Vistra Corp. (NYSE:VST) Q1 2024 Earnings Call Transcript

Vistra Corp. (NYSE:VST) Q1 2024 Earnings Call Transcript May 8, 2024

Vistra Corp. misses on earnings expectations. Reported EPS is $0.268 EPS, expectations were $0.619. Vistra Corp. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good day and welcome to the Vistra First Quarter 2024 Earnings Call. All participants will be in listen-only mode. [Operator Instructions]. Please note this event is being recorded. I would now like to turn the conference over to Eric Micek, VP Investor Relations. Please go ahead.

Eric Micek: Good morning and thank you all for joining Vistra’s Investor Webcast discussing our first quarter 2024 results. Our discussion today is being broadcast live from the Investor Relations section of our website at www.vistracorp.com. There you can also find copies of today’s investor presentation and earnings release. Leading the call today are Jim Burke, Vistra’s President and Chief Executive Officer and Kris Moldovan, Vistra’s Executive Vice President and Chief Financial Officer. They are joined by other Vistra senior executives to address questions during the second part of today’s call as necessary. Our earnings release presentation and other matters discussed on the call today include references to certain non-GAAP financial measures.

Reconciliations to the most directly comparable GAAP measures are provided in the earnings release and in the appendix to the investor presentation available in the Investor Relations section of Vistra’s website. Also, today’s discussion contains forward-looking statements which are based on assumptions we believe to be reasonable only as of today’s date. Such forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those projected or implied. We assume no obligation to update 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 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’ll now turn the call over to our president and CEO Jim Burke.

Jim Burke: Thank you, Eric. I appreciate all of you taking the time to join our first quarter 2024 results call. This call is taking place in conjunction with a major milestone for Vistra, namely the first day of inclusion of our stock in the S&P 500. I want to recognize the hard work of our Vistra team and the support and patience exhibited by our shareholders as this is a result of both strong execution over time bolstered by improving market dynamics in the power sector. We are pleased to be included in the index and excited about the future prospects for Vistra and its stakeholders. Turning to slide five, before we cover the positive results for the quarter, it’s worth noting that we see a significant increase in Vistra’s long-term outlook.

Our team has been hard at work to ensure Vistra’s best position for the increasing power demand fundamentals, while providing reliable, affordable, and sustainable power to our customers. Continuing the theme of execution, our integration teams were hard at work during this quarter. With the closing of our acquisition of Energy Harbor on March 1st, we were ready on day one to unify under the Vistra name and welcome our new colleagues. The core theme throughout the integration process has been one team, and we believe that is crucial to a sustainable, high performance organization. The sites are working closely with each other to share best practices and create a culture of continuous improvement. As a result, the teams identified the potential for several operational and performance improvements throughout the nuclear fleet.

As Kris will cover later, including the expected financial benefits of these improvements and the additional synergies we’ve identified, we now expect the run rate adjusted EBITDA contribution from Energy Harbor to exceed $1.1 billion beginning in 2026. Turning to the other key priorities, we continue to execute on our capital return plan put in place during the fourth quarter of 2021. Since that time, we’ve returned to our investors approximately $4.6 billion, including $3.9 billion of share repurchases through May 3rd of this year. We continue to view our shares as an attractive investment and expect to execute at least $2.25 billion of share repurchases throughout ’24 and ’25. Crucially, our balance sheet remains strong, enabling the ongoing capital return plan.

Our net leverage finished the quarter at approximately three times, exceeding our expectations indicated on the previous quarter results call. We expect net leverage to be below three times by year end 2024. Our discipline capital approach also enables us to invest in solar and energy storage growth that capitalizes on sites interconnects in the Vistra portfolio. Our Baldwin and Coffeen sites, where construction began earlier this year on paired solar and energy storage facilities are good examples of this strategy, and we expect these to be online by the end of the year. Finally, we’ve completed our first non-recourse financing at Vistra Zero, providing attractive capital for a growing portfolio of operating renewable assets. Moving to slide six, we achieved ongoing operations adjusted to about $813 million, a 47% increase compared to the first quarter of 2023.

As you can see, many of the themes contributing to results last year continued into the first quarter of this year. The first quarter of 2024 again reflected the benefits of our comprehensive hedging program as the warmest winter on record in the U.S. led to lower than expected cleared power prices across the country. Specifically, while power prices in the markets we serve cleared below $30 per megawatt hour on average for the first quarter, our first quarter results reflect an average realized power price of over $50 per megawatt hour. In these volatile weather environments, which included a winter event in mid-January and then mild weather in February and March, our generation team once again delivered with another strong quarter of commercial availability at approximately 98%.

Being flexible with not only daily operations, including ramping down when economics signal us to do so, but rescheduling planned outages to optimize opportunities enabled the business to deliver strong results. Finally, the retail team delivered another positive quarter of customer count growth across our Texas and Midwest and Northeast geographies. With the acquisition of Energy Harbor now complete, we’re initiating a guidance on a combined basis for ongoing operations adjusted EBITDA of $4.550,000,000 to $5,050,000,000 and ongoing operations adjusted free cash flow before growth of $2,200,000,000 to $2,700,000,000. It’s important to note that this guidance excludes any potential benefit from the Nuclear Production Tax Credit or PTC. Given the uncertainty around how it will be implemented when the regulations are issued later this year.

However, based on where prices settled in the first quarter and the forward curve for the balance of the year, we believe the PTC could add a significant amount to our 2024 ongoing operations adjusted EBITDA guidance range. Finally, you will note that the implied conversion rate from ongoing operations adjusted EBITDA to ongoing operations adjusted free cash flow before growth for 2024 is below our stated target of 55% to 60%. Primarily due to a couple of timing impacts, we expect to return to our target 55% to 60% range in 2025 and beyond. While we are not providing guidance to reflect specific ranges for Vistra vision and Vistra tradition, our view is that each is expected to contribute roughly half of our adjusted EBITDA over time. However, given the business mix and current capital structure, you can expect Vistra vision will convert adjusted EBITDA to free cash flow before growth at a higher rate over time, roughly 60% to 65%, compared to Vistra tradition, which we expect to convert at a rate of approximately 50% to 55%.

Turning to slide seven, there has been much discussion in recent months about the substantial power demand growth forecasts, including from the potential build out of data centers and other sources of electricity demand. Third party research indicates data center related activity could approach 35 gigawatt of additional demand by 2030. However, our teams also see multiple additional potential drivers of demand in the geographies we serve. These drivers include continued reshoring of industrial activity, as evidenced by multiple large chip manufacturing site build outs, partially due to the CHIPS Act, increased electrification of commercial industrial and residential load across the country, as evidenced by the expectation of approximately 20 gigawatts of additional power demand in West Texas by 2030, and strong population growth, particularly in the state of Texas, which has been steady at 1.5% to 2% per year.

With these drivers, we see the potential demand outcome skewing higher, albeit with a wider range. In their most recent report, PJM’s load growth expectations through 2030 doubled from their 2023 estimate. In Texas, recent reports from ERCOT suggest load growth through 2030 in a wide range, from as low as 1.6% per year to as high as 6% growth per year, or even higher, if more than half of the large loads recently discussed at ERCOT actually materialize. The trailing 10 years has been approximately 2.5%, and that was before some of these more recent drivers of the Permian electrification, the CHIPS Act, and the data center demand. This increase in demand across the country will need to be served by an electric grid that will continue to see coal plant retirements in all markets.

The Inflation Reduction Act will continue to incentivize wind, solar, and battery resources, and we will also need gas fire generation to back up those intermittent sources. The new greenhouse gas rules issued from the EPA on April 25th are expected to make it more challenging to economically build baseload combined cycle gas turbine facilities. But we expect those rules to be litigated, and it’s unclear what the final outcome will be. Natural gas peakers could be a solution that threads the needle of environmental rules and demand needs. In addition, it is likely that existing assets will need to run at higher capacity factors to meet overall annual energy needs as more coal retires. We see Vistra’s well positioned for these trends given our diversified portfolio of reliable and sustainable assets in growing markets.

As you can see on slide eight, the forward curves have moved up considerably in both the Texas and PJM markets on the improved demand outlook, particularly on the longer end of the curve. As an example, ERCOT North around the clock fixed price forwards for calendar 2026 increased over $7 per megawatt hour or approximately 13% since we last provided guidance in November 2023. For 2027 and 2028, the increases were even more significant. In the past, we’ve commented that the backwardation and forward curves did not reflect the tighter grid conditions that we expected to result from continued load growth and planned thermal asset retirements. With the recent improvement of both forward power prices and some additional market interest in transacting farther out on the curve, we believe the market is beginning to recognize these dynamics.

As I stated at the beginning of the call, our integrated business model which combines increasingly critical dispatchable generation assets with a premier retail business positions us well to create long-term value in this dynamic and growing market. As a result, based on recent market curves, we are currently estimating a combined ongoing operations adjusted EBITDA midpoint opportunity for 2025 of $5 billion to $5.5 billion. In addition, while significant uncertainty to both the upside and downside remains for 2026, given our 2026 hedge percentage, which is approximately 50%, we have line of sight to an ongoing operations adjusted EBITDA midpoint opportunity of more than $6 billion. Like the 2024 guidance, our long-term outlook excludes any potential benefit from the Nuclear PTC and we will continue to evaluate the appropriate timing for including any of that potential benefit.

Even without the inclusion of any PTC benefit, the improvement in near-term and long-term outlook for Vistra is expected to result in a meaningful amount of unallocated capital through 2026. And with that, I will turn it over to Kris to provide a detailed review of our first quarter results. Kris?

Kristopher Moldovan: Thank you, Jim. Turning to slide 10, Vistra delivered strong first quarter results in 2024 with ongoing operations adjusted EBITDA of approximately $813 million, including $841 million from generation offset by negative $28 million from retail. This represents a $259 million improvement, nearly 50% year-over-year. For generation, despite another winter on record, our comprehensive hedging program combined with the team’s ability to optimize our flexible assets enabled another quarter of strong results. Turning to retail, as was the case in 2023, the first quarter result was within the range of what we expected. We continue to see higher hedge power costs in the winter and summer months due to entry year shaping and therefore anticipate substantially all of ongoing operations adjusted EBITDA for retail to be achieved in the second and fourth quarters.

We believe continued strong counts and margins in the first quarter position retail well for the balance of the year. Finally, our first quarter results benefited from the inclusion of one month of Energy Harbor, which totaled a month of Energy Harbor, which totaled approximately $60 million for generation and retail combined. On Energy Harbor, we provide an update on the integration process on slide 11. As Jim mentioned earlier, the team’s made significant progress integrating the businesses despite a later than expected closing. In the short time since completing the acquisition, the team has identified approximately $150 million of timing and gross margin benefits that are expected to be realized in 2024. These benefits are expected to bring the in-year 2024 contribution from Energy Harbor to approximately $700 million, which compares favorably to our 10-month contribution estimate.

Turning to integration benefits, we previously communicated expected run rates synergies of $79 million by year-in 2024 and a run rate of $125 million by year-in 2025. Based on the efforts of the teams completed to-date, we are increasing the amount of expected run rate synergies by $25 million to a total of $150 million. Further, when we first announced the acquisition of Energy Harbor, we highlighted our core competency of integrating generation assets, citing the achievements of our Operational Performance Improvement, or OPI, program following the Dynegy acquisition. I am pleased to report that this program continues to deliver, with the teams having identified opportunities for more efficient operations across our nuclear fleet that we expect to lead to $50 million of run rate adjusted EBITDA improvements by year-in 2026.

Importantly, we expect these additional opportunities to be achieved with little incremental capital spend. Finally, we provide an update on the execution of our capital allocation plan on slide 12. As of May 3rd, we executed approximately $3.9 billion of share repurchases, leading to an approximately 28% reduction compared to the number of shares that were outstanding in November 2021. In line with our statements on the fourth quarter 2023 call, we expect to execute at least $2.25 billion of share repurchases over the course of 2024 and 2025. With the long-term update provided today, we still see our shares trading at an elevated free cash flow yield, and thus continue to believe share repurchases to be a sound use of our capital. Moving to our dividend program, we announced last week at first quarter of 2024 common stock dividend of $0.2175 per share, which represents an increase of approximately 7% over the dividend paid in Q2 2023, and an impressive 45% increase over the dividend paid in the fourth quarter of 2021 when our capital allocation plan was first established.

Turning to the balance sheet, this was not leverage ratio currently sits at three times. As Jim stated earlier, we expect to return to below three times by the end of 2024 and continue to target a long-term net leverage ratio below three times. As you may have seen, we successfully issued $1.5 billion of seniors secured and unsecured notes at the beginning of April. These notes were issued primarily to fund our 2024 maturities and are not expected to increase our overall leverage levels. We were very pleased with the transaction and view the tight issuance spreads as recognized by bondholders of Vistra’s well-positioned business model and favorable outlook. Finally, the first quarter of the year was an active period for Vistra Zero. Our team began construction activities at two of our larger Illinois solar and energy storage developments at our former coal plant sites this spring.

Notably, despite the current inflationary environment, we continue to expect these projects to comfortably exceed our targeted return thresholds. Importantly, we took the initial step in developing the long-term capital structure of the Vistra Zero Renewables business, closing on a non-recourse financing at Vistra Zero. The $700 million term loan, which was also well received, is the first step towards our goal to fund our solar and energy storage growth with a combination of free cash flow from operating renewable projects and non-recourse financings. Finally, in connection with the closing of the Energy Harbor acquisition, we have begun paying dividends to the minority investors in Vistra Vision. Our current expectation is that we will pay approximately $100 million in 2024.

We view these dividends as part of our capital allocation program as we continue to analyze Vistra’s earnings power on a consolidated basis. We are very proud of the Vistra team’s performance to begin the year, and we remain committed to executing against our four strategic priorities. We look forward to updating you on our progress on our second quarter call. With that operator, we’re ready to open the line for questions.

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Q&A Session

Operator: Thank you. We will now begin the question and answer session. [Operator Instructions] 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: Good morning. Jim, that does sound like you’ve broken record here, but obviously the moves we’ve seen in Spark, thoughts around maybe traditions, standalone viability, and potentially separating the two companies sooner rather than later or kind of vice versa. And maybe at the very least, should we expect more details around resegmentation with a roll forward later this year as the moves in the curves can obviously change kind of that top level disclosure you just provided between the two segments or it’s just not a priority? Thanks.

Jim Burke: Sure. Thank you, Shar. Yes, as you’ve noted, the spark have obviously increased fixed price power has also increased. This discussion about the value of tradition, which I think has come into focus a lot in the last two months, has been really positive for Vistra overall. As you know, the Vistra tradition business is a key part of how we integrate our model overall. So we have a very large retail business that we have in Vistra Vision and a lot of that business is residential. Residential has a level of usage that can vary with weather and that’s something that the asset side and Vistra tradition supports extremely well. On the Vision side, we of course have a large nuclear fleet and our storage and solar, but that will not help us with the intraday and some of the weather swings that we would see in the seasons.

And so, Shar, I think what we were hoping to happen is happening, which is the Vistra Tradition side is being recognized for being highly valuable. I think there was months ago, obviously already of you, that the assets in Vistra Vision were valuable. There was a question mark about the tradition side. I think that’s being addressed by the tightening you’re seeing in the marketplace. And frankly the inbound that we receive are folks interested in assets in tradition, because these are hard assets to replicate. And I would suggest with some of the EPA rules that have been issued, they’re going to be even harder to replicate. So we think the integrated model has a lot of value as far as disclosures. We try and obviously in our script today, we shared some information about the free cash flow conversion of Vision and Tradition and the relative EBITDA weights.

So our goal here was to provide some insights into how the financials work on the integrated model, but I don’t think at this point it’s a priority for us to do a GAAP reporting associated with that. I think our goal is to provide our investors the key insights that drive the economics which, as you know, have a lot more to do with the forwards and our ability to capture it than some of the traditional segmentation methods. So that’s a little bit, I think, of color. Shar, how are we thinking about it.

Shar Pourreza: Got it. That’s perfect. And then, Jim, just on the market dynamics, I mean a big investor debate right now over a new entry in ERCOT and whether it’ll even make a dent in demand through the end of the decade. I guess what’s your house view on gas, new builds and scarcity at this point? Are we kind of setting up for another early 2000s rush of turbines?

Jim Burke: Great question, Shar. I think, so first of all, I think the queue of gas is starting to build a little bit. The application process will officially open for the Texas loan program in June. I think it’s different than the early 2000s in a couple of ways. Number one, while spark have improved over the — even the last two months. And in ERCOT, we no longer have the severe backwardation that we are accustomed to seeing. So that’s a bullish sign. The loan program would be a bullish sign. However, the EPA rules, the proposed rule and the final rule that was issued last week will make it very difficult for somebody to be comfortable with a combined cycle gas turbine technology, which was different than the early 2000s. That base load technology, if it were to run over 40% capacity factor, would need to have the carbon capture capability installed by 2032.

We do not see an operating combined cycle with carbon capture technology anywhere in the world that we can point to. So I think the emphasis ultimately will be on peakers. The peakers are a higher heat rate machine. They’re going to run and would need to run less than 40% capacity factor. And I think with the build out of renewables, the solar, the wind, and even the shorter duration batteries, peakers make sense from a build out standpoint. But I don’t think they’re going to be the 60 plus percent capacity factor assets that you saw coming in the early 2000s. As far as is it an oversupply, I think we’re in a chicken and an egg situation with ERCOT. I think the demand is there and the demand is going to be waiting for the supply. And so I don’t think it’s a situation where we’re dealing with static demand and which asset can best serve it.

I think it’s going to be an ever-increasing demand that will continue to come as long as assets are coming onto the grid. And I believe Texas, which has positioned itself as open for business, wants to be a leader in this economic development opportunity. And I think that’s true for transmission. I think it’s true for renewables. I think it’s true for dispatchable assets like gas peakers. So I think the fundamentals are really different than what we saw a couple decades ago.

Shar Pourreza: Perfect. Thank you. And then just one really quick one for Kris. Kris, just on the ’26 midpoint opportunity, how much incremental EBITDA would there be if you were fully open in ’26? I guess how sensitive are you to that number? Thanks.

Kristopher Moldovan: Yes. On the sensitivity, what I’ll say is we feel good about the $6 billion number. We have a high confidence in that number given where the curves are and where our hedge percentage is. As we look to sensitivities, we haven’t given that. But as we think about it versus what you’ll see in our deck on 2025, it’s roughly twice, I would say, as sensitive to moves and power and spark as what we’re showing for 2025. So we do feel confident in that $6 billion number.

Shar Pourreza: Perfect. Thank you guys so much, Jim. Fantastic execution today. Thank you. Bye.

Jim Burke: Thank you Shar.

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

Durgesh Chopra: Good morning, team. Congrats on the solid print.

Jim Burke: Thank you.

Durgesh Chopra: Thanks, Jim. Hey, just maybe can I ask you on the free cash flow conversion? So it looks like the ’24 guidance is about 50% of EBITDA, and then you gave us the numbers for Vistra Vision and then Tradition. Just how do you see that trending? The answer to that is higher. But what are the drivers that get you from 50% on the Vision side of the things to 60%? Is that integration, more efficiencies? Maybe just talk to that, please.

Jim Burke: Yes, that’s a good question. As you would expect, we put a lot of emphasis internally on the free cash flow conversion rate. And as Jim said in our prepared remarks, we target 55% to 60%, and we’re a little bit lower than that based on two timing issues, I would say this year. One of those is that, on slide 11, you’ll see that energy harbor increased $150 million. One of that is $100 million of that $150 million is really is due to a change in accounting methodology for outage expense recognition. So that’s a non-cash item that is increasing EBITDA but not turning into cash. So that is hurting free cash flow conversion. And then, the other one is that as you would expect, the retail team enters into contracts for future periods, we generally, as the prices have increased, we generally see the hedge of that.

We do that hedging through a variety of structures. And if that price has risen in the outer years, the cost of those products has increased. So that does create a timing mismatch between when we pay the cash premiums on those options, and when we recognize the revenue in future years. So we would expect that to reverse as we go forward. So if you just reverse those two timing impacts, our free cash flow conversion this year would be closer to 55%. And then we just see some other improvements that get us closer to the 60% starting next year and moving forward.

Kristopher Moldovan: And to what I would add to this comment is as you see the curves rise, some of that does not necessarily require additional capital and expense to achieve the higher earnings and free cash flow. So, as you see the projections improve, you would expect to see some of the free cash flow conversion improved by the nature of the gross margin expansion and more of that dropping to the bottom line. So that is part of the trend that we’re describing when we gave you the outlook for the free cash flow conversion.

Durgesh Chopra: I appreciate all that color, very helpful. And then just Jim and Kris, there’s a lot of debate around how long are you going to do these share buybacks? I appreciate there’s not a clear cut answer. But can you give us some parameters? What metrics are you looking at? Is a free cash flow yield? Is it EBITDA? What is the comp group you’re comparing it to? Is it IPPs or the broader market as we think about your decision making on those share buybacks going forward?

Jim Burke: I’ll start as a more of a free cash flow yield comparison. And how does that compare to the next best use of capital? When we started this process, of course, years ago, we were talking about free cash flow yields north of 20% for the business. It was a very obvious choice, I think, as to how we would deploy capital recognizing where our relative value was in the marketplace. As we’ve continued to see our share price move, which is a good thing, we’ve also seen the forward curves move and the earnings power of the business move. And so, we still certainly see upside from where we sit today from a share value. But you’ll see the free cash flow yields have certainly come down still well above some peers in the market.

But we also have other competitive projects now with those free cash flow yields. The ability to do our Vistra Zero projects in the mid-teens type of free cash flow type returns that gives us some confidence there. We’ve got some organic opportunities, including some gas plants that we think are competitive. There may be inorganic opportunities like M&A on both retail and generation. Those are all more competitive today where we’re currently trading. And the good news is, is I think we could do multiple of those, not an either or. So I still believe where we sit today with a free cash flow yield, the returning capital through our buybacks, as we’ve discussed, through 2025, the two and a quarter building makes a lot of sense. We have additional unallocated cash flow that we could do either more return of capital through buybacks, other shareholder opportunities such as dividends, but we’re really focused on other growth opportunities.

And as long as they’re competitive with that benchmark on the return of capital through repurchases, we’ve got a lot of options on the table. I think that’s an exciting place to be for Vistra. It’s not where we were three years ago in terms of this choice set, but it’s opened up considerably. Kris, anything you’d like to add?

Kristopher Moldovan: Yes, I would just again reiterate that we do maintain an internal model and evaluation. And then we get feedback from our partners, our consultants as well. And we’ve done that recently and we continue to look at different ways to value our stock. And right now, where it sits, is anyway we look at it given the update that we’ve provided today. We still feel like our stock is a good buy to the extent it gets to the point where it exceeds our internal valuation, which we don’t see as being a near term issue. But we would have to then discuss, we will be disciplined in how we spend our capital.

Durgesh Chopra: That’s really helpful, guys. Thanks again.

Jim Burke: Thanks, Durgesh.

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

David Arcaro: Well, good morning, so much in great update.

Jim Burke: Thank you, David.

David Arcaro: I was wondering, could you talk about the data center? I’m curious which location it would be.

Jim Burke: Hey, David, this is Jim. I think I heard you mention data centers and curious about locations. Was that the question that broke up a little bit on us? I’m sorry.

David Arcaro: About that. I was wondering about the data center opportunity with your nuclear plants. Could you give an update as to potential timing, which locations might be more attractive than others?

Jim Burke: Yes, thank you, David. I think the conversation certainly has picked up this year. We started our process, actually, last year looking at the time, it was a perspective close of Energy Harbor, which of course is now in the rearview mirror, which is great. And of course, the Talon AWS deal came out early March. So that was certainly a benchmark and a watershed event for the industry. I will say the two unit sites still have, this is an order of preference that I think the market is grappling with. The two unit sites have more desirability for what their redundancy can provide. Then there’s the single unit sites, of course. And then there’s the gas plants. So what’s been very interesting, David, about our discussions with potential partners is we have normally sort of tried to search for opportunities for us to find partners and bid into their energy needs.

Now this has been reversed. We actually have partners, potential partners coming to us directly. And speed is really very important to them. I would say gas has become as interesting to many of them as nuclear has, in fact, even a preference for some. So from our standpoint, all options are on the table with 40,000 megawatts. And, you know, we’ve got obviously 12 states and 40,000 megawatts that we can do some of our projects with. But we’ve actually flipped it a little bit. So we’ve actually put out some RFPs ourselves. So instead of just responding to the inbounds, we’ve actually gone out to the marketplace to handle actually multiple conversations simultaneously and see what the best opportunity might be for us. And so that process is not concluded yet, but we’re in the middle of that process.

And we’re very excited about the interest. Of course, you can imagine the hyperscalers, the co-locators, and the specific developers are in that process. We’re dedicating a ton of time to it, as I am personally. And it’s probably been the most exciting development for our industry, you know, in quite some time. But we think we can be a great partner to one or more capable parties because of the size of the fleet and multiple geographies. And I don’t know yet which one’s going to happen first. But it’s a it’s a huge opportunity set for us, David, one that I think we’re going to be making really good progress on here shortly.

David Arcaro: Great. That’s really helpful color. I was wondering if you could also touch on just other power plants and other co-location opportunities at gas plants. And are you potentially considering new build yourself as well? Would be curious.

Jim Burke: Yes, David, that actually ties into the earlier question, which is you have existing assets that we have in our portfolio, large scale combined cycle assets. The goal, obviously, for any of these potential partners with the data centers is speed and then reliability that they can, you know, count on for supply. It’s going to be really hard to build an asset like a combined cycle to support a new data center without it having the carbon capture equipment that we were, you know, talking about earlier. And that’s a huge lift that carbon capture equipment could double if not triple the cost of the combined cycle. So I don’t view that as a really attractive near term option at this point until that technology matures. So I think the existing combined cycles are an opportunity for somebody to co-locate.

I think the next best alternative, if it’s involving gas, is likely to be peakers. But that will probably require that that data center needs to also be prepared to pull from the grid so they could get the cheaper wind and solar power on the margin when available, but be prepared to run the peakers for continuity of supply and potentially a price hedge. That, I think, is a potential model. And I think some of our partners we’re talking to are wrestling with the fact that to build out the number of gigawatts that they’re talking about, there’s only so many large meters you can be behind. You’re going to have to actually add supply to the grid. And you’re probably going to have to work in a hybrid type situation where you’re pulling when there’s surplus, but then producing when you need.

And I think peakers could potentially play that role. And I think, again, that plays into this Q discussion of what if there’s a lot of gas to be built? I actually think that means more load comes. And then we might have to build more gas, along with the wind, solar, and battery that is, as you know, already heavily in the queue. But this gas from a reliability standpoint, I think, will play a role one way or the other. I just don’t see it being combined, brand new combined cycles for that purpose. Until there’s more clarity about these EPA rules, they’re likely to be litigated. I think it’s tough to invest into an environment where you’ve got uncertainty with protracted litigation. And so I think it’s going to be difficult to create new baseload assets with confidence.

And that’s why I think the existing baseload assets are getting as much attention as they are.

David Arcaro: Excellent. That’s really helpful. Thanks so much for all the color.

Jim Burke: Thank you.

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

Angie Storozynski: Thank you. So, I just first maybe starting with your credit metrics and investment grade aspirations. So just wondering, what’s the timeline when you think you’re going to hit investment grade metrics? And how you could potentially use like stock-based M&A to actually accelerate this path to investment grade?

Jim Burke: Yes, thanks, Angie. Appreciate that. As you know, what we just said today, we’re right at three times. I think we’re two notches away from investing grade with two of the agencies and one notch away from the other one. So we have some work to do even to get closer to investment grade. I think we’re continuing to look at — as we look at the outlook, I mean, our leverage metrics go down just with the increase in EBITDA that you’re seeing over time. And then, we have a significant amount of cash that has yet to be allocated. And so some of that will go to debt repayment. So we do expect that there could be opportunities to be talking about investment grade metrics in the next year or two. First, we want to make sure that we get the agencies to the one level below, and then we’ll really start talking to them about timing for the deleveraging.

And where we need to get? I think we said on the last call, it’s important for us to get to investment grade. If we do that, that we are comfortably in investment grade, we don’t want to be right at the edge of the metrics. We want to be significantly into that area. So we haven’t had those detailed discussions yet because, like I said, we’re still waiting to get the upgrade to the one notch below. I think as you think about our currency, as we said, we’re still, we’ve been focused. The price of the stock has come up and there could be opportunities to use it in transactions. But at this point, as we just noted earlier in the call, we still see room for our stock to run and we’re currently buying. So, I don’t think that that would be the driver for why investment grade wouldn’t be the driver-free deal like that.

We would certainly think about our ratings as we did any potential opportunistic transaction, but we’re comfortable where we are. We do think we’ll get to investment grade metrics, but we don’t have a specific timeline to do so.

Angie Storozynski: Okay. And then changing topics a bit, like your sensitive assets and the Brownfield sites, especially those associated with the former Dynegy plant. So just wondering, is there any change in your views about the longevity of those sensitive assets? Now it seems like they’re economic, right? But I’m sure that some of the increased output from these assets is embedded in those either that range of that you provided us with. But I just wonder if there is — if some of these assets might get reallocated back to the Vistra vision, meaning that you will not put them in that center bucket. And number two, is if there is any outside associated with those Brownfield sites from the former coal plant, especially in Illinois.?

Jim Burke: So Angie, I think on the on the coal plants themselves, the main driver that we’re looking at on a go forward basis is really the EPA rules that we need to comply with, which means that all but two of our coal plants, the two being Martin Lake and Oak Grove will be retiring in that 2027 timeframe, unless there’s some other change in rule or law that we don’t anticipate. They are more economic, given these curves. I think part of the reason the backward, you know, the further dated parts of the curve, particularly 2028 in PJM and even in Texas is moved up as the dates are becoming more real. And I think the supply and demand dynamic is becoming more apparent. And so, it’s not as much about the economics of those sites at this point that are in Ohio and Illinois and more about the compliance, which of course, we’re going to comply with the EPA rules that are in effect.

As far as Martin Lake and Oak Grove, with the new rules that played out last week, we would either have to add carbon capture technology to those sites, which again, would be very difficult to do. Similarly to the comments I made about combined cycle or cofire, 40% with gas, which we believe is a possibility, something that we think could extend the life if those assets are needed, potentially all the way up to 2039. That’s something we would have to evaluate because we’ve got to have the sufficient gas supply to be doing cofiring at that level. And currently we don’t, we have some cofiring at Oak Grove, but it’s much lower level. So I think Angie, this transition is happening on the grid, this base load across the country, whether it’s regulated markets or competitive markets, has to comply with these EPA rules.

And I think the opportunity for us to do something with those sites and redevelop the sites down the road is possible, but to operate in the coal configuration that it is right now, you know, seems unlikely for, for those sites in Ohio and Illinois.

Angie Storozynski: Okay. And just one last one about capacity prices. I’m just wondering, what kind of assumptions did you embed or versus at least the last two during capacity auction in those ranges that you provided us with, given that we’re, you know, awaiting the next capacity auction in PJM? And we’re seeing some bilateral contracts. We’ve seen those incremental capacity auction clearing, clearing meaningfully higher than that last option. I’m just wondering at least directionally if you can give us a sense what you expect and what is embedded in those ranges?

Jim Burke: Yes, Angie, we do see some bilateral trades that are, that are indicating improvement in PJM capacity clears. I think we’ve still been pretty conservative with our forecast and how we’ve built assumptions for the auctions that are forthcoming, the first one coming in July. I think where we’ve seen some of these clears, we’ve seen them in the $900 kind of megawatt day range, whether we’re going to see that in this upcoming clear or it’s going to be one later in December. We like the steps that PJM has been attempting to bring forward. They haven’t been successful in all of the market reforms that they’ve recommended, but I think there is a recognition of the tightening supply demand dynamics and also the fact that this coal is going to be retiring.

And there’s frankly interest in stakeholders that our visits to Ohio state leaders, they’d like to see some new gas plants built. So it’s not just the Texas market dynamic, it’s other places where they’re attracting industry in the reshoring, the chips build out and they want to see more assets come to ground, which capacity markets play certainly a key role in sending that signal. So we have an improvement embedded Angie, but certainly not anything that I would call a big lift from what we’ve seen some historical clears be, but it’s going to have to prove out in the auctions themselves. And at this point, you know, we await the, they’ve been delayed for a while. So we’re all eager to see how these next couple auctions play out. Steve, anything you’d like to add?

Steve Muscato: No, I think Jim, you hit it. It’s basically if you look historically, PJM cleared on average $100 a megawatt day historically, we see that happening at the very least. And obviously as grids continue to get tighter with demand growth and PJM and the retirements of coal that Jim mentioned, which are really more environment that Jim mentioned, which are really more environmentally driven than they are price driven, that market should continue to tighten.

Angie Storozynski: Great. Thank you.

Jim Burke: Angie, thank you.

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

Steve Fleishman: Thanks. Good morning, Jim, Kris. Thanks for the some of the new disclosures. I’m going to go back to an earlier question just on the 2026 hedging, the 50% hedged. Could you give a little more color on just how the pricing of those hedges are versus current market and or kind of the timing? Like if that 50% number, where was it at year end, ’23, Q1, ’24, just that would be helpful.

Jim Burke: Sure. Steve, the hedging obviously from our standpoint, we look at it as more opportunistic. So we look at where the price obviously is, where our fundamental view is and that is their actual liquidity in the market to transact. So just to give a perspective at the end of last, at the end of last year, so December timeframe, we were in a hedge percentage that was going to be closer to 10% to 15% hedged for 2026. So the team as they’ve seen this move, particularly more recently, they’ve been moving more volume. Steve, there’s also been more liquidity in the marketplace. And I’m going to ask Steve Muscato to comment on that a little bit because obviously if you’re looking to move some of your volume, depending on the depth in the market, you could be having impacts as well.

And the team is sensitive to that. And I’d like Steve to comment on how he’s seen that dynamic change because it’s been more recent. And I think it’s been indicative again of this recognition by market participants that the load is coming, some of the base load is retiring, and this is coming together in a supply-demand dynamic. And Steve, I’d like for you to comment.

Steve Muscato: Sure, Jim. And as you pointed out, we’ve been waiting for the curve in ERCOT to no longer be in backwardation and move up into a contango formation, which it is. And the second thing we look for is basically liquidity events, meaning, there’s got to be people that are willing to buy it with enough skill for us to get our hedges off. And we’re starting to see that liquidity come in. We’re seeing trades that are no longer, let’s say, 10 or 15 megawatts out in the 26th through 28th period we are seeing people willing to buy a couple of hundred megs at a time. And so, we try to mark it. It is something we can scale up. And now that we’re seeing some of that contango come in, we’re taking some off the table. I don’t think we’re done yet.

I think the gas prices are part of the reason why ERCOT is in contango, not just heat rate. But if you look at sparks, sparks are expanding. But if you look at heat rates, and I really want to bring that to your focus, heat rates are not expanding as fast as you would think, giving a tightening market. So a lot of this contango is gas driven. And we think there’s more to come in terms of heat rate expansion.

Steve Fleishman: Okay. And then just two, I guess, other questions on the hedging. In that 50% is there a big difference between your hedges between ERCOT and PJM? Are they both around 50 or?

Jim Burke: Yes, Steve, we weren’t planning to comment on specifically by region on that front. But obviously, those are our two biggest portfolios. So I would just leave it at that. I think it depends on the depth of the market and where we feel we can comfortably move some of the volume. And Steve, I do want to correct one thing I shared a minute ago. I was one file off as I was trying to respond to your question. We were close to around a 25% hedge at the end of the year in 2023, and that’s moved up closer to the 50. So I was trying to be a little bit too nimble and pulling up my —

Steve Fleishman: Yes, no worries. Directionally correct. So okay. And then just we’ve been getting a lot of questions on nuclear fuel with a with a current law. Just could you comment on how you’re positioned on enrich uranium and the like? That’d be helpful. Thank you.

Jim Burke: Yes, we have see we have secured the supply physically for the outages all the way through 2027 and substantially financially, there’s a few of our products that have some index pricing to it. And we are significantly hedged into 2028 as well. So we feel really good about fueling the six units over this planning horizon with the Russian band with an uncertain or to be determined waiver process, I should say, we’re very active in the discussions just to make sure that there’s ample liquidity in the market, as folks will look at these disruptions potentially, and it can cause the spot prices to move up considerably. We’re fairly well hedged in the financial range, we’re kind of looking at a $7 over the whole kind of time period, including Energy Harbor and the Comanche peak site.

So we were a little bit further hedged out for the Texas site, a little bit more open on the back end with Energy Harbor, if we put it all together and locked it all down, it’s a roughly a $7 a megawatt hour average over that period. But the spot markets are in the $11 the $12 range. So DOE with the additional funding of roughly $2.7 billion, we’ll be looking to incentivize domestic production. And we’ll see how that develops. But that’s probably going to take into that timeframe of the end of this decade to see something physically materialized there. But I think we’ve done a good job of locking down some of these risks both physically and financially. And that’s embedded in the in the numbers we’ve provided today.

Steve Fleishman: Great. Thanks so much.

Jim Burke: Thanks Steve.

Operator: The next question comes from Bill Apachele [ph] with UBS. Please go ahead.

Unidentified Analyst: Hi, good morning. Well, most of my questions have been answered. But just on the retail side, can you remind us the arbitration of the contracts and the ability to roll those prices forward as the wholesale prices go higher as we move through time?

Jim Burke: Sure. Yes, Bill. So the business contracts that we sell can be a duration of one to two years all the way up to 10 years. Now, our portfolio is more skewed to the residential, you know, business, which I would say those tend to be one to two year contracts. Residential customers don’t tend to have as much appetite for the longer dated contracts. And so, if you see a sustained higher price environment, you would expect the competitive market from a retail perspective to reflect the new cost of goods sold over time. And that would mean higher prices in a sustained high power market. It also has met in the past lower prices when you’ve seen lower power prices sustain themselves and retailers need to respond to that. I do believe that in this situation, this has been a relatively stable and steady build in power prices.

So these aren’t shock driven like the polar vortex and even winter storm Uri where there were large bills being sent by retailers that hadn’t fully hedged. This has been more of a steady build, I think more consistent with inflation that folks have been seeing in other categories that they procure. But from our integrated model standpoint, you would expect that after you get past the one to two year horizon, you start to reflect the higher or lower retail revenues associated with wholesale power costs. And we try to target more of a steady dollar per megawatt hour type margin and retail so that it’s, you know, additive to whatever’s happening on the wholesale side.

Unidentified Analyst: Thank you. That’s very helpful. And then just want to follow up on that same topic in terms of the given the population growth and can you just speak to your market share and, you know, customer accounts as, you know, you’ve seen that a growing pool of potential customers in the state?

Jim Burke: Sure, Bill. I’m going to ask Scott Hudson, our President of the Retail Business is here and I’ll ask Scott to cover.

Scott Hudson: Sure. Well, first of all, let me just touch on the current retail performance. We really had strong performance in the quarter and year-over-year. We grew residential direct-to-consumer customer accounts by 13%. That came not only from the Energy Harbor acquisition and we had some really nice success in the Lubbock market that just opened, but we’re also growing these books across all markets, you know, sort of organically. So, you know, really nice growth rates in Texas around the population. As Jim mentioned earlier, roughly 1.5% to 2%. And it’s our goal at retail to grow with the market or exceed that market and grow kind of market share. So, we have a very large flagship brand with TXU, Energy that holds significant share in the Europe top market, but we also have five other brands that continue to complement one another and our goal is sort of optimizing those brands by targeting them towards specific populations.

It really is that coordination and sort of our use of advanced analytics to understand what populations, what brands and what particular products that allow us to continue to grow in these markets.

Unidentified Analyst: Thank you, Scott.

Scott Hudson: Thank you, Bill.

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

Jim Burke: Yes, thank you, everyone, for joining us. And I again want to thank the Vistra team, which includes our new members in Ohio and Pennsylvania, and we are very excited about our platform and our unique growth opportunities. The S&P 500 inclusion is a great milestone and our future looks bright. We appreciate your interest and investment in Vistra, and we look forward to visiting soon. Have a great day. Thank you.

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