PPL Corporation (NYSE:PPL) Q2 2025 Earnings Call Transcript

PPL Corporation (NYSE:PPL) Q2 2025 Earnings Call Transcript July 31, 2025

PPL Corporation misses on earnings expectations. Reported EPS is $0.32 EPS, expectations were $0.37.

Operator: Good day, and welcome to the PPL Corporation Second Quarter 2025 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Andy Ludwig, Vice President, Investor Relations. Please go ahead.

Andrew Ludwig: 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 Investors section of our website. To 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. For reconciliations to the comparable GAAP measures, please refer to the appendix. I’ll now turn the call over to Vince.

Vincent Sorgi: 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 4. 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 in 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 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. And 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 5. 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 SCR for our Gen unit to 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 Gen 2 SCR 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 to 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 6 and a few additional regulatory updates. On May 30, LG&E and KU filed a request with the 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 5 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. And 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 Utilities 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 7 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 2 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. And second, we are supporting several initiatives to develop new generation to serve this massive new load coming on to the grid. This includes our new joint venture with Blackstone Infrastructure that was announced at the inaugural Pennsylvania Energy & 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. And 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 gigawatts of data center projects in the advanced stages of development with nearly 5 gigawatts 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. And that brings me to our next slide and the generation part of our data center strategy. Moving to Slide 8 and a discussion of the joint venture with Blackstone Infrastructure.

As a company, we’ve been very vocal about the need for new generation to supply data centers, and we’re committed to help meet that challenge. This new joint venture plans to enter into long-term energy services agreements or ESAs with hyperscalers. Those ESAs will have regulated-like risk profiles that do not expose the company’s to merchant energy and capacity price volatility as PPL is not getting back into the merchant generation business. Therefore, construction of any new generation will require the successful execution of ESAs with hyperscalers. The joint venture is actively engaged with hyperscalers, landowners, natural gas pipeline companies and turbine manufacturers and has secured multiple land parcels to enable this new generation buildout.

PPL owns 51% of the joint venture interest with Blackstone Infrastructure owning 49%. The joint venture does not include PPL Electric Utilities or any of PPL’s regulated subsidiaries. I can say with confidence, there’s a lot of activity and excitement in Pennsylvania in bringing new generation online in support of data centers. And importantly, this is about building new generation resources, not just diverting existing resources to data centers like we are currently seeing in the market. This is also why we continue to support legislative solutions in the state to enable more generation to be built by anyone who can do it. There are 2 pieces of critical legislation, House Bill 1272 and Senate Bill 897 that have been introduced in Pennsylvania to facilitate this much needed investment in new dispatchable generation.

Both the House and Senate bills would allow regulated utilities like PPL Electric Utilities to build an own generation again to solve a resource adequacy need. And both pieces of legislation would also encourage utilities to enter into agreements with IPPs to help derisk their new generation investments. As a company, we are primed to act quickly once this proposed legislation becomes law. In PPL Electric Utilities service territory alone, we now estimate the new generation need to be about 7.5 gigawatts over the next 5 to 7 years, assuming all the projects in advanced stages are developed. That represents a total investment need of between $17 billion and $19 billion, assuming combined cycle natural gas plants are used to meet that need. And again, that is just in our service territory.

This new generation could be built by a combination of existing IPPs, our newly formed joint venture with Blackstone Infrastructure and if allowed, PPL Electric Utilities. Given both federal and state support for new natural gas plants, natural gas pipeline expansion and streamlined siting and permitting, we are optimistic this generation can get built. But in large part, this will depend on the hyperscalers being willing to sign long-term ESAs to support new generation build. I think that is true regardless of whether we’re talking about the IPPs building this generation or our newly formed joint venture, especially given the limitations of PJM’s capacity in energy markets to incentivize the construction of new dispatchable generation. And this generation strategy will actually lower customer utility bills, which is critically important to us and obviously to our customers.

While we do not have any signed ESAs with hyperscalers to date under the JV we will provide additional details once we have those ESA side. I’ll also reiterate that we are actively negotiating with multiple parties and therefore, we will not get into further details on our strategy or our proposed ESA structure. Moving to Slide 9 and taking a step back from the structure of the JV. I wanted to provide some color as to why this strategic partnership is so exciting. First, in terms of Blackstone, I can’t think of a better partner for this type of joint venture. The specific team that we are partnered with is Blackstone infrastructure. Blackstone Infrastructure has an open-ended investment horizon and can be a partner to us for the life of the assets.

And they are very supportive of the regulated-like risk profile that we want to take with this JV. Blackstone also has an excellent track record of success and has tremendous data center experience with their QTS investment and developing and owning generation assets. So for us, Blackstone is more than just a financial partner in this venture. They bring real expertise alongside our own expertise in power generation. As for PPL, we bring a lot to the table that complements the strengths of Blackstone. We’re uniquely positioned as the largest electric and gas utility holding company headquartered in Pennsylvania. We have excellent relationships in the state and have the support of the governor and other state officials in this new venture. While we do not participate in the merchant power markets, our prior experience there provides key insights into the PJM market.

We’ve also been a leader in the state as it relates to supporting data center development with over 60 gigawatts of data center projects in our Pennsylvania queue. We also run one of the best generation fleets in the U.S. in Kentucky. And our team has experience developing and operating generation assets. Our engineering and construction team is currently managing over $3.5 billion of construction projects on time and on budget. And if the CPCN stipulation is approved by the KPSC, that will add another $3 billion worth of projects. Our team is very skilled at delivering large projects and I have complete confidence that we can execute the JV strategy to build and operate this generation as well. The last piece that differentiates this JV from many other market participants is that we are willing to build generation now.

We won’t cannibalize the value of other assets we own in PJM like some of the other merchant power companies. So we’re in a fantastic spot and believe that this JV can create significant value for share owners, while also protecting our Pennsylvania customers for higher prices with no added benefit. Now moving to Slide 10 for a discussion of the economic development opportunities in Kentucky, which expand well beyond just data centers. We continue to engage with a wide variety of customers in Kentucky, which has powered record-breaking economic growth in the common wealth. From 2020 to 2024, roughly $36 billion in new investments have been announced in the state, nearly half of which are in LG&E and KU service territories. And the economic development pipeline remains robust, fueled in large part by access to the reliable, affordable electricity that LG&E and KU provide.

A recent example includes GE Appliances announced $490 million planned investment in LG&E service territory. According to the announcement, the new product lines are scheduled to be in production by 2027. Our latest forecast in Kentucky estimate 8.5 gigawatts of economic development load potential in our service territories. This includes 5.7 gigawatts of potential data center load. So we continue to field new inquiries from hyperscalers and data center developers. On a positive note, the 400-megawatt PowerHouse Data Center that we previously announced has recently been upsized to 525 megawatts. The forecast also includes 2.8 gigawatts of manufacturing and other potential nondata center load as we continue to see new and expanded manufacturing in our service territories.

The CPCN included roughly 1.8 gigawatts of demand growth through 2032. We recently refreshed these projections and now assume about 2.5 gigawatts of demand growth, clearly 700 megawatts of additional load than estimated in our original forecast just 6 months ago. If this potential growth continues to materialize, additional generation resources from what is included in the CPCN stipulation will likely be required. So again, just tremendous growth potential in our Kentucky service territories that can further bolster the local economies with well-paying jobs and local tax revenue. That concludes my business update. I’ll now turn the call over to Joe for the financial update.

Joseph P. Bergstein: 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 return 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. So the timing of our tree trimming costs alone are 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 shareowners. This concludes my prepared remarks. I’ll now turn the call back over to Vince.

Vincent Sorgi: 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 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. And 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 in 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.

Q&A Session

Operator: [Operator Instructions] The first question comes from Jeremy Tonet with JPMorgan.

Jeremy Bryan Tonet: A lot of exciting stuff in Pennsylvania now. And I just wanted to see if you could elaborate a bit more on that $17 billion to $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?

Vincent Sorgi: Yes. Sure, Jeremy. So the — right, the $17 billion to $19 billion is an estimate of what we’re seeing in our service territory alone, which is if all of our 14.5 gigawatts 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 gigawatts. And so we just use 2,200 to 2,500 as a kind of a range for CCGT and got to that $17 billion to $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 DPL Electric Utilities is will be limited to our total load that we’re supplying. So 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. So again, as I said in my prepared remarks, I think all 3 market participants will likely take a piece of that. that number is larger. If you look at statewide, again, that 7.5 gigawatts is just our location. It’s probably 12 gigawatts 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 PJMs, 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.

So we’ll keep this activity in its proper, I would say, relative positioning in terms of the business mix, but 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 build multiple gigawatts in the JV and without it being an outsized part of the overall business mix for PPL Corp.

Jeremy Bryan Tonet: Got it. That’s helpful. And then 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 PPO wants to keep that type of a similar type of risk profile?

Vincent Sorgi: Yes. So 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. And 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. So we’re not getting back into the merchant generation business. So contracted generation with creditworthy counterparties. So we’re looking at trillion market cap hyperscalers potentially utilities in the state if they run an RFP for long-term contracts. Again, utilities very creditworthy counterparties, but then 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.

So the way this kind of progressing is once we negotiate contracts with the hyperscalers, we would then review those with the credit rating agencies that will also feed into kind of how large we would make this as part of the business, again, 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, and they can’t really apply until we have actual agreements for them to review, as you can appreciate.

Jeremy Bryan Tonet: Got it. Very helpful. And the last quick one, if I could. Just any thoughts as far as future equity needs in using forwards to derisk the plan like some of the peers — some of your peers have done?

Joseph P. Bergstein: Jeremy, it’s Joe. So I mean, look, 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. Really, we did that in about 3 or 4 months, given that when we started and the blackout periods. We’ve indicated a $400 million to $500 million for this year. So we’re approaching our full need for the year. But as always, we’ll evaluate our options and look to achieve the most efficient cost of capital.

Operator: The next question comes from Bill Appicelli from UBS.

William Appicelli: Just a question around the bigger picture on the PJM capacity auction. I mean you and other stakeholders have voiced concern around the inability to procure additional generation while still absorbing materially higher costs. So I guess what is your preferred solution here? Because on 1 hand, we’ve got some of the bills pending in Pennsylvania. You’ve got the JV that you’re now pursuing as well. I mean, as you look across the sort of landscape, how do you see this playing out? And are we going to have a series of additional auctions? Or is it easy to take another pause and reassess for longer duration or what other solutions could be?

Vincent Sorgi: Yes, 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 3 years look ahead with the 1-year auction. But yes, look, 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 are — once these last 2 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? And that was simply a transfer of wealth from utility customers to IPPs and to their shareholders. So 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 IPP is building new generation is tough as that cannibalizes the value of their existing fleets. So — because we know building new generation will lower capacity prices. So 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. But at the same time, we’re signing up new data center load almost weekly, right? We’re now up to 14.5 gigawatts in advanced stages, that was 11 gigawatts on our last call. So — and that’s just our service territory again. So again, going from a long position in generation in our territory to a short position.

And then we all know how long it takes to build a combined cycle plant. It’s about 5 years now. So we’re really a couple of years late in getting this generation started. And then 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 gigawatts of new generation in Pennsylvania in that queue. And of that, there’s only 1,200 megawatts of dispatchable gen with gas and nuclear and the nuclear is the PMI restart. So the rest of what’s in that queue is solar and batteries, and we see real issues with the solar developers being able to get their projects completed. So we’re clearly staring at a near-term supply and demand issue that we believe needs to be addressed ASAP.

And that’s really one of the major impetus is 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. And the 2 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. So — 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. But I think it hits on a little bit the question that you were asking broadly.

William Appicelli: Yes. No, that’s very helpful. And then I guess, I appreciate you’ll provide more details as ESAs are announced. But I mean, at the 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?

Vincent Sorgi: Yes. 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 court. So 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. And then on the returns, again, this — we’re looking for this to be as regulated like as we can make it. So probably returns are a little bit higher than our regulated returns, but generally pretty close, but probably a little bit higher due to slightly higher risk.

Operator: The next question comes from Paul Zimbardo from Jefferies.

Paul Andrew Zimbardo: I just — I have to ask on the partnership. I know most 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 order slot reservation. Just trying to gauge, is this a 2025 progress or more 2026 product?

Vincent Sorgi: Yes. Good question, Paul. Maybe I’ll just talk about the turbines first, right? So reservation agreements with the turbine manufacturers generally it requires some significant deposits. And we are taking a very disciplined approach to putting capital at risk here. So we would want to be a bit further along on the ESAs before we would make those types of financial commitments. I will say we’ve made no material financial commitments to date as it relates to the joint venture. On timing, again, I would just say we are in active discussions with hyperscalers and other parties, not really going to get into details. Obviously, if those discussions at this time, but I can assure you that we and Blackstone are very focused on this venture.

And then as soon as we have more information to share, we’ll absolutely do that. I’m not really putting in an artificial time line 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. So could be ’25, could be next year, wouldn’t concern me either way. We’re just — we’ll continue to work it.

Paul Andrew Zimbardo: Okay. I understand that. And then shifting gears, I mean, you guys and girls were busy this quarter to Kentucky. Just 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 like the referencing the 700-ish megawatts 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 5-year roll forward?

Vincent Sorgi: Yes. So with putting Mill Creek 2 back in, right, that’s a 300-megawatt plant. It’s very similar to, I would say, a capacity adjusted battery of 400 megawatts. So that’s kind of a wash there in terms of supplying what we think what’s in the CPCN. We had about 1.8 gigawatts 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 megawatts, 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.

And that’s just the 700 megawatts, right? So if that continues to — we’re looking at 8.5 gigawatts of demand coming from hyperscalers and nonhyperscalers — sorry, data centers and non-data centers. we could easily be back in looking for more generation in the not-too-distant future. But again, we have to see how that plays out.

Operator: The next question is from the line of Angie Storozynski from Seaport.

Agnieszka Anna Storozynski: I’m not going to ask about the Blackstone JV. 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. So I actually 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. And I’m just — and again, it’s somewhat puzzling, given all of the low growth discussion that we’re having. What do you think is? I mean you’re showing contraction in industrial loads 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?

Vincent Sorgi: Yes. I’ll let Joe talk to it. It’s really some one-off situations in the territories. But go ahead, Joe.

Joseph P. Bergstein: Yes, sure. So in Pennsylvania, really what’s driving that industrial load is — was the impact of lower sales from the steel industry from 1 customer that we have there and not something that we’re seeing across our industrial load in Pennsylvania. It’s really just related to 1 individual customer. And then 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, and we’ve seen a slight decline in industrial sales driven by our smaller industrial customers. And then maybe 1 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.

So that likely could have resulted in some less cooling load for those customers. But again, we don’t weather normalize that. But 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.

Agnieszka Anna Storozynski: Okay. Okay. And then on the Kentucky CPCN settlement, so I have basically like about $500 million of CapEx, right, that I need to replenish in order to beat the current CapEx plan unchanged, both for the consolidated PPL. And so I’m assuming that, that is coming from the $750 billion 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?

Vincent Sorgi: Yes. Yes. 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. So — but no, we see opportunities beyond just that.

Agnieszka Anna Storozynski: Then just going back again to the near-term sales volumes and your results, and I obviously appreciate the via the year-over-year weather impact on the earnings. But you were filing rate cases a little bit sooner than I would have expected. Is it just because you are 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 then the earnings are maybe just a touch lower than I would have hoped at this stage.

Joseph P. Bergstein: Yes. I think, Angie, I mean 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 4-year stay-out in Kentucky that we’re beyond that stay-out period. And then in Rhode Island, the last rate case there was not even under our ownership. It was in 2018 under National Grid’s ownership. So it’s just 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 being — driving efficiency across the platform and really trying to impact the affordability and helping our customers. But again, given the duration in each of those jurisdictions, it’s — we need to go back in.

Vincent Sorgi: Yes. And Angie, I would just add to that. I would just add to that we would expect to kind of be back into a more normal cadence of rate cases going forward. So again, 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, and that will help fund the incremental capital that we’re spending to really strengthen the grid against what we’re seeing with these more frequent and severe storms as well as getting some of these technology improvements and 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. So all of those things will help continue to make these rate increases affordable for our customers as we think about the next say, 5 or 6 years.

Agnieszka Anna Storozynski: Okay. And just 1 question. It’s not directly related to the other JV. But I’m just wondering, I mean, obviously, depending what happens with the Pennsylvania legislature. Is it possible that you could develop contract-based generation assets and that the offtaker of those contracts would be your Pennsylvania utility? Is it possible?

Vincent Sorgi: 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. But yes, to answer your question, that is certainly possible, a possible outcome.

Operator: Sure. Next question comes from David Paz from Wolfe Research.

David Alexander Paz: On the newbuild cost range you gave, I may have missed the exact range. Can you remind me what that is? And then more importantly, can you tell me what you’re seeing now in the market? Is it on the high end of that range?

Vincent Sorgi: Sure. Yes. So we just use [ 2200 to 2500 ] for the range, [ 22 ] 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. But current cost estimates that we are actually building in Kentucky are around that [ 2200 ]. We have seen others [ 2500 ] or even higher. So we did include that as well.

David Alexander Paz: I see. And that’s just broadly across the country or specifically PJM, that [ 2500 ] number.

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

David Alexander Paz: Okay. And on the — switching gears on the ’25 guide, can you explain it might be a little nuance. But what you’re saying now sizing at least at least midpoint versus, I think, before, you had upper half in terms of what you’re targeting difference there?

Joseph P. Bergstein: Yes. No. We’ve always said for this year, we’ll be at least the midpoint. The upper part of the range was on the long term guidance in the 6 to 8 to ’28.

David Alexander Paz: I see. Okay. If I could sneak one, last one on storage. What was the reason that didn’t make the cut here on the deal given the tax credits and OBB, it seems — was it cost related?

Vincent Sorgi: Yes. So obviously, when you’re — 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 to open longer. So 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. But as I said before, it was critically important in that settlement to make sure we still have the ability to refile for that battery, if needed, to meet load growth. So 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.

Operator: This concludes our question-and-answer session. I would like to turn back the conference over to Vince Sorgi for closing comments.

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

Operator: Thank you. The conference now has concluded. Thank you for attending today’s presentation. You may now disconnect.