PPL Corporation

Good day, and welcome to the PPL Corporation second quarter 2024 earnings call. All participants will be in a listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star, then one on a touch-tone phone. To withdraw your question, please press star, then two. 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 second quarter 2024 financial results. We provided slides for this presentation on the investor section of our website. We'll begin today's call with updates from Vin Sorge, 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 two and a brief cautionary statement. Our presentation today contains forward-looking statements about future operating results or other future events. Actual results may differ materially from these forward-looking statements. Please refer to the appendix of this presentation and PPL's SEC filings for discussion of some of the factors that could cause actual results to differ from the forward-looking statements. We will also refer to non-gap measures, including earnings from ongoing operations or ongoing earnings on this call. For reconciliations to the comparable gap measures, please refer to the appendix. I'll now turn the call over to Vince.

Thank you, Andy, and good morning, everyone. Welcome to our second quarter investor update. Let's start with our financial results and a few highlights from our second quarter performance on slide four. Today we reported second quarter gap earnings of 26 cents per share. Adjusting for special items, second quarter earnings from ongoing operations were 38 cents per share. Backed by another strong quarter, today we reaffirmed our 2024 ongoing earnings forecast of $1.63 to $1.75 per share and expect to achieve at least the midpoint of our forecast range. In addition, we continue to make excellent progress in delivering on our 2024 priorities. We're on track to complete approximately $3.1 billion in infrastructure improvements this year to advance a reliable, resilient, affordable, and cleaner energy future for our customers. We're on pace to exit our remaining transition service agreements with National Grid in the coming weeks and to complete what has so far been a seamless integration of Rhode Island Energy into PPL. Lastly, we expect to achieve our annual O&M savings target of $120 to $130 million this year, which is compared to our 2021 baseline O&M. Looking ahead, we're well positioned to achieve our projected 6% to 8% annual earnings per share and dividend growth through at least 2027. We remain as focused as ever on executing our capital plan, which includes $14.3 billion in infrastructure improvements from 2024 to 2027. And across PPL, we continue to drive efficiencies through our utility of the future strategy, keeping us on pace to achieve our annual O&M savings target of at least $175 million by 2026, again, compared to our 2021 baseline. Moving to slide five, I want to reiterate our utility of the future strategy. which in a nutshell is to deliver a net zero energy system by 2050, but one that continues to be reliable and affordable for our customers. The decarbonization strategy here in the U.S., and even globally, is to electrify as much of the economy as we can and generate the needed electricity with no or low carbon solutions. This will significantly increase the demand for electricity, currently estimated at two to three times our current levels. but it also requires the electricity grid to be significantly more reliable and resilient than it is today. Our utility of the future strategy addresses this challenge head on across multiple focus areas. First, we will improve the reliability and resiliency of our electric and gas networks through updated design criteria and system hardening to better protect against more frequent and severe storms. Through automation, AI, and smart grid technology that offers self-healing grid capabilities, through grid enhancing technologies that help us extract the most from existing infrastructure, and through robust and ever-evolving cybersecurity that protects against present and future threats. At the same time, we will continue to advance the clean energy transition affordably and reliably. We'll achieve this by transitioning to a reliable, affordable, and cleaner energy mix, one that includes an important role for dispatchable natural gas as we retire aging coal-fired generation. We'll do it by positioning the grid to connect increased renewables, including behind-the-meter resources. And we'll do it by continuing to lead, partner, and invest in R&D to accelerate the commercialization of low-carbon technologies needed to achieve net zero, technologies such as advanced nuclear, carbon capture, hydrogen, and long-duration energy storage. This includes the recent partnerships we've made with the Department of Energy to explore the feasibility of coal-to-nuclear transitions at some of our power plant sites in Kentucky, and a leading carbon capture R&D project at our cane-run combined cycle gas plant. Our Utility of the Future strategy also includes driving sustainable efficiencies to keep energy affordable for our customers as we invest in the clean energy transition. For every dollar of O&M we can take out of the business, we can invest about $8 in capital without impacting our customers' bills. This is why becoming more efficient is such an important part of our strategy and helps to keep the transition more affordable for our customers. We are also focused on using AI and other advanced technologies more broadly, which will drive further efficiencies and improved results. We are starting to see firsthand the power of AI and how transformational this technology will be to our business. This includes balancing the grid and peak shaving, empowering our customers and enhancing their experience with our utilities, and further improving reliability while lowering our costs. The applications of AI technology are tremendous for our industry, and we are extremely focused to unlock that potential to deliver real value. And finally, we'll continue to engage and lead discussions with a wide range of stakeholders to strengthen resource adequacy in the regions we serve, specifically including markets like PJM, which is even more critical following the capacity auction results that were just released this week. With increasing demand and tight supply, we need to do everything we can to protect our customers from such price volatility, including investing further in transmission upgrades to alleviate constrained zones, incorporating additional grid-enhancing technologies to get as much as we can from existing lines, and advocating for legislative changes in Pennsylvania that would drive needed generation development, including authority that would support regulated utility investments in new generations. Collectively, these actions will not only maintain reliability, but also power economic development, while at the same time support data center growth and expansion, which we consider critical to American competitiveness and national security. This is our Utility of the Future playbook to not only address the challenges of delivering a clean energy future that is affordable and reliable, but to enable us to thrive and grow in that ever-changing energy landscape. Moving to slide six. and a deeper dive on our support for data centers. Starting with Pennsylvania, we truly believe our Pennsylvania service territory is uniquely positioned to service large-scale data center connections. First, we've invested $6.5 billion over the last decade in our transmission network while leveraging advanced dynamic line rating technology, which together has improved the reliability of the network to top vessel performance nationwide. Our advanced transmission network is capable of connecting the current data center demand in our queue, and we are confident we can support even further demand should it materialize. This means we can respond very quickly to developer interconnection requests. Our team responds within six weeks. As a result, we now have a total of over 17 gigawatts of interconnection requests in Pennsylvania, and new requests continue to come in each month. While it is likely that some of these requests are duplicative due to developers assessing multiple sites at the same time, we have nearly five gigawatts of potential data center demand in advanced stages of planning, up from the three gigawatts we discussed during our first quarter update in May. These projects all have signed agreements with developers, are in various stages of PJM's review process, with some having already completed that review, and costs being incurred by PPL are reimbursable by the developers if they do not move forward with the projects. On the financial impacts of data centers, the primary upside is in the form of additional returns on transmission investments through FERC formula rates. We estimate that the 5 gigawatts of potential demand in the advanced stages represents incremental PPL capital needs of $400 to $450 million. Because we operate in PJM in Pennsylvania, this data center development will reduce net transmission costs for our existing retail customers. We estimate for every 1 gigawatt of data center demand that's connected to the grid, our residential customers would save about 10% on the transmission portion of their bill. For the average residential customer, that would represent about $3 a month in savings. For the 5 gigawatts in advanced stages of development, That would represent about $15 a month in savings for the average residential customer using 1,000 kilowatt hours a month of electricity. Turning to Kentucky, our service territory there is better suited for midsize data centers as we also have an abundance of land and water, have lower energy prices than much of the U.S., and provide for tax incentives in certain counties that we serve. We are also confident we can make the needed transmission and generation investments required to support continued data center and industrial growth in the Commonwealth. We continue to work with data center developers in our LG&E and KU service territories with active requests totaling more than two gigawatts in the 2027 to 2033 timeframe with about 350 megawatts in advanced stages. As in Pennsylvania, any transmission upgrades in Kentucky would be additive to our capital plan, although the more significant capital investments in Kentucky would arise from any incremental generation investments. Once our new Mill Creek 5 combined cycle gas plant is operational in 2027, we estimate that we will have approximately 400 to 500 megawatts of generation capacity available to support further load growth while maintaining our prudent reserve margins. With Kentucky coming off the best four-year period of economic growth in the state history, on top of this potential new data center demand, we continue to actively monitor our capacity needs to maintain a safe and reliable network for customers. Should new generation become necessary to serve higher electricity demand, we can use Mill Creek Unit 5 as a reference for pricing on potential new baseload generation. That unit, which was approved by the KPSC last year, has an expected cost of $1 billion. The updated integrated resource plan, which will be filed with the KPSC in October, will guide any further generation needs. Keep in mind there are many factors that go into our generation planning and reserve margin analysis. We will refresh that analysis this fall and will include updated load projections and related supply needs. As we think about possibly needing to build a second combined cycle gas plant to meet that load growth, it's important to note that we still have a spot in the queue for a second gas turbine from our prior solicitation. It is important to highlight that our rate designs in both Pennsylvania and Kentucky protect our customers from undue burdens related to data center connections. In both jurisdictions, the data centers are under tariffs that will benefit our non-data center customer rates. Bottom line, and as I shared last quarter, we're ready and eager to support prospective data centers, and we are well positioned to serve their needs. And the good news is that our customers, share owners, and the states which we serve all benefit from this development. Moving to slide seven and several key operational and regulatory updates. On July 11th, the Pennsylvania PUC approved PPL Electric Utilities' request to modify its current Long-Term Infrastructure Improvement Plan, or LTIT. The decision granted us permission to classify approximately $200 million of reliability investments through 2027 as capital eligible for recovery through the DISC, or the Distribution System Improvement Charge. While the PUC denied our request to classify $84 million of planned investments in predictive failure technology as being DISC eligible, the PUC viewed our predictive failure project favorably and indicated PPL Electric may seek recovery of these project costs in a future base rate case. Overall, the approved modification to our LTIP represents a positive outcome. that supports our continued investments to repair and replace aging infrastructure and strengthen grid reliability. Changes to the plan will be implemented during the current plan period, which extends through December 31, 2027. Also in Pennsylvania, our DISC waiver petition continues to proceed through the process, as expected. In June, an ALJ was assigned and a procedural schedule was created, which we have provided in the appendix. Based on that schedule, we continue to expect the proceeding to conclude later this year with a decision in early 2025. Shifting to Kentucky, we recently kicked off construction of our planned 650 megawatt Mill Creek Unit 5 combined cycle natural gas plant following several months of prep work. The new unit is part of more than $2 billion in planned generation investments over the next several years to economically replace 600 megawatts of aging coal generation with a reliable, affordable, and cleaner energy mix. In addition, all long lead time equipment deliveries remain on schedule. Overall, we're on track to complete construction and begin commercial operation of the unit in 2027. We will earn AFU DC on this capital project until it goes into commercial operation. In addition, we secured a site compatibility certificate from the KPSC in July for a planned 120 megawatt solar facility to be built in Mercer County, Kentucky. The approval helps pave the way for final site design and construction of the new facility, which we expect to begin commercial operation in 2026. Finally, just this week, we successfully completed another labor contract negotiation. This latest agreement covers about 60 employees in Kentucky and represents the fifth successful union negotiation over the last year, representing over 50% of our union workforce. We look forward to continued success in this area for years to come, balancing the needs of our employees and customers. That concludes my strategic and operational update. I'll now turn the call over to Joe for the financial update.

Thank you, Vince, and good morning, everyone. Let's turn to slide nine. CPL second quarter gap earnings were 26 cents per share compared to 15 cents per share in Q2 2023. We recorded special items of 12 cents per share during the second quarter, primarily due to integration and related expenses associated with the acquisition of Rhode Island Energy. Adjusting for these special items, second quarter earnings from ongoing operations were $0.38 per share, an improvement of $0.09 per share compared to Q2 2023. Primary drivers of this increase were returns on capital investments and higher sales volumes, primarily due to the return to more normal weather conditions. We estimate that weather was about four cents favorable compared to the prior year and about one cent favorable to normal conditions. These positive drivers were partially offset by higher interest expense, primarily due to higher debt balances with the issuances at PPL Electric and Rhode Island Energy earlier this year, which were executed at attractive rates favorable to our forecast. And we'll continue to monitor the markets and leverage our excellent credit position to be opportunistic and efficiently finance our capital plans. Our Q2 performance puts PPL's gap earnings at 67 cents per share year-to-date through June 30th, compared to 54 cents per share through the same period last year. Adjusting for special items recorded through the second quarter, earnings from ongoing operations totaled 92 cents per share for the first half of 2024, an improvement of 15 cents per share compared to the first half of 2023. We estimate that weather has been 7 cents favorable compared to the first six months of 2023, while tracking slightly below normal conditions year-to-date in 2024. The full year-to-date ongoing earnings walk-by segment is included in the appendix. Turning to the ongoing segment drivers for the second quarter on slide 10, our Kentucky segment results increased by 5 cents per share compared to the second quarter of 2023. The improvement in Kentucky's results was driven by higher sales volumes, primarily due to the return to normal weather and lower operating costs. Our Pennsylvania regulated segment results increased by five cents per share compared to the same period a year ago. The increase was driven by higher transmission revenues and higher sales volumes due to a combination of a return to normal weather and increased usage per customer. Our Rhode Island segment results increased by one cent per share compared to the same period a year ago. This increase was primarily driven by higher distribution revenue from capital investments, higher transmission revenue, and higher interest income, partially offset by higher operating costs and higher property taxes. Finally, results at corporate and other decreased by two cents per share compared to the prior period, primarily due to higher interest expense. With another strong quarter behind us, we're on track to achieve at least the midpoint of our 2024 earnings forecast of $1.69 per share. I'm extremely pleased with our financial performance as we continue to execute our plan and our utility of the future strategy. This concludes my prepared remarks. I'll now turn the call back over to Vince.

Thank you, Joe. In closing, we continued our strong track record of execution in the second quarter, further strengthening PPL's investment thesis. We are implementing our utility of the future strategy necessary to deliver a clean energy future affordably and reliably. We are securing constructive outcomes in key regulatory proceedings. We're achieving strong financial results, which positions us to deliver at least the midpoint of our targeted EPS growth this year and to grow earnings and dividends by 6 to 8 percent through at least 2027. We're maintaining one of the premier balance sheets in our sector that supports the growing investment needs across our jurisdictions. We're advancing the economic transition of our generation fleet in Kentucky. And we're continuing to power economic development that strengthens our communities, including the support of data center expansion. Overall, we've made significant progress on our plans through the first half of the year. We're eager to build on this momentum in the back half of 2024 and beyond. And we look forward to once again delivering on our commitments to share owners, customers, and the communities we serve. With that operator, let's open it up for questions.

We'll now begin the question and answer session. To ask a question, you may press star then one on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed, and you would like to withdraw your question, please press star then 2. At this time, we will pause momentarily to assemble our roster.

The first question comes from Char Perez with Guggenheim Partners.

Please go ahead.

Hey, guys. Good morning. Morning, Vince. Vince, just trying to get a sense on the transmission side. We're looking at 400 to 450 incremental per this update. We've also seen a blowout print in the capacity auction, potentially foreshadowing more RTEP work. What does all this start to add up to as we look at your $725 million placeholder for 27? How should we think about the timing or the shape of that spend as we update our models for 28? and beyond versus that 27 placeholder you have in plan. Thanks.

Yeah, Shar, I think what you're bringing up is a good point in terms of, you know, what is the capacity option signifying, right? And clearly I think it's showing that there's a clear signal that we need new generation and transmission investments needed in PJM. In terms of ability to invest in transmission. I think that's in a few areas. Obviously, there were the two zones that broke out above the RTO. Clearly, I think there's opportunity for additional transmission solutions going into there. So, I think we could probably expect there to be an open window to try to resolve some of that. As you know, in the past, we've been successful in in winning some projects going down into the Maryland, Virginia area. So it could be additional opportunity there in addition to just investments in our own area. You know, I would say that from a broader strategic perspective, I think those auction results also would reinforce our strategy in working with the state of Pennsylvania and the other EDCs in the state to help resolve like the resource adequacy concerns that many of us have been talking about for a while now, in particular in PJM. And so we're not going to just sit back and wait for this issue to resolve itself. You know, we have an obligation to serve and do everything that we can for our customers, whether it's, you know, these additional transmission investments. I think we can do additional grid enhancing technologies on the existing grid. and then continuing to advocate for legislative change. So we'll continue to push that agenda to ultimately lower the price of electricity for our customers and reduce the volatility.

And Vince, just on, it's a good segue right to my follow-up, but on the broader resource adequacy question related to BRA, a lot of your WIRES peers have commented on it this week. You just did. In the past, we've had similar attempts on this kind of re-regulation of a certain amount of generation over 13 years ago, right, in New Jersey and Maryland with the LCAP and MCAP program, which ultimately got struck down by the courts. It was a little bit more on the capacity side versus energy. But I guess what's different now focusing on potential generation requests by the wires companies? Where are the conversations at with policymakers? Are they waiting for the IPPs to step up and build? What's your trigger point? Should we be watching a legislative window next year? I guess just elaborate a little bit on some of the dialogue you guys are having.

Yeah, well, look, I think the biggest difference, Char, is what's in the queue, right? And what we're seeing right now is significant amounts of dispatchable generation being retired with very little dispatchable generation coming on. And so I think that's the big issue. It's not so much the energy play, it's the capacity play and making sure that we have enough capacity to serve 24 hours a day, seven days a week, 365. So that's really the big difference, I would say, from what we're seeing now. And so what's being left in the market is creating real concerns around resource adequacy. You know, I think there's a few signposts that we're certainly watching to determine what the long-term impact of this capacity auction will be in terms of our customer bills, but also just on resource adequacy. You know, we want to see what the auction results are for the 26-27 planning year, which will happen in December. Same thing for the 27-28 planning year. That'll occur next June. I want to see if there's any new dispatchable generation entering the queue between now and December. We suspect that the IPPs will want to see more than just this one data point before they're committing to building new dispatchable gen like natural gas. So we'll be keeping an eye on that. So there's a few things that we'll be looking at. This, of course, is one data point. But I think it clearly supports Our strategy, which is, you know, we need to make sure we keep resource adequacy front and center. We think the states are going to have to play an active role in that. And fortunately, I think Pennsylvania is taking this issue very seriously. We look forward to continuing to work with all the stakeholders in the state to see what we can do to shore this up.

Okay, perfect. I appreciate the additional call here. Congrats on the results, Ben, seriously.

We'll see you soon. Thanks, John.

The next question comes from Durgesh Chopra with Evercore ISI. Please go ahead.

Good morning, Durgesh.

Hey, good morning, Vince. Thank you for taking my questions. Hey, I just want to continue the discussion on the PGM auction results. You know, you mentioned, you know, that IPPs probably want another signal before they can commit capital here. This is a pretty dramatic signal in terms of price increases. And one of the things we're consistently getting asked from investors is what does it do to utility bills? Your peers kind of talked about double legit increases in some of their service territories. I know this is not nine times translates into, you know, that large of a bill increase, but just maybe can you discuss that a bit? What does this mean for customer bills?

Yeah, of course. So I would say, you know, for the near term impact, for customer bills, and this, of course, assumes all else equal, right, which never is the case, but all else equal, we would estimate that these higher prices would impact the generation portion of the bill for an average customer by about $10 to $15 per month. That represents roughly 5 to 10% of the total bill. We would expect that to begin in 2025 as our suppliers start to reflect these higher prices in their solicitation bids. You know, I did talk in our prepared remarks. Fortunately, in addition to the other actions that I just talked about with Char that we're taking on this issue, we are seeing that substantial data center load. And, you know, if we just stick with that five gigs in advance stages, right, that would reduce our customer bills over time. by a similar amount that we're talking as a result of the capacity price increases once that demand all comes online. So lots of moving parts on here. Obviously, the capacity prices will have a near-term increased impact, and then we'll look to mitigate that over time with various actions, including the data center look coming online.

That's very helpful. I appreciate the detail there. Then just switching gears on the balance sheet, just thinking about the $400 to $450 million you mentioned and other opportunities across the different states, how should we think about your balance sheet capacity? What capex could be done with that? And at what point you might consider equity as we think about you rolling forward your plan here into 2029 now?

sure hi there guys it's joe so look up just say that our balance sheet is in really good shape and we expect to be within the ffo to debt range of 16 to 18 percent through the planning horizon you know capital is just one factor that goes into our financing needs and we'll we'll work that through as we update our business plan but obviously there's other things that that drive those financing needs to determine what we'll ultimately do interest rates inflation Our efficiency strategy certainly plays a role in that, and then rate case outcomes. So, you know, as we go through the plan and incorporate all of these factors, including potential additions for data centers and other opportunities, we'll take that into account. But, again, our balance sheet is in really good shape.

Thanks, Joe. Thank you both. Appreciate the time.

Thanks, Josh.

Next question comes from David Arcaro with Morgan Stanley. Please go ahead.

Hi, David. Hey, good morning. Hey, thanks for taking my questions. You know, looking ahead to the Kentucky IRP in October, just curious, does it look likely at this point that you'll need new generation as you're crafting that before you file it?

I certainly don't want to get in front of that process. It's a very extensive process that we go through when we update the IRB. We are required to update that in October with the commission. The reason I say that, Dave, is obviously we have to do a full load forecast update, right? So we'll look at what's going on with the industrial growth, what's going on with data centers, just general new customer additions and what we're seeing from a relatively useful customer perspective. We also have to take into account energy efficiency programs, distributed energy resource penetration. Of course, electric vehicles are starting to come in, so we will do a comprehensive load forecast with multiple scenarios around that forecast and then ultimately feed into how we believe we'll need to deal with that from a generation supply perspective, which could include a combination of dispatchable resources to ensure we have capacity there, which would be something like another combined cycle natural gas plant, but it could also entail additional solar or renewable resources batteries similar to what we got approved last year. Don't want to get in front of what that result will be, but suffice it to say we'll go through that full analysis and we'll have a pretty good sense when we file that what our generation needs. And then if it shows a need for incremental generation, we would follow that up shortly thereafter with a CPCN to request approval for that.

Yeah, understood. That makes sense. I was also curious, do you have a view on how long, just thinking about the PJM market, how tight that market has gotten here, how long does it take to build a new gas plant in PJM, realistically? Like, when could we actually see a supply response, kind of from anybody, as we look at supporting the supply-demand tightness?

Yeah, you're not going to love this answer, but it depends, right? Are we talking peakers? Are we talking combined cycle? Do you own turbines? Do you have to get in the queue? Theoretically, if you own turbines and we're talking peakers, then you've done some site work, probably 18 months, 18 to 24 months on the short end. If you're starting from scratch and you want to go combined cycle, it's probably four to five years.

Yeah, got it. Got it. That makes sense. Tough problem to solve, but depending on which direction you go. Maybe one last question from me. You've highlighted the TMO in the slides, and so looking at the O&M opportunities, I was wondering, have you taken a look at, you know, kind of beyond the 2026 targets? What are the, what's the opportunity set here? Can you continue beyond your existing targets on O&M cost reductions?

Yeah, Dave, it's Joe. Certainly beyond 26, we continue to see opportunities. Vince mentioned AI and some of the use cases that we're seeing that we think can drive longer-term O&M efficiency opportunities. Clearly, we're focused on achieving the $175 million that we've laid out, which we're making good progress on, and we'll achieve that. We'll continue to look for opportunities beyond that timeframe, but certainly there will be opportunities to get more efficient.

Great. Thanks so much. Appreciate the caller. Sure. Thanks, Dave.

The next question comes from Julian DeMolin Smith with Jefferies. Please go ahead. Hey, good morning, team.

Thank you guys for the time. Nice to chat with you guys. So a lot's been said here, but let me pivot a little bit in a different direction here on this conversation on data centers. And that's, you know, the heuristic I think you provided about like one gigawatt reducing the bill by like $3 a month. How do you think about that scaling here? Because you talk about more than one gigawatt of data center. Obviously, I think that there's an element of time here of when you realize those cost savings. But can you speak to that again? You threw out like a five gigawatt potential, for instance, here of late. Like it's not going to reduce transmission costs that size of late, linearly.

What we're seeing with the current five gigs, is that that starts in 2026. We would expect to be at our first gig in 27 and then probably adding a gig each year thereafter.

Got it. And what does that mean for, as you think about like bill cost reductions through that period of time, right? Using that heuristic of that $3 a month. Yeah. See compounding benefits. Every year?

Yeah, it's about $3 a month per gigawatt. So by the time we get the full five gigawatts, it would be about $15 a month in lower bills for residential customers.

Wow. Okay, that's pretty impressive. And then separately here, just in terms of, you know, you talked about this predictive failure technology not being disk eligible. Can you talk about, you know, what that does for rate case timing, if at all? Or can you talk about Pennsylvania writ large on the rate case side? I suppose there are other factors there as well.

Yeah, sure. I mean, in general, I mean, 84 million isn't going to necessarily impact our rate case timing, Julian. But, you know, so we'll look to continue to deploy that technology and seek recovery in our next base rate case. But, Joe, you can talk about timing on that.

Yeah, I think at this point the earliest we would see a rate case in Pennsylvania would be 2026, and that would be at the earliest. We may be able to go beyond that timeframe. Again, to Vince's point, he's right, $84 million isn't going to drive that decision, but we'll deploy it and we'll seek recovery of that in the next rate case whenever it may be.

Got it. All right, excellent. And then related here, thoughts on just going back to that, I think you said October filing on the next IRP here. Just to the extent to which that you are able to move swiftly on that second combined cycle here, presumably, as a piece of that. I mean, how front-end loaded versus longer dated could some of these opportunities prove themselves?

Yeah, so near-term... Transmission upgrades, those will go in line with the requests. Just to give you, again, we're in a $10 to $75 million per project range in Kentucky, just given the size of the projects down there, just to give you a sense for the 350 megawatts that are in more advanced stages in Kentucky. That's just under $30 million of incremental capital there. on the transmission side. So those will get done in concert with the data center demand coming on. In terms of the generation, any large-scale generation likely would not come online until around 2030. That's the indication we've gotten from the commission when we talk to EPC contractors when we look at When we can get the turbines, that's probably where we're talking in kind of the 2030 timeframe. So, obviously, the few years prior to that is when we'll be spending the capital.

Yeah, probably 20 to 2030 there. All right, cool. Excellent. Thank you, guys. Appreciate it very much.

Next question comes from Ryan Levine with Citi. Please go ahead.

Hi, Ryan. Good morning. Hi, everybody. For the 5 gigawatt opportunity, what's the timetable for go, no-go decisions for these potential customers? Is there any cadence or color you could provide around how that could play out?

Yeah, so look, we're making good progress with the developers on all of those. We're working through the PJM planning process as well as the PUC processes. All of that is progressing well. I would say probably no change, Ryan, from what we talked about on the Q1 call. We still expect that any formal announcements would come kind of at the end of the year, beginning of next year. the data center companies are going to want to make sure we get through those full processes before they're announcing. So we would expect that to be really around the end of the year, beginning of next year.

The end of the year decision for the initial three gigawatts or for the entire five?

That's all five.

All five. Okay. And then in terms of the Pennsylvania CapEx associated with that, appreciate the color provided. But in terms of scaling beyond the five, is there any key milestones or amounts that you'd have to achieve to be able to have maybe a bigger step up on a per megawatt basis from an investment standpoint?

I mean, again, it's really very project specific. So, you know, we'll update this quarterly so you have a sense of how we're progressing on overall data center demand in our jurisdictions, how much is in the queue, how much is in advanced stages. We'll try to provide updated CapEx estimates as we go along, but it'd be hard to, again, we're talking $50 to $150 million, so that's a $100 million range depending on the project. So we'll keep that disclosure updated as we go.

Okay. And then one last one for me. In terms of the the headquarters in Pennsylvania. Is there any practical implications from headcount or cost outlook given the real estate sale?

No, I mean, this was really, you know, the decision to sell the building was a kind of post-COVID, had way too much real estate from what we needed. It was underutilized. And so nothing to do with headcount.

Okay, thanks for the cover.

The next question comes from Anthony Crodel with Mizuho. Please go ahead.

Hey, good morning, team. Hope summer's treating you well.

Likewise. Ranger's schedule is out, but we'll keep it just to the call here. I'm just wondering, Vince, you talk about some of the transmission opportunities and the infrastructure investment associated with this higher capacity price. We're going to look at December and see what the print is there. I mean, do you think higher capacity prices are good for PPL, given the potential added investment?

Well, look, I think there's

there's a number of things where we're focused on, Anthony, right? There's resource adequacy overall in the market, in particular in PJM. And so if those higher prices incentivize new generation and shore up resource adequacy, that's a good thing for all of us in PJM. We talked about the higher cost, that that will ultimately – bear for our customers, which obviously is not great for our customers. But we're looking at all alternatives to see how we can bring that generation to bear in the most least cost way, as you know. So there's some puts and there's some takes, I would say, with that print.

got it and then just and then just following up and apologize to just keep harping on the pgm and i'm just not that familiar with it for your customers in pennsylvania that maybe don't shop that maybe the utility procures the energy is there a hedging strategy you guys pursue to mitigate any energy price volatility for customers yes that's why the range is 10 to 15 dollars so we we have in the early part of 25 where we've already

procure that power, it wouldn't have as big of an impact as the back half when we're procuring additional power, and those prices might be reflected in what we're buying. So the next solicitation is October, the fourth quarter of this year. So we're suspecting that those prices will make its way into that solicitation.

Great. Thank you for taking my questions. Looking forward to seeing you guys next week.

Great. Thanks, Anthony.

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

Great. Thank you. I just want to thank everybody for joining us on today's call. We will be in New York next week, and hopefully we'll get to see as many of you as we can then. So thanks again for joining.

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