PPL Stock

Good day, and welcome to the PPL Corporation's Conference Call on Second Quarter 2026 Financial Results. [Operator Instructions] Please note that this event is being recorded. I would now like to turn the conference over to Andy Ludwig, Vice President of Investor Relations. Please go ahead.

Good morning, and thank you for joining PPL Corporation's Conference Call on Second Quarter 2026 Financial Results. We provided presentation materials on the Investors section of our website. This morning, you will hear 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, please turn to Slide 2 for our cautionary statement.

Today's presentation contains forward-looking statements subject to risks and uncertainties. Actual results may differ materially. Please refer to our SEC filings and the appendix for additional information. We will also refer to non-GAAP measures, including earnings from ongoing operations. Reconciliations to the corresponding GAAP measures are provided in the appendix. I'll now turn the call over to Vince.

Thank you, Andy, and good morning, everyone. Let's begin on Slide 4 with an overview of our second quarter performance. Q2 was another quarter of disciplined execution, supporting our 2026 commitments while strengthening confidence in our long-term outlook. Today, we reported ongoing earnings of $0.33 per share. Based on our results through the first half of the year and our expectations for the remainder of 2026, we are reaffirming our ongoing earnings forecast range of $1.90 to $1.98 per share, with a midpoint of $1.94 per share. We expect stronger earnings growth in the second half of the year, supported by rate case outcomes in both Pennsylvania and Rhode Island, with Pennsylvania rates effective July 1, and Rhode Island rates expected to be effective September 1.

We are on pace to deploy approximately $5 billion of capital investments in 2026 to support the delivery of safe, reliable, and affordable energy service. As our investment plan has expanded, our teams have continued to demonstrate the ability to execute these programs safely, efficiently, and on schedule. Longer term, we continue to project $23 billion of capital investment needs through 2029, supporting average annual rate base growth of over 10%. We also reaffirmed our long-term financial targets, including 6% to 8% annual EPS growth through at least 2029, with compound annual growth expected to be near the top end of that range, 4% to 6% annual dividend growth, and FFO to debt of 16% to 18%.

Importantly, these targets exclude any contribution from Invitium Energy, our joint venture with Blackstone, which represents meaningful long-term earnings and cash flow upside beyond the current plan. Turning to Slide 5 for a more comprehensive regulatory update. Coming into 2026, we had base rate case proceedings underway in all 3 of our primary jurisdictions. These rate case filings were after significant periods of stay out, ranging from 5 years in Kentucky, 8 years in Rhode Island, and over 10 years in Pennsylvania. We made excellent progress in these proceedings during the second quarter, continuing to achieve constructive outcomes that derisk our plan.

In Pennsylvania, PPL Electric's rate case settlement became effective July 1 with a positive outcome for both customers and shareowners. The approved increase of $275 million supports critical investments we are making while reflecting less than a 4% increase across all of our rate classes. Importantly, even after our recent rate adjustment, PPL Electric's delivery rates remain nearly 20% below the latest published date average. This outcome reflects the benefits of our Utility of the Future strategy, that prioritizes system hardening, disciplined cost management, strategic use of technology, constructive engagement with stakeholders, and a strong focus on affordability.

The settlement also includes a 2-year stay-out provision. Through the continued use of the DISC mechanism and disciplined cost management, we will target remaining out of base rate cases beyond that period. In Kentucky, we're awaiting the commission's decision on our reconsideration request following another thorough and constructive regulatory process. While we believe the original KPSC decision allows us to deliver on our overall plan objectives, we believe there were some flaws in that decision that require reconsideration by the KPSC. We appreciate the commission's thoughtful review of our filing and continue to believe the investments and mechanisms supporting this filing are important to maintaining safe, reliable, and increasingly resilient service to our customers.

We've requested a decision from the KPSC by August 14. Turning to Rhode Island. Our base rate case proceeding remains on track. Hearings were completed in mid-July, briefs have been filed, and public meetings are scheduled for August 12 to the 20th. New rates are expected to become effective September 1. As mentioned earlier, this is the first base rate increase Rhode Island Energy has requested in 8 years, and builds on the significant reliability improvements we've achieved since our acquisition of the utility back in 2022. The filing supports the continued investment needed to strengthen the system and prepare for frequent and severe weather events and continued distributed renewable deployment in the state. We also continue to make progress with our Hold Harmless Bill Credit proposal which is being considered in parallel with the broader rate case proceeding.

As a reminder, we've proposed accelerating customer bill credits associated with the deferred tax hold harmless commitment that we made when we acquired Rhode Island Energy. If approved, the credits would significantly offset the impact of the requested base rate increase for customers. This is another example of our balanced approach to affordability and investment, proposing creative solutions to help moderate customer build impacts while continuing to invest in system reliability and resilience. Overall, these proceedings highlight the effectiveness of our regulatory strategy and provide a stronger foundation for continued investment.

Moving to Slide 6. Against the backdrop of increasing national scrutiny around data center development, our Pennsylvania service territory continues to stand out because of its strong transmission reliability and access, proximity to major demand centers, and disciplined customer protections. Signed data center agreements with PPL Electric Utilities increased for the tenth consecutive quarter to about 32 gigawatts, an increase of 3.5 gigawatts from last quarter with over 1 gigawatt coming from signed electric services agreements or ESAs. We now have more than 11 gigawatts under ESAs which carry meaningful financial commitments from the customer, which I'll cover in more detail in a few slides.

We also continue to see these projects enter the construction phase with more than 6.5 gigawatts now under construction. And during the quarter, 2 of these data centers began taking utility service, which are expected to ramp to about 2 gigawatts of load by 2031. This continued progression from agreement to construction to taking service is improving our line of sight into future infrastructure and generation needs, including from our Invitium Energy joint venture with Blackstone.

Turning to Slide 7. Our Invitium joint venture continues to make progress across a number of critical paths. Great payer Protection pledges and PJM's recent FERC proposal reinforced the need for new generation to serve large load customers. While strong data center activity in PPL Electric utility service territory is expanding the opportunity for long-term energy supply services agreements or ESSA. During the quarter, we continued to move the joint venture from concept to execution. We now have strategic land sites capable of supporting between 8 and 14 gigawatts of new generation depending on the technology selected, and we are continuing to build our inventory of viable sites. We have over 5 gigawatts of new CCGT generation that has been accepted in the PJM interconnection queue.

We also have over 5 gigawatts of reservation agreements for combined cycle gas turbines. Using the market consensus project cost of approximately $2,500 to $3,000 per KW, that 5 gigawatts represents between $12.5 billion and $15 billion of potential future investment through 2032, of which PPL's share would be 51%. Collectively, these milestones give us increasing confidence that Invitium can support contracted growth and create incremental value for shareowners. While we do not expect the earnings contributions from the JV to be material through 2030, batteries or other shorter lead time technologies could begin contributing earnings in 2029 or 2030, which could enhance our projected EPS growth rate above the top end of our 6% to 8% range.

We would expect more meaningful earnings and cash flows when the CCGTs come online, which could be as early as the 2031, 2032 time frame. And as we've said, we will not move forward with construction or make material financial commitments until we have executed ESSAs with appropriate risk profiles in those contracts or have cost reimbursement agreements in place. Based on progress to date, we expect to have 1 or more commercial agreements by year-end.

Turning to Slide 8. Kentucky also continues to see strong economic development activity. The current development pipeline has expanded to 13.7 gigawatts of potential load growth with data center demand representing 11.6 gigawatts and manufacturing and other nondata center projects totaling 2.1 gigawatts. This is an increase of roughly 800 megawatts from last quarter. Of that pipeline, approximately 1.3 gigawatts is now supported by signed reimbursement agreements, up from approximately 900 megawatts in the first quarter. Our updated probability-weighted projections now indicate 3.7 gigawatts of expected new load by 2032, more than double the amount reflected in our 2025 CPCN filing.

That demand is making it even more likely that we will need to file a CPCN for additional generation resources by year-end. Potential resources for the CPCN include the 266-megawatt Lewis Ridge pumped storage project, the 400 megawatts of batteries that were deferred in the 2025 CPCN, and additional natural gas combined cycle generation. While we won't know the exact resource mix until we file the next CPCN, those projects represent an incremental $3.5 billion to $4 billion of potential investment to be incurred between 2027 and 2032. As you can see, Kentucky is emerging as a significant platform for incremental growth, which is why we've been so focused on large-load tariff protections designed to preserve affordability for our existing customers.

Let's turn to Slide 9 for a discussion on how those large-load tariffs are protecting our customers. The tariffs approved in Pennsylvania and Kentucky are grounded in a simple principle. Large-load customers pay their own way with enforceable provisions that protect existing customers from cost shifts. First, these tariffs require long contracts with a minimum term of 10 years in Pennsylvania and 15 years in Kentucky. Kentucky's term is longer because of the fully integrated business model with generation resources as well.

Second, customers commit to guarantee payments of at least 80% of the capacity they reserve, whether they use it or not. Third, we require collateral upfront. And finally, although no projects with signed ESAs have been canceled to date, there are material termination fees in the event the developer walks away, even if they walk away pre-COD. So with all of these elements in mind, our existing customers are protected from bearing costs to projects that do not move forward. These financial commitments materially improved project quality, and increase our confidence that signed ESAs represent serious executable demand. These tariffs also provide tangible customer benefits.

Starting in 2027, Pennsylvania's large-load customer class will contribute $11 million annually to low-income assistance, which was previously funded by our existing customers. Our existing Pennsylvania customers could also see about $25 a month come off the transmission component of their bills over time, if the 31.8 gigawatts in advanced stages is realized. That would help offset the more than $20 per month, our Pennsylvania customers are currently paying as a result of higher PJM capacity prices. Bottom line, these tariffs provide a disciplined framework to capture growth responsibly while ensuring that growth pays for growth. With that, I'll turn the call over to Joe for the financial update.

Thank you, Vince, and good morning, everyone. Let's turn to Slide 11. PPL's second quarter GAAP earnings were $0.30 per share compared to $0.25 per share in Q2 2025. We recorded special items of $0.03 per share during the second quarter primarily due to IT transformation costs and system integration impacts. Adjusting for these special items, second quarter earnings from ongoing operations were $0.33 per share, an improvement of $0.01 per share compared to Q2 2025, which was in line with our expectations. In the first half of 2026 now complete, we remain firmly on track to achieve at least the midpoint of our 2026 ongoing earnings forecast of $1.94 per share. Base rate case outcomes in both Pennsylvania and Rhode Island, support the stronger second half earnings profile embedded in our plan.

We've also made great progress on our CapEx program and have deployed approximately $2.3 billion through the end of the second quarter. This is roughly 30% more than what we deployed last year through the first 6 months as we continue to strengthen the safety and reliability of our networks. This also includes the great progress on our generation projects in Kentucky which continue to be on budget and on schedule. Lastly, we continue to maintain a strong balance sheet supported by an improving credit profile with enhanced cash flows following our base rate cases and the settlement of previously priced equity, improving our credit metrics over time. That financial strength positions us to deliver our existing capital plan while maintaining flexibility as the additional investment opportunities including those that Vince discussed emerge across our service territories.

We completed our financing needs for 2026 earlier in the second quarter with successful debt offerings at PPL Electric and Rhode Island Energy. Both transactions were very well subscribed and secured long-dated capital at attractive terms. Turning to the ongoing segment drivers for the second quarter on Slide 12. Our Kentucky segment results were flat compared to the second quarter of 2025. These results were driven by higher base rate recovery due to higher retail rates that were effective on January 1. This was offset by lower sales volumes due to less favorable weather than experienced in Q2 2025, higher operating costs, higher depreciation expense, and higher interest expense.

Our Pennsylvania Regulated segment results were $0.01 lower compared to the same period a year ago. These results were driven by higher depreciation expense and higher interest expense partially offset by higher transmission revenue from additional capital investments. Our Rhode Island segment results increased by $0.02 compared to Q2 2025, driven by higher rider revenue and lower operating costs partially offset by higher depreciation expense. Lastly, results at Corporate and Other remained flat compared to Q2 of 2025, mainly driven by higher interest expense, offset by other factors that were not individually significant.

Overall, our growth drivers are in motion to deliver on our commitments for the year. Our financing plan continues to advance, and we see ongoing opportunities to build on the plan that we've outlined, for both our customers and shareowners. This concludes my financial update. I'll now turn the call back over to Vince.

Thanks, Joe. Before we open it up for questions, I'll leave you with a few closing thoughts. The headline for this quarter is straightforward. We are executing on our current plan while creating more visible upside beyond it. We delivered solid second quarter results, reaffirmed our 2026 earnings forecast and long-term financial outlook. We've made great progress in achieving constructive outcomes in our base rate cases, supporting timely recovery of critical investments while maintaining customer affordability. At the same time, accelerating customer demand across our Pennsylvania and Kentucky service territories is giving us a clearer line of sight into the infrastructure and generation investments required to support meaningful future growth. .

We've also advanced tariffs that protect our existing customers as that large-load demand becomes more visible. We continue to make considerable progress on the Invitium Energy joint venture with Blackstone and expect one or more commercial agreements to be announced by year-end. And finally, the Kentucky generation and Invitium energy potential upsides could drive between $10 billion and $12 billion of incremental capital investment through 2032, which strengthens our growth outlook beyond the current plan period. With that, operator, let's open it up for questions.

[Operator Instructions] The first question today comes from Michael Lonegan with Barclays.

Just wondering if you could talk about the interaction of the Invitium JV with the bilateral process and RBA procurement. Would you have to wait for procurement to happen? Or could you announce at any time? And if you announce a deal, would it be included in the procurement?

Yes. So we are actively negotiating bilaterally, and we've been doing that way before the PJM RBP process, Michael. So our ability to get to closure on bilateral contracts is irrespective of the PJM process. We did submit proposals into that process just to maximize our customer contacts, but the 2 are not necessarily related given the activity we've been doing before the PJM process.

Great. And then sticking with the JV, you said you could reach one or more agreements by year-end. Anything you could say about the size of the near-term ones in terms of gigawatts and investment opportunity? And could the announcement come when the agreements are reached? Or would that be essentially a Q4 update?

Yes, sure. So not able to give a size at this point, depending on which ones happen first. So we'll defer that until we actually make the announcements, I would say, timing of the announcements. Again, materiality will really dictate that, Michael. So anything material, we would certainly not wait for an earnings call to announce, we would do that, I would say, in concert with signing of those agreements. Maybe just broadly on timing, I'll make a few comments where in terms of announcement timing, I would say the PJM RBP process is likely affecting the timing for some of our counterparties, but our customer engagement, really, I would say, remains very strong, and we're continuing to see a clear path to the bilateral commercial agreements that support all this new generation I would say, even with the PJM proposal and the rules in their FERC filing, right? They are really pushing towards bilateral contracting and we continue to believe that bilateral contracting will likely be the predominant path for getting new generation development in PJM at least. .

Given the progress that we've made to date and what I've said on the call, again, with the discussions we're having with our customers, but all of the other development work around site readiness, the turbine access, the interconnection activity that we've done with PJM and I'd even add fuel supply to that. That's why we're expecting that we would have one or more announcements by year-end. I will say it could happen sooner, but I wouldn't want to speculate on exact timing just because these are complex, they're long-term agreements. And of course, it takes 2 parties to finalize them.

So I think the key for us is we're not waiting for those ESSAs to begin that development work that we've talked about on the call today, we're running those in parallel. And so we're ready to respond very quickly in concert with the customer negotiations.

The next question comes from Jeremy Tonet with JPMorgan.

Just wanted to maybe follow up a little bit on the last point there. Just when do you expect to see the first results from the PJM capacity matching process? And how do you view this process versus bidding into the actual RBP auction?

Yes. So we have not committed yet into bidding into the RVP option. We did provide a proposal for the matchmaking part of the process. right? Ultimately, PJM is looking to come out at the end of September with all of that. We'll ultimately see how that plays out. Just the caps that we're seeing in the PJM auction part of it, those are well below cone on certainly some of the assets that we're talking about, Jeremy. So more to come on how aggressively we're participating in that process. I will say just like last quarter, our focus continues to be on the bilateral contracting process directly with our customer base. .

Got it. That makes sense. Just wondering maybe a little bit on timing, if the assets you bid into the matching process were selected, will we know by the end of September? Or how should we think about next steps?

I'm not exactly sure of the timing on when we would know that, Jeremy. Certainly, something we'll continue to think through as we progress through that process. I'm not exactly sure of the timing of when we'll hear back from them.

Got it. Fair enough. And maybe going over to Kentucky, everything you talked about there, a lot of upsizing opportunities. And just wondering, I guess, is there a milestone for -- that you need to hit before you could do the additional CPCN filing that could be filed by year-end?

Yes, you cut out on us there, but I think you were asking about what are maybe some triggers for the CPCN filing? .

Yes.

Do I have that right? Okay. Yes. So look, I think we are seeing some of those triggers already as we're seeing, right, the continued increase in the pipeline. We are signing various agreements for new load with data center developers and also with nondata center customers. So all of that continues to move in the right direction. And that's really what's driving our new probability weighted load of 3.7 gigawatts. That's twice what we had in the last CPCN. So I would say the one area that we would want to see in addition to the commission is the conversion from the data center developer to an actual hyperscaler contract. And those, I will say, those activities are happening as we speak. And I would say once we have 1 of those, that would be a pretty big trigger to prompt us to make that filing before year-end.

Next question comes from Paul Zimbardo with Jefferies.

I just wanted to dive a little bit more, of course, into the joint venture. So I know you've been consistent that we shouldn't expect to see material earnings before 2030. Just how would you envision articulating what the earnings contribution is? Would you do like a separate joint venture earnings separate from kind of the base business, more long duration CAGR beyond 2030. Just if you could help on kind of what kind of disclosures we should expect? .

Yes, Paul, it's Joe. Yes, we would give something separate from the base utility business. So you could see the earnings and the growth and the trajectory of earnings coming out of the JV. And then obviously, we would provide an update on its impact on the CAGR that we have currently. So yes, I think you're right. You're thinking about it correctly on both of those.

Yes. And Paul, this is equity method for accounting purposes, so right, single line items on the financials. So we'll clearly break all that out in additional disclosure for this part of the business once it starts to materialize. .

Okay. Great. I understand there. And then shifting to Kentucky for a second. I saw the Governor's executive order around data centers and kind of focus on emissions, water and some of those things. Does that shift what you could procure to support the data centers? Like I know you mentioned the pump storage. But just any thoughts on the executive order would be helpful.

Yes. No. It was good to see the order come out. We view it as fully consistent with the rate payer protection principles that we've been championing and even the rate payer protection pledge that we signed recently, where new large load customers should be supporting and paying for the infrastructure and the resources that are needed to serve them. So Importantly, right, the order did not prohibit or put a moratorium on data center development. It simply is reinforcing that we need to have customer protections built into -- so the process, which, of course, we have built into our approach. So I would say that LG&E and KU with our tariff structure that we've gotten approved in the state, we're well positioned within that tariff structure to align very nicely with our Governor's executive order.

So not concerned at all. We don't think it will slow down the development that we're seeing in Kentucky or our ability to serve it.

Next question comes from Shar Pourreza with Wells Fargo.

Actually, it's Andrew Kadavy on for Shar. So with the longer-dated opportunities come on your plate, could we see maybe a longer planning window net some of you guys update guidance? And what are some of the considerations that go into that decision?

Yes. I think that's certainly possible, right, given the timing that we're talking about is to when we see the earnings contributions from these agreements and given the logistics and timing around getting CCGTs into service. So that's certainly a consideration. .

And then just circling back to PJM, can you share how potential Invitium customers are viewing the connect and manage an IRS rulings in PJM and has the clarity around that helped progress some of your commercial decisions?

Well, so right, the IRS framework was not included in, right, what was in the letter at least was not included in the filing last week, we are expecting that imminently, perhaps even today. So I'll reserve judgment on that until I see the actual filing. But I would say coming from the letter that PJM put out with their guiding principles I think what you're starting to see is some clarity on what large-loads will need to procure during the ramp phases, right? So there was a lot of early questions on do you need to just have BYOG online when you hit your max load? Or do you need to follow your ramp? Or can you do it in chunks? Obviously, the load comes on in different megawatt chunks than you're able to bring generation on if you're using certain types of generation.

So I think you'll see, certainly as we think about following ramps so that the hyperscalers are not in that connected managed or interruptible phase. They'll want to try to match that ramp, the best they can. And that, I think, will prompt batteries and other types of smaller generation that can come online quickly and at smaller amounts. And then you're kind of anchored with some of the larger asset types that we're talking about. But all of those are part of our discussions with the hyperscales, all of those types of technologies and following ramp curves.

The next question comes from Steve Fleishman with Wolfe Research.

So the -- a couple of questions on the joint venture. Just going back to the shorter-term potential projects. You mentioned batteries. What other technologies are you likely to be using for shorter term? Is it mainly just like Recepts or arrows or -- anything else?

Yes, I would say those are the main, right? The CTs are still -- I would say the CTs are quicker than the CCGTs, but probably outside of our '29, right, which is our current plan period, Steve. So CTs could be probably in the '30, '31 range, with the CCGTs in the '31, '32 range. And then, yes, you mentioned the types of technologies that could get in more in that '29, '30 time frame. .

Fuel cells?

We are engaged with the fuel cell manufacturers, so it is on the list of technologies ultimately will depend on what the hyperscalers would like us to procure and operate, but we are open to those as well, yes. .

And then just in thinking about the -- how should we think about funding the joint venture and the projects? And just how much is likely to be equity from PPL and -- and are you looking at kind of alternative financing structures and even just the economics, are you just going to do straight 50-50 or sometimes you can when you have a financial partner, you can kind of manage the path of cash flow and earnings. So just any thoughts on all that?

Yes, sure. So first on the financing question. during the construction period, we'll use construction period type financing structures that will keep the balance sheet to limit any near-term dilution -- and then once those projects go COD, we'll put in place a permanent financing structure as far as the cap structure mean we've talked about utility-like risk profile and returns, but we obviously have some flexibility in and around where that cap structure could be, but we'll keep that in mind as we think about longer-term credit implications. And we obviously want to maintain our strong credit position, and so have to take that into consideration with discussions with the rating agencies as they think about it as well. .

The next question comes from Angie Storozynski with Seaport.

I want to talk about Pennsylvania, how you on the regulatory side. So you have concluded your rate case, you are not allowed to have another one until what, middle of 2028, at least yes. And then just wondering, I mean, are you hoping to maybe rely more on the disk mechanism, any ways to maybe reduce costs so that you don't have to file that rate case anywhere near the '28, '29 time frame?

Yes, Angie, you're exactly right on the settlement provisions. There's a 2-year stay out agreement that we will not increase base rates during that period, which extends through July 1, 2028. We always look to maximize the time between rate cases, and we've done that very effectively across all the jurisdictions. And as you know, in Pennsylvania, it was 10 years since our last rate case prior to this one. I don't know that we can go another 10 years, but we'll certainly use that same discipline that we have. We've utilized the disk extremely effectively over that time period. We'll look to continue to do so. We've also managed our costs very, very well, and we continue to focus on that in that area as we've been and we'll continue to be focused on affordability for customers. .

Our current LTIP plan, which is the capital that is eligible for the disc runs through 2027. So we'll be looking to file an updated 5-year LTIP plan next year. again, looking to maximize that and maximizing the use of the disc mechanism. So I think too early to tell as to what our next rate case would be, but we are always looking to, as I said, maximize the time between cases.

Yes. And I would just add to that, Angie, you've heard from our Chair and our commission that they want to take a look at the disc mechanism where maybe have more formula-based ROE setting in the mechanism, maybe provide some performance band around that base ROE. But the goal is really to provide a mechanism for the utilities to be able to stay out of base rate cases longer. And so we will certainly be engaging with our commission, obviously, the other EDCs in the state and other stakeholders as we go through that process with the PUC. But I think that could be encouraging as well. And so depending on how that plays out, we'll have to factor that into our rate case timing.

But I think all of that is boding well for -- are likely being able to stay out beyond just the 2 years that are in the settlement.

Great. And then changing topics to the data centers in the PPL zone. So the projects that you have already supported by ESAs are well above the current excess generation in the PPL zone and I know that we're still waiting for the Connected managed filing. But I'm just wondering if there were to be forced curtailments in the future, supposedly in your zone, that would be pretty much released likely, again, given excess generation capacity. But again, it will be depleted. So how do you see these things that the Connected managed would potentially actually give you a competitive advantage versus other zones in PJM simply because, again, the force curtailment will be probably least likely in your zone?

You cut out on us a little bit there, but I think what you were saying was just with generation length that we currently have and then that being depleted by the ESA, the 11 gigs of ESAs. And of course, that continues to grow. Yes. I mean I think it's one of the reasons why we have so much interest in the sites that we have in our joint venture, and we've been very strategic in accumulating the sites that we have. So in order to qualify for BYONG now with the end, even under the new proposed rules, right, you don't have to be co-located to the load, but the fact that we are very near the load creates a very competitive position for us as you think about PJM planning, interconnection studies, all of that where the generation and the load are very tightly situated.

So that all bodes well, I would say, for our territory and where we're siting or proposing to site all of this new generation. It really helps to strengthen the reliability of the grid overall and then get back to that long position for generation coming from Pennsylvania, which, as you know, us and West Virginia are the 2 power generation sources for PJM. So I think that -- again, you cut out on me, but I think that's what you were asking, and I agree that our position within the state provides that advantage -- competitive advantage.

The next question comes from Nick Amicucci with Evercore.

So it's Amicucci, but well we know how it goes. I wanted to ask quickly just kind of piggybacking on Steve's question before. Just when we think about kind of the shorter lead time technologies as early as 2029 or 2030. Are those going to require a separate ESSA -- or could they -- or are they going to be typically riding on the CCGT contracts?

Yes. No, the ESSA contract is for generation to supply a data center. So it does not need to be limited to the CCGT, it will be whatever suite of assets that we ultimately agree with the hyperscaler for the third-party data center developers, which are also now getting involved in the BYOD and then providing that full rate service to hyperscalers as 1 package. So we're now seeing other entrants into the interest into the product offering. I will say, though, while the batteries are certainly the fastest to market. They're also the easiest for the hyperscalers to embed in their designs and may just make it part of the data center construction projects.

So part of the issue that we have with predicting how much will show up through '29 is I'm convinced there'll be batteries that are coming on system by 2029, but some of that could be owned directly by the hyperscalers as opposed to third-party generators like Invitium, if that makes sense.

Got it. Yes, makes perfect sense. And then just really quickly, too, on the 2 data centers that began taking service within Pennsylvania in 2Q. So has the LTC minimum demand billing started? Or is there kind of like a ramp schedule associated with that, too, as those continue to come online?

Yes. So that 2 gig is not until -- that's the ramp through 2031. So it's the -- yes, the smaller ramp that's kicking in now under the tariff, yes. .

[Operator Instructions] The next question comes from Paul Patterson with Glenrock Associates. .

Just one question left here. With Pennsylvania, I know we're on resets and stuff, but any -- any thoughts or outlook about what we might see legislatively with respect to some of the legislation that's passed or anything perhaps on the -- I mean, all the stuff that was happening this spring, I'm just wondering -- have you heard anything over the summer here about what might happen in the next few months in Harrisburg.

Yes. So there was quite a bit of activity prior to the budget being approved as you're alluding to. Look, I would just say, overall, as you can see from our pipeline alone, right, that there's tremendous data center interest in Pennsylvania and in particular, our zone. And look, for some of our local communities, right, these projects represent very material investments, right, which is good, but it also can overwhelm these local communities. And so I think what we're seeing, Paul, is just at the local level with the support of their elected officials, right, just this move to slow down a little bit so that they can effectively review the projects, update their zoning requirements as needed, but really just take some time to make sure that they're doing this the right way.

And that seems very reasonable to us. And I think that's what you're seeing with some of the proposed legislation coming from some of our elected officials. And while there was some legislation advanced in the house, I would say that the state continues to remain supportive of this type of development in the sector as long as our customers and our communities are protected. And so you're starting to see some of that legislation designed to ensure that those protections happen. I will say, I'm seeing a shift in the developers and how they're engaging with the local communities and putting together differentiated community benefit packages, right, what one community might think is a benefit another may not.

So doing that kind of community by community engaging earlier more transparently. I think all of that, while we wish it had happened from day 1, we're starting to see the shifts in that. And I know the folks are appreciating that level of transparency and really willingness to work and come up with a win-win for both the data center and for the community. And it's the same areas that you're hearing, right? It's the water, it's the land, it's the noise, it's power prices and power reliability, both of which we have well at hand. And we will be, I would say, pushing that even further as we can build new generation under Invitium and just take some pressure off the supply demand curve at the wholesale level. But all of these things, I think, are moving us in a consistent direction with where some of this legislation or at least the ideas behind some of this legislation were coming from.

Again, I don't think it's misplaced. I don't think you're going to see moratoriums or we just can't add data centers in Pennsylvania. We just need to make sure that our customers and our communities are protected as we do. And again, I think all of that is reasonable.

Okay. So when you look at the -- that sort of on the wholesale side, do you think that sort of transfers this sort of constructive way if they're putting some relief on the wholesale prices that sort of translates to some of this regulated generation, legislation related generation, regulated utility legislation. Do you see that -- how do you see that impacting that? Does that -- do you think that's pretty much sort of on ICE as a result of what you're doing on the wholesale side, if you follow what I'm saying. Does that make sense?

Yes. Yes. No, I do think -- I don't know if it's totally on ICE. It is still part of the discussion. But I would say with all of the moving parts that we've been seeing at PJM and at FERC, the legislature is certainly, I would say, keyed into all of those moving parts and seeing if, in fact, that they will help address the resource adequacy concerns that we've been talking about. Again, we have -- we're a bit skeptical that the PJM FERC filing will, in fact, resolve that long term. And we think the bilat process is probably going to be the predominant way to get things built in PJM. But I think the legislature needs to see that play out.

Our Governor needs to see that play out a little bit. So while regulated generation. I wouldn't say that it's totally off the table. I think they want to see how some of these other things progress to see if they need to pull that lever or not. And of course, we continue to have regular discussions with them. And this will play out as those bills are debated in the prospective committees, and we'll see whether they come out of committee or not. But there's been so much activity, as you know, at both FERC and PJM that legislation, I don't think has been the highest priority for obvious reasons.

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

Great. Thank you, operator. So look, as we wrap up, the key takeaway from today is our investment case continues to get stronger. We're executing a strong base plan today while building additional strong growth opportunities for tomorrow and with continued regulatory execution and accelerating demand growth and the progress that we're making at Invitium Energy, we believe the upside is increasingly visible and remains incremental to the outlook that we've reaffirmed today. Thanks for joining us, and we look forward to seeing you soon. .

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

Good day, and welcome to the PPL Corporation First Quarter 2026 Earnings Call [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Andy Ludwig, Vice President of Investor Relations. Please go ahead.

Good morning, and thank you for joining PPL Corporation's conference call on first quarter 2026 financial results. We've provided presentation materials on the Investors section of our website. This morning, you'll hear 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, please turn to Slide 2 for our cautionary statement. Today's presentation contains forward-looking statements subject to risks and uncertainties. Actual results may differ materially. Please refer to our SEC filings and the appendix for additional information. We'll also refer to non-GAAP measures, including earnings from ongoing operations. Reconciliations to the corresponding GAAP measures are provided in the appendix. I'll now turn the call over to Vince.

Thank you, Andy, and good morning, everyone. Let's begin on Slide 4 with an overview of our first quarter performance. Overall, we delivered strong financial and operational results in the first quarter, reflecting disciplined execution across the enterprise. Today, we reported first quarter GAAP earnings of $0.60 per share. Adjusting for special items, ongoing earnings were $0.63 per share.

Based on these results and our outlook for the remainder of the year, we are reaffirming our 2026 ongoing earnings guidance of $1.90 to $1.98 per share with a midpoint of $1.94 per share. We also remain on track to complete approximately $5.1 billion of planned investments in 2026, supporting the delivery of safe, reliable and affordable energy for our customers. Longer term, we continue to project approximately $23 billion of capital investment through 2029, resulting in average annual rate base growth of 10.3%. This capital projection excludes any investments that may stem from our joint venture with Blackstone, which I'll provide an update on shortly.

We're also reaffirming our long-term financial targets, including 6% to 8% annual EPS growth through at least 2029, with compound annual growth expected near the top end of that range. We also continue to target annual dividend growth of 4% to 6%, along with strong credit metrics throughout our plan period, which support a very compelling risk-adjusted total return for our share owners.

Overall, our quarterly results position us well to deliver on our 2026 targets and beyond. Moving to Slide 5 and some notable regulatory and business updates. During the quarter, PPL Electric Utilities reached a constructive settlement with the majority of the intervenors in the distribution base rate case. Remember that we filed this rate case in the third quarter of last year, following more than 10 years since our last base rate case filing.

Our filing reflected the results of effective cost efficiency and prudent investments over that period that have delivered significant value for our customers, while keeping O&M increases 25% below inflation. The settlement achieves a balance between our strong commitment to affordability and maintaining safe and reliable service for our customers while supporting the significant demand growth in our service territory with large load customers.

Importantly, the settlement would result in bill increases that are less than 4% across all customer classes despite staying out for those 10 years, and it keeps our delivery rates among the lowest in the state. We've also agreed to a 2-year stay out following implementation of the new base rates. The settlement also enhances support for vulnerable customers by increasing hardship fund bill credits, improving access to assistance programs, eliminating reconnection fees, streamlining return of security deposits and boosting the annual low-income weatherization budget.

We also created a new large load customer rate class and electric service tariff that includes key protections for our other customers, such as a [ 10-year ] load requirement and various financial commitments. The proposed tariff and rate class would also provide approximately $11 million annually in support of our residential low-income programs. Put together, the elements of this settlement would provide tremendous value for our customers by ensuring they receive safe, reliable and affordable electric service.

On April 17, we were pleased that the administrative law judges recommended approval of the settlement without modification. We expect the final decision from the Pennsylvania PUC by the end of June with new rates effective July 1. In Kentucky, LG&E & KU were granted reconsideration of decisions made by the Kentucky Public Service Commission regarding its base rate case earlier in Q1. As discussed in February, we expect the current decision by the KPSC will allow us to deliver on our overall plan objectives. However, as outlined in the reconsideration request, we continue to believe, along with many of the intervenors that our negotiated settlement was a better outcome for all parties, including our customers and it should not have been modified.

The reconsideration focuses on a limited number of substantive issues, including such modifications that KPSC made to the settlement and certain cost recovery and return to terminations. Importantly, while LG&E and KU's petitions were granted rehearing by the KPSC, all intervenor requests were denied. A procedural schedule has been set by the KPSC with the additional discovery projected to conclude by May 22. Parties have until May 26 to request the hearing or to ask for a decision based on the record in the case, and we hope to get a decision by the KPSC in the third quarter.

Also in Kentucky, we're excited to announce a couple of new partnerships to explore innovative generation technologies in support of the increasing electricity demand in our service territory. Last month, we announced our partnership with Rye Development to evaluate a new 266-megawatt pump storage hydro project that Rye has been working on in Bell County. The project converts former coal mine land in Eastern Kentucky into a reliable energy storage facility, providing up to 8 hours of storage upon COD currently projected for 2031.

Rye has secured preliminary federal permits at this stage with final licensing projected for the second quarter of 2027. The project's initial cost estimates are approximately $1.3 billion, which excludes potential eligibility for a 50% investment tax credit. This project is not in our current capital plan or earnings projections. If constructed, this would be the first project of its kind in Kentucky and one of the first newly built pump storage projects in the United States in more than 30 years.

I'm also excited to highlight our collaboration with X-Energy, a leading designer of advanced nuclear reactor technology and manufacture of advanced nuclear fuels, which we announced just last week. This collaboration will explore deploying X-Energy's Xe-100 small modular reactor in Kentucky to support large load customers, including data centers with long-term, reliable and carbon-free electricity.

Through this collaboration, we aim to support the significant activity and interest in Kentucky to explore nuclear generation, bolstered by some recently enacted legislation supporting nuclear development. This legislation supports early site development through a $75 million grant program that helps fund development costs for up to 3 sites across the state at $25 million per site and also enables utilities to apply for recovery of other early site work that is not covered by the grant program.

We currently expect early site permitting will cost less than $75 million to complete, most of which is anticipated to be funded through the grant process as well as our project partners. As you would expect, we're approaching potential new nuclear development in Kentucky with a disciplined phased approach. That means starting with early stage evaluation and site readiness work closely aligned with state policy support, clear customer demand and financial support, particularly from large load customers and cost recovery frameworks that protect customers and shareowners.

Any decision to move forward would be gated by economics, regulatory certainty and our long-standing commitment to capital discipline. Both the Rye Development and X-Energy partnerships reflect innovative approaches to bring large carbon-free electricity generation to Kentucky in a manner that supports customer affordability and long-term system reliability as electricity demand continues to grow.

Turning to Rhode Island updates on Slide 6. Rhode Island Energy received approval for over $330 million of critical infrastructure investments through its latest annual electric and gas ISR plants. The approval represents the vast majority of what the company requested in its original filings. Recovery of and on these investments began on April 1 of this year with rider recovery helping to limit regulatory lag. The latest plans fund core investment and vegetation management work to strengthen day-to-day reliability and system resilience. And it's clear these investments are providing tangible benefits to customers as reflected in our excellent operational performance, including Rhode Island Energy's ongoing top quartile reliability metrics and its strong execution during this winter's major storms.

During the region's most severe storm of the season in late February, which brought nearly 40 inches of snow and Hurricane force winds, the Rhode Island Energy team excelled performing better than any other utility in New England. Electric crews restored power to 99% of customers within 48 hours, while our gas crews responded to hundreds of emergency calls to ensure customers had gas service for heat during record-setting winter demand. These efforts did not go unnoticed as our teams were honored by the Rhode Island House of Representatives in March for their response to this historic blizzard.

These results reinforce the strong connection between sustained investments and outcomes that matter most to our customers. And that's precisely what our Rhode Island base rate case is about. The rate case was filed in the fourth quarter of 2025, requesting a revenue requirement increase over 2 years. $181 million in year 1 and an additional $49 million in year 2. The proceeding remains on track with intervener testimony filed in April and evidentiary hearings planned for June and July.

New rates are expected to become effective September 1. In addition, Rhode Island Energy recently filed a new hold harmless commitment proposal that is expected to provide bill credits that would significantly offset the impact of the proposed base rate increase for our customers. As a reminder, this proposal addresses PPL's deferred tax hold harmless commitment arising from the acquisition of Rhode Island Energy, accelerating the payment of related bill credits to support affordability in the near term.

We expect new bill credits to be provided to customers starting in the first quarter of 2027. This approach is representative of how we engage across our jurisdictions, using the tools available to us to support affordability today while continuing to attract the investment needed to maintain a safe, reliable energy system for our customers.

Turning to Slide 7, data center update in Pennsylvania. We continue to see significant growth in data center development across our PPL Electric utility service territory driven by location, access to power and an advanced transmission system that enables speed to market for hyperscalers. Projects in advanced stages of planning now total 28.3 gigawatts, up another 12% from the 25.2 gigawatts we discussed on our year-end update call.

As a reminder, projects in advanced stages have executed agreements, either letters of agreement or electric service agreements with meaningful financial commitments from developers attached to them. Of that total, about 10 gigawatts now have signed ESAs consistent with our expectations. This includes contracts with some of the leading companies in this space, including QTS, AWS, PowerHouse, CoreWeave and others. Meanwhile, 5 gigawatts of the projects in advanced stages are already under construction. These are critical proof points that demand is not only real but continues to grow and progress forward.

As we've discussed on prior calls, our ESAs include strong customer protections, such as prepayments, credit support and minimum load obligations to ensure that developers not existing customers bear the financial risk if projects don't proceed as planned. Those same principles are reflected in the proposed new large load customer rate class and the electric service tariff in PPL Electric's rate case settlement.

And importantly, under our tariff structure, the incremental load growth improves system utilization and lowers transmission costs for existing customers. Taken together, this reflects our balanced approach to data centers and our firm belief that data center development can strengthen the grid and lower cost for all customers, all while delivering significant local benefits, including jobs, tax revenue and community investment.

Let's turn to Slide 8. Kentucky continues to experience strong economic development activity as well, driven by both data centers and advanced manufacturing. The Commonwealth overall and LG&E and KU service territories in particular, remain a highly attractive environment for energy-intensive growth, supported by our competitive energy costs and reliable service.

Our current Kentucky development pipeline now reflects 12.9 gigawatts of potential new load through 2032, an increase of nearly 4 gigawatts from our year-end update. New data center requests make up the majority of the increase with 13 new projects expressing interest in our service territory. In total, we have active requests for almost 12 gigawatts of data center demand. Roughly 1/3 of those projects are considered highly active with transmission service studies underway, of which about 650 megawatts are currently under construction or agreement.

At the same time, we're also seeing continued growth in manufacturing, automotive and other nondata center projects, adding important diversity to the mix. During the first quarter, Global Laser Enrichment and Toyota Motor Manufacturing announced approximately $2.6 billion in combined investment plans within our service territories. Based on our updated planning assumptions, we now project approximately 3.5 gigawatts of expected new load by 2032 compared to about 1.8 gigawatts assumed in our most recent CPCN forecast.

As new load materializes, additional generation resources will be required to maintain reliability, and LG&E and KU could be in a position to file another CPCN as early as this year. We remain focused on ensuring that new demand is paired with timely resource additions, protecting customers, supporting reliability and positioning the system to serve the Commonwealth's long-term economic development needs.

Turning to Slide 9 and an update on our joint venture. Momentum continues to build around our Blackstone joint venture. This is driven by the rapid data center growth in Pennsylvania that I just discussed, combined with increasing expectations that large load customers need to bring dedicated generation solutions online in support of their load requirements. This is also supported by the rate payer protection pledges made by both hyperscalers and some of the large third-party data center developers.

Our joint venture was intentionally built for this moment. Interest from hyperscalers and developers remains high. And as I previously mentioned, we are working with all the major customers in this space. The joint venture continues to do much of the upfront development and coordination work so it can move quickly once commercial arrangements are finalized with the hyperscalers.

We're engaged in strategic discussions with key gas pipeline companies focused on ensuring access to low-cost Marcellus shale gas for our future generation projects. Based on the progress to date with the hyperscalers, we are executing multiple gas turbine reservation agreements and have submitted requests for multiple generation projects into PJM's interconnection queue for certain land sites currently under our control. And we're continuing to evaluate additional strategic land parcels to expand access to key sites for further generation development.

We are doing all of this with deliberate financial and execution discipline. As we've shared previously, we will not build without signed energy supply services agreements or SSAs, and our commercial structures will continue to support a utility-like risk profile through long-term contracts. Our JV continues to be a disciplined generation platform to help meet significant new demand while supporting customer affordability and system reliability.

While our current business plan does not include earnings contributions or capital investments from the joint venture, the progress to date meaningfully increases the probability of JV owned generation over time. We're excited about the progress we've made and look forward to providing you with more updates as contracts are finalized. I'll now turn the call over to Joe for our financial update.

Thank you, Vince, and good morning, everyone. Let's turn to Slide 11. PPL's first quarter GAAP earnings were $0.60 per share compared to $0.56 per share in Q1 2025. We recorded special items of $0.03 per share during the first quarter primarily due to an ISO-New England transmission ROE reduction as well as customer system and meter system integration impacts, partially offset by regulatory asset treatment of costs associated with PPL's IT transformation in Kentucky.

Adjusting for these special items, first quarter earnings from ongoing operations were $0.63 per share, an improvement of $0.03 per share compared to Q1 2025. The increase was primarily due to higher base rate recovery in Kentucky and higher transmission revenues from additional capital investments, partially offset by higher depreciation and higher financing costs. Our solid first quarter results keep us on track to achieve at least the midpoint of our 2026 earnings forecast of $1.94 per share.

We also continue to maintain one of the strongest credit ratings in our sector with a balance sheet that provides the company with significant financial flexibility that benefits both customers and stakeholders. In February, we successfully executed a $1.15 billion equity units offering with a purchase contract for PPL common shares settling in February 2029. This offering provides a clear path to permanent equity while allowing participation in share price upside.

Following this transaction, we have now derisked about 2/3 of the total equity needed to support our current capital expenditure plan. For the remaining equity needs, our base plan is to utilize the ATM, which remains an efficient financing tool. We'll also continue to be opportunistic with other equity-like financing structures to the extent that they provide a lower cost of capital.

Turning to the ongoing segment drivers for the first quarter on Slide 12. Our Kentucky segment results increased by $0.03 per share compared to the first quarter of 2025. The improvement in Kentucky's results was primarily due to higher base rate recovery from new retail rates that were effective on January 1. This was partially offset by lower sales volumes due to less favorable weather than experienced in Q1 2025, higher operating costs, higher depreciation and higher interest expense.

The remainder of our segments were flat compared to the first quarter of 2025. Our Pennsylvania Regulated segment results were driven by higher transmission revenue from additional capital investments, offset by higher operating costs, higher depreciation expense and higher interest expense.

Our Rhode Island segment results were driven by higher rider revenue returns, including investment recovery through the ISR mechanism and FERC formula rates. These favorable items were offset by higher depreciation expense. Lastly, results at Corporate and Other were driven by higher interest expense, offset by several factors that were not individually significant. Overall, we're off to a strong start in 2026 with solid performance across our business segments and a clear line of sight to achieve our financial objectives.

Our capital investment plan remains firmly on track, positioning us to continue to strengthen system reliability, modernize the grid and provide an improved experience for our customers. At the same time, our strong balance sheet and business plan position PPL to confidently achieve our growth targets and deliver strong, stable returns for our shareowners with meaningful upside opportunities beyond the plan.

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

Thank you, Joe. Before we open it up for questions, I'll leave you with a few closing thoughts. Here at PPL, we're executing with discipline, delivering strong first quarter results, reaffirming our guidance and long-term financial targets, and continuing to invest responsibly in the systems our customers and communities rely on.

Across our jurisdiction, we're advancing constructive regulatory outcomes that balance affordability today with the investments needed for long-term reliability and growth. Affordability is a top priority for us, including here in Pennsylvania. We've been talking about this for over 5 years now and made it a cornerstone of our Utility of the Future strategy. So we are not surprised at all by what we are seeing in various states, where elected officials are very focused on affordability for their constituents.

That is why we have consistently taken actions to drive efficiency across the business, maintain cost discipline, employ technology to optimize our assets and limit base rate increases, all while continuing to improve service. A perfect example is our rate case settlement in Pennsylvania, where we hadn't filed a rate case in over 10 years, and the bill impact of our settlement will be less than a 4% increase for all rate classes, which again puts our delivery rates among the lowest in the state.

We don't just talk about focusing on affordability. Our actions support our words, and we have been very effective at delivering excellent service for our customers at a reasonable price and at the same time, competitive returns for our shareowners, and we fully expect to continue to deliver on both of those areas going forward. At the same time and related to improving affordability, our economic development pipeline continues to progress with projects moving from planning into agreements, construction and execution. That demand is supporting new investment opportunities and partnerships, like those we announced with Rye Development and X-energy, focused on delivering reliable, cost-effective generation solutions that done right will lower energy costs for our customers. We're also excited by the continued momentum with our joint venture with Blackstone infrastructure. We believe it positions us very well to meet growing generation needs in PJM in a way that will lower customer bills, improve system reliability and deliver long-term value creation for our shareowners.

As you can hear, we don't view growth and affordability as competing objectives. Done right, incremental load, disciplined investment and thoughtful generation development can improve system utilization and help lower overall customer costs. That's the approach we're taking, grounded in regulatory credibility, capital discipline and a clear focus on delivering safe, reliable and affordable energy while creating long-term value for our communities and our shareowners.

With that, operator, let's open it up for questions.

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

Just wanted to start off with the Genco JV, if you could, and appreciate announcements when they come, but it seems like there's some really good positive momentum happening here. And just want to kind of frame up the time line for when this could come together. Is this like weeks, months or is this quarters? Or is there anything else you could help us think through how the time line could unfold here?

For the ESS, Jeremy?

For the Genco JV?

Yes. I mean your question is like timing around when we might sign contracts or...

Yes.

Well, look, as we talked about in the prepared remarks, right, where we've made a lot of progress, certainly over the last year, and we're really encouraged by the most recent momentum that we're seeing, again, I would say, stemming from really what we've been talking about for months now where the hyperscalers are going to need to pay attention to generation up until very recently, they've been very focused rightfully so, I would say, on getting connected to the grid.

But that time has come now that they are focused on generation. And we're very pleased and fortunate that we started this joint venture over a year ago when we did because we've laid the foundation to be ready to meet the moment when the hyperscalers are taking this seriously, and they clearly are, given the rate payer protection pledge and all of the activity around that. So in terms of timing, I would say, we're continuing to work through the process of getting SSAs in place.

That is an active process. I could tell you that. Trajectory is clearly positive, I would say, it's probably likely that we would have something meaningful to announce this year on that, Jeremy, but these are very complex agreements that have to go through a lot of different parts of the hyperscalers to get to the finish line and then ultimately announce. But I would say, again, based on where we stand today and the momentum that we're seeing, I'd be surprised if we weren't doing -- announcing something meaningful this year.

Got it. That's very helpful. And then I just wanted to turn to Slide 7 here. And there's a lot of data on the data center backlog. Just wanted to see if you could just kind of parse out for me, make sure I'm clear, how much of the data center growth in Slide 7 is incremental to the current earnings and capital plan?

Yes, sure. So the -- in our updated plan that we came out with in February, [ we had about $1.3 billion ] for incremental transmission CapEx. When we look at the 28 gigs, I would say, there's probably another $0.5 billion at least to serve that incremental demand, Jeremy. Some of that, though, I would say would be spent beyond the current plan period in 2029, but it's, I would say, at least another $0.5 billion of upside beyond what's in the current plan.

Got it. That's very helpful. And then just the last one, I guess, going to the RVP. Any thoughts on the impact if it goes through as kind of initially proposed for PPL, both on, I guess, the EDC side as well as if the Genco JV might have interest there.

Yes. Yes, great question. Look, maybe just a few thoughts on the RBA itself. I think clearly, we support PJM's conceptual process for focusing on and starting with bilateral contracting, obviously, we support that. That's why we created the joint venture. But I would say there's quite a bit of work that needs to be done to ensure that the cost that are related to any backstop auction are actually borne by the large loads that they are intended for and that our other customers don't end up getting allocated those costs through some unintended consequence or some allocation methodology that doesn't achieve what we're all trying to achieve here, which it's not clear as written or has proposed that we would actually get that result.

I am optimistic, Jeremy, that we can get there, but there's quite a bit of work that we need to do with both PJM and FERC to ensure that. I would say if the proposal was approved by FERC as is, then at the utility, at PPL Electric Utilities, we would absolutely need to work with the state to ensure that we have those guardrails or those protections either contractually or otherwise to ensure what I said before that the [ EDC ] is not shifting the risk and/or the cost of that auction to our other customers. So headed in the right direction, but there's quite a bit of work, I would say, to be done there.

In terms of the participation, really depends on the final rules. And obviously, PJM is working through feedback that they just received earlier this week. It will also depend, I think, if the EDCs are mandated to participate. But again, if it's approved as proposed, there's quite a bit of work we need to do at the state level to get those protections in, and that could impact our desire to participate at the EDC level.

On the JV, I would say, this could be an opportunity for us. Again, I think it depends on the ultimate rules. But I would say for now, our priority absolutely continues to be on our very active bilateral process. So we're not slowing down on what we're doing with the JV and then we'll see if there's an opportunity to participate in the auction. Currently, we're not sure if we would or we won't. We really see how those rules shake out.

Next question comes from Paul Zimbardo with Jefferies.

I apologies if I missed it, Vince. I think you said multiple slot reservations. Any color you want to put around that? Is that [ 2 is ] multiple? Is it bigger than 2? And just what's the time on delivery for those pieces of equipment?

I would say those are all details given the competitive nature of this, Paul, that I'm not going to get into a lot of detail on it. I would just say confidently that our submittal both on the [ PJM queue ], which we have backed by land that's under our control for all of those submittals, multiple generation projects, but it positions us very well to be competitive with the joint venture. .

And then on the turbine reservations, sufficient quantity to support what I just said on the interconnection queue there.

Okay. Understood. And I get the sensitivity. Shifting gears to the Pennsylvania electric utility, assuming the settlement is approved, I know you have the stay out. Any kind of time frame that you think about when you need to go back in? Or could you kind of rely on the [ DISC ] mechanism to stay out for more than a couple of years.

Yes. No, you're right. Embedded in the settlement. We do have a 2-year stay out. So we have good visibility on a minimum of 2 years. And that's from the date that new rates become effective, which we expect to be July 1. So we wouldn't need anything between now and 2 years out. Yes, look, we stayed out for 10 years prior to our financial discipline, our cost management discipline. As you know, we continue to look at ways to drive costs out of the business. AI is a whole new wave of opportunity there.

We are embarking on our system consolidation that will drive cost savings over time as well. We are in the middle of doing that work though. So how much of that shows up by, call it, mid-'28 when the stay out expires, we'll see. But clearly, that will be a focus of ours to stay out as long as we can, similar to what we did last time.

Our next question comes from David Arcaro with Morgan Stanley.

I was wondering, curious about your reaction maybe to the content of the letter that the governor had sent. Just in terms of the different approaches that were proposed there around ROE, debt and equity ratios, et cetera, how are you interpreting and kind of reacting to that?

Yes. I would say, in general, we share the same ultimate goals as our governor does, right, delivering safe, reliable, affordable energy for our customers. We've talked a lot about -- and I think this is a differentiating factor for PPL we've been talking about affordability for several years, way before most of the industry was focused on it. It's why we've taken the actions that we have to focus on cost control, making the investments around automation and hardening those things, right, reduce O&M over time and that's really enabled us to stay out of base rate cases for over a decade.

So as you know, we only seek rate increases when it's absolutely necessary to maintain that safety and reliability. And so we'll continue to kind of similar to Paul's question around timing of the rate case, we'll continue to operate in that way in the best interest of our customers to ensure that we can improve service, do it affordably and provide competitive returns to our share owners.

We think we can continue to do that even under the points that were in the Governor's letter. Again, I think we share the same goals as our governor. We've been extremely successful at balancing all of those things. It is evident in our settlement after a decade with only a 4% increase nominally for our customers. So Obviously, the governor had some concerns with some of our -- with some of the other EDCs in the state.

But I think we are very well aligned with our governor, and I think we'll continue to engage in stakeholder engagement with him with the PUC, the new special council that's been assigned by the governor. So I'm not concerned that we really need to alter our stance in PA. I still think it's a great jurisdiction. We'll be able to invest in it, earn reasonable returns and deliver what we need to for our customers.

Got it. Yes. That's helpful. Then maybe shifting over to Kentucky. I was curious, just as you see the load projections increase here, could you touch on just what that might mean in terms of what generation resource you might end up needing there, maybe -- any thoughts here on the timing of when you need new generation and if it's peak or baseload or what kind of options might be under consideration?

Yes, sure. Joe, do you want to take that?

Yes, sure. So a couple of things in that question. But I would say on the resource that's needed, that would ultimately, I think, be dependent on the customer and the load ramp and how quickly that's coming online given the time that it takes to get different types of resources online and ready to deliver.

From a timing perspective, of a CPCN that I think will, again, ultimately be driven by how quickly large load demand converts and then the visibility that we have into that load ramp. Importantly, we have about $4 billion of generation projects under -- approved under construction. And so we'll want to see the existing pipeline advance before laying around incremental generation investments.

Having said that, though, if you look at our probability weighted demand growth at about 3.5 gigawatts compared to the 1.8 gigawatts in our prior CPCN, it's certainly becoming more likely that we file another CPCN later this year, especially if we get one or more hyperscalers committed to a significant load ramp. So we could be seeing something later this year.

Yes, Dave, I would just add to that. I mean clearly, the momentum is headed in a direction where it's getting more likely that we will file something this year. To Joe's point, with $4 billion in flight, we want to be very judicious about adding more generation. But I mean, our probability weighted 3.5 gig. We have 1.8 gig in the current CPCN. So I mean it's almost twice the load that's being supported by the current CPCN. We start to see hyperscalers kind of back the projects that we're seeing, so that the projects that are under construction are still developers.

So once we start to see those get back by actual hyperscaler tenants and load, I think the battery, clearly, likely comes back in just that's the quickest thing we can get on. So I think the battery likely comes back in, in that CPCN. But then you have the right development project, do we need additional cash generation on top of that, perhaps, it really depends on how far we're going between the 1.8 gig and the 3.5 gig, at the time we would file that CPCN. So I would say 1 to maybe 3 projects could show up in a CPCN based on this load profile that we're seeing and the momentum that we're seeing, obviously, it's a little bit early, but just given what we're seeing now, I would say that could happen by the end of the year, again, given the momentum that we're seeing.

Next, we have Shar Pourreza with Wells Fargo.

Actually, it's Andrew [indiscernible] on for Shar. We talk a lot about the supply driving the affordability issues in Pennsylvania and the possible solutions that PPL can provide to that issue. Do you see any parallels for the situation in Rhode Island? Are you considering pursuing generation there?

Yes, there's actually proposed legislation in Rhode Island to enable the utility to own generation again, which we obviously support. So very similar issues. I think there's a couple of things that we know are affecting power prices up in New England, the gas constraints into the area are clearly one cause. And there is a lot of recent activity to try to increase gas transmission into New England, in particular, coming up through our area.

We're seeing other projects to even on the existing pipelines, get additional volumes through the existing pipes. We've taken an offtake on one such project. So that's good. We know New England is using high price, high volatility LNG quite a bit. So whatever we can bring in additional potentially Marcellus shale gas, which is much less volatile that can help to lower the volatility in the overall high price of LNG.

And then environmentally, all of this is still good because New England and in particular, Rhode Island has a significant amount of its energy still coming from fuel oil, which comes in on barge and then it gets driven around in diesel trucks around the state and around the region. So obviously, the more we can displace that with clean natural gas, you get a huge environmental benefit as well.

So which we know policy state and regional policy is very focused on carbon and other environmental benefits. So I think there's some win-wins that we can do by improving or increasing the gas flow up there, and there's a lot of activity going on around that, that we are directly supporting and indirectly supporting.

That's very helpful. And then on the retroactive refunds from the FERC ROE determination in New England, is that long period of refunds stands through like the court challenges. Does that affect the way you think about capital allocation to transmission going forward?

Well, first of all, let me talk about the refunds. We're not going to wait until -- I think it's May of '27 was the extension, we're not going to wait that long. Our refunds in the around $25 million, $26 million. So our plan would be to also engage with the commission in conjunction with the rate case and the hold harmless and time those refunds put it all in one package for our customers in conjunction with the rate case. There was another part of that question that I missed or did I answer that?

Just if the precedent of such long-term retroactive refunds stands, will that change how you think about allocating capital to transmission, having that be at risk, the rates that you're charging to customers?

Yes. Yes. No, I don't think so. I mean, again, we're talking tens of millions of dollars exposure. Obviously, the New England TOs filed their 205s. We kind of live and tie together as a group up there, just filed a 205 filing for higher ROEs going forward. So no, I'm not worried about capital allocation in Rhode Island at all. I still think it's a great asset in great jurisdiction. And we'll continue again to I think be able to use creativity and innovation, whether it's regulatory or physical assets to help to take some of the pressure off of the wholesale power markets so that will help with affordability and at the same time, deliver competitive returns to our shareholders for the investments that we're making up there. So every bit is bullish on Rhode Island as we were when we bought it. .

Our next question comes from Michael Lonegan with Barclays.

For the Blackstone JV, you highlighted good progress on the gas side, engagement with pipeline companies reserving turbines. Last earnings call, you talked about alternative generation solutions that could come online sooner, you didn't point any specific type of technology. Just wonder if there's anything you could share on type of technology now and progress on that front?

Yes, sure. So it really depends on what the ultimate hyperscalers want. They're the ones that will be the offtake of the ESA. So if they need generation to ramp -- new generation to ramp with their ramp schedule, then most likely, we'll be doing that with batteries, even some of those alternate forms of energy are getting -- those time lines are getting pushed back closer to where the CCGTs are. So batteries are really -- maybe fuel cells are really the technologies that we can bring online sooner ultimately, the hyperscaler will be the one to determine if and how much they -- of that they would want prior to kind of the backstopping the larger CCGT. But that's kind of how we're thinking about it, Mike.

And again, it's -- and I would also say it's hyperscaler specific. Some want to see gen come on in line with their ramps. Others are more comfortable relying on the current fleet within PJM to provide that and they just want to make sure they get enough when they're kind of at full ramp. So all of those things, we're working with on a one-off basis with our customers.

Great. And then sticking with the JV, I wonder if you could help us think about the returns on those projects. And my understanding is they would be above utility returns. And I know it depends on each project and contract but anything more precise in terms of a range of returns you could share on that?

I think the way you talked about a high level is [indiscernible] willing to share at this point.

Our next question comes from Paul Patterson with Glenrock Associates.

So a few quick ones for you. So on the affordability thing, there is this -- there has been legislation proposals, et cetera, I think, in Pennsylvania to have regulated generation or at least have the potential option of it. And I'm just wondering why how that -- I mean is there any progress in that considering that the governor is concerned about -- I mean, the numbers seem to -- in terms of the wholesale market impact and what have you, could be beneficial. I'm just wondering how that might stand given this affordability concern and this being a potential opportunity for you guys and for the state?

Yes. So you're right, there is a proposed legislation in the state to, I would say, to incentivize new generation, right, either through long-term contracts between utilities and ITTs or as a backstop allowing the utilities to build and own generation again. Those legislations in both the House and the Senate are in committee, come out of committee. .

Look, I would say, given all of the recent activity with PJM around the backstop auction, they just came out with their new market design document that has a few options in there to help promote building new generation and maintaining affordability on the wholesale side. So my sense, Paul, is that the legislature is going to want to see how some of those market dynamics shake out before they push that legislation part within the broader legislature. So I don't know that I would expect anything to come out in the near term on the legislation.

We continue to support it, but we're also not waiting for it, right? And we are actively pursuing this with the Blackstone JV to provide that much needed generation, which is very consistent with both the backstop auction, I would say, kind of process for our goals. And then even with the [ market design white paper that just came out, report that just came out earlier this week, the JV and building Gen fits perfectly within both of those. So that's kind of where our focus is. We're not waiting for the legislation to continue to support it. I do think that the state is going to wait to see how some of these things play out before they push it, certainly to the full legislation.

Okay, that makes sense. And then with respect to the -- you guys have mentioned this before, this sort of unique competitive advantage that you have with advanced transmission systems. You guys have been involved in DLR in the past, I think. And I'm just wondering, and there's, of course, this legislation that passed, I think, unanimously through one of the -- one of the state -- through the -- one of the houses in the state legislature on transmission.

I'm just wondering, could you just maybe just elaborate a little bit more about what makes you guys unique? What makes you feel that you've got this unique competitive advantage in transmission, if I'm reading it correctly.

Yes. I mean there's various reasons why I think we have a competitive advantage around transmission. One is on grid enhancing technologies that you're talking about, which -- we were one of the first utilities in the country to deploy dynamic line rating. We were the first, may even be the only one still to have integrated our DLR capabilities into the day ahead market with PJM. So not only are we using it around our transmission planning, but PJM is using it to identify their constraints live in the system.

So that clearly is a competitive advantage. And we do have various large load customers asking about whether we have DLR on our transmission lines that would support them and/or whether or not we could add that if it's not currently on there. The other, I would say, bigger benefit or a strategic advantage that we have is just the investment that we've made in our transmission grade over the last decade. And we have created -- and a lot of this was due to reliability issues.

So our whole utility of the future on the physical side that we talk a lot about, we've been at that for a decade now in Pennsylvania, in particular, on our transmission grid. And so we have one of the most reliable grids, the most automated grids. And when we were doing all of those reconductoring are going from wood to steel, et cetera, we also upsized the lines. And so that created additional capacity that is enabling us to connect these very large loads very quickly. And what that -- so when we connect, say, a gigawatt scale, it's not that we're not doing any upgrades, but the time it takes us to do those upgrades and the cost of those upgrades is significantly lower than some of our peers' transmission networks.

So we're at the point now at this 28 gigs, we're probably to get a gigawatt scale added, we're spending less than the $150 million total. The hyperscalers are directly paying under the energy services agreement, soon to be under the new tariff they're paying under direct payments, so [indiscernible] more than half of that amount. And then what's left goes into the FERC formula rate, which is the piece that provides broader benefits to the entire grid.

But some of our -- some grids are spending $1 billion or more to connect a gigawatt. So for very little money with connection times that are unrivaled that's the primary competitive advantage that we have. And then we kind of come in with the kicker around DLR. But that's -- I would say that's icing on the cake.

Our next question is Anthony Crowdell with Mizuho.

Tough season, gents. That's an understatement. I appreciate the detail. Hopefully, just 2 easy ones. Just -- do you know in PGM for the bring your own generation plants, do you know if that to be located adjacent to the data centers or they be located? Or your plan is are you going to locate them anywhere in PJM? And then I have a follow-up.

So in the backstop auction, they do not necessarily need to be co-located or near located obviously with our Blackstone strategy, they will.

And then lastly, just -- you guys are unique. You have the ability of -- you're pursuing the JV with Blackstone, in the wires-only region in Pennsylvania. You have a fully integrated utility in Kentucky. When you talk to the large loads, the hyperscalers, is there any preference they have one region versus the other? If you think about the structure of Kentucky, structure in Pennsylvania, is there any -- do they care either way or just location and tying into their needs there?

Yes. It's very -- so obviously, given our 2 major jurisdictions. And I would say even -- we're starting to talk about, "Hey, if you want to serve Boston, let's talk about Rhode Island, right? So I would say we have unique jurisdictions in a data center play. Obviously, in Pennsylvania, when you kind of draw the radius around where we are I mean you're just picking up massive industrial business populations, right?

And so if you are worried about kind of lag and making sure that your reliability is at five nines, and you have to be incredibly reliable with no latency, they're going to go where the population is. However, now with AI, large learning models, more flexible load around datacenter and AI, you can do that anywhere. And so Kentucky much less population, but low power prices, we control our destiny on the whole thing. We just obviously have to get our commission's approval for that, but we're not behold into a market who may or may not be bringing generation to bear.

So they like the fact that we can control everything in the integrated utility, but it's a different type of data center that they would be looking for there than perhaps something in Northeast Pennsylvania. And then like I said, we'll -- I think we can offer benefits for folks that are thinking about Boston as well since we're pretty close there.

Our next question comes from Ryan Levine with Citi.

Just 1 question for me. Given the new PJM CEO's letter and related report, any thoughts around some of the ideas proposed through that report and the future of the capacity auction?

Yes. Look, I think it's -- overall, it's good to see PJM finally recognize the issues that we've been talking about for a couple of years now. And really, I would say the admission that the current market construct will not solve the supply issues that we've been experiencing in PJM. So that's good. As far as some of the proposed solutions, right, just based on the conversation we had here in the Q&A, I think you could see some of them are very consistent with our views as well, including the large loads, bringing their own gen or being interruptible until they do.

We've advocated for that as well. And that clearly can still enable speed to market for the customers, but at the same time, take some pressure off of reliability and higher capacity costs until that new BYOG comes online. So I don't think there's anything in that market design report that would replace the need for BYOD, but it could provide a bridge to it. So look, overall, I think we're headed in the right direction.

Any thoughts on the proposed options around the capacity auction?

Not in detail. I really kind of want to see how that shakes out. Look, I think part of the issue that we've been experiencing in PJM is, right, on the energy and the capacity side where the marginal price is what gets paid to all generation and that's what's kind of been creating this issue.

And so you can see in that report, perhaps some idea to go after that and parse that out a bit. So again, I think headed in the right direction, but more work needs to be done to [ ferret out ] what that would look like. I know there was some mention of maybe going to kind of an ERCOT model again. We have to see details ultimately is being proposed there.

But at the end of the day, we have to find a way to ensure that the generators are earning a reasonable return on the investments, but at the same time, make sure that the wholesale power prices, whether it's energy or capacity or affordable for the customer. And so we're at that point for sure. The market is coming up with other ideas primarily on the bilateral contracting. And it's good to see that the hyperscalers have signed that rate payer protection pledge and taking responsibility for that. That will go a very long way here.

But I still think PJM needs to look at that capacity market and try to figure out how to balance reasonable returns for the generators against affordability for the customers. And it seems like that's where they're headed, which is good to see.

This concludes our question-and-answer session. I would like to turn the conference back over to Vince Sorgi, President and CEO, for any closing remarks.

Great. I just want to say thanks for everybody joining us, and we look forward to seeing folks out on the circuit. Thanks, everybody.

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

Good day, and welcome to the PPL Corporation Fourth Quarter and Full Year 2025 Earnings 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.

Good morning, and thank you for joining the PPL Corporation Fourth Quarter and Full Year 2025 Earnings Call. We have provided the presentation materials on the Investors section of our website. This morning, you'll hear 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, please turn to Slide 2 for our cautionary statement.

Today's presentation contains forward-looking statements subject to risks and uncertainties. Actual results may differ materially. Please refer to our SEC filings and the appendix for additional information.

We will also refer to non-GAAP measures, including earnings from ongoing operations. Reconciliations to the corresponding GAAP measures are provided in the appendix.

I'll now turn the call over to Vince.

Thank you, Andy, and good morning, everyone. Let's begin on Slide 4 with a look back at 2025. I'm proud to report that we finished the year exactly where we said we would, delivering safe and reliable electricity and natural gas service to more than 3.5 million customers and achieving our stated financial targets for investors. Operationally, our teams performed at an extremely high level across the company, directly resulting from years of intentional investment in our infrastructure, combined with strong day-to-day execution by our workforce. We achieved first quartile or near first quartile T&D reliability in all of our jurisdictions and top decile generation performance in Kentucky. I will say first quartile T&D performance is trending worse overall for the industry as a result of more frequent and severe storms as well as more extreme weather events. This is causing utilities across the country to increase their capital investment plans significantly to combat mother nature. And the same applies here at PPL.

During 2025, we continue to clearly focus on innovation as this will be a significant source of continued operating efficiency across our business in support of customer affordability. We are developing several digital solutions to improve customer service, including an Agentic AI digital customer service agent and a recently released customer app at PPL Electric Utilities. We will expand the rollout of these and other digital solutions across our business in the coming years, and we're really excited about the digital future for utilities.

From a financial perspective, we achieved ongoing earnings of $1.81 per share, 7.1% growth from our prior year results and in line with the midpoint of our forecast. From a capital investment standpoint, we executed $4.4 billion of planned investments focused on grid hardening and modernization, advanced metering, pipeline replacement in our natural gas businesses and the initial stages of building new generation in Kentucky. These investments directly support reliability, resilience and long-term affordability for our customers. On the cost efficiency front, we outperformed our O&M savings target by about $20 million, achieving approximately $170 million in run rate savings from our 2021 baseline, about a year ahead of our $175 million target for the end of 2026. Our O&M efficiency strategy has been a key component of our affordability strategy here at PPL and that will continue to be the case as we move forward beyond 2026.

Finally, we engaged extensively with a wide range of stakeholders to power economic development in our territories. These actions have supported the growth of our significant data center pipeline while fueling some of the largest economic development projects our territories have seen, including the $3.5 billion advanced manufacturing investment by Eli Lilly announced earlier this month right here in Allentown, Pennsylvania. In summary, this past year reflects what we strive for as a company, consistently high levels of execution, disciplined financial performance, a forward-looking strategy and results that create value for both customers and share owners.

Let's turn to Slide 5. Building off our strong year in 2025, today, we announced an updated business plan that extends our growth outlook while keeping customer affordability and our strong credit profile front and center. For 2026, we're issuing ongoing earnings guidance of $1.90 to $1.98 per share, with a midpoint of $1.94 per share, representing 7.2% growth from 2025. We're extending our 6% to 8% annual EPS growth target through at least 2029, expecting the EPS CAGR through 2029 to be near the top end of that range based off of our 2025 ongoing earnings. We're expecting stronger growth beginning in 2027 and continuing through 2029 compared to the midpoint of our 2026 growth range since the full year impacts of our current rate cases don't kick in until next year.

Importantly, beyond this strong base plan, we see several identifiable upside opportunities to further enhance or extend our earnings growth over time. These include earnings from competitive transmission projects, additional transmission and distribution investments to support the significant economic development that we're seeing in both Pennsylvania and Kentucky and additional generation needs in Kentucky. It also includes earnings from our joint venture with Blackstone, which I'll cover in more detail in a few slides.

Our earnings growth is supported by our capital investment plan. We project capital investment needs of $23 billion from 2026 through 2029, up from $20 billion in our prior plan period. Our updated plan includes the critical investments that strengthen our networks against those more frequent and severe storms and other extreme weather impacts. These investments will accelerate our ability to restore power when storms do strike and deliver the new generation resources approved by the Kentucky Public Service Commission last year, ensuring we continue to deliver safe, reliable and affordable energy for our customers. The result of these investments is an estimated rate base CAGR of about 10.3%, providing a strong foundation for predictable and durable earnings growth.

Our updated plan supports PPL's strong credit metrics, including 16% to 18% FFO to debt throughout the plan period. In support of our expected capital expenditures, the plan reflects total equity needs of about $3 billion from 2026 to 2029. Importantly, we already executed about $1 billion of that equity need last year, leaving about $2 billion of equity to be issued going forward in support of this updated plan. Finally, in connection with the updated capital needs, we modified our annual dividend growth rate target to 4% to 6%, while we are issuing equity to fund our capital plan. Overall, our updated business plan balances growth, affordability and financial discipline while continuing to provide top-tier returns for shareowners relative to our peers.

Turning to Slide 6 and an update on the final Kentucky rate case orders that were issued earlier this week. Overall, the outcome of these cases allows us to deliver on the business plan we've outlined for you today. The commission approved an aggregate increase of approximately $233 million in annual electric and gas revenues, which is within $2 million of the stipulation we had agreed upon with most interveners in the case. In addition, the KPSC approved allowed ROEs of 9.775% for both utilities with 9.675% for our capital-related mechanisms. These ROEs are 35 and 32.5 basis points higher, respectively, than our previously approved levels.

Importantly, the commission approved the pilot generation recovery mechanism, which enables recovery of and a return on investments associated with new generation and energy storage projects that were previously authorized by the commission. This mechanism supports improving reliability and resilience of our networks as well as our ability to meet growing demand on the system. The mechanism also provides for the recovery of and on certain costs related to keeping the Mill Creek Unit 2 plant online beyond its original retirement date, which was originally scheduled for 2027. We were also pleased to receive approval for our extremely high load factor tariff, which is designed to protect existing customers from the impacts of large data center loads.

One element not approved was the proposed earnings sharing mechanism, which had been tied to our agreement to stay out of rate cases through mid-2028. As a result, we are reassessing the timing of our next Kentucky rate case to ensure we continue to balance customer affordability and the capital required to support system needs. While we are disappointed that the commission modified a settlement that we and the intervening parties worked very hard to achieve, overall, the revenue requirement remained effectively unchanged from the stipulation. From here, we will move forward with implementing the new rates, issuing required refunds related to interim rates and filing a motion for reconsideration with the KPSC on several items.

Moving to Slide 7. We continue to advance progress on our ongoing rate case in Pennsylvania. Earlier this week, evidentiary hearings were held and concluded in 1 day. We are also actively working towards a settlement with intervenors. If we cannot agree to a settlement, we remain very confident in the strength of our case and are well prepared to fully litigate if necessary. Our case balances PPL Electric's need to make critical distribution system and IT investments to maintain and improve reliability, customer service and storm response while providing important customer protections and maintaining affordable rates for our customers. A decision is expected in June with new rates effective on July 1, 2026.

Continuing with Rhode Island regulatory updates on Slide 8. In the fourth quarter, Rhode Island Energy filed its first base rate request since 2017, seeking a 2-year phased increase aligned with the cost of delivering safe, reliable energy while supporting critical infrastructure improvements and affordability programs. This includes a redesigned low-income rate, offering deeper targeted support for those in greatest need, importantly, without raising costs for our other customers. The decision is expected this summer with new rates effective on September 1, 2026. We also filed our annual electric and gas ISR plans in late December, totaling about $350 million, which primarily relates to capital investments to sustain and enhance the safety and reliability of our electric and gas distribution systems. We expect the PUC decision on the ISR filings by the end of March.

Finally, we remain committed to reaching a new hold harmless settlement in Rhode Island to provide meaningful near-term rate relief to our customers. As a reminder, the settlement that we reached with the division last year provided for about $70 a month credit to combined electric and gas customers in the winter months of 2026 and 2027. So very meaningful credits in the months where energy bills tend to be the highest. We'll be engaging with the division and the PUC on a new settlement in parallel with the base rate case proceeding currently underway.

Moving to Slide 9 and an update on our Pennsylvania data center pipeline. PPL Electric Utility service territory continues to see rapid growth in data center interconnection requests. As of today's update, projects in advanced stages, meaning they have executed agreements and have meaningful financial commitments attached to them, now total approximately 25.2 gigawatts, up another 23% since our last quarterly update. We now expect at least 10 gigawatts to be under ESAs by the end of the first quarter. About 5 gigawatts remain under construction, which is consistent with our last update. That said, we believe all of the 25.2 gigawatts of projects have a high probability of completion. And our ESAs include strong customer protections such as prepayments and credit support as well as minimum load requirements for data center customers to pay approximately 80% of forecasted load until the costs incurred to extend service are fully recovered. So data center developers will bear the financial risk of a data center project not getting completed versus our existing customers.

Turning our attention to Kentucky on Slide 10. Economic development overall remains strong. Our current pipeline reflects more than 9 gigawatts of potential new load through the early 2030s. Load related to data centers exceeds 8 gigawatts and about 4 gigawatts of these requests are considered highly active with 500 megawatts under construction. The development pipeline also includes 1.1 gigawatts of advanced manufacturing and other non-data center requests, up about 150 megawatts from our prior update. We are continuing to see robust economic development with several major manufacturers announcing almost $0.5 billion of new investments in our service territories. including Toyota, Foxconn, GE and Anthro Energy.

Our probability-weighted demand growth projections remain at about 2.8 gigawatts or about 1 gigawatt more than what was reflected in the load forecast in our 2025 CPCN. If this potential growth continues to materialize, additional generation resources will absolutely be required. In summary, continued strong interest from both data centers and manufacturing customers validates our long-term generation planning and the recent CPCN approvals in Kentucky.

Turning to Slide 11. As we've been discussing for several years now, affordability remains a core commitment across everything we do and has been a foundational element of the new PPL strategy since 2022. Since that time, we have reduced O&M by nearly 3% annually, reaching $170 million in run rate savings by the end of 2025. About $100 million of those savings benefited our Kentucky customers alone and directly reduced the increases needed in our most recent Kentucky rate cases. In the end, residential bill increases were in the 5% to 11% range after roughly 5 years without base rate increases. This is significantly below the level of inflation over the same period and reflects the tangible benefits of sustained cost discipline. The $170 million of total O&M savings that we've achieved has helped to fund approximately $1.4 billion of capital investment without incremental pressure on customer bills, enabling longer intervals between base rate cases. It's been 10 years in Pennsylvania, 8 years in Rhode Island, and as I said, about 5 years in Kentucky without requesting base rate increases, a direct result of this strategy.

Looking ahead, cost discipline will remain a critical component of our affordability strategy. In our updated plan, we project O&M growth of approximately 1% annually, well below inflation. We expect additional structural savings as we continue to harden the grid and deploy smart grid technologies and improve overall system efficiency. We also see AI as an incremental but meaningful driver of efficiency across customer service, grid operations and back-office functions. Beyond cost control, continued economic development across our jurisdictions also supports customer affordability.

Over time and under the tariff structures we've put in place, incremental load growth, including large load data centers and smaller distribution connected customers improve system utilization and helps moderate costs for existing customers. We also continue to support targeted customer assistance programs to help our customers afford their energy bills. For example, PPL Electric's operation helped leaned in during the 2025 government shutdown to support low-income customers when LIHEAP grants were unavailable. In addition to the low-income program I talked about as part of our Rhode Island Energy rate case, we've also created a new employee-funded assistance program that provides support to Rhode Island customers that meet various income thresholds. And as mentioned earlier, we remain committed to a solution on a hold harmless settlement in Rhode Island and to get those credits reflected in customer bills. In deregulated states like Pennsylvania and Rhode Island, we do not control every aspect of the customer bill, but we are focused on lowering those costs as well.

So let's move to Slide 12 and talk about what we're doing in this regard. As an example, more than half of the customer bill in Pennsylvania comes from costs we do not control, with energy supply costs being the largest component. For several years, we have been sounding the alarm on a worsening generation supply situation in PJM, which has been the primary driver of higher customer bills. Since December of 2020, energy supply costs have increased by roughly 200%. And over that time, PPL Electric's average monthly residential bill has increased by about $68, with approximately $50 of that increase coming from energy supply costs alone.

The takeaway is straightforward. The single biggest driver of long-term affordability in PJM will be increasing generation supply. And with the scale of data center growth we're seeing, we absolutely need to build new reliable generation to meet that demand. The recent call by President Trump and the state governors in PJM for an emergency auction to spur construction of generation, that's a clear acknowledgment of what we've been saying for years. At PPL, we're focused on supporting the build-out of new generation in a number of ways. First, we formed a strategic partnership with Blackstone to build, own and operate new electric generating stations to directly power data centers. Second, we're actively supporting legislation that's been proposed in Pennsylvania to allow regulated utilities to enter into long-term resource adequacy agreements with independent power producers. The legislation would also permit utilities where appropriate, to build and own generation to support reliability and affordability.

At the same time, we continue to invest in a robust transmission grid capable of quickly connecting both new large load customers and generation. At PPL, our grid will not be what stalls either new generation or data center development. I'll note that even with the emergency auction envisioned by President Trump and the governors, a lot more generation will be needed. We estimate the auction, if it comes to fruition, could produce about 6 to 7 gigawatts.

This, however, wouldn't address the expected data center demand in PPL Electric service territory, let alone data center demand across all of PJM. What the auction does signal, however, is increased pressure on data centers to bring their own generation to market or at least pay for the new generation required to power their data centers. And building new generation will directly lower capacity prices in PJM by increasing supply, thus lowering customer bills over time. Bilateral arrangements to bring new generation online will continue to play a key role here as well. And our joint venture with Blackstone is perfectly positioned to enter those agreements now without needing to wait for future PJM reforms.

And that brings me to an update on the joint venture on Slide 13. We've made meaningful progress over the past year as momentum within the PJM market continues to build. Hyperscalers are increasingly seeking bring your own generation solutions and their sense of urgency is significantly higher now. We're extremely well positioned to support this need given our expertise in PJM and the significant generation fleet we operate and are building in Kentucky. Recent market developments are only increasing pressure on large load customers to secure dedicated generation solutions. And we've uniquely positioned the JV to deliver speed to market at scale, which we all know is the #1 priority for these customers. In support of this need, we have diligently executed contracts for several strategic land parcels over the past year and are securing natural gas capacity. We've also evolved our generation solutions in the past few months to meet hyperscalers' changing needs.

In addition to natural gas combined cycle units, which take about 5 years to come online, we now offer alternate generation solutions to enable new generation to come online more commensurate with the ramping requirements of data centers. While we do not have a hyperscaler agreement to announce on our call today, it is important to note that we have not embedded any earnings contributions or CapEx from the JV in our updated business plan. However, depending on the timing of executing these agreements and the generation mix selected by hyperscalers, we could see earnings contributions as early as the back end of our updated planning horizon.

Taken together, the policy signals, the market response, the engagement we're seeing from hyperscalers and other data center developers and all the legwork that we've done over the past year, our joint venture is perfectly positioned for this moment. And we look forward to providing you with more updates as contracts are finalized.

I'll now turn the call over to Joe for our financial update. Joe?

Thank you, Vince, and good morning, everyone. Let's turn to Slide 15. On a full year basis, our 2025 GAAP earnings were $1.59 per share compared to $1.20 per share in 2024. Excluding special items, our 2025 ongoing earnings were $1.81 per share, an improvement of $0.12 and in line with expectations. From an earnings quality perspective, the year-over-year growth was driven primarily by incremental returns on capital investments across our regulated businesses, supported by higher transmission revenues, rider recovery and continued cost discipline, resulting in lower O&M. Those benefits were partially offset by higher interest expense, reflecting the additional financing to support our CapEx plan. Kentucky results increased by $0.09 per share, driven by higher sales volumes, largely due to weather, higher earnings from additional CapEx and lower O&M, partially offset by interest expense.

Pennsylvania results increased by $0.04 per share, led by higher transmission revenue and distribution rider recovery, along with higher sales volumes and lower operating costs, partially offset by higher depreciation and interest expense. Rhode Island results decreased by $0.02 per share compared to 2024. This was due to higher operating costs and other factors that were not individually significant, partially offset by higher distribution revenue. When compared to our 2025 forecast, the Rhode Island segment decreased by $0.06 per share due to several true-ups and higher operating costs related to system costs, nonrecoverable storm costs and several miscellaneous costs. We do not expect those items to reoccur and therefore, do not expect these pressures to carry forward into future periods. Finally, Corporate and Other was $0.01 better than last year, driven by lower income taxes and other factors, partially offset by higher interest expense.

Turning to the ongoing segment drivers for the fourth quarter on Slide 16. Our Kentucky segment results increased by $0.02 per share compared to the fourth quarter of 2024, driven by higher sales volumes due to favorable weather and higher earnings from additional capital investments, partially offset by higher interest expense. Our Pennsylvania Regulated segment increased by $0.01 compared to the same period a year ago, primarily driven by higher transmission revenues, higher distribution rider recovery and lower operating costs, partially offset by higher interest expense and other factors.

Our Rhode Island segment results increased by $0.01 per share compared to the same period a year ago, driven by higher distribution revenue. And finally, results at Corporate and Other increased by $0.03 per share compared to the same period a year ago due to lower interest expense and lower income taxes.

Moving to Slide 17. We continue to execute a plan that has consistently delivered at least the midpoint of our 6% to 8% annual growth target since our strategic repositioning 3 years ago. Over that time period, we achieved a 7% EPS CAGR and the plan we announced today further strengthens our growth outlook. Turning to Slide 18. We are extremely confident in the growth outlined in our updated plan. As Vince noted, we've extended our 6% to 8% annual EPS growth target through 2029, and we expect to deliver a compound annual growth rate near the top end of that range over the period. And we see several upside opportunities to bolster that growth even further. These include transmission investments where we continue to see potential investment needs to further guide reliability and support growth in large load customers. While much of the material transmission upgrades to support our current data center pipeline are reflected in the plan, additional interconnections could enhance our outlook.

We also see opportunities in competitive transmission. Last year, we were awarded almost $600 million of competitive transmission projects in our PPL Electric service territory, and we believe we can be competitive more broadly in PJM and even in MISO. On the Kentucky generation side, should economic development continue to come to fruition as our pipeline would suggest, we will need to build even more generation in Kentucky to meet the increased demand, especially if it is data center demand. Depending on the type of resources needed to meet that demand, this could result in upside to our current plan or support capital spend and earnings beyond 2029.

Finally, on the Blackstone JV, as we have said, we are not assuming any earnings contribution from the partnership in our updated plan. However, depending on the timing of when we sign agreements with hyperscalers and what type of generation they desire, we could see some upside in the back end of the plan. Importantly, most of these upsides do not necessarily drive customer bills higher, but could actually lower them over time. Overall, our updated plan supports a disciplined approach to capital deployment, providing safe, reliable, affordable service for our customers and a focus on delivering strong, sustainable growth for shareowners with a number of upside opportunities.

Moving to Slide 19. We've provided a walk from our 2025 ongoing earnings results of $1.81 per share to our 2026 forecast midpoint of $1.94 per share. Across our business segments, we project this forecast midpoint to be primarily driven by improved rate recovery and higher revenues associated with ongoing capital investment programs. We expect these drivers to be partially offset by higher depreciation and higher interest expense. Taken together, these drivers underscore our continued ability to deliver steady, predictable earnings growth across our segments despite operating in a higher cost environment.

Turning to Slide 20. Our updated capital plan supports customer-focused investments of $23 billion over the next 4 years, a $3 billion increase in CapEx needs compared to our prior plan. Overall, the primary areas driving the increase relate to electric transmission and distribution investments. On the transmission side, we're projecting an increase of nearly $2 billion with nearly $1.3 billion supporting Pennsylvania's data center development and reliability projects. The remaining $700 million of that increase will support system hardening and smart grid deployment in our Kentucky service territory. We're also projecting an $800 million increase in electric distribution investments with the majority of that focused on strengthening and modernizing the grid across Pennsylvania and Kentucky. And in Rhode Island, we've adjusted some of the timing of our prior plan spend, which lowers our capital expenditures throughout this time period.

Turning to Slide 21. Our updated capital investment plan supports annual rate base growth of 10.3% from 2025 to 2029. As shown on this slide, 2/3 of our rate base relates to investments in our electric transmission and distribution networks and about 80% of our expected generation rate base increase is based on projects that have already been approved by the KPSC.

Moving to an update on PPL's financing plan on Slide 22. We continue to believe that having one of the sector's strongest balance sheets is a clear strategic advantage that provides the company with significant financial flexibility, benefiting both customers and shareholders. And our updated business plan maintains strong credit metrics throughout while supporting our updated earnings growth targets. This includes maintaining a 16% to 18% FFO to debt ratio and a holding company to total debt ratio below 25%.

We have included a new funding sources chart outlining how we plan to finance approximately $23 billion of capital investment needs. We expect roughly half of the plan to be funded through cash flow from operations, which is net of common dividends with approximately 40% financed through debt, primarily at the utilities. This results in total equity needs of about $3 billion over the 2026 to 2029 period, including about $1 billion of forward equity transactions already executed in 2025. That leaves approximately $2 billion of equity that we will opportunistically execute through 2029. We expect to continue utilizing our established ATM program and may supplement it with other equity-like financing structures where they provide an efficient cost of capital, consistent with our approach in 2025.

Moving to Slide 23. The dividend remains a key component of PPL's total return proposition. As such, our Board of Directors declared a quarterly cash dividend of $0.285 per share to be paid on April 1 to shareowners of record as of March 10. This represents a nearly 5% increase from our previously issued quarterly dividend, resulting in an annualized dividend of $1.14 per share. The increase aligns with our updated dividend growth target of 4% to 6% per year. We expect the dividend payout ratio to remain within a 50% to 60% range over the planned period. The combination of PPL's EPS growth and current dividend yield continues to provide investors with a top-tier total return proposition in the range of 10% to 12%. This concludes my prepared remarks.

I'll now turn the call back over to Vince.

Thank you, Joe. Let's move to Slide 25. In closing, I'll leave you with a few thoughts. First, 2025 was a year of delivery. We told you what we were going to do, and we did it operationally, financially and strategically. That consistency is the foundation of who we are as a company. Second, our long-term outlook has never been stronger. The updated business plan we introduced today extends our growth trajectory, strengthens the predictability of our earnings and does so with continued discipline around affordability and credit quality, keeping our customers front and center in everything we do. We're entering 2026 with a clear line of sight to the investments, cost structure and regulatory frameworks that will support sustained durable value creation. Third, the trends shaping our industry, data center growth, electrification and the need for new generation are all moving in our favor.

The momentum we highlighted today across Pennsylvania and Kentucky and through our joint venture with Blackstone reinforces the central message you've heard from us for more than 3 years. The system needs new, reliable dispatchable generation, and the market is now aligning around that reality. We are positioned exactly where we want to be as these forces accelerate and converge.

And finally, none of this happens without our people. Our teams continue to deliver for our customers with professionalism, skill and care, whether it's restoring power and natural gas during severe weather, operating one of the nation's most reliable grids or advancing the technology and partnerships that will define the next decade of energy delivery. I can't thank our electric gas and generation crews enough. They are the unsung heroes of our industry as they work in some of the worst conditions possible to ensure our customers have the energy they need to power their lives and businesses.

So we enter 2026 with confidence, confidence in our strategy, confidence in our execution and confidence in the opportunities ahead of us. And we are focused on the long game. We're aligned around the right priorities, and we're committed to delivering value for both customers and shareowners. And for our shareowners, we offer you a top-tier 10% to 12% total return proposition, a return grounded in long-term earnings growth with expectations to achieve compound annual growth near the top end of our 6% to 8% target through at least 2029. That earnings growth is supplemented with a dividend that we have paid consistently for every quarter over the past 80 years and expect to grow in the 4% to 6% range over the planning horizon.

And this growth is driven by the rate base growth being generated by the critical investments we need to make to stay ahead of mother nature, resulting in a rate base growth of over 10%. But none of this is achievable if our customers cannot afford to pay their bills. And that is what sets PPL apart from our peers. We have been and will continue to be laser-focused on minimizing bill increases or even reducing overall bills for our customers. We'll do that through our actions over those areas of the bill that we directly control and even attacking those parts of the bill that we don't. All of this creates the balance between customers and shareowners that we believe utility investors are focused on. We thank you for your continued interest and support of PPL.

And operator, let's open it up for questions.

[Operator Instructions] The first question will come from Shar Pourreza with Wells Fargo.

Just first on Pennsylvania. I mean there's lots of debates and theories with sort of the investment community around the process. Obviously, you guys don't want to front run the process, but maybe just a bit more color around how the conversations are going. Are there any kind of sticky points here? And should we read into anything given the fact that the hearings were done in a day versus the expected three days, and we just saw two black box settlements. So just maybe a little bit more color there would be great.

Sure. There's a lot there, Shar. Let's see, maybe we'll start with the rate case and then maybe more broadly about Governor Shapiro's comments. Does that work?

Perfect.

Okay. So on the rate case, you asked what are the areas of focus, if you will. Look, besides the usual suspects, I would say, generally pretty light, Shar. So a lot of discussion around the impact of data centers on customer affordability. You mentioned the hearings. It was 1 day pretty much the entire hearing was on data center load impact on customers, which, as you know, that's all connected to the transmission grid, so not really directly relevant to a distribution rate case, but that was the main focus of the hearing. So yes, I would say that was positive.

The other area is area of focus from the interveners is really the proposed changes to the net metering rules that we have for non-load generators. These are like the solar projects that are connecting to the distribution grid. In terms of settlement, as you know, no hard deadline there. I will say we are actively engaged with the parties, and we continue to be, as I speak here right now. From an overall process standpoint, I think the case continues to advance. It's going as we would expect. Briefings are scheduled in March with a final order expected in June and then rates effective July 1.

I will say, I think maybe there was some hope or expectation in the market that we would have had a settlement announcement before the hearings. I think if you look back at when those announcements generally happen in Pennsylvania, it's more around the main brief meeting or deadline, not necessarily the initial hearings that we just had. So just FYI on that. But look, we feel really good about the underlying strength of our filing and the investments that are in there that are supported, particularly around improving the reliability of the system.

As I talked about in my prepared remarks, we do have some affordability measures included in there, including memorializing what we have in our ESAs into a large low tariff. But with all that said, I would say a constructive outcome really does not hinge on a settlement in our view. We're comfortable whether this resolves through settlement or a commission decision. So we're feeling good either way.

And then more broadly, just on the Shapiro comments, look, I think the state remains incredibly constructive and supportive of its utilities. And I think they recognize the investments that are needed to not just ensure that we can continue to provide safe, reliable energy to our customers, but it's critical to help drive all this economic growth that we see coming to the state. And you may have heard Senator Yaw just recently made some comments, which we completely agree with, that the core issue around affordability and high prices is that generation has not kept pace with demand, and it's really the imbalance between supply and demand that's driving those pressures. Obviously, affordability is clearly a concern at the state level, but it's important to focus on really what's driving that. And as we said, about 50% of the energy bill or electricity bill is that energy supply cost. And those costs are up about 200% over the last 5 years, represents $50 a month increase of the total $68 a month that we've seen over that time period.

So we'll continue to engage with the governor and his team just to make sure that he recognizes the importance of having strong utilities that they're financially strong and the role that we play in driving all of this economic development. So I think those conversations continue to be constructive. I think the state overall continues to be constructive despite some of the comments that we may have heard that might suggest otherwise. And from our perspective, Shar, we just keep doing the right thing for our customers as we've been doing over the last decade or more, not because we're told to do it that way, but that's just how we operate. And so every dollar we've spent and we'll continue to spend is critical to ensure that we can deliver that safe and affordable, reliable energy. but also drive that economic growth. And there's no question in my mind, none that everything we've done is well justified.

The next question will come from Jeremy Tonet with JPMorgan.

Just want to pivot over to Genco, if I could. It sounds like contracts could be in the near term there. And so just wondering, is this something that you would wait for an earnings call to announce? Or could something be communicated earlier than that if the deal comes together?

Yes, I don't think we would necessarily need to wait for an earnings call now. I think that would be a significant event that we would do that off cycle for sure.

Got it. And for the JV, would the JV look to bid into the base residual auction or just wondering your thoughts around that.

Yes. So right now, we're still evaluating, Jeremy, whether that's something that we would participate in. In the normal auction, I don't see the JV participating in that. The special auction that we might -- that PJM might be holding for the backstop creation or incentivization of new generation, perhaps, but we really need to see the final structure if that even comes to fruition, what that's going to look like. We have to see if it fits within the risk profile that we've set up here. I've said all along that the joint venture with Blackstone, while that could be meaningful for us for sure, we are not looking to significantly modify the risk profile of the company with it, which is why we've talked about regulated like structures of the contracts, et cetera, et cetera. So it really depends on what the details of that auction might look like, and we'll have to determine if that fits the risk profile that we're looking for.

Understood. That makes sense. And one quick one, if I could. Just as regards to the nature of the generation, when you're talking about the alternative generation solutions that could come online more commensurate with the ramping requirements of data centers. If you could share a little bit more color on what that could look like.

Yes. I prefer not to talk about the actual types of technology that we're looking at. But just suffice it to say, these are technologies that we could get online more in kind of the '28, '29 time frame versus, call it, '31, '32, like what we're seeing with the larger CCGTs.

The next question will come from Steve Fleishman with Wolfe Research.

Just a follow-up to that last one. Is it fair to say that it would be mainly other gas fuel technologies? Or would you even be looking at things like , I guess, fuel cells or I guess there's gas fuel too, but fuel cells or storage?

It could be all of those, Steve.

Okay. And maybe switching gears back to your data center backlog. Could you just give some color on all this 10 gigawatts that's supposed to come on by the end of the decade or might even be more than that or the ones that are highly likely, like what were these customers thinking they were going to get their generation from? Just like but it off PJM market? Or -- I mean, obviously, you have Susquehanna 1, but just -- I mean -- and I guess the second part of that is, are they -- what is the risk that they switch gears from the region if this doesn't get resolved soon? Or are they pretty committed to come either way?

Yes, sure. So look, as we've talked about in the past, I think the key for the hyperscalers has been speed to getting connected to the grid. And that has been something that we have been able to deliver consistently since we've been talking about this. So to your point, I'm not sure they were that focused or concerned about where the actual generation was coming. We're in an RTO, we're in the PJM ISO. The market takes care of that. They didn't really have to worry about it. They have energy procurement parts of their business that procure the energy if they want to do that on a forward basis or as part of polar loads or just shopping, et cetera. So I think they were just thinking through the normal process there.

Obviously, the heat has been turned up on just resource adequacy in PJM, the amount of load that is connecting here versus the lack of generation. Obviously, all of that's moving in our favor. So they're to the table, which is kind of where we thought they would be when it was apparent that they were going to have to worry about this, I would say, more pointedly than they had in the past. So the good news is they are. They're extremely focused on it. Our engagement with them is incredibly constructive. Their sense of urgency is much higher than it was probably because of some of the political pressure now that's being put on them and the industry overall. But yes, I think they were just planning on getting it from the market. What was the second part of your question, sorry?

Yes. So yes, I mean, look, we're up another 23% this quarter versus last. I will tell you the interest is continuing to be there. So we're not seeing people pulling out as a result of the gen issue. We just see them engaging in a very different way to help solve it. I would even say, I think Pennsylvania itself, Steve, is starting to look better and better to the hyperscalers. They took notice during this latest cold spell that our transmission network performed flawlessly through that event. And Pennsylvania was the one that was generating and exporting the vast majority of the energy, including down to Virginia, which is where, obviously, current data center alley is. So what we've heard directly from some of the hyperscalers is they're actually very impressed with the reliability, both on a gen and transmission side in PA. So if anything, I would say they're coming -- they're getting more comfortable staying here versus thinking about leaving.

The next question will come from Mike Lonegan with Barclays.

So you highlighted incremental upside to your EPS forecast. You talked about competitive transmission projects, additional T&D in Pennsylvania and Kentucky, more generation in Kentucky and Blackstone JV. I was just wondering if you could talk about the potential size of the investment opportunity here, what it could maybe increase your EPS CAGR to? And what portion of the investment would be financed with equity?

Yes. Thanks, Mike. It's Joe. Well, good job in recapping all of the drivers there. So look, I'm not going to quantify that today from either an EPS or a capital perspective. The intent there really was to show you what gives us confidence in our plan, right, delivering the plan that we laid out today and then where we see the upside potential coming from. So look, I mean, we think we have -- we believe that all of these areas can certainly come through for us, to some extent, ultimately, the size and timing of that will depend on a number of factors, but they are all areas that we're active and successful in to date, and we think that they continue to provide more benefit as we go forward.

As far as your funding question, look, all of that is dependent on what type of capital is, how we get recovery of that rate cases and other things. I would say though, if we added $3 billion of capital to the plan, and we increased the equity amount by $1 billion, I guess, generally speaking, that's a decent rule of thumb, but there are other factors that could influence that amount.

Yes, Mike, I would just add to that, that those upside opportunities for both CapEx and EPS are not the type that necessarily will drive rates up for our customers, which is incredibly important. So obviously, the Blackstone JV, building new generation increases supply, that should put pressure -- downward pressure on wholesale energy costs that flow back to the customers. On the transmission side, right, we've talked about every gigawatt that we connect on the transmission side, that continues to lower the bills for everybody else just because we're spreading fixed costs over more customers and those large loads end up taking a big piece of that fixed cost. So that's good for our customers. So many of those areas are actually while there are upsides to the earnings, they're not pressuring the bill, which is -- in some cases, they could actually lower the bill. So really, really pleased with the makeup of those upsides.

Great. And then secondly for me, for the Blackstone JV, I know in the past, you talked about having the secured turbines still. So just wondering if you could provide an update on where you stand in sourcing the supply chain and I know you said you secured land parcels. I was just wondering if you could talk about more strategic advantages your JV has that you would highlight?

Yes, sure. So I mean I'm not going to talk about the size of where the land parcels are obviously, for competitive reasons. But I will say that they are in Pennsylvania, and they can support multiple gigawatts of generation. And obviously, we strategically locate those where transmission and natural gas can easily be interconnected. So making really good progress there. On the JV side, Sorry, what was the second part of your question, Mike?

Procuring turbines, I was just wondering if you could...

Yes, on the turbines. Yes. So a lot's happening on the turbine front, as you probably know, GE was certainly early on with their commitment to build new capacity for turbines. We're seeing the same now with Siemens and Mitsubishi. So while we have not formally locked in any reservation agreements with either of the three parties, we are very actively engaged with all three and actually feel pretty good about our ability to get turbines from either or all of those to meet the needs of the data centers. The bigger issue, right, is providing generation sooner for them that can kind of match the load forecast and the ramping schedule that they have, and we wouldn't be using the combined cycles for those and that -- those are those other types of technologies and supply chains look good for those and again, but we should be able to get some of that in -- call it, late '28, '29 time frame. So we're focused on that as well for the near term, but we feel good about our ability to get the turbines that we need for that 2031, '32 time frame for the big CCGTs.

The next question will come from David Arcaro with Morgan Stanley.

I was wondering if you could might be able to elaborate a little bit on the EPS growth trajectory, it looks like growing 7-ish percent into 2026 and then looks like it accelerates beyond that point. Wondering if you could just kind of frame out, does it go above the top end of the annual kind of growth rate at some point looking out through the forecast? And how does that shaping look?

Yes, Dave, it's Joe. Yes, you're right. It does increase, as we said, starting in 2027. It's not a back-end loaded plan. I would say growth between '27 and 2029 is generally speaking, pretty linear. So I think you can think of it in that regard.

Okay. Got it. And then maybe on O&M. You've had a very successful O&M cutting program here. And I guess as you look out to the another 1% kind of inflationary rate, I'm wondering if you could just talk to levers to manage that and look for more cost-cutting opportunities going forward within the plan.

Yes. There's certainly more opportunities in the plan that we'll look to as we deploy capital across the networks, continued deployment of smart grid technology can drive costs lower. We've seen that already. I think there's more to do there. System -- IT system upgrades can certainly provide a benefit to us. And then we're looking at deployment of AI across O&M savings besides beyond what we're seeing. Some of those we have in the plan and get us to that 1%. But certainly, others will look to improve upon that once we deploy the various forms of technology.

The next question will come from Paul Zimbardo with Jefferies.

It's Julien on for Paul here. Can you comment a little bit how material could this JV be right, by the end of the decade, right? I just want to make sure we're zeroing in that we're not either exaggerating it or at the same time, understanding the total opportunity here. Again, it seems like you have multiple sites potentially working with hyperscalers, which would imply a certain size and scale. But I want to ask you directly, how material could this be in by when? And how many innings are you into this contracting effort? Because obviously, that can take some time at times.

Yes. I mean we're -- I would say we're many innings in. Obviously, we've been working the JV for about a year now, Julien. So a lot of work has gone into making sure that we can provide those solutions, whether it's land, natural gas supply, working with gas suppliers on extension leads, all of that. At the same time, we're working with the hyperscalers and data center developers as well. It's not just the hyperscalers. We are seeing data center developers also very interested in bringing BYOG solutions to their hyperscaler clients as well. So pretty far along. Again, we haven't given a date or a timing on our expectation of signing an ESA just because of the complexity and the time it takes, primarily to get, I would say, to the hyperscaler approval process, right? These are very large organizations that it just takes time, and they're complicated. So we certainly understand that.

In terms of how big it can be, it's a bit early for that, I would say. Obviously, our focus right now is getting these first deals over the goal line. But as I've said before -- and look, I think the joint venture can be meaningful for us for sure. That's why we're spending so much time and attention on it. But as I've said before and from the beginning, we aren't really looking to change the overall risk profile of the company with the joint venture. So that's why you heard us talk about things like regulated like contracts and things like that.

So you asked through the end of the decade. So through 2030, clearly, I think we're -- given now that we are providing solutions that would have a generation ramp more commensurate with the load profile of the data centers, I think we absolutely can see some earnings from the JV, maybe even the back end of this plan, which is 2029, certainly kicking into 2030. More materially, though, I think you'll see it when those combined cycles start to come online, which is in the early 2030s. But I do think you'll continue -- you'll see from us ultimately some earnings contribution in the back end of this decade, more meaningful into next.

Awesome. Excellent. And maybe if I can come back on the load forecast real quickly, nitpicking a couple of things. On Pennsylvania, it seems like it came down on '27 slightly even while you ramped up materially the longer dated. Can you comment on what you're seeing near term versus longer dated? And then separately, also in Kentucky, you comment here about updated projections of 2.8 gigawatts of load by 2032. Is that fully in the plan? Because I think the plan is this 1.8 gigawatts. Can you comment a little bit about what's in your updated plan here in Kentucky and then also the dynamics in PA?

Yes, sure. So PA is really just -- right, the data center developers and the hyperscaler taking longer to get their projects built and completed. So the projects are still all there. They're just getting pushed out a little bit. So we kind of suspected that, that would happen. Again, a lot of the early discussions in the ESAs that we're signing with folks were to, again to get that capacity signed up. That's the competitive advantage for them. In some cases, I think, right, the time frame that they had given us was probably quicker than they physically were able to build out the capabilities, but overall, the projects are still there. So nothing really of concern in PA.

And then in Kentucky, yes, so the 2.8 gigawatts is 2.8 gigawatts as well last quarter, Julien You may recall, this quarter's 2.8 gigawatts is not the same as last quarter's 2.8 gigawatts, normal business development, I would say, stuff happening in Kentucky as well. We have a lot more projects in this 2.8 gigawatts than the prior 2.8 gigawatts. We actually have close to 2.5 more gigawatts in this 2.8 gigawatts. It's just on a probability weighted basis, the two happen to both the 2.8 gigawatts. So the good news is we're getting more projects, more gigawatts in the queue. We're just early in some of those additions, which is why the overall position hasn't changed much.

But to your point, what we have in the plan is basically the generation that's currently underway, the solar, the battery and the combined cycle plants as well as the environmental remediation on the gen plant So that's all in the plan. We did push out the battery, the 400-megawatt battery that we had in the original CPCN that got deferred, that is still in the plan, Julien, we just pushed it out from 2028 to 2030. So there is some capital spending through 2029 time period for an in-service in 2030 but that all supports just 1.8 gigawatts. So if the 2.8 gigawatts were to happen and there are some large projects in the 2.8 gigawatts that might only be in there at 50% probability. If some of those hit, we could blow through that 1.8 gigawatts very quickly. So that's why we indicated we could potentially have a CPCN filing as early as this year to either go back in for the 400-megawatt battery or potentially even more than that.

But most likely what we would like to see is very similar to the conversation we had on the Blackstone JV and trying to get smaller generation amounts online quicker. I think that's where you would see this type of a CPCN is trying to keep up with the ramp rates as opposed to the big project in 2032 at this point. So that's why we're saying we could do that as early as '26 with all of these things kind of moving in the direction of more versus less.

So it looks like '26, we'll see what you guys ultimately file for in Kentucky batteries or otherwise.

The next question will come from Angie Storozynski with Seaport.

So in your prepared remarks, you talked about potential contracting with generation assets of ITPs in Pennsylvania, at least that what it sounded like to me. And I'm wondering if you're referring to existing assets or to new build? And what type of earnings benefit, if any, that would present for your Pennsylvania utility?

Sure. So this is all in the context of resource adequacy, Angie, and trying to get new generation built in Pennsylvania. So within the legislation that's been proposed, there's really two main components. There's this LTRAA which are really long-term resource adequacy contracts that would be a contract between the utility and an IPP to build new generation. Again, it's not for existing generation. This is to promote building -- getting new plants built. So it would be for new generation and then the second piece, obviously, is the ability for utilities to own generation as a backstop or as directed by the commission for whatever reason. So yes, so that's the LTRAA component of the legislation.

And if you were to pursue one of those, do you think that this capacity would be for example, deducted against the capacity efficiency that would be procured in the backstop PJM capacity auction? I'm just trying to figure out how that gets embedded in the PJM planning and those future capacity procurements.

Yes. So generally, I think the way we're thinking about it right now that, of course, that legislation is proposed and hopefully, in the springtime, we'll start to see some debate on those bills in the chambers, but we're still early innings, as you know, on that legislation. But the thinking now is that both the load and the generation would both be in the PJM auctions. So as you know, a lot of the load is already in the PJM forecast. So any new generation coming on would just increase the supply part of the equation to basically help supply all of the load that we have in there.

But as we kind of think about this going forward, I think the intention and again, the pressure that we're seeing at the federal and state level is that when a hyperscaler or a data center developer brings a gigawatt or 2 gigawatts of loads, they're also bringing the plan that they have to bring the commensurate amount of generation to offset that. And I think the way you need to kind of really think about that is in the calculation that PJM actually performs, which, right, they discount the load significantly less than how they discount generation. So on a pure megawatt per megawatt basis, you actually need more generation than the load for that to balance out in the PJM auction process. And I think you know those details. But -- so those are the conversations that we're having with kind of BYOG solutions.

Okay. And then changing topics. The results in Rhode Island, Joe mentioned the -- about a $0.06 drag on 2025 earnings in Rhode Island versus what you had expected or budgeted and I understand it's a onetime issue. But it's a onetime issue because of the rate case that you just filed, meaning that some of those earnings efficiencies get remediated in this rate case? Or is it that those were just truly a onetime in nature, earnings impacts that will not repeat themselves regardless of the outcome of this pending rate case?

Yes. It's a little bit of both, Angie. There's certainly some that get remediated as part of the rate case and then there were some true-ups like I mentioned on the transmission revenue true-up that was truly onetime in nature. But yes, so that's really why we don't think that these will continue. And we generally -- we see positive earnings performance from here after we get through these true-ups and onetime items.

The next question will come from Anthony Crowdell with Mizuho.

Appreciate you guys squeezing me in here. I'll try not to clear my throat like everyone else. I guess, first, on the settlement discussions in Pennsylvania, it appears from Governor Shapiro's remarks, there's more of a -- affordability is always important, but it seems like there's more of a consumer focus in this state. Have you noticed parties may be a more rigid or less flexible? Any discussions than previously? And I have another follow-up.

No, I would say nothing out of the ordinary in terms of settlement discussions with the parties. I mean there are various views, of course, with the different intervenors, and that's always the challenge in coming up with settlements, but that's normal. So no, I wouldn't say I'm seeing anything different as a result of our governor's comments.

Got it. And then Steve, I had a question when he asked about where did the hyperscalers think the power was coming from. And if I understand correctly, you said they believe just they would connect to the grid. My question is when you have the discussions today with the political backdrop that's going on the political overhang or whatever. When you have discussions today with these hyperscalers, are they -- is there a clear preference for new generation that would benefit the partnership? Or are they just like whatever I could sign I'll take, whether it's existing or new?

No, there's a clear difference for new generation because that's what the White House is calling for. That's what our state governors are calling for PJM, NERC, FERC, everyone is saying, if you're going to bring a gigawatt or 2 of load, you need to bring new generation to supply that load. So there -- I mean, look, will they still try to procure power from, say, the nuclear fleet for their clean energy goals and all of that? Perhaps you'll continue to see that happen. But there is there's just a lot of pressure right now to build new. And that's what we're seeing.

Now in particular, with the joint venture, those are the conversations that we're having because that's the offering that we're providing. So we're not providing -- connecting to existing generation, Anthony. So clearly, that's the conversations we're having, whether they're having conversations on existing assets, I can't necessarily comment on, but the conversations clearly are more urgent more significant, they understand the issue and they seem very committed to helping to resolve it.

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

Yes. Thanks for joining us today, everybody. Again, just a real quick summary the business plan, the business itself. I don't -- I think it's stronger than it's ever been. We're excited about moving into 2026 and delivering this. Blackstone JV, tremendous opportunity there, everything moving in the right direction. So I look forward to seeing you all on the circuit in the next month or so. So thanks for joining us.

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

Good day, and welcome to the PPL Corporation Third 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 of Investor Relations. Please go ahead.

Good morning, everyone, and thank you for joining the PPL Corporation conference call on third 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. For reconciliations to the comparable GAAP measures, please refer to the appendix. I'll now turn the call over to Vince.

Thanks, Andy, and good morning, everyone. Welcome to our third quarter investor update. Let's begin with highlights from our third quarter financial performance on Slide 4. Today, we reported third quarter GAAP earnings of $0.43 per share. Adjusting for special items, third quarter earnings from ongoing operations were $0.48 per share. Building on this strong performance, we've narrowed our 2025 ongoing earnings forecast range to $1.78 to $1.84 per share, maintaining our midpoint of $1.81 per share.

We remain confident in our ability to achieve at least this midpoint, supported by our continued operational discipline and strategic execution. Throughout the quarter, we continued to advance our utility of the future strategy, delivering meaningful progress across our operations. We're on track to complete approximately $4.3 billion in infrastructure improvements this year, critical investments that support reliable, resilient, affordable and cleaner energy networks for our customers now and in the future.

Our continued focus on innovation and technology has us on pace to achieve our annual O&M savings target of at least $150 million compared to our 2021 baseline. Looking ahead, we continue to project $20 billion in infrastructure investments from 2025 through 2028, driving average annual rate base growth of 9.8%. We also remain well positioned to deliver 6% to 8% annual EPS and dividend growth through at least 2028, with EPS growth expected to be in the top half of that range.

Importantly, we expect to maintain our strong credit profile with an FFO to debt ratio of 16% to 18% and a holding company to total debt ratio below 25%. As is customary, we'll provide an updated business plan on our year-end call, including our formal 2026 earnings forecast and roll forward of our longer-term outlook. Turning to some regulatory updates beginning on Slide 5. In Kentucky, LG&E and KU have reached a proposed settlement agreement with the majority of the intervenors in their base rate case proceedings.

The agreement filed with the commission on October 20 includes a revised aggregate increase of approximately $235 million in annual revenues and an authorized ROE of 9.9%. The agreement also features a base rate stay-out provision through August 1, 2028, providing stability for our customers and our business. In connection with this stay out, the settlement introduces 2 new rate mechanisms designed to balance customer affordability with the need for continued investment in Kentucky's energy infrastructure.

The first, a generation cost recovery adjustment clause or a GCR will provide recovery of and a return on investments associated with new generation and energy storage assets already approved by the commission but not yet in service. This would include the Mill Creek Unit 5 NGCC, the Marion and Mercer County solar generating facilities and the E.W. Brown Energy Storage facility approved in our 2022 CPCN as well as the recently approved E.W. Brown Unit 12 NGCC from our 2025 CPCN proceeding.

The GCR does not cover Mill Creek Unit 6 as that unit's recovery was considered separately in our CPCN stipulation with intervenors. I'll cover the commission's CPCN order in a few moments. The second rate mechanism agreed to in our rate case stipulation is a sharing mechanism adjustment clause. This mechanism would help to mitigate regulatory lag while protecting customers from potential overearning during the final 13 months of the stay-out period, ensuring an ROE of no less than 9.4% and no more than 10.15%.

The stipulation also includes support of a new tariff designed for customers with large demands and very high load factors such as data centers. The tariff helps to attract these customers and continues to drive economic growth in our service territories while ensuring adequate safeguards are in place for all customers. While the stipulation agreement remains subject to commission approval, we believe it represents a balanced result and again, underscores the collaborative approach we take with key stakeholders in Kentucky to achieve fair and constructive outcomes.

New rates are expected to take effect no earlier than January 1, 2026. Official hearings began earlier this week, and we anticipate a decision from the KPSC by the end of the year. Turning to Slide 6 for a few additional regulatory updates. I'm also pleased to report that LG&E and KU received approval in a KPSC order for much of the company's July 2025 CPCN stipulation agreement. This decision marks a significant milestone in our long-term generation investment strategy, and it again reflects our ability to work collaboratively with stakeholders to deliver reliable, cost-effective energy solutions.

With this approval, LG&E and KU will construct 2 new 645-megawatt natural gas combined cycle units, around 12 and Mill Creek 6. These units will be similar to the Mill Creek 5 combined cycle unit currently under construction. In addition, LG&E, KU will install an SCR to mitigate NOx emissions at Unit 2 of the generating station. These investments will ensure we continue to meet Kentucky's growing energy needs, driven by record-breaking economic development and data center expansion, all while maintaining reliability and affordability for our customers.

The approval also supports requests regarding regulatory asset treatment for AFUDC and recovery of the Ghent 2 SCR costs through the existing environmental cost recovery mechanism. The KPSC decided not to approve 2 proposed cost recovery mechanisms for the recovery of Mill Creek 6 and the recovery of costs associated with keeping Mill Creek 2 open beyond its original retirement date in 2027.

However, the KPSC encouraged LG&E and KU to provide additional evidence on such matters in separate proceedings, including the open rate case proceedings. We have decided to address the recovery of the Mill Creek 2 stay open costs in the pending rate case proceedings, and we'll address the Mill Creek 6 recovery in a future proceeding since that unit is not expected to come online until 2031. We appreciate the commission's constructive feedback and remain confident in our ability to present compelling evidence in upcoming proceedings.

Our team is committed to securing cost recovery that supports continued investment in reliable energy infrastructure to meet the growing needs in the Commonwealth. In other updates, on September 30, PPL Electric Utilities filed a request with the Pennsylvania Public Utility Commission to increase annual base distribution revenues, which would represent its first distribution base rate change in more than a decade.

The requested increase supports our need to build and maintain a stronger, smarter and more resilient electric grid to better withstand increasingly severe weather, prevent outages and improve service to our customers. Over the past 10 years, we've been successful in avoiding base rate increases while creating one of the nation's most sophisticated and efficient grids. In fact, PPL Electric's operating and maintenance expenses have increased by only 7.4% nominally since 2015 compared to 32% inflation over that same period.

We are requesting a net revenue increase of just over $300 million or 8.6% as more than $50 million of the base rate request includes revenue that is already reflected in customer bills through riders like the DSIC. Also as part of this base rate case, the amount of rate base included in the DSIC mechanism will reset to 0 and the cap on the DSIC revenue would also reset back to 5% of base distribution revenues. Our rate case application is supported by a fully forecasted test year that begins July 1, 2026, and a requested ROE of 11.3%.

We anticipate a decision from the PUC on our case in the second quarter of next year with new rates effective on July 1, 2026. And finally, in our last regulatory update, we continue to expect Rhode Island Energy to file a distribution base rate request before the end of this year. Now let's turn to Slide 7 and our data center updates in Pennsylvania. There's a lot to unpack in this quarter's update, as shown on this slide. First, momentum continues to build in PPL Electric Utilities service territory in terms of interconnection requests to our transmission network.

Since our last update, the number of data center projects in advanced stages of planning, those projects that have either a signed electric service agreement or an ESA or a signed letter of agreement, LOA, have jumped more than 40% from 14.4 gigawatts to 20.5 gigawatts. This marks yet another increase in our PA data center pipeline since we initially announced about 3 gigawatts in advanced stages in the first quarter of 2024. Both of these agreements require significant financial support from the counterparties.

LOAs carry significant financial burden for counterparties as they agree to pay for all the engineering and long lead time materials, which could easily run into the tens of millions of dollars. The ESAs include all the commitments in the LOAs plus customer commitments around additional credit support and require the counterparty to pay a minimum load requirement based on 80% of their load forecast. Over 11 gigawatts of the 20.5 gigawatts under signed agreements have been publicly announced, including about 5 gigawatts that have already begun construction.

So overall, we're very confident that at least 20.5 gigawatts of demand is real, especially given we have an additional 70 gigawatts of demand in the queue. I know there's a lot of discussion in the market about the quality of utility load forecasts related to these large loads. And I have a few thoughts on this issue as well. First, we know that load forecasting is a critical component of system planning, and it's also a fundamental part of the PJM capacity auction process.

So we are very supportive of efforts to ensure that load forecasts are reasonable and generally prepared in a consistent manner. We are actively engaged with PJM and the other PJM utilities to review and potentially improve the load forecasting process given the amount and pace of interconnection requests. I will also point out that PJM discounts the load forecast it receives from the utilities by as much as 30%. So the load forecast that the utilities provide PJM are not the final forecast used in the capacity auctions.

And while reviewing this process is an important step, I want to be clear that these load additions are real, they are coming fast and furious and focusing on load forecast alone does not obviate the need to start building new generation now. Forecasts will continue to be refined as they always are, but the near-term risk of overbuilding generation simply does not exist. The bottom line is that we need to start building new generation as soon as possible.

And as you know, that is exactly why we continue to support state solutions like long-term contracting for generation and a utility ownership backstop, while we are also active in PJM's large load customer collaboration and market reforms. We support the continued focus by Governor Shapiro to mitigate supply price increases for our customers and encourage new generation development in the state. A recent proposal to incentivize large loads to bring their own generation and bifurcate the capacity auctions between existing generation and new build are things that we think could have merit.

We'll be involved in helping to shape details to advance workable proposals that protect reliability, accelerate economic development and support affordable electricity for our customers. That also includes leveraging our joint venture with Blackstone Infrastructure, which is prepared to build new generation to directly support data center demand under long-term energy supply agreements. At the end of the day, our strategy and the solutions we've proposed are geared towards ensuring reliability, affordability and resilience as we navigate this unprecedented wave of demand growth.

And finally, we've updated our CapEx estimates related to the 20.5 gigawatts to be at least $1 billion or an incremental $600 million to what is in our current capital plan. Given the number of projects we have in their locations, we are seeing that some of the upgrades required for these data center projects were already included in our transmission capital plan. So the prior sensitivity of 1 gigawatt representing $50 million to $150 million of capital additions no longer holds true.

But we will continue to define the potential upside with each quarterly update. And of course, we'll provide full details on the business plan refresh during our year-end call. Turning to Kentucky Economic Development on Slide 8. The economic development pipeline continues to grow, fueled in large part by access to the reliable, affordable electricity that LG&E and KU provide and most recently with the CPCN approval to build new generation resources. The economic development pipeline now totals just under 10 gigawatts of electricity demand.

This includes data center requests totaling about 8.7 gigawatts, an increase of 3 gigawatts from our second quarter update. About 4 gigawatts of these data center requests are considered highly active with another 500 megawatts that are under construction. While we saw a decrease in our non-data center demand due to a few large projects that were canceled or were reclassified into the data center category, the number of project requests continues to be robust and has increased quarter-over-quarter.

With these updates, our refreshed probability weighted demand growth projections now total about 2.8 gigawatts, a 300-megawatt increase from our Q2 estimate. If this potential growth continues to materialize, additional generation resources will be required. As a result, we continue to monitor the progress of these projects very closely as our recent CPCN only included about 1.8 gigawatts of new demand growth.

Our success in supporting this growth was once again recognized in September when LG&E and KU were named a Top Utility in Economic Development by Site Selection magazine, the 12th time they earned this distinction since 2012. Turning to Slide 9. Let's talk about affordability, one of our core commitments here at PPL. We know that affordability matters to our customers, and we're focused on keeping bills as low as possible while continuing to invest in reliability, resiliency and economic growth.

Success begins with a culture of continuous improvement and innovation across our organization. Through disciplined cost management and smart investments, we have delivered on initiatives that keep us on track to reduce O&M costs by an average of 2.5% per year from 2021 through 2026. These savings come from deploying smart grid technologies on our transmission and distribution networks, optimizing planned generation outages and centralizing shared service functions to improve efficiency.

We're also incorporating new technologies across PPL, including the use of artificial intelligence in all aspects of our business, from predictive maintenance to customer service to back-office functions to deliver better results for our customers at lower costs. We expect these technologies will enable us to achieve the next wave of future cost efficiencies. At the same time, we're supporting robust data center growth while protecting our other customers and ensuring rates remain fair.

In Pennsylvania, connecting data centers to our grid lowers the transmission portion of the customer bill for the existing customer base as these large load customers will pay a larger portion of the fixed transmission costs. In addition, our electric service agreements in Pennsylvania require data center customers to pay a minimum amount, generally 80% of their requested load forecast even if they use less electricity until the costs incurred to extend service are fully recovered. And we've proposed a new tariff in our rate case to memorialize these terms within our tariff structure.

In Kentucky, as I mentioned earlier, we've also proposed a new tariff for large load customers requiring them to make a 15-year commitment to pay for at least 80% of the forecasted demand for the entire term. These measures ensure that large load customers pay their fair share and that our existing customers in Pennsylvania and Kentucky do not end up subsidizing the large load customers. We're also finding other creative ways to save customers' money.

In Rhode Island, we've agreed to credit customers a total of nearly $155 million in January, February and March of 2026 and 2027 when winter bills tend to be the highest. This arrangement is net present value neutral for PPL but provides our customers with some much needed near-term bill support with the average electricity customer receiving $20 to $25 a month and the average gas customer receiving $40 to $45 a month.

These credits were approved by the Rhode Island Division of Public Utilities and Carriers or the division, to satisfy a deferred tax hold-harmless commitment tied to our acquisition of Rhode Island Energy. The division is a separate organization from the Rhode Island Public Utility Commission, and it was the division that approved our acquisition of Rhode Island Energy, and it was the division that we made the hold-harmless commitment to.

The settlement is currently in front of the Rhode Island Public Utility Commission for final implementation approval. While we cannot predict the outcome of that proceeding, given our collaborative approach in the division's prior approval, we are optimistic about a positive outcome and look forward to delivering meaningful bill credits to our Rhode Island customers.

And in Pennsylvania, we're supporting legislation that would incentivize new generation build in the state, helping to address resource adequacy needs and lower wholesale capacity prices. Our joint venture with Blackstone Infrastructure is another prime example as it intends to build new generation to serve data center load, mitigating rising prices for customers and delivering value for shareholders. Affordability isn't just a talking point. It's embedded in everything we do.

By combining innovation, disciplined cost control and strategic partnerships, we're ensuring that customers benefit from a reliable, resilient and affordable energy future. As you have heard countless times from us, every dollar of O&M savings achieved can be reinvested as about $8 of capital without impacting customer bills. That's the power of disciplined cost management and operating efficiency, creating room for critical investments while keeping affordability front and center. That concludes my business 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 11. PPL's third quarter GAAP earnings were $0.43 per share compared to $0.29 per share in Q3 2024. We recorded special items of $0.05 per share during the third quarter of 2025, primarily due to IT transformation costs and certain costs related to the integration of Rhode Island Energy. Adjusting for these special items, third quarter earnings from ongoing operations were $0.48 per share, a $0.06 per share increase compared to Q3 2024.

The increase was primarily due to several favorable factors, including higher revenues from formula rates and rider recovery mechanisms as well as lower operating costs, which were partially offset by higher interest expense. As Vince mentioned in his remarks, with the strong quarterly results, we've narrowed our 2025 ongoing earnings forecast range and remain confident in achieving at least the midpoint of $1.81 per share. During the third quarter, we took the opportunity to derisk a sizable portion of our equity financing needs as we fund our substantial growth.

In August, we entered into forward contracts to sell approximately $1 billion of equity. We completed these transactions under the ATM, which minimized fees and enabled efficient execution. This brings the total amount of equity executed under the forward agreements to approximately $1.4 billion of the $2.5 billion forecasted equity needs through 2028. Approximately $400 million will settle at the end of this year, with another $500 million to settle at the end of 2026 and the remaining $500 million settling in mid-2027.

Turning to the ongoing segment drivers for the third quarter on Slide 12. Our Kentucky segment results increased by $0.02 per share compared to the third quarter of 2024. This increase was driven by higher sales volumes, largely due to favorable weather in Q3 2025, lower operating costs and higher earnings from additional capital investments, partially offset by higher interest expense. Our Pennsylvania regulated segment results also increased by $0.02 per share compared to the same period a year ago.

The increase was primarily driven by higher transmission revenue from additional capital investments and higher distribution rider recovery, partially offset by higher interest expense. Our Rhode Island segment results increased by $0.01 per share compared to the same period a year ago. Primary driver of this increase was lower operating costs. Finally, results at Corporate and Other increased by $0.01 per share compared to the prior period due to several factors that were not individually significant.

We are pleased with our performance through 3 quarters of the year and remain well positioned to deliver on our commitments to shareowners in 2025 and beyond. Our focus on providing real value to our customers underpins our robust business plan and our confidence in our long-term financial targets. And we continue to make excellent progress on derisking that plan through constructive regulatory outcomes and financial discipline while driving initiatives that can support future growth. This concludes my prepared remarks. I'll now turn the call back over to Vince.

Thank you, Joe. In closing, PPL is delivering strong results today, and we're building a strong foundation for tomorrow. We've narrowed our earnings guidance. We remain confident in achieving at least the midpoint of that guidance, supported by disciplined execution and a clear vision. We're advancing our utility of the future strategy, investing in infrastructure, deploying technology and driving innovation, all while maintaining affordability for our customers.

PPL's disciplined execution and strategic investments, coupled with our focus on innovation, data center expansion and operational efficiency sets us apart in the utility sector, and that focus creates value for both our customers and our shareholders alike. Thank you for your continued confidence in PPL and our team. And with that, operator, let's open it up for questions.

[Operator Instructions]

Operator, while you're compiling the roster, I just want to take a moment to acknowledge the UPS plane crash that occurred yesterday in Louisville. Our hearts go out to the families of those who lost their lives and those who have been injured. Fortunately, our employees are all accounted for and safe. Yesterday, we supported the emergency responders. We ended up de-energizing transmission lines that were going into a nearby substation, and we ended up cutting off some nearby gas lines to ensure the safety of those first responders.

The impact to our customers was minimal, but we are working to get everyone back online, but to do so as safely as we can. We also had team members embedded in the Louisville operator center to assist as needed, and we remain committed to supporting the community and first responders any way that we can. It is certainly a sad day for our entire Louisville community.

Operator, who has our first question?

Our first question comes from Shar Pourreza with Wells Fargo.

Vince, just on the Kentucky CPCN case that obviously mentioned the tracking mechanism for Mill Creek 2 stay open cost and Mill Creek 6 were rejected. You highlighted denied without prejudice. I guess what information was missing for them to decide. Why the denial and any sort of near-term EPS impact there we should be thinking about?

Sure, Shar. So not concerned from an earnings perspective per se. I'll kind of take Mill Creek 2 separate from Mill Creek. So for Mill Creek 6, the commission did approve AFUDC treatment. So that project will be in construction through 2031 when it goes into service. So really no earnings impact there. The new mechanism would not have gone into effect until the in-service date. So we have plenty of time to address Mill Creek 6. And as you said, they were -- those mechanisms were designed without prejudice.

So not only do we have the ability to refile for those, but the commission actually encouraged us to refile those mechanisms in either a future proceeding or even the current open proceeding for the rate cases to which we are dealing with this week in hearings. For Mill Creek 2, we want to get that one addressed sooner, obviously, because we are actively spending money a little bit this year but going forward to enable us to continue to operate that plant beyond 2027.

And we really need to get recovery of any of those costs before we would agree to continue to operate that plant beyond 2027. We would be incurring about $30 million of additional O&M, about $40 million of additional CapEx from now until 2030 in addition to what was filed in the base rate case request for Mill Creek 2. So we would want to see recovery of that. And so we updated the testimony last Friday to address Mill Creek 2, and that's part of the hearings this week.

So as I said, Mill Creek 2, we're addressing that now. Mill Creek 6, we'll deal with that in a future proceeding. You asked what was missing. I'm not sure that a whole lot was missing necessarily, although I think it's safe to assume that the commission felt it was -- that the CPCN proceeding was not the proper arena to deal with rate mechanisms, and they would rather deal with that in a rate proceeding.

Got it. Okay. No, that's perfect. And then just on the resource adequacy topic in Pennsylvania specifically, there's obviously 2 bills sitting at the House and Senate. I think they'll reconvene in November. I guess thoughts there, Vince. And more importantly, can sort of the wires companies strike a middle ground with the IPPs maybe around a long-term resource adequacy agreement structure that's also being proposed in the legislation versus this kind of push-pull around rate basing generation. So I guess how are discussions going. And can you guys strike a deal there?

Yes, sure. So maybe just broadly what's happening with the legislation, right? So I think we need to see a couple of things before you'll really see movement on this proposed legislation, but really any meaningful movement of legislation. And the first is just the state budget. Obviously, the budget impasse is negatively impacting broader discussions around legislation. I would throw REGI into the mix as well. That seems to be a gating issue for energy policy discussions.

Both of those, I think, could be resolved by the end of the year, probably more imminent for the budget, REGI maybe before the end of the year. So that's kind of, I would say, the background on not a whole lot of movement with those 2 bills that you had referenced. But clearly, there's a lot of legislative support in the state to find ways to spur new generation particularly in light of the data center load that we're seeing and just the 2 cost increases that we saw in the last 2 capacity auctions.

Of course, our governor has been extremely engaged with PJM on this. So it's great to see that there is focus on the issue. I would expect the next steps we would see really, Shar, I would say, more so in the beginning of the year would be the debating of the issues -- sorry, of the legislation in the respective committees. And of course, they are still debating, I would say, within the legislature whether or not to permit regulated generation to be part of the solution.

In terms of discussions with the IPPs are coming up with some middle ground with the IPPs, look, we said all along that the goal here is to incentivize new generation and ultimately get steel in the ground to ensure that we have enough electricity to supply all this load that we're connecting, but also to stabilize capacity prices in the wholesale markets. If there's a way that we could do that where the utilities and the IPPs can agree to a solution certainly, we would be open to that.

Our next question comes from Jeremy Tonet with JPMorgan.

Just want to echo your sentiment there on condolences to those impacted and our prayers go out to them. Just want to start off maybe as far as the pipeline in Pennsylvania, the 20.5 gigawatts there. I was wondering if you might be able to peel back a little bit more, I guess, what that looks like sizing there? And really just wanted to get a better feeling for how you think the cadence could come together for formalizing parts of that pipeline here.

Sure. So in the appendix of the deck, we actually have the ramp rates for that 20.5 gigawatts. I'll get you the slide number in a second here. Slide #25. So that's the old chart that we used to show. What I did want to show this time was just how much we've seen that the ramp of each quarterly addition to the pipeline in advanced stages since Q1 of last year, starting with the 3 gigawatts. So the amount of growth has been phenomenal.

And again, I go back to just the quality of the backbone of our transmission grid and our ability to connect these large loads very quickly, which provides speed to market for the hyperscalers, but also to be able to do it very cost competitively. So given kind of where we are with our transmission grid, we feel very comfortable that we can connect this 20.5 gigawatts. And every one of these projects, Jeremy, does require some level of upgrade and some are more than others.

And each time we make those upgrades, it kind of keeps us in front of the demand in terms of our starting point of having a strong grid. So even at the 20.5 gigawatts [indiscernible] to connect that or even to connect additional capacity beyond that, which is good because, as I mentioned, we have 70 gigawatts above what's in the 20, that's still in the queue. But the 20 are those projects that either have an ESA signed or an LOA signed, which brings with it significant financial commitments on the part of the counterparties to either fund long lead time purchase of materials or engineering and development work.

Obviously, the ESAs go a step further. They provide us with commitments around credit support for 100% of the cost of construction for anything that would be socialized in the formula rate as well as generally an 80% minimum load against their forecasted load. So a lot in there, but we feel really good about at least the 20.5 gigawatts in our pipeline, and that would likely continue to grow based on what we've been seeing.

Got it. And just want to pivot to the Blackstone JV, if we could. Just wondering any incremental thoughts with regards to when we could see news flow, more developments on that side?

Sure. So obviously, we don't have an announcement that we're making. Otherwise, I would have done that, but I can assure you that there is a lot of activity going on between the PPL team and the Blackstone team. We're extremely focused with the hyperscalers, with other data center developers, with landowners, pipeline companies, et cetera. So while there's no announcement today, tons of activity, I would say, going on there. Hard to say timing-wise, Jeremy, when we would have an announcement there.

As you can appreciate, these are very complex deals. They take a long time to negotiate to make sure that we're structuring an agreement that's got the proper risk profile for our customers and our shareholders and ultimately is meeting the needs that we're trying to do with this JV. I will say, though, with the amount of new connections or new requests in the advanced stages, so up to this 20.5 gigawatts, we are starting to see a lot more interest and the discussions are moving a lot more towards data center companies wanting to shore up generation, not just shore up their interconnection on the transmission grid, which we've been talking about, as you know, for a while.

I think one of the pluses and minuses of our grid is we've been able to connect customers very quickly to the transmission grid, and that has been their primary focus, and they've been able to wait a little bit longer on worrying about the generation part of the equation. I think we're starting to see them shift to the gen part of the equation and the JV, I think, is situated nicely to take advantage of that.

Got it. That's very helpful. And just one last quick one, just to clarify, if I could, with regards to Mill Creek 2, the O&M number you quoted before, if that was an annualized number? I just wanted to get the context there.

No, those are the total increases between now and 2030. So $30 million of incremental O&M over that time period and $40 million of incremental CapEx.

Our next question comes from Paul Zimbardo with Jefferies.

The first one I wanted to ask about just after the Kentucky rate case stipulation, the Pennsylvania rate case filing. Could you comment a little bit on the linearity of the growth rate in the plan? It just seems like with Kentucky stepping up in '26, Pennsylvania stepping up in '27, the growth would be a little bit more front-end loaded in the plan. So I was curious what your perspectives are there.

Yes, Paul, it's Joe. No, I don't necessarily think it's front-end loaded. Obviously, you're right on the timing of those rate cases and when they're coming into the plan, but we have significant capital investment that runs through the plan. We have the riders in the jurisdictions that we'll get recovery of that spend. So no, I don't necessarily see it front-end loaded.

Yes, PA is coming in midyear too.

Okay. And follow-up on the Kentucky load side. Is there a good amount of megawatts to think about you would include in that new capital plan roll forward? Should we think about the full gigawatt? I know that's through 2032. But just any color you can provide there would be helpful.

You're referencing the gigawatt above the 1.8 gigawatts that was in the CPCN. Is that what you...

Correct. Yes, the 2.8 gigawatts versus the 1.8 gigawatts, yes?

Yes. Yes -- I mean we continue to assess that additional load, Paul, and based on our conversations with developers and others in the state that are driving that. And so we'll continue to assess the probability of that, and we'll make the determination of how much we would put in the plan. Really, the -- what that would drive is additional generation investment beyond what we have, perhaps some smaller amounts on the T&D side, but really, the larger numbers would come from generation. So we'll continue to look at that and assess the need as we're going through this planning process and future plan updates and IRPs.

Yes, Paul, I would just say the team is really keeping a very close eye on that pipeline. So that 2.8 gigawatts is a probability weighted forecast. So we're just keeping a very close eye on how and when those projects are materializing so that we can get in front of this additional generation need as soon as we would need to.

I would say likely if we determine we need additional gen that likely the battery project that we delayed might be the first project to come back into play, but the team is really watching this, as I said, very closely so that we can stay in front of it. But the battery is one that we can build very quickly and provide that peaking support that we might need, again, depending on the types of load that come in. So no decision on it yet but watching it very closely.

Our next question comes from Steve Fleishman with Wolfe Research.

The 11 gigawatts of publicly announced data centers, could you give us a little more color on the details of that? Just what those are? I mean we obviously, we know Talen, Susquehanna with AWS, and we know the Homer City and stuff. But just -- I mean, is there -- can you give us the pieces of that?

Yes. So for confidentiality reasons, we don't provide who those hyperscalers or data centers are or where they're located. Obviously, that could have implications on other data center activity. So we're very careful not to do that, Steve. I would say, as we kind of think about the amount of investment needed to support those, it's about $800 million of capital for the 11.3 gigs and about $400 million of capital for the 5 gigs under construction.

So just when you're defining these as publicly announced, like is that -- what is the definition of that?

So some of that is what was announced during the summit that we had in Pittsburgh and then there have been other public announcements following that, that some of the customers would have made, but those are -- I think those are for them to discuss, not us.

Yes. Okay. And just this profile of the data center growth, how does that compare to what is in the kind of in whatever latest load forecast you gave to PJM? I don't know if they've been updated since the beginning of the year, but is it -- has this -- has your -- at least your zone gone way up relative to what you had forecasted previously?

Yes. So the latest we have with PJM is about 16 gigawatts, Steve.

Okay. And I guess, what is the customer savings that you used to give a ratio of how much T&D rates maybe would be saved, customer reductions. Could you give us some sense based on what -- I don't know which number you want to use, like what the customer savings are from sharing the transmission grid? Yes.

Yes. In the early pieces, it's about 10% savings on the transmission component per gig. That was about $3. But the more you add, that gets diluted a little bit. Joe and Andy, maybe we can provide that. We'll provide that, Steve.

But there's still savings each time more gets added.

Yes. Yes.

Our next question comes from Angie Storozynski with Seaport.

I have no complaints about earnings. So I just wanted to make it clear because I've been picking over the last couple of quarters, but nothing to pick on this time. So the -- my question -- 2 questions. One is you mentioned that as the data center pipeline grows, the rule of thumb about how much transmission spending is needed for every gigawatt of load added no longer holds. And I just wanted just to give me a little bit more on that.

And then secondly, on the joint venture with Blackstone. So we're seeing a number of secondary gas plants in your zone changing hands. And again, we'll see if any of them go to your joint venture. I'm just wondering if that -- is that all part of the plan to acquire existing sites and to expand them? Or is this just a brand new build that you would consider only once you have secured long-term contracts?

Sure. Maybe I'll take the second one first. So on the JV with the gas plants, we created the JV, Angie, to really help deal with the resource adequacy concerns that we were seeing in PJM. And obviously, with our territory and PPL sitting right on top of Marcellus Shale, we felt and continue to believe that we can provide a very competitive solution to a data center that is looking to contract and basically procure generation. Buying existing assets don't necessarily support additional resource adequacy unless we can expand them like you described.

However, there could be some benefit in procuring -- in buying existing generation if for instance, it's an old asset that we need for 5 or 6 years until we can get the new asset up and running and the data -- and the hyperscaler wants to have an asset-backed deal, maybe there's a scenario where it would make sense for us to buy existing gen, but that's not the core part of the strategy, but I wouldn't preclude it. So kind of my thoughts there. And then on the $50 million to $150 million, so what I would say on that is, look, generally, that $50 million to $150 million per gigawatt is a good rule of thumb.

The only caution that we are providing with this update is in our 5-year CapEx plan or 4- or 5-year CapEx plan for transmission, some of the upgrades that we may have had in that plan are starting to overlap with the upgrades that would be required for a particular data center project. So the $50 million to $150 million to serve the data center may still hold, but that may not be incremental to what's in the plan. Does that make sense?

Our next question comes from Anthony Crowdell with Mizuho.

I just have one quick follow-up, I guess. I appreciate the update. You mentioned the growth in Kentucky and Pennsylvania is quite impressive. Just the company has done a great job in the regulatory arena as we see more and more data centers connecting. Is there a concern of maybe an unhealthy revenue concentration that potentially could offset the solid regulatory balance you guys have achieved over the past several years. Just it looks like more and more load is coming from one sector. Wondering if that could create an unhealthy regulatory balance going forward.

Yes. Look, I think that's a really good question. I don't necessarily think that we're feeling concerned about an overconcentration of risk to the data centers because of the protections that we're building into the tariff structures and the ESAs that folks are signing for these large loads. So really, I think the issue becomes, Anthony, you build all this stuff, it's in rate base and then for whatever reason, the customers aren't using as much power, and those costs are being defrayed to our existing customer base.

So we built the protections in for that. I would say in Pennsylvania, they -- the PUC is proposing their large load tariff this week. And I think what we have in our proposed tariff in the rate case, those protections will be in that tariff and that tariff may go even further than what we have proposed. So overall, I think as long as we have these proper protections in place, not overly concerned about concentration risk. The other broader, I would say, aspect to this is certainly in the early stages, which we are.

I don't see these hyperscalers not needing the amount of power that they're signing up for. In fact, they're probably going to need even more. So as you think about the advancements in the chips themselves, those advancements basically enable more compute power in the same physical space that the prior generation was, well, compute power equals electricity. So if anything, I think we're going to need to continue to support these data centers with additional power needs, not less.

Great. And then just one follow-up. I'm not sure if you were leading this way, and that's my question. I don't know if it was Angie's question or to the person before. But you talked about maybe the haircuts of the load forecast when the utilities submit to PJM, PJM haircuts even more. You're seeing greater load growth in your areas. Are you trying to highlight that the potential that the regions PPL serves is a candidate for breaking out in the next auction? Or that's not what you were trying to say, just overall, the resource adequacy has an issue?

Yes. I was not suggesting that the PPL zone would necessarily break out. And so the load forecast that we provide PJM or the projects that we're including in that are consistent with the projects that we're including in the 20.5 gigawatts. There are just timing differences between when we update the intervals on when we're updating the PJM and when we're having our investor updates on our quarterly calls.

So the last time we updated was about, like I said, 16 gigawatts, but that would represent those projects at that time that we had ESAs and LOAs signed by customers. So the next update for PJM would be this 20.5 gigawatts and then PJM would go through their process to haircut that 20%, 30%, whatever they deem appropriate. But no...

This concludes the question-and-answer session. I would like to turn the conference back over to Vince Sorgi, President and CEO, for any closing remarks.

Yes. Thanks for joining us this quarter. Again, continue to execute third quarter strong results sets us up really nicely for finishing strong in 2025. Look forward to providing our full update on the year-end call. And of course, we will see many, if not all of you next week at the EEI Financial Conference. Thanks, everybody.

The conference has now concluded. You may now disconnect.