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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

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.