Good afternoon, and welcome to the Talen Energy First Quarter 2024 Earnings Conference Call. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Ellen Liu, Senior Director of Investor Relations. Please go ahead.

Thanks, Jona. Welcome to Talen Energy's first quarter 2024 conference call. Participating on today's call are Chief Executive Officer, Mark 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. I'd like to highlight that we have posted materials on the Investor Relations section of our website, www.talen.com and filed continuing disclosures on the TLNE page of the OTC website that provide additional information about our operations, first quarter results and other matters discussed on the call today. We have also provided information reconciling our non-GAAP financial measures to the most directly comparable GAAP financial measures in our earnings materials. Today, we are making some forward-looking statements based on current expectations. Actual results could differ due to risk factors described in our financial disclosures and other periodic public filings. [Operator Instructions] With that, I will now turn the call over to Mac.

Great. Thank you, Ellen. Good afternoon, everyone, and thank you for joining us today. As Ellen mentioned, we have posted an earnings presentation and Terry and I will reference those slides as we go through our prepared remarks. Starting on Slide 3 and with Q1, we are pleased to report strong operational and financial performance. Our fleet generated $289 million of adjusted EBITDA and $194 million of adjusted free cash flow in Q1, largely driven by realized hedge gains of $165 million from our commercial hedging strategy. On that, we are updating our 2024 guidance to remove the ERCOT fleet going forward and increasing guidance on our remaining fleet for higher forward prices and spark spreads, along with lower interest payments from our term loan repricing. Our new guidance ranges are adjusted EBITDA of $600 million to $800 million and adjusted free cash flow of $160 million to $310 million. We are off to a strong start in 2024, and we unlocked value in multiple ways this quarter. As announced on our Q4 call, after observing an opening in the ERCOT M&A market, we launched the monetization process for our 1,700-megawatt ERCOT fleet in late 2023. Earlier this month, we closed the sale of those assets to CPS Energy for $785 million gross, capturing a valuation materially higher than consensus estimates. We successfully completed a repricing of our term loan B and C on May 8, decreasing the interest rate by 100 basis points, which drops annual interest by approximately $13 million. We also obtained a waiver on our debt paydown requirement for the estimated $723 million of net proceeds from the ERCOT sale and achieved other amendments in our credit agreements. All of this enabling greater capital allocation flexibility. I will also note that S&P upgraded our outlook to…

Thank you, Mac, and good afternoon, everyone. As Mac mentioned, Talen's PJM gas fleet is well positioned to benefit from increasing power prices and expanding spark spreads. We believe our diverse fleet of gas-fired assets provides a significant source of upside to commodity price dynamics. As you may know, these intermediate and peaking plants run for a portion of the year, largely dependent on the economics of power and fuel prices. When spark spreads expand, 2 things happen to our gas fleet. First, new generation becomes in the money or profitable. And second, existing generation becomes deeper in the money. This could have a multiplier effect on generation margins. On Slide 7, we've provided an illustration of how recent spark spread moves impact our gas fleet. When we compare pricing as of December 29 versus March 28, you can see that a percentage change in spark spreads could have a significant impact on expected generation and margin. For example, 2025 average forward spark spreads between those dates were up approximately 11%, while the expected generation from that price move increased 13%. Furthermore, those changes resulted in an overall increase in our gas fleet's gross margin by 30% or approximately $50 million. For 2026, a similar dynamic takes place with an 18% increase in spark spreads, resulting in a 24% increase in expected generation volumes and ultimately, a 45% or $75 million increase in gross margin for our gas fleet. Load growth has been accelerating, and the wholesale market has only recently started to respond with power prices decoupling from their traditional correlation with natural gas, resulting in widening spark spreads across the forward curve. This resulting impact will further boost the earnings potential of our PJM gas fleet and our baseload generation assets as well. Turning to Slide 8. Let's…

Great. Thanks, Terry, and thanks for everyone joining us today and your interest in Talen. With that, we're going to turn it over to the operator and take questions.

We will now begin the question-and-answer session. [Operator Instructions] Your first question comes from the line of Michael Sullivan from Wolfe Research.

Thanks for all the new disclosures around sensitivities and hedging. Can you give us any color around how just '25 and '26 may be tracking relative to '24, so we have a sense for what the base is to sensitize off of?

Yes, Michael, this is Terry. I'll take that question. I think when you look at '25 and '26, obviously, as noted in the prepared remarks, we've seen a move in spark spreads. So we tried to highlight that for everybody from a modeling standpoint. I think the other thing that you have to layer into that, and Mac noted this earlier in his prepared comments, is we're starting to lay in the AWS contract and starting to see earnings from that in both of those years. And so I would refer back to the material that we previously provided on the impacts of that transaction. But starting from sort of the '24 standpoint, you can add those incremental items and sort of get a directional view on '25 and '26.

Okay. That's very helpful. And then when we just think about your cash position right now, sort of $1.4 billion in unrestricted cash, and I think you said you have another $300 million coming from the AWS transaction later this year. As we match that up with the increased buyback today, is just simple math, $1.7 billion, less the $1 billion, the remaining $700 million. Is that spoken for or could potentially be available as well? How do we think about that?

So Michael, good question. I think a couple of things on that. I would refer to the comments that I made earlier. When we get to Q2 and Q4, we do have higher cash needs for the business, and so you have to factor those into consideration. But generally, yes, you could factor additional cash for other activities as we move forward around shareholder returns.

Your next question comes from the line of [ Angie ] Storozynski.

So first, the 10% CAGR or above 10% CAGR for free cash flow, that looks actually pretty low to me given just the drivers you just laid out at the AWS and the pickup in sparks, not to mention a likely pickup in capacity prices. So is it meaningfully above 10%? I mean again, that number looks really low.

Well, first of all, Angie, how are you? Good to hear from you. Look, I think that hopefully, we've demonstrated a track record, let me say it that way, of being conservative and being committed to delivering on expectations. And so when we look at out there, we wanted to provide some indication of what the next 5 years looks like. And I think the point that we're making is that, we have visibility to that. And a lot of that comes through contracted revenues, not just increase in sparks that are in the out years when you get out to years 4 and 5, there's not a lot of liquidity in the power markets. And so we are seeing that and have the opportunity to realize that increased growth through the AWS contract as well as these sparks. But look, we have not provided, I think Michael was asking the question before. It's been a while since I think the January 27 disclosure of last year during bankruptcy that we provided out year guidance, and that's not lost on us. We're in the process of doing that. We're just in the early stages of doing it, and we'll provide an update on the guide, but we wanted to give people a view of having some direct visibility to cash flow growth.

Understood. And then besides the buybacks, is there anything else that you guys are working on? And the buybacks on the uplist, I guess. But now that Cumulus has been monetized, are you guys working to replicate this strategy at other plans? Are you looking at any potential combinations with either public or private IPPs? Is there any thought about maybe enlarging the existing portfolio again to either like a large M&A transaction or asset-based transactions?

Yes. Appreciate the question. And I like your persistence on it. As you know, we don't comment on M&A. But I will tell you the same thing. We did mention that we're looking to release the escrow. That's a big deal for us, right, to get that done, the milestones as part of that deal as well as we're starting to collect revenues from the long-term contracts with AWS. And then we're looking to implement that because we've laid out a schedule as everyone knows, on March 4, where we showed half campus built, full campus built. We're looking to do as much as we can to make sure that, that becomes more and more real and sooner rather than later. We're also working on the coin aspect, as I mentioned, I wouldn't say it's necessarily a mandate, but we are saying that we're going to get out of coin at the right value. And so we've got a lot going on there, and we also just completed the transaction, ERCOT and closed that, and that was just on the heels of AWS. And then we repriced the term loan. So I think we've been doing quite a few things, quite frankly. And we're going to continue to do so. But we don't talk about some of the other stuff that we could or could not be working on. We'll let you know when we get them done.

Okay. And the last one about PJM capacity prices. So we have these 2 auctions this year. The first one still have some rule changes that will not be implemented. But I'm just wondering, your set of assets seems uniquely sensitive to capacity prices in PJM. So I'm wondering how you see those evolving?

Well, look, we'll see where the auction clears, don't want to front run the auction. We do think that the power markets are tightening, and that should be reflected in the capacity markets. If you look at the last couple clears for RTO and MAC, they've been fairly low. And I think you see continued retirements and also new rules that are tightening the markets. And I think, by the way, our gas plants, I hope one of the things that Terry went through is that, yes, while those gas plants in the past or last couple of years have been more of a capacity play, as you mentioned. Going forward, and if you look at the expanding sparks and I forget what the exact slide number that is there, Terry, but the [ 7 ], these gas plants are becoming more and more in the money generation, if you will, as sparks expand. And so they are both a capacity and an energy spark play. But we'll have to see, Angie, when it comes to that, I don't like to front run those. We have our views, but we do think that the markets are tightening and should be reflected in the next '25, '26 auction in July.

Your next question comes from the line of Ian Zaffino from Oppenheimer.

I know you guys gave us a little bit of an update on the potential for other data centers at some of your other locations. You had ongoing discussions about that. And if that's the case, what would you need to to create data centers or at least make the facilities available for a data center, either let's just say, a Colstrip or Lower Mount Bethel.

Yes. Ian, good to hear from you. Look, I appreciate it. It's a fairly open-ended question. I think that what we've been able to create in a first-mover advantage, if you will, with the AWS transaction is to demonstrate that we learned a lot on how to contract and how to contract long term in a data center capacity. And obviously, we're going to look to leverage that. But there's nothing that we can comment on right now other than say that it's a little bit interesting to say, well, we're looking at it, and we're working on it. But that's what you're going to get because we don't talk about commercial activities until we're done.

Okay. And then on the $1 billion buyback or potential, any thoughts on how you're going to do that? Would it be a [ Dutch ]? Would it just be open market purchases? What should we expect on a way to return just this much capital?

Ian, this is Terry, definitely by the way. Yes. So with respect to the share repurchase program, we'll utilize a number of different avenues for that at the end of the day. And I guess what I would commit to you is, #1, the $1 billion has been approved by the Board. And so that is locked and loaded, and we'll execute that between now and the end of 2025. I think the other thing is we want to return money to our shareholders in a timely manner. And so we'll move with purpose when it comes to doing that. So hopefully, that gives you a sense of the direction of travel with respect to the share repurchase program. All right.

[Operator Instructions] Your next question comes from the line of Hamed Khorsand.

So my question was really about when you look out to '26 and you're seeing this kind of demand and the expectation that demand is going to go up, what's the risk here that you have regulatory action where it increases the supply? And obviously, the nation is not going to run out of electricity.

Yes. Well, it's a good question. I mean if you look at the market and particularly the market that after we're out of ERCOT, we're now principally in PJM. The entire concept of the capacity market that has been introduced that has been revamped several times, and we're getting ready to do an auction here for next year's planning year '25, '26, which is intended to be 3 years in advance. The concept of that market is to drive and to send signals for new build generation. And so hopefully, when we get back to steady state capacity markets, that will send a signal for growth. Now I think that there's a lot of perhaps externalities that are going to be consequential when it comes to new generation coming on, which is regulations. There's been a huge push to go towards renewable generation, which is not dispatchable, and renewable generation as well as some newbuild thermal generatoin is typically away from load centers, which requires additional transmission build as well. And so I think that all of those can be solved over time, okay? If you look at, for example, I mean, just look at the RMRs that we filed at Brandon and Wagner, there is transmission upgrades that are going to come to relieve that, but it's going to take as estimated by PJM at least 3 years to get that done, and $800-plus million of transmission. So I think all of those constraints will eventually resolve themselves, and they will because of energy security, and we won't let the light necessarily go out as a country, but they will take time to resolve. And I think in the past, the response has been that there has been a queue that could be ramped up and hit the grid quicker. But we have not seen CCGT build to any material size. I think some of the financing and the raising of money around that has atrophied as well. And so you're going to see those be longer lead time items. And I think that there's other places in the world that you're starting to see supply chain issues associated with gas turbines. So there's a lot that needs to get resolved in there. And hopefully, we get back to a capacity market that sends a 3-year forward signal that allows for this to work its way through the market.

Okay. I appreciate that. And then my follow-up was going to be, you have a plant that says being asked to be kept online that you were going to retire here. Is there going to be any increased CapEx, if you look out into '26 and that plant stays online because of the current situation you're describing?

I mean, yes, we have filed with FERC and those are on the docket, you can look there. And if you need to, we can follow up with you and get to those dockets, but we filed our costs associated with it and includes CapEx. One of the things when you look to, for example, at Brandon, which is a coal facility in the harbor there in Baltimore, the coal facility that you expect to shut down and we had said that it was going to be shut down in May of next year, June 1, effectively May 31 of next year, '25. But obviously, you don't necessarily starve anything of CapEx, but you don't necessarily plan to run it for 3 more years. And so decisions are made around that. And those decisions will have to be reversed and there will have to be capital that goes in, in order to ensure the reliability of Brandon, when it's called upon to relieve transmission constraints under an RMR agreement. But it would be included in the cost of that RMR just to be clear. And those costs are included in that docket that I was referencing at FERC.

There are no further questions at this time. I would now like to turn the call back to Mac.

Well, great. Thanks, everyone, for joining us today and for your continued support of Talen. We really believe we're at the intersection of some interesting catalysts as a pure-play IPP, the data center opportunity, spark and power price expansion combined with downside protection of the nuclear PTC. It's really an exciting time for us. Thanks, and have a great day.

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