Q1 2025 Earnings Call Transcript

Good morning, everyone and welcome to Vistra's First Quarter 2025 Earnings Call. All participants will be in a listen-only mode. [Operator Instructions] At this time, I would like to turn the floor over to Eric Micek, VP of Investor Relations. Please go ahead.

Good morning, and thank you for joining Vistra's Investor Webcast discussing our first quarter 2025 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's 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. All references to adjusted EBITDA and adjusted free cash flow before growth throughout this presentation refer to ongoing operations, adjusted EBITDA and ongoing operations, adjusted free cash flow before growth. Reconciliations to the most directly comparable GAAP measures are provided in the earnings release and in the appendix to the Investor Presentation available in the Investor Relations section of Vistra's website.

Also today's discussion contains forward-looking statements which are based on assumptions we believe to be reasonable only as of today's date. Such forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those projected or implied. We assume no obligation to update our forward-looking statements. I encourage all listeners to review the Safe Harbor statements included on Slide 2 of the Investor Presentation on our website that explain the risks of forward-looking statements, the limitations of certain industry and market data included in the presentation and the use of non-GAAP financial measures.

I will now turn the call over to our President and CEO, Jim Burke.

Thank you, Eric. Good morning and thank you for joining us to discuss our first quarter 2025 operational and financial results. 2025 is off to a strong start for Vistra. We remain excited about the demand growth trends we are seeing across our markets, and we believe Vistra is poised to serve the growing needs of customers in numerous ways. While there has been a bit of turbulence the last few months in the macro environment, the administration is prioritizing AI and attempting to find ways to unlock America's leadership in this area.

The hyperscalers have continued to affirm or even increase their CapEx investment levels with respect to datacenter investments. We believe to meet this growing load, it will require increased power generation from not only new assets, but existing assets as well. While there are policy challenges to solve, we see a growing willingness on the part of all stakeholders to come together on solutions that will serve new large loads while minimizing impacts for existing customers. Vistra is very well-positioned to be a leader with respect to these solutions and to benefit from the tailwinds in our sector.

Beginning on Slide 5, the team worked diligently across the business to maintain last year's strong momentum into 2025. As you can see from our results, our team was able to deliver, achieving adjusted EBITDA of $1,240 million for the quarter. Consistent execution from generation, commercial, and retail was key to this success, highlighting the strength of our integrated business model and our one team approach. We continue to believe that a diversified portfolio of generation assets, including nuclear and gas, combined with a best-in-class retail business and a strong commercial set of capabilities, creates a superior and resilient business model for navigating volatile power markets.

We are reaffirming the guidance ranges for 2025 adjusted EBITDA of $5.5 billion to $6.1 billion and adjusted free cash flow before growth of $3 billion to $3.6 billion, both introduced on our third quarter 2024 call. Moving to 2026, while we have not updated our 2026 adjusted EBITDA midpoint opportunity, we remain confident in our ability to deliver significantly above the floor of $6 billion. Our confidence in our ability to deliver this outlook is primarily underpinned by our continued strong operational performance and our comprehensive hedging program, where we have successfully hedged approximately 95% of our expected generation over the 2025 to 2026 timeframe.

We continue to believe our comprehensive hedging program, which focuses on locking in value during periods of volatility, ensures a more stable and resilient earning stream across varying economic cycles. Turning to Slide 6, our four strategic priorities continue to be central to our long-term success while driving strong operational and financial performance. As highlighted earlier, our integrated business model and comprehensive hedging program deliver consistent results and enhance visibility into our earnings potential while providing a significant downside protection to our near-term outlook.

The excellent teamwork across our business is central to the successful execution of our strategy. Operationally, our generation team achieved another strong quarter of commercial availability at approximately 95%, enabling us to perform for our customers during multiple winter storms in both our PJM and ERCOT markets. On the retail side, we achieved another quarter of organic growth in the Texas market after a strong 2024, demonstrating the consistency and strength of our retail business. Switching to capital allocation, we maintain a disciplined approach of returning capital to shareholders, investing in select growth projects that achieve mid to high teens returns on capital, and maintaining a strong balance sheet with a long-term net leverage target of less than 3x.

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 $6.3 billion to our investors through share repurchases and common stock dividends. We grew our zero carbon business, including through the acquisition of Energy Harbor, and we achieved our long-term leverage target. As part of this program, we expect to return at least an incremental $2 billion in total through share repurchases and dividends through the remainder of 2025 and 2026. On the subject of growth, we have two equipment queue positions for our Permian 1 and Permian 2 peakers, and we have an attractive cost profile given the timing of when we placed these orders.

We believe these projects with build costs of approximately $1,000 per kilowatt are advantaged relative to current estimates for peakers of more than $1,500 per kilowatt. We will continue to evaluate the returns for these projects and assess market reforms, including legislative activity in Texas and elsewhere, as we determine our best path forward. With respect to the strategic energy transition, we continue to execute on our strategy of utilizing existing land and interconnects to opportunistically complete solar and energy storage projects. This quarter, we continue the construction on our Oak Hill, Texas and Pulaski, Illinois sites in support of our contracts with Amazon and Microsoft, respectively.

Once online, these facilities will add over 600 megawatts of renewable capacity to our portfolio. Our Oak Hill site is approximately 90% complete and on track for a fourth quarter 2025 commercial operations date. The Pulaski site is approximately 20% complete and on track for a fourth quarter, 2026 commercial operations date. We also began mobilizing for construction on our Newton battery and storage site in Illinois.

This site will add over 50 megawatts to the region with a planned commercial operations date in 2026. Importantly, cost structures for these projects remain insulated from recently announced tariffs. Moving to our nuclear portfolio, feasibility studies are underway for potential nuclear uprates. As we noted last quarter, initial estimates indicate the potential for uprates 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.

You can expect future updates from us as we evaluate these opportunities and prioritize projects. Moving to Slide 7, we continue to see electricity load growth as providing a structural tailwind for our sector. Similar to the summer and winter peak load growth highlighted in our fourth quarter results call, quarterly weather normalized load in the PJM and ERCOT markets continues to see accelerating growth trends. Our analysis suggests the sources of demand growth are durable and diversified across industries, with data center power demand being a key driver, but not the only one.

Importantly, electricity demand growth has historically proven to be fairly inelastic over varying economic cycles, and we don't see recent concerns around economic growth impacting the structural change in demand that we see in today's power markets. While this growth provides an exciting opportunity for Vistra to serve customers in new and varied ways, the wide range of projections has garnered the attention of policymakers across the country, not only in competitive markets, but in vertically integrated markets as well. We continue to believe the actual level of load growth will compound annually in a low to mid single digits range through 2030 across our markets.

This is consistent with what we shared last year on our Q1 results call, and now we see this dynamic playing out. While this is a strong level of growth compared to the past 20 years in most areas of the country, we believe this demand can be reliably and cost-effectively served. Because grids are built to serve the highest demand during so-called super peak hours, the electric grid remains underutilized for most hours in the year. ERCOT's a perfect example, where peak load has been approximately 85 gigawatts, but the average load is approximately 53 gigawatts.

We think this excess capacity during most days of the year provides a unique opportunity to meet a large portion of the pending load growth with existing capacity. In the 1% or less of the hours that are super peak hours, which typically occur in peak summer or winter weather, there are relatively straightforward solutions like demand response, use of onsite backup generation at the customer's location, and higher utilization of existing assets to meet these needs. It is our view this combination can allow for new load to come into our markets in an orderly fashion and be served cost effectively.

Over time, as the load continues to grow, there will be time for additional investment in generation and transmission to serve customer needs. Importantly, given the market backdrop and the load growth materializing in the near-term, existing dispatchable assets will be essential to delivering the resource adequacy grid operators and customers expect. We believe Vistra with its large and flexible fleet of generation assets, combined with own sites that can bring new generation is well-positioned for this environment. Our large CCGT fleet with nearly 20 gigawatts of total capacity, which currently operates at average utilization rates of approximately 55% to 60% can run at substantially higher capacity factors, improving grid utilization and lowering unit costs for customers.

Our approximately two gigawatts of simple cycle peakers have the quick start capabilities to ramp up as load materializes, further contributing to grid reliability. On development, the diversity of the Vistra generation portfolio allows for multiple types of capacity additions through both the expansion of existing assets and development of new projects. Upgrades at existing gas plants in ERCOT and the coal-to-gas conversion of our Coleto Creek plant represent near-term opportunities to add megawatts to the grid at attractive unit economics. Other opportunities like the previously mentioned Vistra Zero or nuclear upgrade projects represent longer term prospects for capacity additions.

Policymakers are also working on solutions to address the growing number of large loads that plan to connect to the grid. Importantly, whether these large loads connect directly onto the grid or co-locate with a power plant, the amount of power they consume and the net supply and demand balance are the same in either scenario. We will continue to work with policy makers and large load customers on solutions that meet all customer needs, including those of our residential and small commercial customers. We continue to advance our discussions with large load customers on various power solutions.

And we are optimistic about regulatory developments and our ability to serve these customers. With the Texas legislative session ending in early June and the PJM regulatory process related to the FERC co-location show cause order potentially concluding this summer, we are ready to navigate the evolving landscape and believe we are well-positioned for success. VISTA remains committed to supporting a reliable, affordable, and sustainable grid, and our integrated business is poised to serve customers with growing needs. Now I'll turn it over to Chris to provide more details on our first quarter results, outlook, and capital allocation.

Chris.

Thank you, Jim. Turning to Slide 9, Vistra delivered first quarter results in 2025 that were approximately 53% higher year-over-year compared to Q1 2024, achieving adjusted EBITDA of approximately $1,240 million, including $1,056 million from generation and $184 million from retail. The significant year-over-year increase was partially driven by the inclusion of two additional months of Energy Harbor's generation and retail results, given the transaction closed March 1st of last year. Generation also benefited from our comprehensive hedging program, which delivered averaged realized prices nearly $4 per megawatt hour higher compared to the same quarter last year.

A better weather backdrop in January and February also led to higher capacity factors across our PJM and ERCOT assets. Turning to retail, the business continues to realize benefits from strong customer counts, margins, and supply management as our consistent product development combined with strong brand recognition drove higher year-over-year customer additions in our key markets. Similar to generation, retail results were also bolstered by favorable weather in our Texas and Midwest Northeast markets compared to the first quarter last year, which was negatively impacted by the warmest winter on record.

As a reminder, due to higher hedge power costs in the winter and summer months, we expect the majority of adjusted EBITDA for retail to be realized in the second and fourth quarters. Depending on the shape of those power costs throughout any given year, the expected relative contribution from each quarter is subject to change. Notably, our expectation heading into the year for Q1 2025 was significantly higher than the first quarter results for retail in 2024. Moving to Slide 10, we are reaffirming our 2025 adjusted EBITDA guidance range of $.5 billion to $6.1 billion and our adjusted free cash flow before growth range of $3 billion to $3.6 billion.

We believe the reaffirmed outlook for 2025 demonstrates the earnings resiliency afforded by the diversified model especially in light of our outage at Martin Lake Unit 1 and our MOS landing batteries being offline. Turning to our outlook for 2026, as Jim mentioned, we continue to see our outlook develop positively. We are increasingly confident in an adjusted EBITDA midpoint opportunity outcome for 2026, approaching mid to high $6 billion and even possibly $7 billion. We expect to provide guidance for 2026 later in the year, likely on our third quarter call.

As always, our guidance and near-term outlook remain supported by our comprehensive hedging program. For 2025, our gross margin remains highly hedged, with approximately 100% of our expected generation already sold. For 2026, our hedge ratio increased from approximately 80% to approximately 90% as our commercial team took advantage of market opportunities. Finally, turning to Slide 11, we provide an update on the execution of our capital allocation plan.

Since beginning the program in November 2021, we have reduced our shares outstanding by approximately 30%, repurchasing approximately 163 million shares at an average price per share of just under $32. This reduction has notably led to a 49% increase in our dividend per share since the dividend paid in Q4 2021 to the dividend paid in Q1 2025. Regarding our balance sheet, Vistra's net leverage ratio currently sits just under 3x adjusted EBITDA in line with our long-term target of below 3x. In terms of future capital deployment, we will maintain a disciplined approach towards further deleveraging, investment for growth, and shareholder return.

We expect to invest just over $700 million on solar and energy storage projects in 2025, including the previously discussed solar projects supported by contracts with Amazon and Microsoft, along with our Newton site, which we began preparing for construction this quarter. Based on our current project pipeline, we anticipate a reduction in solar and energy storage development CapEx for 2026, subject to change with any new offtake agreements. As a reminder, we expect to fund a significant portion of our growth expenditures with third-party capital, including non-recourse loans. We continue to believe these projects are a great opportunity to leverage existing sites to increase the proportion of our contracted EBITDA at attractive returns while limiting the impact of our cash available for allocation.

Lastly, we believe Vistra continues to be well-positioned to create sustained long-term value. The resilience of our business is evident in our strong results and reaffirmed earnings outlook amidst increased market volatility. Our team is focused on our core mission of lighting up lives and powering a better way forward. We remain confident in our ability to be part of the solution to address our country's growing power demand in the coming years, and we look forward to the months and years ahead.

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

[Operator Instructions] And our first question today comes from Shar Pourreza from Guggenheim Partners. Please go ahead with your question.

Hey guys, good morning.

Hey, Shar, good morning.

Good morning, Jim. Jim, I couldn't get a sense on the preparations [ph]. Just on Comanche Peak, deal conversations, are you waiting specifically for co-locations at this point or could you be moving ahead with front of the meter and virtual PPAs in the interim? And the reason why I ask is one of your peers noted yesterday that FOM and BTM pricing is harmonizing in their customer conversations, which I think is counter to what Vistra has been messaging in the past.

So just a little bit of a sense there, thanks.

Sure. Well, Shar, I think what I've tried to mention on previous calls, and I know we've covered a lot of ground, really, for the past year's worth of calls, that no two deals really are going to look alike. I think the customer needs really dictate that. And for some areas of the country, the front of the meter may actually be as good of an opportunity set as co-location.

From our perspective, when we've looked at the deals that we're working on with many customers, they're still looking at co-location as a potential speed advantage. And again, that's going to depend on which part of the country and how clear are the rules. I think from our team's perspective, the activity level has not slowed down. We remain very engaged with a number of these opportunities and we're very pleased with the progress we're making.

There is still a desire for clarity because as we mentioned on previous calls, you have to contract through these deals, which are long-term deals, 10 to 20 years, and new contracts need to anticipate how rules and regulations are going to play out. So to the extent the rules and regulations can become clearer, it'll make the ease of contracting these, I think, a little bit more straightforward. As far as pricing, a lot of these customers look at alternatives around the country. So what is the next best alternative to either a front of the meter location or co-location with existing assets?

And that includes co-location potentially with even new assets, all of that creates a price spectrum. And I think we've talked about the fact that there is going to be a spectrum of prices out there. I don't think there's enough deals signed to say that one deal is going to equal another deal because there just really, frankly, haven't been that many deals announced. And so I think it's too early to say that front of the meter and behind the meter is harmonizing from our perspective, but I also think no two deals are going to look exactly the same.

And I don't think we should expect that. These are sophisticated customers. The markets all have different nuances in terms of their design and their ability to deliver for the customer. And I think our ability to price that is going to be our ability to work with that customer that we can meet their needs.

And so what I'm excited about is that the hyperscalers have either reaffirmed or increased their CapEx. So we're still talking about nearly $2 trillion between now and 2030 that the major four players intend to spend. And the administration is prioritizing AI. They're setting a tone that we've got to win the AI race.

So we've got to make co-location work. We've got to make front of the meter work. We need to be able to build new assets as well as utilize existing ones. And so that's how we're approaching it, sure.

Got it. That's actually very consistent in the past. And then, Jim, just lastly, I know this is not an easy question to answer, but just on general deal timeline at this point, does SB6 finalization, does that unlock a Comanche deal?

I think SB6, the end result of SB6 will unlock a lot of things. We don't know how SB6 is going to frankly turn out. I mean, there's a hearing today. It's the first time it's being picked up in the House.

And as we've covered in previous calls, Texas could attract a lot of load if we're able to lay out clear rules and regulations. And I think that could unlock a Comanche Peak deal, but I think it could unlock a lot of deals, including front of the meter deals. SB6 deals with both. And so we're active on SB6 as are our peers, as is the large customer coalition is very active on this.

So the session ends in early June. The goal obviously would be to get clarity around that time frame and I would expect that you will see some things announced shortly thereafter with the view that the deal parameters and the kinds of things that folks are trying to contract around would become more clear.

Got it. Perfect. Thanks again, Jim. Very helpful color. Appreciate it as always.

Thank you, Shar.

Our next question comes from Julian Dumoulin-Smith from Jefferies LLC. Please go ahead with your question.

Julian Dumoulin-Smith: Hey, good morning, team. Thank you guys very much. Appreciate the time. Guys, maybe just to follow-up a little bit here on what you guys are saying about '26 here and $7 billion. Can you guys comment briefly on '27? I mean, the curve has been moving around. Obviously, the opportunities that you guys are seeing also moving around, but -- any shall we say initial commentary that you guys would really be willing to provide?

Julian, it has been I think I use the word turbulent in the prepared remark. So it is moving around. I think the good news is that that turbulence has showed strength before some of the concerns around the economy, and that has bounced back. And so our team has been actively hedging, as you've heard the update that Chris gave.

And I think I mentioned on the last call, and Chris was giving a nod to this in his remarks, '26 is looking strong and we see '27 and even '28. We see that holding similar strength. We're not hedging, obviously, as far out as you would -- as you'd like to because the depth of the market isn't always there to be able to hedge as far out, but the earnings profile is strong. So even with some of the anticipated coal retirements that we have, we see the strength of our current asset base becoming more valuable. The curves are reflecting that.

And I think that the earnings power looks very consistent from our point of view.

Julian Dumoulin-Smith: Got it. So just to make sure I understand, you presumably had some degree out in '27 here incrementally, but given even with the open position, the mark-to-market looks somewhat similar to what you're seeing on the '26 as it stands today. And I'll only hold it to you today.

Thank you, Julian. I appreciate that, and the answer is yes.

Julian Dumoulin-Smith: Awesome. All right. Well, that's my two questions. Thank you guys very much. I appreciate it.

Our next question comes from Angie Storozynski from Seaport. Please go ahead with your question.

Thank you. I'm just going to make a comment at first. So when we listen to your prepared remarks, it's hard to tell that you have this upside potential, probably once in a generation, coming from AI. I mean, I know it might be just a different style of communications.

But again, it would be hard to guess that there is this upside potential ahead of you. And -- so, again, is it just because you're trying to manage our expectations? Is it that something has changed? Is it that you don't want to commit to a certain timeline?

Again, I'm at a loss why you don't sound a little bit more upbeat.

Well, Angie, I appreciate that. I would say we take the -- this responsibility of how we think about messaging to our shareholders and how the complexity of this marketplace is a reality. I also think these large scale customers, and we see it in the interconnect queues throughout the country, as we've communicated before, they have lots of opportunities. We think these interconnect queues, and I think all of our peers have described this at some level, they may be overstated anywhere from 3x to 5x what might actually materialize, either in regulated markets or competitive markets.

So I just respect the customer's ability to develop on multiple fronts around the country. It's our job to compete to win that deal. And that's exactly what we're wired to do. But we respect the fact that we have competitors and we respect the fact that even regulated markets are competing for this load.

I mean, competition benefits customers. And I fully respect that. I've spent 25 years in the competitive market side and I understand the ferocity of competition. So I have had a style here and it's been, I think consistent from a team perspective that when we have something that's ready to disclose, we will.

And I can assure you of that. And we're working extremely hard to have something to disclose. But until that happens, it's just not been my style to predict. Just given the fact that these customers are sophisticated, have choice, and until you're at the finish line, you're just not there yet.

So that's, I think, Angie, the color that I would provide.

Okay. So just taking it may be a step forward. For example, your '26 guidance, you're very heavily hedged. You have a capacity auction that comes with a pricing floor.

I mean, the math is relatively simple looking at your disclosures, and again, incorporating even the floor, and that would be well in excess of that $6 billion plus you're showing me -- I understand that Chris alluded to it could be even ahead of $7 billion and again you are as unlikely that '26 is going to be impacted by any of the potential AI-related deals and yet you're not updating the numbers?

Yes Angie, I think we covered this a little bit last quarter. I think from our perspective there are still some uncertainty So we're not ready to provide actual guidance. I mean you wouldn't expect us to provide guidance for next year and so when we're -- there -- those things again, we still have some open length. We still have the capacity auction to clear.

I mean there is a distance between the floor and the cap, and we still have some hedges to perfect. So we're not ready to provide guidance. We've tried to give as much color as we can. We just want to think it makes sense to get back on schedule where we provide guidance, any update for the current year, and then guidance for the next succeeding year, and then maybe in addition to that, a midpoint opportunity outlook for the following year after that.

We expect to do all that on the third quarter call. So we're just trying to get back on that schedule where we don't update guidance every quarter, or -- but we're still, as you said, in our remarks, we've leaned in pretty hard to say that we're significantly above $6 billion. We just haven't changed the number on the page. And I think you'll see us, again, return to that third quarter update, formal updates for guidance in multiple years.

Understood. Thank you.

Our next question comes from Jeremy Tonet from JPMorgan. Please go ahead with your question.

Hi. Good morning.

Hey, Jeremy. Good morning.

Just want to start off with, I think, kind of a two-pronged question, if I could. Just wondering, with PJM and the auction collar now approved, just how you think that sets up new build incentives, PJM, next few years here? And wanted to contrast this backdrop in PJM versus Texas and wondering if you could expand a bit more, I guess, on the Texas backdrop as you see it in data center proliferation there and the state desires to be a big player. Just wondering if you could give us your thoughts on the contrast there.

Sure. Look, the clear that occurred last July in PJM was a good clear relative to the three previous clears. And we talked about that, that that's a material increase in the capacity clear and it actually garnered attention of a number of policy makers. And again, a lot of that is relative to the prior clears that had occurred that were quite low and drove a lot of retirements in PJM.

One thing that I think is interesting is that one clear, I think, has actually provided some incentive for this reliability resource initiative, which garnered a lot of attention in PJM, where 27 gigawatts applied at about 9,000 megawatts or 9 gigawatts awarded. And that's really on the basis of, we have a one clear that was in the 270 range, and now we have a cap and a floor, which means the boom bust cycle of the auction is a little bit more stabilized. And I think that sends a good investment signal. You might recall over the last 10 years, 30 gigawatts of gas fire generation have been built in PJM through the capacity auction.

So I think, if anything, price signals matter. And price signals have shown in PJM that when they're appropriate, people bring investment. When they're too low, people retire assets. And I think that's normal.

I also think price signals matter on the energy side, not just the capacity side. And that price signal for energy can also encourage customers to conserve and effectively help the grid manage supply demand. So I think PJM with the cap in the floor for just the next two auctions is a good bridge to what we hope the quadrennial review and what I think could happen in the future is the continued signals that PJM wants to send to build new resources, knowing that there's still a lot of coal that's going to retire in PJM. In ERCOT, I would say there has not been the same level of commitment to sending the price signal for dispatchable resources.

There have been attempts for market reforms. Most of those have been put on hold. There's still a little bit of work to do on one of the key ancillaries, the DRRS ancillary, this Dispatchable Reliability Reserve Service. Those details aren't known yet, but I think from the standpoint of Texas is open for business, Texas wants people to invest, and what we've seen is that the batteries and the solar have been viewed as the better way to invest in generation in Texas.

The question I think will be going forward is if this data center load comes, it's our view that the first almost 8 to 10 gigawatts of that can actually be served with the existing capacity already in our cuts. I think that's one of the key things that policymakers are looking at is if we can bring the 10 gigawatts, is what -- is really what our estimate of ERCOT might add in data center load between now and 2030. If we can bring that and utilize existing resources, then all we need to worry about is the super peak hours. And there has been legislation in Texas offered to help customers use their backup generation in a way that would be helpful from a grid reliability perspective.

And I think that's a key. I think that is a key to an unlock. And the goal from a affordability standpoint for all of these grids across the country ought to be that if capital investments have already been made in generation and capital investments have already been made in transmission and distribution, as a society we should fully utilize those resources because that's the lowest cost way to serve all customer classes and not just focus on new build transmission, new build generation, because we have a lot of excess capacity on the grid as we see it. So we have talked about our peaker projects in Texas because we have a good queue position.

The economics don't quite pencil for the peakers yet. We're still going through the test process and it's too early to say how that will turn out. But I do think the peakers probably make a little bit more sense than the combined cycle build at today's investment signals. But obviously it's a competitive market so people can bring whatever resources they think makes sense.

But that's how I would describe the policy environment at this point, and I'll turn it over to Stacey to see if she's got anything she'd like to add on color for those two markets.

Stacey Doré: Yes, sure. Well, I think Jim captured the key points, and I agree that Texas is focused on figuring out how to be a leader in that data center effort and attract the load growth that can come with those customers. And I think what they're grappling with, as Jim referenced, is really how to solve the very few hours of the year that we may not have excess capacity. And I'm really pleased to see the efforts of the legislature to come up with bills that address that by giving, for example, customers that bring backup generation some assurance that they can run that backup generation during grid emergencies and not be subject to environmental enforcement. I'm pleased to see the efforts of the legislature on things like HB14 where they were trying to pleased to see the efforts of the legislature on things like HB14 where they were trying to give support for the development of new nuclear. So I think there are some good efforts underway to ensure that Texas can continue to be a leader in these areas. With respect to PJM, we're very pleased with efforts in some of our states like Ohio to recognize the value of dispatchable generation and to ensure that generators have the smoothest path possible to getting approval for new dispatchable generation and other types of projects that can bring megawatts to the grid. So I think we see a lot of efforts to recognize the value of reliability and dispatchable generation, and we continue to be highly engaged in those efforts.

Thank you, Stacey.

Got it. Thank you for all the details.

Our next question comes -- go ahead, Mr. Tonet.

Sorry, just one more question. Just wondering if -- when you're looking to sign new contracts for data centers, does that ever interfere with the ability to conduct buybacks? I was just wondering about the pace of buybacks amidst this volatility.

Yes, thanks, Jeremy. I would say that our buyback program is, it would not affect that. Our program is generally consistent. We expect to have a consistent bid in the market pursuant to a 10b5-1. And so we -- the main goal is to maintain a consistent daily bid in the market.

So we've been doing that pursuant to that 10b5-1 over time. And you can see that as you look back when we negotiated and announced the Energy Harbor deal or the purchase of the minority interest, we have never paused the share buyback program since we started it in 2021, and we don't expect to. So we keep it going through open -- closed windows and in periods where we might have material nonpublic information.

Very helpful. Thank you.

And now our next question comes from David Arcaro from Morgan Stanley. Please go ahead with your question.

Hey, thanks so much. Good morning.

Hey, David. Good morning.

Hey, Jim, I was wondering if you could maybe elaborate on your outlook for market prices, I guess, as you talk about better utilizing your existing fleet, demand response, maybe backup generation and using that for the market. What does that mean for the outlook for power prices?

Sure, David. It's one of the things that I think will help make sure the grid stays reliable is that these price signals, again, not just capacity but energy drive behavior, both on the supply side and the demand side. I think the key is that people recognize that signals do need to actually be sent and there's always a policy desire to have low prices. And that's important from an affordability standpoint, but it also you have to have signals every now and again to ensure reliability.

I think from our view, the forward curves still do not assume the level of build out from a data center standpoint that we think the CapEx budgets for the hyperscalers suggest. And I think that's just a reluctance, I think, to, one, put those kind of bids in there at that point because it takes time to materialize. I mean, we're a year past the announcement of the first large co-location deal and it hasn't made it all the way through the approval process at FERC. So things just take longer.

But if the CapEx budgets play out the way we see them playing out, you're going to see the demand side build in forecasts that I don't think are reflective, even when we say 3% to 5% of a compound growth rate in ERCOT, we don't see that in the forward curves. Let alone the projections that we've seen come from the ISOs in various markets. So I think demand response is important, but demand response should be coming in at the price signal that it should come in at, which is usually higher than where real-time prices have been settling for the last year to 2 years. So I view those two things as complimentary, David.

I think backup generation is still an expensive asset to use, but it should be used when the grid needs it, and that's usually in a higher price environment. That's how markets should work. And I think that is a well-functioning marketplace. And I think when you try to do it through mandates or alerts, I don't think you're going to get the same customer behavior because customers do respond to economic incentives.

And that's the beauty, I think, of competitive markets is it does send that signal. I just don't think those signals are out there fully yet in the forward curves. It is our view.

Yes, absolutely. Thank you for that. And then, separately, I was wondering, Jim, how much time are you spending in DC. recently, just given all the political gyrations going on? Are there -- what issues are you focused on most at the federal level?

I'm curious whether you might be kind of making efforts to differentiate the IPP space on issues where you might have a different view from say the traditional regulated utility on federal issues here?

Yes, well I do spend quite a bit of time in DC. I think the idea that this administration has been looking to sort of unleash the American Energy Dominance Council and look at how do we treat energy as a strategic resource. We have always talked about reliability, affordability, sustainability in that order, and that's how we've messaged for years. I think that's very consistent with the executive orders that have come out so far.

What we're trying to do is look at how do the executive orders potentially then manifest themselves and whatever rules or laws that would spawn from those that can affect markets. It's my belief that the best design ultimately for this is to have markets basically do resource allocation in most categories, including electricity. It's not our philosophy that any of us are going to guess exactly what the winning technology is going to be, what is the right level of investment. So I'm concerned that if people get approval to spend a lot of money, and for some reason it's more spent in infrastructure than is needed on a given timeframe, customers could bear that.

Competitive markets put that risk on shareholders. I think that's where that risk belongs. And so our message and that, the message of I think the competitive space is that, let us do the best we can to meet customer needs and put shareholder capital at risk. And that's a different model than where the regulated market design is today.

And I do think that we're going to need transmission and distribution to be built. But as I've mentioned in my prepared remarks, there's a lot of capacity on the existing system. And if we can find the best places to unlock where that excess capacity is, that's a winner for everybody. And price signals will help do that, whether that's congestion price signals, capacity price signals, or wholesale energy price signals.

So I'm spending a lot of time educating about the markets because this is a very fragmented industry, developed over a 100 years into a highly fragmented space that I think is hard to create a one size fits all policy. But since more than half the country's megawatt hours and wholesale are competitive, we have a huge playing field. And so I just want to make sure that we're able to tap that huge playing field and that if we do this right, I think the competitive market should get more than their fair share of this load growth opportunity. And I think Texas has a chance to get more than its fair share of this load growth opportunity coming from data centers.

Okay, great. Yes, thank you for all the color. Appreciate it.

Thank you, David.

Our next question comes from Steve Fleishman from Wolfe Research. Please go ahead with your question.

Yes. Hi. Good morning. For what it's worth, I think your under-promise, over-deliver way of doing things is the best anyway.

So, appreciate that. I guess just first on the data center kind of demand and maybe just to try to get a little better color on that, Jim, how would you characterize your views on that today versus maybe the year-end, call a couple months ago, because it seems like some better conviction and on-demand pricing tone, but just maybe characterize it relative to where your head was a couple months ago in the year-end call.

Yes, perfect, Steve. Thank you. I actually have increasing confidence over the last couple months and frankly even over the last year. I think what's happened is folks again shareholder capital is being used by these hyperscalers which they don't take lightly and they are spending it and they're recommitting and they're increasing their expected levels of investment.

That gives us increasing confidence that there's going to be opportunity and then it's just where does that opportunity manifest itself. To me it all starts with a customer and they are the targeted customer base that everybody is seeking to partner with. So in the last couple months, of course, even if you go back earlier in the year to DeepSeek, I mean, there's just been this whole level of uncertainty. And I think the commitment through it, which we've kind of been down and back up again as a sector, I think is highly encouraging.

Having said that, we are talking about nearly $2 trillion of CapEx from these top four companies, plus other capital others will spend. And they need to be good stewards of that capital. And I think the business model of AI is still proving itself out. I think that is, folks have conviction, but everyone is looking for the conviction around the revenue models and the ultimate sustainability of those CapEx levels.

But given the level of interest in the discussions we're having and the stage at which our discussions are, we see increasing confidence from the customer base out there. And so I do think, Steve, that it's in a better place than probably where we were just a couple months ago.

Yes. okay. And then two more -- two other questions. First, just on the -- given the range that you're talking about for 2026, Chris, just could you give us a sense of cash available beyond the kind of current buyback commitment? Just -- because you would think there'd be more room on your credit metrics at those kind -- at that kind of EBITDA level. Unallocated cash, yes.

Yes, Steve, as you say, the cash generation power of the business continues to support a lot of optionality. If you -- and we've said this, we've talked about this before. We'll stick with the lower projections, but even if you just look at our public, what's out there publicly, if you assume $5.8 billion of EBITDA in 2025 and $6 six billion, only $6 billion in 2026, and you apply the 55% to 60% conversion rate that we talk about, I mean, you can get there through all of our commitments to about a $1.5 billion of cash that we have not yet allocated to anything for '25 and '26. So as you increase that number from 2026, and you continue to put the 55% to 60% conversion ratio, you know, you can see that number getting into the $2 billion range of cash that we still have to allocate.

Okay. And then last question, just with the Trump administration executive order on coal, any kind of updated thoughts on your coal retirement plans could any of them. I know there's other rules and commitments related to those, but just could you give us any color on that?

Yes, Steve I think the most immediate impact that we see is the potential for some of the MATS, the Mercury Compliance to be pushed out a few years, which would really affect Martin Lake and Oak Grove, which are two large Texas sites that don't have retirement dates. As you know, the three sites in Illinois and the one in Ohio, those retirements are driven by other state and federal environmental rules, which are currently still in place. So unless there's a change there, the executive orders in and of themselves don't change that timeline. We are looking at some potentially being coal to gas conversions.

There's also a notion in the executive orders about they want to see some equivalent megawatt hour outputs if you do that conversion. So there is a lot going on there, Steve, and I think it's pretty dynamic. But certainly the emphasis on reliable resources sticking around longer is something that we have messaged for quite some time. But the framework needs to acknowledge there still are existing laws that we have to abide by, and we'll see how that develops.

Okay, thank you.

Our next question comes from Durgesh Chopra from Evercore ISI. Please go ahead with your question.

Hey team, good morning. Thanks for giving me time. Hey, just Jim -- hey, Jim. Thank you, thank you, sir.

Just your thoughts on Senate Bill 6, as it currently says, in the past, you've kind of talked about the load curtailment provision, you've highlighted that. Just trying to gauge that, if it passes in its current form, what does that mean for future data center deals? Is that a bottleneck? So just any thoughts or color you could share there, please.

Well, if it passes in its current form, I do think that the concerns that we've expressed before, we still share. I think the large customer coalitions, particularly data center coalitions, are expressing some concerns around things like the disconnect switch and again the control that they would like to have of their own assets. They're willing to participate in some of the demand response and the load shifting to manage a reliable grid. But I do think there are concerns that the customers have around some of these provisions.

From our perspective again co-location we think is an advantage to meeting customer needs and co-location is still getting a separate kind of focus in the version that the Senate passed. And our view is, is since the reliability situation is the same between a front of the meter and a co-located load, in fact, we don't have to build out the same level of transmission to serve it. It's actually a very efficient way to serve these large load customers and again, take advantage of assets already being paid for by customers on the grid. Having said that, if SB6 moves forward in its current form, folks are innovative, folks work through it, we'll be one of those companies working through it.

But as I said, I think Texas has a chance to get a disproportionate share of this large load. And these are huge economic development opportunities. So I think if Senate Bill 6 is considered in the House, and there's some revisions that we can work through in the House, I think it would set Texas up extremely well to win the AI race. But as I mentioned, the hearings today, it's too early to predict where that goes.

But I think our comments from previous calls still are relevant, but I think there's time to work through some of the potential changes.

Got it, Jim. Thank you. That's very clear. Then just really quickly, if I may, pivoting to PJM and FERC, just are you in settlement discussions currently with the T&D operators there in that region?

What does that say? And then as we think about Texas here, Senate Bill 6 getting resolved in June, what do you think is the timeline for getting some clarity there in the PJM area, in particular? Thank you.

We actually did not just -- it's just interesting, but we didn't file sort of seeking settlement discussions. We thought the record was ample at FERC and the back and forth between PJM and FERC set up well, we thought for a decision to be made. Now we're always willing and able to get into any settlement discussions. But this has been a long time coming.

And I think everyone's ready to move forward. And I think that's the most important thing. And I think we still expect that whether there's settlement discussions or not, we could see clarity coming in the next, I think, couple 3 months is possible. If the settlement discussions drag it out from there, I'd say kind of shame on all of us as an industry, because again, we have to meet customer needs and these customers are moving forward.

So we should be able to get there is our view. Senate Bill 6, as you know, would be wrapped up hopefully by the end of the session here in Texas in that first week of June. So I think over the course of this summer, I think we have a chance for both markets to potentially have more clarity than they have at the moment. And I'll turn it over to Stacey to see if there's anything she'd like to add.

Stacey Doré: Yes, the only thing I'd add on the FERC co-location docket is, as Jim said, we did not participate in the request for settlement discussions, but we did provide some very specific solutions to FERC that we think they could simply adopt on the record and move us forward. And that's what we're interested in, is speed of resolution. It's notable that the transmission owners, they filed and they did not file in support of settlement discussions either. They said they were open to them, as we all would be, if settlement discussions are ordered, but their position is that no changes are needed to the tariff. So I think FERC has a clear record before it of the parties' various positions, including PJM, and we would really urge FERC to make a decision on the very full and complete record before it.

And I'd just add, Durgesh, that FERC did acknowledge our filing, that co-location is specifically allowed in the PJM marketplace. We just need to work out the tariff issues. I think that was sort of lost in the process with the back and forth, but co-location is a viable model. We just have to get the details ironed out.

Yes, that was clear. They're clearly supportive of co-location. That's good. Stacey, is there a timeline when FERC needs to rule on this thing by? As it currently, I mean, there's so many deadlines. I'm sorry if I'm forgetting, but just what's the next milestone for the FERC to kind of take action here?

Stacey Doré: Yes, I think, Durgesh, that there -- FERC has a lot of flexibility in terms of when it rules, but I think what we would point to is FERC itself saying that it understands the need for urgency here and that it would hope to rule within a couple of months of completion of the filings. And so, if it does not go down the settlement path, then I think we could see a result, a ruling this summer. If it does order settlement, that probably does take an additional 60 to 90 days before FERC comes back in and makes a decision as a result of any settlement discussion. So again, that's why our preference is for FERC to rule on the record before it. But if they decide to order settlement discussions, we'll of course participate and try to reach the best solution that we can. But I think if they were to order settlement discussions, you'd see a result more like at the earliest late summer or maybe fall.

Thank you so much. Really appreciate the time.

Thank you, Durgesh.

And ladies and gentlemen, with that, we'll conclude today's question-and-answer session. I'd like to turn the floor back over to Jim Burke for closing remarks.

Yes, thanks, Jamie. I want to thank everybody for joining. As we covered, 2025 is off to a fast start, and I really want to thank our team for their continued execution and service to our customers and our communities. It's an exciting time for the industry and it's certainly for Vistra and we have a lot to do. We look forward to the next update. Thanks for joining and have a great day.

And ladies and gentlemen, with that we'll conclude today's conference call. We do thank you for attending. You may now disconnect your lines.