Good morning, and thank you for joining PPL Corporation's conference call on first quarter 2026 financial results. We provided presentation materials on the Investor section of our website.

This morning, you'll hear from Vince Sorgi, PPL President and CEO; and Joe Bergstein, Chief Financial Officer. We'll conclude with a Q&A session following our prepared remarks.

Before we get started, please turn to slide two for our cautionary statement. Today's presentation contains forward-looking statements subject to risks and uncertainties.

Actual results may differ materially. Please refer to our SEC filings and the appendix for additional information.

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

I'll now turn the call over to Vince.

Thank you, Andy, and good morning, everyone. Let's begin on slide four with an overview of our first quarter performance.

Overall, we delivered strong financial and operational results in the first quarter, reflecting disciplined execution across the enterprise. Today, we reported first quarter GAAP earnings of 60 cents per share.

Adjusting for special items, ongoing earnings were 63 cents per share. Based on these results and our outlook for the remainder of the year, we are reaffirming our 2026 ongoing earnings guidance of $1.90 to $1.98 per share, with a midpoint of $1.94 per share.

We also remain on track to complete approximately $5.1 billion of planned investments in 2026, supporting the delivery of safe, reliable, and affordable energy for our customers. Longer term, we continue to project approximately $23 billion of capital investment through 2029, resulting in average annual rate base growth of 10.3%.

This capital projection excludes any investments that may stem from our joint venture with Blackstone, which I'll provide an update on shortly. We're also reaffirming our long-term financial targets, including 6% to 8% annual EPS growth through at least 2029, with compound annual growth expected near the top end of that range.

We also continue to target annual dividend growth of 4% to 6%, along with strong credit metrics throughout our plan period, which support a very compelling risk-adjusted total return for our shareowners. Overall, our quarterly results position us well to deliver on our 2026 targets and beyond.

Moving to slide five and some notable regulatory and business updates. During the quarter, PPL Electric Utilities reached a constructive settlement with the majority of the intervenors in the distribution base rate case.

Remember that we filed this rate case in the third quarter of last year, following more than 10 years since our last base rate case filing. Our filing reflected the results of effective cost efficiency and prudent investments over that period that have delivered significant value for our customers, while keeping O&M increases 25% below inflation.

The settlement achieves a balance between our strong commitment to affordability and maintaining safe and reliable service for our customers, while supporting the significant demand growth in our service territory with large-load customers. Importantly, the settlement would result in bill increases that are less than 4% across all customer classes, despite staying out for those 10 years, and it keeps our delivery rates among the lowest in the state.

We've also agreed to a two-year stay-out following implementation of the new base rates. The settlement also enhances support for vulnerable customers by increasing hardship fund bill credits, improving access to assistance programs, eliminating reconnection fees, streamlining return of security deposits, and boosting the annual low-income weatherization budget.

We also created a new large-load customer rate class and electric service tariff that includes key protections for our other customers, such as a 10-year load requirement and various financial commitments. The proposed tariff and rate class would also provide approximately $11 million annually in support of our residential low-income programs.

Put together, the elements of this settlement would provide tremendous value for our customers by ensuring they receive safe, reliable, and affordable electric service. On April 17th, we were pleased that the administrative law judges recommended approval of the settlement without modification.

We expect the final decision from the Pennsylvania PUC by the end of June, with new rates effective July 1st. In Kentucky, LG&E and KU were granted reconsideration of decisions made by the Kentucky Public Service Commission regarding its base rate case earlier in Q1.

As discussed in February, we expect the current decision by the KPSC will allow us to deliver on our overall plan objectives. However, as outlined in the reconsideration request, we continue to believe, along with many of the intervenors, that our negotiated settlement was a better outcome for all parties, including our customers, and it should not have been modified.

The reconsideration focuses on a limited number of substantive issues, including such modifications the KPSC made to the settlement, and certain cost recovery and return determinations. Importantly, while LG&E and KU's petitions were granted rehearing by the KPSC, all intervenor requests were denied.

A procedural schedule has been set by the KPSC, with the additional discovery projected to conclude by May 22nd. Parties have until May 26th to request a hearing or to ask for a decision based on the record in the case, and we hope to get a decision by the KPSC in the third quarter.

Also in Kentucky, we're excited to announce a couple of new partnerships to explore innovative generation technologies in support of the increasing electricity demand in our service territory. Last month, we announced our partnership with Rye Development to evaluate a new 266-megawatt pumped storage hydro project that Rye has been working on in Bell County.

The project converts former coal mine land in Eastern Kentucky into a reliable energy storage facility, providing up to eight hours of storage upon COD, currently projected for 2031. Rye has secured preliminary federal permits at this stage, with final licensing projected for the second quarter of 2027.

The project's initial cost estimates are approximately $1.3 billion, which excludes potential eligibility for a 50% investment tax credit. This project is not in our current capital plan or earnings projections.

If constructed, this would be the first project of its kind in Kentucky and one of the first newly built pumped storage projects in the United States in more than 30 years. I'm also excited to highlight our collaboration with X-energy, a leading designer of advanced nuclear reactor technology and manufacturer of advanced nuclear fuels, which we announced just last week.

This collaboration will explore deploying X-energy's Xe-100 small modular reactor in Kentucky to support large-load customers, including data centers, with long-term, reliable, and carbon-free electricity. Through this collaboration, we aim to support the significant activity and interest in Kentucky to explore nuclear generation, bolstered by some recently enacted legislation supporting nuclear development.

This legislation supports early site development through a $75 million grant program that helps fund development costs for up to three sites across the state at $25 million per site, and also enables utilities to apply for recovery of other early site work that is not covered by the grant program. We currently expect early site permitting will cost less than $75 million to complete, most of which is anticipated to be funded through the grant process as well as our project partners.

As you would expect, we're approaching potential new nuclear development in Kentucky with a disciplined, phased approach. That means starting with early-stage evaluation and site-readiness work, closely aligned with state policy support, clear customer demand and financial support, particularly from large-load customers, and cost recovery frameworks that protect customers and shareowners.

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

Turning to the Rhode Island updates on slide six. Rhode Island Energy received approval for over $330 million of critical infrastructure investments through its latest annual Electric and Gas ISR plans.

The approval represents the vast majority of what the company requested in its original filings. Recovery of and on these investments began on April 1st of this year, with rider recovery helping to limit regulatory lag.

The latest plans fund core investment and vegetation management work to strengthen day-to-day reliability and system resilience. It's clear these investments are providing tangible benefits to customers, as reflected in our excellent operational performance, including Rhode Island Energy's ongoing top-quartile reliability metrics and its strong execution during this winter's major storms.

During the region's most severe storm of the season in late February, which brought nearly 40 inches of snow and hurricane-force winds, the Rhode Island Energy team excelled, performing better than any other utility in New England. Electric crews restored power to 99% of customers within 48 hours, while our gas crews responded to hundreds of emergency calls to ensure customers had gas service for heat during record-setting winter demand.

These efforts did not go unnoticed, as our teams were honored by the Rhode Island House of Representatives in March for their response to this historic blizzard. These results reinforce the strong connection between sustained investments and outcomes that matter most to our customers, and that's precisely what our Rhode Island base rate case is about.

The rate case was filed in the fourth quarter of 2025, requesting a revenue requirement increase over two years: $181 million in year one and an additional $49 million in year two. The proceeding remains on track, with intervenor testimony filed in April and evidentiary hearings planned for June and July.

New rates are expected to become effective September 1st. In addition, Rhode Island Energy recently filed a new hold harmless commitment proposal that is expected to provide bill credits that would significantly offset the impact of the proposed base rate increase for our customers.

As a reminder, this proposal addresses PPL's deferred tax hold harmless commitment arising from the acquisition of Rhode Island Energy, accelerating the payment of related bill credits to support affordability in the near term. We expect new bill credits to be provided to customers starting in the first quarter of 2027.

This approach is representative of how we engage across our jurisdictions, using the tools available to us to support affordability today, while continuing to attract the investment needed to maintain a safe, reliable energy system for our customers. Turning to slide seven, a data center update in Pennsylvania.

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

As a reminder, projects in advanced stages have executed agreements, either letters of agreement or electric service agreements, with meaningful financial commitments from developers attached to them. Of that total, about 10 gigawatts now have signed ESAs, consistent with our expectations.

This includes contracts with some of the leading companies in the space, including QTS, AWS, PowerHouse, CoreWeave, and others. Meanwhile, 5 gigawatts of the projects in advanced stages are already under construction.

These are critical proof points that demand is not only real, but continues to grow and progress forward. As we've discussed on prior calls, our ESAs include strong customer protections, such as prepayments, credit support, and minimum load obligations, to ensure that developers, not existing customers, bear the financial risk if projects don't proceed as planned.

Those same principles are reflected in the proposed new large-load customer rate class and the electric service tariff in PPL Electric's rate case settlement. Importantly, under our tariff structure, the incremental load growth improves system utilization and lowers transmission costs for existing customers.

Taken together, this reflects our balanced approach to data centers and our firm belief that data center development can strengthen the grid and lower costs for all customers, all while delivering significant local benefits, including jobs, tax revenue, and community investment. Let's turn to slide eight.

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

Our current Kentucky development pipeline now reflects 12.9 gigawatts of potential new load through 2032, an increase of nearly 4 gigawatts from our year-end update. New data center requests make up the majority of the increase, with 13 new projects expressing interest in our service territory.

In total, we have active requests for almost 12 gigawatts of data center demand. Roughly a third of those projects are considered highly active, with transmission service studies underway, of which about 650 megawatts are currently under construction or agreement.

At the same time, we're also seeing continued growth in manufacturing, automotive, and other non-data center projects, adding important diversity to the mix. During the first quarter, Global Laser Enrichment and Toyota Motor Manufacturing announced approximately $2.6 billion in combined investment plans within our service territories.

Based on our updated planning assumptions, we now project approximately 3.5 gigawatts of expected new load by 2032, compared to about 1.8 gigawatts assumed in our most recent CPCN forecast. As new load materializes, additional generation resources will be required to maintain reliability, and LG&E and KU could be in a position to file another CPCN as early as this year.

We remain focused on ensuring that new demand is paired with timely resource additions, protecting customers, supporting reliability, and positioning the system to serve the Commonwealth's long-term economic development needs. Turning to slide nine and an update on our joint venture.

Momentum continues to build around our Blackstone joint venture. This is driven by the rapid data center growth in Pennsylvania that I just discussed, combined with increasing expectations that large-load customers need to bring dedicated generation solutions online in support of their load requirements.

This is also supported by the ratepayer protection pledges made by both hyperscalers and some of the large third-party data center developers. Our joint venture was intentionally built for this moment.

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

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

We're continuing to evaluate additional strategic land parcels to expand access to key sites for further generation development. We are doing all of this with deliberate financial and execution discipline.

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

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

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

Thank you, Vince, and good morning, everyone. Let's turn to slide 11.

PPL's first quarter GAAP earnings were 60 cents per share, compared to 56 cents per share in Q1 2025. We recorded special items of 3 cents per share during the first quarter, primarily due to an ISO New England transmission ROE reduction, as well as customer system and meter system integration impacts, partially offset by regulatory asset treatment of costs associated with PPL's IT transformation in Kentucky.

Adjusting for these special items, first quarter earnings from ongoing operations were 63 cents per share, an improvement of 3 cents per share compared to Q1 2025. The increase was primarily due to higher base rate recovery in Kentucky and higher transmission revenues from additional capital investments, partially offset by higher depreciation and higher financing costs.

Our solid first quarter results keep us on track to achieve at least the midpoint of our 2026 earnings forecast of $1.94 per share. We also continue to maintain one of the strongest credit ratings in our sector, with a balance sheet that provides the company with significant financial flexibility that benefits both customers and stakeholders.

In February, we successfully executed a $1.15 billion equity units offering with a purchase contract for PPL common shares settling in February 2029. This offering provides a clear path to permanent equity, while allowing participation in share price upside.

Following this transaction, we have now de-risked about two-thirds of the total equity needed to support our current capital expenditure plan. For the remaining equity needs, our base plan is to utilize the ATM, which remains an efficient financing tool.

We'll also continue to be opportunistic with other equity-like financing structures to the extent that they provide a lower cost of capital. Turning to the ongoing segment drivers for the first quarter on slide 12.

Our Kentucky segment results increased by 3 cents per share compared to the first quarter of 2025. The improvement in Kentucky's results was primarily due to higher base rate recovery from new retail rates that were effective on January 1st.

This was partially offset by lower sales volumes due to less favorable weather than experienced in Q1 2025, higher operating costs, higher depreciation, and higher interest expense. The remainder of our segments were flat compared to the first quarter of 2025.

Our Pennsylvania Regulated segment results were driven by higher transmission revenue from additional capital investments, offset by higher operating costs, higher depreciation expense, and higher interest expense. Our Rhode Island segment results were driven by higher rider revenue returns, including investment recovery through the ISR mechanism and FERC formula rates.

These favorable items were offset by higher depreciation expense. Lastly, results at Corporate and Other were driven by higher interest expense, offset by several factors that were not individually significant.

Overall, we're off to a strong start in 2026, with solid performance across our business segments and a clear line of sight to achieve our financial objectives. Our capital investment plan remains firmly on track, positioning us to continue to strengthen system reliability, modernize the grid, and provide an improved experience for our customers.

At the same time, our strong balance sheet and business plan position PPL to confidently achieve our growth targets and deliver strong, stable returns for our shareowners, with meaningful upside opportunities beyond the plan. This concludes my prepared remarks.

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

Thank you, Joe. Before we open it up for questions, I'll leave you with a few closing thoughts.

Here at PPL, we're executing with discipline, delivering strong first quarter results, reaffirming our guidance and long-term financial targets, and continuing to invest responsibly in the systems our customers and communities rely on. Across our jurisdictions, we're advancing constructive regulatory outcomes that balance affordability today with the investments needed for long-term reliability and growth.

Affordability is a top priority for us, including here in Pennsylvania. We've been talking about this for over five years now, and made it a cornerstone of our Utility of the Future strategy.

We are not surprised at all by what we are seeing in various states, where elected officials are very focused on affordability for their constituents. That is why we have consistently taken actions to drive efficiency across the business, maintain cost discipline, employ technology to optimize our assets, and limit base rate increases, all while continuing to improve service.

The perfect example is our rate case settlement in Pennsylvania, where we hadn't filed a rate case in over 10 years, and the bill impact of our settlement will be less than a 4% increase for all rate classes, which again puts our delivery rates among the lowest in the state. We don't just talk about focusing on affordability; our actions support our words.

We have been very effective at delivering excellent service for our customers at a reasonable price, and at the same time, competitive returns for our shareowners. We fully expect to continue to deliver on both of those areas going forward.

At the same time, and related to improving affordability, our economic development pipeline continues to progress, with projects moving from planning into agreements, construction, and execution. That demand is supporting new investment opportunities and partnerships, like those we announced with Rye Development and X-energy, focused on delivering reliable, cost-effective generation solutions that, done right, will lower energy costs for our customers.

We're also excited by the continued momentum with our joint venture with Blackstone Infrastructure. We believe it positions us very well to meet growing generation needs in PJM in a way that will lower customer bills, improve system reliability, and deliver long-term value creation for our shareowners.

As you can hear, we don't view growth and affordability as competing objectives. Done right, incremental load, disciplined investment, and thoughtful generation development can improve system utilization and help lower overall customer costs.

That's the approach we're taking, grounded in regulatory credibility, capital discipline, and a clear focus on delivering safe, reliable, and affordable energy, while creating long-term value for our communities and our shareowners. With that, operator, let's open it up for questions.

We will now begin the question-and-answer session. To ask a question, you may press star 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 the question, please press star then two.

At this time, we will pause momentarily to assemble our roster.

Hi, good morning. Thanks.

Just want to start off with the GenCo JV, if we could, and appreciate announcements will come when they come, but it seems like there's some really good positive momentum happening here. Just want to kind of frame up the timeline for when this could come together.

Is this a weeks, months, or is this quarters? Or is there anything else you could help us think through how the timeline could unfold here?

For the ESSAs, Jeremy?

For the GenCo JV.

Yeah. Your question is timing around when we might sign contracts or—

Yes.

Look, as we talked about in the prepared remarks, right, we've made a lot of progress certainly over the last year, and we're really encouraged by the most recent momentum that we're seeing. Again, I would say stemming from really what we've been talking about for months now, where the hyperscalers are going to need to pay attention to generation.

Up until very recently, they've been very focused, rightfully so I would say, on getting connected to the grid. That time has come now that they are focused on generation, and we're very pleased and fortunate that we started this joint venture over a year ago when we did, because we've laid the foundation to be ready to meet the moment when the hyperscalers are taking this seriously.

They clearly are, given the ratepayer protection pledge and all of the activity around that. In terms of timing, I would say we are continuing to work through the process of getting ESSAs in place.

That is an active process, I can tell you that. Trajectory is clearly positive, I would say.

I would say it's probably likely that we would have something meaningful to announce this year on that, Jeremy. These are very complex agreements that have to go through a lot of different parts of the hyperscalers to get to the finish line, and then ultimately announce.

I would say, again, based on where we stand today and the momentum that we're seeing, I'd be surprised if we weren't announcing something meaningful this year.

Got it. That's very helpful.

Thank you.

Then

just want to turn to slide seven here. There's a lot of data on the data center backlog.

Just wanted to see if you could just kind of parse it out for me, make sure I'm clear, how much of the data center growth on slide seven is incremental to the current earnings and capital plan?

Sure. In our updated plan that we came out with in February, we had about $1.3 billion for incremental transmission capex.

When we look at the 28 gigs, I would say there's probably another half a billion, at least, to serve that incremental demand, Jeremy. Some of that, though, I would say would be spent beyond the current plan period in 2029.

I would say at least another half a billion of upside beyond what's in the current plan.

Got it. That's very helpful.

Then just the last one, I guess, going to the RBP. Any thoughts on the impact if it goes through as kind of initially proposed for PPL, both on I guess the EDC side as well as if the GenCo JV might have interest there?

Yeah. Great question.

Look, maybe just a few thoughts on the RBA itself. I think clearly we support PJM's conceptual process for focusing on and starting with bilateral contracting.

Obviously, we support that; that's why we created the joint venture. I would say there's quite a bit of work that needs to be done to ensure that the costs that are related to any backstop auction are actually borne by the large loads that they are intended for, and that our other customers don't end up getting allocated those costs through some unintended consequence or some allocation methodology that doesn't achieve what we're all trying to achieve here, which it's not clear as written or as proposed that we would actually get that result.

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

Headed in the right direction, but there's quite a bit of work, I would say, to be done there. In terms of the participation, really depends on the final rules.

Obviously PJM is working through feedback that they just received earlier this week. It'll also depend, I think, if the EDCs are mandated to participate.

Again, if it's approved as proposed, there's quite a bit of work we need to do at the state level to get those protections in, and that could impact our desire to participate at the EDC level. On the JV, I would say this could be an opportunity for us.

Again, I think it depends on the ultimate rules. I would say for now, our priority absolutely continues to be on our very active bilateral process.

We're not slowing down on what we're doing with the JV, and then we'll see if there's an opportunity to participate in the auction. Currently, we're not sure if we would or we won't.

We really need to see how those rules shake out.

Got it. That makes sense.

I'll leave it there. Thank you.

Thanks, Jeremy.

Hi, good morning, team. Thank you for the time.

I apologize if I missed it, Vince. I think you said multiple slot reservations, energy.

Do you want to put around that? Is that two is multiple?

Is it bigger than two? Just what's the time on delivery for those pieces of equipment?

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

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

Okay. Understood, and I get the sensitivity.

Shifting gears to the Pennsylvania Electric Utility, assuming the settlement is approved, I know you have the stay-out. Any kind of time frame that you think about when you'd need to go back in, or could you kind of rely on the DISC mechanism to stay out for more than a couple years?

Thank you. Yeah.

No, you're right. Embedded in the settlement, we do have a two-year stay-out, we have good visibility on a minimum of two years.

That's from the date that new rates become effective, which we expect to be July 1st. We wouldn't need anything between now and two years out.

Look, we stayed out for 10 years prior through our financial discipline, our cost management discipline. As we continue to look at ways to drive cost out of the business.

AI is a whole new wave of opportunity there. We are embarking on our system consolidation; that'll drive cost savings over time as well.

We are in the middle of doing that work, though, how much of that shows up by, call it mid-2028 when the stay-out expires, we'll see. Clearly that'll be a focus of ours to stay out as long as we can, similar to what we did last time.

Okay.

No, great. Thanks a lot.

Good luck, team.

Thanks, Paul.

Hey, thanks.

Good morning.

Curious about your reaction maybe to the contents of the letter that the governor had sent, just in terms of the different approaches that were proposed there around ROE, debt and equity ratios, etc. How are you interpreting and kind of reacting to that?

I would say, in general, we share the same ultimate goals as our governor does, right, delivering safe, reliable, affordable energy for our customers. We've talked a lot about—and I think this is a differentiating factor for PPL—we've been talking about affordability for several years, way before most of the industry was focused on it.

It's why we've taken the actions that we have to focus on cost control, making the investments around automation and hardening, those things, right, reduce O&M over time. That's really enabled us to stay out of base rate cases for over a decade.

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

We think we can continue to do that even under the points that were in the governor's letter. Again, I think we share the same goals as our governor.

We've been extremely successful at balancing all of those things. It is evident in our settlement after a decade with only a 4% increase nominally for our customers.

Obviously the governor had some concerns with some of the other EDCs in the state, but I think we are very well aligned with our governor. I think we'll continue to engage in stakeholder engagement with him, with the PUC, the new special counsel that's been assigned by the governor.

I'm not concerned that we really need to alter our stance in PA. I still think it's a great jurisdiction.

We'll be able to invest in it, earn reasonable returns, and deliver what we need to for our customers.

Got it. Thanks, Vince.

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

Sure. Joe, you want to take that?

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

From a timing perspective of a CPCN, that, I think, will again ultimately be driven by how quickly large-load demand converts and then the visibility that we have into that load ramp. Importantly, we have about $4 billion of generation projects approved and under construction.

We'll want to see the existing pipeline advance before layering on incremental generation investments. Having said that, though, if you look at our probability-weighted demand growth at about 3.5 gigawatts, compared to the 1.8 gigawatts in our prior CPCN, it's certainly becoming more likely that we file another CPCN later this year, especially if we get one or more hyperscalers committed to a significant load ramp.

We could be seeing something later this year.

Dave, I would just add to that, clearly the momentum is headed in a direction where it's getting more likely that we will file something this year. To Joe's point, with $4 billion in flight, we want to be very judicious about adding more generation.

Our probability-weighted 3.5 gigs, we have 1.8 in the current CPCN. It's almost twice the load that's being supported by the current CPCN.

We start to see hyperscalers kind of back the projects that we're seeing, so that the projects that are under construction are still developers. Once we start to see those get backed by actual hyperscaler tenants and load, I think the battery clearly likely comes back in.

Just that's the quickest thing we can get on. I think the battery likely comes back in in that CPCN.

Then you have the Rye Development project. Do we need additional gas generation on top of that?

Perhaps. It really depends on how far we're going between the 1.8 and the 3.5 at the time we would file that CPCN.

I would say one to maybe three projects could show up in a CPCN, based on this load profile that we're seeing and the momentum that we're seeing. Obviously, it's a little bit early, but just given what we're seeing now, I would say that that could happen by the end of the year, again, given the momentum that we're seeing.

Yeah. Great.

That makes sense. Thanks so much.

Sure.

Good morning. We talk a lot about the supply driving the affordability issues in Pennsylvania and the possible solutions that PPL can provide to that issue.

Do you see any parallels for the situation in Rhode Island? Are you considering pursuing generation there?

There's actually proposed legislation in Rhode Island to enable the utility to own generation again, which we obviously support. Very similar issues.

I think there's a couple things that we know are affecting power prices up in New England. The gas constraints into the area are clearly one cause, and there is a lot of recent activity to try to increase gas transmission into New England, in particular coming up through our area.

We're seeing other projects to even on the existing pipelines get additional volumes through the existing pipes. We've taken an offtake on one such project, so that's good.

We know New England is using high-price, high-volatility LNG quite a bit, whatever we can bring in additional, potentially Marcellus Shale gas, which is much less volatile, that can help to lower the volatility and the overall high price of LNG. Then environmentally, all of this is still good, because New England, and in particular Rhode Island, has significant amounts of its energy still coming from fuel oil, which comes in on barge and then it gets driven around in diesel trucks around the state and around the region.

Obviously, the more we can displace that with clean natural gas, you get a huge environmental benefit as well. Which we know state and regional policy is very focused on carbon and other environmental benefits.

I think there's some win-wins that we can do by improving or increasing the gas flow up there, and there's a lot of activity going on around that that we are directly supporting and indirectly supporting.

Thank you. That's very helpful.

Then on the retroactive refunds from the FERC ROE determination in New England, if that long period of refunds stands through the court challenges, does that affect the way you think about capital allocation to transmission going forward?

Let me talk about the refunds. We're not going to wait until I think it's May of '27 was the extension.

We're not going to wait that long. Our refunds in the around $25 million, $26 million.

Our plan would be to also engage with the commission in conjunction with the rate case and the hold harmless, and time those refunds, kind of put it all in one package for our customers in conjunction with the rate case. There was another part of that question that I missed, or did I answer that?

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

No, I don't think so. Again, we're talking tens of millions of dollars exposure.

Obviously, the New England TOs filed their 205s. We kind of live and die together as a group up there.

Just filed a 205 filing for higher ROEs going forward. No, I'm not worried about capital allocation in Rhode Island at all.

I still think it's a great asset, a great jurisdiction, and we'll continue again to I think be able to use creativity and innovation, whether it's regulatory or physical assets, to help to take some of the pressure off of the wholesale power markets, and so that'll help with affordability and at the same time deliver competitive returns to our shareholders for the investments that we're making up there. Every bit as bullish on Rhode Island as we were when we bought it.

Great. Thank you.

I'll leave it there.

Sure.

Hi, thanks for taking my questions. For the Blackstone JV, you highlighted good progress on the gas side, engagement with pipeline companies, reserving turbines.

Last earnings, you talked about alternative generation solutions that could come online sooner. Didn't point to any specific type of technology.

Just wondered if there's anything you could share on type of technology now and progress on that front?

Sure. Really depends on what the ultimate hyperscalers want.

They're the ones that will be the offtake of the ESSAs. If they need new generation to ramp with their ramp schedule, then most likely we'll be doing that with batteries.

Even some of those alternate forms of energy, those timelines are getting pushed back closer to where the CCGTs are. Batteries, maybe fuel cells, are really the technologies that we can bring online sooner.

Ultimately, the hyperscaler will be the one to determine if and how much of that they would want prior to kind of the backstopping the larger CCGT. That's kind of how we're thinking about it, Mike.

Again, and I would also say it's hyperscaler-specific. Some want to see gen come on in line with their ramps; others are more comfortable relying on the current fleet within PJM to provide that, and they just want to make sure they get enough when they're kind of at full ramp.

All of those things we're working with on a one-off basis with our customers.

Great. Thank you.

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

I think the way you talked about a high level is all we're willing to share at this point.

Okay. Thank you very much.

Sure.

Hey, good morning.

Hey, Paul. Good morning.

A few quick ones for you. On the affordability thing, there has been legislation proposals, etc., I think in Pennsylvania to have regulated generation, or at least to have the potential option of it.

I'm just wondering is there any progress in that considering that the numbers, in terms of the wholesale market impact and what have you, could be beneficial. I'm just wondering how that might stand given this affordability concern and this being potential opportunity for you guys and for the state?

Yeah. You're right, there is proposed legislation in the state to, I would say, incentivize new generation, right, either through long-term contracts between utilities and IPPs, or as a backstop allowing the utilities to build and own generation again.

Those legislations, in both the House and the Senate, are in committee. They haven't come out of committee.

Look, I would say, given all of the recent activity with PJM around the backstop auction, they just came out with their new market design document that has a few options in there to help promote building new generation and maintaining affordability on the wholesale side. My sense, Paul, is that the legislature's going to want to see how some of those market dynamics shake out before they push that legislation hard within the broader legislature.

I don't know that I would expect anything to come out in the near term on the legislation. We continue to support it.

We're also not waiting for it, right? We are actively pursuing this with the Blackstone JV to provide that much-needed generation, which is very consistent with both the backstop auction, I would say, kind of process or goals, and then even with the market design white paper that just came out, or report that just came out earlier this week.

The JV and building Gen fits perfectly within both of those. That's kind of where our focus is.

We're not waiting for the legislation, continue to support it. I do think that the state's going to wait to see how some of these things play out before they push it, certainly, to the full legislature.

Okay. That makes sense.

Then with respect to, you guys have mentioned this before, this sort of unique competitive advantage that you have with advanced transmission systems. You guys have been involved in DLR in the past, I think.

I'm just wondering, and there's, of course, this legislation that passed, I think, unanimously through one of the houses in the state legislature on transmission. I'm just wondering, could you just maybe just elaborate a little bit more about what makes you guys unique, what makes you feel that you've got this unique competitive advantage in transmission if I'm reading it correctly?

There's various reasons why I think we have a competitive advantage around transmission. One is on grid-enhancing technologies that you're talking about, which we were one of the first utilities in the country to deploy dynamic line rating.

We were the first, may even be the only one still, to have integrated our DLR capabilities into the day-ahead market with PJM. Not only are we using it around our transmission planning, but PJM is using it to identify their constraints live in the system.

That clearly is a competitive advantage, and we do have various large-load customers asking about whether we have DLR on our transmission lines that would support them, and or whether or not we could add that if it's not currently on there. The other, I would say, bigger benefit or strategic advantage that we have is just the investment that we've made in our transmission grid over the last decade.

We have created, and a lot of this was due to reliability issues, our whole Utility of the Future on the physical side that we talk a lot about, we've been at that for a decade now in Pennsylvania, in particular on our transmission grid. We have one of the most reliable grids, the most automated grids.

When we were doing all of those reconductorings or going from wood to steel, etc., we also upsized the lines, and so that created additional capacity that is enabling us to connect these very large loads very quickly. When we connect, say, a gigawatt scale, it's not that we're not doing any upgrades, but the time it takes us to do those upgrades and the cost of those upgrades is significantly lower than some of our peers' transmission networks.

We're at the point now at this 28 gigs, we're probably, to get a gigawatt scale added, we're spending less than $150 million total. The hyperscalers are directly paying under the energy services agreements, soon to be under the new tariff, they're paying under direct payments, CIAC, more than half of that amount.

Then what's left goes into the FERC formula rate, which is the piece that provides broader benefits to the entire grid. Some grids, youre spending $1 billion or more to connect a gigawatt.

For very little money, with connection times that are unrivaled, that's the primary competitive advantage that we have. Then we kind of come in with the kicker around DLR, but that's I would say that's icing on the cake.

Awesome. Thanks so much, guys.

Sure.

Hey, good morning, team. Thanks for squeezing me in.

Tough season, Vince. Tough season, right?

That's an understatement. Appreciate the detail.

Hopefully, just two easy ones. Do you know in PJM, for the bring-your-own-generation plans, do you know if they have to be located adjacent to the data centers or are you going to locate them anywhere in PJM?

Then I have a follow-up.

In the backstop option, they do not necessarily need to be co-located or near-located. Obviously, with our Blackstone strategy, they will be.

Great. Then

lastly, just you guys are unique. You're pursuing the JV with Blackstone in the wires-only region of Pennsylvania.

You have a fully integrated utility in Kentucky. When you talk to the large loads, the hyperscalers, is there any preference they have one region versus the other?

Or if you think about the structure in Kentucky, the structure in Pennsylvania, do they care either way or just location and tying into their needs there?

Yeah. Obviously, given our two main jurisdictions, and I would say we're starting to talk about, hey, if you want to serve Boston, let's talk about Rhode Island, right?

I would say we have unique jurisdictions in the data center play. Obviously, in Pennsylvania, when you kind of draw the radius around where we are, you're just picking up massive industrial, business populations, right?

If you're worried about kind of lag and making sure that your reliability is at five nines and you have to be incredibly reliable with no latency, they're going to go where the population is. However, now with AI, large learning models, more flexible load around data center and AI, you can do that anywhere.

Kentucky, much less population, but low power prices. We control our destiny on the whole thing.

We just obviously have to get our commission's approval for that, but we're not beholden to a market who may or may not be bringing generation to bear. They like the fact that we can control everything in the integrated utility, but it's a different type of data center that they would be looking for there than perhaps up in Northeast Pennsylvania.

Then like I said, well, I think we can offer benefits for folks that are thinking about Boston as well, since we're pretty close there.

That's all I had. Thanks for squeezing me in.

All right. Take care, Anthony.

Hey, Ryan. Ryan, you there?

Yeah. Thanks for taking my questions.

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

Look, I think it's overall, it's good to see PJM finally recognize that the issues that we've been talking about for a couple years now, and really I would say the admission that the current market construct will not solve the supply issues that we've been experiencing in PJM. That's good.

As far as some of the proposed solutions, right, just based on the conversation we had here in the Q&A, I think you could see some of them are very consistent with our views as well, including the large loads bringing their own gen or being interruptible until they do. We've advocated for that as well, and that clearly can still enable speed to market for the customers, but at the same time take some pressure off of reliability and in higher capacity costs until that new BYOG comes online.

I don't think there's anything in that market design report that would replace the need for BYOG, but it could provide a bridge to it. Look, overall, I think we're headed in the right direction.

Any thoughts on the proposed options around the capacity auction?

Not in detail. I really kind of want to see how that shakes out.

Look, I think part of the issue that we've been experiencing in PJM is right on the energy and the capacity side, where the marginal price is what gets paid to all generation, and that's what's kind of been creating this issue. You can see in that report perhaps some idea to go after that and parse that out a bit.

Again, I think headed in the right direction, but more work needs to be done to ferret out what that would look like. I know there was some mention of maybe going to a kind of an ERCOT model.

Again, and we'd have to see the details on what ultimately is being proposed there. At the end of the day, we have to find a way to ensure that the generators are earning a reasonable return on the investments, but at the same time make sure that the wholesale power prices, whether it's energy or capacity, are affordable for the customer.

We're at that point for sure. The market is coming up with other ideas, primarily on the bilateral contracting, and it's good to see that the hyperscalers have signed that ratepayer protection pledge and taken responsibility for that.

That will go a very long way here. I still think PJM needs to look at that capacity market and try to figure out how to balance reasonable returns for the generators against affordability for the customers.

It seems like that's where they're headed, which is good to see.

Great. Appreciate the time.

Sure.

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

Thanks, everybody.