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

Good morning, and thank you all for joining Vistra's Investor Webcast discussing our second quarter 2024 results. Our discussion today is being broadcast live from the Investor Relations section of our website at www.vistracorp.com. There you can also find copies of today's investor presentation and earnings release. Leading the call today are Jim Burke, Vistra's President and Chief Executive Officer; and Kris Moldovan, Vistra's Executive Vice President and Chief Financial Officer. They are joined by other Vistra senior executives to address questions during the second part of today's call as necessary. Our earnings release, presentation, and other matters discussed on the call today include references to certain non-GAAP financial measures. Reconciliations to the most directly comparable GAAP measures are provided in the earnings release and in the appendix to the investor presentation available in the Investor Relations section of Vistra's website. Also, today's discussion contains forward-looking statements, which are based on assumptions we believe to be reasonable only as of today's date. Such forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those projected or implied. We assume no obligation to update our forward-looking statements. I encourage all listeners to review the Safe Harbor statements included on Slide 2 of the investor presentation on our website that 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.

Thank you, Eric. Good morning, and thank you all for joining us to discuss our second quarter 2024 operational and financial results. Beginning on Slide 5, you can see the team has been hard at work across multiple parts of our business. Through their efforts, we achieved ongoing operations adjusted EBITDA of $1.414 billion, a very strong second quarter against a backdrop of lower wholesale energy prices across the country. While results benefited from the inclusion of the first full quarter contribution from the Energy Harbor businesses, consistent execution from our generation, commercial, and retail teams played a major role in this achievement. Specifically, our diversified portfolio of generation assets produced record levels of power for our customers while completing the planned outages needed to prepare the fleet for the crucial summer months. Our retail business led by our flagship TXU Energy brand delivered year-over-year growth, while producing solid margin performance and maintaining a top score on the PUC of Texas power to choose scorecard. Finally, despite the weather volatility across the country in general, power prices cleared below our hedge levels. Through strong execution of our comprehensive hedging program by our commercial team, our second quarter results reflect the solid performance anticipated when we set our expectations for the year. Turning to guidance. We are reaffirming our guidance range for 2024 ongoing operations adjusted EBITDA of $4.550 billion to $5.050 billion. Based on performance to date and our forecast for the remainder of the year, we are confident in our ability to deliver towards the upper end of this range. As we noted during our first quarter results call, our guidance excludes any potential benefit related to the nuclear production tax credit or PTC, given the uncertainty around the interpretation of gross receipts in the regulations. However, based on where prices settled in the first seven months of the year and the forward curves for the balance of the year, we believe the impact of the PTC to our 2024 ongoing operations adjusted EBITDA could be upwards of $400 million. Moving to our long-term outlook. Our integrated business model, which combines critical dispatchable generation assets with a premier retail business, positions us well to create long-term value in the current volatile and growing markets. Given our hedging activity over the past several months and the recent 2025-2026 PJM planning year auction results, we are raising our estimated 2025 ongoing operations adjusted EBITDA mid-point opportunity range by $200 million to $5.200 billion to $5.700 billion. Similar to our 2024 guidance, our range of 2025 ongoing operations mid-point opportunities excludes any estimates related to the nuclear PTC. However, it is important to note that we believe the nuclear PTC will provide downside support for such range of opportunities and we will continue to evaluate the appropriate timing for including PTC estimates in our forecasts. Underpinning the improvement in our outlook is our focus on our four key strategic priorities outlined on Slide 6. Our integrated business model leverages our diverse portfolio of generation assets coupled with our strong retail brands to deliver more consistent results as evidenced by our second quarter performance. Our core tenant of one team continues to foster not only teamwork, but drives learning and best practices across all aspects of our company to create a culture of continuous improvement, including at our recently added PJM nuclear sites. As discussed on the previous slide, our commercial teams continue to execute on our comprehensive hedging program to provide visibility into the earnings power of the business, while also providing meaningful downside protection to our long-term outlook. While our current 2024 guidance and long-term outlook both exclude any estimates related to the nuclear PTC, we believe the availability of a nuclear PTC de-risks a substantial portion of the earnings potential of our nuclear assets, making them increasingly more valuable. Switching to capital allocation, we view this as a critical responsibility and we will remain disciplined in our allocation process. We continue to execute the capital return plan put in place during the fourth quarter of 2021. Since that time, we've returned approximately $5 billion to our investors, including $4.25 billion of share repurchases through August 5 of this year. We expect to execute at least $2.25 billion of share repurchases throughout 2024 and 2025. Moving to the balance sheet. Our financial position remains strong with net leverage at the end of the quarter at 3x ongoing operations adjusted EBITDA. We continue to expect net leverage to be below 3x by year-end 2024. On energy transition, we continue to be opportunistic in executing on a renewable development pipeline. We began construction on two new large scale solar projects, one in Texas and one in Illinois. To ensure full off-take from these facilities, we executed new long-term power purchase agreements with two of the world's leading technology companies, one with Amazon and the other with Microsoft. We are excited to partner with these well-known companies to provide carbon-free electricity for their operations. Moving forward, our development opportunity pipeline remains robust. Our large geographic footprint across the country, which encompasses more than 70 sites with grid interconnects and thousands of acres of land for development, provides ample opportunities to meet customer needs for a particular energy technology or to co-locate operations. Our approach to the energy expansion continues to responsibly balance reliability, affordability and sustainability while ensuring disciplined project returns for our shareholders. We have highlighted this approach in our most recent sustainability report, which we published on July 31. We are proud of the approach we take to sustainability, which ensures that we are reducing our emissions while also creating a sustainable business strategy for all of our stakeholders. Moving to Slide 7. We see a potential significant supply gap emerging in the largest markets we serve. During our first quarter results call, we outlined the potential multiple drivers of future demand and these include the reassuring of industrial activity partially due to the CHIPS Act, the build-out of data centers, whether behind the meter or in front of the meter, increased electrification of commercial, industrial and residential loads and strong population growth, particularly in Texas. In addition to this demand growth, we believe current environmental policies will drive significant retirements of dispatchable thermal generation, notably coal plants, through the end of the decade, creating a supply/demand gap. Many of these policies are driven by decisions at the state level and are less influenced by federal policies. Supported by PJM's recent market reforms, the higher clearing prices for the 2025/2026 capacity auction are beginning to signal to competitive market participants, including investors who can respond to this supply gap. While it is only one auction clear, capacity revenues over time can help offset lower wholesale energy prices, which have softened in the outer year since our last call in May. Generation units are long-lived assets, and a consistent, predictable market framework focused on reliability is necessary to attract capital for new dispatchable supply. The Texas market relies almost exclusively on the wholesale energy price to incentivize new generation, and we have seen a lot of volatility in these forward curves. Policymakers have recently created the Texas Energy Fund to provide lower cost financing and completion bonuses for up to 10 gigawatts of new gas fuel dispatchable generation. This does provide some financial support for new builds, but we believe forward price signals and market reforms will be necessary to attract sufficient equity capital to build new gas fuel generation. However, in a competitive market, as has been the case in Texas for nearly 30 years, there will be many market participants and investors to evaluate their opportunities and decide their best path forward. As we announced in late May, we are targeting up to 2,000 megawatts of dispatchable gas fuel generation additions at ERCOT. This includes 500 megawatts of augmentations at existing facilities, nearly half of which we have brought online already this summer, and up to 600 megawatts from the conversion of our Coleto Creek coal plant to a gas-fueled unit, which will take place after the plant's retirement in the middle of 2027. These investments represent accretive opportunities for our company while preserving good paying jobs for our fellow Texans. We also submitted our application in July for the Texas Energy Fund financing for up to 860 megawatts of advanced peaker plants in West Texas. As noted in our announcement, we are in the early stages of development of these plants as we monitor the successful implementation of key market reforms focused on grid reliability as well as sufficient market signals. These key reforms include a suite of ancillary services, the performance credit mechanism, or PCM, and an effective reliability standard, a first for Texas. We will continue to work with policymakers and other stakeholders to shape a robust framework for investment in Texas. Looking broadly across the markets we serve, the interconnection queues are largely filled with wind, solar and battery resources for a number of reasons, including tax incentives, state policies and the preferences of large customers. The combination of low growth coal plant retirements and additional intermittent resources will require both baseload and flexible dispatchable units. Vistra is well-positioned with its diversified fleet and we will continue to work with policymakers, customers, and communities to ensure their energy needs are met reliably, affordably, and sustainably. This is what drives our purpose at Vistra and our team is excited about the future set of opportunities. And with that, I will turn it over to Kris to provide a detailed review of our first quarter results.

Thank you, Jim. Turning to Slide 9, Vistra delivered another strong quarterly result with ongoing operations adjusted EBITDA of approximately $1.414 billion including $625 million from generation and $789 million from retail. This represents an approximately 40% improvement year-over-year and brings our year-to-date ongoing operations adjusted EBITDA to $2.227 billion. Notably, the performance of generation and retail year-to-date, together with our forecast for both businesses for the remainder of the year are driving our confidence in Vistra's ability to deliver 2024 aggregate results towards the upper end of the guidance range. Focusing on year-over-year results despite continued mild summer weather in Texas and lower wholesale prices across competitive markets, the generation team once again capitalized on the volatility in the quarter by optimizing the run profile of our generation units, including ramping down and buying power from the market when economically appropriate. The team's ability to perform in a variety of market conditions is made possible by the consistently high operational performance, the diversity and the flexibility of our fleet. Turning to retail, our second quarter results benefited from the continuation of higher counts and margins cited in the first quarter. Additionally, as expected, due to the evolving seasonality of underlying power costs, the retail team delivered a significantly higher portion of the expected annual ongoing operations adjusted EBITDA in the first half of 2024 as compared to 2023. Finally, our 2024 results for generation of retail have benefited from the inclusion of the former Energy Harbor businesses, which benefit totaled approximately $200 million for the second quarter and approximately $260 million year-to-date. The contribution from these businesses for both the second quarter and year-to-date results was primarily driven by the PJM nuclear fleet, which accounted for approximately three-quarters of the contribution in both periods. Moving to Slide 10. We have seen significant volatility in forward power price curves in the last several months. However, our commercial team was able to take advantage of this volatility, increasing our wholesale hedge balances to approximately 86% in calendar year 2025 and approximately 55% in calendar year 2026 at what we believe to be attractive prices. As Jim noted earlier, given our current hedge positions in 2025, combined with the prices realized in the recent 2025/2026 PJM planning year capacity auction, we increased our estimate for the 2025 ongoing operations adjusted EBITDA mid-point opportunity range by $200 million. Although forward power prices have generally fallen since our first quarter earnings call, the additional hedges we have executed and the 2025/2026 PJM auction results continue to give us confidence in our estimated 2026 ongoing operations adjusted EBITDA mid-point opportunity of more than $6 billion even before we update our assumptions for the upcoming 2026/2027 PJM planning year capacity auction. Notably, as is the case with our 2024 guidance, our long-term outlook excludes any estimates related to the nuclear PTC, which could be meaningful. Finally, we continue to target a conversion rate of ongoing operations adjusted EBITDA to adjusted free cash flow before growth of 55% to 60% for 2025 and beyond, excluding any upside from the nuclear PTC, which is generally expected to benefit adjusted free cash flow before growth at least one year after being recognized in ongoing operations adjusted EBITDA. As a result, we expect to generate a meaningful amount of unallocated capital through 2026, which we expect to discuss in more detail on our third quarter results call in November. Finally, we provide an update on the execution of our capital allocation plan on Slide 11. Our share repurchase program has generated significant value for our shareholders. Since beginning the program in November 2021, we reduced our shares outstanding by approximately 135 million shares or approximately 29% at an average price per share of approximately $27.50. Despite the increase in our stock price in 2024, we still see our shares trading at an elevated free cash flow yield and continue to believe allocating capital to share repurchases is an important priority. To that end, as Jim noted, we expect to execute at least $2.25 billion of share repurchases over the course of 2024 and 2025, and at least an additional $1 billion in 2026. Moving to the balance sheet. Vistra's net leverage ratio currently sits at 3x ongoing operations adjusted EBITDA, despite the additional debt that was required to close the Energy Harbor acquisition in the first quarter of this year. We expect it to return to below 3x by the end of 2024. We continue to target a long-term net leverage ratio, not including the benefit of margin deposits, below 3x. As Jim discussed earlier, we are excited to announce the two long-term power purchase agreements with Amazon and Microsoft for two new large scale solar facilities. As a reminder, we expect to fund approximately 60% to 70% of our solar and energy storage capital expenditures with non-recourse financing. We remain committed to our opportunistic approach to our solar and energy storage growth strategy and continue to target levered returns of mid-teens or higher for these projects. Finally, as we highlighted in the first quarter results call, 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 $135 million of such dividends 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 in the first half of the year and we remain committed to executing against our four strategic priorities. With that, operator, we're ready to open the line for questions.

We'll now begin the question-and-answer session. Our first question today is from Shar Pourreza with Guggenheim. Please go ahead.

Good morning, Jim. Jim, just in light of the PJM capacity print, would you consider investing in new gas or storage and RTO at this point? I mean, do you think one or two more prints at this level are sufficient to attract new entry? Does this kind of change any of your thinking regarding any potential coal to gas on the Sunset fleet? Thanks.

Yes. Shar, it's a great question. PJM has been working on market reforms for quite some time, and we've talked about that on previous calls. It's a long process, and I think they've made great headway in looking at the sort of contribution that different resource classes, like dispatchable, can provide. And I think we saw that reflected in this most recent clear. It is only one auction, of course, and not long enough out in the future to be starting a new project because they are behind, obviously, and they're catching up on the number of auctions in the next couple of years. This December will be another interesting signal. We think it can clear at or above where this most recent clear was just given some of the fundamentals. And I think that does make PJM attractive. I think that's one of the things that PJM is offering now is a signal towards assets that provide us reliability benefit. We have a number of sites in PJM operating. We obviously have some coal plants, we could look at potential conversions at some point to gas. And I think others will look at that as well. But it is a good signal. Shar, it's still early stages, but I think a lot of progress has been made there.

Got it. Perfect. And then just, Jim, on 2026, right, obviously, you reiterated the mid-point opportunity, but we saw some trade-offs between the curves falling in the blowout PJM capacity number. But the question is like, would you have been at that $6 billion figure before the auction results? Maybe if you could just put a little bit of a finer point on the ranges around the year, even directionally? Thanks.

Sure. That's a good question, Shar. When we initially announced the $6 billion target, we discussed it during the May call. The market conditions in Texas and PJM were looking quite favorable at that time, as were conditions nationwide. However, as you know, market conditions have softened since then. We were approximately 50% hedged during that call, and now we are at about 55% hedged. This change has led to some erosion of the gross margin for the unhedged portion, impacting our 2026 earnings. We anticipated some volatility in the curves due to our open position, which is why we felt confident in setting the $6 billion target, as volatility is inherent in our business. This target only reflects part of 2026, and the upcoming auction in December will capture the remainder of that year. We did not revise our 2026 earnings forecast; however, as you pointed out, we did revise the 2025 estimate. With the recent clarity we've gained and the upcoming auction, we are optimistic about exceeding the $6 billion figure, but we'll update that figure in the next quarter. In our next call, we will provide guidance for 2025, which we've not disclosed today, and offer more insights into 2026. Overall, the business remains very resilient, and the diversification of our fleet along with our retail operations strengthens our earnings potential.

Got it. Perfect. And then just one more quick one. Just on the FERC Technical Conference, I know you guys have been obviously super vocal in the Susquehanna ISA amendment process. Has the technical conference slowed any of the conversations you've been having with customers around co-location opportunities? Thanks.

Hey Shar, the pace has not slowed down. While the number of conversations has decreased, we still have many customers engaging with potential suppliers like us. We are making significant progress with our customers and are in due diligence for several sites. This process, which includes a technical conference, remains of interest to many. However, these discussions are long-term and involve considerable decisions. Contracting for one of our larger sites could mean power costs nearing $1 billion annually at a single location. Thus, these conversations require time to develop, but the activity has not diminished. There will be plenty of data center load both behind and in front of the meter, and customers are thoroughly assessing all their options. We'll see how the technical conference unfolds. We support FERC's approval of the amended ISA, and we believe the evidence strongly favors this. There will be more updates, and we will remain engaged, as will all market participants. This represents a significant opportunity for our industry to meet customer demands and stimulate job creation and economic development. I hope our industry remains proactive to ensure this load growth benefits the broader economy. We anticipate these discussions to remain active until we reach a decision with a few key customers, for which we feel optimistic.

Okay. Perfect. Thank you guys so much. Much appreciated. See you again.

Thank you, Shar.

The next question is from Angie Storozynski with Seaport. Please go ahead.

Thank you. Continuing on the topic of co-locations and load growth, we are noticing increased discussions from utilities and competitive markets, particularly in PJM. They seem to be worried about the load growth and the reliability of electric service in the coming years as this load develops. This has raised concerns about possible interventions in competitive power markets and regulated new builds. It appears that these worries are not only tied to the projections for new builds but also to the recent PJM capacity auction. This is somewhat alarming, especially since the same stakeholders did not advocate for merchant power plants when power prices were at their lowest. Ideally, we would expect a cyclical market where power and capacity prices rise to encourage new builds. How do you intend to handle this situation? Will you expedite your assets to secure contracts to safeguard against any market interventions? Do you believe this is merely a passing concern? Is the demand so significant that all parties can benefit? My impression is that it indicates that utility stakeholders realize that the best opportunity lies with generation assets. I'm curious about your strategy moving forward.

Yes. Angie, there's a lot in that question. It is something we think about quite a bit. The beauty of a competitive market is anybody can build generation in a competitive market, and that includes the regulated utilities as long as they're doing it in the competitive market context. That framework has shown over the years to over $80 billion has been invested by competitive companies in PJM since the market opened over $100 billion has been invested by competitive companies at ERCOT since the market opened. This is the first clear, as we just talked about, that has shown real life in quite some time. And while it looks like it's 9x to 10x higher than the last clear, on average is bringing maybe 40% to 50% of what you would need to build a new gas plant. This is not a clear that in and of itself without energy margin makes all the math work from an investor point of view. I know the regulated utilities feel a need to serve their customers with a reliable product, and we feel that need as well. That is a core tenant of our strategy. I think there's plenty of investment opportunities on the transmission and distribution side to not only serve new load but to connect the new generation resources. And that queue has been slow to develop in PJM, and I know PJM wants to accelerate that. So I still go back to what I said just a minute ago, I don't think we should be worried about, are there some ancillary services that need to be paid or some wires charges that need to be paid. The customers we're talking to want to pay for the services that they're being delivered, whether that's on the wire side or the generation side. I think there's plenty of opportunity for all of us to work together to not only make this an economic opportunity for our respective companies, but to meet the customer need. That's ultimately what we're doing here is meeting a customer need, and I think we're going to all have to work together to do it. But it's something that I think, Angie, is going to unfold through time. Nothing happens in the power market as fast as the technology space would like it to. And frankly, as fast as we would like it to. So I think we just need to keep the dialogue open and work through these issues. But we think there's plenty to go around for this to be a real boom for all stakeholders.

And then as far as your approach to those co-location deals and any other long-term contracts, I mean it seems like you were taking this portfolio strategy. But I'm just wondering, it almost feels like the time is of the essence, not just about the time to market for tech companies, but also as far as regulatory scrutiny of these deals. I mean, don't you think that maybe it would be worth pulling forward some of these transactions not to wait for all of the reviews to happen just to announce these deals on like a plant by plant? Again, in other portfolio announcements, but just plant by plant deals, again, if only because there could be more risk to future deals as well as these co-locations happen?

Yes. I think, Angie, the regulatory questions obviously are getting some attention, but I still view this as a customer-driven event. The customers are going to want to sign these contracts and get comfortable with the resources, the location, the speed with which they will energize the terms under which we'll do business. So it isn't just up to our company to just move quickly. It's up to our company to be responsive to customer needs, and we need to work through the necessary filings and the studies to make that happen. But if the customer pull is there, I think Vistra is going to be right there with any of the other parties to be able to meet this need. But I also think the regulators are doing the job they need to do, which is ask questions. And I think the response that's been provided in the amended ISA has answered those questions, and we're optimistic that, that will get approved. But this is not simply up to Vistra in terms of how fast Vistra wants to move. There are real customers here with real resources that they're committing just like we'll be committing and those conversations take time. These are complicated deals, and they're valuable for all of us. But we hear your question. I just think that it's not just a one-way direction for Vistra to control. I think this is something that we need to work together to get it done on the right time frame.

Okay. And the last one, you mentioned both behind the meter and in front of the meter co-location. Do you have any preference? I mean, it almost feels like in front of the meter co-location would have addressed some of the concerns raised in Talent's ISA?

Yes, definitely. First, I believe there will be both options available. The frustration sometimes expressed by participants stems from the perception that these are mutually exclusive. With significant load growth anticipated, particularly for data centers and other electrification and reindustrialization initiatives, most of this will occur in front of the meter. It's simply not feasible to satisfy all requirements from behind the meter. We see both as contributing to load growth, which will help balance supply and demand fundamentals. The behind the meter aspect presents a unique opportunity for us to co-locate, similar to what large customers have done over the past two decades. We can offer a speed to market advantage because the resources required for transmission development are less intensive from a timing standpoint. If we have the land and can deliver a reliable product, we should be able to secure contracts and generate a margin. Therefore, both opportunities are valuable, and we are actively pursuing them with our customers.

The next question is from David Arcaro with Morgan Stanley. Please go ahead.

Hey, good morning. Thanks so much. Could you give an update on your latest views on new builds in ERCOT, how that's going to shake out? How much could we see as we think about this TEF, the final proposals there? And in your view, are prices high enough when you look out the curve to really justify the economics of new build?

David, that's a great question. There are a few points to consider. I've noticed that the curve has been changing over the last couple of months. The perspective we had in early May is different from where we are now. When we analyze the curves, it's clear that these projects face challenges. As a company, we tend to generate more power than we actually serve to retail customers. Therefore, we have to be cautious about reacting to the curves, especially given their limited liquidity. The Texas market presents a unique investment scenario compared to other markets in the country, which I believe the legislature understood. This is why they passed legislation to promote low-cost financing for gas plants, with a maximum capacity of 10,000 megawatts. So far, $5 billion has been funded, and we anticipate the remaining $5 billion could be available either before or during the next legislative session to fully support this capacity. However, we believe that just providing low-cost financing and completion bonuses won’t be enough to justify these projects. While cheaper financing is beneficial, it's crucial to have sufficient revenue for these projects to be viable. The market reforms are essential in this regard. When we announced in May about the 2,000 megawatts, we felt confident about moving forward with our plans, including the conversion of Coleto. We haven’t had any test requests for that and expect to proceed based on the favorable economics. We have applied for the TEF for the two new peakers, and while that loan is helpful, we still need to understand the revenue structure that the market reforms aim to improve. It remains uncertain how much TEF generation will actually be developed, and it's premature to make any predictions. In the long run, it's important not only to incentivize the right reliability assets but also to maintain the existing ones, many of which are quite old, with lives extending beyond 40 or 50 years. We need appropriate revenue signals for that. However, there's disagreement among stakeholders on this issue. Large industrial and commercial users are highly sensitive to costs, as this market prioritizes low energy prices. The stakeholder process is unpredictable, and we'll continue to monitor it actively as it evolves throughout the session. It’s still too early to determine how everything will pan out, especially if some aspects of market reform don’t receive support consistent with the Sunset Bill.

Got it. Very helpful. Thanks for all the color. I'll leave it there. Appreciate it.

Thank you, David.

The next question is from Steve Fleishman with Wolfe Research. Please go ahead.

Just to maybe follow-up on that last question on the TEF. Could you give us a better sense of like when the go/no-go decision might need to be made by you and others through this process for whatever the curves? Yes, when do you have to make a decision really?

At the end of August, we expect to learn about the selected participants moving forward with the TEF process. By then, all market players should know if they advance to the next round of the loan and bonus program. The due diligence process may take some time, and ultimately, an award will be made for the loans. We'll need to assess how quickly those funds will be available, but I expect them to be dispersed by late 2025. Our decision-making timeframe includes completing engineering work, site work, and the interconnection process. We anticipate making a go/no-go decision on some of these peaker projects around early next summer, at which point we will have more information. This is the timeline as we currently see it, and we plan to remain active in the market and stakeholder process leading up to that date.

That's helpful. I have a couple of questions related to numbers. Thank you for sharing the $400 million disclosure concerning the nuclear PTC for 2024, if it had been included. For 2025, you mentioned it would provide downside support. Does that indicate that currently your projections for 2025 are above the PTC floor? Are you saying this without quantifying it yet? Could you provide more details on that?

Sure. Steve, your question depends on which week we're talking about. Literally, right at that PTC floor, and then as of August 5, we're right below the PTC floor. So I think the way we can obviously change our annual views day-to-day, week-to-week like this. But our communication in that range was we merely wanted to reflect the capacity revenue flow through so that you could see that it's not needed to cover some other underlying softness in our business. We feel strongly about 2025 as we did before, and we're adding the $200 million for the capacity revenues. The downside protection comes in, and if curves stayed exactly where they are, maybe we get a little bit more PTC upside. But certainly, if curves came off, you would get a lot more PTC protection. And that's really what we're communicating for 2025, it's not only have we raised the range, but we feel the PTC provides some downside protection that's valuable. You're going to see it in our 2024 results if the regs come out the way we think they are, we're giving you that $400 million number over and above the upper end of the range that we're communicating for 2024. So that's how it works. It isn't always an in-the-money tool, but it certainly provides the downside protection that should give our investors some comfort.

Okay. And then one last question. Just on the upside from the PJM auction in 2025, the $200 million increase. That seems somewhat less than we would have calculated just based on the actual auction outcome. Could you just talk to maybe some of the offsets that might be in there?

Yes. When we consider our numbers for 2025, which we previously shared last quarter, we had revenue projections based on an auction clear that were less than what the auction ultimately proved to be. Thus, we already have a foundation for our 2025 figures. In our business, especially in retail for residential services, we conduct forward sales not only for energy but also for capacity. These contracts are typically not long-term in the residential sector, but they do represent a fixed price commitment for our customers. As a result, you wouldn’t expect full value pass-through. Some commercial and industrial contracts may pass through, but that is not common in residential cases. The $200 million figure reflects a six-month planning period, and there are also benefits extending into 2026. By the 2026/2027 auction, we can anticipate even less retail capacity being forward sold, leading to further pass-through at the current clear levels as we proceed.

The next question is from Durgesh Chopra with Evercore ISI. Please go ahead.

Hey Jim, good morning. Thanks for give me time.

Hey, Durgesh.

Hey, good morning. Hey Jim, I hate to put you on the spot, but the burning question every time we talk to you on the earnings is, when are you going to sign a data center co-location opportunity? This has been asked to you before several times, but just any more color you can share on timing? I understand there's a lot of moving pieces. Just trying to understand whether we can see something this year? Or how are you thinking about potential announcement and timing there?

Yes, Durgesh, that's a tough question, and I appreciate being put on the spot. I can only respond as best as I can. These are large and complex deals that rely not only on our willingness to finalize them but also on the customers' confidence in proceeding. I believe we are making excellent progress with the details. We have strong engagement and thorough due diligence processes, but we recognize that the customers are in discussions with several parties, not just us. There is significant activity in the industry related to power generation as well as with hyperscalers and co-locators, and I anticipate a streamlined process leading to realistic options. For example, there are ongoing discussions in the PJM environment concerning the amended ISA, which does not apply in ERCOT. Comanche Peak is becoming more relevant, and we are seeing some interest there, especially as the conversation around the amended ISA in PJM has started to gain attention. So, Durgesh, it's a dynamic market. That's about the best I can say, and we are working as quickly as possible, but it’s essential for the customers to feel comfortable moving forward. As I've mentioned, these deals are quite large and intricate. However, the fundamentals of our business do not rely on securing numerous data center deals. The supply and demand dynamics we've discussed remain in place, whether for front-of-the-meter or behind-the-meter opportunities. It simply presents a unique chance for our company with many sites and partnerships available, which is an upside for us. We haven't incorporated that into our forecasts and outlook yet, but I can assure you that our competitive team is doing everything we can to close a deal.

Thank you for sharing that information. My second question relates to the ongoing discussions about a potential hard landing and a severe recession. What does that imply? I understand that the long-term dynamics of power supply and demand are a significant benefit for your business. However, what are the short-term implications for power prices and your operations?

We have experienced several economic shocks during our 24 years as a competitive company. In the near term, specifically the next two to three years, we are very confident in our ability to deliver consistent returns. However, as we look towards 2027 and beyond, our business will be more exposed to the macroeconomic environment, including power and natural gas prices, as well as customer demand. Our baseload and residential businesses are both quite strong and tend to be resilient during recessions. For our commercial and industrial sectors, we typically do not assume the risk associated with load fluctuations as we generally sell take-or-pay or fixed quantity products to our customers. Overall, I believe our business is well-positioned. Our track record shows that in softer market conditions, we can reduce the output of some units, cost-effectively buy back hedges from the market, and still maintain our margins, regardless of whether we are generating power or scaling back. While we have demonstrated the resilience of our business model, longer-term considerations regarding capital allocation and investment may arise if we anticipate a prolonged downturn. However, this is not a concern we have in the immediate planning horizon.

Thank you. I appreciate the discussion.

Thanks, Durgesh.

The next question is from Julien Dumoulin-Smith with Jefferies. Please go ahead.

Hi everyone, this is actually for Julien. I hope you’re doing well, Jim and Kris. To follow up on the data center side, I know you haven't signed anything yet. Can you comment on how the discussions about pricing for potential contracts have changed as you begin to evaluate agreements with data center providers? The value of reliable baseload capacity is increasingly recognized. With the recent PJM capacity auction, how do you see pricing trends? How does this affect your comfort level in signing a long-term deal?

Yes, we are a competitive company, and pricing is an important topic for our earnings call. The customers we are working with recognize the value of our nuclear units, particularly their carbon-free attributes, reliability, and the potential speed to market. They are willing to pay for these benefits. It's a competitive process, so we are in discussions with buyers and sellers to agree on this value. We are making progress in these conversations. Beyond the nuclear fleet, we also discuss our gas fleet, which offers different advantages for customers. They may not pay the same premium for the carbon-free attribute, but the gas assets contribute reliability and the potential for grid connectivity, allowing the use of renewables to optimize prices. There are many variables involved that are specific to each deal and customer. The capacity clears are noteworthy; customers will consider these when evaluating costs. The recent auction results indicate that auction revenues could surpass those of previous auctions. The upcoming auction and the current parameters suggest a need for additional supply in PJM, leading us to expect the clears to remain at this level or increase. Customers are perceptive and recognize these trends regarding power costs.

Got it. Thank you. And then lastly, we've been talking a lot about new builds, but these take time to come online. How do you think about buying existing assets? Do you see any opportunities out there? How wide the sort of bid-ask spread has been today?

Yes. We have actually grown our business considerably through acquisition. And I think the history of the IPP sector, unfortunately, has been that brand new assets usually end up trading at a discount. In many cases, the IPPs themselves have not stayed financially solvent and folks have picked up those assets much more cheaply in the aftermath. And so you see that even with a recent sale that was announced of a competitive fleet, largely PJM, where those assets are receiving a value that one could argue is still $0.50, $0.60 on the dollar for new build. And I think that's the challenge with when people look at ERCOT forward curves and we talk to partners about an off-take agreement on a gas plant, for instance, they might look at the forward curves and say it's still cheaper to be leaning on the market and buying on the market than paying for a brand-new asset with a return requirement. That's true whether that's a regulated asset or in a market or that's true, whether it's in a competitive market. So I think we have shown an ability to pick up assets and integrate them and earn the synergies, and we're still open to doing that. There are more assets coming to the market. I think people have seen the value of these gas assets have improved, but they haven't improved to the level that it costs to do new build. And that gap is not closed meaningfully. And so yes, we will be active. We always are active in looking at opportunities. But we'll be looking to see if those two things converge down the road. But right now, there is still a delta.

Got it. Thanks, Jim, and congrats on the quarter.

Thank you.

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

Yes. I just want to thank everyone for joining. I want to thank our team for their continued execution and service to our customers and our communities. We appreciate your interest in Vistra, and we'll continue to work hard to power through the summer months here and deliver on our strategic priorities. And we hope to see you in-person soon. So have a nice end of your summer, and we'll talk to you again on our next quarter call in November. Thanks.

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