recently order some pretty short time lines for PJM to respond to that order with compliance filings. And so we do think FERC is very focused on clarifying the rules of the road. And in the meantime, customers continue to explore colocation with us at both gas and nuclear sites. And so those contracting discussions can continue in parallel while the rules are clarified. And we think that has to be part of the solution for meeting this demand because there is a speed to power advantage while additional resources take longer to come on the grid.

Unknown Analyst: That’s really helpful. And maybe shifting to ERCOT, obviously, milder weather here in the quarter. Does that shift any of the expectations? And are you thinking of any offsets around ’26 kind of just within the current guidance ranges? And maybe extending that to your views on the moving forwards in ERCOT? Is there a degree of load expectations shifting energy storage impacts? Any color that you can provide?

James Burke: Yes. Constantine, what was noted, I think, in many external reports was just how mild this first quarter was, and we noted that. Fortunately, one of the benefits of our business is a highly diversified business, both generation and retail. So we saw some offsets. That’s why we had a good quarter. So retail bore the brunt of some of the mild weather for this particular quarter. But the rest of the business, particularly generation had a good quarter. And I expect to see that integrated model continuing to be a strength for Vistra. So we don’t feel the need to necessarily have offsets. Obviously, we’d always like to outperform. So you’d like to have the full performance of generation and retail all the time. But when you do see these offsets like this happen, that’s why our model is designed the way it is.

So I actually feel really good about how the integrated model performed. The second question, which is the ERCOT forwards. Obviously, we’ve seen ERCOT forwards come off. We didn’t see much weather as a function of what we just discussed. I think that tends to read through to some of the future periods. I think the concern about the pace of load getting hooked up because there’s a big discussion, obviously, about the batch process and how long is it going to take to get through the approval process. So I think there’s a bit of a sort of a perspective at the moment of how quickly will the load come. And I think towards the back end of the decade, I don’t think there’s any doubt about how quickly the load is going to come. In our chart, we’re showing very consistently this 5% to 6% compounding kind of load in ERCOT.

But I think the market is expecting more than that. And what we’re saying is I don’t even think the market forwards reflect 5% or 6% compounding load. So I think there is a wide disparity in view out there because I think the market had a view that it was going to compound a lot faster than this. We did not. We actually have said the physical world takes much longer to develop than what people might imagine it takes, and we just think that’s playing out. So I think there are folks trading around that. We feel very solid that the 5% to 6% is a good compound growth rate. I also don’t believe the 400-plus gigawatts of interconnection. We’ve said that. We believe that ERCOT is looking at something in the order of probably 30 to 40 gigawatts of growth in total by 2030.

We think 10 to 15 of that’s likely large data centers. So I think there’s just a lot of confusion out there because there’s a lot of information people are trying to sort through. But we feel good about the position we have in ERCOT. We think it’s going to be a market that’s going to continue to strengthen through time. And I think because we’re on both sides of it, both retail and gen, it can work for us from a durability standpoint with the integrated model. So I think we’ll just have to see this play out, Constantine. We’d love to see the load hooking up a little faster than it is. But this pace of play is about what we expected, and we think the forwards would still actually improve from where they are even if the 5% to 6% were maintained.

Operator: Our next question is from Steve Fleishman with Wolfe Research.

Steven Fleishman: So just — I heard Kris’ commentary on the customer engagement being strong, both on the nuclear and the gas. But we did have Constellation come out in the last month or 2 and talk about a little bit of a pause from customers due to the kind of RBP uncertainty and some of the structural uncertainty, I guess, particularly PJM. So I’m curious just have you seen a similar change in tone from your customers? Or are you still seeing the same interest that you have talked about on the last call?

James Burke: Yes, Steve, this is Jim. So I think it’s logical that with the amount of information flying around that people are just even trying to digest it. I mean just yesterday, PJM put out a 70-page paper. I think it’s actually quite helpful in raising the discussion around market design. So our partners that we’re talking to, the customers we already have and the ones we hope to become customers, they look to us also for insights and guidance on how to navigate this. Because these deals, and we’ve maintained for several years, these deals are complicated. They take time. We have said that from the beginning, and I think we would still say that. And this just becomes yet another variable that we have to talk to them about.

But the load is still coming. And the question really is going to be, when is there enough clarity on some of these that they feel confident it’s time to go. And they have real questions, for instance, in PJM, how does participating in an RBP help or not with speed to market? Does connect and manage come into play? What does that look like? Some of those are unknowns, but they know they can’t wait for clarity either. So our discussions are going in parallel. They’re consistent. The activity level has remained as high as we’ve ever seen in this. So I don’t see a change there. We’d all want clarity. They want clarity, and we’re all going to work hard to get it. But Steve, I think the pace of play on this is where we expected it to be, and we’re comfortable with where it is.

But from a competitive markets person, I want the competitive markets to get as much of the opportunity to serve these customers as anybody. So we’re eager to get on with any and all clarity. And I think that’s how the customers feel too. But the pace of play is where we expected and it’s still strong. And Stacey, anything you’d like to add to that?

Stacey Dore: Continuing to engage at the same level that they have been. And I’ve said, I think, several times that there are uncertainties for sure on the regulatory front that you can contract around those uncertainties. It’s just a matter of allocating risk. And so as Jim said, that’s just another variable that comes into the negotiation. But of course, they want to understand how all of these rules of the road will work. And they talk to us about that. They get our take on the regulatory hurdles and the regulatory rules, and we work through that with them and try to help them come up with the solutions that deliver speed to power, which is what they want. And those solutions sometimes can include things like bridge power, for example, because they’re not sure when they can get connected.

So what we’ve been advocating is while we’re working out the rules of the road, we really need to get load connected as quickly as possible because that’s the best way to deliver for the customers, but also to address the affordability issue.

Steven Fleishman: Okay. Great. And my follow-up is on that — is actually on that topic on the bridge power. I think you mentioned called the distributed gen faster time to power in your remarks. Just could you talk about some of the options you’re looking at there for customers?

James Burke: Sure, Steve. So on the bridge power, the discussions, obviously, customers want to get power as quickly as possible. So bridge has become part of the workaround for these customers. Ideally, customers would like a grid connection and like it quickly. I mean that’s the starting point. When they can’t get that, then they look at bridge. And ultimately, that bridge might be longer in some cases, depending on how long it takes to get the hookup. The reason why colocation, we think, makes so much sense is there’s less transmission work involved, so you could actually get the hookup quickly. But in the case where they decide to go down the bridge power path, we’re having discussions with multiple parties about bridge power ultimately to get to grid connection.

And that takes a variety of the technologies that you’re familiar with. But more of our conversations have been leaning towards the use of gas in these bridge power solutions. And obviously, that’s something we’re comfortable with. But the customers ultimately are looking to scale up. And so it’s more about how do you get started. And I think that gets to the earlier question, which is the pace isn’t really slowing down. It’s just the way in which folks are trying to get to market. They’ve had to be a bit more creative. And we’re part of that with them. We wish it were simpler. We wish it could actually get to the existing grid because as we’ve talked about, there’s plenty of existing gen capacity on the system. We just need to manage the super peak hours.

I think that’s being recognized more, but there’s plenty of generation on the grid. And it’s unfortunate we can’t tap it as quickly as we’d like. So this bridge will be part of that solution. But hopefully, ultimately, we get all of this hooked up, and we’re able to support the customer in the most cost-effective way possible.

Operator: The next question comes from James West with Melius Research.

James West: I wanted to get a framework or think about how to frame the conversations you’re having with the data center hyperscalers. And with all the — as you’ve alluded to several times, the kind of noise or the information in the system and in the regulatory environment, which is going through some changes and their own framework. But speed to power is still the most important thing for the hyperscalers. And so are they willing still to go bilateral in negotiations with you guys? And as we get some of this clarity, go ahead and contract well ahead of if it’s PJM in an auction or batching if it’s FERC?

James Burke: Yes, James, I’m going to go ahead and let Stacey kick this one off.

Stacey Dore: Yes. Thanks, James, for the question. Yes, they are willing to and are engaging in discussions about bilateral contracts even ahead of the rules for the backstop procurement being clarified. And I’d just go back to what’s really important is that we talk about raising the bar on the interconnection queue because it’s not as much — I mean, certainly, the lack of clarity on some of the rules in PJM, as we just talked about, are impacting discussions. But really, what they want and what they — what these customers start with is they want a grid connection and they can contract for generation, both existing and new, to bring their power, but they still have to get a load interconnection done. And so what we really would like for the focus to be on is how do we start raising the bar on these load interconnection queues and have the utilities, particularly in PJM, where they control the load interconnection process, get these customers hooked up as quickly as possible.

And so those are the things that we focus on, and they are certainly talking to us about bilateral contracts. And we think bilateral contracts is a good way to solve the issues in these markets because it addresses the affordability issue. It addresses the resource adequacy issue and particularly colocation with existing plants where the customers are bringing back up generation, as we said many times, solves the super peak issue and takes advantage of the excess capacity that’s on the grid today.

James West: Right. Got it. That’s very helpful. And then you mentioned — you guys mentioned the shift a little bit towards natural gas. I’m curious in your conversations with the gas providers, upstream, both in the midstream providers, is the — we have the resource. We know that in the U.S. we have that. That’s very clear. But is the infrastructure in place to provide this increase in natural gas? Or is it getting in place?

James Burke: Yes. Broadly speaking, James, it’s like everything in this business, location matters. But in quantity of supply, plenty. I mean — and I think that’s why you’re seeing some of the announcements, not just from us but other parties as to where folks are expanding. I mean even us putting capital to work in West Texas, where we see the Permian units having real opportunity, just like our colocation point, it makes sense to go where the resources are. So yes, there may be some infrastructure that needs to be built out. I’d call it modest like in some of our coal to gas conversions, but all that’s factored into this. So as a country, we are blessed to have the gas resources that we have. I think the customers see that as a real opportunity.

And obviously, speed to power, gas is available. And with the places where we’re looking to go, you can get access to it even if there needs to be some laterals built that’s not the biggest hurdle. So to me, it’s smart. It’s actually aligned with speed and affordability. And so I think working with our gas partners, and we’ve had some really good relationships over the years and developing them as part of this new load growth, they’re excited about it. Like they see this as a real opportunity, too. And so I think this is a nice solution for the customer.

Operator: The next question comes from Moses Sutton with BNP Paribas.

Moses Sutton: I wanted to turn to the ERCOT batch process. You mentioned the 30-40 type number by 2030, that’s about 5%, 6% CAGR. We have the same type of numbers in our own model. Do you expect all or most of that come through in batch 0? It seems a bit opaque that has 145 gigawatts in there. And then under the hood, how much would you look at in terms of nonfirm and CLR classification? And we could see Vistra is pretty heavy in the public proceedings there. So any color there would be quite helpful and how you think that plays out.

James Burke: Yes. Moses, let me start. I think part of the challenge here, and this is something that is a positive about competitive markets, but could also be a challenge with competitive markets as the bar is really low to get into the load queue and it’s low to get into the generation queue. And the resources to study this, both at the utilities as well as at ERCOT, there is ultimately a constraint. And the question before us, I think, is what’s real. And we’re trying to give a view as to what’s real. We wish the bar were higher for both of the queues, but particularly now the load queue because I think what we run the risk of is that a bunch of projects get allocated some level of transmission, but they’re not real and they’re not going to move as fast as the projects that are ready and are real.

I’ve heard that batch 0 could be as big as potentially even 100 gigawatts, okay? If we think the number is 10 to 15 of additional data center between 2025 and 2030, you don’t even really need a whole lot of batch 0. You actually need what’s already been allowed to ramp. It’s been energized, but is not at the full take at this point in terms of peak capacity, plus what’s in baseline, which could be about 17 gigawatts. So batch 0 could almost end up becoming on top of every estimate that we’ve provided. So — but it’s getting a lot of focus because people say, how are we going to serve hundreds, potentially 300 to 400 gigawatts of load. That is not helpful from a policy perspective. And if I were a policymaker, I’d be worried if that were the number.

You can’t get to that number with a $3 trillion to $4 trillion CapEx spend by the hyperscalers. You can’t get to that number if it all came to Texas. And we think Texas is going to get more than its fair share, but it’s not all coming to Texas. So in my view and where we’ve been trying to inform policymakers is we’ve been pushing that the world gets simpler if the commitments to be real move up. And we’re still advocating for that. And I think that would speed up the load that’s real. And I think it would also address some of these affordability and reliability concerns. So that zero is interesting. We’ll see where it goes. But most of the numbers — the numbers that we’re sharing with you don’t even really require a lot coming to fruition as energized load by 2030.

Now we hope it comes, but there’s already a lot that’s being processed and will continue to be energized.

Moses Sutton: Incredibly helpful. And I guess some of the parallel questions on PJM, with the behind-the-meter comments you made, how big — you mentioned connect and manage. How big do you think it can actually be? Do you think the majority is headed that way? Is that going to be more of an Ohio story, Virginia? Any thoughts you can give on connect and manage beyond high level?

James Burke: Yes. you’ve actually — and we should probably have a bigger discussion offline, Moses, because I think the policy paper yesterday, which I mentioned already, I thought was incredibly helpful. It raises the level of discussion to where I think we ultimately should go, which is different products will probably have different attributes. Some products might actually be firm from a capacity standpoint. Some may not be. That could be a cheaper product. That could be one that gets you connected sooner. And that’s ultimately a customer choice. And where I’d like to see the conversation go is where load-serving entities such as Vistra are actually looking at these as products that they’re offering to their customers and customers are opting into the product that provides the attributes they’re looking for, that could cover capacity, that could cover energy.

I realize I’m moving forward in that discussion from white paper to recommendation. But I think where we’re having trouble right now is we have a central body that’s trying to make product choices for everybody and where to set that bar. And I think the hyperscalers are learning the opportunities to be flexible. You’ve seen some hyperscalers really lean into that with a lot of public announcements. We were part of announcements with Emerald AI about their tools to be more flexible, and they’re doing some pilots in Silicon Valley with NVIDIA that I think will be very interesting from a demonstration of this capability. So I do think the world, as we look at trade-offs is starting to become more accepting of some level of flexibility in order to get speed.

How soon does that materialize? I can’t say and at what price because the question is where does an RVP clear and what does it cost to be firm versus potentially be connect and manage. I don’t think we have those details yet. I think that’s something we’re very active in. But I think it’s too early to call it. And I think customers, because they have choices as to where to go, they can decide which markets to go into, which states, obviously to go into. We serve a lot of them. So we hope to serve them in one of our markets. But I don’t think we can give you a prediction of how much would be flexible and how much would be firm. And Stacey, welcome any feedback on this.

Stacey Dore: Yes. Thanks, Jim. I would just add that, as Jim noted, the customers are willing to be flexible. And in some ways, the rules, especially in PJM, actually need to catch up to the customer because the customers just want to know what those rules are so they can make decisions about do they bring back up gen, how much do they bring, when are they going to have to turn it on. And so Connect and Manage, as an example, is behind from a process standpoint, the backstop procurement. And what PJM, I think, is hearing from customers and other stakeholders, and they’re acknowledging this in the stakeholder meetings is that really those 2 things have to go together, the backstop procurement and Connect and Manage because customers will make decisions about how much generation they contract with when they understand what it means for their flexibility criteria.

And I think PJM is trying to be responsive to that and potentially accelerating some of the connect and manage rulemaking, but we’ll see how that plays out. In ERCOT, for example, we are starting to get more clarity around what the flexibility rules are. Some of the net metering arrangements that have been approved have now set some of those rules. And so as the rules are set, I think the customers, to Jim’s point, will adopt the products that match what the availability of those products are. And so I just think the regulatory process in some ways, needs to actually catch up with the customer willingness to be flexible so that they can get connected. But again, it kind of we’re maybe beating a dead horse on this. But again, it goes back to like can they get connected and when.

And if they can, I think you’ll see them be very creative around these flexibility solutions.

Operator: The next question is from David Arcaro with Morgan Stanley.

David Arcaro: I was wondering if you could comment on what the — where is the conversation on contracting your remaining nuclear fleet versus potentially making more progress with the gas plants?

James Burke: Sure. David, we can count on you for that question. So we appreciate it. I’m going to let Stacey comment. Thanks, David.

Stacey Dore: Thanks, David, for the question. We do continue to have conversations on both. I’m not going to get into which is going to come first or predictions about dates because as we’ve said before, these are complex discussions. They’re customer-driven. And we continue to make progress, and we feel very good about what our opportunity set is on across our portfolio, both gas, nuclear and even new build options.

David Arcaro: Got it. Okay. And then maybe looking at Slide 7, I see you maybe more explicitly highlighting here development opportunities at gas and coal plants, the new gas plants that you mentioned there. Just curious, are you kind of intentionally moving more toward a new build strategy or looking more at hybrid offerings, combining new megawatts and existing gen as you’re progressing these contracting conversations?

James Burke: Yes, David, it’s really customer-driven. I think part of what we’ve seen happen in the last 2 years, as we’ve talked about, customers came in with a set of what I call preferences and then those evolved to needs as they tried to figure out what the art of the possible was. I think that’s still happening. I think that’s why bridge power, which came up on one of the earlier questions. This discussion 2 years ago wasn’t about bridge power. and it sort of has evolved to bridge power as an example. I think colocation was an early idea, then people are trying to figure out how the tariffs work. I think colocation is going to be coming back with new and existing into the picture. So I would not view this as we have a shift in strategy.

What we’re doing is kind of meeting the customer needs as the customer needs adapt, and they are different by hyperscalers or even different in different geographies. I think this 4,500 megawatts was as much a reminder to ourselves as it was to the market that we are developing a fair amount of assets, but not because we started off with just the intention of let’s go develop a lot of assets. We have to steward the shareholders’ capital. And if the right stewardship of that capital is not to do these kinds of projects, then we’re going to make the right call. And I think Kris can talk at length about how we think about that. But we do want to meet customer needs, and we can do that and get the right returns for shareholders. That’s a win-win, growing our business, meeting the needs of the customers, returning capital to shareholders.

So I would not say that we have some commitment to a pipe or a commitment to build a certain number of megawatts as an overall theme because I think that can be limiting in terms of market opportunities. And we have been opportunistic. I think we’ve shown that, and we’ve been disciplined. So I see us sticking with that.

Operator: Our next question is from Bill Appicelli with UBS.

William Appicelli: Just going back to some of the commentary you had earlier around ERCOT and the forward curves. You talked about the incremental load growth you see over the next several years. I mean what do you think is driving that sort of mispricing that you see in the curve? Is that just a lack of conviction given all the sort of confusion out there? I mean, how much upside do you see just based on your load forecast?

James Burke: Yes. I’m going to start, and I’m going to ask Shawn Stuckey to chime in. I think there’s a couple of drivers. One is, I think folks are trying to get their head around what is a fair load forecast for the reasons we talked about earlier on the call and just the amount of discussion around the size of these batches and when are you going to get approvals to hook up the load. Again, I don’t think that is actually driving what our view of a load forecast is in the near term, and we think the forward curves don’t reflect even our view of a load forecast. I do think the amount of batteries that have come into the market for the last 3 years have returned virtually nothing to the owners of those batteries. And I do think the batteries will end up shaking out at some point because as we know, most of them are in the 1- to 2-hour variety.

So when the higher load factor load does come on to the system, it’s not designed to meet that high load factor customer profile. But the batteries have been a material increase in supply. And when you have a low volatility kind of environment because the weather has not been that strong, you haven’t seen the clears be very high. So I think that’s part of this backdrop that we’re seeing and particularly since 2023 when you saw the kind of peak in the August ’23 real-time prices. And we just haven’t seen that level since then. Even though the underlying load is growing, the peak has not been growing quite as fast. So Shawn, I’d love to hear your comments if there’s anything about how that’s kind of worked its way through the forwards and anything you’re seeing as sort of drivers that they could keep an eye on.

Shawn Stuckey: Yes. Thanks, Jim. So what I would add to that is this is a recurring theme that we’ve seen across the ERCOT market throughout the years. The term markets really do trade off of near-term weather and near-term pricing. So expectations of load growth in the term is obviously a significant driver. But we’ve seen it time and time again, existing weather in cash really drives the forwards. And I think if you look at what happened around April 14, April 15, 2 things happened. ERCOT released their long-term load forecast. I think people looked at some of the numbers in there and started to wake up and sort of think about the possibility of what was realistic as well as what was not realistic in those load growth expectations.

And there was also some heat that was showing up in late April. We did see some heat. We did see some pricing. And you’ve seen the forwards respond accordingly. You saw both summer and winter prices move up fairly materially. And I think that has been a recurring theme over time, and we expect that to continue. So I think it’s kind of more of the same.

William Appicelli: Okay. That’s very helpful. And then just one quick follow-up. When you guys are talking about the gas bridge power, I mean, is that generally aero derivatives? Is that what you’re looking at there?

James Burke: Bill, we haven’t been technology. We actually are talking to multiple OEMs about different technologies and some customers have different preferences to technology. So unless Stacey has a different view, based on the discussions I’m in with Stacey and her team, we’re seeing all of the varieties coming through, and it sort of depends on availability, cost and the customer preferences.

Stacey Dore: Yes, I agree, Jim. That’s actually an advantage that Vistra has is we’re driven by what the customer need is. We’re not committed to one technology or another. So based on what their needs are, we’re able to help them identify what’s available and what would serve their needs, and that can be a variety of different types of OEMs and technologies.

Operator: Our next question is from Julien Dumoulin-Smith with Jefferies LLC.

Julien Dumoulin-Smith: Maybe to talk in a little bit of a different term or permutation here. Can you talk about like hedging capacity? We saw one of your smaller peers here put up a 12-year capacity deal here. Can you talk about how you think about hedging out maybe in a comparable way, any kind of MISO or MISO exports on term in a way that might sidestep additionality? And then separately, any ability to get term in PJM on capacity? How do you think about that opportunity here? And then I’ve got a quick follow-up.

James Burke: Sure. So Julien, just to make sure I understand your question. I mean, our deals that we have announced include capacity as part of the construct. Obviously, there’s different ways we can contract. But as we discussed what we’ve announced already with Meta as an example, we were contracting capacity and energy. So I just want to make sure I understand your question. Was it in light of everything…

Julien Dumoulin-Smith: Yes, incrementally, right?

James Burke: Yes, incrementally.

Julien Dumoulin-Smith: In this day and age, if you can’t — if it’s more difficult to get an energy and capacity contract, how do you think about just simply hedging capacity, right? I hear you. In fact, your earlier comments, you were very clear in saying, look, it seems as if you’re maintaining length in ’28 onwards when it comes to your energy hedging. And so especially given what your peers are doing in hedging their capacity, I’m trying to bifurcate how you think about the different attributes that you can monetize and especially being conscious that one of your peers got this long-duration capacity contract, MISO, you all being very heavily oriented in the Midwest in some respects, is there an ability to kind of lean on that side?

James Burke: Yes. So the MISO fleet, as you know, has been going through a transition. That’s one of the markets that we serve that is a coal-fired fleet. And there’s a lot in that question, Julien, because there’s a lot of overlay of what’s happening with federal policies and obviously, state policies. I would turn the question a little bit broader to say those are great sites and opportunities for us to do things with parties that may not be with assets because in reality, the existing assets have a life to them. There’s a debate about just how much more life is there, but it’s not the same as the nuclear fleet. So I think you’re going to see the development opportunities come to pass for us. And as we noted in our slides, we have hundreds of thousands of acres and 70 sites, but it’s still going to be customer-driven.

So I don’t view MISO at the moment as we have an asset that’s there, can I go get a 12-year contract off of it. I don’t know that, that’s going to be the right match for that type of asset. But I do think those sites have real opportunity for us to do things for customers that are probably going to be a little bit more organic and take the redevelopment of the site into consideration.

Julien Dumoulin-Smith: And Jim, since you bring it up that way, I mean, you all have been pretty instrumental in Illinois and talking about storage. I haven’t heard you talk much about it today in the context of additional capacity. How do you think about leading the charge on that front, whether it’s in Illinois in response to both the backstop and/or the state mandates or frankly, across the footprint? I mean, complementing with storage, it seems like a ripe conversation for you guys in particular, but you haven’t emphasized it here today, notably.

James Burke: Yes. Well, that is probably because, Julien, the way we, again, think about our business is we start with a customer and what does the customer need look like. Batteries have different roles to play. Obviously, batteries on sites that might support data centers play a different role than just putting a wholesale battery out onto the system and hoping that it gets a fair capacity payment and maybe a spark or some sort of spread. And we’ve seen in ERCOT, that’s been a difficult proposition. So when you look at the cost of these batteries, they have not come down in price as much as people might think. Obviously, there’s ITC challenges if it’s not more domestic in origin. But we don’t see from our math that batteries inherently have a better IRR opportunity than some of the other dispatchable options.

But again, we’re going to be customer-driven in the way we think about this. And so there will be customers that prefer batteries. If that’s part of the additionality for them, that’s important. If the grid operators from an ELCC give credit for that or that helps with the flexibility requirement that they may have as part of their load ramp, then batteries will come into the picture. But I would tell you that simply the battery strategy as a wholesale product in the market, I would say, have debatable returns unless you can get a really long contract with an offtaker for it and reduce your market exposure.

Operator: This concludes our question-and-answer session. I would like to turn the conference back over to Jim Burke for any closing remarks.

James Burke: Yes. I just want to thank everybody for joining. I think you can tell based on this call, it’s a very busy time, but it’s also incredibly exciting for Vistra. And we’re going to provide you updates as we continue to execute on this strategy. It’s also an important moment for all of us in the industry. And I think a lot of policy discussion is occurring, and Vistra is going to do its part to make sure that we’re part of that and that we deliver reliably and affordably. I want to thank our team for their service to our customers and to our communities. And I want to thank our shareholders for their interest in Vistra, and we look forward to seeing you in person soon. Have a great rest of your day.

Operator: The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.

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