David Arcaro; Analyst; Morgan Stanley & Co. LLC
Jeremy Tonet; Analyst; J.P. Morgan Securities LLC
Durgesh Chopra; Analyst; Evercore Group L.L.C.
Good day. And welcome to the PPL Corporation third-quarter 2024 earnings conference call. (Operator Instructions) Please note this event is being recorded.
I would now like to hand the call 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 2024 financial results. We have 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 will 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 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 third-quarter investor update. Let’s start with our financial results and a few highlights from our third-quarter performance on slide 4.
Today, we reported third-quarter GAAP earnings of $0.29 per share. Adjusting for special items, third-quarter earnings from ongoing operations were $0.42 per share. Given the strength of our year-to-date performance, we narrowed our 2024 ongoing earnings forecast to a $1.67 to $1.73 per share from the prior forecast range of a $1.63 to a $1.75 per share. As a result, we’ve increased the midpoint $0.01 to $1.70 per share.
Throughout the third quarter, we continue to make excellent progress on delivering 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. And through our ongoing business transformation initiatives, we’re on pace to achieve our annual O&M savings target of $120 million to $130 million this year 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’re focused on executing our capital plan, which includes $14.3 billion in infrastructure improvements from 2024 to 2027 with continued potential upside driven by data center connections in Pennsylvania and Kentucky, new generation in Kentucky, new enterprise-wide technology investments, and additional resiliency investments across all of our jurisdictions as we combat more frequent and severe storms.
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, which again is compared to our 2021 baseline.
Moving to slide 5, on October 18, LG&E and KU submitted their updated integrated resource plan or IRP to the Kentucky Public Service Commission. The IRP provides a robust analysis of a wide range of variables, including demand growth, fuel prices, supply side resource costs, and pending environmental regulations all to guide our resource planning. This year’s IRP examined 300 potential resource portfolio and fuel-price combinations to arrive at a plan to most effectively meet forecasted demand over the next 15 years.
It’s important to note that the IRP is submitted for informational purposes only. That said, the detailed analysis provides reasonable insights about future generation needs and helps us to identify no regrets recommendations, given there is uncertainty with some of the inputs. Key drivers in our latest IRP analysis includes stronger demand forecast and higher costs for new supply side resources from what we saw in our last IRP, which was filed three years ago in 2021.
In terms of demand, our mid-load scenario reflects load growth of nearly 1.5% annually through 2039, but more importantly, projects annual load growth of over 3% through 2032, which is significantly impacted by projected data center load.
We evaluated several scenarios for data centers ranging from zero to nearly 2 gigawatts of new load by 2032, with the mid-load scenario assuming just over 1 gigawatt. Based on the interest levels that LG&E and KU have already seen from developers, we view no or low data center growth as unlikely.
Regarding the cost of new generation, we’ve seen those costs increased markedly since our 2021 IRP except for batteries. That increases the relative value of our existing generation resources and significantly impacted the generation mix recommended in this year’s IRP.
Regarding the battery cost, this is the first time in our ongoing resource planning that the sum of capital and non-fuel O&M cost for battery storage, with tax incentives included, is less than the cost of new simple cycle combustion turbines. For this reason, our recommended plan includes the addition of 900 megawatts of battery storage.
Importantly, due to the price increases in solar generation, we are not assuming the 637 megawatts of solar PPAs that were approved by the KPSC and our 2022 CPCN get built.
As noted in our IRP, the impact of environmental regulations remains a key uncertainty as three major regulations are the subject of current federal court challenges. Our IRP modeled four different environmental regulation scenarios ranging from none to all of the regulations becoming enforceable. The updated IRP assumes all resources and retirements approved in our last CPCN proceeding are completed as planned by 2028, except for the solar PPAs that I just mentioned. This includes our approved plans to retire 600 megawatts of aging coal and 50 megawatts of aging peaking units by 2027.
In addition, it includes building a new 640-megawatt natural gas combined cycle unit, 240 megawatts of company-owned solar, and 125 megawatts of battery storage. Above and beyond this generation, the IRP lays out several resource plans, including two we’ve referenced on this slide, a recommended resource plan as well as an enhanced solar plan applicable in certain scenarios.
The recommended plan reflects our no regrets approach to planning much like our latest CPCN filing. That includes important generation development, even if scenarios that reflect high-economic load growth or CO2 regulations do not come to fruition. This plan projects the need to build an additional 2,700 megawatts of new generation from 2028 through 2035 to safely, reliably, and affordably serve future demand growth.
This includes two new 650-megawatt combined cycle natural gas plants, one in 2030 and another one in 2031. That includes the addition of 400 megawatts of new battery storage in 2028 and 500 megawatts of additional battery storage in 2035. It also includes 500 megawatts of solar in 2035.
The recommended plan also projects the need to add new environmental controls at the Ghent and Trimble County coal plants to ensure compliance with ELG and NOx regulations. The enhanced solar plan, meanwhile, differs from the recommended plan only in the timing and level of new solar generation added. Rather than adding 500 megawatts of solar in 2035, the enhanced solar plan would accelerate and boost solar additions to 1,000 megawatts by 2032 to address potential data center interest in carbon free generation or a faster-than-projected decline in solar prices.
Based on our analysis of current factors, we see potential additional generation needs ranging from 2,700 to 3,200 megawatts with associated capital investments including the environmental retrofits for the coal plants of $6 billion to $7 billion to 2035 using current pricing estimates. We also evaluated the prospects of joining an RTO in our review of options, which concluded that we would be introducing significant unquantifiable risk to our customers, which is not surprising based on what we are seeing in other RTOs.
Our next steps in the IRP process are to engage with the KPSC over the next few months and discuss the various plans we’ve provided. We would expect to file an additional CPCN request as early as the first quarter of next year to address near-term generation needs for our customers.
Moving to slide 6 and an update on data center development, our Pennsylvania and Kentucky service territories continue to attract growing interest from data center developers. In our Pennsylvania service territory, we now have over 39 gigawatts in our queue with 8 gigawatts in advanced stages of planning, up from the 5 gigawatts we highlighted during our second-quarter call in August. We estimate these 8 gigawatts represent incremental PPL capital needs of $600 million to $700 million in the 2025 to 2029 time frame, none of which are reflected in our current capital plan. Note that we’ve included these types of projects in our latest PJM large load forecast, which shows that PPL Electric has the second highest projected peak load additions in PJM through the end of this decade.
It’s important to note that projects in the queue may include duplicates due to developers assessing multiple sites for the same project. And it’s important to highlight that all the projects in our queues are in front of the meter projects. Projects in the advanced planning stages have signed agreements. They are in various stages of PJM’s review process, with some having completed those reviews. Costs incurred by PPL for these projects are reimbursable by developers, even if they do not move forward with the projects.
Recall that each new data center connection will lower transmission cost for customers. The savings are expected to occur as the data center load ramps up over the next several years and the data centers begin to pay transmission charges. In terms of the amount, we estimate that for the first gigawatt of data center demand that’s connected to the grid, our residential customers could save nearly 10% on the transmission portion of their bill, assuming a PPL investment level of about $100 million, which for the average residential customer and based on current rates would represent about $3 per month in savings.
While additional data center connections will also lower transmission costs for customers, the amount of those savings will depend on a number of factors, including timing of load ramp, the amount of investments required, and the peak load on our system.
Turning to Kentucky, we have about 400 megawatts in advanced stages of planning with potential to increase up to 1 gig. Active data center requests in Kentucky now total nearly 3 gigawatts of potential demand, an increase from 2 gigawatts at the time of our second-quarter call. 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.
As I shared earlier, the recommended plan in our IRP projects a need for additional natural gas and battery storage, beyond what was in our CPCN approved last year to support longer-term economic development and data center load growth.
Moving to slide 7 and several key operational and regulatory updates, LG&E and KU responded well to the remnants of Hurricane Helene, which knocked out power to more than 224,000 customers and resulted in 1,600 downed wires and 160 broken poles. This storm was the fourth most significant weather event for the region in the last 20 years.
We restored 95% of our customers within four days and all customers capable of receiving service within six days. And a great example of our one PPL strategy crews from our Pennsylvania operations and more than 400 contract resources aided in the effort. We’ve since requested regulatory asset treatment for about $11 million in operating expenses tied to our restoration efforts.
Once our restoration efforts in Kentucky were complete, we were proud to send over 400 employees and contractors from our utilities in Pennsylvania, Rhode Island, and Kentucky to support our colleagues in Florida, Georgia, and Virginia, following the significant damage sustained by Hurricanes Helene and Milton.
Mutual assistance is one of those areas that makes our industry truly unique, and I thank all the men and women on our teams that provided that much needed support. I also thank all the men and women from ComEd, Duquesne Light, NIPSCO, and CenterPoint that helped us in our efforts to restore power to our Kentucky customers during hurricane Helene.
And other updates from Kentucky, in October, we filed a request with the KPSC to recover $125 million in retirement costs associated with Mill Creek 1, which is set to retire by the end of this year. We requested approval to recover the cost through the retired asset recovery rider or RAR in our first filing under this new mechanism. The rider provides cost recovery over a 10-year period upon retirement of such assets as well as a return on those investments at the utilities then weighted average cost of capital. The implementation of the RAR rider, if approved, will result in a slight bill credit for customers beginning in May 2025 based on the current procedural schedule established by the commission.
Turning to Pennsylvania, our disc waiver petition to increase the disc revenue cap from 5% to 9% continues to proceed through the process as expected. We’ve completed the briefing process and anticipate a recommended decision in November from the ALJ that’s assigned to the case with a PUC decision to follow in early 2025.
Also in Pennsylvania, PPL Electric Utilities yesterday announced new price to compare rates effective December 1. The new residential price to compare represents about a 2% decrease compared to last year’s winter price to compare price.
In all aspects of our business, our companies remain very focused on affordability for our customers. This focus also extends to how we purchase power for non-shopping customers and PA. With this in mind, we were pleased to reach a settlement with the parties to our latest default service program and procurement plan filed with the PUC. We are seeking approval of our plan to procure electricity from June 1, 2025, through May 31, 2029, to meet PPL Electrics provider of last resort obligations.
Our latest plan, which we filed in March, includes modifications to the current product mix and auction timing that PPL Electric uses to buy power. These modifications are intended to strengthen price stability and lower prices for customers while supporting resource adequacy and fostering the continued growth of renewable generation. We expect the PUC decision on the settlement by the end of the year.
Shifting to Rhode Island, I am pleased to report that we completed the integration of Rhode Island Energy into PPL in the third quarter. Exiting the transition services entered into — with National Grid when we acquired Rhode Island Energy in May 2022. I can’t say enough about how well our teams rallied as one PPL to deliver this outcome, which involve exiting more than 130 transition services in phases over the past two years.
It was truly a team effort from Rhode Island to Pennsylvania to Kentucky as well as everyone at National Grid that worked so hard to make the transition possible. We’re excited to have Rhode Island Energy now fully integrated to best serve our customers.
Finally in September, the Rhode Island Public Utilities Commission approved the company’s winter last resort service rates as filed. The rate for non-shopping residential customers effective October 1, reflects an 8% decrease from last year’s winter rate and we’re pleased to be able to pass those savings on to our customers.
I’ll now turn the call over to Joe for the financial update.
Joseph Bergstein
Thank you, Vince, and good morning, everyone. Let’s turn to slide 9.
PPL’s third-quarter GAAP earnings were $0.29 per share compared to $0.31 per share in Q3 2023. We recorded special items of $0.13 per share during the third quarter., primarily due to integration and related expenses associated with the acquisition of Rhode Island Energy.
Adjusting for the special items, third-quarter earnings from ongoing operations were $0.42 per share, a decrease of $0.1 per share compared to Q3 2023. Turns on capital investments and higher sales volumes, primarily due to favorable weather in Kentucky, were more than offset by higher operating and financing costs quarter over quarter. For Q3 2024, we estimate that weather was about $0.01 favorable compared to normal conditions with cooling degree days up about 13% in our Kentucky territories over the quarter.
Turning to the full year, through the first nine months of 2024, our GAAP earnings are now at $0.96 per share compared to $0.85 per share to the same period last year. Adjusting for special items recorded through the third quarter, earnings from ongoing operations totaled $1.34 per share for the first nine months of 2024. This represents an improvement of $0.14 per share compared to the same period a year ago, which puts us in great shape heading into the fourth quarter to achieve our financial targets for 2024.
Turning to the ongoing segment drivers for the third quarter on slide 10, our Kentucky segment results were flat compared to the third quarter of 2023. Kentucky’s results were driven by higher sales volumes due to the favorable weather offset by an adjustment to environmental cost recovery revenues. That was recognized during the quarter.
Our Pennsylvania regulated segment results decreased by $0.01 per share compared to the same period a year ago. The decrease was driven by higher operating costs in several areas including higher storm cost, increased vegetation management, and an increase in uncollectibles. These higher operating costs were partially offset by higher transmission revenues.
Our Rhode Island segment results increased by $0.01 per share compared to the same period a year ago. This increase was primarily driven by a favorable adjustment to property taxes. And finally, results at corporate another decreased by $0.01 per share compared to the same period a year ago, primarily due to higher interest expense due to an increase in long-term debt. In Q3, we were opportunistic amidst increased market volatility and issued $750 million of senior notes at PPL capital funding at a rate of 5.25% that mature in 2034.
We saw significant demand for the deal which we believe is attributable to PPL’s excellent credit position with one of the strongest balance sheets in the sector. With another solid quarter behind us, we’re on track to deliver on our financial targets for our shareowners.
We expect to exceed the midpoint of our original 2024 ongoing earnings forecast as reflected in our updated forecast range of $1.67 to $1.73 per share with a midpoint of $1.70 per share. And we remain extremely well positioned for continued long term growth. As Vince outlined, we see an improving fundamental backdrop that we believe will require significant capital investments to advance our utility of the future strategy that can satisfy our customers evolving needs and ensure we can continue to deliver safe and reliable service.
We strategically position PPL with the financial flexibility needed to support these critical investments while continuing to deliver on our earnings growth targets. But we’re as excited as we’ve ever been for the prospects of PPL.
This concludes my prepared remarks. I’ll now turn the call back over to Vince.
Vincent Sorgi
Thank you, Joe.
In closing, we continue to deliver across the board on our commitments to shareowners and customers in the third quarter. This includes executing our capital plans on time and on budget to strengthen grid reliability and resiliency, advancing sustainable efficiencies to help keep energy affordable for our customers, completing the successful integration of Rhode Island Energy into PPL, responding quickly and effectively to major storms to restore power and peace of mind for our customers and communities, and advancing our responsible generation investments in Kentucky as well as responsible resource planning to deliver a safe, reliable, affordable, and cleaner energy mix.
As we work to close out 2024, I continue to be very proud of our team here at PPL. I’m confident in our utility of the future strategy. I’m proud of the progress we’re making as we execute that strategy. And I’m excited about the opportunities ahead as we move into 2025.
With that operator, let’s open it up for questions.
Operator
(Operator Instructions)
Shar Pourreza, Guggenheim Partners.
Shar Pourreza
Good morning. Vince, I know sort of this resource adequacy topic has been kind of a perennial question with the Eastern wires companies during this earnings season. And obviously, to your credit, you’ve been one of the first to highlight the issues and kind of talk about the solutions over a year ago.
The auction is now delayed. I guess, not sure you guys are all aligned. But I guess, where do we stand with the solution there? Could we see a bill introduced in Pennsylvania effectively proposing to allow the wireless companies to own a certain amount of peaking assets and base rates? Is it Texas-type energy fund enough? I guess, what should we be watching for on the legislative side? How should we be thinking about all the different pieces out there? Thanks.
Vincent Sorgi
Yeah, there’s a lot there in that question. Shar, let me — maybe, just how I’m thinking about this issue broadly. So the option itself of the delay, look, I think, that just reinforces the need for the state to take control of this issue. So I truly hope that Pennsylvania continues to pursue state solutions and does not slow that down as a result of the delay in the auction.
I do think and fully expect that PJM will make some improvements on the supply side of the equation with the delay, but I also expect them to include an uploaded — an updated load forecast, which, of course, will include the incremental data center load. So we’d expect that to be higher as well.
So at this point, I can’t predict whether capacity prices will be lower in the next auction, which is for the 2026, 2027 plan a year compared to the 270 that printed for the 2025, 2026 planning year, just given the different moving parts on both the supply and the demand side. In terms of timing of legislation, we’ve always been operating under an expectation that, that would occur sometime in early 2025 anyway. Again, hopeful that, that would not be delayed as a result of the auction. I think the need and the criticality of this issue, the urgency of this issue is such that we need to continue to move forward at the pace we’ve been working with.
We continue our discussions with all of the important decision makers, the Governor’s office, the state legislature as well as the PUC. In fact, the PUC has scheduled a resource adequacy technical conference. Towards the end of this month, we’ll be participating in that. And then, as we’ve talked in the past, just thinking about what this legislation could look like, obviously, we don’t have anything out there right now to comment on. But as I think about the options, obviously, there’s the permitting of utilities to invest in generation, which we’ve been talking about and they could support us in building that new generation in the state, putting it in rate base.
I think on the market side, Shar, they can provide low-interest loans to the generators similar to what they did in Texas with that low-interest fund. I think they can also create some incentives for utilities and the IPPs to enter into long-term power purchase agreements beyond what we are currently able to do under our default service plan. So we have some ability to do that, but it’s not as extensive as I think. Potentially, they could incentivize us to do.
So from our perspective, look, we continue to believe that allowing the utilities to directly invest in the generation would be the most impactful and getting generation built in the state, certainly in the time frame necessary to address the gaps that we’re seeing around resource adequacy. But look, I think it’s reasonable to believe or expect that any new legislation in the state could include some or all of these ideas.
Shar Pourreza
Got it. Okay. That’s helpful. I guess, we’ll stay tuned there. And then on just the Kentucky side, you touched on it a little bit on your prepareds. But if we look at all this advanced stage data center demand, I guess, how do we think about the capital requirements to these versus the current plan. Is there the same transmission sensitivity as Pennsylvania there? I know we have to wait for the capital update, but just maybe a little bit of color there would be helpful. Thanks.
Vincent Sorgi
Yeah. So generally, the opportunity or the requirement really for additional CapEx around transmission related to the data centers is just less than it is in Kentucky as opposed to PA. And that’s primarily because we’re dealing with those supply constraints with generation. And so we’re very opportunistic in where we build that generation. And so taking advantage of our existing sites where we have generation where we may be retiring certain assets, we just don’t need to make as much investment in transmission, Shar. Really the material capital requirement is around the generation which you saw in the updated IRP.
Operator
David Arcaro, Morgan Stanley.
David Arcaro
Hey, good morning. Thanks so much. Hey, wondering just as you think about this first CPCN — it could come pretty soon, but what maybe specifically might be included in that first one in Kentucky related to the IRP? Would you potentially be looking out to that 2030 generation need? And would there be a gas plant potentially in this first round?
Vincent Sorgi
Yeah. Thanks for the question, Dave, you know. Around timing, as I said, I think we could follow the IRP with a CPCN filing as early as the first quarter. I think under any scenario that we’re looking at, it’s pretty clear that we need to at least get moving on the second CCGT to be in service in 2030. So that’s really driving, I would say, the need to get the CPCN filed as soon as we can.
The team will be looking at all of the various supply recommendations to see what we include in the CPCN versus a future one. But clearly, I would expect at least that that second CCGT, likely the one in 2031, some of the other dispatchable gen maybe in the ’28 time frame, like the batteries, et cetera.
So, when we look at really the batteries and the SCR on gen, those are really in there to create and extend dispatchable generation for what we see as a more immediate demand increases coming from the data center.
So obviously, it takes some time right now to get the combined cycles built. Right now, we’re looking at 2030 and then 2031 at the earliest. So some of those again batteries in the SCR to keep that supply there while that demand is ramping up in a more near term.
David Arcaro
Yeah. I got you. Okay. That’s clear. That makes sense. And then I guess as you — I guess, in Kentucky, like how speculative is the data center outlook? I mean, you’ve described kind of what stage it’s at right now. I’m just wondering, is it far along enough to give the commission confidence now that that these investments are needed — you do need this generation. Obviously, it’s a pretty big ramp-up in the data center outlook, but probably maybe more uncertainty than usual. So how are you thinking about that?
Vincent Sorgi
Yeah, sure. I mean, clearly — so the data center load is not the only large load that we’re seeing come to fruition in Kentucky, especially with all of the economic development that’s been occurring there over the last few years.
So the demand curve, that mid-load demand curve that we put in the in the recommended case, we feel really good about, Dave, in terms of data centers, in particular, again, where we’re seeing 400 megawatts in the advanced stage active discussions to upsize that to 1 gigawatt. That’s all we put in the mid-load case. So we’re obviously looking at 3 gigs, overall. That continues to grow quarter after quarter. So we’re pretty confident with that 1 gig that we included in the mid-load case.
Operator
Jeremy Tonet, JP Morgan.
Jeremy Tonet
Hi. Good morning. Just wanted to take a finer point to some of the conversation on data centers as you outlined there. Specifically, as far as the timeline of formal deal announcements, if you have any thoughts on how that could materialize and just kind of the cadence over time? Just trying to get a feel for when the CapEx really start to enter the plan incrementally based on what could happen there.
Vincent Sorgi
Yeah, sure. So I think we’re actually getting close on some of these announcements. And I think once you see the first one or two, right, it’ll probably prompt some others to make announcements as well. Obviously, there’s a huge competitive component, at least on the hyper scaler side with these announcements. And so, not getting too far out and showing your competitive position around your region, I think, is a pretty critical kind of communication strategy on the hyper scalers part. But I think once those announcements start, I would suspect that you’ll see the floodgates open. So again, getting close on the first one, I would suspect by the end of the year, at least first large one, and then I will see going into ’25, what follows from that
Jeremy Tonet
Very helpful. Thank you for that. And then shifting gears to Kentucky, we have observed a very constructive relationship, I think, with the PPO and the commission over time here. But now that we have kind of a new composition, just wondering if you could provide any updated thoughts on how you see that relationship at this point in time.
Vincent Sorgi
Yeah, look, I think the relationship is incredibly constructive. As you said, we’ve always operated under a constructive regulatory construct in Kentucky. I think part of that is because our team is thoughtful, their analysis is deep, it’s well supported with our — conclusions or our recommendations are well supported with the analysis and the depth and breadth of that analysis.
As you know, I think the commission uses our operations as a model in the state when they’re dealing with some others. So generally, it’s been quite positive. We’ve met with the new commission. Nothing coming out of that discussion would lead me to believe that, that relationship would be anything different with this new commission moving forward.
So we’re feeling good. Obviously, the commission is at full staff now, with the three commissioners. Angie Hatton, who was the Vice Chair is now the Chair. And then John Will Stacy just joined in September. So with that appointment, we have a full complement. And again, I would expect the constructive nature of that relationship to continue.
Operator
Durgesh Chopra, Evercore ISI.
Durgesh Chopra
Hey, team. Good morning. Thanks for giving me time.
Hey, just on the comment of one of the strongest balance sheets in the sector, I totally agree there. I would just kind of — don’t want to front run your Q4 update. But just can you talk to whether you think you’ll need equity in the plan or not, just given the cadence of CapEx raises? Maybe any color you can share there would be helpful. Thank you
Vincent Sorgi
Yeah. Well, it does sound like you’re trying to front run the yearend call. Joe, why don’t you talk —
Joseph Bergstein
Yeah. Thanks for the question, Durgesh. Yeah. So I mean, look, there’s numerous factors that go into determining our financing needs and we are going through the business planning process now and evaluating those factors, including additional capital needs and those needs are beyond what would be in the next CPCN filing.
We’re seeing additional needs for things like grid modernization; grid resiliency, given the more severe and frequent storms that we’re seeing across all of our territories; digital transformation, transmission to support data centers and other load growth. And we’ve clearly been on a trend of identifying additional capital spend, which is driving higher-rate-based growth. And I think, in fact, each year since we’ve had the strategic repositioning, our rate base growth has increased by about 100 basis points in each iteration of the plan. And I certainly expect that trend to continue in our next update.
So we’ll evaluate our financing needs in context of that broader plan update and provide you our expectations on the yearend call. But we are in great shape, given our excellent credit position. And we have flexibility to develop a plan that maximizes value for our share owners. And we continue to feel really good about our ability to achieve our earnings growth targets, even with the additional capital needs that we expect in this next update.
Durgesh Chopra
That’s excellent. Thanks for that color, Joe. Maybe just a follow-up to that capital allocation question is some of your peers have lowered dividend growth to support higher EPS growth. Now again, like going back to your comments around very strong balance sheet, which it is. Just maybe give us your thoughts there as you make those capital allocation decisions, dividend, equity, earnings growth.
Joseph Bergstein
Yeah, I mean, all of those things go into our consideration for our financing needs and the overall plan. But I think where we’ve seen that occur is in with companies that have had not the strength of a balance sheet that we have. So that is not — that’s not our intention at this time.
Operator
Paul Zimbardo, Jefferies.
Paul Zimbardo
Hi. Good morning, team. I know you had a lot on the generation and like the data center transmission needs as well. I was just hoping you could frame the scope of the PJM RTEP. Just looking at the — the proposals there, it seems like there could be a lot in PPL zone like around Three Mile Island as well. Just hoping there’s any quantification or details you could provide on potential incremental from that area as well.
Vincent Sorgi
Yeah. Thanks, Paul. So we did submit a number of projects to resolve the issues that were identified in the most recent window. We should know what projects, if any, are selected from that window in the December, January time frame. And of course, we’ll be able to reflect those in our updated plan on the yearend call. But look, I would say regardless of what is selected in this window, we continue to believe that there will be significant transmission opportunities in Pennsylvania for the foreseeable future.
And that’s really stemming from the strong economic development, including the data center load that we’re seeing just the resource needs in the region. But I think you’re aware, but if not, the vast majority of our transmission spend is not derived from these RTEP open windows. So we really view these as incremental opportunities for us not baked into our capital planning for transmission.
Paul Zimbardo
Okay. Yes. No, I definitely understood on that point.
And then one other on the Kentucky IRP, like a two-parter. Did you disclose what the potential customer bill impact could be for the base plan you’re recommending? And just more holistically, it’s a lot of capital, a lot of construction, just your comfort with ability to get the workers and the behind-the-scenes things to execute such a big plan. Thank you.
Vincent Sorgi
Yeah, sure. So all of that will go into our filing of the CPCN. So the IRP is not — it’s not a rate case. It’s not a filing where we’re requesting rate adjustments or anything like that. So we will include and look at all of that as we’re contemplating what we file in the CBCN in the first quarter. We do have the coal plants retiring and continuing to depreciate, which provides bill headroom there.
Obviously, the RARR, which is the first time we’re using that, which is retired asset recovery mechanism in Kentucky that takes the net book value at the date of retirement and then spread it out over a future 10-year period. So, any retirements associated with this plan would likely use that mechanism, which again reduces customer bills. So overall, when we look at our rate case timing and strategies, we’re always thinking about affordability and making sure that we balance our ability to get these very critical investments approved, but at the same time, making sure that we’re keeping bill impacts within the inflationary amounts as best we can. And I don’t think we’ll have an issue being able to do that as we implement the CPCN stemming from the IRP.
Paul Zimbardo
Okay, great. And just any overall thoughts on like labor, construction, just execution ability.
Vincent Sorgi
Yeah, so no concerns on getting a battery installed in 2028. I think, really, what you’re highlighting is the reason why the next CCCGT would not be able to go in service until 2030, and then the one after that, in 2031. So obviously, we used to be able to get combined cycle plants done in a three-ish time period. It’s now five. That’s really due to supply chain constraints, to your point, not just on the turbines themselves but with the EPC contractors and getting enough folks to do all this work. So that is exactly in that — driving that 2030, ’31 timeframe.
Operator
Angie Storozynski, Seaport.
Angie Storozynski
Thank you. So I wanted to talk about that 8 gigs of data center load or potential data center load. And I know that you point out that some of it might be double counting of some of the low growth that you see in other areas. But you, as one of the few companies in PJM, operate in a zone which is heavily over supplied with power. You chose to have an amicable relationship with power companies and data centers. And more importantly, you already have one large data center being developed in your service territory in Pennsylvania, and as little as I know about hyperscalers, then they tend to operate in clusters, right? So that definitely bodes well for future investments in your zone.
I mean, do you see it like that? I mean, is there something that you think — I mean, don’t you think that you actually have a strong competitive advantage versus other utilities across the PJM data center loads?
Vincent Sorgi
Yes, absolutely. 100%. So first of all, I would say that the duplicate projects, we don’t see any duplicates in the 8 gigs. All of those we think — again, those are in advanced stages. We think those are very likely to come to fruition. The duplicate is in the 39 total interest that we have. We do think there could be some of those that are duplicate.
But I think the 8 gigs, we’re feeling good about as those progress. Angie, but to your point, the more — especially, when you’re thinking about all the points that you just made, where we are in PJM, where we are with generation supply. But even just how the formula rate works and being in a nice — in an RTO, the more generation you add, that actually — or the more load you have, especially at these level, it ends up bringing down kind of the average cost per gig a lot of load for the data centers.
So to your exact point, the more you build, the cheaper it becomes on a per unit basis over time. And so I 100% agree with you and that’s why we’re making sure that we can support this and we feel very good with our ability to connect this. And it’s really on the generation side which we’ve been active on that side within PJM to make sure outside of PA and even within PA, we’re continuing to build generation. But on the transmission side, we feel very comfortable with our ability to not only connect the 8 gigs but to continue to connect beyond that.
Angie Storozynski
And then, separately, on the quantification of the transmission benefits for customers, I mean — so I mean, you wouldn’t be able to retain it, right? So that’s not an earnings driver per se, right? Because you’re capped on returns on existing transmission assets. It just provides the customer bill room for either additional investments or to absorb rising energy and capacity prices. Is that fair?
Vincent Sorgi
That’s exactly correct. Yes.
Operator
David Paz, Wolfe.
David Paz
Thanks. Apologies, if you’ve already kind of addressed this. May have missed it. But as we think of the things you’re talking about on the significant capital investment opportunities, your strong positioning, what are the headwinds that would keep you from — maybe keep you at or below even the midpoint of your 6% to 8%. I’m just trying to figure out why a lot of these things you aren’t saying won’t translate into more robust EPS growth. Thanks.
Joseph Bergstein
Yeah. Hey, David. It’s Joe Bernstein. Yeah, I think, as I said earlier, we’re going through the business plan process now. We’ll give a full update on all of this at — on the year end call. But as you think about our earnings growth now and the drivers of that, it’s driven by a mix of energy efficiencies and rate-based growth, and clearly, we’ve been talking about that transitioning to the more traditional rate-based, growth-driven earnings growth profile. And I think, we’ve been seeing that through the — since the repositioning with each of the plan updates as I had indicated and I expect that trend to continue where we’ll be — earnings growth will be driven by rate based growth as we move forward. And I think that’s what you’ll clearly see that in the next iteration of the plan.
David Paz
I got it. All right. So the six, three or so currently on the rate-based growth that could arise. But your O&M savings tailwinds subside a little net-net. But maybe — I guess, it depends on how much you’re adding, which we’ll find out in February. But that all makes sense. Thank you.
Joseph Bergstein
Yeah, I think, high level, that is correct. We’ll continue on the O&M efficiency strategy but we’ll need to make capital investments to achieve those O&M savings.
David Paz
Great. Thank you. And just on the resource adequacy conference, do you anticipate — how will that beat into, if at all, the legislative process for whatever the solutions may be there in Pennsylvania for generation?
Vincent Sorgi
Yeah. Well, I do think the PUC will have an active role in administering any legislation that could ultimately get approved there. So I think the PUC engaging in this topic to understand the nuances of it, the magnitude of it, and then potentially, how they may have to alter their internal procedures, et cetera, to potentially administer some law. I think it’s really constructive.
So again, there’s no law on the books that we’re responding to or anything like that. But I think the commission is preparing accordingly in the event something happens there so that they can really do their part. Again, I would expect the commission will have a significant role in administering whatever this legislation could look like.
Operator
Gregg Orrill, UBS.
Gregg Orrill
Yeah. Hi, thank you. What’s the latest thinking on the timing of general rate cases in your jurisdictions?
Joseph Bergstein
Yeah. Thanks, Gregg. It’s Joe. So well, I would say based on our current plan, which again we’re in the process of updating, we would have a rate case in Kentucky in the first half of next year at the earliest. We have a stay out provision from the last rate case that ends at the end of June of next year, so rate case potentially likely after that.
In Rhode Island, it’s likely the fourth quarter of 2025. Again there, we have had an agreement as part of the acquisition that we would not file a rate case until we were off of the TSAs for 12 months. And we did complete the TSAs in September. So that’s why it looks like the fourth quarter of next year.
And then in Pennsylvania, based on the current plan, that’s 2026 at the earliest. But we’ll assess the timing of all of these as we’re going through the business plan update and give you an update on the yearend call.
Operator
This concludes our question-and-answer session. I would like to turn the call over to Vince Sorgi for any closing remarks.
Vincent Sorgi
Great. Thanks so much to everybody for joining us today. Really looking forward to seeing many of you at EEI in the not-too-distant future. So we will see you then. Thanks, everybody.
Operator
The conference is now concluded. Thank you for attending today’s presentation and you may now disconnect.
