PPL Corp Q2 2025 earnings call

Good morning, everyone, and thank you for joining the PPL Corporation Conference Call on Second Quarter 2025 Financial Results. We have provided slides for this presentation on the investor 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. We'll conclude with a Q&A session following our prepared remarks. Before we get started, I'll draw your attention to Slide Two 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'll also refer to non-GAAP measures, including earnings from ongoing operations or ongoing earnings on this call. For reconciliations to the comparable GAAP measures, please refer to the appendix. I'll now turn the call over to Vince.

Thank you, Andy, and good morning, everyone. Welcome to our second quarter investor update. Let's start with our financial results and a few highlights from our second quarter performance on Slide Four. Today, we reported second quarter GAAP earnings of $0.25 per share. Adjusting for special items, second quarter earnings from ongoing operations were $0.32 per share. While the timing of certain expenses and milder weather than last year contributed to lower period-over-period results, as Joe will discuss in his remarks, we remain confident that we will achieve at least the midpoint of our 2025 Ongoing Earnings Forecast of $1.81 per share, as our plan assumed stronger earnings growth in the second half of 2025, resulting from higher returns on capital investments and lower O&M year over year.

We're solidly on track to complete over $4 billion in infrastructure improvements in 2025 to strengthen grid reliability and resiliency and advance a cleaner energy mix without compromising on affordability for our customers. We continue to incorporate new technology and explore the use of Artificial Intelligence in all aspects of our business, from the field to the back office, to drive better results and greater efficiency. As a result of our investments, we expect to build on our prior year's success and deliver cumulative annual O&M savings of $150 million this year compared to our 2021 baseline. We also continue to project $20 billion in infrastructure improvements from 2025 to 2028, resulting in average annual Rate Base Growth of 9.8%.

This does not include any capital expenditures that may be required under the new Joint Venture agreement with Blackstone Infrastructure to build new generation in Pennsylvania to directly serve data centers. Lastly, we're well positioned to achieve our projected 6% to 8% annual earnings per share and dividend growth through at least 2028, with EPS growth expected in the top half of that range. Throughout our plan, we expect to maintain our excellent credit profile with an FFO-to-Debt Ratio of 16% to 18% and a Holding Company-to-Total Debt Ratio below 25%. Turning to Slide Five, we have a number of positive business and regulatory updates this quarter. Let me begin with some key regulatory updates, starting with the stipulation agreement that we just filed with the KPSC earlier this week related to the CPCN proceeding to construct much-needed generation in Kentucky.

We were pleased to have announced a very constructive stipulation with many of the intervening parties to the case. The stipulation strikes the right balance between building new generation needed to support economic development in the state, including supporting anticipated data center load, and ensuring we maintain affordability for our customers. The stipulation supports approval of two 645 megawatt natural gas combined cycle units, Brown 12 and Mill Creek 6, as well as an SER for our Ghent Unit 2 coal plant, as we requested. It also supports mechanisms that reduce lag on these investments, including recommending approval of AFUDC treatment on both NGCCs during construction, as well as cost recovery of the Ghent 2 SER via our existing environmental cost recovery mechanism or the ECR.

The agreement also supports a new Tracker to recover costs of the Mill Creek 6 NGCC over the life of the plant, allowing for recovery of operating costs and returns of and on capital investments. The stipulation also supports the life extension of the Mill Creek 2 coal unit from the current retirement date of 2027 to 2031 when Mill Creek 6 is placed into service. Related to this plant life extension, the stipulation supports a new ECR-like mechanism to recover incremental O&M and capital costs required to keep Mill Creek 2 open, including any costs we incur in the remainder of this year. We also agreed to provide an analysis of operating Mill Creek 2 beyond 2031 as part of our next Integrated Resource Plan in 2027.

With the life extension of the Mill Creek 2 coal unit, the stipulation also requires the companies to withdraw the request for the Cane Run Battery Storage Project without prejudice. This means we can file another CPCN for the battery storage project at any time if needed. Should the commission approve the stipulation, we do not expect a significant change to our overall CapEx plan or Rate Base Growth projections, as we see additional investment needs across our networks that are not currently in our plan. We will provide a full CapEx and rate base refresh per normal course on our year-end call. The stipulation is subject to approval of the KPSC, and a hearing is scheduled for next Monday, August 4. We continue to anticipate a final decision by November 1 of this year. Turning to Slide Six and a few additional regulatory updates.

On May 30th, LG&E and KU filed a request with the Kentucky Public Service Commission (KPSC) for a combined $391 million increase in annual Electric and Gas Revenues to support continued safety, reliability, and resiliency investments in our systems and improve service to our customers. Our applications are supported by a fully forecasted test period ending December 31, 2026. It has been nearly five years since we saw the base rate increase in Kentucky. During the period from 2021 through 2024, the cumulative amount of inflation was 19.7%, which is significantly higher than the overall percentage increase of 10.7% that the companies are seeking in these cases. We expect a decision from the Commission by the end of the year and new rates to be effective on January 1. Turning to Rhode Island.

Earlier this month, we agreed with the Advocacy Section of the Division of Public Utilities and Carriers to settle the Hold Harmless Commitment related to our acquisition of Rhode Island Energy. In summary, the acquisition accounting resulted in the elimination of certain accumulated deferred income taxes, which resulted in an increase in Rate Base. At that time, we made a commitment that we would make bill credits that could extend nearly 40 years to hold our customers harmless from this accounting change. The settlement computed the net present value of those future Bill Credits to be $155 million. We agreed to credit our customers that $155 million in January, February, and March of 2026 and 2027. This is a very constructive solution that significantly improves affordability for Rhode Island customers when bills are at their highest in the winter, while at the same time satisfying a significant acquisition commitment.

We expect a final decision on the settlement in the coming weeks. Shifting to Pennsylvania. We now expect to file a Base Rate Case by the end of this year, our first PA Rate Case in a decade. The fact that we've been able to go so long without a base rate increase in Pennsylvania is a testament not only to the constructive regulatory framework in the Commonwealth, but also, and importantly, our strong focus on efficiency and affordability. We've created one of the most sophisticated grids in the nation in PPL Electric Utility Service Territory, and that, in turn, has driven not only substantial reliability improvements but also significant value for our customers, including the ability to quickly connect large load customers like data centers and manufacturing facilities.

Our expected rate request in Pennsylvania will support our continued efforts to strengthen the grid against future storms and incorporate advanced technology that allows us to work smarter and more efficiently while delivering a better experience for our customers. Now let's turn to Slide Seven and the exciting economic growth in Pennsylvania that is currently being powered by data centers. As we've said before, we have made it a strategic priority at PPL to serve data centers across our service territories as AI will be critical to America's continued competitiveness and national security, as well as the execution of our Utility of the Future Strategy. There are two main components to our data center strategy. First, we are enabling speed to market for the data centers by being able to connect them to the grid faster than they can get the data centers built.

Second, we are supporting several initiatives to develop new generation to serve this massive new load coming onto the grid. This includes our new Joint Venture with Blackstone Infrastructure that was announced at the inaugural Pennsylvania Energy and Innovation Summit held in Pittsburgh by Senator McCormick earlier this month. At the summit, state and federal officials, as well as technology leaders, highlighted Pennsylvania's unique position to lead the next wave of data center expansion. In total, over $90 billion of Project Commitments were announced. Our Pennsylvania subsidiary, PPL Electric Utilities, is particularly well suited to meet this demand. We've already invested $13 billion in our Pennsylvania grid since 2013, and our current Capital Plan includes another $7 billion through 2028. That means we can connect data centers as quickly as developers can build them.

It also means that we are not holding up Data Center Development in Pennsylvania, which is a clear strategic advantage. We now have about 14.5 GW of data center projects in the advanced stages of development, with nearly 5 GW being publicly announced. This includes Amazon's planned data center expansion in Pennsylvania, a data center project announced in the Carlisle area by PA Data Center Partners and Powerhouse Data Centers, and a data center announced by CoreWeave. With these advancements, we've increased the projected Transmission Capital Investment needed to meet these demands to a range of $750 million to $1.25 billion, with only $400 million included in our current $20 billion Capital Plan. Meeting this unprecedented demand growth will require an unprecedented response and will require all market participants to be part of the solution.

Thank you, Vince, and good morning, everyone. Let's turn to slide 12. PPL's second quarter GAAP earnings were $0.25 per share compared to $0.26 per share in Q2 2024. We recorded special items of $0.07 per share during the second quarter of 2025, primarily due to IT transformation costs and certain costs related to the Rhode Island integration.

Adjusting for these special items, second quarter earnings from ongoing operations were $0.32 per share, a $0.06 per share decrease compared to Q2 2024. The decline was primarily due to several anticipated factors, including the timing of certain operating costs and true-ups of about $0.03, as well as favorable weather in Q2 2024 and higher interest expense, which were about $0.01 each. As Vince mentioned in his remarks, our business plan assumes stronger growth in the second half of the year, stemming from higher returns on capital investments via formula rates, Rider mechanisms, and AFUDC, as well as lower O&M. On the O&M front, this is due to the execution of our cost-saving initiatives and the timing of certain expenses like tree trimming costs. You may recall that we invested in additional tree trimming in the fourth quarter last year in preparation for the winter.

We also incurred the bulk of our planned tree trimming budget during the spring of this year to better prepare for the summer thunderstorm season. The timing of our tree trimming costs alone is a notable driver of the timing of our earnings growth for 2025 versus 2024. Accordingly, we remain confident in achieving at least the midpoint of our 2025 earnings forecast of $1.81 per share. Moving to our credit profile, PPL's balance sheet remains among the best in our sector, and we continue to support our credit position since our last update while we fund our substantial growth. Over that period, we issued an additional $180 million of equity through the ATM, bringing the total amount issued this year to about $350 million, which includes forward contract features enabling settlement at the end of the year.

Turning to the ongoing segment drivers for the second quarter on slide 13, our Kentucky segment results were flat compared to the second quarter of 2024. Lower sales volumes, primarily due to favorable weather experienced during the second quarter of last year, were offset by several insignificant factors. Our Pennsylvania regulated segment results decreased by $0.02 per share compared to the same period a year ago. The decrease was primarily driven by higher operating costs and the timing of a transmission revenue true-up, partially offset by returns from ongoing capital investments. Our Rhode Island segment results decreased by $0.03 per share compared to the same period a year ago. Higher distribution revenues from capital investments were more than offset by the timing of certain operating costs and a number of items that were not individually significant.

Finally, results to Corporate and Other decreased by $0.01 per share compared to the prior period, primarily due to higher interest expense. In summary, we're pleased with our progress to date and are well-positioned to deliver on our commitments to shareowners. We're executing a robust business plan that supports our long-term financial targets, a plan that is underpinned by critical investments that deliver real value to our customers. At the same time, we continue to explore additional opportunities like the JV with Blackstone Infrastructure that we believe can support our growth profile over the long-term and create value for share owners. This concludes my prepared remarks. I'll now turn the call back over to Vince.

Thank you, Joe. Over this past quarter, we continued to execute our utility of the future strategy, which I believe is a real differentiator for PPL.

We're making investments to improve the reliability and resiliency of our electric and gas networks and to better protect against severe weather. With our generation investments well underway in Kentucky and the progress on our latest CPCN request, we're advancing a cleaner energy mix without compromising on safety, affordability, and reliability. Importantly, we're leading the way in innovation, incorporating new technologies in all aspects of our business, including AI, to deliver better outcomes for both our customers and shareowners. Finally, we're laser-focused on engaging with key stakeholders to strengthen resource adequacy and power economic development that benefits the regions we serve and enhances America's competitiveness and national security. Bottom line, we continue to make excellent progress on all fronts.

As our recent announcement with Blackstone Infrastructure highlights, we've positioned ourselves as a forward-looking organization committed to solving some of the most pressing challenges in today's energy landscape without losing sight of what's truly important to our customers and our shareowners. I continue to be very excited about the opportunities ahead to showcase PPL's many strengths. With that, operator, let's open it up for questions.

Hey, good morning, Jeremy.

All right, thanks. A lot of exciting stuff in Pennsylvania now, and just wanted to see if you could elaborate a bit more on that $17-$19 billion of CapEx that you outlined there as far as needs. Just wondering how you think about how that could be solved, and I guess how do you think about is there a preference for the JV or regulated generation there or any thoughts on market share in general that PPL could capture?

Yeah, sure, Jeremy. The $17-$19 billion is an estimate of what we're seeing in our service territory alone, which is. If all of our 14.5 GW of data center load in advanced stages of development there comes to fruition, that would take our territory from a net long position in generation to a net short position by that 7.5 GW.

We just used 2,200 to 2,500 as kind of a range for a CCGT and got to that $17 billion-$19 billion. In terms of who will ultimately meet that need, I think clearly the Joint Venture has the opportunity to take a piece of that. I think the existing IPPs could take a piece of that. I think as you referenced in your question, if permitted, I think PPL Electric Utilities would also be able to take that. The issue with PPL Electric Utilities is we'll be limited to our total load that we're supplying. I would suspect that PPL Electric will be solving specific resource allocation needs very specific to our territory, where the JV could look at broader solving data center demand broader across the state.

Again, as I said in my prepared remarks, I think all three market participants will likely take a piece of that. That number is larger if you look at statewide. That 7.5 GW is just our location. It's probably 12 GW or larger if you look across the entire state, although we don't have full visibility into our peers' data center queues, but just looking at what's in the PJM queues, we would estimate it to be about that or more. Ultimately, I would say, though, we're not looking to significantly change the risk profile of the company. We'll keep this activity in its proper, I would say, relative positioning in terms of the business mix.

As I think about the opportunity with the JV and the fact that we are 50/50 with Blackstone, I think we can get a decent amount of new generation built, multiple GW in the JV, and without it being an outsized part of the overall business mix for PPL Corporation.

Got it. That's helpful. Thank you for that. As you talk about not changing the risk structure for PPL, just wondering if you're able to talk about, I guess, how power risk could be, I guess, allocated within what the JV does if PPL wants to keep that type of a similar type of risk profile.

Yeah. One of the reasons why we partnered with Blackstone is they are very supportive of our desire to enter into this venture in a regulated-like manner.

Jeremy, I would just say high level when we say regulated-like, what we mean by that is this would be long-term contracted generation. We're not getting back into the merchant generation business. Contracted generation with creditworthy counterparties. We're looking at trillion-dollar market cap hyperscalers, potentially utilities in the state if they run an RFP for long-term contracts. Utilities are very creditworthy counterparties. The ESA terms would provide a regulated-like risk profile that would really enable us at PPL to achieve our credit metrics to maintain our credit ratings. The way we see this progressing is once we negotiate contracts with the hyperscalers, we would then review those with the credit rating agencies.

That will also feed into how large we would make this as part of the business, wanting to make sure that we're not significantly changing the risk profile of the company, which will obviously depend on our discussions with the rating agencies. They can't really opine until we have actual agreements for them to review, as you can appreciate.

Got it. Very helpful. Thank you. A last quick one, if I could, just any thoughts as far as future equity needs and using forwards to de-risk the plan like some of your peers have done?

Sure. Yep. Hey, Jeremy. It's Joe. The ATM program continues to be a cost-effective means for us to issue equity. We've issued, as I said, $350 million in the first half of the year. We did that in about three or four months given when we started and the blackout periods.

We've indicated $400 to $500 million for this year, so we're approaching our full need for the year. As always, we'll evaluate our options and look to achieve the most efficient cost of capital.

Got it. Thank you. I'll leave it there.

Okay. Thanks. Thanks, Jeremy.

Hey, good morning.

Good morning. Good morning, Vince. Good morning. Just a question around the bigger picture on the PJM capacity auction. You and other stakeholders have voiced concern around the inability to procure additional generation while still absorbing materially higher costs. What is your preferred solution here? On one hand, we've got some of the bills pending in Pennsylvania. You've got the JV that you're now pursuing as well. As you look across the sort of landscape, how do you see this playing out?

Are we going to have a series of additional auctions, or does it need to take another pause and reassess for longer duration, or what other solutions could be?

I can't predict what PJM is going to ultimately do in terms of future auctions. I would think they would try to get back on to their normal schedule of three years look ahead with the one-year auction. I would say, Bill, a lot went into our decision to create this Joint Venture as a vehicle to try to solve this lack of generation being built. To your point, the auctions are clearing at levels that, once these last two capacity auctions are reflected in our customers' bills, it's going to increase them by about $20 a month with no new generation to show for it, right?

That was simply a transfer of wealth from utility customers to IPPs and to their shareholders. I think as we think about the IPPs and their willingness or reluctance to build new generation, obviously, what we're seeing in the market today is contracting long-term deals with hyperscalers for nuclear capacity. I would expect that to continue. I think the IPPs building new generation is tough as that cannibalizes the value of their existing fleets because we know building new generation will lower capacity prices. It's not a surprise to us that the competitive markets are not delivering on this much-needed generation. It's just not consistent with their business model. At the same time, we're signing up new data center load almost weekly, right? We're now up to 14.5 GW in advanced stages. That was 11 on our last call, and that's just our service territory again.

Going from a long position in generation in our territory to a short position. We all know how long it takes to build a combined cycle plant. It's about five years now. We're really a couple of years late in getting this generation started. To your point, when you look at what's in the queue, the PJM queue, which goes beyond just the capacity auction, there's only about 10 GW of new generation in Pennsylvania in that queue. Of that, there's only 1,200 MW of dispatchable generation with gas and nuclear, and the nuclear is the PMI restart. The rest of what's in that queue is solar and batteries. We've seen real issues with the solar developers being able to get their projects completed. We're clearly staring at a near-term supply and demand issue that we believe needs to be addressed ASAP.

That's really one of the major impetuses for us to engage in this Joint Venture. I could sit here and complain about it each earnings call, or we could try and do something about it. The two approaches we're taking to try to do something about it and be part of the solution is obviously supporting the legislation in Pennsylvania to enable the PA utilities to build generation to meet a resource adequacy shortfall, and then obviously the Joint Venture with Blackstone. Sorry for the long-winded response, but a lot went into our analysis and decision-making on the need for us to create the Joint Venture. I think it hits on a little bit the question that you were asking broadly.

Yeah. No, no. That's very helpful. Thank you. I appreciate you'll provide more details as ESAs are announced.

High level around the structure, should we think about this as utilizing incremental leverage and seeking returns in excess of regulated rate of returns on these projects within the JV?

Yeah. Not necessarily. I would say the cap structure will really depend on the ESAs we ultimately negotiate with hyperscalers, right? Obviously, that could impact the capitalization structure. Overall, we'll be looking to maintain our overall cap structure and credit metrics at core. I would venture to think that the JV would likely be financed more in line with the utility cap structure, and then back leverage above that should Blackstone or, probably not so much us, but if Blackstone wanted to lever up, they could do that above the JV. That's kind of initial thinking, though, Bill. It doesn't necessarily have to be that way, but we will focus on our overall corporate credit metrics.

On the returns, again, we're looking for this to be as regulated-like as we can make it. Probably returns a little bit higher than our regulated returns, but generally pretty close, but probably a little bit higher due to the slightly higher risk.

Okay. Great. Thank you so much.

Sure.

Hi, though. Thank you, team.

Hey, Paul.

I just had—I have to ask on the partnership. I know most of this is asked, but just in terms of timing, do you expect to have progress in 2025 to report back, whether it's ESAs or turbine orders, slot reservations? Just trying to gauge, is this a 2025 progress or more 2026 process?

Good question, Paul. Maybe I'll just talk about the turbines first, right? Reservation agreements with the turbine manufacturers generally require some significant deposits.

We are taking a very disciplined approach to putting capital at risk here. We would want to be a bit further along on the ESAs before we would make those types of financial commitments. I'll say we've made no material financial commitments to date. As it relates to the Joint Venture, on timing, I would just say we are in active discussions with hyperscalers and other parties. Not really going to get into details, obviously, of those discussions at this time, but I can assure you that we and Blackstone are very focused on this venture. As soon as we have more information to share, we'll absolutely do that. I'm not really putting an artificial timeline on this. We don't solely control the timing, right? That's also the hyperscalers. They have other alternatives that they are also looking at as well. Could be 2025, could be next year.

Wouldn't concern me either way. We'll continue to work it.

Okay. I understand that. Shifting gears, you guys and girls were busy this quarter, to Kentucky. If you could refresh pro forma for the stipulation agreement on the generation, but also the higher load, just how much incremental generation capacity do you have? Referencing the 700-ish MW above what you embedded in the CPCN proceeding. Just how much length do you have? How much more generation could you need in, say, the next five-year roll forward? Thank you.

Yeah. With putting Mill Creek Two back in, right, that's a 300-megawatt plant. It's very similar to, I would say, a capacity-adjusted battery of 400 MW. That's kind of a wash there in terms of supplying what we think was in the CPCN. We had about 1.8 GW in there.

We thought with what we had in the CPCN that we could meet that with a little bit extra. Again, at that 700 MW, if that were to come to fruition, and again, those are just updated estimates, but if that happens, we would likely need to go back in and refile that CPCN to get at least that 400-megawatt battery, maybe even more. The reality is that's probably the quickest source of generation that's dispatchable-like. Obviously, the battery is somewhat dispatchable. That would be able to meet the need if that load continues to come, like I said, come to fruition. That's just the 700 MW, right? If that continues to, we're looking at 8.5 GW of demand coming from hyperscalers and non-hyperscalers, sorry, data centers and non-data centers. We could easily be back in looking for more generation in the not-too-distant future.

Again, we have to see how that plays out.

Thank you very much for that answer. Sure.

Hi, Angie. Good morning.

Thank you. Hi. I'm not going to ask about the Blackstone JV for once. I feel like there's been enough questions. Even though I would really want to know how you would plan to hedge gas exposure, but maybe next time. I have a bigger question because there are a number of companies from the Midwest and Mid-Atlantic that have reported and all have shown actually weak industrial sales, actually residential sales as well. Again, it's somewhat puzzling given all of the low-growth discussion that we're having. What do you think this is? I mean, you're showing contraction in industrial loads for both Pennsylvania and Kentucky. Do you think it's tariff-related?

Do you think there's basically some sort of a lag effect when the load is going to show up?

I'll let Joe talk to it. It's really some one-off situations in the territories, but go ahead, Joe.

Yeah. Sure. In Pennsylvania, really what's driving that industrial load was the impact of lower sales from the steel industry from one customer that we have there and not something that we're seeing across our industrial load in Pennsylvania. It's really just related to one individual customer. Turning to Kentucky, again, in a similar fashion, certainly sales that we're seeing from our largest industrial customers were flat to the prior year. We've seen a slight decline in industrial sales driven by our smaller industrial customers.

Maybe one thing I would just note for Kentucky, and while we don't weather normalize industrial sales, which I think is normal practice, most of the differential in our industrial sales occurred in the month of May, which was significantly cooler in 2025 than 2024. That likely could have resulted in some less cooling load for those customers. Again, we don't weather normalize that. Given what we're seeing in both jurisdictions, it's nothing that we're concerned about, and it seems to be isolated just to a couple of customers.

Okay. And then on the Kentucky CPCN settlement, I have basically about $500 million of CapEx that I need to replenish in order to keep the current CapEx plan unchanged for the consolidated PPL.

I'm assuming that is coming from that $750 million to $1.2 billion in the CapEx that you're quantifying to Pennsylvania, off of which only $400 million is embedded in the plan. Is that correct?

Yeah. I would say you're thinking about it properly. Angie, I would say we see additional opportunities in T&D across both Pennsylvania and Kentucky, but just that data center, the midpoint of that data center range covers that $500 million that you referenced alone. We see opportunities beyond just that.

Going back again to the near-term sales volumes and your results, I obviously appreciate the year-over-year weather impact on the earnings, but you are filing rate cases a little bit sooner than I would have expected. Is it just because you're facing cost inflation? Is it because the sales volumes are slightly weaker than you had expected?

It just feels to me there is more of a regulatory activity than I would have expected, and the earnings are maybe just a touch lower than I would have hoped at this stage.

Yeah. I think, Angie, it's been a number of years since we've been out of rate cases in all of the jurisdictions, right? The last rate increase in Pennsylvania was in 2016. We had a four-year stay-out. In Kentucky, we're beyond that stay-out period. In Rhode Island, the last rate case there was not even under our ownership. It was in 2018 under National Grid's ownership.

Given the duration of time that we've been able to stay out, which really is a testament to the strategy that we've employed on driving efficiency across the platform and really trying to impact affordability and helping out customers, given the duration in each of those jurisdictions, we need to go back in.

Angie, I would just add to that we would expect to be back into a more normal cadence of rate cases going forward. As we implement our AI strategy, our Utility of the Future strategy, any incremental O&M efficiencies that we're able to achieve there, those will go back to our customers. In more real time.

That'll help fund the incremental capital that we're spending to really strengthen the grid against what we're seeing with these more frequent and more severe storms, as well as getting some of these technology improvements in that will drive longer-term cost-efficiency savings and better outcomes for our customers. There's a pretty big uptick in CapEx that you've seen in our capital plan. All of those things will help continue to make these rate increases affordable for our customers as we think about the next, say, five or six years.

Okay. Just one question. It's not directly related to the JV, but I'm just wondering, obviously, depending on what happens with the Pennsylvania legislature, is it possible that you could develop contract-based generation assets and that the off-taker of those contracts would be your Pennsylvania utility?

Is it possible? Yes.

Obviously, we would have affiliate rules that we would have to tend to. Any agreement or any process there would have to be an open RFP process, obviously, because we're an affiliate of the utility. Yes, to answer your question, that is certainly a possible outcome.

Great. Thank you.

Sure.

Morning, David. Hey. Good morning.

Good morning. On the new build cost range you gave, I may have missed the exact range. Can you remind me what that is? More importantly, can you tell me what you're seeing now in the market? Is it on the high end of that range?

Yeah. Sure. We just use $2,200 to $2,500 for the range. $2,200 is what we're currently building them for. These are the new ones that we're seeing in the Brown 12 and Mill Creek 6.

It's less than that for the Mill Creek 5 unit that's currently in construction. The current cost estimates that we are actually building in Kentucky are around that $2,200. We have seen others quote $2,500 or even higher. We did include that as well.

I see. That's just broadly across the country or specifically PJM, that $2,500 number?

Yeah. No, that's more broad. It also depends on do you have land, do you have current infrastructure. Obviously, when we're building in Kentucky, we're building on existing sites. There's certainly efficiencies and economies of scale that we're able to take advantage of there versus a pure greenfield, which likely would be a bit more expensive for obvious reasons.

Okay. On the switching gears on the 2025 guide, can you explain—it might be a little nuanced—but what you're saying now emphasizing at least midpoint versus, I think, before you had upper half.

In terms of what you're targeting this year. Is there any difference there?

Yeah. No, we've always said for this year, we'd be at least the midpoint. The upper part of the range was on the long-term guidance in the 6% to 8% through 2028. Through 2028.

I see. Okay. Thank you for that. If I could sneak one last one on storage, what was the reason that didn't make the cut here on the deal? I'm given the tax credits and O&M. It seems—was it cost-related?

Yeah. Obviously, when we're looking at an overall settlement, the real reason why we were able to defer the battery storage project was because we agreed to seek approval to keep Mill Creek 2 open longer. David, that was just through the negotiation process on getting everybody to agree with a set of new generation builds.

We agreed to keep Mill Creek 2 open in lieu of building that new battery storage. As I said before, it was critically important in that settlement to make sure we still had the ability to refile for that battery if needed to meet load growth. We likely see this as more of a deferral than a cancellation of that project. Again, should load materialize as we're seeing and expect.

Got it. Thank you. Sure.

Great. Thanks, everybody, for joining us today. We look forward to seeing you all when we're out and about on the circuit. Thanks.