Good morning, and welcome to Vistra’s Third Quarter 2024 Earnings 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 third 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 for joining us to discuss our third quarter 2024 operational and financial results. It has been an active year on a number of fronts, and I'm very proud of what the Vistra team has been able to deliver so far in 2024 while setting the stage for long-term value creation. Turning to Slide 5. I would like to recognize the Vistra team for another quarter of hard work and strong operational performance. Through their efforts, we achieved solid quarterly financial results of ongoing operations adjusted EBITDA of $1.444 billion despite a continuation of the milder Texas weather we have experienced most of the year. The consistent execution from our team across generation, commercial, and retail delivered reliable power and customer solutions that reflect the strength of our integrated business model. As you may remember from our second quarter results call, we indicated our 2024 ongoing operations adjusted EBITDA was trending toward the upper end of the guidance range. I am pleased to report that with the results announced today and our outlook for the fourth quarter, we are raising and narrowing our guidance range for 2024 ongoing operations adjusted EBITDA to $5.0 billion to $5.2 billion with a midpoint above the upper end of our previous range. We are also raising and narrowing the guidance range for ongoing operations adjusted free cash flow before growth to $2.65 billion to $2.85 billion. As we noted on our previous results call, our guidance excludes any potential benefit related to the nuclear production tax credit, or PTC, as we await clarity from the treasury around the interpretation of gross receipts. However, based on year-to-date settled prices and the forward curve for the balance of the year, we believe the impact of the nuclear PTC on our 2024 ongoing operations adjusted EBITDA could be approximately $500 million. Moving to our longer-term outlook, we are introducing guidance ranges for 2025 ongoing operations adjusted EBITDA of $5.5 billion to $6.1 billion and ongoing operations adjusted free cash flow before growth of $3.0 billion to $3.6 billion. Notably, our ongoing operations adjusted EBITDA guidance midpoint of $5.8 billion is higher than the $5.7 billion upper end of our previously communicated range for 2025. While our ongoing operations adjusted EBITDA guidance for 2025 is not currently expected to benefit from the nuclear PTC at any significant amount due to the current level of forward price curves, we do expect the availability of the nuclear PTC to provide downside protection in the event prices settle lower. For calendar year 2026, although our current hedge percentage has increased to approximately 64% of expected generation, a meaningful amount of gross margin variability remains. Furthermore, the delay in the 2026, 2027 PJM capacity auction, including the potential modification of the associated auction parameters create some additional uncertainty. For these reasons, we are maintaining our outlook for our 2026 ongoing operations adjusted EBITDA midpoint opportunity of over $6 billion with line of sight to potentially be meaningfully higher. Finally, the third quarter marked an active period of capital allocation and capital returns. On September 16, we announced the acquisition of the Vistra Vision 15% minority interest from our minority investors. We believe this acquisition will be highly accretive to our shareholders with an implied transaction multiple of less than 8 times enterprise value to EBITDA, providing 100% ownership upon closing at year-end and financial flexibility allowed through an extended payment schedule. In addition, the significant share price weakness we experienced in late August and early September resulted in an uptick in repurchases, and we were able to execute in the quarter. In all, we repurchased approximately $400 million of shares in the open market in the third quarter at an average purchase price of approximately $83 per share. Combined with the Vistra Vision 15% minority interest acquisition, which we view as similar to a forward share repurchase program with a deferred payment schedule, we were able to allocate a combined approximately $3.5 billion to the repurchase of our equity at an average indicative purchase price between $80 and $85 per share, roughly a 30% discount to our recent share price. Turning to Slide 6. Our four key strategic priorities remain integral to our strong business performance. As we have previously stated, we believe our integrated business model and comprehensive hedging program provide our stakeholders increased visibility into our future financial performance. From an operational perspective, our team continues to deliver. Our generation team achieved overall commercial availability of approximately 96% for our gas and coal fleet. Our nuclear fleet also had an outstanding quarter with capacity factors averaging approximately 98% for the period as we continue to make great progress on our integration efforts. On the retail side, the team continues to outperform through both strong customer count performance in the Texas and Midwest Northeast markets, as well as disciplined margin management. Finally, we are seeing persistent growth in our large business market segment through longer-term customer relationships as a result of providing solutions to meet customers' goals, including sustainability objectives and budget certainty. Switching to capital allocation, we remain disciplined in our approach by targeting a significant return of capital and executing on attractive growth projects like the Energy Harbor acquisition, while also maintaining a strong balance sheet. As part of this approach, we continue to execute the capital return plan put in place during the fourth quarter of 2021. Since that time, we have returned approximately $5.4 billion to our investors through open market share repurchases and common stock dividends. Chris will cover capital allocation in more detail later in the presentation. But you will see that we expect at least an additional $1.5 billion of capital available to allocate through year-end 2026. This number is net of our current capital responsibilities including the recently announced provision, 15% minority interest purchase, and the recent Board authorization for an additional $1 billion of share repurchases expected to be executed by year-end 2026. Speaking of the balance sheet, our financial position remains strong with net debt at the end of the third quarter at approximately 2.7 times ongoing operations adjusted EBITDA. Although our net leverage is expected to move slightly above 3 times with the closing of the Vistra Vision 15% minority interest purchase, we expect it to fall back below 3 times in 2025. Moving to energy transition, as you know, our approach continues to responsibly balance reliability, affordability, and sustainability while ensuring disciplined returns for our shareholders. The Vistra Vision 15% minority interest purchase is a great example of this strategy as we view the transaction as an attractive investment in our carbon-free assets and retail franchise. In addition to repurchasing the minority interest in our best-in-class retail business. Through this acquisition, we will increase our ownership of nuclear generation by approximately 970 megawatts across our four sites at an average price of approximately $2,100 per kilowatt. We believe this compares very favorably to per-unit costs for other nuclear generation alternatives such as plant uprates, new builds, or additional M&A. Finally, the acquisition will result in an approximately 200-megawatt increase in our solar and storage capacity assets, and we look forward to continued growth in this business through the disciplined execution of our existing project pipeline. As highlighted on Slide 7, this year alone, we have seen numerous announcements of major manufacturing and data center additions by companies spanning across industries. These announcements have spurred heightened awareness and projections of power demand growth. Some grid operators have already raised their expectations for demand growth through midyear updates, while numerous industry observers have published forecasts reflecting an acceleration in power demand across the country. We also discussed this growth dynamic on our first and second quarter calls, specifically highlighting many of the drivers of power demand growth, including the build-out of large chip manufacturing facilities, partially due to the CHIPS Act, the electrification of oil and gas load in the Permian Basin of West Texas, the reshoring of industrial activity, and, of course, the build-out of data centers. As shown in the bar chart on the left, actual weather-adjusted load growth for 2024 in PJM and ERCOT not only exceeded historical rates but is trending toward long-term forecasted levels. We believe the level of growth across both markets confirms our view that load growth is already occurring, and we expect it to continue. While there has been a lot of focus on FERC's rejection of the amended talent interconnection service agreement, or ISA, we believe there will be multiple paths to resolve any issues relating to that project and other similar projects. FERC's ruling was narrowly based on the commission's view that the ISA failed to meet previous FERC precedent, leaving the door open for a refiling of a streamlined ISA. Nothing about FERC's ruling prevents us or other generators from contracting with customers who are seeking to co-locate for their needs. We will need to address open issues and find the path to FERC approval of interconnection service agreements, which we believe is doable. As we've stated before, there will be many large load opportunities that will have a variety of configurations, whether located next to a generation facility or in a more traditional front-of-the-meter configuration. We don't believe there will be a one-size-fits-all approach to this, and there shouldn't be, as customer needs will vary. This transmission is to meet these needs and that of our broader customer base, just as we do today. I'm sure we will discuss this more in the Q&A, but I will turn it over to Kris to provide a detailed review of our third quarter results, our outlook, and capital allocation. Kris?

Thank you, Jim. Turning to Slide 9. While the third quarter did not benefit from the same weather opportunities as last year, which we estimate added approximately $300 million to our earnings in the third quarter of 2023, Vistra was able to deliver solid results due to excellent operating performance and execution by our generation, retail, and commercial teams. Despite lower cleared wholesale prices compared to last year, our flexible generation fleet continued to perform extremely well and maximize available opportunities. Turning to retail, as expected, third-quarter results reflected higher power costs compared to 2023. However, year-to-date results are meaningfully higher compared to 2023 as the team continues to deliver strong customer count and margin results. Finally, our third-quarter 2024 results for both generation and retail benefited from the inclusion of Energy Harbor, which we estimate to be approximately $165 million for generation and approximately $35 million for retail. Moving to Slide 10. As Jim noted, we are raising and narrowing our 2024 ongoing operations adjusted EBITDA guidance range to $5 billion to $5.2 billion. We are also raising and narrowing our 2024 ongoing operations adjusted free cash flow before growth guidance range to $2.65 billion to $2.85 billion. Although our team is executing at a high level across the business in 2024, this latest increase in our guidance range is primarily related to the performance of our retail business. Moving to 2025. The improvement in our outlook is attributable to increased expectations for both our generation and retail businesses, specifically as it relates to retail. We have previously communicated that we expected this business to contribute adjusted EBITDA in the range of $1 billion to $1.2 billion on an annual basis. Due to several factors, including the addition of Energy Harbor and sustained growth in residential demand in Texas and large business market demand across the country, we now expect the annual adjusted EBITDA contribution from this business over the next several years to be in the range of $1.3 billion to $1.4 billion. However, for 2024, we do project our retail results to come in above that range due to a few tailwinds that are one-time in nature. Switching to ongoing operations adjusted free cash flow before growth, the midpoint of our guidance range implies a conversion ratio of approximately 58%, comfortably in our previously indicated long-term target range of approximately 55% to 60%. Of course, our guidance and long-term outlook remain supported by our comprehensive hedging program. Our commercial team continues to be opportunistic in taking advantage of recent power market volatility, increasing our wholesale hedge balances to approximately 96% for calendar year 2025 and approximately 64% for calendar year 2026. Turning to capital allocation on Slide 11. Our share repurchase program has generated significant value for our shareholders. Since beginning the program in November 2021, we have reduced our shares outstanding by approximately 30%, repurchasing approximately 158 million shares at an average price per share below $2. Notably, this reduction in our share count has led to an approximately 46% increase in our dividend per share since Q4 2021. Moving to the balance sheet. As of the end of the third quarter, our net leverage was comfortably below our long-term target of 3 times ongoing operations adjusted EBITDA. Although we expect that ratio to move slightly above 3 times when we close the acquisition of the 15% minority interest, we expect to delever quickly and be comfortably below 3 times by year-end 2025. Importantly, our business remains well capitalized, and we continue to manage the balance sheet in a conservative way, as evidenced by the recent upgrade of our corporate credit rating to BB+ by Standard and Poor's. Finally, we will continue to be opportunistic and disciplined in the deployment of capital towards growth. To that end, we expect to spend approximately $700 million in 2024 and 2025 as we execute on our development project pipeline, including the recently announced solar projects for Amazon and Microsoft. Of course, we will continue to pursue opportunities to fund those expenditures with third-party capital, including nonrecourse loans. Finishing on Slide 12. Based on our guidance for 2025 and our current expected 2026 ongoing operations adjusted EBITDA midpoint opportunity of at least $6 billion, as well as our expectation that we will continue to achieve our targeted long-term ongoing operations adjusted free cash flow before growth conversion rate, we project to generate a meaningful amount of capital through year-end 2026. We also expect our net leverage, excluding our nonrecourse financings, to reduce materially as our earnings power improves, providing additional capital flexibility. As you can see, our current capital allocation plan through year-end 2026 continues to focus on shareholder return with over $6.5 billion allocated to the Vistra Vision 15% minority interest purchase, common and preferred dividends, and expected open market share repurchases comprised of the approximately $2.2 billion remaining under the existing authorization through 2026, including the additional $1 billion share repurchase authorization announced today. However, despite the significant amount of capital already earmarked for shareholders, we still expect to have approximately $1.5 billion of incremental capital available for allocation through the end of 2026. Because this amount is based on $6 billion of ongoing operations adjusted EBITDA, we see the potential for upside to this amount. As highlighted on the previous slide, over the last three years, we have been significant buyers of our common stock, including jumpstarting the repurchase by issuing preferred equity. However, it is important to remember that the decision to repurchase our stock was only one aspect of our capital allocation framework. We sought to balance capital return, maintaining a strong and resilient balance sheet, and executing on opportunistic growth. We expect this framework to continue to guide our capital allocation decisions not only through year-end 2026 but also over the longer term. Importantly, our return thresholds for both organic and inorganic growth have not changed, and we remain disciplined in choosing the opportunities we pursue. I do think it is also important to note that we still see our shares trading at an elevated free cash flow yield, especially when compared to the average free cash flow yield for companies in the S&P 500, and we continue to believe allocating capital to share repurchases is an important priority. With that, operator, we're ready to open the line for questions.

The first question comes from Shar Pourreza with Guggenheim Partners. Please go ahead.

Hey guys. It's actually James on for Shar. Good morning and thanks for the time. So I guess maybe just coming back to the Susquehanna ISA and some of your prepared, I guess, how has the rejection impacted your customer conversations in the past week? One of your peers sounds committed to co-locations and other maybe more focused on front of the meter. I guess, where do you fall kind of within those soup polls? It sounds maybe a little more like colos, but just any more color there would be helpful. Thanks.

James, we were disappointed with the ruling last Friday. But I think if you look at our discussions on this topic in the past, we've acknowledged that these are complicated deals. They take time; they're large even by the standards of the customers that we're talking to. Then if you look at the quantity of deals that this country is going to do, the vast majority of them are going to be front of the meter. It's unique to have the large sites that we have and have an opportunity to do a co-located deal. We think there are multiple paths forward on this. We're not 100% sure how the other parties that are obviously active on that particular ISA you're going to want to pursue it. But nothing precludes us from still moving forward with our plans. I would acknowledge that everyone is looking at these types of issues and how do we work through them because they are novel. I mean some of the co-located deals even that we've done were smaller. And so when things are of this scale, there are more questions that need to be answered. But we think there's multiple paths forward. We can go into some details as to how we think that might play out. But our conversations are still continuing. We still have a number of really good options, both with our nuclear sites as well as gas sites and potentially the new build. And so I don't think that this is a load profile and a customer base that is going to slow down in aggregate. I just think it comes down to which areas of the country are more open to this? Are they able to attract this load because it's a huge economic development opportunity? We will have to see how that plays out, and it could play out differently in different parts of the country. So I just think that's where we are, and it's a process. And we're going to work through it with our peers in the industry, the vertically integrated utilities. Obviously, the ISOs and any of the other stakeholders as we need.

Okay. Great. And then maybe just kind of piggybacking on that. If we could touch on your thoughts around additionality. Just we heard some commentary from certain members of the PUCT in recent weeks kind of calling for it. So I guess at this point, do you think a colo in ERCOT like Comanche Peak would have to come with additionality? Maybe just some more general thoughts there. Thanks.

Yes. I do think there are a couple of issues obviously at play here. One is resource adequacy in general, right? So even without the additional data center load that could come to, say, Texas in this example, there have been questions about whether there's adequate price signals for new investment regardless of just the data center load. In fact, the data center load over the next 5 years to 6 years will probably not be the largest source of load growth in ERCOT. It just so happens, though, when you start talking about the data centers, it looks like one big chunky load coming at a time, so it gets the attention. As you know, we've put out our announcement of our intention to add megawatts in ERCOT, both with the Coleto Creek conversion as well as the augmentation of existing gas sites; those two alone are going to bring 1,100 megawatts. The peakers are projects that we're still developing still need to see some of the market reforms come to fruition to make those economic or contracts that could come from bilateral contracts with customers can make those kinds of projects feasible. So I don't think this is a discussion that you can solve with just a rule because we've got multiple customer classes coming that are bringing additional load requirements to ERCOT. But I do think that the objective of the customers that we're talking to, they want to see resources added. They're not looking to see the grid become tighter and tighter either. So we are very active in the discussion about what additional resources we can bring potentially even in addition to the ones we've already announced. And we hope that if that is a compact that works for all the stakeholders that could help set a confidence that welcoming the load to Texas or any part of the country is actually going to send the investment signal for the supply side, and having discussions about whether we may or may not want the load can actually create its own problems. And so we've seen many cycles in this industry. People are prepared to invest and build if the signals are there. I think this is more than just a typical load coming to the market. This is a unique opportunity for regions of the country and specifically for the U.S. to lead on this topic for such a critical load and use artificial intelligence. I hope we all see it that way, and that's been our main focus in our discussions with policymakers.

Excellent. I’ll leave it there. Thank you.

Thank you, James.

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

Hey thanks, good morning.

Good morning, David.

Could you provide a bit of follow-up on your comments? We heard from Encore that they're seeing over 80 gigawatts of data centers looking in their service area, at least in the pipeline. Given that scale, there must be a variety of approaches that these data centers are considering. So, what are you observing regarding interest in co-location at your gas plants in ERCOT? Also, could you elaborate on the idea of new builds? Are you currently in discussions with potential data centers for possible partnerships or contracts for a new plant build?

Sure. David, great question. I'm going to start, and I'm going to ask Stacey Doré, our Head of Strategy, to comment on this. She's working on these types of opportunities on a very near full-time basis. It's certainly an active time for all those types of conversations. I'd start with load forecasts have been obviously extremely robust in ERCOT. CenterPoint put out some information about the kinds of load growth they're seeing in their territory, certainly Encore through the separate call yesterday, and ERCOT itself has revised the middle of the summer long-term load forecast. We've been a bit more conservative only because we believe still it's hard to understand the full duplication that could exist not only within a state but even across the country because folks are looking for PaaS to get speed to be able to bring this load. And so they're exploring all options. I do think that demand, if we can satisfy it, I do think Texas is probably as well positioned as any part of the country to satisfy that demand. And we certainly want to be part of that, not only on providing the relationship for the load, but the potential addition of resources. So I'd like for Stacey to provide some color on the types of conversations we're having and how we're working with Encore, with CenterPoint, and ERCOT to make sure that we can all solve this together.

Thank you, Jim, and thank you for your question, David. We are actively seeking opportunities at various locations in our portfolio. We are also initiating discussions with developers about a portfolio strategy that could allow us to pursue co-location agreements with a single customer across multiple sites, potentially including the construction of new facilities. We are engaged in detailed discussions with customers at some of our nuclear sites where there is significant interest. Additionally, we are in ongoing conversations with various development companies regarding several of our gas sites in PJM and ERCOT. We are also in early talks with some hyperscalers about nuclear upgrades and new builds, as Jim noted. Moreover, we are in discussions with two major companies about constructing new gas plants to support a data center project. These discussions vary in nature and involve multiple companies across different sites. We are also including stakeholders in these talks, ranging from policymakers to the relevant transmission and distribution utilities. As we have mentioned previously, the diligence process for these agreements is lengthy and requires considerable effort, as they involve long-term power purchasing commitments. We are dedicating significant time and resources to these discussions and are excited about the opportunities ahead. We believe that jurisdictions like Texas, along with Pennsylvania and Ohio, are very open to accommodating this demand due to the economic benefits it provides. Therefore, these projects involve multiple parties in conversation.

Thanks for that. It makes sense just given the staggering scale here that so many options are under consideration. And I guess maybe to ask it more directly to in terms of Comanche Peak. Have you seen Comanche Peak becoming better positioned here just after seeing the FERC challenges that have popped up in PJM? Like has urgency increased there? And just would be curious your latest thinking on what the timing of a deal could potentially be?

Thank you, David. Our discussions regarding Comanche Peak have been ongoing for a while, and there is clearly interest in that location due to its speed-to-market advantage, even prior to the FERC decision. ERCOT offers one of the fastest interconnection processes in the country, and Texas takes pride in this efficiency, with the TDUs and ERCOT collaborating to facilitate load interconnections. Consequently, the fact that ERCOT is not under FERC jurisdiction and the recent order has further enhanced the appeal of Comanche Peak, although it was already attractive before the FERC order. However, it's challenging to determine exactly when we can finalize discussions since there is still significant work needed and numerous stakeholders involved, including ERCOT, policymakers, Encore, and local officials. We are deeply engaged in that process and are actively pursuing this opportunity, which represents a significant prospect for Vistra and our customers.

Okay, great. Thank you.

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

Hi, I guess I'll dare ask one other question on this topic, which is just Texas has emphasized availability of resources at kind of emergency or peak times and the like. Do you see solutions in ERCOT where you could have the generation even if it's co-located, available for kind of the more sensitive periods?

Yes, Steve, we do. We have even noted, I think, in previous discussions, customers are learning how they can also manage their load during emergency conditions. So whether it's something around a load response or whether it's the backup generation that could be also configured at the site. Again, I think these large customers are responding to some of the questions that they're receiving and the concerns around resource adequacy, and they're showing that they want to be part of that solution. So that is, again, to Stacey's earlier point, why these discussions do take some time, and they're complex is there's a lot of variables that we're managing. So I do think there's going to be some flexibility there, Steve, and I think that will help multiple stakeholders become comfortable with it.

Okay. We just had a significant election outcome, and although it's only been two days, I'm curious about what this might mean for both new gas builds and your coal fleet.

Yes, Steve, the election prediction business is challenging, as is the policy prediction business. We are considering the GHG rule, which is currently facing legal challenges in the DC circuit. This rule may be revised in the future. The current administration's decisions have impacted not just coal units but also new gas projects. We will have to wait and see how this develops, which could take some time, but it seems to be more open conceptually right now. Returning to the topic of resource adequacy and the changes in administration, evaluating 30 to 35-year assets against policy shifts that occur every four years is a complex challenge for investors. One aspect I appreciate about our business model is our diversification. We operate in various major markets across the U.S., with a mix of technologies. While our largest segment is gas-fired generation, we also have nuclear, a declining coal business, and a growing solar and battery segment. Our retail business is significant and expanding, complementing our generation operations. Assessing the potential impacts of policy changes is difficult, but we have proven to be adaptable as a company. We aim to seize the opportunities presented by the market. I wouldn’t categorize this as standard for Vistra; however, adapting has been a significant part of our history in the competitive market. We are open to the technologies mentioned, which are vital to our portfolio, and we will see if some of these can have extended opportunities, but it is too early to determine.

Okay, and one last quick question. You mentioned the possibility of exceeding $6 billion in 2026. Can you elaborate on what you mean by "meaningfully"? Also, if the PJM auction prices at levels similar to the last auction, could you provide more insight on that? Is that the main factor, or is it more related to ERCOT pricing? Any additional details would be appreciated. Thank you.

Steve, I'm going to let Kris take this one. Good question. We know words matter, and that would be one that you pick up on. So Kris?

Yes, Steve, I believe it's a mix of factors. Currently, we are 64% hedged, and we are making progress in that area. However, if we take a look at our guidance for 2025, it has a range of plus or minus 5%, and we are 96% hedged for that year. As we look ahead to 2026 with only 64% hedged, we can expect the range to be a bit wider. You also mentioned the PJM auction, which is a significant aspect. Therefore, we believe it is wise to maintain a target of $6 billion. If the auction results are similar to the last one and we continue to hedge more, we have accounted for some protection against potential adverse outcomes, which could lead to some upside. Although we will not specify where we see the upper limit, we have incorporated a bit of upside considering the additional hedging and the auction results.

Hi, good morning.

Hey Jeremy.

I just wanted to pick up, I guess, on the diversified footprint as you mentioned there. Just wondering how you think about the ERCOT versus PJM opportunity set at this point in time, particularly in light of the Town ISA ruling granted it's early days, but do you see things like this kind of starting to favor ERCOT more at the margin?

I don't think so, Jeremy. The capacity, again, the ISA is one dimension, but a capacity market construct in PJM is something that I think creates a real opportunity to send a price signal and encourage investment, whether that's some assets that are on the grid to not retire or to bring new assets and obviously meeting the load growth that PJM is now forecasting. That market design does not exist in Texas. And that's something that from a capacity market discussion, where it's an energy-only market. And so it has been a bit more volatile in terms of you might have a really strong summer in 2023, but we've had weaker clears in 2024. So if you were putting batteries on the grid right now in 2024, you're probably wondering if you're going to get a return on those batteries, whereas you might have felt really good about it heading into the summer of 2023. So the ISA is only one dimension. It's important to note that load is low. If this load comes into PJM, whether it's behind the meter or front of the meter, it's load growth. A capacity market should send a signal like it did at the end of July, but there was intervention coming on the heels of that that's now led to a request for a 6-month delay. Again, as I stated earlier, if these markets would consistently run their opportunities for the auction in the case of PJM and for Texas being clear about signaling wanting the load to come, I think these price signals would be there. There'd be investment opportunities in both of them. But right now, PJM has a more structured way of valuing capacity and signaling in a forward curve basis, the need for that capacity than does the ERCOT market.

Got it. Understood on the PJM capacity auction there. But maybe coming back to the power curves, how do you see that evolving over time? Do you think that demand is really reflected in future pricing there? Or how do you see that kind of evolving?

Yes. That would get more to sort of a fundamental view of where do we think the curves are relative to this load growth. And I would say it feels to me, and Steve Muscato, our Head of our Wholesale and generation business can chime in here, but it feels to me that the curves are not factoring in all of this load growth at this point. That there's a lot of forecasts out there; folks are going to want to see more data points that are actually coming to fruition. And we try to put in our presentation, we're seeing that we're on this curve of load growth. We put that in for what we're seeing in 2024. But as noted earlier in some of the questions, there's massive load growth being forecasted by the ISO as well as the wires companies. I would not say the curves reflect all of that coming in at this point. And I think just some of the recency of this summer is also weighing on the curves. And Steve, I would like to have you add some comments to that.

Sure, Jim. I think people are projecting historical load growth from the past two or three years of around 3% to 4% during peak times. They seem to be incorporating that into their models. It ultimately depends on how much of the ENCORE study data, which indicates 80 gigawatts, actually comes into play. The question is whether we will surpass the historical trends we've observed. I also believe there is some recent bias. Unfortunately, power is only liquid up to maybe 2028 or 2029, making it difficult to predict beyond that, and there isn't much activity. The recent results we saw this summer have influenced perspectives because people are trying to understand the significant pricing asymmetry in Texas that we've observed in both winter and summer. Traders will likely pay more attention to the winter premium moving forward because, even if batteries continue to enter the market, as you mentioned earlier, there are challenges since they are affecting revenue streams. Currently, there are so many batteries available that their numbers exceed what the ancillary services can accommodate, which is their main revenue source, rather than through arbitrage. When this is combined with a winter event that lasts longer than just a couple of hours, we may see more scarcity reflected in the winter curves in the future.

And thank you, Steve. And I'd like to add, Jeremy, just two other dimensions. This was the first month that we've seen where the new additions in the queue for solar and storage and wind were actually less than the number of projects canceled or moved into inactive status. So I do think markets have a way of over time rationalizing economics. The other thing I think that's weighed on the curves was the curves looked very attractive in the sort of May 2024 timeframe. And I think the test, the quantity of the test interest and the discussions of continuing TEF, or even having a larger TEF, I'm sorry, I'm saying TEF, Texas Energy Fund. That is something that I think the markets are struggling to figure out how to handicap and look at is that only going to be an incentive for new generation only? Or is that going to send a signal to keep existing generation online? And I think there's still a lot to sort out, I think, on the TEF because we're still in the early stages with the due diligence process, and we're going to enter a legislative session next year. And I think folks are trying to figure out what is the state going to do if they're going to actually increase that quantity of assets qualifying for TEF or if they're going to let the market send a price signal to try to bring that investment. And I think that's still too early to call.

Got it. That's helpful there. That was kind of getting to my last question here with regards to TEF and just your project development activities in ERCOT, especially with the tough considerations that you said there, could you just, I guess, update us overall on your thought process?

Sure. Yes. We did submit two peakers as part of the TEF application. Basically, each party that was selected, was selected for one project. So one of our two peakers was selected. As we stated when we made the announcement in May and have continued to say since then, we want to see the actual development from a market design standpoint make progress. Our reliability standard has been developed. It's not linked to a requirement if we fall below a reserve or there are concerns around reliability is not linked to a market mechanism to procure additional resources in the market, but at least the reliability standard has been designed and will be studied on a periodic basis. The PCM performance credit mechanism is now hard capped at $1 billion. It was a net cap. So presumably, that could mean a lower overall quantity of resources being dedicated to a performance credit mechanism. And there are some discussions about even that being challenged potentially in the legislative session. So I think that in the ancillary services, like the dispatchable reliability reserve service are still to be figured out. Real-time co-optimization is in flight as well for ancillaries and energy that could be bearish for some price formation. And that also speaks to how do we incentivize resources to come into the state to meet the load growth. And I don't think we have all that figured out yet in Texas. And I think that's work that we've got to do as an industry so that we can continue to meet the need. We've designed our projects for the peakers that we're continuing to move forward. The team is working on all the efforts we need on site as well as with our key partners. But we also have off-ramps to both of those peakers if the market developments that we need to see don't occur. And we hope that's not the case because we'd like to bring those peakers, but we've got to make economic decisions. And we're still not there yet.

Got it. Thank you for that.

Thank you, Jeremy.

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

Thank you. So maybe first on 2026, maybe even 2027. So just wondering if by then, by 2026, 2027, you would expect to have any meaningful EBITDA impact from those data center deals, be it colocations or virtual PPAs? And also, if that changes the way you're hedging especially baseload units in those outer years?

Yes, thank you for the question. I would say it's difficult to see it being significant in 2026 or 2027 due to the necessary groundwork and the availability of resources, servers, and chips. This all needs to happen after completing the initial studies. Therefore, the timeline could extend to a 4 to 5-year process before we can deliver a substantial amount of power to a co-located facility. Consequently, this timeline is not influencing our hedging approach for the near term regarding 2026 and 2027. If it were to have an impact, we would start to incorporate it, but we’re more open to 2027 than 2026. We hope that opportunity will allow us to layer it in, but from a guidance or hedging perspective, it’s not on the horizon we have been discussing with the market regarding our earnings potential.

Okay. And then changing OpEx. So a lot of discussion, obviously, in your nuclear plants. You have many more gas plants. Can you just give us a sense directionally about the pricing differential for nuclear assets versus gas assets? Is it as simple as just the carbon-free attributes? Or again, just even directionally, how these prices compare and the discussions that you have with the data centers? Thank you.

Thank you, Angie. We prefer not to disclose pricing differences by asset class. However, I've previously mentioned that customers view this as a list of preferences, considering factors like location and energy needs for cooling. Various variables will impact how valuable this is to customers in terms of speed, land, water, and others, which will influence their willingness to pay for different locations. I don't expect gas assets to command the same premium as nuclear due to nuclear's carbon-free attributes, but there is a positive openness towards gas that we find encouraging. The flexibility of working with these assets appeals to several entities, including co-location partners that are not directly hyperscalers. That summarizes our perspective on the matter, Angie.

And then last one, I know I promised Eric, just one question. But could you comment about the transmission capacity around your PJM assets, especially the Beaver Valley. So for example, if there were to be a need for a virtual PPA in like in front of the meter deal for that asset, is the transmission sort of overbuilt around it? Or do you have to wait for upgrades?

Yes, I'll start, Angie, and I'll ask Stacey for her views, but we sit in a pretty balanced area where we are from a congestion point of view with locations we have, the three locations there in PJM. There's still going to be study processes and efforts to connect load even if there is a perceived capacity available on the transmission system, because there is still studying to be done about what adding load and particular spots are going to do to the whole system. And I don't think we view it necessarily as it's going to be faster or slower if there is some capacity or not; I think it's probably going to be slower if it's front of the meter versus co-located. And I think that's what we need to work. Again, we may end up doing both in the area and that region of the country. Stacey, anything you'd like to add to that?

I would just add that at Beaver Valley, we do have a necessary study agreement. It's already been studied that a load could be co-located there without negative impacts to the grid. And so I agree with Jim that it's the benefit of co-location and the reason customers are pursuing it is for speed to market. So it will be faster than front of the meter. Having said that, again referencing what Jim said earlier, there will be plenty of front-of-the-meter connections as well. And to the extent we can serve those customers with their front of the meter connections, we're certainly open to those discussions and having some of those discussions as well.

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

Yes. Thank you for joining us today. I want to thank the team for their continued execution and service to our customers and communities. We appreciate we're having this call in a very dynamic time. And I can just assure you our team is focused on delivering. We appreciate your interest in Vistra, and we certainly hope to see you in person soon. Have a great rest of your day. Thank you.

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