Vistra Corp. (NYSE:VST) Q4 2024 Earnings Call Transcript

Vistra Corp. (NYSE:VST) Q4 2024 Earnings Call Transcript February 27, 2025

Vistra Corp. beats earnings expectations. Reported EPS is $2.38, expectations were $0.85.

Operator: Good morning, and welcome to Vistra Corp.’s Fourth Quarter 2024 Earnings Call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing star then zero on your telephone keypad. After today’s presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your telephone keypad. To withdraw your question, please press star then two. Please note this event is being recorded. I would now like to turn the conference over to Eric Micek, Vice President, Investor Relations. Please go ahead.

Eric Micek: Good morning, and thank you for joining Vistra Corp.’s investor webcast discussing our fourth 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 Corp.’s President and Chief Executive Officer, and Kris Moldovan, Executive Vice President and Chief Financial Officer. They are joined by other Vistra Corp. senior executives to address questions during the second part of today’s call if necessary. The 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 the appendix to the investor presentation available in the Investor Relations section of Vistra Corp.’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 two of the investor presentation on our website that explains the risk 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 fourth quarter and full year 2024 operational and financial results. 2024 was a transformational year for our company, defined by growth and execution. In the past twelve months, we closed on a unique acquisition, adding three new nuclear sites and one million retail customers with nearly two thousand team members joining the Vistra Corp. family. We completed a twenty-year license renewal for our Comanche Peak nuclear power plant and secured two large power purchase agreements for a renewable pipeline. Our retail business grew and reached performance levels not achieved in the past two decades at competitive markets. This was a result of our one team mindset at Vistra Corp., and I’m excited about what we can achieve in 2025.

Turning to slide five, Vistra Corp. delivered another strong year of financial and operational performance, resulting in full-year adjusted EBITDA of $5.656 billion. This outstanding financial performance, which the team achieved despite a mostly mild year of weather in our key markets, exceeded the top end of our original guidance range even before considering the $545 million benefit from the nuclear production tax credit that we recognized in the fourth quarter. This consistent execution from our team across generation, commercial, and retail, supported by a focused corporate services team, delivered reliable power and customer solutions that reflect the strength of our integrated business model. We believe the performance achieved in 2024 is proof that a diversified portfolio of generation assets, including nuclear and gas, combined with a best-in-class retail business and a sophisticated commercial team, produces a superior business model for operating in volatile power markets.

Moving to our longer-term outlook, we are reaffirming our guidance of $5.5 billion to $6.1 billion in adjusted free cash flow before growth of $3 billion to $3.6 billion that were introduced on our third quarter call. As you can see, we are also maintaining our outlook for a 2026 adjusted EBITDA midpoint opportunity of over $6 billion. While we have the potential to be significantly above this amount, there are still a number of variables in play, including final approval of the 2026, 2027 PJM auction parameters and remaining hedging activity required to take us above the current hedge level of 80%. We expect to provide more clarity on our expectations for 2026 later this year. Finally, during 2024, Vistra Corp. positioned itself to deliver significant capacity additions at our key markets to meet the coming load growth.

This starts with the megawatts we can bring to the grid most quickly. Augmentations of existing gas assets in our Texas market, totaling approximately 500 megawatts. These upgrades represent an effective and efficient use of capital to add capacity to the market, especially in the hours when it’s needed most. Completed nearly half of those upgrades in 2024, and we’ll finish the remainder in time for this summer. We also announced the expected conversion of our Toledo Creek coal plant to a gas fuel plant once it ceases coal operations in 2027, enabling it to operate beyond its previously announced retirement date. In addition, we adjusted the 2025 retirement date for Baldwin, extending operations to 2027, which will help reliability concerns in MISO.

We are developing contracted solar and battery projects in a number of competitive markets, moving to new gas build as we announced last May, are in the early stages of development for two natural gas peakers totaling up to 860 megawatts of capacity. While we continue to target a commercial operations day for these units in the middle of 2028, the ultimate decision on construction will depend on our view of the economics, including any market reforms being considered. Turning to slide six, our four key strategic priorities remain central to our strong operational and financial business performance. As highlighted on the previous slide, our integrated business model and comprehensive hedging program provide increased visibility into our long-term financial outlook.

From an operational perspective, our generation team achieved another year of strong commercial availability at approximately 95% for our gas and coal fleet. Our nuclear fleet also delivered a solid result with a capacity factor of 92%. We are excited about the work that’s already been done to form a nuclear fleet operating model, and we believe we have opportunities going forward with respect to our operations performance improvement efforts. Our team continues to deliver high commercial availability, particularly in hours when it’s needed most. The most recent example being the winter storms in February of this year, where the team achieved commercial availability of approximately 96% across the fleet nationwide. On the retail side, the team delivered an impressive result driven by strong customer account growth, in disciplined margin management, despite milder weather in most of our markets.

Switching to capital allocation, we remain disciplined in our approach to allocating shareholder capital through a strategy that balances return of capital and investment in growth. 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 $5.9 billion to our investors through open market share repurchases and common stock dividends. We expect to return at least $2 billion in total through share repurchases in 2025 and 2026, which includes the additional $1 billion share repurchase authorization announced last quarter. Also closed on the highly accretive acquisition of the 15% misprovision minority interest. That acquisition, which represents a significant investment in our nuclear and renewable generation assets, as well as our retail franchise, simplifies our business model and increases our proportion of zero-carbon revenue streams, all while balancing financial leverage.

Moving to the balance sheet, our financial position is ahead of expectations communicated during our third quarter call, with net debt at the end of 2024 below three times adjusted EBITDA. We expect further deleveraging through 2025 and 2026. With respect to zero-carbon growth projects, we continue to execute on our strategy of utilizing existing land and interconnects to opportunistically complete solar and energy storage projects. As part of the strategy, we completed and brought online two solar and energy storage facilities at our Baldwin and Coffeen sites in Illinois as part of our Illinois coal to solar and energy storage initiative in the fourth quarter. We have also begun construction at our sites in Oak Hill, Texas, in support of our contract with Amazon, and Pulaski, Illinois, for a contract with Microsoft.

Once online, these facilities will add over 600 megawatts of renewable capacity to our portfolio. Moving to our nuclear portfolio, we have engineering studies in process with initial estimates indicating the potential for upgrades across our nuclear fleet of approximately 10%. We expect to finalize these studies over the next year with target online dates in the early 2030s. Before I continue, I’d like to take a minute to address our Moss Landing site in California. As you know, one of our facilities on the site, the 300-megawatt phase one battery storage facility, experienced a fire. We are grateful there were no injuries, and the event was managed safely by our team and first responders. And we appreciate the support of the community. Other facilities located on-site, including the 100-megawatt phase two battery storage facility, 350-megawatt phase three battery storage facility, and the 1,020-megawatt combined cycle gas plant were not damaged by the incident.

The combined cycle plant has since restarted and resumed normal operations. The other two battery facilities will remain offline until we’ve had sufficient time to evaluate them in light of what is learned. We will continue to work with the community and state leaders on our path forward, including the remediation of the phase one facility, with safety remaining the team’s highest priority. Moving to slide seven, we continue to see real-time load growth at our primary markets. Similar to the 2024 summer peak load growth highlighted in our third quarter results, actual load growth, weather normalized in PJM and ERCOT, the 2024, 2025 winter peak, also exceeded historical rates. This included new records for winter peak load of 145 gigawatts in PJM, exceeding winter storm Elliott by approximately 9 gigawatts, and approximately 80 gigawatts in ERCOT, exceeding last year’s winter storm, Heather, by approximately 3 gigawatts.

Energy usage in these markets is growing even faster than peak demand, indicating likely future acceleration and peak load growth as these numbers converge. We continue to believe the level of growth across both markets confirms our view that load growth is already ramping, and the most recent updates to load forecasts from PJM and ERCOT reflect these accelerating growth trends. PJM and ERCOT have consistently revised long-term forecasts upwards, and that is certainly a bonus sign. We will keep an eye on the ramp rates as we go. Importantly, the source of this expected load growth remains diversified across industries, with power demand related to AI data centers being only one aspect of the growth in large load sources. The magnitude of expected load growth has raised the level of discussions with differing views on how to solve projected declines at system-wide reserve margins.

Over the last few months, there has been significant regulatory and legislative action related to market design in both PJM and ERCOT. Generation interconnect queues across the country remain heavily weighted towards renewable projects, which do not provide the same reliability benefits as dispatchable resources. While there have been some short-term actions taken by policymakers, long-term market structure questions remain. Recent developments with respect to the PJM capacity auction will provide some clarity, but continued delays and persistent regulatory uncertainty have made it difficult for generators to respond in a timely manner. FERC’s recent 206 order, which we believe indicates the collocated load in PJM will continue to be permitted, is a step in the right direction.

However, there are a number of questions to be answered, and clarity may not be provided until this summer. In Texas, policymakers remain concerned with grid reliability and the challenges of meeting the forecast for rapidly growing load. We appreciate policymakers’ concerns about grid reliability. It’s a message we have consistently reinforced for many years. However, the market reforms to incentivize new generation have been limited or shelved, which is leading to a heightened concern about new large loads. Recent legislative activity in Texas is raising some questions with both generators and large load customers, particularly data center customers. It is still early in the legislative process and is not yet clear whether customers will pause or change any of their siting decisions for data centers in ERCOT while the legislation is under consideration.

But we see workable pathways to a resolution. With the proper policy framework, our competitive markets can welcome the load growth and the economic development that accompanies it. We can build generation faster and at a lower cost than other areas of the country. The utilities build out the needed transmission. The team at Vistra Corp. will continue to work with policymakers and regulators on these key issues. This is a big opportunity for the areas of the country that find a way to do this well. It aligns with our national interest. In competitive markets, our view remains to let markets function by sending the proper supply and demand signals. Load growth by itself is a market signal that can incentivize generation. As we’ve discussed on previous calls, we expect load growth to come from many sources, including residential, onshoring and manufacturing, oil and gas electrification, as well as data centers, including those focused on AI.

Regardless of the demand source, we believe a new paradigm of load growth is already occurring, and we expect it to continue. With that, I will turn it over to Kris to provide more info on our outlook and our capital allocation. Kris,

Kris Moldovan: Thank you, Jim. Turning to slide nine. As a reminder, on our first quarter results call following the closing of the Energy Harbor acquisition, we initiated guidance for 2024 combined adjusted EBITDA with a range of $4.55 billion to $5.05 billion, including $700 million expected to be contributed from owning the Energy Harbor business for months. Despite the lower cleared prices and the mostly milder weather we’ve experienced throughout 2024, we delivered adjusted EBITDA excluding the nuclear production tax credit, of more than $300 million above the midpoint, more than $50 million above the top end of that range. Including the nuclear production tax credit, our adjusted EBITDA was more than $850 million above the midpoint and more than $600 million above the top end.

Notably, the ten-month contribution from Energy Harbor, including the nuclear PTC, exceeded our $700 million expectation by approximately $200 million. As you would expect, the adjusted EBITDA overperformance in 2024 adjusted free cash flow before growth of approximately $2.888 billion, implying a conversion ratio of approximately 57% from adjusted EBITDA. As we’ve stated previously, we didn’t expect the 2024 nuclear PTC to begin impacting cash until 2025 at the earliest. Looking forward, we continue to target a conversion rate of adjusted EBITDA to adjusted free cash flow before growth of at least 55% to 60%. Moving to slide ten. Despite the potential impact from the Moss Landing fire, including the uncertainty around the timing and treatment of insurance recoveries, which we expect to total up to $500 million, we are reaffirming our 2025 adjusted EBITDA guidance range of $5.5 billion to $6.1 billion, our adjusted free cash flow before growth range of $3 billion to $3.6 billion.

Looking forward to 2026, as Jim noted, we continue to have high confidence in an adjusted EBITDA midpoint opportunity of over $6 billion. As always, our guidance and long-term outlook remain supported by our comprehensive hedging program. Since our third quarter call, our 2026 hedge ratio has increased from 64% to 80%. Our commercial team continues to be opportunistic in taking advantage of periods of power price strings and volatility to protect our gross margin. Turning to slide eleven, we provide an update on the progress of our capital allocation plan. Our share repurchase program continues to generate significant value for our shareholders. Since beginning the program in November 2021, we have reduced our shares outstanding by approximately 30%, repurchasing approximately 160 million shares at an average price per share of approximately $30.46.

Notably, this reduction in our share count has led to an approximately 48% increase in our dividend per share since Q4 2021. Moving to the balance sheet. As of the end of 2024, our net leverage was below our stated long-term target of three times adjusted EBITDA, despite closing the acquisition of the 15% vest revision minority interest on the last day of the year and recognizing the remaining payment obligations as debt. Going forward, we expect to continue to manage the balance sheet in a conservative manner. Finally, we will remain disciplined in the deployment of capital towards further deleveraging, growth, and shareholder return. To that end, we expect to spend just over $700 million on solar and energy storage projects in 2025, including the previously announced solar projects supported by contracts with Amazon and Microsoft.

Based on our current pipeline of contracted projects, we expect a moderate step down in solar and energy storage development CapEx for 2026, but this could change as additional offtake agreements are executed. Of course, we will continue to pursue opportunities to fund a significant portion of our growth expenditures with third-party capital, including nonrecourse loans. Finally, we continue to expect to return at least $1.3 billion to our shareholders in each of 2025 and 2026 through dividends and share repurchases. Even after taking that into account, we continue to expect to have at least $1.5 billion of incremental capital available for allocation through the end of 2026, that we highlighted on our third quarter call. As a reminder, this amount is based on an assumed $6 billion of adjusted EBITDA in 2026, so we see potential for significant upside.

We are excited for the opportunities in the coming year, believe Vistra Corp. remains well-positioned to take advantage of the growing energy dynamics in our primary markets. We believe the significant amount of cash that we generate, combined with our disciplined capital allocation program, will continue to add substantial value for our shareholders. With that, operator, ready to open the line for questions.

Q&A Session

Operator: We will now begin the question and answer session. To ask a question, you may press star then one. If you’re using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star then two. At this time, we will pause momentarily to assemble our roster. The first question comes from Shar Pourreza with Guggenheim Partners. Please go ahead.

Shar Pourreza: Hey, guys. Good morning.

Jim Burke: Hey, Shar. Good morning.

Shar Pourreza: Morning, Jim. So obviously no surprise on the line of questioning here, but I guess what color can you provide on the timeline for a deal at this point? I mean, can you at least bookend it? Should we see something by midyear, year-end, 2026? I guess and then what’s the primary impediment on getting a deal done as the Texas legislature? Is it FERC and PJM, something else? Appreciate it. Thank you.

Jim Burke: Sure. Yeah. Thank you, Shar. I think we had a sense this question might be coming. I would say assuming this is an M&A and it’s about data center deals, because there’s multiple deals that we need to have all the time. But I will tell you that on the data center side, it’s important, I think, to elevate the dialogue from the simple nature that there’s just a contract to be signed. The flavor of the deal matters. So you can assume that we’re speaking to all the major hyperscalers and that we’re actively engaged with them, and the major data center developers. But they’re flavors of complexity. So the virtual PPA, which would be a front of the meter, those are relatively straightforward deals to execute. We have a number of discussions going on with those.

Those do not offer, we think, the same margin potential as the more complicated deals, which do involve colocation, it’s with existing assets or new assets. When you think about that, because it’s a new concept, there’s a lot of terms and conditions including the risk sharing. That goes into that partnership because you’re making a ten, fifteen, twenty-year commitment. And you see not many deals have been announced that have actually been colocation related. We think common deals offer a lot of benefits for not only the data center customer in our fleet, but the market overall the overall customer base because it not only provides speed to market for the customer, it can result in lower transmission build-out. That the grid absorbs today the customer may be willing to pay for that speed, pay for the reliability benefits.

But because it’s fairly complicated, it’s elevated to the discussion in all regulatory and policy-making circles. So FERC, of course, has been active on that, and we have seen some positive progress there. Texas has just recently filed legislation. Trying to sort out how do they think about front of the meter, and colocation deals? And customers are aware of that. So when we’re talking to these customers, they want to be viewed as constructive. They want clarity. On these rules. And so I think the timing of an announcement will also be dependent at some level on when we get clarity on how these deals can move through the process, both in PJM and in Texas. It wouldn’t prevent us from signing front of the meter virtual PPAs, but I think the deal that you’re speaking about and that folks want to see is where the marriage of the load and the generation asset is approximate.

Because that makes a lot of sense for a lot of reasons. And that complexity, I think, has raised, I think, the level of discussion at the federal and state level as well as our customers. But we are in this discussion every single day. We feel good about the direction of travel on it, but it’s still something that we’ve got to actually get over the finish line before you’d see us announce something.

Shar Pourreza: Got it. And it’s just fair to assume that Comanche Peak is probably the lowest hanging fruit versus Davis Besseil or Beaver Valley, etcetera? Is that in your discussions, is that where the focus is?

Jim Burke: I would say there’s interest in both markets for different reasons. I would say the Comanche Peak opportunity is probably right now considered the most attractive for a variety of reasons, but I think it’s also one that is from the standpoint of having the amount of land we have and the ability to bring that on pretty quickly, just the construction timelines in Texas, working with the wires companies to make sure that we’re set up we think is probably the fastest execution that we have across the portfolio.

Shar Pourreza: Perfect. And just lastly, just on a commercial question, obviously, this CDR was very bullish for power, but the moves in the forwards have been a little slower than what we may have expected. We just hit a winter peak demand last week. Can you just talk a little bit about what the commercial team is seeing in the outer years of the forwards and maybe just how that impacts your positioning? Thanks, guys. Appreciate it.

Jim Burke: Sure. And, Shar, that leads to also the question of if you were to sign a long-term deal at a power price, what do you think is a fair power price? But if you don’t think the forwards today reflect the load growth that everyone is worried about, then you got to be thoughtful about what’s the right price to be selling a ten, fifteen, twenty-year deal, especially if it’s a fixed price construct. We don’t think that the forwards, while they have moved up, in the last couple of months, and I’m speaking about ERCOT, they’ve actually turned a little bit on the outer years in PJM. So we’re not seeing exactly the same direction in those two markets. But speaking of ERCOT, since you referenced the CDR, we don’t think the kind of load growth that’s in the officer attestations or even if you haircut it by 50%, we don’t think that’s in the forwards fully.

And so we’re going to be thoughtful about signing up a valuable asset that’s producing power and selling on a routine basis at a level that’s producing very strong earnings like we just covered in 2024. And so our commercial team thinks that while we’re starting to see some of that response, we don’t think it’s fully in there. And that colors the discussions we have with customers. Because they also are trying to figure out what does the forward look like, what’s going to happen with the inflation reduction act, are the solar and batteries going to continue to come at the same level, and all of that affects the supply-demand signal that I talked about in my prepared remarks. So we’re bullish, of course, because our fleet is well-positioned.

But I think the signals that are there if you were just taking the forwards, we’d be a lot to just be signing that up on a ten, fifteen, twenty-year basis and be comfortable that we can tell our shareholders that that’s fair value.

Shar Pourreza: Got it. And I appreciate it. But, Jim, that’s actually very helpful, and I think it’s something that investors should think about as your views around power and contracting. So thank you so much on that. Appreciate it.

Jim Burke: Thank you, Shar.

Operator: The next question comes from Julien Dumoulin-Smith with Jefferies. Please go ahead.

Julien Dumoulin-Smith: Hey. Good morning, team. Thank you guys very much. I appreciate the time. Look, maybe just to follow-up on where Shar left it and some of the comments that you made. How do you think about the additionality? Right? And I mean that in a more complex sense of you know, is there a need immediately or over time? To add to existing sites? I mean, obviously, we see sort of the intent of SP6 in summer stacks. We see some of the commentary. How are you thinking about managing that both in the PJM and ERCOT narrative? And how does that figure into your planning? And then I gotta follow-up on the guidance here quickly.

Jim Burke: Yeah. Julien, thank you for the question. When you think about this twenty-four by seven load that is the profile that the data centers expect to have, and then you look at a grid like ERCOT, we’re only tight certain hours of the year. So the question, I think, that we’re trying to work through with policymakers is what problem are we trying to solve? And I think the problem that we’re trying to solve is that if this load continues to come on aggressive in ERCOT, with its current portfolio of resources, can it add a lot more load and not worry about any reliability impacts particularly to the residential customer base who has traditionally been part of any load shed protocol. In fact, even first, in the load shed protocol.

And I think that’s very fair. To elevate that concern. But since we’re talking about a few hours of the year, summer and winter and likely even more winter than summer, all of these data centers expect to be bringing one for one backup resources. That’s unlike any other customer class. So what we’re working through is on those limited hours of the year, can the backup resources with proper notification can those backup resources be utilized? And if they can, and we can get the clarity of that with the environmental rules, then we can solve a problem. In this in the super peak hours. And I don’t think it takes new combined cycles just to solve this problem. Okay? I think we’ve got a very active and diversified portfolio of resources we need to have flexibility to use that backup.

I think that is gaining some interest and I think that’s something that policymakers are open to. But I think we’ve also got to be clear that they have to have high reliability and fidelity of power. And so that leaves the notice process, and they’ve got to be prepared to shift to that. In some of the legislation that’s been proposed, it’s unclear if there’s going to be notice if there’s, for instance, a disconnect switch that somebody else can trigger. And so we need to work through some of those aspects. But I think the concept that there’s actually excess capacity most hours of the year on the grid. Our combined cycles run at 50% to 60% capacity factor. So the issue is not the average day. The issue is really about super peak hours, and that’s what we’re focused on.

Julien Dumoulin-Smith: Right. So you still think something could happen this year though, right after the summer for legislative session? And PJM resolution.

Jim Burke: I certainly hope so, Julien. I will tell you though, and tried to message this on previous calls, these customers have a lot of options. Everybody’s talking to them. They have markets all over the country. Obviously, they have international opportunities, but even in the US, I do expect that we’re going to get something done but I respect their ability to negotiate and work their option set, and they’re sophisticated. And so having just the land and the interconnects and the gas turbines and, look, we have two slots coming, you know, for turbines in 2026 and first quarter 2027. We’re as early in the queue on that, but when I look at it, they still have choices where they’re going to go, and we have value in those assets. And that needs to marry up. And so, yes, I do expect to make progress, and I think policymakers and legislative clarity here would help.

Julien Dumoulin-Smith: Got it. Excellent. Thank you again, guys.

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

David Arcaro: Hey. Thanks so much. Good morning.

Jim Burke: Hey, David. Good morning.

David Arcaro: Morning. I was wondering, are you able to discuss or give a rough range of kind of what pricing levels that you might be thinking or discussing out there with potential deal structures? We had some suggestions from a peer of yours yesterday wondering if you would give any color around how that compares to your own discussions.

Jim Burke: Yes. For a lot of reasons, I don’t think I’m comfortable talking about pricing in a competitively sensitive kind of category that we’re in. And, obviously, it matters on the value proposition. So I mentioned on the earlier response, a string sort of front of the meter virtual PPA, I’d expect to have a lower margin assumption because it’s a less differentiated product. You might get paid for some emissions attributes, like if it’s a carbon-free energy credit or of sorts, but you can capture some of that value. Colocation on an existing resource where you’re offering speed to market for a customer, if you can execute on that, I think you would potentially see the highest margin. The one that I think is unclear at the moment is if you pair new generation with a new customer, and they need to take a take or pay, especially if it’s not grid-connected, there could be a premium that the customer has to pay to make that whole model work but it may not be a margin.

It may just give you your required equity return and maybe not a lot of extra, but that took a lot of investment. You know, for you to bring that about. So the sweet spot as we see it is understanding what value proposition you have with your fleet and then figuring out is there a place where you can meet in the middle. With a customer for what you provide. And I think that’s what Vistra Corp. has that differentiates it from many others is that we’ve got a lot of operating assets with a lot of land. We can do a coo on existing sites but we can also go to sites that we have over fifty that don’t have power plant assets on them. We could build new there. We could partner with a customer. That isn’t typical what’s the what can you do to help us in 2027 with our needs?

Those packages look like 2029 and 2030. And they’re interesting. But they’re not as actionable to the customers that we’re speaking with.

David Arcaro: Okay. Got it. That makes sense. Then wondering if you could give an update on the prospects for potential gas plant colocation. You know, what’s the interest level in those assets from potential counterparties, how do you see the size of the opportunity within your fleet?

Jim Burke: David, you guys have heard a lot from me. I’m going to turn this over to Stacey Doré, who’s been leading this effort. You’ve heard from her before on previous calls. And I’d like for her to give you a sense of the variation of the models we’re talking about with gas plants so you have a sense of how we’re attacking it.

Stacey Doré: Thanks, Jim. Hi, David. I think we talked a little bit on the previous call about the fact that we are seeing interest in our existing gas sites primarily from the data center developers at this point. And I think there are a variety of ways to arrange those deals. Typically, you’re going to need a grid connection at a gas plant, so you’re going to have to go through the same regulatory approval process that you would even for a front of the meter interconnection. So that adds some complexity and time. You probably need to be able to add some, maybe, batteries and other backup gen to replicate the reliability that the customers need. And a lot of our gas sites don’t have quite as much land associated with them as, say, a nuclear site.

So you have the challenge of thinking about, you know, where the data center will be built. You know, having said that, we’re progressing a lot of those conversations on a handful of our sites in detail, you know, working on agreements to bring those projects to fruition. And in addition to that, we are in a number of conversations about building new gas for data centers as well with and without grid connections and in various markets. So we have a number of conversations going on that are at the papering stage. And as Jim referenced earlier, you know, those agreements can be complex but we are optimistic about our ability to bring those projects to a close.

David Arcaro: Okay. Great. Thanks so much for the color.

Operator: The next question comes from Michael Sullivan with Wolfe Research. Please go ahead.

Michael Sullivan: Hey. Good morning.

Jim Burke: Hey, Michael.

Michael Sullivan: Hey. Why don’t you just ask on, you know, the forward outlook and maybe why the decision to continue to mark off of November curves. And then when you talk about the certainty needed for a 2026 rate to give a formal range there, is it more so you need to see the auction results or just more clarity on the rules and parameters?

Jim Burke: Yep. Michael, I’ll start, and now it’s Kris to provide some input. But when we say six billion plus, and I think I’ve toned it in my remarks, we’re very confident about six billion and so there’s ranges around that. The issue that we have is that because we don’t have the auction clear and the parameters aren’t set yet and we’re not fully hedged, whatever next bump we give you or the market, I should say, they’re going to be asking for the range around that, and we really want to be in the process of giving the next year guidance. On the call that we have in the third quarter. And I think you can assume that the earnings power of the business looks much stronger than the six billion plus for 2026. And we don’t see that tailing off in 2027 and 2028.

So I’m going to ask Kris to provide his color on this, but I think Michael, it’s really more about what’s the right cadence for providing the updates not simply there are a couple variables moving around, but let’s…

Kris Moldovan: Yeah. I agree. I think it’s the cadence, and it’s also we continue there are some variables that we’re waiting on. You mentioned the capacity auction. We’re still even though we’re 80% hedged in 2026, that leaves approximately 45 terawatt hours of generation that’s open. And so, you know, I think as we continue to have and we get some more clarity on the auction parameters, you know, later this year, we’ll be in a position as Jim said, it’s once we start moving the number, then we get into ranges. And so we’re hesitant to do that at this time. As for the curves, I think you’ll see that historically as we reaffirmed guidance, we haven’t updated the know, we say that it’s still based on the curves because we’re reaffirming the guidance that we gave before.

But you can assume that we have considered changes in curves and all the factors that go into it when we go ahead and reaffirm, it’s typically I mean, this is obviously early in the year, and we don’t typically move guidance at this point. So we’ll wait until later in the year to adjust guidance. But I would read into the fact that we’re still basing it on November fourth curves where we’re certainly to get to the reaffirming stage thinking about all the puts and takes that have happened since we put out that guidance.

Michael Sullivan: Okay. Appreciate it. Look. All the color there. And then kinda related to that, but more on the policy side, two questions. I guess, what should we think about the likelihood of the cap four proposal passing for the capacity auction? And then in Texas, I mean, you talked about customers having choices and options and the like. Is there any particular provision in SB6 as it stands that you think would push them away from Texas?

Jim Burke: Yeah, Michael. Great question. On the first, I think we feel the cap and floor is likely to be approved. You know, we’ve seen, obviously, stakeholders weigh in. We’ve seen IMM comments. So I think that’s likely for the next two options. And I think that that brings some of the volatility around the marketplace, which has you’ve seen. We’ve had low clears for the last three auctions until this most recent one, and then that’s the only one that makes the news. You know, the load clears were not newsworthy, but they were having real impacts, you know, on bringing capacity and asset retirements. On Texas, yes. There are things in SB6 that are certainly helpful for the marketplace. The idea that we need to understand what’s really in the interconnect queue from a load standpoint and maybe raising the bar so that we get more clarity about the load forecast.

If it’s a really low bar and folks are worried that we’re going to see the grid double, you know, by 2030. It causes concern when the next deal gets announced for a data center because the view is that we need to solve all the way up to 150 gigawatts. We have not. That has not been our view. You’ve seen us for many quarters suggest that the load growth, while robust, is not a double-digit CAGR. On peak demand each year. We see it more in the 3% to 5% peak demand range. So bringing clarity to that and getting a load forecast, I think will help policymakers who are trying to figure out how big of a grid am I solving for? And frankly, the Talend Amazon deal what it really did because that data center could be fun of the meter. It’s still the same load as it would be if it’s sitting next to a new plant.

It just catalyzed the conversation on resource adequacy. It really wasn’t about colocation, and there’s always going to be a question about is there a transmission charge that should be paid or not. Setting that aside, the concern was do we have a resource adequacy issue? And that’s what a large colocation deal really brought to light. In Senate Bill 6, part of how they’re looking to solve that is to put requirements on customers larger than 75 megawatts to shed load during critical peak hours, which we agree with. And we think the customers that we’re talking to are preparing in their designs to be able to do that. I think when you get to something like a remote disconnect switch, that’s unusual and would only exist for these customers. And that’s something that gives them pause because they’re going to spend tens of billions of dollars.

And they need to know that they’re in control. Of those assets, and they’re more than willing to work as we are with the policymakers to give them comfort that with notice of what these weather events they do give you some notice. So all we really need to do is get to some adequate notice. And we can move forward. The final one is the transmission charges. We just need clarity on them. They just want to know, are they going to get something that’s commensurate with the transmission and grid utilization? There’s a revisiting potentially of the four coincident peak methodology. That probably does need revisiting. Because some company some customers are able to either reduce their load or turn on backup and minimize their transmission exposure, which means those costs go to other customers, including potentially residential customers.

And since we serve nearly five million customers, we’re sensitive. To that as well. So there’s a lot in that bill. You know, there’s a hearing going on today. About it. They’re going to get a lot of feedback. But I would say clarity is what we need, and then this disconnect, this remote disconnect I’d say, is one of the things that we hear from the customer side is very concerning is they’re not seeing that specific approach in other markets right now.

Michael Sullivan: Appreciate all the thoughts. Thank you.

Jim Burke: Thank you, Michael.

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

Angie Storozynski: Thank you. Thank you. So maybe first, I mean, just taking a step back. So it doesn’t sound like gas deals are waiting for any regular clarity. It’s just more about contractual arrangements. So, you know, why haven’t we heard of any gas deals? Is it that, you know, you mentioned in the past some sort of a portfolio deals. Are they associated with some of the nuclear deals that you’re working on, and that’s why we haven’t heard of those? Or is there some reluctance either by the off-takers or you to contract these gas plants, you know, at current terms or the terms that they are offering?

Stacey Doré: Right. Angie, hi. This is Stacey. Thanks for the question. I would say that the gas deals that we’re working on, the colocation deals with existing assets are waiting on regulatory clarity as well. I mean, the same uncertainty that is applying to behind the meter or collocated deals in PJM, for example, with the FERC proceedings would apply whether the asset is nuclear or gas. Because the question really that’s being asked is, you know, what is the transmission charge, if any, that has to be paid on those deals? So, PJM’s willingness to move forward with necessary study agreements, for example, applies whether it’s gas or nuclear. Similarly, in Texas, Texas with SB6, you know, all of the provisions in that bill that could affect collocated loans would apply whether the asset is gas or nuclear.

So I do think the same regulatory clarity that Jim referenced that we need and customers need to move forward on any colocation with existing, with new, if it’s grid-connected. All of that will be necessary for these deals to ultimately be understood well. And in terms of the portfolio approach, that I’ve mentioned on the last call, we are still in discussions with a number of parties, including some financial backers and capital providers. About those kinds of approaches. I would not say that those conversations are holding up particular deals because we also have discussions about specific sites that continue on in parallel. And so all of those conversations continue on a daily basis, you know, in detail with a lot of work being done in terms of on the customer side as well as our side understanding the physical attributes of those projects, the regulatory timeline, as well as the commercial terms.

Angie Storozynski: Okay. And then on the nuclear deals, so, you know, it was my understanding in the past that, you know, as long as at least directionally you understand how to structure these deals, you might proceed with them even before we have, you know, rules in place. You know, if only because, for example, there would be some time lag between any potential deal announced and when you would be asking, you know, FERC for any ISA amendments. Has that changed? Did this approach do we are we waiting both in Texas and at FERC for the final rules to be passed? Before any deals can be announced.

Stacey Doré: Yeah. Thanks, Angie. We are not waiting necessarily on full clarity from either FERC or Texas before we announce the deal. Having said that, you know, while all of these proceedings are going on in the background, it raises questions in the commercial discussions about things like who’s going to be, you know, taking the risk on a change of law. You always have change of law provisions in contracts that you have to negotiate. But when you’re in the middle of actual legal proceedings that are contemplating changes in law, it just heightens the discussion around those kinds of terms. In addition to that, you know, I think we’ve referenced before that we do have what we believe to be a final necessary study agreement at Beaver Valley, and we are continuing progress on that project.

Again, on the ground and with customers. But I believe that PJM does feel that they need some additional clarity from FERC to actually file an amended ISA. Having said that, that doesn’t prevent us from continuing to work both with PJM, the customers that we’re talking to about Beaver Valley, and then just with our own team on doing the development work that has to be done to directly connect a data center to Beaver Valley or Comanche Peak. So all of that work continues on. There is no pause. There is no, you know, waiting until we have an absolute answer. But having said that, the regulatory process does affect the discussions, and I think we’re both sides, both us and the customers are trying to work through that and figure out how we can contract around some of the unanswered questions.

Jim Burke: And, Angie, what I’d like to add, thank you, Stacey, is underpinning some of the reaction to the Amazon talent deal and even the filing of SB6 in the hearing is still a view that co-locating load with a plant is a concern for the grid. But having an equal amount of load sitting one mile down the road from the plant is not a concern. For the grid. And physics those are going to be the same supply-demand and reliability concerns either way, and we need to solve for the supply-demand in both cases. But I do believe that the customers are sensitive that they want to be viewed as I’m bringing economic development, I’m bringing jobs, I’m bringing capability that we think net multiple states want to be a leader in. So they want to be welcomed in that context.

The fastest speed to market or the colocation deals. But if you read the commentary and you read the concerns, there are views that that is somehow taking megawatts off the grid. But the same size data center one mile down the road is not taking megawatts off the grid. That fundamental difference of view drives a lot of the discussion, and it’s our job along with other stakeholders in the process to be as clear as we can be about what the supply-demand effects are. Load is load, and we need to have adequate supply. The colocation of that does not change that fundamental supply-demand balance, but I think it’s still an awareness that the customers have right now that we need to get that thought more clearly articulated in the way we inform policymakers and engage with them so that those kinds of deals are viewed as actually net beneficial because they will likely result in less aggregate transmission build-out just to put something in front of the meter.

And that could get uplifted to all customers. So there’s a discussion here about the pros and the cons, and both are going to be on the grid. We’ve said that multiple times. There’s going to be a lot that’s going to be done in front of the meter regardless, and there should be some. We think there should be a fair amount done through colocation because it’s efficient in effect.

Angie Storozynski: Okay. It’s just that I think we would have hoped that this discussion has already taken place given that it’s been almost exactly twelve months since this was kind of deal with the house. No. So and I understand that this is somewhat of a contentious topic, but still, you know, time is of the essence as you know.

Jim Burke: Yep. Real quick, Angie. We share your view. Hundred percent. And partly, our business model, as you know, is no matter what is getting built out on the grid, whether it’s front of the meter, and it’s done by the hyperscalers, the colo providers, oil and gas, our assets are positioned to see benefit from demand growth. In addition, we’d like to capture this value if we can capture it. If we for some reason, this gets delayed or it’s just difficult to capture, we’re going to capture a lot of value with our business the way it set up today because we are net long. Generation beyond our retail requirements. And so I think we’re set up well for that, but we agree with you. We thought we’d be further along as industry. In some of the fundamentals on this discussion, but we aren’t yet. We’re going to have to keep working it, Stacey.

Stacey Doré: Yeah. Angie, I would just add to that. I’m yeah. I thought it was interesting that in the FERC 206 order that came out last week, which is setting this colocation topic for us finally on a schedule, which we’re optimistic about and we think is a positive step forward, and we hope to have some clarity from FERC in the next five to six months on that. And I appreciate it. We appreciated the commissioner’s focus on urgency because to your point, you know, you would we would have hoped we would have figured out this conversation by now because at the end of the day, we’ve all said we this just has said, the customers have said, that we believe that, these collocation collocated loads should pay some cash aspect of grid charges for whatever services they’re using, but that can be different.

Based on the configuration of a particular project, and that needs to be taken into account. And I think FERC is finally setting up a process to consider that. They did recognize in the order this exact point that that Jim is making, and we’ve briefed to this point ourselves, which is that there is no resource adequacy difference between front of the meter load and behind the meter load. They both five hundred megabyte data center uses five hundred megawatts of power, whether it’s behind the meter or in front of the meter. So I think FERC recognized the argument that there is no resource adequacy difference as the same time, they pointed out that what they believe policymakers are concerned about is the timing of collocated load bringing the load faster than what is happening in front of the meter.

And that’s exactly why the customers are interested in it. So that’s the disconnect that we have to solve is the customers want to get online fast. They’re willing to pay for that. That in a behind the meter configuration. At the same time, policymakers are concerned about resource adequacy, and they, you know, are concerned that allowing this colocation will bring resources on load on faster than the utilities can get it on in front of the meter. And I think we all owe it to the customers and to economic development and to what’s best for the national interest figure that out and to make sure that we have the appropriate procedures to allow colocation. And the last thing I’d say is that, you know, first order first press release on the order was also positive in the sense that it pointed out that the purpose of that 206 proceeding is to decide how to appropriately allow colocation.

So that was definitive in our view that FERC knows and wants these colocation projects to move forward, and we just need to figure out what the rules of the road are.

Angie Storozynski: Good. Thank you.

Operator: The last question comes from Durgesh Chopra with Evercore ISI. Please go ahead.

Durgesh Chopra: Hey. Thanks for squeezing in there. First, quick clarification. I think, Kris, you mentioned the $500 million associated with Moss Landing. What is that exactly? Is that the insurance coverage? Is that the cash payments? What were you referring to there?

Kris Moldovan: Yeah. The $500 million, we have an insurance policy that covers the Moss Landing battery assets and it’s got a limit of $500 million and our expectation at this point is that we would receive up to that $500 million limit on that insurance policy.

Durgesh Chopra: Okay. Got it. Okay. One of the news outlets kind of was calling it as the cash payout from that. So I just want to clarify that. Okay. So that’s the insurance policy. Okay. Thanks. And just, Jim, just one thing I wanted to kind of get your thoughts on is assuming that we get clarity from Texas, from FERC, on colocation. It’s smooth sailing going forward. One of the things you mentioned is the disconnect between, you know, on the between how you’re seeing forward prices versus how your customers are seeing forward prices, and, obviously, you have been prudent just signing these long-term contracts. How do you get around that? So assuming just fast forward to second half, we have all the clarity in the world. But there’s still a disconnect between where forward ERCOT prices might be in 2028, 2029. What do you think of it to be? What’s your customers? How do you get around that?

Jim Burke: Sure. First of all, I don’t think there’s a single clearing price for these deals like there is sort of like a real-time price of power. So I think it gets to the site characteristics, the nature of that transaction with respect to, say, speed to market, and any other benefits as Stacey laid out, any risk sharing and things that we’re bringing to the table as part of the structure. So there are a lot of customers that we talk to. Some are in better shape during certain time periods of, like, the next five-year horizon. And so depending on different customers’ motivation, where in the country they want to be, the speed with which they want to get there, that’s why this is actually part a time-consuming exercise is it’s really all one-to-one.

Conversations that you have to have. There isn’t really an option for all of this to happen and clear. I do think it’s going to be a spectrum, and speed does matter. Not only the speed to actually bring these assets online, but in these conversations and getting to term sheets. We’re pretty conservative, Durgesh, and that’s my fault. But when things are real, they’re real, and they’ll be announced. And it’s just hard to see underneath the hood because you’re not here to see what we’re doing and the kinds of activity that’s actually happening on a daily basis and the engagement we’re having. And I know that’s frustrating for folks, but I’d like to think that what we have focused on for the, you know, for many years and will continue to do so as we call it putting points on the board, which is where you know you have something definitive.

And we could move forward and give our shareholders confidence. And that’s just not where we are yet on these deals, but we’re working hard to get there.

Durgesh Chopra: Thank you, Jim. I appreciate your commentary discussed it. Thanks.

Jim Burke: Thank you, Durgesh.

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: Thank you everyone for joining. You know, 2024 was a very strong year, and I really want to thank our teams for their continued execution and service to our customers and community. Some of that can get lost, as we talk about just what’s next in the horizon, but this was a really strong year, and folks deserve the congratulations for their execution and also signed up for a strong 2025 and beyond. And I expect we’re going to create value in a variety of ways as demand continues to accelerate. I know we’re going to see a lot of you on the road and we hope that we get to see you in person soon. Thank you for joining, and have a great day.

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