Q1 2026 Earnings Call Transcript

Good day and welcome to the PPL Corporation First Quarter 2026 Earnings Call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the appropriate key. To withdraw your question, please press star then 2. Please note this event is being recorded.

I would now like to turn the conference over to Andrew Ludwig, Vice President of Investor Relations. Please go ahead.

Good morning, and thank you for joining PPL Corporation's conference call on first quarter 2026 financial results. We provided presentation materials on the Investors section of our website. This morning, you will hear from Vincent Sorgi, PPL Corporation President and CEO, and Joseph P. Bergstein, Chief Financial Officer.

We will conclude with a Q&A session following our prepared remarks. Before we get started, please turn to Slide 2 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 will also refer to non-GAAP measures including earnings from ongoing operations. Reconciliations to the corresponding GAAP measures are provided in the appendix. I will now turn the call over to Vincent Sorgi.

Thank you, Andrew, and good morning, everyone. Let us begin on Slide 4 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 $0.60 per share.

Adjusting for special items, ongoing earnings were $0.63 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 will provide an update on shortly. We are 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 5 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 ten 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 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 ten years, and it keeps our delivery rates among the lowest in the state. We have also agreed to a two-year stay-out following implementation of the new base rate. The settlement 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 ten-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 17, 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 June, with new rates effective July 1. 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 22. Parties have until May 26 to request a hearing, or to ask for a decision based on the record in the case. We hope to get a decision by the KPSC in the third quarter.

Also in Kentucky, we are 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 MW 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 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 thirty years. I am also excited to highlight our collaboration with X-energy, a leading designer of advanced nuclear reactors 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 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. It 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 are 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 Rhode Island updates on Slide 6. Rhode Island Energy received approval for over $330 million of critical infrastructure investments through its latest annual electric and gas ISR plan. The approval represents the vast majority of what we requested in our original filings. Recovery on these investments began on April 1, with rider recovery helping to limit regulatory lag. The latest plans fund core investment in vegetation management work to strengthen day-to-day reliability and system resilience.

It is 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. That is precisely what our Rhode Island base rate case is about. The rate case was filed in 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 1. 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 Corporation'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 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 7 and 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 GW, up another 12% from the 25.2 GW 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 GW now have signed ESAs, consistent with our expectations. This includes contracts with some of the leading companies in this space, including QTS, AWS, PowerHouse, CoreWeave, and others.

Meanwhile, 5 GW 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 have 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 do not 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 us turn to Slide 8. 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 GW of potential new load through 2032, an increase of nearly 4 GW 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 GW of data center demand. Roughly a third of those projects are considered highly active with transmission service studies underway, of which about 650 MW are currently under construction or agreement.

At the same time, we are also seeing continued growth in manufacturing, with 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 GW of expected new load by 2032, compared to about 1.8 GW assumed in our most recent CPCN forecast. As new load materializes, additional generation resources will be required to maintain reliability.

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 9 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 are 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 are 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 have 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 are excited about the progress we have made and look forward to providing you with more updates as contracts are finalized. I will now turn the call over to Joseph P. Bergstein for our financial update.

Thank you, Vincent, and good morning, everyone. Let us turn to Slide 11. PPL Corporation's first quarter GAAP earnings were $0.60 per share, compared to $0.56 per share in Q1 2025. We recorded special items of $0.03 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 Corporation's IT transformation in Kentucky. Adjusting for these special items, first quarter earnings from ongoing operations were $0.63 per share, an improvement of $0.03 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 Corporation 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 will 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 $0.03 per share compared to 2025. The improvement in Kentucky's results was primarily due to higher base rate recovery from new retail rates that were effective on January 1. 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 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 are 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 Corporation 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 will now turn the call back over to Vincent.

Thank you, Joseph. Before we open it up for questions, I will leave you with a few closing thoughts. Here at PPL Corporation, we are 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 are 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 have been talking about this for over five years now and made it a cornerstone of our utility-of-the-future strategy. So 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.

A perfect example is our rate case settlement in Pennsylvania, where we had not filed a rate case in over ten 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 do not 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 are 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 do not 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 cost. That is the approach we are 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. We will now open the call for questions.

We will now begin the question-and-answer session. To ask a question, you may press star then 1 on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw the question, please press star then 2. At this time, we will pause momentarily to assemble our roster.

Our first question comes from Jeremy Bryan Tonet with J.P. Morgan. Please go ahead.

Hi. Good morning, and thanks. I wanted to start off with the Genco JV, if you could. It seems like there is really good positive momentum happening here. Can you help frame the timeline for when this could come together? Is this weeks, months, or quarters? Any color on how the timeline could unfold?

Your question is timing around when we might sign contracts or ESSAs? We have made a lot of progress, certainly over the last year, and we are really encouraged by the most recent momentum. As we have been talking about for months now, hyperscalers are going to need to pay attention to generation. Up until very recently, they were very focused—rightfully so—on getting connected to the grid.

That time has come now that they are focused on generation, and we are very pleased that we started this joint venture over a year ago when we did, because we have 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, we are continuing to work through the process of getting ESSAs in place. The trajectory is clearly positive.

I would say it is likely that we would have something meaningful to announce this year. 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. Based on where we stand today and the momentum we are seeing, I would be surprised if we were not announcing something meaningful this year.

Got it. That is very helpful, thank you. Turning to Slide 7, there is a lot of data on the data center backlog. How much of the data center growth on Slide 7 is incremental to the current earnings and capital plan?

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 GW, I would say there is probably another $500 million at least to serve that incremental demand. Some of that would extend beyond the current plan period in 2029, but it is at least another $500 million of upside beyond what is in the current plan.

Very helpful. Lastly, on the RBA, any thoughts on the impact if it goes through as proposed for PPL Corporation, both on the EDC side as well as if the Genco JV might have interest there?

We support PJM's conceptual process for focusing on and starting with bilateral contracting. That is why we created the joint venture. But there is quite a bit of work that needs to be done to ensure that the costs related to any backstop auction are borne by the large loads they are intended for, and that our other customers do not end up getting allocated those costs through some unintended consequence or allocation methodology. It is not clear, as proposed, that we would get that result.

I am optimistic we can get there, but there is work to do with both PJM and FERC. If the proposal was approved by FERC as is, at PPL Electric Utilities we would need to work with the state to ensure we have protections either contractually or otherwise to ensure the EDC is not shifting the risk or the cost of that auction to our other customers. In terms of participation, it depends on the final rules and whether EDCs are mandated to participate. If it is approved as proposed, we would need to do state-level work to get those protections, and that could impact our desire to participate at the EDC level.

For the JV, this could be an opportunity, again depending on the ultimate rules, but our priority continues to be our very active bilateral process. We are not slowing down with the JV. We will see if there is an opportunity to participate in the auction once the rules are finalized.

Got it. That makes sense. Thank you.

Our next question comes from Paul Andrew Zimbardo with Jefferies. Please go ahead.

Good morning, and thank you for the time. I think you said multiple slot reservations in your queue. Any color you want to put around that—is it two, bigger than two? And what is the timing on delivery for those pieces of equipment?

Given the competitive nature here, I am not going to get into a lot of detail. I will say confidently that our submittals into the PJM queue are backed by land that is under our control for all of those submittals—multiple generation projects—which positions us very well to be competitive with the joint venture. On turbine reservations, we have sufficient quantity to support what I just said on the interconnection queue.

Understood. Shifting to the Pennsylvania electric utility, assuming the settlement is approved, I know you have a stay-out. Any timeframe when you think you need to go back in, or could you rely on the DISC mechanism to stay out for more than a couple years?

Embedded in the settlement, we have a two-year stay-out from the date new rates become effective, which we expect to be July 1. We would not need anything between now and two years out. We stayed out for ten years prior through our financial and cost management discipline. We continue to look at ways to drive cost out of the business. AI is a new wave of opportunity.

We are embarking on our system consolidation that will drive cost savings over time as well. We are in the middle of that work, so how much of that shows up by mid-2028 when the stay-out expires, we will see. But it will be a focus to stay out as long as we can, similar to last time.

Great. Thanks a lot. Good luck.

Thanks, Paul.

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

Hey, thanks. Good morning. Curious about your reaction to the contents of the governor's letter—different approaches proposed around ROE, debt and equity ratios, etc. How are you interpreting and reacting to that?

In general, we share the same ultimate goals as our governor: delivering safe, reliable, affordable energy for our customers. We have been talking about affordability for several years, before most of the industry was focused on it. It is why we have focused on cost control and made investments around automation and hardening that reduce O&M over time. That has enabled us to stay out of base rate cases for over a decade.

We only seek rate increases when it is absolutely necessary to maintain safety and reliability. We will continue to operate in that way to improve service affordably and provide competitive returns to our shareowners. We think we can continue to do that even under the points in the governor's letter. It is evident in our settlement after a decade with only a sub-4% increase for our customers.

The governor had some concerns with other EDCs in the state, but we are very well aligned. We will continue stakeholder engagement with him, the PUC, and the special counsel assigned by the governor. I am not concerned that we need to alter our stance in Pennsylvania. It remains a great jurisdiction where we can invest, earn reasonable returns, and deliver for our customers.

Thanks, that is helpful. Shifting to Kentucky, as you see the load projection increase, what might that mean for generation resources? Timing of when you would need new generation, and whether it is peak or baseload—what options are under consideration?

On the resource needed, that will ultimately be dependent on the customer, the load ramp, and how quickly it is coming online, given the time to bring different types of resources online. From a CPCN timing perspective, it will be driven by how quickly large-load demand converts and the visibility we have into that load ramp. Importantly, we have about $4 billion of generation projects approved and under construction. We want to see that existing pipeline advance before layering on incremental generation investments.

That said, with probability-weighted demand growth at about 3.5 GW compared to 1.8 GW in our prior CPCN, it is 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.

I would add that momentum is headed toward it being more likely we will file this year. With $4 billion in flight, we want to be judicious about adding more generation, but with a probability-weighted 3.5 GW versus 1.8 GW in the current CPCN, it is almost twice the load. As we start to see hyperscalers back the projects currently under construction by developers, the battery likely comes back in first as the quickest asset we can get online. Beyond that, the Rye Development project and potentially additional gas generation could be needed depending on how far we go between 1.8 GW and 3.5 GW at the time we file.

One to maybe three projects could show up in a CPCN based on the current load profile and momentum. Given what we are seeing now, that could happen by the end of the year.

Great. That makes sense. Thanks so much.

Up next, we have Shahriar Pourreza with Wells Fargo. Please go ahead.

Hi, it is Andrew Gadavy on for Shahriar. Thanks for taking my questions. We talk a lot about the supply driving affordability issues in Pennsylvania and the possible solutions that PPL Corporation can provide. Do you see any parallels for the situation in Rhode Island? Are you considering pursuing generation there?

There is proposed legislation in Rhode Island to enable the utility to own generation again, which we support. There are similar issues: gas constraints into New England are clearly one cause. There is recent activity to increase gas transmission into New England, particularly coming up through our area, including projects to increase volumes on existing pipelines. We have taken an offtake on one such project.

New England uses high-price, high-volatility LNG quite a bit. Bringing in additional Marcellus Shale gas, which is less volatile, can help lower volatility and overall price. Environmentally, Rhode Island still has significant amounts of energy coming from fuel oil, delivered by barge and trucks. Displacing that with cleaner natural gas provides a significant environmental benefit, which aligns with state and regional policy focus on carbon and other environmental benefits.

There are win-wins by increasing gas flow, and there is a lot of activity around that which we are directly and indirectly supporting.

Thank you, that is helpful. On the retroactive refunds from the FERC ROE determination in New England—if that long period of refunds stands through court challenges, does that affect how you think about capital allocation to transmission going forward?

On the refunds, we are not going to wait until May 2027—the extension date. Our refund is around $2.526 billion. Our plan would be to engage with the commission in conjunction with the rate case and the hold harmless, and time those refunds and put it all in one package for our customers in conjunction with the rate case. As to whether the precedent changes capital allocation, I do not think so.

We are talking tens of millions of dollars of exposure for us. The New England TOs filed their 205s for higher ROEs going forward. I am not worried about capital allocation in Rhode Island at all. It remains a great asset and jurisdiction.

We will continue to use creativity and innovation—regulatory and physical—to help take pressure off wholesale power markets, supporting affordability while delivering competitive returns for our shareholders on the investments we are making there. We remain as bullish on Rhode Island as when we bought it.

Great. Thank you. I will leave it there.

Our next question comes from Michael Logan with Barclays. Please go ahead.

Hi, thanks for taking my question. For the Blackstone JV, you highlighted good progress on the gas side—engagement with pipeline companies and reserving turbines. Last earnings, you talked about alternative generation solutions that could come online sooner but did not point to specific technology. Anything you could share now on technology type and progress?

It depends on what the hyperscalers ultimately want, since they will be the offtake on the ESSAs. If they need new generation to ramp with their load schedule, most likely we would do that with batteries. Some alternative forms of energy have timelines getting pushed closer to where CCGTs are, so batteries—and maybe fuel cells—are really the technologies we can bring online sooner. Ultimately, the hyperscaler will determine if and how much they want prior to backstopping the larger CCGT.

Some want generation to come online in line with their ramps; others are more comfortable relying on the current PJM fleet initially and just want to ensure they get enough when they are at full ramp. We are working those on a one-off basis with customers.

Thanks. Sticking with the JV, can you help us think about the returns on those projects? My understanding is they would be above utility returns—anything more precise you can share?

The way we have discussed it at a high level is all we are willing to share at this point.

Our next question comes from Paul Patterson with Glenrock Associates. Please go ahead.

Good morning. A few quick ones. On affordability, there have been legislative proposals in Pennsylvania to enable regulated generation or long-term contracting. Is there any progress there, given the governor’s concerns and potential benefits to wholesale markets? How does that stand as an opportunity for you and the state?

There is proposed legislation to incentivize new generation—either through long-term contracts between utilities and IPPs, or as a backstop allowing utilities to build and own generation again. Those bills in the House and Senate are in committee and have not come out. Given recent PJM activity around a backstop auction and their new market design document with options to help promote building new generation while maintaining affordability, my sense is the legislature will want to see how market dynamics shake out before pushing that legislation through the broader legislature. I would not expect anything near-term.

We continue to support it, but we are not waiting for it. We are actively pursuing generation with the Blackstone JV to provide needed generation, which is consistent with both the backstop auction goals and the market design ideas PJM just put out. That is where our focus is.

That makes sense. You have mentioned a unique competitive advantage with your advanced transmission systems. You have been involved in DLR. Could you elaborate on what makes you unique and why you feel you have a competitive advantage in transmission?

On grid-enhancing technologies, we were one of the first utilities in the country to deploy dynamic line rating and the first—and may still be the only one—to have integrated DLR into PJM’s day-ahead market. Not only are we using it for transmission planning, but PJM is using it to identify live system constraints. Large load customers ask whether we have DLR on our lines that would support them and whether we could add it if not currently in place. The bigger advantage is the decade of investment in our transmission grid in Pennsylvania.

Driven by reliability, we created one of the most reliable and most automated grids. In going from wood to steel and other upgrades, we upsized lines, creating additional capacity that enables us to connect very large loads quickly. When we connect a gigawatt-scale customer, we are not doing zero upgrades, but the time and cost are significantly lower than some peers. At the current 28 GW, to add a gigawatt we are spending less than $150 million total.

Hyperscalers are directly paying more than half of that under ESAs and, soon, under the new tariff. The remainder goes into the formula rate, which provides broader grid benefits. Some grids are spending $1 billion or more to connect a gigawatt. So, for relatively little money, with unrivaled connection times, that is our primary competitive advantage, with DLR as icing on the cake.

Our next question is from Anthony Crowdell with Mizuho. Please go ahead.

Good morning, team. Thanks for squeezing me in. A couple of easy ones. In PJM for bring-your-own-generation plans, do they have to be located adjacent to the data centers, or can they be located anywhere in PJM?

In the backstop auction, they do not necessarily need to be colocated or near the data centers. Obviously, with our Blackstone strategy, they will be proximate to the load.

Lastly, you are unique in pursuing a JV with Blackstone in a wires-only region of Pennsylvania and having a fully integrated utility in Kentucky. When you talk to hyperscalers, is there any preference for one region versus the other, given the different structures?

In Pennsylvania, when you draw a radius around where we are, you pick up massive industrial and business populations. If you are worried about latency and need five-nines reliability, you go where the population is. With AI and large learning models, more load can be sited anywhere; Kentucky, with much less population, offers low power prices and we control our destiny across the value chain—subject to commission approval—in an integrated utility. Hyperscalers like that we can control everything, but it is a different type of data center than in Northeast Pennsylvania.

We can also offer benefits for those thinking about Boston, given our proximity via Rhode Island.

That is all I had. Thanks.

Our next question comes from Ryan Levine with Citi. Please go ahead.

Thanks for taking my question. Given the new PJM CEO's letter and related report, any thoughts around some of the ideas proposed and the future of the capacity auction?

It is good to see PJM recognize the issues we have been talking about for a couple of years and acknowledge that the current market construct will not solve PJM’s supply issues. Several proposed solutions are consistent with our views, including large loads bringing their own generation or being interruptible until they do. We have advocated for that as well. It can enable speed to market while taking pressure off reliability and high capacity costs until BYOG comes online.

I do not see anything in that market design report that replaces BYOG; it could provide a bridge to it. On capacity options, I want to see how details shake out. Part of the issue has been the marginal price being paid to all generation in energy and capacity, contributing to current problems. The report hints at approaches to address that.

There was mention of possibly moving toward an ERCOT-like model—details matter. At the end of the day, we must ensure generators earn reasonable returns on investments while keeping wholesale prices affordable for customers. The market is moving toward bilateral contracting, and it is good that hyperscalers have signed the ratepayer protection pledge. That will help.

PJM still needs to refine the capacity market to balance reasonable generator returns against affordability, and it seems that is the direction, which is good to see.

This concludes our question-and-answer session. I would like to turn the conference back over to Vincent Sorgi, President and CEO, for any closing remarks.

Great. Thank you, everyone, for joining us. We look forward to seeing folks out on the circuit.

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