PPL Corp (PPL) — Q1 2025 Earnings Call Transcript

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 can be found in the appendix. I'll now turn the call over to Vince.

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, 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 through 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, 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 queue, 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 requests in our Kentucky queue. 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 the 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 share owners. That concludes my strategic and operational update. I'll now turn the call over to Joe for the financial update.

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 in 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 share owners. This concludes my prepared remarks. I'll now turn the call back over to Vince.

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 shareholders. And we look forward to building continued momentum as we proceed throughout the year. With that, operator, let's open it up for questions.

Hey, guys. Thanks. Good morning.

Morning.

Could you elaborate on the resource adequacy legislation mentioned earlier? What advantages do you see for the investor-owned utilities compared to the independent power producers when it comes to bringing generation to market? It appears that everyone is dealing with the same issues related to turbine availability. I'm trying to understand what might make the investor-owned utilities more efficient or advantageous. Additionally, could this situation lead to offering a better price signal to generators through a long-term power purchase agreement structure? Do you think it's preferable to build yourselves or to create incentives for others to build and potentially profit from that? Thank you.

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 the 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 generation, we are absolutely willing to build and 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 generation companies 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.

Perfect. That's helpful. Let me quickly ask Joe. We've been receiving many inquiries about equity. Joe, is a block a consideration, or are the forwards under the ATM sufficient at this time? Thanks.

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 good about where we are 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.

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

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 whatever is the most efficient tool at the time we have the need. So continuing with the base of the ATM program, but continue to assess other options.

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

Thanks, Shar.

Good morning, Jeremy.

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?

Sure, it's Joe. We have two battery projects underway. One is a 125 megawatt facility that is currently under construction, and we are in constant communication with the vendor to minimize any potential tariff impacts. The second project, which you mentioned, is part of the 2025 filing for 400 megawatts of storage. We recognize the need for these projects due to the significant economic development and demand from data centers. We believe that batteries are the best solution to fulfill that demand. However, as you pointed out, there may be other options for the 2025 project. If companies increase their battery production in the U.S., that could help reduce some of the tariff pressures. Fortunately, we have time to navigate this process for the second unit and will continue to collaborate with various battery manufacturers.

Thank you. I have a question regarding the recent announcement in Kentucky and Oldham County. How do you see this potentially creating more opportunities for generation needs in that area? Also, what are your thoughts on resident concerns or other factors that might affect the project's viability from your perspective?

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 in the queue. So it's part of that that we're working through, certainly provide more information at the appropriate time when that becomes available.

Appreciate it. Thanks. I’ll leave it there.

Hi. Good morning. Thank you.

Good morning, Paul.

I was just going to stay in Kentucky for a little bit longer. Could you share any perspective or thoughts on the coal executive order and if that could change the timing or potential of the roughly 300 megawatts of retirements that you have planned?

Sure. So I don't expect that the executive order 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, a 300-megawatt unit that's scheduled to retire in the 2027 timeframe, 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 online in 2031, comes online. So a lot to 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.

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.

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 Generation 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 Generation 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 we will need to do. But again, that's not a material amount to our $20 billion capital plan.

Okay. Thank you very much, Vince.

Welcome.

Thank you. I have two questions regarding Pennsylvania. We haven't seen any public announcements about the 11 gigs or the original 9 gigs of load growth in your area. I am curious if we are waiting for something, such as guidelines from FERC or the Pennsylvania Utilities Commission. That's my first question.

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 agreements. 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.

But I'm curious if you're finalizing these data center deals without waiting for that model tariff to be established.

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.

And just one more thing. Regarding that hearing, there were many comments from the hyperscalers about the duration of load studies. It didn't seem that those comments were negative towards you. However, some other utilities, particularly in Eastern Pennsylvania, mentioned that they need to re-evaluate their load studies due to load being added in adjacent zones, which I consider includes the PPL zone. So, do you still have a significant advantage concerning the time to power benefit? Is that disproportionately benefiting your zone in terms of attracting load growth in Pennsylvania?

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.

Very good. Thank you.

Sure.

Hey, good morning, Vince. Good morning, Joe.

Good morning, Anthony.

Thanks for squeezing me in. If I could just stay on the path 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 requests in advanced stages, how much of that is ESAs?

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.

Great. If I could just shift the conversation to CPCN in Kentucky. I'm sorry if this was mentioned in the last call or in the filing, but have you disclosed the price for the CCGTs? If the price isn't already locked in, do you think that could be an issue for the approval of the unit?

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, etc., 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.

Great. Is there existing load that the CCGTs will supply for, or is it more about the prospective load that you anticipate coming into the system in Kentucky, as indicated by some of the data center requests?

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.

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

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?

Yes, it really depends. I think those comments were probably more applicable to Kentucky when we saw that initial announcement which essentially doubled the queue in just a couple of months, increasing from 3 to 6 gigawatts of interest. We're already managing 50 to 60 gigawatts of interest in Pennsylvania. There’s a significant interest primarily because we can connect them to the grid quite quickly, by mid-2026. Moreover, we are much easier to work with compared to traditional utilities, and they appreciate that the speed to market is better with us than with others. Additionally, we've discussed before the natural advantages of Pennsylvania—the land, the water, the cyber capabilities, and our transmission capacity. So, I believe there is considerable interest in Pennsylvania regardless of those announcements. I’m not sure that one announcement will necessarily lead to many others, but there’s substantial activity focused on the goal of getting connected as soon as possible in 2026.

That makes sense. Regarding the socialized cost you mentioned when discussing Pennsylvania, how should we consider the earned return on that cost? Is it just related to the formulated rate? Also, does that return on equity include any ISO adders or similar components?

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

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?

I think that it's very close to that, David. I don't think it's materially different between the two.

Thank you so much.

Sure.

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 you haven't 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?

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, we are looking at whether it makes sense to have a data center or a large load tariff, not just for data centers.

Okay. That's obviously very helpful. Again, thanks for taking the questions.

Great. Thank you.

Great. Thanks, everybody, for joining us. Again, off to a good start for the year, continuing 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.