Talen Energy Corporation (NASDAQ:TLN) Q3 2024 Earnings Call Transcript

Talen Energy Corporation (NASDAQ:TLN) Q3 2024 Earnings Call Transcript November 14, 2024

Operator: Ladies and gentlemen, thank you for standing by. Welcome to Talen Energy Corporation Third Quarter 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. [Operator Instructions] Please be advised that today’s conference is being recorded. I would like now to turn the conference over to Ellen Liu, Senior Director, Investor Relations. Please go ahead.

Ellen Liu : Thanks, Michelle. Welcome to Talen Energy’s third quarter 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.

Mac McFarland : Well, thank you, Allen. Good morning, everyone, and thanks for joining us today. Before we get into our quarterly results, I would like to start with a few brief remarks. Market and regulatory events over the last few months have further underscored how critical existing generation is to serving demand growth and supporting grid reliability. Since we signed the Amazon deal in March of this year, the market fundamentals for power in the United States have only become more construct for IPPs. The higher PJM capacity auction results in July, the Microsoft Green Clean Energy announcement and increasing utility load forecast, mostly driven by data centers, the reshoring of industry and the electrification of our economy, all support this thesis.

The U.S. is expected to be the fastest growing market for data centers, growing from 25 gigs of demand in ‘24 to more than 80 gigs by 2030. Meeting this demand will require significantly more generation to speed the market and access the long-term power have become top priorities for hyperscalers and data center customers. As I said before, serving this massive data center demand will require an all of the above approach. This includes co-location like our arrangement with AWS, hybrid arrangements that co-locate primary power behind the meter while using the grid for backup and front of the meter connections to utility transmission. While we are disappointed in first decision to reject the ISA amendment, it does not change the fact that this load growth is coming and it will not stop our progress.

First, development of the data center campus will continue under the existing 300 megawatt ISA as we and AWS work together on the path forward. Talen’s colocation arrangement with AWS is part of the solution to issues raised at the FERC technical conference on large co-located load. It brings service to the customers quickly and without expensive transmission upgrades that would impact a retail consumer’s energy bill. That said, we are exploring the whole suite of commercial and legal solutions to facilitate full development of the Susquehanna campus as well as progressing other opportunities across our fleet. This includes filing a motion for FERC rehearing in parallel with AWS contract discussions. We are keeping all of our options open when it comes to co-location, front of the meter or the hybrid solution I discussed earlier.

I know the first questions in our Q&A today will be when are you going to have this solved? What will it look like? And what about your next data deal? The short answer to all of this is, we’ll let you know when we’re done. Quite frankly, this reminds me of a year-ago when we hosted our Susquehanna site day visit and data set at our data center campus and talked about colocation as a novel concept. Many of you asked these same questions then, and you heard me gave the same answer. You all know that we don’t do commercial negotiations in public and we’re not going to comment on them at this time. That said, I believe we can leverage our transaction experience, advantage grid location and strong stakeholder relationships to utilize all of the options on the table.

I am confident that we as an industry can meet the challenges in front of us and seize the opportunity to power the AI economy and bring its substantial economic benefits to Pennsylvania specifically and the U.S. more broadly. So now turning to our key highlights, starting with Slide 3. Talen has had an active third quarter and I’d like to highlight several of our achievements, starting with our solid operational and financial performance. In the third quarter, we generated $230 million of adjusted EBITDA $97 million of adjusted free cash flow. Based on our strong performance year-to-date, we are raising and narrowing our guidance for 2024 and we are also affirming the 2025 financial guidance announced at our Investor Day in September. Terry will provide more details on that as well as our 2026 outlook.

In October, we acquired TeraWulf’s 25% share in Nautilus, which provides a strategic flexibility with the building and its power use. Operational activities at Nautilus have been suspended, which releases 150 megawatts of power to be sold at more profitable levels to the PJM wholesale market and eventually to Amazon. Lastly, we were added to 5 equity indices over the last few months driving passive fund demand for our stock and continued shareholder rotation. I’m proud of what the team has accomplished this quarter while setting the stage for more long term value creation. Turning to Slide 4, you’ve heard me talk about the ISA and path forward. We also participated in the FERC technical conference on November 1st. There was a lot of good discussion and we applaud the commission for taking up this serious matter.

We continue to believe the path forward is that all solutions should be on the table as long as the RTO, the generator, the transmission operator and the state PUCs are on board or the respective state PUC. Turning to the PJM capacity auction. PJM has requested and the FERC has approved the six month delay of the ‘26, ‘27 auction that was originally scheduled for next month due to complaints filed by the Sierra Club and other NGOs. Subsequent auctions will occur every six months through the ‘28, ‘29 auction in December of 2026. PJM is focused on reevaluating the auction reference technology, which impacts the steepness of the supply curve as well as the treatment of RMR or reliability must run units. We are generally supportive of PJM taking another look at the supply curve.

However, we think PJM should compress the time between auctions to get them back on track sooner to the original timeframe of three years in advance. Further delays in the capacity market create uncertainty in the very market that needs signals to incentivize new build. We also believe that requiring RMR units to either bid into the capacity market as a price taker or be accounted for as a phantom supply will distort price signals. RMR units are meant to support transmission reliability not to serve as a capacity resource. Removing RMR resources from the capacity market is appropriate to send the proper signals that new generation is needed. We encourage PJM to resolve these issues as quickly as possible and look forward to engaging constructively with them on the process.

On that note, let’s turn to Slide 5 and put some numbers behind the supply demand situation in PJM. Since 2020, 19 gigawatts of generation assets have retired in PJM and nearly all of those are gas and coal plants. While only 10 gigawatts of new gas plants have come online, along with 13 gigawatts of renewables and batteries, which do not provide the same dispatchability as gas plants and coal plants. From a demand perspective, PJM recently reported significant increases in submitted requests to the 2025 power demand forecast for anticipated large loads like data centers and manufacturing. These requests include 15 gigawatts of demand by ‘26 and over 50 gigs by 2030. PPL itself forecast that by 2,030 large loads could double the peak summer demand curve demand in its control area and that is where most of our plants are located.

These data points highlight how PGM needs more reliable dispatchable generation to meet the power demand growth that is coming. Moving on to Slide 6, let’s look at our year to date operational and financial results. Our team continued to deliver from an operational perspective. Our fleet ran well generating over 27 terawatt hours with an equivalent forced outage factor of only 2.4, which is an improvement to 3.5% in the same period last year. Roughly half of that generation came from our carbon free Susquehanna nuclear facility. Importantly, our team works safely during the busy summer months. We have a year to date TRIR of only 0.3, which is truly remarkable. 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 deliver significant adjusted EBITDA and adjusted free cash flow on a year to date basis. We continue to prioritize capital returns and balance sheet discipline during the quarter. Terry will take you through the year to date numbers, our leverage and our liquidity later in the presentation. I’d like to stop and take this opportunity to recognize and thank our employees across the company who have worked safely to deliver impressive operational results across the entire portfolio. 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 is possible.

I’ll now turn the call over to Terry. Terry?

Terry Nutt : Thank you, Matt, and good morning, everyone. Now turning to financial results. For the third quarter of 2024, Talen reported adjusted EBITDA of $230 million and adjusted free cash flow of $97 million. Compared to the same period last year, expanded spark spreads and higher power demand drove increased generation margin across our fleet. Generation margin along with the combined impacts of our hedging strategy and the PTC more than offset the absence of earnings from our ERCOT generation portfolio, which was sold in March of 2024. Q3 2024 adjusted free cash flow included the impact of a $40 million higher pension plan contribution, reflecting our continued commitment to our workforce and retirees. Additionally, we accelerated some raw uranium purchases during the quarter to take advantage of pricing opportunities.

These collectively resulted in lower adjusted free cash flow compared to the third quarter of 2023. For the year-to-date period, adjusted EBITDA was $606 million and adjusted free cash flow was $262 million. Moving now to guidance on Slide 8. With three quarters of performance behind us, we are raising and narrowing our 2024 adjusted EBITDA and adjusted free cash flow ranges. Our new adjusted EBITDA range is $750 million to $780 million. And our new adjusted free cash flow range is $265 million to $285 million. Looking ahead to 2025, we are reaffirming the guidance ranges we announced at our Investor Day in September. Our adjusted EBITDA range remains at $925 million to $1.175 billion and our adjusted free cash flow range is still $395 million to $595 million.

Additionally, our 2026 outlook also remains unchanged from what we disclosed at our Investor Day. These ranges continue to demonstrate Talen’s significant earnings and cash flow growth profile, which includes nearly tripling adjusted free cash flow per share by 2026. Turning to Slide 9, we remain committed to maintaining net leverage below our target of 3.5x, along with maintaining ample liquidity. As of November 8, our forecasted net debt to 2024 EBITDA ratio was only 2.1x, well below our target. In addition, we have nearly $1.3 billion of liquidity, including over $550 million of unrestricted cash on the balance sheet. We continue to engage with the rating agencies, two of which have responded to our balance sheet discipline by upgrading our credit ratings.

In September, our S&P corporate credit rating was upgraded to BB- and in October, our Moody’s rating was upgraded to Ba3. We remain focused on unlocking value and returning capital to shareholders. In September, we announced another upsizing of our share repurchase program and have over $1.2 billion of capacity remaining through year end 2026. We have returned approximately $950 million to shareholders year-to-date by repurchasing roughly 8.3 million shares. Due to the timing of our Investor Day and subsequent non-deal road show, there was limited time to repurchase shares at the end of this quarter. That said, we continue to see share repurchases as the best use of our capital and continue targeting a return of 70% of adjusted free cash flow to shareholders.

Turning to the next slide. After uplifting to the NASDAQ, Talen has become eligible to join several equity indices, which has driven substantial institutional and passive stock demand. Talen has been added to five indices resulting in passive investment funds acquiring over 6 million shares in September 11. Earlier this month, Talen was added to the MSCI USA Small Cap Index, which will be effective on November 25th, and we anticipate additional passive fund demand from that inclusion. Further, Talen could qualify for additional value growth for sector specific indices, further enhancing stock demand and accelerating the natural shareholder rotation. With that, I’ll hand the discussion back to Mac.

Mac McFarland : Great. Thanks, Terry. As all of you have heard me say before, Talen remains an IPP that’s focused on being an IPP. And that’s at a time when reliable and flexible generation assets are more valuable than they’ve been in many years. We appreciate your interest in Talen for joining us on today’s call. We will now open the line for questions and I’ll turn it back to the operator. Michelle?

Q&A Session

Operator: [Operator Instructions] And the first question will come from Shar Pourreza with Guggenheim.

Shar Pourreza: Morning. Mac, just by your prepared, it seems like there’s not a lot of appetite to answer my AWS strategy question. So let me just shift gears towards resource adequacy, which is obviously very topical at EEI. Are you involved, I guess, in state level conversations in Pennsylvania at this point? And if the PAPUC would eventually run an RFP and look for peaking PPAs or the state passes a test like mechanism. Would you — would Talen be involved in new development? I guess, how do you see this sort of unfolding the session overall? Thanks.

Mac McFarland : Sure. Well, obviously, that’s a broad policy question because I understand that there are a number of people who are talking about either RFP-ing or rate basing generation. I think that there’s a couple of things that are going on. One, first of all, for the first time in seven years, we had a higher capacity clear, a clear that was higher than $100 a megawatt day. And, I think we have a fair amount of reactive voices going on here with respect to how to solve the resource adequacy problem. I think first and foremost, the solution to that problem is, as I said in my remarks, is to get the capacity market on track so that we’re providing pricing those three years out. With respect to the TEF that has been floated, we have been in conversations in Harrisburg through our company has.

And look, we think that something like a TEF that provides low cost loans to generation that can help the resource adequacy issue that we see on the horizon. And we’re supportive of it, but generally, it depends on how those loans come out, what strings are attached to them, etcetera. So when you ask that question, Shar, there’s not a lot of specifics out there right now. There are people talking about should we rate base generation, should we do something like the TEF, a PEF, a Pennsylvania Energy Fund? Should we think about other ways to solve the resource adequacy? I think what’s get lost in all of this with respect to Pennsylvania is that Pennsylvania has excess reserve margins in excess of 30%. Its other states that have lower reserve margins that are quite frankly somewhat of the issue.

That said, Pennsylvania has an opportunity given that it has gas, local gas, plentiful gas, a pro-fracking position on things, regardless of what side of the aisle you’re on there. And so they have the ability to export energy. I think that they can continue to do that and I think capacity markets are the way to do that. But I’ll open it to Terry, so if you have any further comments, Terry.

Terry Nutt : Yeah. Thanks, Mac. A couple of things to add to that response, Shar. First of all, the Pennsylvania PUC is holding a conference on resource adequacy here right before Thanksgiving and we plan on participating in that. So obviously, being a large generator in the PJM market, we definitely are engaged in those discussions and we’ll continue to be engaged. Back to sort of the general policy question, the other thing I would add to Mac’s comments is, I think obviously a Pennsylvania Energy Fund is an interesting concept. We’ve seen that done in Texas. I think whether it’s a Pennsylvania Energy Fund or whether it’s some of these discussions around RFPs, the devil is always in the details, right? What does that asset if you put in that new asset, how does it participate in a capacity market?

What is it ultimately, what economics are sort of borne by the asset itself and what can it do and what can it not do from a participation standpoint. So, I think they’re constructive discussions, we’ll be engaged and look forward to helping solve the resource adequacy issue.

Mac McFarland : And Shar, just one more comment on that real quick, which is as we talk about our sites which are in the PPL zone as advantage sites, we have a lot of sites that have access to gas and are in the right point on the transmission system to interconnect and we’re looking to see how we can leverage those sites as redevelopment opportunities. Again, it’s going to have the right kind of economics, the right kind of returns etcetera, but we are exploring it there. And if you want to ask your AWS question, feel free.

Shar Pourreza: Sorry, I could pass that to someone else. But just my only question is as legislation starts to form, is there discussions you’re having with the wires companies or is the bid ask kind of too wide right now to even come to a discussion table?

Mac McFarland: I think that the things that are being discussed right now are so preliminary. There’s it’s not like there’s a bid ask that’s wide or tight. It’s just that everything is so preliminary. That’s why I said that these have been somewhat reactive to this capacity clear again. And it’s being, quite frankly, I think that we’re not even close to what it’s going to take and the capacity clears to incentivize new generation, and people say we should rate base it. Let’s just be clear or go through an RFP process. Let’s be clear. The reason why PJM is the most effective deregulated wholesale market in the country is because it was people didn’t want to pay for stranded assets. They wanted to move to a deregulated market in PJM because they felt as though it would drive the lowest cost of supply possible. We continue to believe that and we will participate in that.

Shar Pourreza: Got it. Perfect. I’ll touch base with you guys in a little bit. I appreciate it. I’ll pass it to someone else. Thanks, Mac.

Operator: And our next question comes from Jeremy Tonet with JPMorgan.

Jeremy Tonet : Just wanted to come back to, I guess, the technical conference here, if I could. Looking at the proceeding there as a read through for the amended ISA, how do you think about that or just really any thoughts on data center development more broadly coming out of the conference here? Just wondering what your take was on the technical conference?

Mac McFarland : So I think in general and Cole is on the line who is a witness during the third panel, and he can jump in here at the end of this. But I think in general, I think there was a lot of discussions that were beneficial to thinking about how does how do we solve the growing demand from data centers. I do believe that ISAs got conflated with resource adequacy and that the distinction between so called front of the meter and behind the meter, collocated, etcetera, sort of worked its way into that conversation, and then it really should be parsed separately. I think we believe that the outcome should be and I said this in the opening remarks, Jeremy, is that if the RTO, in this case PJM, the transmission operator, in this case PPL on our specific ISA, and the generator are all in agreement as is the state level PUC being the PAPUC in this instance, this is a state level issue and that if those four parties are in agreement and they don’t see that there are incremental costs, which is exactly what was found in the case of the ISA and it created reliability, we think that that’s a model that should be approved.

Whatever fits and with those 4 parties agree. Now, we may have colleagues that have a different view of that who I think that that’s what should come out of them, you know, as we go back. And I think we’ll see where this goes. There’s the PJM guidelines and some other things that that need to be addressed. You started the question with, amending the ISA. We’re looking at that right now. I think the current path on a regulatory front put aside the commercial, which is where we’re focused for just a second. But on the regulatory path is first to file a motion for rehearing and that’s the step that we’re taking on that path. Cole, do you want to talk about what we’re doing on the current AWS contract for a bit?

Cole Muller : Yeah, sure. Hi, everyone. I think first on the question as Mac said, I think co location got kind of lost between the forest and the trees during that conference and resource adequacy kind of completed co location as Mac said. I think we think it’s going to get sorted out. It’s going to take a little bit of time here, but we’re optimistic that FERC will start to set a path forward that gives clarity on the co-location in particular. On our commercial paths forward for our existing agreement with Amazon, I think it’s important to reiterate what Max said in the opening remarks that we have an existing ISA that’s been approved for 300 megawatts, which enables us to have runway here to optimize getting to the 960 megawatts for this deal over time here.

We are evaluating all of our options jointly with AWS on how to accelerate that. And folks probably saw that AWS recently publicly reiterated a commitment to the site, right? And so the fast forward are a wide range as Mac also outlined in the opening remarks from kind of the status quo configuration all the way to a full grid connection. And there’s a bunch of shades of gray in between. We’re looking at each of those options and weighing those carefully. Some of those configurations may have technical and engineering adjustments that are going to require some review and analysis. So we’re in process to get to an optimal answer here jointly between all the parties, and we’ll provide an update when we have one.

Mac McFarland : I’ll just add on to it. No, no. I was just going to add on, look, we and I mentioned this, we’ve been looking at a number of different commercial arrangements across the fleet. When we signed the original 960 deal with AWS earlier this year, it’s not as though we then started resting on our laurels. We’ve been looking at a number of different commercial arrangements and that is what allows us to sort of focus on how do we — if you want to call it pivot or look at a different way to get to the 960, we’re actively doing that. We’re also going to preserve our optionality with respect to colocation because we think that colocation is one of the forms to speed the market and to power the AI economy and should not be lost. And so that’s why we’re going to continue on that front, but we’re focused on the commercial aspects of things.

Jeremy Tonet: Got it. Very helpful there. Thank you. And then just pivoting here, data center is looking for firm, sources of power and there’s only so much nuclear out there. So just wondering if you could provide any updated thoughts on the appetite for gas to service this demand be it behind the meter or what have you. Just any updated thoughts on that side?

Mac McFarland : Look, I think there’s a couple there’s a couple things at play here. I mean, obviously, many of the hyperscalers and those that use that are non-hyperscalers that use cloud services, etcetera, all have aspirations for carbon neutrality at some point and some at some point in the future. And so weighing that, people are looking at the carbon free aspect of nuclear, obviously, because it’s base load and it fits the load side of the equation, in this case, data centers, which are effectively 24/7 load. That’s not exactly accurate, but let’s use that for now. And the use of renewables as well, to meet their energy demand. But in the near term, and I think this is important over the next decade, until there is SMRs that can be put in place and so put those out in the mid-30s, That gap, if you believe that the load is coming, that gap is going to have to be served by gas units.

And I think that if you look at PJM, PJM has a real opportunity to serve that load because of where it’s geographically located for the data centers. And because and then if I wish to hone that down, we think we’re in an advantage spot because Pennsylvania has abundant gas, pro fracking, pro-business. And, there will be the ability to put additional electrons on the grid via new gas units. And so — and I think the appetite will get there because the need is there and it is going to be, if you want to call it this, a transition fuel till we can get more nuclear. Now anybody that’s ever –anybody that I’ve ever spoken with knows that I’m very much pro nuclear and think that as a energy independence, if you go to the electrical side, nothing could be better than having a lot more nuclear units along with gas units.

Okay? But it’s going to take some time to get there. And so to fill that gap is going to have to be gas units. And we’re looking at what opportunities we have to play to answers to go back to Shar’s original question about the resource adequacy, how might we help fill that gap.

Jeremy Tonet: Got it. Very helpful there. And if I could just quickly pivot to the PJM auction, any expectations for changes there or any reforms that you would be supportive of?

Mac McFarland : Well, I think I said in the opening remarks and then I’ll bring Terry into the conversation too. Look, we’ve had conversations with our colleagues as well as industry working groups and things of that nature. And I think the biggest thing that the thing that most of us agree on is that we don’t want very binary outcomes to where you either get a zero clearing price for 700. Okay? Because whether you believe it’s price shocks, and we can talk about that because capacity is the smallest portion of anybody’s bill. So the — so called 5 times going from 50 to 250 is the smallest portion of the bill. It does not increase a bill that much. But put that aside politically and you hear people react to the prices going up, we don’t want that volatility there.

So that is why we are supportive of changing the curve as PJM looks with this delay to make modifications to the RPM for ‘26, ‘27, we’re supportive of that in general. There’s always, as Terry said earlier, devils in the detail. We also, as I said in the remarks and I’ll reiterate it here and we’ve been pretty clear that we’re willing to participate in RMR and we’re having ongoing discussions with respect to RMR, but what we’ve always said is they should not distort the capacity and energy market. And they’re there and their need is there as PJM has said, for transmission reliability, but not as a capacity resource. And so, we think those are two very important issues here as we go into this auction. Terry, you want to pick up on that?

Terry Nutt : Yeah. Maybe to add to Mac’s comments. I think the other variable that we’re paying attention to, right, we always like to do just basic sort of fundamental supply and demand analysis and a big variable that I think will be interesting is to see what the demand forecast looks like. Most people may be aware that PJM runs various subcommittees and they had a load analysis subcommittee meet a few weeks ago. And some of the demand forecasts that are coming out of that committee are very interesting. And so — and we alluded to it in the slides, if you take a look at some of the forecast, there is obviously tightness in the market, especially as we move through the next few years. So that to us is probably the biggest variable that we’ll have to see how it comes out.

Mac’s comments on RMR units, so I can’t agree with more. I think putting an RMR unit is in some if you put it if you put it in the supply stack or you just net it out of demand, what ultimately is going to happen when that RMR unit retires at the end of the RMR period, right, you’re just going to see that drop off, right. In some respects, it’s a bit of a distortion and delaying a little bit of the inevitable. So, we’re obviously opposed to that. But we’ll stay engaged. We’ll see where PJM comes out on the parameters and then look forward to the auction as we get into next year.

Operator: And the next question comes from Angie Storozynski with Seaport.

Angie Storozynski: Thank you. So, just on the timing of the resolution, for Susquehanna, I mean, I know that I’m the very first one to say that I want an answer now, but I’m actually having some second thoughts here having spoken to your peers. I mean, they’re making really interesting points. They’re basically saying collocations are still the most viable option, from the speed to power argument perspective. We have new administration, which is very supportive of economic growth in AI in the U.S. We may have some meaningful changes at FERC, come next year, and you have 300 megawatts to deploy and seemingly all options available given as you said, the transmission availability, et cetera. So again, I know it’s surprising, but why rush with any decisions here with changes to the existing contract. Why not just take some time to actually assess the backdrop that is about to change or potentially about the change for AI in this country.

Mac McFarland: Angie, I appreciate the question. The — look, when we say that — and Cole jump in here. When we say that we are looking at commercial arrangements with AWS, I would tell you that we don’t think that anything is off the table. There’s all sorts of possible options. And as I said in the opening remarks, colocation is one of those, and we’re continuing to keep that option open by filling the motion for rehearing. I think in general, I’m going to say in general, we agree with some of the points you laid out, but also there’s an aspect of — you put the time element in here. Obviously, the time element is meaningful as well. And as we go through and look at our options and we have discussions with our counterparty, our counterparty, we think about how — what is the best way to do this going forward.

And it is — takes into consideration a lot of different things, including the economics. And so therefore, we will take our time. We’ll be very reasoned about the amount of time we take just as I hope were viewed as reasons with respect to our commercial activities. And so there’s no easy answer to that question, Angie, but I do appreciate. Cole, anything to add?

Cole Muller: Yes, I would just reiterate that we’re not rushing, Angie, to your question, and we are being methodical in analyzing all of our options. We do want to be responsive to our customer who does need clarity at some point to accelerate and make large investments. So that is part of the analysis. But as Mac said, we’re going to look at the economics and other pros and cons of each option, and we’ll let folks know when we have an answer there.

Angie Storozynski: Okay. And then the other thing is, there are already questions about your gas assets. I mean you have former coal plants converted to gas that are currently running as speakers but used to be a baseload assets that run 80%, 85% of the time. One could argue that if these assets were to stay on the grid, you can’t necessarily ramp the output from these assets until basically power prices rise like market power prices rise. So we’re having all of these discussions about additionality and how, for example, extensions of operating licenses of nuclear plants with the additionality, but how about the fact that you could increase the output from some of your gas plants? I mean, a fourfold if there were to be supported by an above market contract, again, as long as these assets are in behind the meter sort of a setup. So.

Mac McFarland: Yes, Angie, I think it’s a good point, whether it’s behind the meter or front of the meter, the load is coming, okay? And these assets have been used, as you said, is peaking assets for the most part over the last several years. And now they’re receiving higher capacity revenues, but the energy margin on them is effectively on a year-over-year basis, sparks are relatively flat, if you will, okay? But we do have, for example, at Montour, a 105 heat rate unit, we have ample gas supply. We ran a gas lateral there. We’ve made the conversion. From an energy standpoint, it can provide a lot more energy. It’s just there’s no additionality at the peak, but there’s a lot in all the other hours that it doesn’t run, right?

So when it’s running 10%, 15% of the time, and we’re starting to see that uptick. We saw strong loads in the second quarter and Montour is starting to run more and more. And so you will get, to your point about — I don’t know if it’s exactly fourfold, I think, is the number you used. You will get increased dispatch even if these don’t have a contract and increased sparks that should manifest themselves over time as the supply — or the demand starts to show up. I also think there’s an opportunity at a lot of these sites, as I said before, because of the interconnections of where they’re located for repowering opportunities as well. In fact, when you convert Montour over to a gas unit that is a repowering opportunity. And so we’re looking at all opportunities of expanding.

Can we get incremental megawatts? And so when people ask about resource adequacy, what are you doing to solve it? Well, the first thing that’s going to happen is as we’re looking at how do we run these units more, have more megawatts to get out of these units, okay? And how can we — and that will be the first part that contributes to resource adequacy. It’s not the 1,000-megawatt CCGT announcement. But when you do this across our fleet and other fleets where everybody is looking to get 10, 20 megawatts more, you just start to fill some of that resource adequacy hold over time. And then you’ll get to new build. So we think that those gas assets are in a prime position for increased energy margin or to be a solution to power the AI economy as well.

Cole, Terry?

Terry Nutt: Yes. Mac, let me jump in there real quick. Angie, it’s Terry. So a couple of things to add to Max’s comments. When you take a look at the second quarter and the third quarter of this year, our gas fleet did run appreciably more. And so as we had periods of tightness in warm weather and PJM, those assets did dispatch quite a bit more this year than we’ve seen in prior years. So we’ve seen some of that phenomenon come into play already in 2024. I think you look at it on a weather-adjusted basis, PJM load was higher, has been higher this year than the prior year. And to that end, one of the things when you start usually, you have a few initial reactions to resource adequacy and you see it in most markets. Some of that is, okay, to your point, okay, are you dispatching the existing fleet across the supply stack in an incremental basis.

The second one then becomes, okay, do you have anything that was previously announced as a notice of suspension or retirement that you’re going to unretire. Some of the other things that you may see is could there possibly be conversions of assets that previously were one technology or one fuel type, similar to what we did on our Montour plant where we converted it to burning gas. And so that resource adequacy response, there’s a few steps that are usually taken first because they’re quicker, they may be more economical. And then obviously, when you think about a new build and to Mac’s point earlier, a brand-new utility scale combined cycle plant is probably going to take you sort of 5 to 6 years to get done. And so you’re going to need these incremental things that are done in the interim to help address the additional generation.

And then the last thing on our fleet specifically to Talen, we have added, given the additional dispatch that we saw in our gas plants in the second and third quarter, we’ve added some incremental maintenance cost into our numbers that were included on our Investor Day to make sure that those assets are there and they’re hardened and they’re ready to go as we move forward over the next several years. So that’s sort of where we think — how we think about the gas units today.

Mac McFarland: And Angie, you can see, by the way, if you look at the percent hedge in ’26, you can see that the percent hedge went down. Some of that is the PTC put becoming less in the money, okay? But a lot of that’s also driven by increased dispatch — forecasted dispatch of our gas fleet. So you’re right on.

Operator: And our next question will come from Nicholas Campanella with Barclays.

Nicholas Campanella: So you just brought it up at the end of your remarks there, but you brought the hedges down. And I just want to confirm that’s not a change in view of like freeing up additional open capacity or energy for longer-term GPA.

Mac McFarland: Yes. Maybe just to clarify, that was not an action by us to take hedges off. It’s just the denominator in that calculation is expected gen and expected gen rose. And because of slight increases in sparks, particularly in periods by which the gas units are more likely to run, so around the summer and winter time frame. So when you increase that generation, if you keep the numerator the same, it just drives it down. So it’s not — we didn’t take hedges off. It’s not based off of a view. I would think if you wanted a perspective on that, we feel more comfortable given that we’re moving to more contracted revenues with the PTC as a downside protection, we feel more comfortable being a little more open, particularly as we look at demand coming, as Terry mentioned, from the forecast of the load forecast from the subcommittee of PJM, that would be the position we’ve taken.

But all that means is we haven’t layered on additional hedges and there has been increased generation forecasted.

Nicholas Campanella: That’s great context. And then just on the current RMR processes at FERC, I know you’re in settlement discussions, but just can you reconfirm your timing there? Do you still expect that to kind of be solved by year-end? And just wondering if there’s any impact to that discussion based off of the wider kind of RMR being included in the capacity auction now discussion? And is there going to be a delay in your ability to kind of get to the settlement? Because I know that timing is of the essence on that side.

Mac McFarland: So I’m going to John Wander, our General Counsel is here, and I’ll ask him to provide some context around the RMR. But let me start with this, which is even with the delay of the capacity auction and the overlay of the RMR, regardless of the intersection there, — we’ve got a plant in brand insurers with employees, with fuel contracts, with maintenance needs with outages and things of that nature that you cannot make a decision with respect to that RMR one day before it’s supposed to shut down. And in fact, we have employed all constituents to come to the table and to find a solution to the RMR this year. That was our stated goal and time frame because we have to make a lot of decisions to impact or impact our fuel contracts, all the things that I just said. And you just don’t flip a switch on those. And so we need time to do that. And so hopefully, we’ll get to that time. Now John, do you want to provide some update on the process.

John Wander : Sure. Sure, Mac. Nick, thanks for your question. What we’re really doing here in the immediate moment is focusing on those settlement negotiations. And there are settlement conferences set both in the end of November and early December, and we’ve made it very clear throughout the process that our objective in this is to be done by the end of December with the knowledge of what we can reach an agreement on whether that’s an agreement that has a FERC order behind it or not, we won’t know that probably by the end of December, but we’re going to have an idea by the end of December what the parameters of a settlement will look like. We made that very clear to everybody.

Operator: And our next question will come from Michael Sullivan with Wolfe.

Michael Sullivan: I’m just going to pick up, right, where Nick left it there, and maybe drill down a little further. I guess how can you settle in front of what FERC is going to come with in early December, which potentially could impact how these units are treated? Or is that enough time when they come with that in early December to turn it around by year-end?

Mac McFarland: Michael, I’m not sure I understand the question. I think we’re targeting by the end of this period, John can go through this, having a settlement we need to, early next year, prepare for it, we said it was going to shut down May 31. We’ve got to start preparing and you just — you can’t flip a switch to prepare. And so that’s why we’re asking everybody to come to the table and resolve this now. But I’m not sure I exactly understood the timing of your question from a timing perspective. What — could you rephrase that — are you asking?

Michael Sullivan: Yes. Maybe I’m misunderstanding. My understanding is FERC or sorry, PJM was going to come to FERC with some capacity market rule changes with the 205 filing in early December. And as part of that, I think they were reevaluating how these RMR units get treated and so just if they change how they get treated, is that enough of a turnaround time for you all and how you hash out terms of a settlement?

Mac McFarland: John, do you want to pick up on that?

John Wander: Yes, I can take that, Mac. Look, I think that the 2 things are relatively distinct, right. The inclusion in the capacity market of the RMR plants is about the capacity of the RMR plants, not about what we get paid in the RMR. Now will that be a factor ultimately, when the auction runs and if PJM gets its way and the RMR gets included and there’s some offsets for people who are paying for the RMR, we’ll see how that shakes out. But from our perspective, there are separate questions. Whether we can get to an RMR agreement that satisfies us on what it takes to run those plants into the future for the next several years is distinct from whether PJM includes the capacity for those plants in the supply side in the auction.

Michael Sullivan: Okay. That’s very clear. And then, I guess, when you say all options are on the table and working with Amazon, maybe just to clarify, like you talked about the 960 is doing something potentially even bigger on the table and involving other plants in your fleet?

Mac McFarland: Look, I think, first, Michael, as I said, we’ve been looking at a number of different commercial arrangements that we think we could port from other thoughts over to how might we go forward with AWS. I think that many people asked us whether or not the second reactor because of the first arrangement, it was a backup to the first one when it was done, if you recall that arrangement, I’m sure you do. That’s how it worked and how might you free up that. And we talked at that time about looking at how might other types of commercial arrangements be there. I’m not going to talk about what we’re talking to Amazon about. But I do think that there are ways by which using grid as backup, grid as primary stores, co-location, all — that’s what we mean when all of those things are on the table. I hope that’s helpful, but we’re just not going to get into what we’re discussing with AWS. Cole, do you have anything to add?

Cole Muller: No, I think that’s right.

Operator: And the next question comes from [indiscernible] with Jefferies.

Unidentified Analyst : And congrats on the quarter. So I guess, if we can talk a little bit about speed to market seems like it’s one of the main factors for the hyperscalers. Can you give us a sense maybe how long it would take for [indiscernible] deal to go through the process. So you agree on terms already. How long does it take until the contracts start contributing going through PPL, PJM? Is there anything you can to recycle from the 960-megawatt ISA and how that would change if the deal will be larger than the combined 960?

Mac McFarland: Yes. That’s getting too specifically with respect to Susquehanna and the AWS. So I’m not going to talk about that, but perhaps if I was just to pan out for a second and talk about what is a front of the meter solution. And as I said, we’ve been looking at all these different types of commercial arrangements across the fleet. The front of the meter is effectively a retail contract or the virtual PPA or PPA, as was done as we understand was done with Microsoft and TIM or the clean energy center. And that is with respect to speed to market, our understanding of the way that PPL, the zone that most of our plants are in that we’ve been discussing here today, that speed to market, we believe, is faster in that zone, whether it be co-located grid back up or front of the meter because of the advantage PPL has in that it has a transmission system that can be easily attached to — and I think you saw that when PPL put forth basically $781 million, to be exact, almost $800 million worth of transmission upgrades to serve 6 to 8 gigs of what they see as highly likely data centers coming.

And so the transmission system in PPL is advantaged. And because we have sites and assets in PPL, we believe we’re also in an advantaged position. But one thing I will tell you is that people — I think a lot of questions revolve around this concept of the front of the meter. And one of the things that I’ve said in conversations is the fact that no one has defined what front of the meter is, no 1 to find a colocation deal to we did it — and now people are talking about a front-of-the-meter deal, I guess the closest and this is, by the way, I applaud Constellation for their deal with Microsoft the crane center — that’s the closest that we see. But I don’t know that, that’s necessarily been defined. But if you look at the characteristics of speed to market, I think you have to have an advantaged transmission zone, you have to have ample land, water, generation resources, et cetera, we think that we’re in the right zone that has those.

Cole, anything that you would add there?

Cole Muller: I was going to reiterate record this comment you made about PPL. I mean maybe [indiscernible] folks to go look at other comments PPLs made both in our earnings and other analysts have written about. But they’ve discussed their timing. They think they can connect front of the meter fairly quickly. And you can also look at some of the filings they’ve made with PJM and their subcommittees to kind of confirm the timing for large projects. So — we think that’s something that certainly won’t delay potential opportunities across our fleet. And obviously, for Susquehanna, we’re we have plenty of runway, as I said earlier, with the 300 megawatts under the existing ISA.

Unidentified Analyst: Just if I can, on the new build side, I’m curious if there will be any appetite for you to build a new CCGT today on a merchant basis in the PGM or elsewhere.

Mac McFarland: So Anton, it depends on how you define merchant. Merchant means all revenues are received from capacity and energy, I think that first of all, it relies on what are these capacity market changes, which have yet to be defined. It needs to have a rigorous capacity market that provides the proper signals and then it depends on, obviously, the expectations of energy margin. Now I will tell you that the landscape is the generation landscape and in doing this for a while. There’s been a litany of project developed CCGTs that go full merchant that go bankrupt. And so we’d have to look long and hard at that. We actually think that the model going forward will be to have — I don’t know if it’s that RFP, but I’ve said this in the past that hyperscalers can provide their balance sheet to this or a combination of a data center developer along with the generating unit that combo provides an offtake agreement.

That — we haven’t had large loads like this in a long time since sort of the industrial build-out, particularly of the Delaware River Basin with refiners and et cetera. But when you have large loads like that, that have a power need, you can match those things up and do contracts. And so we see that as the more likely way that we might participate going forward, at least having a portion of the plant tied to contracts, if you will.

Unidentified Analyst: If I just can, real quick. Can you characterize maybe the opportunity for uprates at Susquehanna there’s been a bunch over the many years. I’m just curious if there’s any opportunity there?

Mac McFarland: Yes. We’re looking at those. Obviously, that provides to the so-called additionality argument. And we’re looking at those. A number of upgrades were done across the nuclear fleet in the early 2000s, and the next evolution of them becomes more expensive, imputes more need to think about how might it impact your what we call margin and at a nuclear facility, which is safety margin. And reliability factors in there as well. We’re looking at them. I don’t know that it’s as prevalent in our opportunity here as it might be in some others.

Mac McFarland: So great thanks, everyone, for joining us today, and thank you for your continued interest and support of Talen. Everyone, have a good day, and we look forward to connecting with you in the future. Take care.

Operator: This does conclude today’s conference call. Thank you for participating. You may now disconnect.