Good day, and welcome to the PPL Corporation Fourth Quarter 2024 Earnings Conference 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, Investor Relations. Please go ahead. Good morning, everyone, and thank you for joining the PPL Corporation Conference Call on Fourth Quarter and Full Year 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 Vince Sorgi, PPL President and CEO, and Joe Bergstein, Chief Financial Officer. I will conclude with a Q&A session following our prepared remarks. Before we get started, I'll draw your attention to slide two and a brief cautionary statement. Our presentation today contains forward-looking statements about future operating results or other future events. Actual results may differ materially from these forward-looking statements. Please refer to the appendix of this presentation and PPL's SEC filings for a discussion of some of the factors that could cause actual results to differ from the forward-looking statements. We 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. Thank you, Andy, and good morning, everyone. Welcome to our Fourth Quarter Investor Update. Returning to slide four, I'm very proud of our PPL team and all we accomplished in 2024 in executing our Utility of the Future strategy. Most importantly, we continue to deliver electricity and natural gas safely, reliably, and affordably to our three and a half million customers in Pennsylvania, Kentucky, Rhode Island, and Virginia. This included top quartile transmission and distribution reliability in Kentucky, Pennsylvania, and Rhode Island, and generation reliability in Kentucky that remains among the nation's best. This was a fantastic result considering we saw some of the worst storms in our company's history, as our crews were called upon time and time again to restore power for our customers. To combat the more frequent and severe storms, we increased our vegetation management spending compared to plan to enhance reliability and reduce storm-related outages. We'll continue to review our vegetation management programs going forward to effectively balance reliability versus cost for our customers. Moving to our financial performance, we delivered ongoing earnings of $1.69 per share, the midpoint of our original 2024 guidance. While we are disappointed that we fell a penny short of the increased ongoing earnings midpoint guidance of $1.70 per share due to some very mild weather in the second half of December, we're confident that the increased vegetation spend was in the best interest of all of our stakeholders in closing out the year. Turning to other 2024 highlights, we executed $3.1 billion of planned infrastructure investments on time and on budget to strengthen grid reliability and resilience and advance a safe, reliable, affordable, and cleaner energy mix. We also continued our focus in becoming more efficient and keeping energy affordable, achieving the top end of our cumulative annual O&M savings target of $130 million from a 2021 baseline through continued deployment of smart grid technology, automation, and data science. As shared on our third quarter call, we completed the integration of Rhode Island Energy into PPL, exiting the transition services agreement we entered with National Grid when we acquired Rhode Island Energy in May 2022. The integration involved exiting more than 130 transition services in phases over the past two years, with careful attention paid to minimizing any impacts on our customers and employees along the way. Overall, I'm immensely proud of the strong collaboration and teamwork that took place across PPL and with National Grid to achieve this success. Moving to slide five, today we announced an updated business plan that strengthens and extends our runway for annual earnings and dividend growth while supporting the delivery of safe, reliable, and affordable energy for our customers. In connection with this update, we announced our 2025 ongoing earnings forecast range of $1.75-$1.87 per share. The midpoint of this range, $1.81 per share, represents 7% growth from our original 2024 forecast midpoint and year-end result of $1.69 per share. Looking beyond 2025, we are extending our 6%-8% annual earnings and dividend growth through at least 2028, which is based off the 2025 forecast midpoint. Given the strength of our updated plan, we are confident that we can achieve the top half of our targeted growth rate range over this period. Underpinning these updated targets is a refreshed capital plan that includes $20 billion in expected infrastructure investments from 2025 through 2028. This compares to $14.3 billion in our prior plan period. Our updated plan includes a mix of investments aimed at strengthening the grid against current and future weather impacts, speeding up our ability to restore power when storms strike, and advancing a cleaner energy mix without compromising on reliability and affordability. These critical investments are expected to drive average annual rate-based growth of between 9.5% and 10% through 2028, up from 6.3% over the prior plan period, which strengthens the predictability of our growth targets. In support of customer affordability and a critical component of our strategy, we remain hyper-focused on improving operational efficiency across the enterprise. As for every dollar of O&M we can take out of the business, we can fund an average of $8 of capital without impacting the customer bill. I'm very proud of how our teams across PPL have embraced the drive to innovate and work smarter and more efficiently for our customers. We continue to expect cumulative annual O&M savings of at least $175 million through 2026, based off the 2021 baseline. Given the significant increase in capital needs in our updated plan, we expect to need $2.5 billion of equity through 2028. This supports our strong credit metrics, which we expect to maintain throughout the plan period. Finally, today we also announced a quarterly common stock dividend of $0.2725 per share. This represents approximately a 6% increase from the current quarterly dividend, which is at the lower end of our target range given the significant capital investment needs in our updated plan. Turning to slide six, over the past year, we've made substantial progress in our Utility of the Future strategy, which sets us up well heading into 2025. We've restructured our business and realigned departments and teams across PPL to better execute the strategy, implement best practices across the enterprise, increase operational efficiencies, and drive continuous improvement. These changes have already begun to yield significant benefits. We also kicked off an IT transformation initiative that will bring alignment of our systems across PPL. This included engaging with some of the world's leading technology companies, exploring new opportunities to apply cutting-edge technology to the utility industry to deliver a better experience for our customers and employees. As we continue to make decisions and plan for the future, we will increasingly use AI and other advanced technologies to inform our decisions, optimize our asset planning and maintenance, better manage supply and demand on the grid, and empower our customers through digital solutions and better service. I'm convinced our investments in technology will deliver better results at lower costs for our customers. Over the past year, we've also begun to execute our planned generation replacement strategy in Kentucky that will advance a reliable, affordable, and cleaner energy mix. Last fall, for instance, we broke ground on construction of a new 640 MW combined cycle natural gas plant at our Mill Creek facility. And throughout 2024, we continued to advance our plans for development of 240 MW of new company-owned solar and 125 MW of battery storage. We continue to drive innovation and invest in research and development, partnering with more than 30 different organizations on over 175 R&D initiatives, including one of the industry's leading carbon capture projects at our Cane Run Combined Cycle Natural Gas Plant in Kentucky. In addition, we've developed common design and operation standards across our utilities that will continue to bring advanced technologies, best practices, and more robust engineering and construction specifications for future grid designs. And while wildfire risks are low throughout most of the areas we serve, we take nothing for granted when it comes to public safety, and in 2024, we implemented wildfire mitigation plans at all of our utilities. We remain committed to help drive economic development in our service territories, including supporting significant data center build-out, as we recognize that data center growth and expansion is key to America's future economic competitiveness and national security. Finally, we continue to engage with key stakeholders to strengthen resource adequacy in PJM. In Pennsylvania specifically, we continue to advocate for a state-focused, no-regret strategy that addresses impending energy shortfalls and provides the state with additional tools to help protect customers from price volatility and reliability concerns. We believe one way to do this is to allow regulated electric utilities to invest in generation resources up to and including owning and operating generation again. This would complement the competitive market by addressing resource adequacy gaps rather than relying solely on market forces to deliver a solution. Turning to slide seven and a brief regulatory update, we continue to advance on several key regulatory proceedings across our jurisdictions and expect to file a few more this year. Starting in Kentucky, LG&E and KU continue to advance their latest integrated resource plan through the Kentucky Public Service Commission's review process. Since it was filed last October, the process has proceeded as expected, with a public hearing scheduled for May 13th. Our analysis continues to support the need for additional generation capacity by the end of the decade, and we've updated our capital plans to reflect our recommended path forward. Informed by this IRP, we expect to file a CPCN request later this quarter to address near-term generation needs. Finally, we anticipate filing a base rate case in Kentucky later this summer, with our current stay-out period ending on July 1st. As a reminder, LG&E and KU's last base rate increase was about four years ago in July 2021. Turning to Pennsylvania, PPL Electric Utilities continues to await a PUC decision on our petition to increase the distribution system improvement charge cap to 9% of revenue from the current cap of 5%. In late November, a PUC administrative law judge recommended the denial of our petition. Despite that recommendation, we continue to believe in the merits of our request. We've since filed exceptions to the recommended decision and await a final order from the commission. Also, in Pennsylvania, we continue to evaluate the timing of our next rate case, where we've not had a base rate increase since January 1st, 2016. The team has done an outstanding job of making critical investments while becoming more efficient, resulting in solid financial performance over that time period. We are evaluating the timing of a Pennsylvania rate case given increased capital investment needs, continued frequency and intensification of storms, and overall inflationary impacts. Turning to Rhode Island, in late December, Rhode Island Energy filed its annual electric and gas infrastructure safety and reliability plans for fiscal year 2026, which covers investments from April of this year through March of 2026. Our electric ISR filing seeks a total budget of about $260 million for infrastructure investments, including nearly $90 million for advanced metering functionality, which has already been approved by the Rhode Island Public Utilities Commission, as well as certain costs for vegetation management and other costs relating to maintaining safety and reliability. Our gas ISR filing, meanwhile, seeks a total budget of about $225 million to sustain and enhance the safety and reliability of our gas distribution system. Hearings on both plans will be conducted in March, with a decision expected by April 1st. Meanwhile, we continue to expect to file a base rate case in Rhode Island in the fourth quarter of 2025, following conclusion of our stay-out period on October 1st. Remember that as part of our transition plans for Rhode Island Energy, we had agreed not to file for a base rate increase until we had been off the transition service agreement with National Grid for a full 12 months. We completed the transition services in September of 2024. Moving to slide eight and an update on data center development in our service territories, we continue to see substantial interconnection requests in Pennsylvania and now have over 56 GW in our queue. While we continue to recognize that there's likely duplication in that figure, we have nearly 9 GW in advanced stages of development. We estimate potential transmission capital investment of between $600 and $700 million for these projects. We've included about $400 million in our updated capital plan, which was prioritized based on the requested interconnection dates. As we've shared previously, we expect that each new data center connection in Pennsylvania will lower transmission costs for customers, with savings expected to ramp up over the next several years as data centers begin to pay more significant transmission costs. In Kentucky, we were pleased to announce our first hyperscale data center customer in Jefferson County, the latest example of the state's success and our support in attracting economic development. The joint venture between PowerHouse Data Centers and Poe Companies will involve the development of a 400 MW data center campus located in Louisville. The first 130 MW are expected to come online in October 2026, with demand growing to the full 400 MW by 2028. Meanwhile, active data center requests in Kentucky continue to meaningfully increase and have doubled since our Q3 call, with nearly 6 GW of potential demand in our queue. In summary, we continue to see robust demand in both states and look forward to continuing to support these important customers. 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 10. PPL's fourth quarter GAAP earnings were $0.24 per share compared to $0.15 per share in Q4 2023. We recorded special items of $0.10 per share during the fourth quarter, primarily due to integration and related expenses associated with the acquisition of Rhode Island Energy and IT transformation costs. Adjusting for these special items, fourth quarter earnings from ongoing operations were $0.34 per share, a decrease of $0.06 per share compared to Q4 2023. On an annual basis, our 2024 GAAP earnings were $1.20 per share compared to $1.00 per share in 2023. Adjusting for special items recorded throughout the year, our 2024 ongoing earnings were $1.69 per share, an improvement of $0.09 per share compared to our 2023 results. Turning to the ongoing segment drivers for the fourth quarter on slide 11, our Kentucky segment results were flat compared to the fourth quarter of 2023. Kentucky's results were driven by higher sales volumes, primarily due to favorable weather compared to last year. The favorable weather impact was offset by higher operating costs, which included the higher vegetation management costs, as Vince mentioned earlier. Our Pennsylvania regulated segment results were also flat compared to the same period a year ago. Pennsylvania's results were primarily driven by higher transmission revenues, offset by higher operating costs in several areas, including increased vegetation management costs and an increase in uncollectibles. Our Rhode Island segment results decreased by $0.03 per share compared to the same period a year ago. This decrease was primarily driven by lower transmission and distribution revenues, which included a favorable annual ISR true-up recognized in Q4 2023. Finally, results at corporate and other decreased by $0.03 per share compared to the same period a year ago. The decrease was primarily due to higher interest expense from increased holding company debt balances and higher income taxes driven by higher tax credits that were recognized last year. Moving to slide 12, we continue to build a track record of delivering our 6%-8% annual growth target and achieve 7% growth from $1.58, our original 2023 forecast midpoint. Looking ahead, we remain extremely confident in our growth, and the plan we've rolled out today strengthens that even further. We've extended our 6%-8% annual EPS growth target another year to 2028 and expect to achieve growth in the upper half of that range. In our updated plan, our growth will be driven by the significant investment needs and the corresponding rate-based growth across the enterprise. In connection with that investment, we do expect to experience some regulatory lag over this period while needing equity to support this meaningful growth, and we are shifting from earnings driven by rate-based growth and O&M savings to growth primarily driven by rate-based growth. Our updated plan clearly positions PPL to deliver strong, sustainable growth for shareholders and improved service for our customers for years to come. Moving to slide 13, we've provided a walk from the midpoint of our original 2024 ongoing earnings of $1.69 per share to our 2025 forecast midpoint. Starting with our Kentucky segment, we project results to increase by $0.05 per share in 2025. The increase is projected to be driven by higher sales volumes due to a return to normal weather and modest weather-normalized growth, lower operating costs, and higher AFUDC income related to new generation and AMI projects. These increases are expected to be partially offset by higher interest expense due to higher projected debt balances as we finance our capital investments. In Pennsylvania, we also project segment results to increase by $0.05 per share in 2025. Returns on additional capital investments in transmission and lower operating costs are projected to be partially offset by higher interest expense due to higher debt balances. Rhode Island segment results are expected to increase by $0.04 per share in 2025 compared to our 2024 results, primarily due to increased rider revenue from capital investments and lower operating costs, partially offset by higher interest expense. Finally, we project our corporate and other results to decrease by $0.02 per share in 2025, primarily due to higher interest expense. Our 2025 earnings forecast does not include the impact of any base rate cases in any of our jurisdictions, as we do not expect any rate increases to take effect until January 2026 at the earliest. Turning to slide 14, over the next four years, we have planned capital investments of $20 billion to meet the growing demand needs on our networks, to continue to provide reliable service and enhance the overall customer experience, and to support economic expansion in our service territories. This includes advancing industry-leading grid modernization, expanding and hardening our transmission and distribution networks, improving the safety of our natural gas networks, implementing our approved generation replacement plan in Kentucky, and building new generation that is necessary to support future load growth. This plan represents a $5.7 billion increase in capital investments compared to the prior four-year plan, with nearly $4 billion of that increase expected to occur between 2025 and 2027. Most of the increase in that timeframe is projected to be in Kentucky and Pennsylvania. In Kentucky, we see nearly $1.3 billion of additional investments related to new generation to support the growing demands in our service territory and additional environmental retrofits on our coal fleet. The new generation investments assumed in our plan aligns with the recommended resource plan submitted in our IRP, including two combined cycle natural gas plants with 2030 and 2031 in service dates and 400 MW of battery storage by 2028. We also project about $500 million of additional transmission and distribution investment to strengthen and modernize the grid, which is critical given more intense and frequent storms, including significant impacts from tornadoes. In Pennsylvania, we see nearly $1 billion of additional distribution system investment needed to support grid resiliency and another $200 million of transmission investments to support data center growth. In addition, we added nearly $600 million of IT investments across the enterprise. These needed upgrades will enhance cybersecurity, improve our customers' experience, and enhance the efficiency of our back office functions like finance, supply chain, and human resources. We continue to expect significant investment needs into the end of this decade, as reflected in our 2028 forecast of $5 billion. This includes investments needed to continue to replace aging infrastructure, increase reliability and resiliency, and construct new generation in Kentucky to support growing demand and economic development in the region. Turning to slide 15, these additional capital investments are projected to lead to annual rate-based growth of 9.8% from 2024 to 2028. This compares to annual rate-based growth of 6.3% in our prior planned period from 2023 to 2027. As shown on the slide, two-thirds of our rate base relates to investments in our electric T&D networks, given the significant needs as we strengthen and modernize the grid. The percentage of our total rate base related to coal generation is expected to be less than 11% by the end of 2028, down from about 16% today. Coal will remain a critical generation resource for us in Kentucky well into the future, especially given the expected load growth in the region. However, as our coal plants reach the end of their useful lives, with the next significant tranche of retirements expected in the mid-2030s, we continue to expect to replace that coal generation with a mix of natural gas, renewables, and energy storage solutions. In summary, you can see the updated capital needs drive meaningful growth in the company's rate base. While we are transitioning to a more traditional rate-based growth-driven model, delivering operating efficiencies will remain central to our strategy to continue to support customer affordability. We remain keenly focused on optimizing our business, which will allow us to continue to make prudent investments in the most efficient manner. Moving to an update on PPL's credit on our financing plan for 2025 on slide 16, 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. And our updated business plan maintains strong credit metrics throughout while supporting our earnings growth targets. This includes maintaining a 16%-18% FFO to debt ratio and a holding company to total debt ratio below 25%. We expect equity needs of $2.5 billion over the planning period to fund the growth associated with the increased capital investments. We plan to establish an ATM program to support these financing needs and then complement that with other equity-like financing structures to the extent they provide an efficient cost to capital. In terms of debt financing, we have limited near-term refinancing risk with only $550 million of total utility maturities in 2025. And we continue to maintain limited floating rate debt exposure with approximately 5% of total long-term debt at year-end. Our solid financial foundation keeps us very well positioned to execute our updated business plan and growth targets while we deliver value for customers and share owners. Moving to slide 17, we continue to view the dividend as an important piece of total shareholder return. Today, our board of directors declared a quarterly cash dividend of $0.2725 per share to be paid on April 1st to share owners of record as of March 10th. This results in an annualized dividend of $1.09 per share compared to our prior annualized dividend of $1.03 per share, approximately a 6% increase. We continue to target future dividend growth within 6%-8% per year. We expect dividend growth to remain at the lower end of the range through the current planned period given the meaningful CapEx plan. The combination of PPL's EPS growth and current dividend yield continues to provide investors with attractive total return proposition in the range of 9%-12%. This concludes my prepared remarks. I'll now turn the call back over to Vince. Thanks, Joe. In closing, I remain as excited as ever about PPL's future. We have positioned the company as an agile, forward-looking organization poised for long-term growth and success. That growth is backed by a robust capital plan featuring $20 billion in infrastructure improvements from 2025 through 2028. Through at least 2028, we offer investors visible and predictable long-term earnings per share growth in the top half of the 6%-8% range, with dividend growth closer to 6% given the significant capital investments in the updated plan. It's also a plan that our customers can afford and one where they can continue to expect reliable service and continued improvement to the overall customer experience. We maintain one of the strongest balance sheets in our sector, a clear strategic advantage that provides significant financial flexibility, and importantly, we have a strong track record of operational excellence, consistently delivering top quartile transmission and distribution reliability and top decile generation reliability. We have the right strategy for the right time. Our vision is to be the best utility in the U.S., and we're absolutely determined to achieve this vision. With that, Operator, let's open it up for questions. We will now begin the question and answer session. To ask a question, you may press *, then one on your touch-tone 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 *, then two. At this time, we will pause momentarily to assemble our roster. The first question today comes from Durgesh Chopra with Evercore ISI. Please go ahead. Morning, Durgesh. Hey, good morning, team. Sorry, I was on mute talking to myself. Hey, congrats on the update here and the capital plan raise. Just, I had two questions. One on the Kentucky CPCN, maybe just updated thoughts there. What are you as you get closer to that filing? How many megawatts capital investment? I assume it's included in the $1.3 billion capital increase for Kentucky, but just thoughts there and when to expect a final decision. Yeah, Durgesh. So what we've updated in the capital plan is our recommended resource plan that we had in the IRP that we had filed and is currently going through review with the commission. In total for generation in the plan, we've added about $2.5 billion. That includes two new combined cycle plants with a 2030 and 2031 in service date. Includes 400 MW of additional battery storage projects within service dates in the 2028 timeframe that is needed to cover us before the CCGTs come online with expected load growth from large load customers in Kentucky. And then it also includes some additional environmental spend on the coal fleet, including the SCR on Ghent. Perfect. Thank you. Thank you for that, caller. Presumably, all of that will be captured in the CPCN filings, or are those going to be staged? Yeah, that's consistent with the recommended resource plan, which will be the basis for the CPCN. We'll file that by the end of the first quarter. We would expect a decision by the fourth quarter. Excellent. Thank you. And just quick follow-up question on the equity issuance. Should we assume that ratable $2.5 billion, or just any color and timing on how you issue that equity? Yeah, Durgesh, it's Joe. So I mean, look, we have flexibility on the timing of those issuances given the quality of the balance sheet. And as I indicated, we may complement that ATM with other equity-like financing structures. But I mean, look, I think for modeling purposes, you could assume something in the order of $400 million-$500 million this year and then sort of tracking the capital plan as we go through the planned period. But again, we'll be flexible, and we'll take advantage of the market conditions as we have the funding needs. Excellent. Thank you, guys. Appreciate the time. Thanks, Durgesh. The next question comes from Paul Zimbardo with Jefferies. Please go ahead. Hi, good morning. Thank you very much. And to follow up on the equity side of the equation, if you could help unpack the comment you had about complement with other equity-like financing structures, is that there's other equity linked in the debt? That's something you could do to reduce equity financing. If you could just explain that a little bit, please. Yeah, sure, Paul. I mean, yeah, and you're right. There's obviously hybrids get 50% equity treatment from the agencies. And so I think from a base assumption, we view the ATM as a cost-effective tool to issue that equity, but there's other means to do that. And so we'll be, as I said, opportunistic around that. And there's points in times that there's funding means that are more efficient than others. And so given the balance sheet and the position that we're in, we have the flexibility to do that. And so we'll take advantage of market conditions as they come. Okay. I understand there. And then shifting back to Kentucky generation and just the data center opportunity set now that you kind of have filled the entire 400 MW bucket, just if hypothetically there was a 1 GW data center in Kentucky, could you just describe what kind of lead time, ability to serve you have pro forma for the new combined cycles that you're adding? Yeah, sure. So just when we think about reserve margins in Kentucky, right, our summer margins for this year are just over 20%, Paul, and then winter is around 27-ish%. With the in-service date of our Mill Creek CCGT, Mill Creek 5, which is expected to go in service in 2027, we would be able to accommodate the 400 MW of data center load that we recently announced, but not much more. As you know, with the load growth that we're projecting, right? And with what we filed in the IRP for the two additional CCGTs to go into service in 2030 and 2031, that's why we're also including 400 MW of batteries to provide an interim solution between that first CCGT going online in 2027 and then the second two in 2030 and 2031. So that's really the basis for that battery solution in that 2028 timeframe. Okay. So if there is a pickup in Kentucky load, whatever class, that would require more generation. Is that fair? Yes. Okay. Thank you very much. Sure. The next question comes from James Kennedy with Guggenheim. Please go ahead. Hey, guys. Good morning. Congrats on the role. Thanks for taking the questions. So Vince, if I could just come back to resource adequacy in Pennsylvania. You mentioned regulated generation and the PJMs. It seems like some stakeholders still want to wait for competitive entry. So I guess maybe just some more color on what you see as a pathway forward here in this legislative session and in your view, how much of a time cushion really remains? Yeah. Look, obviously, this is a major legislation around energy policy in the state. We are clearly an energy leader in PJM as really the state that drives most of the generation in PJM, as we know. So energy policy and PA will be critical as we think about state resource adequacy, but also PJM. So obviously, there's been no legislation proposed yet. We are very actively engaged with the governor's office, various legislators, of course, with the PUC. I would say those discussions remain constructive. We would expect some proposed legislation to be proposed in this legislative session, perhaps as early as the spring or summer. We've talked a bit about what could be in that legislation. I think there's a number of things that we've heard from various legislators. Obviously, we're talking quite a bit about permitting utilities to invest in and ultimately own and operate generation again in rate-based. So that could be one. They could create incentives within the bill for utilities and the market, i.e., the IPPs, to enter into long-term power purchase agreements beyond what is currently allowed under our default service plans, which is pretty limiting. We've seen ideas floated with proposals like the Texas Energy Fund. Senator Yaw has the Basel oad Energy Development Fund, very similar to the Texas Energy Fund, low-cost financing to help lower the cost of new entry for generation. So I could see any or all of those potentially making it into legislation. And again, we'll support ultimately whatever the state wants to do that supports getting generation built in Pennsylvania and supporting PJM resource adequacy. Okay. Got it. And then just on the Pennsylvania data center spend, so you rolled in $400 million, I think, with this update, but there's more to go. So just how should we think about cadence of updates on that balance? Will you update throughout the year? Do you have to wait for customer announcements? Just any more color there. Thanks. Yeah, sure. We'll certainly be able to provide updates on that as we go through the year as we kind of think about Pennsylvania and the 6 GW or so that's in the queue. Obviously, we believe there's duplication in that number. But as we kind of peel that back a bit, right, we have the 9 GW of projects in advanced stages. So we have a higher degree of confidence on those. But kind of if I take a 50/50 probability, the projects that would kind of fit in that 50/50 bucket, that 9 GW goes to 12 GW or 13 GW. So we'll certainly be keeping an eye on those projects as they progress through the development process and move up into that advanced stage. But you're right, of the $600 million-$700 million, we've only included $400 million in the plan. And clearly, we'll provide updates to that as those projects continue to move in the development phase. Perfect. Thanks, guys. The next question comes from Jeremy Tonet with J.P. Morgan. Please go ahead. Hi, good morning. Hey, Jeremy. Good morning. Just wanted to, I guess, circle back on customer bills and how you think about that at this point in time, the amount of headroom there. Given a big step up in capital, just wondering how you feel about that dynamic going forward. Yeah, Jeremy, it's a great question, right? I'll just reiterate, and you guys know this about us and our strategy all along that we keep affordability top of mind and front and center. It is such a key component of our strategy. It's why we remain so focused on driving efficiencies across the business, right? We've talked about that eight to one ratio for every dollar of O&M we can take out of the business. We can fund on average $8 of CapEx and not impact the customer bill. So even beyond the 175-26, we will remain laser-focused on continuing to drive cost out of the business primarily for affordability reasons. When we look at this plan update, we believe that we can execute the updated plan without unduly impacting affordability as we would expect average bill increases to generally remain within the rate of inflation. So again, we think our customers can afford this plan. Got it. Thank you. And then ahead of upcoming filings in Kentucky, just wondering any more thoughts you could provide with conversations with the commission, stakeholders there, given the newer composition of the commission. Just wondering any other thoughts there. Nothing out of the ordinary. This should be a clean CPCN. It will track the IRP recommended resource plan. So obviously, the commission is reviewing the IRP right now. We would expect them to issue their order on the IRP by mid-July. That's just how that process progresses. Obviously, we're not waiting for that decision necessarily before we would file our CPCN, but a lot of consistency there. So not expecting there to be any surprises at the commission level with these filings. Got it. And just a quick last one, if I could. The 6%-8% EPS kicker you outlined there, just wondering, I guess, how you see the cadence of growth across that. You expect 7% next year or just wondering if there's any dynamics to that trajectory? Yeah. Generally, I would say it's linear. So we're continuing to maintain linear growth off of our new midpoint for 2025. Got it. That's helpful. I'll leave it there. Thanks. Great. The next question comes from Paul Patterson with Glenrock Associates. Please go ahead. Hey, good morning. Good morning, Paul. So just to sort of follow up here with the potential for new generation, utility-owned generation, it would appear in the current auction environment that that could substantially lower wholesale costs. And I'm just sort of wondering how you see that working and when the soonest, I mean, assuming that, let's say, you did get legislation this year, when that could show up if you follow what I'm saying, just sort of a timing on that. Yeah. So as I think about the capacity auctions maybe more broadly, Paul, right, our governor actually negotiated a settlement with PJM to cap the auctions at a ceiling of 325 per megawatt day and a floor of 175. That's for the next two auctions. And look, I don't think it's unreasonable to believe that those auctions wouldn't clear at the caps of 325. A lot will go into those when you think about just the higher load curves coming from data centers across all of PJM, seeing a lot of interest, as we know, clearly from us, but also our peers. So clearly, we're expecting that demand curve to go up. Look, at those higher prices, though, I would expect some of the generation that was in the queue to retire in the prior auction would likely come back in. So that could help mitigate some price increases. But ultimately, over the next two auctions, I don't think it's unreasonable that we'll see that cap cleared. If we go through this year with getting legislation approved where utilities could own again, there would be some period of time where either the PUC or some other regulatory body that needs to kind of administer that new law would need to get stood up and kind of figure out how they're going to go through the process to approve generation. Not exactly sure how long that would take, but I would expect six-plus months for that to happen, and then, of course, we know what the supply constraints are with getting new turbines installed. If you're talking about combined cycle plants, obviously, it's a little bit less if you're talking about peakers, but so figure kind of three to five years to get generation then built, so it's certainly a long-term gain. But obviously, once we start to be able to put new generation in those future auctions, that's what could help temper the pricing, as you know. Okay. And then with respect to the DSIC, the D-S-I-C, I apologize if I missed this, but at least from what I was thinking, I was thinking it was going to maybe be addressed a little bit earlier. Is there any time frame? If you could just give us a little update in terms of what you expect it to be. I apologize if this was answered already, but if you could just help me on that. Sure. Yeah, Paul, it's Joe. Yes. We're still waiting for the commission decision on the DSIC waiver. I don't know when that will be, and so we'll just wait for the commission to make a decision there. There's nothing scheduled at this point that I could point you to, so we just continue to wait. And there's no issue, though, or anything that's come up that we should be aware of? No, not from the commission perspective. We're just awaiting the decision. Okay. Great. Thanks so much. Thanks. As a reminder, if you have a question, please press star, then one to be joined into the question queue. The next question comes from Angie Storozynski with Seaport. Please go ahead. Thank you. I'm not going to ask about Pennsylvania or the legislative session. I'll let that go for now. But instead, okay, so you have this very meaningful increase in the rate-based growth. And yes, it comes with additional equity. And I'm actually surprised that it doesn't result in an increased earnings growth trajectory. Also speaking about the equity, I mean, you have this particularly strong balance sheet in the utilities industry. You're not leaning into it to finance the growth, hence the incremental equity. Again, it's hard to believe that, again, the low growth is accelerating, not the low growth, the rate base is accelerating so much, and yet there is no commensurate increase in the earnings growth. Yeah, Angie, it's Joe. Maybe let me touch on the balance sheet first, and then we can talk about growth. I mean, look, we have a strong balance sheet, and we think that gives us a strategic advantage that we certainly want to maintain. And we believe that the strong earnings growth that we have, along with the strong balance sheet, puts us in a great position to deliver value for shareholders over the long term and mitigate risks that could come, risks and uncertainties that we could see in the future. And so our focus is on the long term, not short term, maybe pops or what have you in an earnings growth rate, but to deliver for the long term. And we think the combination of that growth and that balance sheet allows us to do that. And that's why we want to have the equity in the plan to finance the growth that we've talked about today. As far as where we are within that growth rate range, I mean, look, I think having a gap between rate-based growth and earnings growth certainly is not uncommon. And some of that is obviously driven by the equity financing needs. But as we put together our business plan, there's a lot of assumptions that go into developing a business plan. And I think we've made reasonable assumptions there. And those reasonable assumptions give us the confidence in our growth rate. But as always, we'll be laser-focused on optimizing around those. That's execution of the capital plan, execution of the financing plan, regulatory outcome, O&M management, storm response. And that's just to obviously name a few. And certainly, that gives us the ability to offset any uncertainties if they arise. And if not and we're successful in optimizing that, then we would certainly do better than our base assumption. And that's where our focus lies. Okay. And then on the 2024 results, so the cold weather drag was probably the biggest surprise here. I understand the interest rate angle, but is there, so when I look at 2024 and the future years, is there an additional tax component, the benefit which will go away, which would sort of exacerbate the drag, especially beyond 2025? I'm sorry. I missed the first part of your question. No, because you said that the reason why there was such an increase in the [Holdco] drag or the corporate and other drag versus 2023 was because there was some tax benefit reflected in 2023 results versus 2024. So I'm asking if there is any remaining tax shield that will go away that will exacerbate the drag beyond 2025. Yeah. Sorry. Yeah. Sorry. I understand the question. No, what there is on the year-on-year results is we did have some tax benefit in 2023 with the transferability of tax credits and our ability to utilize those from prior periods, particularly around the sale of WPD, and so that's just a year-on-year variance that you're seeing. I wouldn't expect that to go forward, right, in that regard. Okay. Thank you. Thanks. Yep. Sure. The next question comes from David Paz with Wolfe Research. Please go ahead. Hey. Good morning. Thanks for the time. Actually, before I get to my question, I had just a clarification on the EPS growth annual cadence question earlier. When you said you expect to be linear, is that fair to say each year you expect to be on the upper half of that range, so like seven to eight each year? Or did you mean just with the six to eight? Okay. Yeah, David, it's Joe. Maybe just obviously for 2025, we're showing a 7% growth rate there. And that's kind of what we've delivered since we're strategic repositioning. And we've come out with a new plan. And we've done that without rate cases. And there's no rate cases effective in 2025 in this plan. And we certainly don't expect to have any. So I think once we get beyond the rate case period, that's where we see the growth in the upper half of the range. Great. Yeah. So 2025 is really the last year that we're kind of in the stay-outs across all three jurisdictions. So moving from earnings growth coming from rate-based and O&M efficiencies to more rate-based driven. So as Joe said, kind of delivering that 7% to midpoint through 2025 and then being able to do better than that once we kind of get back into a normal rate case cycle. Great. That makes sense. Actually, just on rate cases or more specifically your earned returns, just what are you embedding for Kentucky and Pennsylvania in your long-term outlook? If you don't want to get specific, just kind of a sense of how they compare relative to where we currently see ROEs in those segments. Yeah. So we've obviously, through this period of staying out of rate cases, done a great job in managing O&M for the ultimate benefit of customers and affordability, and that's helped support ROEs that are at or near the allowance. Obviously, with the significant increase in the capital plan, that'll put some pressure on those. We are going into rate cases kind of across the board here over the planning period. And so I don't want to get into specifics around rate case or rate ROE assumptions. I think, again, they're reasonable to that point. And we do experience some level of lagging between rate cases, but that's something that we'll stay focused on and work to minimize and earn around our allowed ROEs. Great. Thank you. And then just actually on the costs of your gas of 2031, do you have a rough estimate of what the dollar per kilowatt is? Are they in the ballpark of Mill Creek 5's update, or are they higher? The cost of the CCGTs in 2030 and 2031, is that what you're asking? Yes. Yeah. Right now, I mean, you'll see those in the CPCN. We're kind of refreshing all of that right now, so I don't want to get in front of that. But ultimately, they're similar to what we're seeing with Mill Creek 5. Great. Thank you. This concludes our question-and-answer session. I would like to turn the conference back over to Vince Sorgi for any closing remarks. Great. Thanks, everybody, for joining us. Looking forward to getting out on the road and seeing you all to discuss this in more detail. So thanks again for joining us, and we'll see you soon. The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.