Ladies and gentlemen, thank you for standing by. Welcome to Talen Energy Corporation's Q2 2024 earnings call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during the session, you would need to press star one one on your telephone. You would then hear an automated message advising your hand is raised. To withdraw your question, please press star one one again. Please be advised that today's conference is being recorded. I would like now to turn the conference over to Ellen Liu, Senior Director of Investor Relations. Please go ahead. Thanks, Michelle. Welcome to Talen Energy's Q2 2024 Conference Call. Participating on today's call are Chief Executive Officer Mac McFarland and Chief Financial Officer Terry Nutt. They are joined by other Talen senior executives to address questions during the second part of today's call, as necessary. We issued our earnings release this morning, along with the presentation, all of which can be found in the Investor Relations section of Talen's website, www.talenenergy.com. Today, we are making some forward-looking statements based on current expectations and assumptions. Actual results could differ due to risk factors and other considerations described in our financial disclosures and other SEC filings. Today's discussion also includes references to certain non-GAAP financial measures. We have provided information reconciling our non-GAAP measures to the most directly comparable GAAP measures in our earnings release and the appendix of our presentation. With that, I will now turn the call over to Mac. Great. Thank you, Ellen. Good morning, everyone, and thank you for joining us. Before we get into our earnings results and presentation, I'd like to comment on the challenges and opportunities facing our industry as we meet the growing electrification needs of the AI economy. At Talen, we have come up with one creative, cost-effective solution by co-locating a 1-GW AWS data center campus next to our Susquehanna Nuclear Plant. Everyone seems interested in our efforts, our colleagues in the IPP space, regulated utilities, and RTOs. And the issue now sits at FERC's doorstep, where it plans to hold a technical conference on the broader issues this fall. In the investment community, our deal created excitement about increased demand and incremental value creation across the entire power sector, attracting new investors. And I'll admit, it is one of the most exciting times I've seen in my power career. It will drive unprecedented change in our industry, change that will yield great opportunity. The focus has now turned to the question: How will the value creation get shared across companies? The recent high PJM capacity auction prices, coupled with this new demand, have caused people to discuss the repeal of deregulation, RTOs coming apart, states separating from PJM, and to engage in other comments and distracting discussions. These ideas are misguided and miss the point that PJM has been a highly successful, competitive market, keeping prices relatively low and providing reliable electricity and bringing to market nearly 60 GW of new build capacity in the past two decades. This rhetoric creates uncertainty, which, if allowed to persist, chills investment and job creation at a moment in time when we all have an exciting new demand to serve. They also miss the point that the opportunity here is so large that regulated companies, T&D companies, and generators will all participate in the value creation, and in fact, are all necessary for the solution. I typically agree with the saying, "Where you stand depends on where you sit." However, I think at this time, we all sit in the same place. As I see it, it is a win-win for everyone if we can get it right. The IPPs, T&Ds, as well as the customers in the region we serve, who will benefit from increased reliability, lower cost, and much-needed economic development. It's an opportunity for us as an industry to lead. Everyone's talking about 15 GW of backlog here, 5 GW of backlog there, and so on, with respect to data centers. While these estimates seem large, the customer need is really large and a matter of when, and to some extent, where, but not if. How will we, as an industry, rise to the occasion to meet the challenge of electrifying the future? You've heard me discuss it before. The Big Four hyperscalers have a 2024 CapEx budget of nearly $250 billion, and those estimates have been rising. They're on a pace to spend over $1 trillion by 2028. You can reach a similar conclusion if you look at chipmaker production forecasts. Electrifying that growth in data center demand will challenge the industry to deploy capital for new generation and transmission enhancements in the billions of dollars for every gigawatt of data center capacity when the existing capacity on the grid is insufficient. The generators cannot do it alone, and the T&Ds cannot do it alone. One forecast of data center growth totals 60 GW of capacity by the end of this decade nationally, with nearly 15 GW of that being in PJM. That means we, as an industry, will need to deploy $hundreds of billions to meet this need. This will mean an opportunity for generation developers and significant rate-based growth for T&D companies alike. If we can bring these solutions to the customers and meet the needs of the AI economy, we can help drive economic development for the states we operate in. For every gigawatt of data centers built, direct investment is roughly $10 billion, and the total economic impact is a multiple of 2 to 3 times that when you add the ancillary jobs and investment created. So we really should think about this as a $20 billion-$30 billion of economic development for every gigawatt of data center investment. This is a big economic opportunity for those who get it right: housing, schools, services, jobs. It's no wonder the labor leaders I talk to are highly supportive, and I am optimistic we can get it right. Turning to our specific deal with AWS. When we announced our deal, we did not kid ourselves. We knew we had a solution, one that was quick to market, cost-effective, and reliable, but we also recognized that it is not the only solution. Our behind-the-meter direct connect solution is just one innovative way to solve but 1 gigawatt of the challenge. Many others will have to follow, and the next evolution will need to be balanced, balanced in its form of supply for customers, behind the meter, front of the meter, and whatever creative solution can be developed. Balanced in terms of the appropriate cost-sharing, protecting residential rates, and maintaining grid reliability. Our one deal brings hundreds of jobs and tens of billions of dollars of economic development to the state of Pennsylvania, and importantly for us, the greater Berwick area. Our one deal matters because data centers form in multi-site clusters, so we hope that proving one working model in Pennsylvania is a sign of good things to come for further build-out. While our ISA has been the subject of much debate, we remain optimistic that FERC will approve the filed amendments once PJM responds to FERC's question, and the commission has had time to fully review. We look forward to participating in the technical conference this fall, and I am confident that as an industry, we can meet the challenges in front of us, seize the opportunity to power the AI economy, and do it swiftly so that we can bring about the economic benefits and investment capital to PJM, Pennsylvania, and the entire U.S. I'd like to quickly mention our RMR proceedings at Brandon and Wagner. After the recent PJM capacity auction results, people have asked us if we're going to change course from the RMR process. Said simply, no. That's not how it works, and it's more complicated than that. So as long as we are paid a fair rate, we are committed to the RMR process and are working with stakeholders in settlement discussions before FERC to try to reach an agreed-upon rate that will allow us to stay online. That said, we are willing to consider repowering the site and potentially adding batteries under the right circumstances. This could make sense and could potentially eliminate costly transmission upgrades. We look forward to continuing the process and finding a solution, as I said, with all stakeholders. I look forward to your questions on these important matters and will now turn to our key highlights for this earnings call. So starting with slide three, Talen has had an active Q2. I'd like to highlight several of our achievements. One overarching theme is the increasingly visible impact of rising power demand through higher prices in both energy and capacity markets. In the Q2, our fleet ran well during periods of unusually high temperatures and demand in PJM, enabling us to capture healthy generation margin, as our gas fleet ran significantly more than it did in Q2 of last year, demonstrating the value of dispatchable generation in a rising power market. Given our solid first half performance, we are raising our 2024 Adjusted EBITDA and Adjusted Free Cash Flow guidance ranges, and the representative midpoints. With respect to the recent PJM auction, our fleet cleared 6.8 GW of capacity at roughly $270 per MW-day in the 2025-26 auction, compared to $50 per MW-day in the prior planning year. This equals $600 million in capacity revenues for the 2025-26 planning year. AWS continues to make progress on its data center campus near Susquehanna. The local township recently granted AWS a zoning amendment that will allow the construction and operation of 960 MW of data centers. And in Q3, we expect to receive $300 million of sale proceeds currently in escrow. Additionally, we reached another strategic milestone by listing on the Nasdaq exchange on July 10, which in turn improved the trading liquidity of our equity, enabled greater access for more investors, and made us eligible for major indices. We are proud of the value that we have unlocked and believe there's more opportunities for value creation to come, especially in the current market backdrop. So please join us at our Investor Day in New York on September 5. I'll now turn the call over to Terry for further details. Thank you, Mac, and good morning, everyone. Moving to slide four, let's take a look at our year-to-date operational and financial results. Our fleet ran well during the period, generating over 16 TWh of power, with an equivalent forced outage factor of only 2%. 53% of that generation came from our carbon-free Susquehanna Nuclear facility, which successfully completed spring refueling outage in April. Importantly, our whole team worked safely, with year-to-date total reportable incident rate of only 0.3. This is in line with or better than our peers, and we continue to emphasize safety as our first priority across the fleet. We leveraged our strong operational foundation and commercial strategy to earn $376 million of Adjusted EBITDA and $165 million of adjusted free cash flow year to date. We continue to prioritize capital returns and balance sheet discipline. Our net leverage is only 2.4 times, far below our 3.5 times target, and we currently have over $1.1 billion of liquidity, thanks to cash generated from operations. This gives us capital allocation flexibility and enables us to focus on shareholder returns. I'd like to take this opportunity to recognize and thank our employees across the company, who have worked safely to deliver impressive operational results. The past couple of months were the busiest time of year for many of our operation team members, as they successfully navigated our spring outage schedule across the fleet. These team members are key to our overall performance as they operate, maintain, and improve our generation fleet and other assets. Without their hard work and commitment to excellence, none of this would be possible. Turning now to the PJM capacity auction results on Slide 5. As Mac mentioned earlier, the 2025/2026 auction cleared at significantly higher prices than prior years, with PJM's reserve margin declining from 20% to 18.5%. Focusing on calendar year impacts, Talen will earn roughly $285 million more in capacity revenues in 2025 when compared to 2024. These results illustrate how Talen is the IPP most levered to PJM's capacity auction outcomes. These auction results are a strong indication of a tightening market, but I will caution that it's currently just one data point. The results also demonstrate the value proposition for reliable, dispatchable generation. Looking ahead to the next auction, we expect supply tightness to persist. Years of low energy margins and capacity prices led to a large exit of reliable legacy generation assets, and investment signals need to be persistent to spur long-term investments in new, dispatchable resources that have 30-year investment horizons. Furthermore, the supply chain for turbines, transformers, and other equipment in the global market presents challenges, meaning that building and bringing a new gas-fired plant online could take 5 years or longer. PJM's parameters for the 2026/2027 capacity auction will be available in late August, and the auction will be held in December, while the following planning year auction will be in June of 2025. Now turning to financial results. For the Q2 of 2024, Talen reported adjusted EBITDA of $87 million and an adjusted free cash flow use of $29 million. Building on our solid financial performance in the Q1 resulted in $376 million of Adjusted EBITDA and $165 million of Adjusted Free Cash Flow year to date. As a reminder, our business is seasonal, and we make most of our money during the core winter and summer months. The Q2 and Q4 are shoulder periods when we typically don't earn as much and often schedule our maintenance outages. Additionally, certain periodic cash payments happen in the second and Q4 that further reduce cash flow, such as our semiannual debt service payments. That said, the Q2 was strong for Talen. In PJM, Q2 weather was unseasonably warm, with Philadelphia experiencing its highest average cooling degree day total since 2014. Additionally, this quarter's average power demand in PJM was the highest Q2 demand seen in the last five years. In this market backdrop, our PJM gas fleet demonstrated the value of dispatchable generation, producing approximately 1.5 more TWh and $20 million more of generation margin than the same quarter of 2023. Turning now to guidance on Slide 7. Based on our solid first half performance, we are raising our 2024 Adjusted EBITDA and Adjusted Free Cash Flow ranges. Our new Adjusted EBITDA range is $720 million-$780 million, with a midpoint that is 7% higher than prior guidance. Our new Adjusted Free Cash Flow range is $245 million-$285 million, with a midpoint 13% higher than before. I'd also like to take a moment to highlight our hedging activity from this past quarter. On Slide 8, there is a graph of average calendar year 2025 and 2026 spark spreads. Spark spreads expanded considerably through mid-April before retracing by the end of June. During this period, our commercial team successfully executed our hedging strategy and added hedges when spark spreads were higher, as detailed on the right-hand side of the slide. Turning to Slide 9, we remain committed to maintaining net leverage below our 3.5x target, along with ample liquidity. As of August 9, our forecasted net debt to EBITDA ratio was only 2.4x, well below our target. We continue to actively engage with the rating agencies and currently maintain positive outlooks with both S&P and Moody's. In addition, we have over $1.1 billion of liquidity, including over $400 million of unrestricted cash. We've taken several actions since the end of the Q1 to optimize liquidity, including remarketing our municipal bonds, which allowed us to terminate $133 million of LCs that were backstopping them. We also terminated over $90 million of other LCs, opening up even more capacity under our credit facilities.... Moving to slide 10. Since the start of 2024, we have returned approximately $930 million to shareholders by repurchasing roughly 8 million shares, or 14% of our shares outstanding. We've executed most of these buybacks through two large transactions. In June, we repurchased approximately 5.3 million shares through a $612 million tender offer. In July, we bought back roughly 2.4 million shares from our largest shareholder for $280 million. We continue to see purchasing our stock as the highest and best use of our capital. We have over $100 million of capacity remaining under the current share repurchase program and are working to refresh that capacity. We will provide a capital allocation update during our Investor Day at the start of September. Moving to slide 11. We achieved an important milestone on July tenth, when Talen rang the opening bell and began trading on the Nasdaq. We believe uplisting to a national exchange has provided several positive impacts for our equity. It improved our trading liquidity and enables a larger universe of investors to access our stock. In fact, we've doubled our average daily trading volume compared to the 3 months prior to uplisting. We also had the opportunity to gain access to several equity indices, including potential eligibility for the Russell in mid-2025 and the S&P starting late next year. With that, I'll hand the discussion back to Mac. Great. Thanks, Terry. I'd like to reiterate how proud we are of what we've been able to accomplish in 14-15 months since we exited restructuring. But we're not done, and we hope to see you at one of our upcoming events. We'll be hosting an Investor Day in New York, as Terry mentioned, on September fifth. Importantly, on that, during that day, we will discuss our 25 guidance, our 26 outlook, and update, as Terry mentioned, on our capital allocation plan, as well as discuss long-term growth drivers of the business. Following the Investor Day, we will be on the road in Boston, Los Angeles, Philadelphia, and New York, and hope to see you there. We'll now open the line for questions and turn it back to Michelle, the operator. Thank you. As a reminder to ask a question, please press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one again. The first question will come from Michael Sullivan with Wolfe Research. Your line is now open. Hey, good morning. Morning, Michael. How are you? Hey, Mac. Doing well, thanks. Wanted to just ask, you know, appreciate your comments on the pending FERC process. I guess, even if this does go your way, the 480 MW, how do you think about the other 480 MW that you'll ultimately have to get approval for, and then also your ability to do any other incremental data center deals in the backdrop of everything going on at FERC right now? Yeah. Appreciate the question, Michael. I mean, look, as I mentioned, we think that, just to their first part, for the first 480, we remain optimistic that once we fully answer FERC's questions, or PJM, in this case, with our help, with PPL answers, that we're optimistic that they'll approve the ISA as submitted. Obviously, we're disappointed that we received a deficiency letter, but perfectly understand the FERC's need for additional time and clarification and wanting to build a fulsome record there as they review the ISA. But to your second point, we were encouraged by FERC also bifurcating the larger, you know, co-locator and data center, fueling the data center AI economy, as I call it, with power, into a separate technical conference, which we'll participate in. Our view is that we continue to move ahead with AWS at the site under the current ISA of the 300 MW that will be approved, hopefully, to the 480. We're optimistic that we get there. And then I do think that we need, as an industry, as I said in my opening remarks, to come together and to find a solution and to find one swiftly, so that we can all benefit in the economic development that powering the AI economy will bring. We think our deal does that. We think there's other types of deals that will do that, and we look forward to that conversation. As far as what we're doing, we just continue to move forward with the site. I mentioned that, you know, we're confident that we will, in the Q3, release the $300 million of escrow as we meet certain project milestones, and we continue to pursue the data deal as signed with AWS. Okay. Appreciate all the color there. And then just, you know, looking ahead to this next PJM auction, any, you know, high-level drivers that you all want to highlight? And then also, as it relates to that, as we just look to the Analyst Day in September, and I think you're going to give some commentary on the 2026 outlook, I guess, how do you get comfort out there, just knowing part of that's going to be this upcoming auction, where results can be variable and you're still fairly open from a hedge perspective? Yeah. So we'll... Michael, we'll give you the marks that go into that outlook so that you can do sensitivities around that. That's our plan for the 2026 outlook. And so, that will include, there is a visible market for 2026 that we'll cite at that point in time when we provide that outlook with respect to power prices. With respect to capacity, obviously, that auction is not until December, and so we won't know the outcome there, but we'll give you an underlying assumption. I would not say it's our forecast, but an underlying assumption and sensitivities relative to that.... What I would, you know, point out, and again, we and Terry mentioned this in his comments, is that as an IPP that is focused in PJM, primarily in PJM, and as an IPP that does not have retail load, we are highly levered to the outcomes associated with this, which we think is a good spot to be currently. With respect to drivers of 2026, 2027, Christopher, you want to, Christopher Morice, Chief Commercial Officer, you want to say? Yeah, look, coming off the heels of the 2025, 2026 clear and the compressed timelines for the December auction, fundamentally, there's not a lot that can change supply and demand-wise, prior to getting to December. So again, absent of putting out a forecast, right, I think the, the pricing backdrop remains constructive, given the tight supply and demand that, that PJM has. We'll get the parameters next week. At the end of August, yep. For the capacity auction. So Michael, more on that to come. I hope that provided some color around it. Very helpful. Thanks. Thanks, Matt. Thanks, Christopher. The next question comes from Angie Storozynski with Seaport. Your line is open. Thank you. So just going back to the co-location question. So there's been a lot of discussion, including with your utility partner, about behind the meter versus in front of the meter co-locations, the sort of a plant operating risk that you assume under the current contract. And also seemingly, you know, no pushback, at least from hyperscalers, towards, you know, bearing those additional charges for transmission under in front of the meter contract. So my question is, how do you see those two structures going forward as you try to potentially contract the second unit and maybe look at co-locations of gas plants? Would you be open to potentially, you know, changing the current deal structure to in front of the meter, again, just to discourage any future pushback at FERC or any other levels? Morning, Angie. How are you? Morning. Good question. Good morning. And a lot to get into there. But I think if we go back to my opening remarks, I... What I see in front of us as an industry, and I can, you know, bring it back down to our deal as you requested. But what I see as a challenge, which is an opportunity for the industry, is significantly large in terms of the investment that's going to be required, in terms of the range of alternatives and solutions that are going to be required. And so when I said balanced, I hope you heard we say front of the meter, behind the meter, and all sorts of new types of models that will be developed in order to serve this growing demand. It is an exciting time, and it poses challenges, but I think that it's also going to be a significant opportunity for generators to invest, T&D companies to invest. But we've got to all get it right, and hopefully, that we can do it in the right way by which it increases reliability and lowers cost to customers, residential customers. And so that and everybody bears their fair cost, which is what I've said. I think with respect to our current deal, my view is that we like our current deal. We think that going forward, will there be front-of-the-meter deals associated with gas units? Yes, possibly. We haven't seen one get done. Will they rely on the grid? Because that's what we're calling front of the meter as shorthand. Yes, I could see where they will be connected and will maintain backup from there. I think that, and eventually, over the next 5 years or so, Terry mentioned about, you know, supply chain issues and about the growing need to construct gas assets. I think over time, that could be a model by which new gas assets get built, which is that they're built and contracted long term through hyperscalers for capacity and then rely on the grid for backup. That can absolutely be held true. What I find somewhat interesting is that we've had one, you know, and I mentioned this, one capacity clear, right? And then one deal, and all of us, all of a sudden, are looking at the opportunity, trying to figure out who gets what. I think the opportunity is so big that we just need to all come together and say all solutions are on the table. Okay, and just one follow-up to that topic. So would you actually expect, you know, like, different, i.e., lower economics for power companies under those front of the meter deals versus behind the meter, just because, I mean, there's a higher transmission fee? Or would the offtaker, the hyperscaler, or any other tech company just absorb this additional cost? Well, until the first one gets done, who knows what the model is? I mean, there are certain tariffs and things that are structured that you have to comply with to do Front-of-the-Meter. You know, we did a unique or novel solution, a creative solution to do Behind-the-Meter. Front-of-the-Meter is going to have to meet the tariffs, and it'll be, I think, a negotiated outcome on really an ISA by ISA, right? Like, you know, each utility will have difference, and they all have their ISA. The PPL, who's the party to our ISA in this agreement with PJM leading that way, has said that they have our Behind-the-Meter solution, and they have Front-of-the-Meter solutions. And I think it's going to take a combination of all of those by which to fill the demand. And I think that as an industry, being able to support all or a balanced approach with a number of different working models is what's necessary in order to drive what I see as significant economic development opportunity. If you look at the forecasts that come out of PPL where we have a lot of our generation, there's 5 GW that is being discussed there. That, if you use the numbers that I was talking about, is $100 million-$150 million of economic development for Pennsylvania and for that region. And my view is, is that that's plenty of opportunity for everyone to figure out how to solve it. Okay. Then changing topics, so we saw some press reports about your coal business. Just wondering if you can comment at all about the future of that business? What we've said is, we don't believe that it's not a strategic asset for us, and we're looking at what are the alternatives with respect to coal, and that's all we have to say at this point in time. Awesome. Thank you. Our next question comes from Ian Zaffino with Oppenheimer. Your line is open. Hi, great. Thank you very much. What- Morning, Ian. Good, good, good quarter. Thanks for all the guidance and all the color. Appreciate it. Question will be on Brandon Shores and Wagner. You know, how are we thinking about the resolution when it comes to that timing? Maybe, you know, I know there's an ask, but how do we think about what maybe the EBITDA impact could be or where that settles, and kind of all the steps to kind of get us to that? Thanks. Yeah. So, first of all, with respect to Brandon and Wagner, we've said we'll participate with all stakeholders to come to, you know, what we think is an equitable solution. We hope to do that by the end of this year. That's our target. There, we've started the proceeding. There's been an ALJ judge assigned, and schedules are being worked through. One of the things, Ian, that, you know, just as a matter of principle, that for us is that we don't talk about matters that are in front of FERC, just like we don't talk about matters that are in front of a judge. We don't tend to try to prognosticate, you know, come to a conclusion as to what's gonna happen there. So, we'll let it be. But what we said is we're looking for a solution for all stakeholders by the end of this year. And we think that that's important because these are assets that if they're going to be run for the next three years, there are certain aspects, physical constraints and things of that nature with respect to the operations of the plant, labor, you know, maintenance, things of that nature, that need to be decided upon. And so that's why we're looking to get this resolved before the year end. Okay, great. Thank you. And then, on the guidance, can you maybe just talk about, you know, what I guess, your expectations are for, for PJM forward pricing, you know, spark spreads, and, and, you know, how they kind of move versus, you know, what you were expecting? Hey, Ian, it's Terry. So with respect to our guidance, what we're using is a view of forward prices here at the end of July. If I go back to the slide earlier in the deck, you can see that spark spreads have sort of bumped around since the start of the year. Since we're 100% hedged for the balance of the year, we really don't have you know, really too much sensitivity with respect to how 2024 will move. So really, there's not a massive sort of impact with respect to changes in sparks. Okay, thank you very much. Our next question comes from Craig Shere with Tuohy Brothers. Your line is open. Good morning. Thanks for taking the questions. Morning, Craig. On Ian's RMR question, just to dig in a little further, how much could a prospective repowering with the best deployment be on those sites? I don't think we've put a number out on what it would take to do that. It's more a matter of time. So if you look at it back when the capacity markets were clearing in that $50 a megawatt day, it was uneconomic to convert the unit from coal to oil. We cannot continue to run the unit without some relief of some permit issues, as well as an arrangement with Sierra Club past June of next year. Now, I think both of those can be resolved in order to maintain reliability under the right construct, and in order to solve the transmission constraints until transmission can be built. But if there's a way by which we could repower the units under a construct that provided an ample return, we would look at repowering that unit to oil and could do so over the next 3 years. We also have a couple in the queue, 100 MW - several hundred MW of batteries deployed across Wagner and Brandon that could also be put in. And if those are a more economic solution to the customers in the region, we would look at doing that. Thank you. Kind of a bigger picture question, I'm sure you're going to address this in more detail at the Investor Day. But one of the ultimate valuation questions is: Is this really a volatile commodity spark spread story, or is this a systemically shifting capacity market, PPA, RMR agreement, much more long-term, stable, recurring free cash flow story? Can you kind of provide some sense or color around that? Sure, Craig, let me start and then have Terry jump in. But if you look at where we are, and obviously we've got the Production Tax Credit, let's start there, with downside with respect to the megawatts that come off of Susquehanna, that provides a floor. There's you know, we can get into the debate about the IRA and whether it continues, et cetera, or all portions of it continue, but right now, that provides downside protection, and we think that that will continue in the future, no matter what the administration. But in addition to that, to your point, we have megawatts that have been contracted up that will eventually reach 960 megawatts through the AWS deal. We've often said that we're looking for creative solutions for adding to that at the Susquehanna site and looking at other sites by which we would then have contracted revenue streams. And so to your point, I think that leads us down the path where a lot of our revenue, okay, and a lot of our margin is going to come through either contracted energy or capacity payments over time, to your point. That said, we've also, you know, changed things since we emerged from bankruptcy. Now that we've got a cleaned-up balance sheet and have ample liquidity, Christopher and the team have been employing, I'll call it, more strategic hedging of looking at how do we capture the extrinsic value associated with the gas asset that sits somewhere in the middle. So they get a capacity payment, but they also provide option value that we've been able to capture, like we did in the first half of this year. So I think it's a combination of all of those, but when you look at it going forward into the future, one of the things that we like about our portfolio is that we're anchored by Susquehanna with fixed-price contracts out there, that over time will reprice, but obviously, it's contracted revenues with a double A credit on the other side of it. That provides for, you know—Terry mentioned that we're right now to, what? 2 point- 2.4. 2.4 times net leverage. Think of it in the future, that that's just going to create incremental debt capacity and even more secure revenue. So either we should have a lower cost of capital, or we have ample room to be-- to increase leverage, all of which create, I'll call it, increased flexibility about how do we see the future. So we like where we are, but I think your, your general, sort of thesis that you had is, is accurate. We're, we are headed towards where we have more contracted revenues and, and capacity revenues than energy on the margin. But it'll take time. Yeah. And Craig, maybe just to add a couple of things to Mac's comments. Right, when you think about Susquehanna, it makes up half of our generation on an annual basis. And so getting, you know, contracted cash flows with a high, high-grade credit counterparty is, is obviously, you know, very supportive of valuation, especially for a transaction that we have that spans multiple years. I think the other dynamic that's really interesting right now is just sort of unfortunately, given the scheduling challenges around the capacity auctions in PJM, we're now in a spot where by the same time next year, we're going to have capacity auction clears for 2026 and 2027, and for 2027 and 2028. And so you're going to have more clarity on the capacity revenue stream across the entire fleet through part of 2028, which should also solidify value and, you know, give more certainty around how you think about, you know, the equity at the end of the day. So, good question and good point on sort of where the contracted cash flows of the business look going forward, and we'll continue to sort of build off of that. Great. Thank you. Our next question comes from Thomas Meric with Janney Montgomery. Your line is now open. Hey, good morning, team. Thanks for taking the time and for the questions, and, you know, appreciate the opportunity for the Investor Day in a couple of weeks in New York. Curious on co-location deals for new build assets and just how the PJM auction potentially changed the price outlook hyperscalers are looking at for co-location deals, whether they're existing or potentially new build into the future? Good morning, Thomas. I think Terry mentioned it during his remarks that it's one data point. That said, you know, one of the things that this demand will drive over time is the need for increased supply. But that need for increased supply needs to be balanced with making sure that the appropriate cost-sharing is done and that residential rates are protected from that, if you know, the build-out is necessary for what I would consider industrial load. I consider data centers to look like industrial load because it's 24/7. It looks a lot more like a manufacturing process than it does a commercial building. And so, I think that what that will lend itself to is that people have a view that there will be inflationary... costs or there will be costs to build out transmission, which is going to increase the cost on the system and build generation, both of those things, and that's what you're seeing reflected in the market. When the market tightens, you see decreased reserve margins, increased capacity pricing, heat rates and sparks have gone up. Ultimate power, just underlying power prices have gone up in the forward curves. They've come back down some recently, but ultimately, it will drive those increases. Now, what I think you'll see in the future is that generation will get built, and it'll be built to serve specific loads under PPAs, whether that's front of the meter, but has an energy component that hedges the energy for these loads, and allows, you know, new generation to get built with an underlying revenue stream, as we just talked about with Craig on sort of having this contracted revenue stream. I think that's highly possible. I think that the challenge will be is being able to get the, you know, the balance sheet and the rest of it right with respect to these entities, because a lot of, you know, SPV type, which is the old build of CCGTs, where you have a single asset, you lever that asset, you hedge it with, with puts, gas puts, typically, or power, just ultimate power purchase agreement sales. Those don't lend themselves to having the portfolio effect, the credit support, the rest of it. So we think we're uniquely positioned in that because we have a portfolio, we have a balance sheet, we can participate in that, and it's pretty exciting. But I do think it should be a combination of all. I think you're going to see that the capacity prices are going to start to show tightness. They haven't for a long period of time. Energy markets have been in the doldrums as well, with the exception of a few weather-driven events, so very temporary pricing, but you're seeing the overall sort of fundamental pricing go up in the market. So I think you're going to see a combination of a bunch of different ways to solve this going forward. Thanks. That's it for me. Thank you. I show no further questions in the queue. I would now like to turn the call back to Mac McFarland for closing remarks. Well, great. Thanks, Michelle, and thanks to everyone for joining us and your questions today. We appreciate your continued support of Talen. As we continue to focus on challenges and opportunities facing the industry, we look forward to seeing you on September fifth. Have a great day. This concludes today's Conference Call. Thank you for participating. You may now disconnect.