PPL Corporation (NYSE:PPL) Q1 2025 Earnings Call Transcript

PPL Corporation (NYSE:PPL) Q1 2025 Earnings Call Transcript April 30, 2025

PPL Corporation beats earnings expectations. Reported EPS is $0.6, expectations were $0.53.

Operator: Good day, and welcome to the PPL Corporation First Quarter 2025 Earnings Conference Call. All participants will be in a listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note today’s event is being recorded. I would now like to turn the conference over to Andy Ludwig, Vice President, Investor Relations. Please go ahead.

Andy Ludwig: Good morning, everyone, and thank you for joining the PPL Corporation conference call on first quarter 2025 financial results. We provided slides for this presentation on the Investors section of our website. We’ll begin today’s call with updates from Vince Sorgi, PPL President and CEO; and Joe Bergstein, Chief Financial Officer. And we’ll conclude with a Q&A session following our prepared remarks. Before we get started, I’ll draw your attention to Slide 2 and a brief cautionary statement. Our presentation today contains forward-looking statements about future operating results or other future events. Actual results may differ materially from these forward-looking statements. Please refer to the appendix of this presentation and PPL’s SEC filings for a discussion of some of the factors that could cause actual results to differ from the forward-looking statements.

We will also refer to non-GAAP measures, including earnings from ongoing operations or ongoing earnings on this call. The reconciliations to the comparable GAAP measures, please refer to the appendix. I’ll now turn the call over to Vince.

Vince Sorgi: Thank you, Andy, and good morning, everyone. Welcome to our first quarter investor update. Turning to Slide 4. I’m pleased to share that we’re off to a strong start this year as we continue to make progress on our Utility of the Future strategy. Today, we reported first quarter GAAP earnings of $0.56 per share. Adjusting for special items, first quarter earnings from ongoing operations were $0.60 per share or an 11% increase over ongoing earnings of $0.54 per share a year ago. This increase was supported by additional returns on capital investments to improve service to our customers as well as higher sales volumes, which reflect more favorable weather this year compared to last year. Looking ahead, we remain confident in our ability to deliver on our 2025 ongoing earnings forecast of $1.75 to $1.87 per share with a midpoint of $1.81 per share.

We’re on track to complete over $4 billion in infrastructure improvements this year to strengthen grid reliability and resiliency, make our operations more efficient and advance our generation replacement strategy in Kentucky. We continue to project $20 billion in capital investment needs from 2025 to 2028, resulting in average annual rate base growth of 9.8%. We also remain on track to deliver at least $150 million of cumulative O&M savings compared to our 2021 baseline. A key component of our Utility of the Future strategy to help support customer affordability. Finally, we remain confident in our ability to execute our long-term business plan and are well positioned to achieve the top half of our projected 6% to 8% annual earnings per share growth target to at least 2028.

On the dividend, we continue to target annual growth in the 6% to 8% range. And we also expect to maintain strong credit metrics throughout the plan period, maintaining a 16% to 18% FFO-to-debt ratio and a holding company to total debt ratio below 25%. Moving to Slide 5 for operational and regulatory highlights. On February 28, we filed the CPCN request with the Kentucky Public Service Commission to address near-term generation needs identified in LG&E and KU’s latest integrated resource plan. And reinforced by recent increases in demand for electricity in our Kentucky service territories. The plan includes the construction of two new highly efficient 645-megawatt natural gas combined cycle units with 2030 and 2031 in service dates. The addition of 400 megawatts of battery storage by 2028 and upgrades to environmental controls on Unit 2 at our generating station.

To date, the CPCN process has proceeded as expected. The KPSC has set a hearing date of August 4, and we anticipate a decision on our request by November. Also in late February, LG&E and KU received regulatory approval to recover $125 million in costs associated with the retirement of Mill Creek Unit 1 through the retired asset recovery rider. Recall that this rider allows for recovery of and a return on certain generation retirement costs. The approved costs will be recovered over 10 years through the rider. Finally, Construction continues to advance on several new previously approved generation resources in Kentucky. We recently began construction on both the 120-megawatt Mercer solar facility and the 125-megawatt battery storage system at our brown station.

And we continue to make good progress on our 640-megawatt combined cycle natural gas facility, which we began at our Mill Creek Station mid-last year. We expect completion of these projects in 2027 and early 2028. This is critically important as Kentucky continues to be a tremendous success story. When it comes to economic development that creates new jobs, and additional tax revenue for Kentucky communities. Our generation strategy directly supports this economic development. Turning to Slide 6. Just as we’ve done in Kentucky, we’ve continued to advance key initiatives in Pennsylvania and Rhode Island that support safe, reliable and efficient energy service to our customers. In February, we secured Pennsylvania PUC approval to increase PPL Electric Utilities disk revenue cap to 7.5%, up from the prior cap of 5%.

The new cap will be in effect through the remainder of PPL Electric’s current long-term infrastructure improvement plan, which extends through 2027 or until a new distribution base rate case takes effect, whichever occurs first. In Rhode Island, we received approval for nearly $400 million in infrastructure investments in select operating costs in connection with our latest electric and gas infrastructure, safety and reliability plans. The Rhode Island ISR is a very constructive capital recovery mechanism, and we appreciate the PUC’s continued support in approving these critical investments via this mechanism. The ISR plans for gas and electric are submitted annually and outline proposed capital investments and related operating costs to strengthen the safety, reliability and resiliency of our electric and gas distribution networks.

The latest plans at Trust Rhode Island Energy’s proposed spending from April 1, 2025, to March 31, 2026. Included in the nearly $400 million approval is approximately $220 million in capital investments for Electric, which includes $88 million for advanced metering infrastructure and approximately $145 million for capital investments in gas, including $108 million for gas main replacements. The PUC also authorized recovery of approximately $35 million in operating costs for vegetation management and restoration paving tied to gas main replacement projects. We look forward to executing on these plans and continuing our delivery of exceptional service to the residents of Rhode Island. Moving to Slide 7. We continue to see increased interest from data center developers in our Pennsylvania and Kentucky service territories.

In Pennsylvania, we now have nearly 11 gigawatts of projects in the advanced stages of planning, up from nearly 9 gigawatts as we shared last quarter. Keep in mind for a project to be in the advanced stages of planning, it means the data center developer has signed a letter of authorization, which allows us to begin spending money to connect them to the grid. The developer in turn is obligated to reimburse us for those costs. As a result, developers in this phase have more at stake and while that doesn’t guarantee that a data center will be built, it certainly signals a higher probability of connection. The potential capital investment related to these data centers in advanced stages in Pennsylvania ranges from $700 million to $850 million, of which we have $400 million in the plan.

And within this category of projects, we now have load that has progressed to fully executed contracts. Importantly, we’ve structured these energy services agreements to include minimum load commitments for the data centers, which significantly reduces the risk to our other customers from these large projects. In addition to the projects in advanced stages, we now have more than 50 gigawatts of other interconnection requests in our Q, demonstrating continued interest in our Pennsylvania service territory. And as we’ve shared previously, connecting large-scale data centers is a win-win for our customers as these data centers will share in the cost of transmission system, and they will help reduce transmission costs for our other customers. Turning to Kentucky.

We remain very excited to support our first 400-megawatt data center customer, which we highlighted on our year-end earnings call. In addition, we continue to manage nearly 6 gigawatts of active data center request in our Kentucky Q. And the Kentucky legislature recently expanded the sales tax incentive program for data center projects across the entire Commonwealth and not just in Jefferson County. We expect this will further attract data centers to Kentucky, including across our broader service territories. Turning to slide 8 and several items on the horizon. On April 4th, we notified the Kentucky Public Service Commission of our intent to file a base rate case on/or after May 30th. As background, LG&E and KU’s last base rate increase occurred in July 2021, at which time we agreed to a four-year stay-out provision.

Our intent with the expected filing will be to seek new rates effective January 1, 2026 to support continued infrastructure investments that improve reliability, enhance the customer experience, enable long-term grid resilience, and support projected load growth. Our application will be supported by a fully forecasted test period ending, December 31, 2026. Turning to Pennsylvania. We continue to advocate for legislative changes to incentivize construction of new generation in the commonwealth that help address both rising electricity prices for consumers and potential energy shortfalls. We believe Pennsylvania must take control of its energy future rather than being wholly reliant on the PJM market, which is struggling to incentivize new generation build even with all the expected load growth coming from data centers.

We believe one way of addressing this issue is to allow regulated electric utilities to invest in generation resources. This would complement the competitive market by addressing resource adequacy gaps rather than relying solely on market forces to deliver a solution. We’re absolutely convinced the time to act is now, and we’re encouraged by the recent introduction of legislation, House Bill 1272 that supports allowing regulated utilities to build and own generation in the state. A co-sponsor memo was also filed in the Senate, and we expect companion legislation later this spring. Finally, PPL is very well-positioned to manage through the recently proposed trade tariffs, and we do not expect a significant impact on our plan. Our team has done an excellent job managing supply chain disruptions and constraints for several years now.

I’d highlight that about 70% to 80% of our capital projects and nearly 90% of our O&M is labor. On top of that, most of our materials are sourced domestically. So the size of the potential impact from tariffs shrinks very quickly. Bottom line, we remain very well positioned despite the current macroeconomic uncertainty and remain very confident in our ability to deliver our plan for customers and shareowners. That concludes my strategic and operational update. I’ll now turn the call over to Joe for the financial update.

Joe Bergstein: Thank you, Vince, and good morning, everyone. Let’s turn to Slide 10. PPL’s first quarter GAAP earnings were $0.56 per share compared to $0.42 per share in Q1 2024. We recorded special items of $0.04 per share during the first quarter, primarily due to IT transformation costs, a settlement charge related to energy efficiency programs in Rhode Island for activity prior to our ownership and some remaining Rhode Island integration costs. Adjusting for these special items, first quarter earnings from ongoing operations were $0.60 per share, an improvement of $0.06 per share compared to Q1 2024. Our solid first quarter results keep us on track to achieve at least the midpoint of our 2025 earnings forecast of $1.81 per share.

We also continue to maintain one of the strongest balance sheets in our sector, which provides the company with significant financial flexibility. In February, we established a $2 billion ATM program that supports our financing needs associated with the increased capital plan. Year-to-date, we have issued about $170 million of equity through the ATM with forward contracts that expire at the end of the year. We continue to expect to issue between $400 million and $500 million of equity in total this year. Turning to the ongoing segment drivers for the first quarter on Slide 11. Our Kentucky segment results increased by $0.05 per share compared to the first quarter of 2024. The improvement in Kentucky’s results was primarily driven by higher sales volumes, primarily due to mild weather experienced during the first quarter of last year.

$0.01 of that favorable variance was due to colder-than-normal weather in Q1 2025. Our Pennsylvania Regulated segment results increased by $0.03 per share compared to the same period a year ago. The increase was also primarily driven by higher sales volumes due to mild weather experienced last year as well as higher transmission revenue from our ongoing capital investments. Our Rhode Island segment results decreased by $0.01 per share compared to the same period a year ago. This decrease was primarily driven by lower transmission revenues due to a prior period true-up and higher operating costs, partially offset by higher distribution revenue from capital investments. Finally, results at Corporate and Other decreased by $0.01 per share compared to the prior period, primarily due to higher interest expense.

We continue to be pleased with our execution as we deliver on our commitments to customers and shareowners. This concludes my prepared remarks. I’ll now turn the call back over to Vince.

Vince Sorgi: Thank you, Joe. In closing, we’re off to a good start with our strong first quarter results. Our Q1 performance puts us solidly on track to deliver on our 2025 commitments. Meanwhile, across our operations, we continue to make excellent progress in executing our utility of the future strategy. We’re responsibly investing in our networks, which supported first quarter storm response that was considerably improved compared to last year despite more severe weather this winter. We’re progressing in building new and cleaner generation resources in Kentucky that support our communities. We’re achieving our O&M savings targets that benefit our customers in a time of inflationary pressures. We’re driving continued economic development in our regions, including new data centers.

And we’re advancing an IT transformation that includes key digital solutions that will strengthen cybersecurity, improve the customer and employee experience, improve our grid operations, and make our field workers more efficient and effective in their jobs, all while lowering our ongoing technology costs. We’re extremely excited about the opportunities ahead for PPL, our customers, and our share owners. And we look forward to building continued momentum as we proceed throughout the year. With that, operator, let’s open it up for questions.

Q&A Session

Operator: Thank you. [Operator Instructions] Today’s first question comes from Shar Pourreza with Guggenheim Partners. Please go ahead.

Shar Pourreza: Hey, guys. Thanks. Good morning.

Vince Sorgi: Morning.

Shar Pourreza: So, let me just — on the resource adequacy legislation that you kind of talked about in your prepared remarks. Maybe just speak a little bit what you see as the advantages of the IOUs versus the IPPs and bringing generation to market? I mean, it seems like everyone faces the same turbine Q issue. So trying to understand, I guess, what makes IOU the faster or better? Or could this actually turn into maybe providing a better price signal to generators through a longer term PPA structure. So, do you really want to build or provide that incentive for someone else to build and maybe earn on that incentive? Thanks.

Vince Sorgi: Yes, Shar, there’s quite a bit there in that question. I think the limitation with the market is the capacity, the market is really a one year price signal three years forward. And so right, the question becomes, is that enough to incentivize the competitive market to build new generation 30, 40-year assets and can you finance it? Obviously, that’s a different calculation and calculus when you’re in a regulated utility model with the asset going in rate base, it’s getting depreciated over 40 years. So, from a stability of power price and predictability and reducing volatility, clearly, I think the regulated utility model can provide some benefits there. In terms of your question on the PPA versus building gen, we are absolutely willing to build an own generation in rate base in Pennsylvania, should we be allowed to do that with this new legislation.

Obviously, we have one of the highest performing Gencos down in Kentucky. Our Engineering and Construction Group is building new generation as we speak. We could clearly do it in Pennsylvania as well as we’re doing it in Kentucky. So, we are able and ready to provide that service to the market and our customers if we’re allowed to do it. On the PPAs, we do have the ability to do some of that today under the default service provisions that we have. It would be somewhat limited when you’re thinking about our load that’s under default service and the need across PJM. So, we could probably do a little bit there, but not enough to really solve the issue that we’re talking about, Shar.

Shar Pourreza: Perfect. No, that’s helpful. Let me just quickly for just a quick one for Joe. Obviously, we’ve been, the past few weeks, we’ve been getting a lot of inbounds on equity, right? I just — I guess Joe, is a block a consideration or the forwards under the ATM kind of sufficient at this time? Thanks.

Joe Bergstein: Yeah. Shar, thanks for the question. So I mean, as we’ve said since we provided our updated plan in February, our base case is that we’ll use the ATM program to satisfy most of our equity needs. And clearly, we see it as an efficient cost-effective tool and it’s obviously been that to-date. And so we feel really about where we are in now. But given our flexibility and the position that we’re in, we’ll remain opportunistic and continue to assess all of our options and just try to achieve the most efficient cost of capital that we can.

Shar Pourreza: Got it. But Joe is that still the ATM route?

Joe Bergstein: I mean again, we like the ATM. And we’re very happy with the execution of that. But I think as we’ve talked about and I said before, that we will evaluate the market and use what is ever the most efficient tool at the time we have the need. So continue with the base of the ATM program, but continue to assess other options.

Shar Pourreza: Okay. Perfect, that fantastic, guys, appreciate it. Congrats on the results.

Joe Bergstein: Thanks Shar.

Operator: And our next question today comes from Jeremy Tonet with JPMorgan. Please go ahead.

Joe Bergstein: Good morning, Jeremy.

Unidentified Analyst: Hey. Good morning. This is actually Eden on for Jeremy. Maybe just wondering, if we could focus more on the potential tariff exposures, and it looks like in the 2024, IRP, the plan includes roughly 400 megawatts of battery storage. Maybe you could just walk through how the tariff might impact that? Or like maybe just more broadly, the domestic versus international breakdown you’re kind of seeing anything else on that ones?

Joe Bergstein: Yeah. Sure. It’s Joe. So we have actually two battery projects. One that was part of the 2022 CPCN for 125 megawatts that battery facility is under construction and so we’re obviously talking to the vendor all the time and working closely with them to try to minimize any potential tariff impacts there. And then, the one that you referenced is in the 2025 CPCN filing for 400-megawatt storage. Clearly, we see a need for those projects given the significant economic development we’re seeing and the data center interest and just that increasing demand. So we think — continue to think that the battery is the best solution to meet that plan. But certainly, as you suggest there’s potentially other options for the battery in the 2025 CPCN and if we see companies increase their U.S. production of batteries, then that could alleviate some of the pressures on the tariff.

And so with that second unit, we have time, obviously, to work through that. And we’ll continue to do that with a variety of vendors that are manufacturing batteries.

Unidentified Analyst: Got it. Got it. Thank you. And then maybe just one question on — I appreciate the ongoing nature here, but like to what extent do you see the recent announcement in Kentucky and Oldham County kind of maybe potentially unlocking more upside to generation needs there and just any other thoughts on resident concerns or other considerations to that project’s viability from your perspective?

Vince Sorgi: Yeah. This is Vince, Eden. So yeah, you’re referencing a potential project in Oldham County, it’s called Project Lincoln. Obviously, there’s been some media attention on that. We don’t have a lot more to share at this point. But clearly, we are working with the developer there, excited to provide them with whatever needs they have to get that project over the goal line at this point, not much more to share. But obviously, it’s a good indicator of the continued interest that we’re seeing down there. That is in our 6 gigawatts of in the Q. So it’s part of that that we’re working through, certainly provide more information at the appropriate time when that becomes available.

Unidentified Analyst: Appreciate it. Thanks. I’ll leave it there.

Operator: Thank you. And our next question comes from Paul Zimbardo with Jefferies. Please go ahead.

Paul Zimbardo: Hi. Good morning. Thank you.

Vince Sorgi : Good morning, Paul.

Paul Zimbardo : I was just going to stay in Kentucky for a little bit longer. Just could you share any perspective or thoughts on the coal executive order and if that could change the timing or kind of potential of the — I think it’s roughly 300 megawatts of retirements that you have planned?

Vince Sorgi: Sure. So I don’t expect that the EO would have necessarily an immediate impact on our generation planning. You did reference our really the only plant that we have in the near term that is scheduled to retire, which is Mill Creek 2, it’s a 300-megawatt unit that’s scheduled to retire in the 2027 time frame, commensurate with Mill Creek 5, which is the combined cycle unit that we are currently constructing. At this point, Paul, the air permit for Mill Creek 5 depends on us retiring Mill Creek 2. But that is something that we will certainly be I think analyzing and discussing with stakeholders as part of the CPCN approval process, especially if we continue to see the interest in Kentucky around data centers and some of that load comes to fruition we may want to delay the retirement of Mill Creek 2, at least for a period of time, perhaps when Mill Creek 6, which is the one that would come on in 2031, comes online.

So a lot to, I think, analyze and discuss there, not necessarily the executive order. I think that’s driving that. It’s more just the demand and how we want to best meet that demand, which we will, again, go through with the CPCN process that we’re actively engaged with right now with the commission.

Paul Zimbardo: Okay. And then I guess just overall, holistically as it relates to that and elsewhere, I don’t want to put words in your mouth, but you feel comfortable on the overall capital plan, there could be some changes potentially, but you feel good on capital and the overall outlook, it sounds like.

Vince Sorgi: Yes. Yes, we do. We don’t have a lot of environmental CapEx in the plan. We have less than $400 million total. The 2 big components of that are the SCR at Gen 2. That’s obviously in the CPCN filing that we’re working through right now. We would expect at this time to continue to install that SCR that would enable us to really ensure that we can run that unit in the long term during the OSO season. So there’s a real strategic need to have Gen 2 available. That’s about a $150 million project. And then the remaining $250 million in there is for the fluid limitation guideline rules. Again, based on what we’re seeing from the administration, we could see some modification to those rules. Not sure exactly where we’ll land on that and if and how much of that $250 million will need to do. But again, that’s not a material amount to our $20 billion capital plan.

Paul Zimbardo: Okay. Thank you very much, Vince.

Vince Sorgi: Welcome.

Operator: Thank you. Our next question comes from Angie Storozynski with Seaport. Please go ahead.

Agnie Storozynski: Thank you. So I have two questions about Pennsylvania. So I mean we haven’t seen any announcements at least public announcements about the 11 gigs or even the original 9 gigs of low growth in your zone in Pennsylvania. And I’m just wondering if — are we waiting for something? Is this — are we waiting for some guidelines either for — from FERC or from the Pennsylvania Utilities Commission. So that’s one. And number two, speaking of the Pennsylvania PUC, the third day hearing on the interconnection of large loads, very interesting overall. I wonder the commission is clearly considering a potential model tariffs for large loads. Your representatives didn’t seem that interested in that option. And I’m just wondering if you have a view overall, what it takes to have the DC load finalized in your zone?

Vince Sorgi: Sure. So I think they’re somewhat related those questions, Angie. Maybe I’ll start with just a lack of announcements. So not anything I’m concerned about. We are making excellent progress on a number of the projects that are in there. We don’t really control the timing of when the data centers want to make those announcements. There’s obviously a lot of competitive positioning that they’re taking into account when they make those announcements. So we’re just not going to get in front of them on that, but no concerns there. The reason I feel the way I do, and again, a proof point in our materials is the fact that we have signed energy services agreement. So even beyond just the authorization to spend money we’ve got to the point where we’ve signed agreements.

And so it will just be a matter of time before those counterparties make their public announcements. What we’ve been able to do within those ESA agreements is really protect our existing customers from stranded asset risk, which we know is an area that has been a concern at commissions across the country. And what we’ve done there is, right, there’s really two components that make up the cost of connecting a data center. There’s the costs that are specific to the data center, and those we get reimbursed under contributions in aid of construction. So those are direct reimbursements from the data center. But then there’s the other upgrades that may be required to the grid that all customers benefit from. So those costs end up going into the FERC formula rate, and they get socialized across all of our customer groups.

So what we’ve done with the ESA agreements is we’ve obligated the data center customers to pay a minimum revenue based on their peak load regardless of their actual electric usage, until the cost of that socialized upgrade. So the piece that’s being charged to all customers is paid off. And then we also have letters of credit and termination fees included in those agreements. So that structure essentially is protecting our customers against stranded asset risk. That’s why we in the hearing, we said we don’t necessarily need a model tariff to be able to achieve the same objective because we’re already achieving those objectives with our ESA contracts and so our testimony was to ensure that we can maintain the flexibility required to balance getting these large loads connected to the grid, but at the same time, protecting our customers.

So if there is ultimately a large load model tariff, we would just want to make sure that, that flexibility is preserved.

Angie Storozynski: But I’m just wondering — but you’re not waiting, but you’re not waiting for that model tariff to be established before basically finalizing these data center deals?

Vince Sorgi: No, no. No, we’re entering into ESAs as we speak. And those are not insignificant. I mean, we’re talking multiple gigawatts that we’re signing up.

Angie Storozynski: And just one more. So again, back to that hearing. So lots of comments there from the hyperscalers about how long load studies take? It didn’t sound like that was against you at all. But there were some other utilities, especially in Eastern Pennsylvania that were saying that they need to rerun some of their load studies as there is load being added to adjacent zones, which I took up the PPL zone. So is it — do you still have this material benefit on the time to power benefit? And is that in a sense disproportionately benefiting your zone as far as attracting the load growth in Pennsylvania?

Vince Sorgi: Absolutely. We continue to respond very quickly and nimbly to our large load customers. Again, we’re getting back to them with initial quotes and study results of our studies in weeks, not months. And we consistently hear from our data center customers that it is a different experience dealing with PPL than some of our peers.

Angie Storozynski: Very good. Thank you.

Vince Sorgi: Sure.

Operator: [Operator Instructions] Our next question today comes from Anthony Crowdell with Mizuho. Please go ahead.

Anthony Crowdell: Hey, good morning, Vince. Good morning, Joe.

Vince Sorgi: Good morning, Anthony.

Anthony Crowdell: Thanks for squeezing me in. If I could just stay on the pat that Angie brought up, I’m curious if you’re able to tell us or would you tell us when we look at the chart on Slide 7 on the data center request in advanced ages, how much of that is ESAs?

Vince Sorgi: Yeah. So those terms are confidential at this point. But as I just said at the end of my comments to Angie, we’re talking multiple gigawatts. So not insignificant, Anthony.

Anthony Crowdell: Great. And then if I could just pivot you talk about on the — I’m sorry, CPCN in Kentucky. Just — and you may have disclosed it on the last call, and I apologize if I missed it, in the filing, have you disclosed what the price is for the CCGTs and will that — if it’s not already locked in the price does that — do you think that becomes an issue on approval of the unit?

Vince Sorgi: I mean, we do have our cost estimates in the CPCN filing. We’re kind of around that $2,000 per kW as we’re seeing kind of across the spectrum. At this point, based on where we are with our vendors and EPC contractors, et cetera, we feel pretty good about those amounts. But obviously, we are always engaging with the commission and updating them on cost estimates if they move significantly between the time we file the CPCN and the time that we would ultimately get approval for that. And then once that gets approved, there’s like a 5% buffer that we kind of have to manage within before we’d have to go back to the commission and update those numbers further, but that’s kind of how the process works.

Anthony Crowdell: Great. And is there existing load like — apologies again, is there existing load that this CCGTs are going to supply for? Or is it more on the prospective load that you see coming into the system in Kentucky as you highlight with the — some of the data center requests there.

Vince Sorgi: Yes. So what’s currently been approved was the retirement of Mill Creek 1, which we retired at the end of last year, again, about a 300-megawatt coal plant. And then Mill Creek 2 is scheduled to retire in 2027. So obviously, some of that new generation is replacing those retirements. And then the new CPCN is also to really handle new load requirements that we’re seeing from data centers and just other large economic development activity that’s occurring in the state.

Anthony Crowdell: Great. Thanks for taking my question. Really appreciate it. Congrats on a good quarter.

Operator: And our next question comes from David Paz with Wolfe. Please go ahead.

David Paz: Good morning guys. Yes, pre-stating questions are essentially what I was going to ask. But just maybe following up on the data center announcements. I think in the past, you’ve Vince, you suggested that once you hit 1 or 2 announcements all essentially prompt others to follow suit shortly thereafter. Is that still kind of the mindset I understand you have some ESAs in place. But are you still at that kind of we can see these come pretty fast once you get the first few?

Vince Sorgi: Yes. It really depends. I mean, I think those comments were probably more relevant to Kentucky when we saw that initial announcement drew basically a doubling of the of the Q in just a couple of months when we went from 3 to 6 gigawatts of interest in Kentucky. I mean we’re already dealing with 50 or 60 gigawatts of interest in PA. So there’s a lot of interest, I think, not only because we can connect them very quickly, mid-2026, to the grid. And then like I said before, we’re much easier to work with than your traditional utility. And they find that the speed to market is better when they’re dealing with us than others. So — and then obviously, we’ve talked a lot in the past just about the natural qualities of Pennsylvania, the land, the water, the cyber and then, of course, our transmission capacity.

So lots of interest, I think, in PA irrespective of those announcements. I don’t know that if we get one announcement that will necessarily trigger many others, but there’s just a lot of activity all trying to get to, I would say, the goal line of getting connected as soon as they can in 2026.

David Paz: That makes sense. Just on the socialized cost that you were talking about when you broke down those two pieces regarding Pennsylvania. What is the — remind me what — how should we think about the earned return on that socialized cost? Is that just to formulate rate? And what does that ROEs including ISO adders or anything?

Vince Sorgi: Yes. So those are the ROEs that are embedded in the formula rate, which is basically 10% right now.

David Paz: Okay. Great. And maybe one quick squeeze one on the 2,000 per kilowatt number. Is that inclusive of ABDC and transmission for the CCs in Kentucky?

Joe Bergstein: I think that it’s — it’s very close to that. David. I don’t think it’s materially different between the two.

David Paz: Thank you so much.

Vince Sorgi: Sure.

Operator: Our next question comes from Ian Rapp at Bank of America. Please go ahead.

Ian Rapp: Hey, guys. Thanks for taking my questions. I think the bulk of questions have been answered, but maybe just focusing a little bit more on the data center tariff structure relative to the Kentucky rate case filing. And I know made a determination for Pennsylvania yet. But just curious whether there are any contemplated tariff structure changes or anything related that we would expect to see in those rate cases?

Vince Sorgi: Yes. So obviously, we haven’t filed those yet. So it would be more appropriate to discuss that once we make those filings. But I would say in both jurisdictions, and we are looking at whether it makes sense to have a data center or a large load tariff, not just data center.

Ian Rapp: Okay. That obviously, seen there. That’s very [indiscernible]. Again, thanks for taking the questions.

Vince Sorgi: Great. Thank you.

Operator: Thank you. And this concludes our question-and-answer session. I’d like to turn the conference back over to Vince Sorgi for closing remarks.

Vince Sorgi: Great. Thanks, everybody, for joining us. Again, off to a good start for the year, continue the momentum as we go through the year. We have a few marketing events coming up later this week and into next week in New York. So look forward to seeing some of you then. And again, I appreciate you joining the call.

Operator: Thank you. This concludes today’s conference call. We thank you all for attending today’s presentation. You may now disconnect your lines, and have a wonderful day.