Vistra Corp. (NYSE:VST) Q3 2024 Earnings Call Transcript

Vistra Corp. (NYSE:VST) Q3 2024 Earnings Call Transcript November 7, 2024

Vistra Corp. beats earnings expectations. Reported EPS is $5.4, expectations were $1.2.

Operator: Good morning, and welcome to the Vistra’s Third Quarter 2024 Earnings Call. All participants will be in listen-only mode. [Operator Instructions]. After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions]. Please note this event is being recorded. I would now like to turn the conference over to Eric Micek, Vice President of Investor Relations. Please go ahead.

Eric Micek: Good morning, and thank you all for joining Vistra’s Investor Webcast discussing our third quarter 2024 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. Leading the call today are Jim Burke, Vistra’s President and Chief Executive Officer; and Kris Moldovan, Vistra’s Executive Vice President and Chief Financial Officer. They are joined by other Vistra senior executives 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.

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 explains 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’ll now turn the call over to our President and CEO, Jim Burke.

Jim Burke: Thank you, Eric. Good morning, and thank you for joining us to discuss our third quarter 2024 operational and financial results. It has been an active year on a number of fronts, and I’m very proud of what the Vistra team has been able to deliver so far in 2024 while setting the stage for long-term value creation. Turning to Slide 5. I would like to recognize the Vistra team for another quarter of hard work and strong operational performance. Through their efforts, we achieved a solid quarterly financial results of ongoing operations adjusted EBITDA of $1.444 million despite a continuation of the milder Texas weather we have experienced most of the year. The consistent execution from our team across generation, commercial and retail delivered reliable power and customer solutions that reflect the strength of our integrated business model.

As you may remember from our second quarter results call, we indicated our 2024 ongoing operations adjusted EBITDA was trending toward the upper end of the guidance range. I am pleased to report that with the results announced today and our outlook for the fourth quarter we are raising and narrowing our guidance range for 2024 ongoing operations adjusted EBITDA to $5.0 billion to $5.2 billion with a midpoint above the upper end of our previous range. We are also raising and narrowing the guidance range for ongoing operations adjusted free cash flow before growth to $2.65 billion to $2.85 billion. As we noted on our previous results call, our guidance excludes any potential benefit related to the nuclear production tax credit, or PTC, as we await clarity from treasury around the interpretation of gross receipts.

However, based on year-to-date settled prices and the forward curve for the balance of the year, we believe the impact of the nuclear PTC to our 2024 ongoing operations adjusted EBITDA could be approximately $500 million. Moving to our longer-term outlook. We are introducing guidance ranges for 2025 ongoing operations adjusted EBITDA of $5.5 billion to $6.1 billion and ongoing operations adjusted free cash flow before growth of $3.0 billion to $3.6 billion. Notably, our ongoing operations adjusted EBITDA guidance midpoint of $5.8 billion is higher than the $5.7 billion upper end of our previously communicated range for 2025. While our ongoing operations adjusted EBITDA guidance for 2025 is not currently expected to benefit from the nuclear PTC at any significant amount due to the current level of forward price curves we do expect the availability of the nuclear PTC to provide downside protection in the event prices settle lower.

For calendar year 2026, although our current hedge percentage has increased to approximately 64% of expected generation, a meaningful amount of gross margin variability remains. Further, the delay in the 2026, 2027 PJM capacity auction, including the potential modification of the associated auction parameters create some additional uncertainty. For these reasons, we are maintaining our outlook for our 2026 ongoing operations adjusted EBITDA midpoint opportunity of over $6 billion with line of sight to potentially be meaningfully higher. Finally, the third quarter marked an active period of capital allocation and capital returns. On September 16, we announced the acquisition of the Vistra Vision 15% minority interest from our minority investors.

We believe this acquisition will be highly accretive to our shareholders with an implied transaction multiple of less than 8 times enterprise value to EBITDA, 100% ownership upon closing at year-end and financial flexibility allow through an extended payment schedule. In addition, the significant share price weakness we experienced in late August and early September resulted in an uptick in repurchases and we were able to execute in the quarter. In all, we repurchased approximately $400 million of shares in the open market in the third quarter at an average purchase price of approximately $83 per share. Combined with the Vistra Vision 15% minority interest acquisition, which we view as similar to a forward share repurchase program with a deferred payment schedule, we were able to allocate a combined approximately $3.5 billion to the repurchase of our equity at an average indicative purchase price between $80 and $85 per share, roughly a 30% discount to our recent share price.

Turning to Slide 6. Our four key strategic priorities remain integral to our strong business performance. As we have previously stated, we believe our integrated business model and comprehensive hedging program, provide our stakeholders increased visibility into our future financial performance. From an operational perspective, our team continues to deliver. Our generation team achieved overall commercial availability of approximately 96% for our gas and coal fleet. Our nuclear fleet also had an outstanding quarter with capacity factors averaging approximately 98% for the period as we continue to make great progress on our integration efforts. On the retail side, the team continues to outperform through both strong customer count performance in the Texas and Midwest Northeast markets as well as disciplined margin management.

Finally, we are seeing persistent growth in our large business market segment through longer-term customer relationships as a result of providing solutions to meet customers’ goals, including sustainability objectives and budget certainty. Switching to capital allocation, we remain disciplined in our approach by targeting a significant return of capital and executing on attractive growth projects like the Energy Harbor acquisition, while also maintaining a strong balance sheet. As part of this approach, we continue to execute the capital return plan put in place during the fourth quarter of 2021. Since that time, we have returned approximately $5.4 billion to our investors through open market share repurchases and common stock dividends. Chris will cover capital allocation in more detail later in the presentation.

But you will see that we expect at least an additional $1.5 billion of capital available to allocate through year-end 2026. This number is net of our current capital responsibilities including the recently announced provision, 15% minority interest purchase and the recent Board authorization for an additional $1 billion of share repurchases expected to be executed by year-end 2026. Speaking of the balance sheet, our financial position remains strong with net debt at the end of the third quarter at approximately 2.7 times ongoing operations adjusted EBITDA. Although our net leverage is expected to move slightly above 3 times with the closing of the Vistra Vision 15% minority interest purchase, we expect it to fall back below 3 times in 2025.

Moving to energy transition. As you know, our approach continues to responsibly balance reliability, affordability and sustainability while ensuring disciplined returns for our shareholders. The Vistra Vision 15% minority interest purchase is a great example of this strategy as we view the transaction as an attractive investment in our carbon-free assets and retail franchise. In addition to repurchasing the minority interest in our best-in-class retail business. Through this acquisition, we will increase our ownership of nuclear generation by approximately 970 megawatts and across our four sites at an average price of approximately $2,100 per kilowatt. We believe this compares very favorably to per unit cost for other nuclear generation alternatives such as plant uprates, new build, or additional M&A.

Finally, the acquisition will result in an approximately 200-megawatt increase in our solar and storage capacity assets and we look forward to continued growth in this business through the disciplined execution of our existing project pipeline. As highlighted on Slide 7, and this year alone, we have seen numerous announcements of major manufacturing and data center additions by company spanning across industries. These announcements have spurred heightened awareness and projections of power demand growth. Some grid operators have already raised their expectations for demand growth through midyear updates while numerous industry observers have published forecasts reflecting an acceleration in power demand across the country. We also discussed this growth dynamic on our first and second quarter calls, specifically highlighting many of the drivers of power demand growth, including the build-out of large chip manufacturing facilities, partially due to the CHIPS Act the electrification of oil and gas load in the Permian Basin of West Texas, the reshoring of industrial activity and, of course, the build-out of data centers.

As shown in the bar chart on the left, actual weather adjusted loan growth for 2024 in PJM and ERCOT not only exceeded historical rates, but is trending towards long-term forecasted levels. We believe the level of growth across both markets confirms our view that low growth is already occurring, and we expect it to continue. While there has been a lot of focus on FERC’s rejection of the amended talent interconnection service agreement, or ISA, we believe there will be multiple paths to resolve any issues as it relates to that project and other similar projects. FERC’s ruling was narrowly based on the commission’s view that the ISA failed to meet previous FERC precedent, leaving the door open for a refiling of a streamlined ISA. Nothing about FERC ruling prevents us or other generators from contracting with customers who are seeking to co-locate for their needs.

We will need to address open issues and find the path to FERC approval of interconnection service agreements, which we believe is doable. As we’ve stated before, there will be many large load opportunities that will have a variety of configurations, whether located next to a generation facility or in a more traditional front of the meter configuration. We don’t believe there will be a one-size-fits-all approach to this, and there shouldn’t be as customer needs will vary. This transmission is to meet these needs and that of our broader customer base just as we do today. I’m sure we will discuss this more in the Q&A, but I will turn it over to Kris to provide a detailed review of our third quarter results, our outlook and capital allocation. Kris?

Kris Moldovan: Thank you, Jim. Turning to Slide 9. While the third quarter did not benefit from the same weather opportunities as last year, which we estimate added approximately $300 million to our earnings in the third quarter of 2023, Vistra was able to deliver solid results due to excellent operating performance and execution by our generation retail and commercial teams. Despite lower cleared wholesale prices compared to last year, our flexible generation fleet continued to perform extremely well and maximize available opportunities. Turning to retail. As expected, third quarter results reflected higher power costs compared to 2023. However, year-to-date results are meaningfully higher compared to 2023 as the team continues to deliver strong customer count and margin results.

Finally, our third quarter 2024 results for both generation and retail benefited from the inclusion of Energy Harbor, which we estimate to be approximately $165 million for generation and approximately $35 million for retail. Moving to Slide 10. As Jim noted, we are raising and narrowing our 2024 ongoing operations adjusted EBITDA guidance range to $5 billion to $5.2 billion. We are also raising and narrowing our 2024 ongoing operations adjusted free cash flow before growth guidance range to $2.65 billion to $2.85 billion. Although our team is executing at a high level across the business in 2024, this latest increase in our guidance range is primarily related to the performance of our retail business. Moving to 2025. The improvement in our outlook is attributable to increased expectations for both our generation and retail businesses, specifically as it relates to retail, we have previously communicated that we expected this business to contribute adjusted EBITDA in the range of $1 billion to $1.2 billion on an annual basis.

Due to several factors, including the addition of Energy Harbor, and sustained growth in residential demand in Texas and large business market demand across the country. We now expect the annual adjusted EBITDA contribution from this business over the next several years to be in the range of $1.3 billion to $1.4 billion. However, for 2024, we do project our retail results to come in above that range due to a few tailwinds that are onetime in nature. Switching to ongoing operations adjusted free cash flow before growth, the midpoint of our guidance range implies a conversion ratio of approximately 58%, comfortably in our previously indicated long-term target range of approximately 55% to 60%. Of course, our guidance and long-term outlook remains supported by our comprehensive hedging program.

Our commercial team continues to be opportunistic in taking advantage of recent power market volatility, increasing our wholesale hedge balances to approximately 96% for calendar year 2025 and approximately 64% for calendar year 2026. Turning to capital allocation on Slide 11. Our share repurchase program has generated significant value for our shareholders. Since beginning the program in November 2021, we have reduced our shares outstanding by approximately 30%, repurchasing approximately 158 million shares at an average price per share below $2. Notably, this reduction in our share count has led to an approximately 46% increase in our dividend per share since Q4 2021. Moving to the balance sheet. As of the end of the third quarter, our net leverage was comfortably below our long-term target of 3 times ongoing operations adjusted EBITDA.

Although we expect that ratio to move slightly above 3 times when we close the acquisition of the 15% minority interest, we expect to delever quickly and be comfortably below 3 times by year-end 2025. Importantly, our business remains well capitalized and we continue to manage the balance sheet in a conservative way, as evidenced by the recent upgrade of our corporate credit rating to BB+ by Standard and Poor’s. Finally, we will continue to be opportunistic, yet disciplined in the deployment of capital towards growth. To that end, we expect to spend approximately $700 million in 2024 and 2025 as we execute on our development project pipeline, including the recently announced solar projects for Amazon and Microsoft. Of course, we will continue to pursue opportunities to fund those expenditures with third-party capital, including nonrecourse loans.

Finishing on Slide 12. Based on our guidance for 2025 and our current expected 2026 ongoing operations adjusted EBITDA midpoint opportunity of at least $6 billion as well as our expectation that we will continue to achieve our targeted long-term ongoing operations adjusted free cash flow before growth conversion rate, we project to generate a meaningful amount of capital through year-end 2026. We also expect our net leverage, excluding our nonrecourse financings to reduce materially as our earnings power improves, providing additional capital flexibility. As you can see, our current capital allocation plan through year-end 2026 continues to focus on shareholder return with over $6.5 billion allocated to the Vistra Vision 15% minority interest purchase, common and preferred dividends and expected open market share repurchases comprised of the approximately $2.2 billion remaining under the existing authorization through 2026, including the additional $1 billion share repurchase authorization announced today.

However, despite the significant amount of capital already earmarked for shareholders, we still expect to have approximately $1.5 billion of incremental capital available for allocation through the end of 2026. Because this amount is based on $6 billion of ongoing operations adjusted EBITDA, we see the potential for upside to this amount. As highlighted on the previous slide, over the last 3 years, we have been significant buyers of our common stock, including jump starting to repurchase by issuing preferred equity. However, it is important to remember that the decision to repurchase our stock was only one aspect of our capital allocation framework, we sought to balance capital return, maintaining a strong and resilient balance sheet and executing on an opportunistic growth.

We expect this framework to continue to guide our capital allocation decisions, not only through year-end 2026, but also over the longer term. Importantly, our return thresholds for both organic and inorganic growth have not changed, and we remain disciplined in choosing the opportunities we pursue. I do think it is also important to note that we still see our shares trading at an elevated free cash flow yield, especially when compared to the average free cash flow yield for companies in the S&P 500 and we continue to believe allocating capital to share repurchases is an important priority. With that, operator, we’re ready to open the line for questions.

Operator: [Operator Instructions] The first question comes from Shar Pourreza with Guggenheim Partners. Please go ahead.

Q&A Session

Unidentified Analyst: Hey guys. It’s actually James [ph] on for Shar. Good morning and thanks for the time. So I guess maybe just coming back to the Susquehanna ISA and some of your prepared, I guess, how has the rejection impacted your customer conversations in the past week. One of your peers sounds committed to co-locations and other maybe more focused on front of the meter. I guess, where do you fall kind of within those soup polls? It sounds maybe a little more like colos, but just any more color there would be helpful. Thanks.

Jim Burke: James, we were disappointed with the ruling last Friday. But I think if you look at our discussions on this topic in the past, we’ve acknowledged that these are complicated deals. They take time they’re large even by the standards of the customers that we’re talking to. Then if you look at the quantity of deals that this country is going to do, the vast majority of them are going to be front of the meter. It’s unique to have the large sites that we have and have an opportunity to do a co-located deal. We think there are multiple paths forward on this. We’re not 100% sure how the other parties that are obviously active on that particular ISA you’re going to want to pursue it. But nothing precludes us from still moving forward with our plans.

I would acknowledge that everyone is looking at these types of issues and how do we work through them because they are they are novel. I mean some of the co-located deals even that we’ve done, they were smaller. And so when things are of this scale, there are more questions that need to be answered. But we think there’s multiple paths forward. We can go into some details as to how we think that might play out. But our conversations are still continuing. We still have a number of really good options, both with our nuclear sites as well as gas sites and potentially the new build. And so I don’t think that this is a load profile and a customer base that is going to slow down in aggregate. I just think it comes down to which areas of the country are more open to this?

Are they able to attract this load because it’s a huge economic development opportunity and we’ll have to see how that plays out? And it could play out differently in different parts of the country. So I just think that’s where we are, and it’s a process. And we’re going to work through it with our peers in the industry, the vertically integrated utilities. Obviously, the ISOs and any of the other stakeholders as we need.

Unidentified Analyst: Okay. Great. And then maybe just kind of piggybacking on that. If we could touch on your thoughts around additionality. Just we heard some commentary from certain members of the PUCT in recent weeks kind of calling for it. So I guess at this point, do you think a colo and ERCOT like Comanche Peak would have to come with additionality? Maybe just some more general thoughts there. Thanks.

Jim Burke: Yes. I do think there are a couple of issues obviously at play here. One is resource adequacy in general, right? So even without the additional data center load that could come to, say, Texas in this example, James, that you mentioned it, there have been questions about whether there’s adequate price signals for new investment regardless of just the data center load. In fact, the data center load over the next 5 years to 6 years, will probably not be the largest source of load growth in ERCOT. It just so happens though when you start talking about the data centers, it looks like 1 big chunky load coming at a time, so it gets the attention. As you know, we’ve put out our announcement of our intention to add megawatts in ERCOT, both with the Coleto Creek conversion as well as the augmentation of existing gas sites, those two alone are going to bring 1,100 megawatts.

The peakers are projects that we’re still developing still need to see some of the market reforms come to fruition to make those economic or contracts, contracts that could come from bilateral contracts with customers can make those kinds of projects feasible. So I don’t think this is a discussion that you can solve with just a rule because we’ve got multiple customer classes coming that are bringing additional load requirements to ERCOT. But I do think that the objective of the customers that we’re talking to, they want to see resources at it. They’re not looking to see the grid become tighter and tighter either. So we are very active in the discussion about what additional resources we can bring potentially even in addition to the ones we’ve already announced.

And we hope that if that is a compact that works for all the stakeholders that could help set a confidence that welcoming the load to Texas or any part of the country is actually going to send the investment signal for the supply side and having discussions about whether we may or may not want the load can actually create its own problems. And so we’ve seen many cycles in this industry. People are prepared to invest and build if the signals are there. I think this is more than just a typical load coming to the market. This is a unique opportunity for regions of the country and specifically for the U.S. to lead on this topic for such a critical load and use its artificial intelligence. And I hope we all see it that way. And that’s been our main focus in our discussions with policymakers.

Unidentified Analyst: Excellent. I’ll leave it there. Thank you.

Jim Burke: Thank you, James.

Operator: The next question comes from David Arcaro with Morgan Stanley. Please go ahead.

David Arcaro: Hey thanks, good morning.

Jim Burke: Good morning, David.

David Arcaro: Hey, maybe a little bit of a follow-up on that on your comments there, thanks. Very helpful. We heard yesterday from Encore that they’re seeing over 80 gigawatts of data centers looking in just their service territory, at least in the pipeline. I mean just given that scale, there’s just got to be a bunch of approaches, maybe diversity of approaches that these data centers are going to consider. And so maybe just given that, like what are you seeing as the interest in co-location at your gas plants in ERCOT? And then wondering if you could elaborate, too, on just that new build idea? Like are there — are you in conversations with potential data centers that you might be able to partner with contract with a new plant build as well?

Jim Burke: Sure. David, great question. I’m going to start, I’m going to ask Stacey Doré, our Head of Strategy, to comment on this. She’s working on these types of opportunities on a very near full-time basis. It’s certainly an active time for all those types of conversations. I’d start with load forecasts have been obviously extremely robust in ERCOT, CenterPoint put out some information about the kinds of load growth they’re seeing in their territory, certainly Encore through the separate call yesterday, and ERCOT itself has revised middle of the summer, it’s long-term load forecast. We’ve been a bit more conservative only because we believe still it’s hard to understand the full duplication that could exist not only within a state, but even across the country because folks are looking for PaaS to get speed to be able to bring this load.

And so they’re exploring all options. I do think that demand, if we can satisfy it, I do think Texas is probably as well positioned as any part of the country to satisfy that demand. And we certainly want to be part of that, not only on providing the relationship for the load, but the potential addition of resources. So I’d like for Stacey to provide some color on the types of conversations we’re having and how we’re working with Encore, with CenterPoint with ERCOT to make sure that we can all solve this together.

Stacey Doré: Yes. Thanks, Jim, and thanks for the question, David. So we are currently pursuing deals at multiple sites in our portfolio. We’re also having some early conversations with some of the developers about a kind of portfolio approach where with one customer, we might be able to pursue colocation deals at multiple sites and combine that with even building some new generation. We have — we’re in pretty detailed customer discussions at some of our nuclear sites. There’s a lot of interest, obviously, in the nuclear side. But we have ongoing conversations with several different development companies, about a handful of our gas sites, both in PJM and in ERCOT. And we’re in early discussions with some of the hyperscalers about nuclear uprates, and some new build as well as Jim mentioned.

And then finally, we’re in discussions with two particular large companies about building new gas plants to support a data center project. So as you can see, these discussions just take a number of forms with multiple companies around multiple sites. And of course, we’re including stakeholders in those conversations as well from policymakers to the applicable transmission distribution utilities. As we’ve said before, the diligence process for these deals takes a long time. It’s an intense effort because these are very long-term commitments to purchasing power. And so we’re devoting a lot of time and resources to these discussions, but we’re excited about the opportunity, and we believe that the — whether it’s Texas or other states that we operate in, Pennsylvania, Ohio, these are jurisdictions that are really interested in welcoming this load because of the economic development it brings.

And so it’s a multiparty conversation for all of these projects.

David Arcaro: Thanks for that. It makes sense just given the staggering scale here that so many options are under consideration. And I guess, maybe to ask it more directly to in terms of Comanche Peak. Have you seen Comanche Peak becoming better positioned here just after seeing the FERC challenges that have popped up in PJM? Like has urgency increased there? And just would be curious your latest thinking on what the timing of a deal could potentially be?

Stacey Doré: Yes. Thanks, David. So we — our discussions on Comanche Peak have been ongoing for some time, and there certainly is interest in in that location because of the speed-to-market advantage it has even before the FERC decision, frankly. I mean ERCOT and ERCOT is one of the fastest interconnection processes in the country. And the state prides itself on that, the TDUs and ERCOT as well working together to get load interconnected as an advantage in Texas. So certainly, the fact that ERCOT is not subject to the FERC jurisdiction and the order that came out last Friday has continued to make Comanche Peak an attractive site, but it was before the FERC order as well. So in terms of timing, it’s hard to say exactly when we could conclude discussions on that side because, again, there’s a lot of work to be done.

There’s a lot of stakeholders to involve not just ERCOT, policymakers Encore, who is the local TDU at that side, but local officials as well. So there’s a lot of conversations to have, and we’re well into that deep into that process and continuing to pursue that opportunity, and it’s a great opportunity for Vistra and for customers.

David Arcaro: Okay, great. Thank you.

Operator: The next question comes from Steve Fleishman with Wolfe Research. Please go ahead.

Steven Fleishman: Hi, I guess I’ll dare ask one other question on this topic, which is just Texas has emphasized availability of resources at kind of emergency or peak times and the like. Do you see solutions in ERCOT where you could have the generation even if it’s co-located, available for kind of the more sensitive periods?

Jim Burke: Yes, Steve, we do. We have even noted, I think, in previous discussions, customers are learning how they can also manage their load during sort of emergency conditions. So whether it’s something around a load response or whether it’s the backup generation that could be also configured at the site. Again, I think these large customers, I think they’re responding to some of the questions that they’re receiving and the concerns around resource adequacy, and they’re showing that they want to be part of that solution. So that is, again, to Stacey’s earlier point, why these discussions do take some time, and they’re complex is there’s a lot of variables that we’re managing. So I do think there’s going to be some flexibility there, Steve, and I think that will help multiple stakeholders become comfortable with it.

Steven Fleishman: Okay. And then on the — we just obviously had this big election result. And I’m just — I know it’s two days in, but just the — any kind of thought process on what this means for kind of both new build gas and then also for your coal fleet?

Jim Burke: Yes, Steve, I’d tell you the election prediction business is tough, and so is the policy prediction business. It’s — I guess some of the thoughts that we are working through the GHG rule, and that’s already being challenged, obviously, legally and with the DC circuit. There’s — that could potentially be revised at some point. And you can see that with this administration, that affected not only the coal units, but also new gas. And so that’s something that — we’ll have to see how that plays out, and that could still take some time to play out, but that does appear to be more open at the moment, at least in concept. But getting back to this resource adequacy topic and also just the administration changes, it’s hard to look at 30, 35-year assets and look at the changes that happen policy-wise on a 4-year cadence, and see through all of that.

That’s a difficult thing for investors to do. One of the things I like about our business model, and I don’t think this is something we talk about a lot is that we’re a pretty diversified company. We have geographic diversity across major markets in the U.S., different jurisdictions, all obviously, competitive markets but we have a broad technology diversity. The largest part of our fleet is gas-fired generation, but then it’s nuclear and a coal business that’s continuing to decline and a growing solar and battery business. So we have a lot of diversity in technologies and in line of business. You heard today, the retail business is large and growing. And that tends to be complementary to the generation business. So it’s really hard to look at first and second order effects of potential policy changes, but I think we’ve demonstrated that we’re flexible as a company and that will take opportunities that the market presents us and execute on it.

So I view this as — I wouldn’t say this is normal course for Vistra, but this has been a lot of our history in the competitive market is having to adapt. And so we are obviously open to the technologies that you’ve mentioned. It’s a big part of our portfolio, and we’ll have to see if that if some of those get some extended life opportunities, but too early to call.

Steven Fleishman: Okay. And then one last quick one. You added the mention for 2026 of potentially meaningfully above the $6 billion. I don’t know if you care to define what meaningfully means and the like or just in the event that — in the event that the PJM auction just were to price where it did the last auction, is there any kind of more color you could give about that? Is that the main driver? Is it really more ERCOT pricing? Just any color would be helpful. Thank you.

Jim Burke: Steve, I’m going to let Kris take this one. Good question. We know words matter, and that would be one that you pick up on. So Kris?

Kris Moldovan: Yes, Steve, I think it’s a combination of those things. I think, obviously, as you look at it, we’re only — we’re 64% hedged. We’re making progress in that area. But even if you look at our 2025 guidance, there’s a good range around that. It’s 5% plus or minus around our 2025 guidance, and we’re 96% hedged there. So as we look out to 2026, and we see 64% hedged, you can imagine that our range around that is a little bit wider. And you also mentioned the PJM auction, that’s an area. So we think it’s still prudent to say $6 billion. I think if the auction comes in where we where it came in the last time and as we hedge a little bit more, we have built in some protection against those things potentially going against us.

So you could see some upside. And I think that we’re not going to we’re not going to state where we see the upper end, but you can imagine that we’ve built in a little bit of upside to that if those things — as we hedge more and as we see the auction results come in.

Steven Fleishman: Great. Thank you. Appreciate it.

Operator: The next question comes from Jeremy Tonet with JPMorgan. Please go ahead.

Jeremy Tonet: Hi, good morning.

Jim Burke: Hey Jeremy.

Jeremy Tonet: I just wanted to pick up, I guess, on the diversified footprint as you mentioned there. Just wondering how you think about the ERCOT versus PJM opportunity set at this point in time, particularly in light of the Town ISA ruling granted it’s early days, but do you see things like this kind of starting to favor ERCOT more at the margin?

Jim Burke: I don’t think so, Jeremy. The capacity, again, the ISA is one dimension, but a capacity market construct in PJM is something that I think creates a real opportunity to send a price signal and encourage investment, whether that’s some assets that are on the grid to not retire or to bring new assets and obviously meeting the load growth that PJM is now forecasting that market design does not exist in Texas. And that’s something that from a capacity market discussion, where it’s an energy-only market. And so it has been a bit more volatile in terms of you might have a really strong summer in 2023, but we’ve had weaker clears in 2024. So if you were putting batteries on the grid right now in 2024, you’re probably wondering if you’re going to get a return on those batteries, whereas you might have felt really good about it heading into the summer of 2023.

So the ISA is only one dimension. It’s important to note that load is low. If this load comes into PJM, whether it’s behind the meter or front of the meter, it’s load growth a capacity market should send a signal like it did at the end of July, but there was intervention coming on the heels of that that’s now led to a request for a 6-month delay. Again, as I stated earlier, if these markets would consistently run their opportunities for the auction in the case of PJM. And for Texas being clear about signaling wanting the load to come, I think these price signals would be there. There’d be investment opportunities in both of them. But right now, PJM has a more structured way of valuing capacity and signaling in a forward curve basis, the need for that capacity then does the ERCOT market.

Jeremy Tonet: Got it. Understood on the PJM capacity auction there. But maybe coming back to the power curves, how do you see that evolving over time? Do you think that demand is really reflected in future pricing there? Or how do you see that kind of evolving?

Jim Burke: Yes. That would get more to sort of a fundamental view of where do we think the curves are relative to this load growth. And I would say, it feels to me and Steve Muscato, our Head of our Wholesale and gen business can chime in here, but it feels to me that the curves are not factoring in all of this load growth at this point that there’s a lot of forecasts out there, folks are going to want to see more data points that is actually coming to fruition. And we try to put in our presentation, we’re seeing that we’re on this curve of load growth. We put that in for what we’re seeing in 2024. But as noted earlier in some of the questions, there’s massive load growth being forecasted by the ISO as well as the wires companies. I would not say the curves reflect all of that coming in at this point. And I think just some of the recency of this summer is also weighing on the curves. And Steve, I would like to have you add some comments to that.

Steve Muscato: Sure, Jim. I think people are extrapolating what I’ll call historical load growth from the last 2 or 3 years of between 3% to 4% over the peaks. And I think they’re putting that forward in their models. It really gets down to how much of — I think someone mentioned the ENCORE study with 80 gigawatts of data. So how much of that actually gets in? And will we exceed the historical trends that we’ve seen before. And I also do think there’s some recency bias. Unfortunately, power is only liquid may be out until 2028, 2029, it’s hard to see beyond that, and there’s not a lot of activity. And so the recent clears we saw, I think, this summer have weighed a little bit because I think people also try to figure out there’s a very large asymmetry in pricing in Texas that we’ve seen both in the winter and in the summer.

And one of the areas I think you’ll see Traders focus on more in the future is what kind of premium do you put on winter because even if batteries continue to come into the market, which I think they’re going to be challenged because they’re — as you mentioned earlier, Jim, they’re cannibalizing the revenue streams. Right now, there’s so many of them, there’s more batteries in the market right now. Then the ancillary services can handle, which is their primary source of revenue, not necessarily under arbitrage. And when you mix that in with a winter event that’s not just 1 or 2 hours in duration. I think you may see some more scarcity come into the winter curves going forward.

Jim Burke: And thank you, Steve. And I’d like to add, Jeremy, just two other dimensions. This was the first month that we’ve seen where the new additions in the queue for solar and storage and wind were actually less than the number of projects canceled or moved into inactive status. So I do think markets have a way of over time, rationalizing economics. The other thing I think that’s weighed on the curves was the curves looked very attractive in the sort of May 2024 time frame. And I think the test the quantity of the test interest and the discussions of continuing TEF or even having a larger TEF. I’m sorry, I’m saying TEF, Texas Energy Fund. That is something that I think the markets are struggling to figure out how to handicap and look at is that only going to be an incentive for new generation only?

Or is that going to send a signal to keep existing generation online. And so there’s still a lot to sort out, I think, on the TEF because we’re still in early stages with the due diligence process, and we’re going to enter a legislative session next year. And I think folks are trying to figure out what is the state going to do if they’re going to actually increase that quantity of assets qualifying for TEF or if they’re going to let the market send a price signal to try to bring that investment. And I think that’s still too early to call.

Jeremy Tonet: Got it. That’s helpful there. That was kind of getting to my last question here with regards to TEF and just your project development activities in ERCOT, especially with the tough considerations that you said there, could you just, I guess, update us overall on your thought process?

Jim Burke: Sure. Yes. We did submit two peakers as part of the TEF application. Basically, each party that was selected, was selected for one project. So one of our two peakers was selected. As we stated when we made the announcement in May and have continued to stay since then, we want to see the actual development from a market design standpoint make progress. We — our reliability standard has been developed. It’s not linked to a requirement if we fall below a reserve or there are concerns around reliability is not linked to a market mechanism to procure additional resources in the market, but at least the reliability standard has been designed and will be studied on a periodic basis. The PCM performance credit mechanism is now hard capped at $1 billion.

It was a net cap. So presumably, that could mean a lower overall quantity of resources being dedicated to a performance credit mechanism. And there are some discussions about even that being challenged potentially in the legislative session. So I think that in the ancillary services like the dispachable reliability reserve service are still to be figured out. Real-time co-optimization is in flight as well for ancillaries and energy that could be bearish for some price formation. And that also speaks to how do we incentivize resources to come into the state to meet the load growth. And I don’t think we have all that figured out yet in Texas. And I think that’s work that we’ve got to do as an industry so that we can continue to meet the need.

We’ve designed our projects for the peakers that we’re continuing to move forward. The team is working on all the efforts we need on site as well as with our key partners. But we also have off ramps to both of those peakers if the market developments that we need to see don’t occur. And we hope that’s not the case because we’d like to bring those peakers, but we’ve got to make economic decisions. And we’re still not there yet.

Jeremy Tonet: Got it. Thank you for that.

Jim Burke: Thank you, Jeremy.

Operator: The next question comes from Angie Storozynski with Seaport. Please go ahead.

Angie Storozynski: Thank you. So maybe first on 2026, maybe even 2027. So just wondering if by then, by 2026, 2027, you would expect to have any meaningful EBITDA impact from those data center deals, be it colocations or virtual PPAs? And also, if that changes the way you’re hedging your especially baseload units in those outer years?

Jim Burke: Yes, Angie, thank you for the question. I would say it’s tough to see it being meaningful in 2026, 2027 simply because of the physics building out what you need to on the ground and then obviously powering the site as resources, servers chips become available and installed. And that’s after the study processes have to be done on the front end. And so the time line for these, you could be in a 4 to 5-year process before you’re putting a meaningful amount of power to a co-located facility. So I think time line wise, it’s not really affecting how we’re thinking about the hedging in the more near term sort of this 2026, 2027. And if it did, we’d start layering it in, in a more — we’re pretty open, still obviously, 2027, more than 2026.

So we hope that opportunity is there to be layering that in, but I would not say from a guidance perspective or from a hedging perspective, it’s in the horizon that we’ve been talking to the market about in terms of our direction here for our earnings power.

Angie Storozynski: Okay. And then changing OpEx. So a lot of discussion, obviously, in interest in your nuclear plants. You have many more gas plants. Can you just give us a sense directionally about the pricing differential for nuclear assets versus gas assets? Is it as simple as just the carbon-free attributes or again, just even directionally, how these prices compare and the discussions that you have with the data centers. Thank you.

Jim Burke: Yes. Thank you, Angie. I would say we aren’t able and really would prefer not to share pricing differences by asset class. But I will say that in previous calls, I’ve mentioned that customers look at this as a list of preferences. There’s things that they are seeking that are more ideal including location and what kind of energy needs there might be for cooling, right? So there’s all sorts of variables that are going to go into the equation of how valuable is this to a customer in speed and land and water and other variables are going to play into their willingness to pay under certain circumstances, more or less for different locations. And so I would not expect — I could be wrong, but I would not expect the gas assets to have the same premium as nuclear because of the carbon 3 24/7 attributes of nuclear.

But there is an openness to gas that we’re encouraged about. And I think the flexibility of being able to work with these assets is attractive for a number of parties, including co-location partners that aren’t directly the hyperscalers themselves. So I think I’d like to leave it at that, Angie, but I think that’s the way we’re thinking about it.

Angie Storozynski: And then last one, I know I promised Eric, just one question. But could you comment about the transmission capacity around your PGM assets, especially the especially Beaver Valley. So for example, if there were to be a need for a virtual PPA in like in front of the meter deal for that asset, is the transmission sort of overbuilt around it? Or do you have to wait for upgrades?

Jim Burke: Yes, I’ll start, Angie, and I’ll ask Stacey for her views, but we sit in a pretty balanced area where we are from a congestion point of view with locations we have, the three locations there in PJM. There’s still going to be study processes and efforts to connect load even if there is a perceived capacity available on the transmission system because there is still studying to be done about what adding load and particular spot is going to do to the whole system. And I don’t think we view it necessarily as it’s going to be faster or slower if there is some capacity or not, I think it’s probably going to be slower if it’s fun of the meter versus co-located. And I think that’s what we need to work. Again, we may end up doing both in the area in that region of the country. Stacey, anything you’d like to add to that?

Stacey Doré: I would just add that at Beaver Valley, we do have a necessary study agreement. It’s already been studied that a load could be co-located there without negative impact to the grid. And so I agree with Jim that it’s the benefit of colocation and the reason customers are pursuing it is for speed to market. So it will be faster than front of the meter. Having said that, again referencing what Jim said, earlier, there will be plenty of front-of-the-meter connections as well. And to the extent as we do with all customers that we can serve those customers with for their front of the meter connection, we’re certainly open to those discussions and having some of those discussions as well.

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

Jim Burke: Yes. Thank you for joining us today. I want to thank the team for their continued execution and service to our customers and communities. We appreciate we’re having this call in a very dynamic time. And I can just assure you our team is focused on delivering. We appreciate your interest in Vistra, and we certainly hope to see you in person soon. Have a great rest of your day. Thank you.

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