Vistra Corp. (NYSE:VST) Q2 2025 Earnings Call Transcript

Vistra Corp. (NYSE:VST) Q2 2025 Earnings Call Transcript August 7, 2025

Vistra Corp. beats earnings expectations. Reported EPS is $0.92, expectations were $0.875.

Operator: Good day, and welcome to the Vistra’s Second Quarter 2025 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Eric Micek, Vice President, Investor Relations. Please go ahead.

Eric Micek: Good morning, and thank you for joining Vistra’s investor webcast discussing our second 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. Earnings release, presentation and other matters discussed on the call today include references to certain non-GAAP financial measures.

All references to adjusted EBITDA and adjusted free cash flow before growth throughout this presentation refer to ongoing operations adjusted EBITDA and ongoing operations adjusted free cash flow before growth. Reconciliations to the most directly comparable GAAP measures are provided in the earnings release and in the appendix to the investor presentation available in the Investor Relations section of Vistra’s website. Also, today’s discussion contains forward-looking statements, which are based on assumptions we believe to be reasonable only as of today’s date. Such forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those projected or implied. We assume no obligation to update our forward-looking statements.

I encourage all listeners to review the safe harbor statements included on Slide 2 of the investor presentation on our website that explain the risks of forward-looking statements, the limitations of certain industry and market data included in the presentation and the use of non-GAAP financial measures. I will now turn the call over to our President and CEO, Jim Burke.

James A. Burke: Thank you, Eric. Good morning, and thank you for joining us to discuss our second quarter 2025 operational and financial results. The business continues to perform well and with our strong year-to-date results, we remain on track to achieve a record result for the company in 2025. The trends in demand growth continue to persist in our major markets. The recent experience in PJM in the Northeast is a great example with the late June heat wave resulting in PJM load hitting the highest level in 14 years in New York, the highest in 10 years and in New England, the highest in 12 years. The administration continues to pursue multiple avenues to accelerate America’s development of AI and the electricity sources needed to power it.

We continue to believe this will require a diversified solution with capacity coming from all types of generation sources, particularly dispatchable across all major power markets. We believe the challenge of meeting expected load growth in a way that minimizes the impacts to all customers is solvable. And as I will outline later, we believe Vistra is well positioned to be a leader in developing these solutions for the energy needs of our customers and our nation. Starting on Slide 5, the team has worked hard across the business and achieved adjusted EBITDA of $1.349 billion for the quarter. The consistent execution from our team across generation, commercial and retail delivered reliable power and customer solutions that reflect the strength of our business model.

The strong execution of our team year-to-date provides us with confidence that we will meet or exceed our plan despite the impacts of ongoing unplanned outages at a few of our units. Thus, 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. Moving to growth. We recently announced our plans to acquire 7 modern natural gas facilities from Lotus Infrastructure Partners with a combined capacity of approximately 2,600 megawatts, including 1,800 megawatts in the PJM market. We believe these assets are highly complementary to our fleet, and we look forward to closing the transaction later this year or early next year. Lastly, given our hedging activity over the past several months, combined with the results of the recently completed 2026, 2027 PJM capacity auction, we are increasing our 2026 adjusted EBITDA midpoint opportunity, excluding any contribution from the Lotus assets to be at least $6.8 billion.

Turning to Slide 6. Our 4 strategic priorities remain integral to our strong business performance and both our short-term and long- term success. Our integrated business model and comprehensive hedging program leverages our diverse portfolio of generation assets. This, combined with our strong retail brands and experienced commercial team, provide increased visibility into our earnings potential while providing considerable downside protection. Operationally, we achieved commercial availability in line with expectations as the team worked diligently to prepare the fleet for the critical summer months. This preparation was evident, especially during the June heat wave in PJM, MISO and the Northeast markets. Despite the demands placed on the fleet, particularly during the hottest 3 days beginning June 23, our fleet performed very well with a commercial availability of approximately 95% across our diversified set of assets.

On the retail side, we achieved another solid quarter of performance driven by growth in ERCOT across our portfolio of brands and strong compliant performance versus our competitors. We also continue to grow our large business markets franchise as customers are looking to secure power while managing price volatility. In fact, our Texas business markets volumes were 10% higher year-over-year with strong margins. Switching to capital allocation, we remain committed to our disciplined approach of returning capital to shareholders, executing on attractive growth opportunities like the announced acquisition of assets from Lotus Infrastructure Partners while also maintaining a strong balance sheet. Since implementing the capital return plan put in place during the fourth quarter of 2021, we have returned over $6.5 billion to our investors through share repurchases and common stock dividends.

We expect to return at least approximately $1.8 billion of incremental capital to shareholders through share repurchases and dividends through the end of 2026. We also expect this capital return to coincide with significant balance sheet deleveraging, which we believe will position us for an upgrade to investment-grade ratings as our earnings grow and we complete remaining future payments related to the Vistra Vision minority interest acquisition. Moving to strategic energy transition. We continue to execute on our strategy of utilizing existing land and interconnects to develop solar and energy storage projects. Our Oak Hill, Pulaski and Newton sites remain on schedule for commercial operations in 2025 and 2026. We continue to evaluate the remainder of our development portfolio for additional opportunities as long-term power agreements materialize.

Finally, we were excited to achieve the successful relicensing of our Perry Nuclear Power Plant during the quarter. The Nuclear Regulatory Commission approved the license renewal through 2046, an additional 20 years beyond its original license, and we look forward to the continued operations of this key baseload asset. We believe nuclear power’s unique combination of carbon-free dispatchable power will continue to play a critical role in meeting our country’s electricity needs for decades to come. Turning to Slide 7. We continue to see a structurally improved demand backdrop, which has significant positive implications for our business. While third-party forecast and utility estimates have wide variation, we continue to see a structural shift in electricity consumption with recent growth in electricity demand across the country returning to pre-2000 trends after approximately 2 decades of stagnation.

As we highlighted last quarter, energy growth in our biggest markets continues to track ahead of electricity demand growth for the entire country with weather-normalized load in PJM growing approximately 2% to 3% and the ERCOT market growing approximately 6% year-over-year. Our fundamental view suggest the growth energy consumption will outpace the growth in peak energy demand. This will mean higher utilization of existing assets, including generation and transmission and distribution assets as well as demand response activities, particularly from large customers, including crypto, data centers and other industrial customers. Our view is that markets are beginning to send the a much needed signals for investment in new generation. This is underpinned by the continued investment from industrial and commercial sectors including data center customers.

Since the beginning of this year, the administration’s push to drive investment into U.S. manufacturing has identified over $2 trillion of announced projects. As covered on recent quarterly investor calls, hyperscalers continue to invest in AI and data center infrastructure, including capital expenditure budget increases of over 50% to 60% on average compared to the prior year. The recent PJM capacity auction clear is a sign of markets responding to this increased demand with recent prices signaling the value of additional capacity, whether it’s plant augmentations, deferring retirements, conversions or new build. We believe returning the PJM capacity auction to its regular schedule with a 3-year lead time, combined with the necessary stronger auction clears will incentivize the capacity additions the system needs.

Policymakers are understandably concerned about system reliability and system costs and programs like the Reliability Resource Initiative and PJM can help accelerate dispatchable generation additions. Finally, we continue to believe near-term demand can be reliably and cost effectively served by the grid we have today, given that electric grids remained underutilized for the vast majority of hours in the year. This remains the case for both ERCOT and PJM, where peak load has been approximately 85 gigawatts and 162 gigawatts, respectively, but the average load is approximately 55% to 60% of that level throughout the year. Our thermal fleet on average runs 50% to 55% capacity factors as most thermal assets do across the grid. These resources can scale to meet additional load requirements.

The super peak hours can be reliably met with straightforward solutions like on-site backup generation and demand response, allowing the new load to come into our markets, utilizing the investments already made by the electricity sector, both regulated and competitive. In the medium to long term to sustain the economic growth and meet customer demand, more investment will be needed across the system. As outlined on Slide 8, we believe Vistra’s diverse fleet of generation assets, innovative retail business and development capabilities strategically position Vistra for success in the power sector through a variety of opportunities. Customers are looking for multiple tailored solutions to meet their energy needs and whether it is data center contract opportunities with existing assets or higher utilization of our more than 40,000 megawatts of existing assets, we have multiple paths to create value.

Our dedicated team is actively progressing these opportunities, and we have good momentum. We have a number of short-term, medium-term and long-term options across the generation fleet, and we feel confident about the status of these opportunities and look forward to providing more details over the balance of the year. Our existing asset base provides a strong foundation from which to grow capacity through upgrades, not only at gas plants, but also at our nuclear sites where we expect to finish our upgrade studies by the end of the year. We anticipate being able to add more than 600 megawatts to our existing nuclear capacity by early to mid-2030s. Moving to our coal sites, our Coleto Creek coal-to-gas conversion remains on track for 2027. We see additional potential conversion opportunities at our other retiring coal plants given the strong capacity clears and our improved market outlook, including our Miami Fort coal plant located in Ohio.

With the recent capacity auction clears, combined with an improved outlook in forward energy prices and the state’s dedication to markets with the passage of House Bill 15 in Ohio, we are taking concrete steps to prepare a potential conversion of the plant to gas, allowing it to run beyond the mandated retirement date and adding key capacity to the PJM market for years to come. Turning to new generation. We are proud that our development team’s track record makes us a preferred partner including structuring and evaluating potential opportunities for new build gas generation in partnership with large customers. For renewables, we view the Vistra Zero strategy is complementary to our dispatchable generation assets, and we’ll continue to execute our pipeline by utilizing existing sites and interconnects to serve customer needs.

Finally, as we have demonstrated over time, we believe acquiring and integrating generation and retail assets to be a core competency of the team. We will continue to take an opportunistic approach to M&A as market opportunities arise. On the topic of M&A, I would like to briefly cover the recently announced Lotus transaction on Slide 9. As you’ll recall, we announced mid-May an agreement to acquire 7 modern natural gas facilities totaling 2,600 megawatts of capacity from Lotus Infrastructure Partners. The acquisition includes 5 combined cycle gas turbine facilities and 2 combustion turbine facilities located across PJM, New England, New York and California, which will further geographically diversify Vistra’s natural gas fleet while providing valuable dual fuel capabilities at 3 of the sites.

This transaction, which was struck at an attractive valuation of approximately $740 per kilowatt of capacity before taking into account any tax benefits will enhance our footprint in the Northeast and provide additional optionality as power markets tighten while exceeding our mid-teens levered return target. The acquisition remains on track for close later this year or early 2026. In summary, our financial outlook continues to strengthen while market tailwinds expand our opportunity set. We believe we have both the assets and the team to maximize value and deliver for our key stakeholders, and we are excited about the numerous opportunities in front of us. Now I’ll turn it over to Kris to provide more details on the second quarter results, outlook and capital allocation.

Kris?

Kristopher E. Moldovan: Thank you. Turning to Slide 11. Vistra delivered $1.349 billion in adjusted EBITDA in the second quarter, including $593 million from Generation and $756 million from retail. The Generation segment continued to realize material benefits from our comprehensive hedging program with average realized prices nearly $3 per megawatt hour higher compared to the same quarter last year. The stronger realized price benefit together with higher capacity revenue substantially offset the impacts of unplanned outages at Martin Lake Unit 1 and our battery facilities at Moss Landing. On a year-to-date basis, the additional 2 months of Energy Harbor results combined with higher realized wholesale prices and higher capacity revenue more than offset the impact from the outages.

The team is working diligently to restore site operations at Martin Lake Unit 1 and we currently anticipate that it will restart late this year or early next year. Despite isolated challenges at specific plants, the results of the Generation segment highlight the benefits of operating a large diversified fleet. Moving to retail. It is important to note that based on the shape and level of supply costs, we expected a year-over-year increase in results for the first quarter, which was realized, but a modest year-over-year decrease in results for the second quarter. Notably, the second quarter, like the first quarter benefited from strong customer count and margin performance. Retail continues to generate strong earnings for our business in a variety of market conditions and is on track to outperform 2024 results.

The team’s use of innovative and customer-centric solutions maintains the competitiveness of the business and supports our long-term outlook. Moving to Slide 12. Our commercial team continues to opportunistically hedge our expected generation, providing more certainty with respect to our expected 2025 adjusted EBITDA and our 2026 adjusted EBITDA midpoint opportunity. For 2025, as Jim noted, we have confidence in our ability to deliver 2025 results at or above the midpoint of the guidance range. Based on realized prices for the first 6 months of the year, together with expected forward prices for the balance of the year as of June 30, we did not book any nuclear PTC in our second quarter financial statements. However, we continue to expect the nuclear PTC to provide meaningful downside support to our adjusted EBITDA outlook.

Turning to 2026, given our current hedge position, combined with the recent price clear in the 2026, 2027 PJM planning year capacity auction, we are increasing the expected floor of our 2026 adjusted EBITDA midpoint opportunity to $6.8 billion. Notably, despite a modest pullback in 2026 power prices since our first quarter results call, we continue to see the possibility for our 2026 adjusted EBITDA midpoint opportunity to be $7 billion. It’s important to note that this improved opportunity for 2026 does not include any benefit from the pending acquisition of gas-fired power plants from Lotus Infrastructure Partners. We look forward to providing our formal guidance for 2026 as well as a view of our adjusted EBITDA midpoint opportunity for 2027 on our third quarter results call after we have executed additional hedges with respect to our expected generation for those years.

Moving to free cash flow. As you may recall, we have targeted a conversion rate of adjusted free cash flow before growth to adjusted EBITDA of approximately 55% to 60%. Given the expected benefits from the passage of the 1 big beautiful Bill Act, we now expect consistently higher free cash flow conversion. As a result, starting in 2026 and we are increasing our targeted conversion rate of adjusted free cash flow before growth to adjusted EBITDA over the medium term to be at or above 60%. Based on this revised outlook, we expect to generate a meaningful amount of additional unallocated capital and as Jim mentioned, we have many options on how to deploy this capital. We plan to provide a more detailed update on unallocated cash available for allocation on our third quarter results call.

Finally, we provide an update on the execution of our capital allocation plan on Slide 13. The share repurchase program remains an integral part of our capital allocation framework and has added significant value since the initial implementation in late 2021. Since beginning the program, we have reduced our shares outstanding by approximately 30%, repurchasing approximately 164 million shares at an average price per share of just under $33. This reduction has led to a 50% increase in our dividend per share when comparing the dividend per share in Q4 2021 to the dividend per share paid in Q2 2025. Our [indiscernible] plan has allowed us to stay in the market even when in possession of material nonpublic information. The plan is designed to flex up or down based on multiple predetermined factors, including our share price.

For example, in the second quarter, nearly 2/3 of the total share repurchases in the quarter were executed during the April market downturn, achieving an average price paid per share in that month of less than $115. Going forward, we expect to remain consistent buyers of our shares with the goal of leaning in during periods of market dislocation. Moving to the balance sheet, Vistra’s net leverage ratio is currently approximately 3x adjusted EBITDA. While current leverage levels have remained approximately 3x for the last few quarters, we continue to expect our ratio to decline materially beginning in 2026 as we realized higher levels of EBITDA, in line with our outlook, meet payment obligations associated with the purchase of the Vistra Vision minority interest and allocate additional cash to incremental growth or additional debt repayments.

We remain committed to maintaining very strong leverage metrics, which we believe, when coupled with the expected stability and diversity of our earnings will position us for an upgrade to investment-grade credit ratings in the next 12 to 18 months. Finally, turning to organic growth. 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. Consistent with comments made last quarter, we anticipate a significant reduction in solar and energy storage development CapEx for 2026. As always, this remains subject to change with any new offtake agreements. As Jim outlined earlier, we see an exciting and expanding opportunity set of growth projects across all generation types within our fleet.

We remain committed to our disciplined approach, including targeting at least mid-teens levered returns on these projects, while continuing to return capital to our shareholders and limiting the impact on our leverage metrics. In summary, the team remains focused on delivering another strong year and positioning Vistra for long-term value creation. As always, the team remains laser-focused on executing against our 4 strategic priorities in this growing demand backdrop. With that, operator, we’re ready to open the line for questions.

Q&A Session

Operator: [Operator Instructions] Our first question comes from David Arcaro with Morgan Stanley.

David Keith Arcaro: First, I thought could we start on Comanche Peak. I was wondering if you could just comment on how is the potential deal at Comanche Peak progressing and latest thoughts on timing there and any gating factors as you look at that opportunity?

James A. Burke: David, I somehow knew this one was coming. So I appreciate you asking it. It’s an important topic. Our strategy to date has been to announce something when we have a completed agreement and not before. I think that’s been a bit differentiating from others through this process. And it’s important that we’ve been intentional in not providing a specific time frame because reaching any data center deal is complex, and we actually want to maintain leverage too in the negotiation of these deals. So in my view, you’re not done until you’re done. And our focus has been on finalizing the right deal for our company, which, of course, includes our shareholders. And so it isn’t just about price, it’s also about terms. So given that background, there’s been a ton of interest in Comanche Peak.

And while I’m not ready to preannounce anything, I can share with you that at this point, I feel very good about where things stand in getting a deal done at Comanche Peak. I hope that’s helpful color, David. I know there’s going to be other questions about it, but I feel really good about it. The team feels really good about it and something that the team is working hard at.

David Keith Arcaro: Got it. I can appreciate that, and that is helpful color there. And maybe just to add one more question on that topic. I’m curious just is there anything else that’s needed from a maybe Texas policy standpoint to move forward? I think previously, you had characterized SB 6 as one of the key elements there. Do you feel like you have everything you need in terms of regulatory clarity or the regulatory approval process is still somewhat in flux. Is that one of the next milestones that could determine the path forward?

James A. Burke: Yes, David, it is. So SB 6 was an important piece of legislation. I think its primary focus was concern around large load growth and grid reliability and how will either front of the meter or co-located deals contribute to providing reliability resources if a reliability event were to occur, and that’s where the backup generation piece was highlighted. Our project had already been filed and is already subject and we believe meets the requirements of all existing ERCOT large load interconnect processes. We think it meets the requirements of any new process. But to your point, there’s still a bit undetermined about the new process. There’s been a workshop. There’s been an open meeting here recently. Our feeling is that the approach we’ve taken from the initial construct of this deal and working with our partner to where it sits today is that a binding deal signed before September 1 is not subject to the new SP 6 process and we’re already underway in that process.

But if there were requirements that came out of SB 6, we feel confident our project meets that. So we don’t view that as a gating item necessarily, David. I just think it’s a process, and we’ve been very interactive with stakeholders in Austin throughout our discussion. So again, that’s all part of when I say I feel good about where we are in getting a deal done. I say it with respect to that, and I also say it with respect to timing.

Operator: Our next question comes from Michael Sullivan with Wolfe Research.

Michael P. Sullivan: Sorry, just one more on the timing front. I think you said kind of more updates by year-end. Is that specifically referring to Comanche Peak? Or are there other opportunities? And any color you want to provide on maybe some of the other things that might be in the hopper that we could get color on?

James A. Burke: Yes, Michael, that wasn’t specific just to Comanche Peak. As I mentioned earlier in the background on responding about the Comanche Peak opportunity, we have not preannounced activities. We will talk to you about the level of activity and the fact that we’re working across the fleet on front of the meter and co-located deals. I could see because you manage a queue, customer interest comes and goes at times depending on what other options they’re evaluating even beyond our portfolio of opportunities. So we think that there could be other opportunities that could come from where they sit today to completion by year-end. But no, the year-end comment was not specific to Comanche Peak.

Michael P. Sullivan: Okay. I appreciate that. And then maybe on the M&A front, I know you have something pending right now. Do you think about that as precluding you at all from doing any other deals in the interim? And any market power issues that you see in any grids that you might be running up against for any future deals?

James A. Burke: It’s a good question, Michael. We don’t see it as precluding. This was not — on a percentage basis, this was not as large a deal as obviously some of what our peers recently announced. We had done bigger deals earlier. You might remember, we were — we started this with the acquisition of Dynegy way back when and when prices were even lower from an asset standpoint than today. And then, of course, Energy Harbor and then this one. I do think there are going to be specific tests that obviously regulators will look at in specific pockets, but we think that’s manageable. There’s plenty of assets that are of interest to us. We have headroom in the major markets, including the major PJM markets as well as ERCOT. So we expect to be in the discussions and in the evaluation of future opportunities.

Operator: Our next question comes from Jeremy Tonet with JPMorgan.

Jeremy Bryan Tonet: Maybe to put a bow on this part of the conversation with respect to contracting in general. Just wondering if we could kind of gauge the momentum here. Do you feel more confident in your full opportunity set across the portfolio now versus last quarter given developments we’ve seen over the past several months?

James A. Burke: It is interesting that you’re gauging it quarter-to-quarter because we do see conversations ebb and flow at times because, again, these large customers, and we’re talking primarily the hyperscalers are pursuing multiple opportunities across the country and internationally. So getting their attention on certain deals comes and goes, and we’ll see the team come into a conversation where we’re talking about multiple deals and then it will go a little quiet and then even more deals come up for discussion in the aftermath of that. I can only assume our peers are seeing similar type reaction because these are complicated deals. Colocation, for instance, I describe it as sort of like having a permanent roommate. It’s not a paper contract or a hedge, you’re colocated, you’re coordinating activities.

You’re relationship lasts for decades. You’re managing load ramp, grid protocols, expansion plans, water use, land use. There’s — those are real important partnerships to get right. I would say, overall, the interest this quarter appears just from an activity level to be even greater than it was last quarter. But I don’t want to say that’s a prediction that next quarter is going to be even busier. I’m just suggesting that it’s not all linear in the way that these conversations develop, but they do take time to get right. And that’s the most important thing is we aren’t focused on just getting a deal. We want to get the right deal for our company and our shareholders, but I do think the activity level has picked up this quarter.

Jeremy Bryan Tonet: That’s helpful. Maybe, I guess, to reframe it a little bit better. Any thoughts you could share on the relative attractiveness of long-term contracting across the markets you’re in, such as ERCOT versus PJM or even think about nuclear versus gas at this juncture?

James A. Burke: Yes. I’ve described in the past, and I think I said this a year ago, and I don’t think my view has changed in the year of these discussions and the process of developing these opportunities with potential customers. I think there is still a premium for carbon-free resources like nuclear. We also see speed to market advantages with colocated deals. I think those deserve a premium. And that price spectrum, I’d put those still towards the upper end. I think as you move to front of the meter for those same resources, they’re still attractive. I wouldn’t expect them to garner the same premium. And as you move to gas, I think you also have a colocated versus front of the meter and the customers are working that entire spectrum of opportunities.

But I think just like any other consumer product you have, people will pay for value. So if there’s land, if there’s access to being able to expand, there’s value to all of that. So I look at it much more from the standpoint of these are sophisticated customers. And I would say that the IPPs and those that are regulated utilities working with these customers are learning their needs, but folks will be economically oriented, and there are some things that fit their profile differently. And so for instance, the colocation providers that are not the hyperscalers, they may be more interested in some of the gas arrangements than the nuclear arrangements. I think that’s natural. That’s how market should clear. But that price spectrum we’ve talked about before, I think, is still intact, and that’s the flavor of the conversations we’re having.

Operator: The next question comes from Bill Appicelli with UBS.

William Appicelli: Just a question on the free cash flow conversion improvement you discussed. Can you just put some more color around that? I assume this is driven by the OBBB depreciation improvements. And so what level can that get to? Is that something we can see go up to 65%? Or what’s the magnitude?

Kristopher E. Moldovan: Yes. I appreciate the question. So I think as we said, we were in the 55% to 60% range. So if you kind of look at the middle of that, which is on average where we were and now we’re saying 60-plus percent. that’s approximately — again, I think if you assume 3% a year, which wouldn’t be unreasonable. Now the timing of that shifts from year-to-year. So it’s not straight line. But 3% a year and if you think about us being starting in 2026 at $6.8 billion to $7 billion of EBITDA, you get to approximately $200 million a year. And then again, over a 5-year period, that would get you to somewhere in the neighborhood of $1 billion. That wouldn’t be unreasonable. It’s — again, I want to make sure though to state that that’s — some of that is a little bit lumpy. It comes a little bit more in the ’27 through ’29 time frame than the ’26 benefit.

William Appicelli: Okay. And then the mention around the investment grade over the next 12 to 18 months, can you just speak to that as to what you need to achieve? Is that just on the higher EBITDA projections? And — or is this an increased effort to target a lower leverage level in terms of not just EBITDA moving up but paying down additional debt?

Kristopher E. Moldovan: Yes. As we — I noted in the remarks, we do expect to delever relatively quickly. And part of that is paying down debt. That includes the repurchase obligations relating to our Vistra Vision minority interest, but it’s not — that’s not the only debt that we anticipate paying down over the next couple of years. So we will be reducing debt. And then as you say, our additional adjusted EBITDA opportunities that begin starting in 2026. So we delever very quickly. And we’ve always said our goal was to maintain a strong balance sheet. We weren’t targeting — I think over the last couple of years, we weren’t targeting a specific rating. But as we’ve done the Energy Harbor deal and the Lotus transaction and some opportunities have arisen, we see our business risk profile and leverage metrics, both improving.

And that puts us on a clear path to investment-grade ratings. And we think that’s warranted. We’re welcome it. And we do think it would be incrementally positive for Vistra and its stakeholders. So I do think we’ll get down to those metrics. I think you would — we continue to say we target less than 3x. I think what we see something materially below that. And I think once we get there, we’ll plan to stay as a lower levered company. So I could see us being materially below 3x. And and we’ll welcome the investment-grade ratings, and we’ll continue to run our balance sheet accordingly.

William Appicelli: All right. Great. And then just lastly, I mean, can we just get your views on the PJM capacity auction clearing at the cap and where maybe we go from here from a policy perspective? And should we assume that ultimately, this capacity price is going to fade down? Or do you expect it to stay at [Audio Gap] level for the foreseeable future?

James A. Burke: Yes. That is obviously a difficult question to answer. I would say from a prediction standpoint, we know we have a cap and a floor for the next auction. And I think that is giving at least signals to both the customer side of this as well as the supplier side that we’re going to be in sort of a banded outcome. As you guys know, the capacity clears have been all over the board. And prior to last summer, the previous 3 clears were effectively in the dirt. And we’ve seen market response to that. We’ve seen lack of new build during that period, but also plant retirements. With the last 2 clears, including this most recent one, you’re seeing the market respond. I mean on an ICAP basis, on an installed capacity basis, we saw almost 5 gigawatts of new supply in just this auction.

Obviously, when you do it on a UCAP and they factor that down, that’s a lower number, but that UCAP gets applied on the supply side and the demand side. So I think it’s important to not lose sight that all companies are responding in this environment. Miami Fort is a great example of that. It’s 1,000-megawatt coal unit near the Cincinnati area, and that is slated to retire. We have broadcasted that for several years. With the previous auction clears, we couldn’t even think about converting that to gas because there’s a cost to the pipe. We have to sign a contract for gas supply. So we increase our fixed cost. And then we have to have a view towards capacity and energy. 1,000 megawatts in the DO zone is very meaningful to the marketplace. And we’ve done augmentations.

We’ve been — we’ve submitted a couple of projects as part of the RRI effort, which is going to add about almost 12 gigawatts and half of that’s new gas, including CCGTs and CTs. So I think people believe that one clear, everything should appear, but it just doesn’t. It takes time. And the interconnect queues are part of that as well. And so I believe 2 things should happen. One, we should see higher utilization of existing assets because as I’ve mentioned, there is excess capacity on the grid as it sits today. That doesn’t mean in every load pocket and every node, there’s excess supply, but there is excess supply, and we should be working with our utility partners on where the best place to site load is as well as generation so that we can utilize the capacity that’s already on the grid and build new where we need to.

The other part of this that I think is important to keep in mind is a lot of the auction clear and what’s important is relative to the cost of building new as well. The cost of building new has more than doubled in the last 5 years. So just looking at a historical auction clear and saying these are higher clears than we’ve had in the past is interesting, but it’s actually not the full equation because we have to pay for not only the capital to build a new plant, but the labor to construct it. And once you have your capital cost, you know your gas cost, you forecast energy revenue, you look for this capacity piece to help fill in the difference. As those costs have moved up, necessarily the auction clears need to move up in order to make that math work.

And that’s true no matter who the investor is. It’s not just IPPs. Anyone can invest in PJM, anyone can invest in ERCOT, and they’re all going to look at our proper investment signals there to do so. The consumer bill impacts were a little bigger from the previous auction from last summer. We think this auction moving up into the 329 range per megawatt day is about a 2% bill increase for customers. So I do think it’s a higher level than they’ve seen. But over the last 10 years what you’ve seen customers experience is an overall bill increase. But if you actually look underneath that, the energy and capacity piece is flat to down over that 10 years. And the wires rates, the transmission distribution utility charges have generally doubled over that time period.

So energy and capacity is now, in most cases, a smaller part of the absolute bill than the wires charges are. So when we think about affordability overall, we need to look at the total bill, not just what’s there on energy and capacity, but look at the total bill and make sure that we have a product that’s affordable for customers and that we’re using the current grid as efficiently as possible. So I know that’s a little longer than what your question was from a price prediction, but I do think in this demand where everyone is looking for turbines and everybody is looking for load growth across the — in many markets across the world, not just the U.S., the cost of developing new projects is moving up, and therefore, the cost on the other side, whether it’s a long-term contract or an auction is going to need to reflect that.

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

Julien Patrick Dumoulin-Smith: I’m sorry to do it, but to bring it back, just given the comments from earlier about the September 1 time line, I mean, is there just an expectation here that you’d say, look, we’re going to try to get it done before 9/1 considering that? Or just again, the SB 6 and the way that, that’s been moving forward, look, you feel entirely fine about how that implementation process looks such that it would be sort of analogous pre or post in terms of process? And would that put any extra strains about what it would look like in terms of the deployment permutation? Or is what you’re contemplating sort of irrelevant with respect to SB 6? And any other comments about SB 6 requiring or mandating in any kind of way this demand response type activity here as far as your negotiations go?

James A. Burke: Yes, Julien, there’s a lot in there. I would say nothing about our approach to this discussion and completion of an agreement with our customer is based on trying to extend the time frame. I mean these are just large complicated deals. And so we’ll be done when we’re done. And I think our deal will work pre or post a 9/1 completion. And I think to your point about backup generation, one of the challenges, obviously, of working this on-site partnership is that we want to make sure that land and water and the ability to expand the site is there for the customer, including for their backup generation because we do expect that to be part of the reliability offering of a large site like this, and that takes planning.

And so I mentioned we will meet — we meet the current rule requirements. We don’t know exactly how a rule requirement might develop if we are going through a review with SP 6. But in all the discussions we’ve had, we feel confident we meet the requirements of any new process that’s contemplated. So I don’t see that as being a material driver of the outcome of this deal. Obviously, clarity is better than less clarity. So I’m not seeking to try to extend the process in Austin. But we have raised this reliability topic and the idea of how do you manage these super peak hours on a grid that largely has a lot of excess capacity. We’ve raised that as a company for years as how do we make sure the customer including residential, of course, has the energy they need when they need it.

And the customer we’re working with, they want to be part of that same solution. I mean they have a license to operate, and they’re looking to be economic development opportunities, and they want to be a solution, not a problem. So I think we’re aligned, Julien. So I don’t see it as material.

Julien Patrick Dumoulin-Smith: Actually, since you say it this way, the backup generation or adjacency opportunity here, I mean, I know we’re principally talking about a nuclear contract here, but would you expect to effectively undertake that on behalf of any said customer? And then effectively, that would be part of the economics? Is it sort of a package deal that you would develop a gas plant or some kind of comparable generation that would effectively be paid for through a nuclear contract or a separate arrangement on a gas deal? Just trying to understand how you think about that. Especially the compensation part.

James A. Burke: Yes, that [indiscernible] by customer, Julien, I don’t want to comment specifically about this particular arrangement, but that’s going to differ by customer. Some of them feel very strongly about this being a core competency and something that they want to tightly manage and control and others are looking for a more turnkey solution. So I think it could be either. And we will discuss this deal in more detail at a later date, but we’re seeing that it could go either way.

Julien Patrick Dumoulin-Smith: Got it. Excellent. Sorry, I just squeeze one last one in. On ’27, any comments yet about where you guys are relative to what you said about ’26? I know you provided a little bit of an update, but curious if you’d offer any initial observations…

James A. Burke: Yes, sure. So from the last update we gave a quarter ago, the curves are down just a little bit, Julien, not enough for us to change our views on 2027, but I think it’s reality that when folks are looking for weather, they’re looking for the weather to move the forwards. And like in ERCOT, there just hasn’t been much weather. So that’s just been the way it’s played out. And in PJM, even though we saw the weather earlier in the summer in that kind of June 23 time frame, we saw prices really move in the sort of real time, and we saw some clear in the thousands of dollars that we haven’t seen in those markets in quite some time. But we didn’t see the forwards move that much. We think both are inconsistent with the load growth that’s coming.

And so we’re a little more bullish, I’d say, than where the curves are sitting at the moment. we’re not fully hedged obviously in ’27. We have some hedges on for sure. But yes, I would say don’t take this — we tried not to view this as a quarter-to-quarter kind of mark on the business. but ’27 or comments before about ’26, ’27, ’28, being in this range and trending in the right direction, still hold. Kris, anything you’d like to add?

Kristopher E. Moldovan: No, I think I’d just point out that we have some roll-off of some hedges, but then we have some projected gas or coal plant closures. And so I agree with Jim. We continue to say we see those years being in line, but trending a little bit in the right direction as we go forward in time, and I agree that still holds.

Operator: Thank you. We will now conclude our question-and-answer session. I would like to turn the conference back over to Jim Burke for any closing remarks.

James A. Burke: Yes. Thank you, everyone, for joining. I want to take a moment to thank our team for their continued execution and service to our customers and communities. This is an incredibly exciting time for our company. I hope you can tell by some of the topics today that there are a lot of growth opportunities out there, and we intend to capture them. We look forward to seeing you in person this fall and have a great day.

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