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Good morning, and welcome to the Vistra Second Quarter 2024 Results Conference Call. All participants will be in listen-only mode. [Operator Instructions]. After today's presentation, there will be an opportunity to ask questions. [Operator Instructions]. 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 explains 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 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 build, 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. Kris?

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 to 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. [Operator Instructions]. 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 provides 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.

Right.

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. Yes, good question, Shar. So when we first announced the $6 billion plus, we were talking about this on the May call. Curves were actually quite strong at that point in time in the market in Texas and PJM, frankly, across the country. As you know, the curves have come off quite a bit. We were about 50% hedged on that call. Now we're about 55% hedged. So we have seen some gross margin for particularly the unhedged portion, erode some of the 2026 earnings. But we had a sense because of our open position, Shar, we wouldn't have put $6 billion plus out if we couldn't handle some volatility in the curves because that's just the nature of the business we're in. With this clear, obviously, that captures only part of 2026 and this auction coming up in December will capture the other part of 2026. We did not revise the 2026 number. As you noted, we did revise 2025. I think with these -- with the clear we've had, in this upcoming clear, we are strongly above the $6 billion plus figure, but we're going to refresh that next quarter. When we come out next quarter, we'll give you a 2025 guidance number, which is not what we've provided today. We merely reflected the auction clear for 2025, and we'll give more visibility into 2026. But the business has been very resilient. And I think these -- the diversification of our fleet, plus having the retail business, the earnings power of the business is strong.

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 that -- the technical conference, has that slowed any of the conversations you've been having with customers around co-location opportunities? Thanks.

Hey Shar, it has not slowed. The conversation is down. I think, first of all, these conversations are numerous. They are not only are there a lot of customers having -- that we're having conversations with, but they're having conversations with a lot of potential suppliers like ourselves. We're making really good progress with our customers. We're in due diligence for a number of sites. Clearly, this process, including a technical conference will -- it is of interest to folks. But these are some long-dated conversations and these are sizable decisions that folks are making. If they contract for one of our larger sites, for instance, they could be approaching $1 billion a year in power costs at a single site. So these take time to evolve, but it has not slowed the pace of play. I think there's going to be plenty of data center load behind the meter or co-located and also front of the meter. I think there's going to be plenty. And I think they're evaluating these customers are evaluating all their options. So we'll see how the technical conference goes. We're clearly in support FERC approving this amended ISA. We think the record is very clear on that, but more to come, and we're going to stay active, as I know all of the market participants will. But this is a really big opportunity for our industry to meet customer needs. And frankly, create a lot of jobs, a lot of economic development, and I hope as an industry we don't get in our own way here and that we're able to see that this load growth is really beneficial for our economy broadly. And we expect these conversations to stay active until we get to a decision with a couple of key customers, which we're pretty optimistic about.

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. So just continuing on this topic of the co-locations and general, the load growth. So we're seeing some raised conversations from wires on the utilities and competitive markets, PJM, in particular, they are seemingly concerned about the load growth and reliability of the electric service over the next couple of years as this load materializes. And so that led to some concerns about potential interventions in competitive power markets, regulated new build, you name it. And that seemingly is not just response to the new build projections, but also to this last PJM capacity auction. I mean, it's somewhat concerning, right, because the same parties were not raising their hands to support merchant power plants when power prices were super low. And seemingly, it should be a cyclical market where we should spikes in power and capacity prices to incentivize new build. So I mean, how do you manage this narrative? Do you sort of rush your assets to contract them to protect them against any sort of market interventions? Is it just -- do you think that this is just a rhetoric that will pass? Is the basically the pull so big that all parties can benefit? I mean my take has been that just -- that goes to show that wires on the utilities know that the best way to benefit is through generation assets, but I'm just going to wonder how you're going to approach that.

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, absolutely. I think -- first of all, I think there's going to be both. There is -- this is -- the frustration, I think, that comes into this discussion at times from players is everybody views these as one or the other. There's so much load growth, and if you follow what folks are looking at, not only for data centers, but other sources of electrification and reindustrialization there's going to be a lot -- the vast majority will be front of the meter. There's just no way to meet all of these needs behind the meter. So we view that as load growth in either way and that is going to help supply demand kind of fundamentals. The behind the meter piece is just a unique opportunity really for us to co-locate much like other large customers have done for the last 20 years, and we can provide a speed to market advantage because there should not be the same level of resources needed to build out on the transmission side simply from a time frame perspective. When if we've got the land and the ability to provide them the reliable product that they're looking for, we should be able to contract and earn a margin for doing so. So I think both of those are valuable opportunities, Angie, and we're pursuing both 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 newbuild 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 newbuild?

And David, great question. So a couple of things there. I do think the curve is coming off in the last couple of months, just starting there in and of itself is a different view than where we were even sitting in the first week of May. And so if you just simply look at the curves, these projects are challenged. And I think we're a long -- a net long generator as a company. We have a lot more generation length than we serve retail load. So if we only were looking at the curve and the curve is not that liquid, so you can't overreact to the curves in early May, and you can't overreact to the curves here in early August. But on a curve-only basis, the Texas market is a different investment construct than other markets in the country. And I think the legislature recognized that. That's why they pass the test, and then the Sunset Bill last session, they also put in a couple of other things to work on some reliability reserve service, which is a new ancillary, and they also codified the performance credit mechanism. So in our view, what the Texas legislature did, would say we need to provide some low-cost financing to encourage gas plants to be built. And that has a maximum of 10,000 megawatts. So regardless of how many had notification of interest and how many are in the application process, the max is 10,000 megawatts. That was expected to have $10 billion of funding to back it. And right now, they have funded $5 billion. But it's likely the additional $5 billion could come, before the next session or during the next session, to fully fund up to the 10,000 megawatts. Our view is that low-cost financing and some completion bonuses alone would not make these projects justifiable. The lower cost of financing is helpful, but you still need adequate revenue to be able to make these projects work. So the market reforms we believe are very important part of the overall package. And when we made our announcement in May about the 2,000 megawatts, we're comfortable proceeding with the augmentations. We're comfortable proceeding with the conversion of Coleto, and we don't have any test requests for that, and we expect the -- given the economics of those, those would move forward. However, we did file for TEF for the two new peakers, and we think that the TEF loan is, again, helpful, but we also still need to see the revenue construct that the market reforms are intended to help address. We don't know how those are going to ultimately shake out because there's been so much interest in the TEF that I think some folks believe that maybe that's enough to address the concerns around grid reliability in Texas. We're not sure how much of the TEF generation ultimately gets built. I think it's too early to tell. But for the long-term, not only to incentivize the right reliable -- reliability assets, but also to preserve the reliability assets that are currently on the grid, some of which are aging quite -- to quite long lives, 40, 50 years plus, there needs to be some revenue signals. Not all stakeholders in agreement on that. The advocacy from the large industrials and commercial customer base is very price sensitive, very cost sensitive. This is a market that values low energy prices. So I don't know how the stakeholder process will ultimately work out. We're going to monitor that from here, and we're very active in it, and we'll see how it develops throughout the session. But I think it's too early to tell how all of this is going to come to fruition, especially if some of the market reform aspects are not supported through the end of the process, consistent with the Sunset Bill at SB3.

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?

So at the end of August, we expect to hear who's been selected from a due diligence perspective to move forward with the TEF process. So on the loan and bonus program, Steve, I think all market participants will hear by the end of August, whether they make it to the next round. And then the due diligence process can take time. And ultimately, there will be an award made for the loans, and we'll have to see from a timeframe perspective, how quickly those monies will be made available. I believe they need to be dispersed. I'm going to look to stay through real quick by late 2025. And our timeframe, Steve, in terms of our decision making is that we have engineering work, we have site work, we have the interconnect process we're working through. We anticipate a go/no-go decision on some of these -- on the peakers to line up probably closer to early next summer. And then we'll have a lot more information at that point in time. But that's the timeline as we see it. And obviously, we expect to learn more, and we'll be active in the market and the stakeholder process between now and then.

That's helpful. And then a couple, I guess, maybe numbers questions. You -- thank you for that disclosure of the $400 million that you would have had from nuclear PTC in 2024, roughly, if you included it. You then say for 2025 that it would provide downside support? Does that mean that on average right now for 2025 you are above the PTC floor? Are you just trying to kind of -- you're not really -- you're just saying that because you're not quantifying it yet. Just could you give more color 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. So when we look at putting out our numbers for 2025, that we had already disclosed last quarter, we had a revenue assumption on an auction clear -- embedded in that than half, Steve, what the auction clear turned out to be. So we've already have a starting point in the 2025 numbers. And then if you look at how our business works, particularly in the retail piece on residential, you do some forward sale of not only energy, but capacity. So those are not as long dated of the deal, particularly in the residential space, but you have some of that, which effectively is a fixed price commitment for customers. So you wouldn't expect that to pass-through at the full value. Some of the commercial industrial contracts would pass-through. But on residential, it is not typical to be passing through the capacity piece. So when you see the $200 million, obviously, that six months of the planning period. And then, of course, there's 2026 benefit as well. By the time you get to the 2026/2027 auction, there's even less retail that would be -- that would have forward sold capacity. So you would see even more flow through at these levels of clear as you move forward.

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, it is a hard question to answer, and I don't mind being put on the spot. I can only answer the question the best I can, which is, these are large complicated deals and they do depend on not only our desire to get one done, but the customers' comfort with getting these deals done. I do think some of the details we're working through extremely well. We have strong engagement and due diligence processes but we know that they're having conversations with multiple parties, not just Vistra. So there's a lot of work in the industry from a power generation as well as the hyperscalers and co-locators, and I do think that there's going to be a process of the funnel working its way down to realistic options. For example, with the questions being raised in the PJM environment regarding the amended ISA. Well, ERCOT does not have that same jurisdiction. So there's a Comanche Peak on a relative value perspective, step up in the process, and we're seeing some interest in Comanche Peak and even as these discussions with PJM have started to become more public on that amended ISA. So Durgesh, it's a dynamic market. It's about the best thing I can say to that, and we're moving as fast as we can, but it does take the customer side to be comfortable with this. As I mentioned, these are very large complicated deals. So our fundamentals of our business, Durgesh, they don't depend on doing a lot of data center deals. I think the supply/demand fundamentals that we've talked about, they're there, whether they're front of the meter or behind the meter, it's just a unique opportunity for a company like ours with so many sites and so many opportunities to partner directly with customers, it is upside. And we have not baked that into our forecast and our views. And so -- but I can tell you we're a competitive bunch that our team is working as hard as we can to get to a deal.

Great. Thank you for sharing that color. My second question is that just as we -- there's a lot of chatter around a hard landing scenario here, a bad recession, what does that mean? I know the long-term power supply demand dynamic is a major tailwind for you. But what does that mean near-term implications on power prices and then for your business?

We've been through some economic shocks a number of times in our 24 years as kind of a competitive company. Obviously, the near-term, and when I say near-term, the next two years to three years, we feel really strong about our ability to generate consistent returns. But as you move out into 2027 and beyond, our business is going to be more open to the macroeconomic environment. That's not only power price and natural gas price levels, but also just the customer demand is the demand there. We have a very healthy baseload business and a very healthy residential business that tend to be pretty recession proof. And most of our business that's commercial and industrial, we don't have contracts where we're taking sort of the swing or the load risk in that. We tend to sell more take-or-pay or fixed quantity type products to those customers. So I think our business is set up well, Durgesh. I think it's a business that has shown that even when things get soft, we're able to back down some of our units, buyback hedges in the marketplace cost effectively, earn margin, whether we're generating or whether we back down. So I think we've proven the resiliency in the business model, but certainly, long-term, it make you think about your capital allocation and your investment, if you really thought we were at a prolonged sort of downturn. But that is not -- that's not anything we'll worry about in this near-term planning horizon.

Thank you. I appreciate the discussion.

Thanks, Durgesh.

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

Hi guys, it's actually [indiscernible] for Julien. Hope you are well doing, Jim and Kris. So to follow-up on the data center side, I know you haven't signed anything yet. But maybe can you comment on how the discussion on pricing for these potential contracts has evolved to start evaluating contracts with data center providers? Like the value of reliable baseload capacity is getting more and more recognized. You just had the PJM capacity auction. How do you see pricing trending? And how does that play into your level of comfort into signing a long-term deal?

Yes. Well, we are a competitive company and pricing is a sensitive topic to be discussing on our earnings call. But I would say that the customers that we are engaged with understand the value of -- particularly on the nuclear units, they understand the value of the carbon-free attribute. They understand the value of reliability. They understand the potential speed to market benefit and they're willing to pay for that. I mean, again, you're in a competitive process. So other people are offering that, that have similar resources to Vistra. So this is, again, a buyer and a seller needing to reach agreement on what that value is. But we are having those conversations, and I think those are moving along well. Ultimately, there's more options than just the nuclear fleet. The gas fleet is also part of the conversation, and they provide other benefits for customers. They wouldn't necessarily be paying the same premium for the carbon-free attribute. But obviously, the gas assets provide reliability. They provide the opportunity to potentially be grid connected in some cases and use the renewables that are on the grid to optimize price for the customer. So there's a lot of variables to this that are going to be deal and customer-specific. But the capacity clear was noted. I think that's something that a customer, whether front of the meter or behind the meter, they're going to be looking at these kind of capacity clears as something that load is going to need to pay. And so I do think that it was a little bit more unclear before this last auction, that the auction revenues might actually be more than what they've been in previous auctions. I think this auction and the parameter shaping up for this December, show that there is actually a need for more supply in PJM. And so we'd expect the clears to stay at that level or higher, and we know that customers are savvy and they see this coming from a power cost perspective.

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.