Exelon Corp (EXC) — Q2 2025 Earnings Call Transcript

Thank you, Gigi, and good morning, everyone. Thank you for joining us for our 2025 second quarter earnings call. Leading the call today are Calvin Butler, Exelon's President and Chief Executive Officer; and Jeanne Jones, Exelon's Chief Financial Officer. Other members of Exelon's senior management team are also with us today, and they will be available to answer your questions following our prepared remarks. Today's presentation, along with our earnings release and other financial information can be found in the Investor Relations section of Exelon's website. We would also like to remind you that today's presentation and the associated earnings release materials contain forward-looking statements, which are subject to risks and uncertainties. You can find the cautionary statements on these risks on Slide 2 of today's presentation or in our SEC filings. In addition, today's presentation includes references to adjusted operating earnings and other non-GAAP measures. Reconciliations between these measures and the nearest equivalent GAAP measures can be found in the appendix of our presentation and in our earnings release. It is now my pleasure to turn the call over to Calvin Butler, Exelon's President and CEO.

Good morning, Andrew, and thank you very much, and thank you all for being with us today as we report on our results through the first half of the year. We continue to execute well across our priorities for 2025, building on a platform that is very well positioned to lead our states and jurisdictions through an exciting time in the sector. We earned $0.39 in operating earnings in the second quarter, above expectations at the time of our first quarter call, driven by favorable timing and cost management at our utilities, offsetting the impact of our $50 million customer relief fund and a stormy start to the summer. This keeps us on track to deliver on our operating earnings guidance for 2025 of $2.64 to $2.74 per share. Now storm seasons always highlight the talented and committed employees that make up the Exelon team. In June, PECO was hit with one of the largest storms in recent memory, with peak customer outages surpassing 325,000. Restoring power quickly was critical in light of a heatwave that followed the storm, and over 3,000 of our team members at PECO were joined by almost as many support personnel from around the country to bring customers back online, working tirelessly in 100-degree temperatures. It's easy to take performance like this for granted. This is what you've come to expect from Exelon and why we continue to be recognized as the #1, #3, #5, and #8 most reliable utilities across the country. I'm incredibly proud of the sacrifices our team makes on a regular basis to provide the service our customers and communities expect. Turning to regulatory activity. I will remind you that our core rate case activity is limited this year, having updated investment recovery rates across close to 90% of our rate base in the last couple of years. However, we have remained very active across a variety of federal and state proceedings to solve an ever-evolving set of opportunities to better serve our customers and advance our state's energy and economic goals. Building on the momentum from the first quarter, our legislatures continue to consider ways in which they might address an energy landscape that is rapidly evolving. Illinois wrapped up its spring legislative session after drafting an energy omnibus legislation, seeking opportunities to expand efficiency efforts, transmission build, storage, and resource planning, among other areas. While the legislature did not pass the bill, the process offered us and other stakeholders the opportunity to discuss critical issues, and we remain optimistic that Illinois will continue to lead the nation in advancing progressive, constructive legislation that enables effective partnership across private and public entities. Other states like Pennsylvania and New Jersey remain in active discussions around ways in which they might address tightening power markets, including bills to allow for utility ownership of generation. Coming off of last week's capacity auction, it's clear now more than ever that states should be thinking broadly about how to secure the energy futures for our citizens. Exclusive reliance on PJM enabled low and relatively steady supply costs for its customers in a period of low demand and growth—low demand growth, and when states weren't yet facing significant turnover in their generation supply driven by economics, policy, and technology. But the volatility and unpredictability we are seeing in supply cost, along with a steady increase in warnings from institutions like NERC and DOE, is undermining faith in the status quo. Despite higher prices, we are not seeing the market respond fast enough. We saw some new generation entry, but demand growth was double that amount. In fact, the capacity contribution by one of the quick solutions available—demand response—actually declined in this most recent auction. States have an opportunity to proactively bring control, certainty, and cost benefits by pursuing options outside of the capacity market, including regulated generation. Such options can ensure solutions are there to meet state goals when the market can't or won't deliver. State involvement already resulted in savings for customers with a temporary cap on pricing, resulting in close to $3 billion saved relative to an uncapped outcome. But bigger, longer-term fixes are available with legislative action, and we stand ready to be part of that solution. We look forward to continuing the dialogue with our states to be part of the solutions to ensure energy is delivered reliably and cost-effectively in a manner that best suits their goals. Time remains of the essence in adding supply to the grid. As you can see, our pipeline for large load remains robust. Our large load pipeline is holding firm at more than 17 gigawatts, and customers remain in our Q2 study, another 16 gigawatts of high probability load that we expect to formalize as part of our pipeline by the end of the year. In fact, we have also opened another cluster study window at ComEd closing in August, in which several gigawatts worth of large load have indicated an interest in participating. And transmission solutions to connect this new load and generation to the grid are also advancing. We continue to be well positioned to be assigned over $1 billion of transmission work associated with the MISO Tranche 2.1 set of projects. And we now have the organizational structure and are developing strategic and financial partnerships necessary to take further advantage of our industry-leading position in transmission. The expansive work needed across all aspects of the grid gives us strong confidence in our 4-year outlook and beyond, investing $38 billion through 2028, with an additional $10 billion to $15 billion of transmission work identified beyond that to support our jurisdictions and, most importantly, our customers. Success in winning competitively bid projects, which we have already proven we can do with the Tri-County line, would offer even more upside. By earning a fair return on equity of 9% to 10% on a rate base growing at 7.4% through 2028 and financing that with a balanced capital strategy, we expect to grow our earnings at an annualized rate of 5% to 7%, with the expectation of delivering at the midpoint or better of that range. I will now turn it over to Jeanne to provide a more detailed update on our financial outlook and rate case activity.

Thank you, Calvin, and good morning, everyone. Today, I will cover our financial update for the second quarter and the progress on our current regulatory activity. Starting on Slide 5, we present our quarter-over-quarter adjusted operating earnings block. Exelon earned $0.39 per share in the second quarter of 2025 compared to $0.47 per share in the same period in 2024, reflecting lower results of $0.08 per share over the same period. Earnings are lower in the second quarter relative to the same period last year, primarily driven by $0.13 of higher distribution and transmission rates driven by new rates in effect. This favorability was offset by $0.07 of ComEd timing, which reverses most of the favorability seen in the first quarter due to revenue shaping and timing of O&M spend relative to 2024. There's $0.04 at corporate attributable to our customer relief fund, $0.03 of higher storm costs at PECO, $0.02 of higher interest at corporate and PHI, and $0.02 attributable to the recognition of Pepco Maryland's first MIP reconciliations for rate years 1 and 2 in 2024. The remaining $0.03 is attributable to smaller nonrecurring items, including timing of taxes at corporate and approximately $0.01 attributable to the derecognition of a regulatory asset subsequent to Maryland's Next-generation act. As Calvin mentioned, these results are slightly ahead of the guidance we provided in our prior quarter call due to favorable revenue and tax timing at ComEd and disciplined cost management at our utilities. Our year-to-date performance underscores our ability to deliver strong financial results amidst increasingly significant storm activity and while continuing to find new and creative ways to support our customers. Looking ahead to next quarter, we expect earnings to be approximately 29% of the midpoint of our projected full year earnings guidance range, which contemplates new rates in effect, anticipated shaping up costs and revenue timing, and assumes normal weather and storm conditions, along with our ability to seek deferral treatment of extraordinary storm costs at PECO from the first half of the year. As we look towards the end of the year, we remain on track for full year operating earnings of $2.64 to $2.74 per share, with the goal to be at the midpoint or better. Finally, we have reaffirmed our annualized earnings growth rate of 5% to 7% through 2028, with the expectation to be at the midpoint or better of that range. Turning to Slide 6, I will review the limited base rate case activity across our platform. We received intervenor testimony on July 25 on the Delmarva Power gas distribution rate case filed last September, keeping the rate case on track. The rate filing seeks to recover continued reliability investments such as aging piping, along with the LNG plant upgrades, which help protect customers from price volatility during peak periods. Following intervenor testimony, the case will be open for rebuttal testimony in September before evidentiary hearings are held in November, an order is expected in the first quarter of 2026. Our second open base rate case is at Atlantic City Electric, where settlement discussions remain ongoing as we seek recovery for grid improvement and modernization efforts in line with New Jersey's Energy Master Plan and the Clean Energy Act. An order is expected by the end of the year. At ComEd, our first reconciliation under the new multiyear rate plan framework is underway. As a reminder, we filed for a $268 million reconciliation adjustment primarily driven by operating under a lower revenue requirement in 2024 than what was ultimately approved by the commission. The reconciliation is also inclusive of $6 million related to a positive 5.3 basis point adjustment to our return on equity from our performance metrics. In initial testimony filed on July 15, recommended a $108 million reduction in the net reconciliation amount but noted they would consider additional information that could impact their ultimate recommendation. We continue to feel confident in the spend we incurred in 2024 as we maintained industry-leading levels of reliability at well below average rates and are working towards the remaining rounds of testimony, including our rebuttal testimony due next week. Finally, in Maryland, we continue to wait for decisions on our final reconciliations from the first BGE and Pepco Maryland multiyear plans, along with the commission's comments on the lessons learned proceeding to support our next filings. We trust that we can find an approach that best aligns stakeholders' interests in balancing affordability, reliability, economic development, and the state's energy transition goals. Finally, I'll conclude with updates on our balance sheet activity on Slide 7, where we've continued to make substantial progress on our 2025 capital needs. From a financing perspective, we have successfully completed nearly 80% of our planned long-term debt financing needs for the year, with ComEd and BGE issuing $725 million and $650 million in the second quarter, respectively. The strong investor demand and attractive pricing we continue to achieve in our debt offerings are supported by the strength of our balance sheet and by the low-risk attributes of our platform. Investor confidence in our offerings, along with our pre-issuance hedging program, position us well as we seek to finance the energy transformation in the most cost-effective way for our customers and our investors. As it pertains to equity, we've successfully priced the full $700 million of planned equity needs for 2025 via our ATM, issuing $175 million in shares and pricing an additional $525 million under forward agreements for the issuance later in the year. In addition to de-risking 2025, we've also priced nearly $160 million of our equity needs for 2026 through forward agreements using our ATM, which we renewed an upside in the second quarter to cover our needs for the current 4-year plan. We continue to project 100 to 200 basis points of financial flexibility on average over the Moody's downgrade threshold of 12%, approaching 14% at the end of our guidance period, with a focus on ways in which we can protect and strengthen our balance sheet to ensure we support all opportunities to invest to meet our customer needs. Most recently, we filed with FERC for construction work and process incentive treatment on our Tri-County transmission project, which will support stronger credit ratings. We also continue to advocate for language that incorporates repairs for calculating the corporate alternative minimum tax, which will lower energy costs for our customers. As a reminder, favorably addressing repairs in the minimum tax calculation would result in an increase of approximately 50 basis points to our consolidated metrics on average over the plan. And I'll also remind you that our financing plan and credit metrics are not impacted by the most recent tax legislation.

Thank you, Jeanne. Closing on Slide 9. We remain focused in 2025 on our four core areas to create value for our customers, jurisdictions, and shareholders. As I noted, our employees deliver unparalleled service to our customers in all jurisdictions, which becomes especially apparent in the face of increasingly unpredictable and volatile weather. We invest every dollar as prudently and efficiently as possible, trying to prevent outages from impacting our customers in the first place, even amidst storms. It's why 98% of the net profit earned at our utilities has been reinvested back in the system over the last five years. But storms inevitably bring disruptions. When that happens, our team works tirelessly to bring people back online as quickly as possible. Those two elements, our investments in the system and the performance by our employees, are the reason why we occupy four of the top eight spots in reliability in the industry. This focus on top-notch service at below-average cost is what drove ComEd's latest large low-tier proposals, which seek to ensure an interconnection process that is as efficient as possible for new customers while protecting existing customers against the risk that the load does not materialize at expected levels. We appreciate the engagement with large customers and other stakeholders in developing this set of proposals and look forward to finding a balanced solution as we continue to grow our pipeline of customers seeking to take advantage of industry-leading reliability at some of the lowest rates in the nation. That customer orientation was also highlighted by the CEO of a quantum computing company who noted ComEd's partnership with the state at the beginning of the company's site evaluation process was a key differentiator when deciding to locate in Chicago. Connecting this load continues to offer long-term advantages for our jurisdictions. The market for data processing, driven by artificial intelligence and increased reliance on the cloud and other high-density load, is national, and ensuring our customers get the local benefits of that growth, including from a reduced share of fixed cost, supports longer-term affordability. But with the extent of investment needed in the grid, not just from new business, but from connecting new generation to serve it and from ensuring reliability and resiliency amidst more challenging weather conditions, affordability requires every tool we have and new ones as well. It's why we continue to focus on connecting customers to federal, state, and local relief funds, including continued advocacy for key programs like LIHEAP. It's why we suspended disconnects, offered extended payment plans, and waived late payment fees after a cold winter. It's why we partnered with trusted local nonprofits to provide $50 million in customer relief for low- and middle-income customers this summer. And it's why we're increasingly advocating that our jurisdictions be proactive in taking more control over their power supply, complementing the supply induced by the capacity market with solutions like utility-owned generation that their regulators oversee, giving them control, certainty, and cost benefits to customers that markets alone don't offer. By putting our customers at the center of everything we do, we are confident we can earn a fair return on our investment and maintain a balanced funding strategy that enables delivery not only on 2025 guidance, but also on our long-term growth rate of 5% to 7%. We have built a platform and a culture of excellence over the last 25 years, and we are committed to using it to deliver consistent growth and long-term value for our communities and shareholders for the next 25 years and beyond. Gigi, we are now happy to take any questions.

I think just to kick it off, and you described it well on your call, and it seems like nearly every one of your governors, if not all of the governors, has been increasingly active with PJM. Which jurisdictions do you think is the most ripe for further action on that utility-owned generation or more energy efficiency, storage, something in those areas?

Yes. Thank you, Paul. This is Calvin, and I'll begin with your question. You're absolutely right. Our governor has stepped in, and we appreciate their engagement. We are committed to collaborating with PJM, but we believe state involvement is crucial in this effort, as I mentioned. Governor Shapiro's initiative specifically helped cap what our customers would have otherwise had to pay, resulting in approximately $3 billion in savings, which is significant. Most of our jurisdictions have taken part in some legislative process that allows us to explore what we can do to supplement the existing supply. In Maryland, there is battery storage being offered at the T&D level, and there are considerations for utility-owned generation in Delaware and similar discussions in New Jersey. To address your question, it really depends on how quickly they are looking to move and where the demand is emerging from. However, as we engage with them, we identify three key needs: one, certainty; two, a sense of control from the states regarding customer benefits derived from utility-owned generation; and three, our commitment to being part of the solution, which is directly related to affordability. We are focused on what we can do for our customers today that isn't currently being addressed. In the meantime, we need to provide short-, mid-, and long-term solutions in this context. I'll turn it over to Mike Innocenzo, our COO, to see if he has anything to add.

Yes. The only additional point I would mention regarding timing is the Maryland legislation, which has a specific request for 3,000 megawatts of power. By October, we will know if that demand is met by the competitive market. If it is not, that may prompt the next steps in our timeline for additional actions.

Thank you, Mike. Paul, does that answer your question?

Yes, it does. And just a follow-up, and I appreciate that timing, Mike. Is it something that could be ready for a fourth-quarter refresh when you do that next roll forward, just given the Maryland opportunities, Delaware, New Jersey, just purely on the storage side? Is that something that could be ready in time for fourth quarter? Or could it take a little bit longer?

Yes. I think it depends on the outcome of the procurement that Mike mentioned. But I think sometime next year, we'll have more clarity for sure on all of our states.

And Paul, as you know how we do this, we're very deliberate about rolling forward on what we share with you. We're not going to speculate. We're going to be consistent and transparent in everything we do. And I promise you, we'll bring that to you as soon as we have some clarity on where it's going.

I wanted to follow up on the potential $10 billion to $15 billion transmission opportunity. When can we expect to see that included in the company's base plan? Will it be part of the fourth-quarter refresh, or can you provide more details on the timing of its integration into the base plan?

Yes, Anthony, it's Jeanne. So you're right. We would normally do that in Q4. And the reason why is we have the cluster study that I mentioned. So we'll have more clarity on that in the fall. We have ComEd grid plan that has to be filed in '26, BGE looking at its next filing. So we like to take all that together, including the transmission, and build that into the updated plan that we present to you on Q4. All of that will be contemplated in there including the new business. And I think if you look back at the last couple of updates, we've typically updated about 8% to 10% every four years. And I think transmission has gone up about 30%. So you can expect that transmission will continue to be a big part of our roll forward going forward. And then, of course, we'll continue to keep an eye on the potential generation opportunities, working with our states. We wouldn't build that in until it's certain. And then Calvin also mentioned that we've organized ourselves under our Head of Transmission, Carim Khouzami, to also look at other competitive types of transmission. So as those opportunities are not in the $10 billion to $15 billion, and we would only put that in, as you would expect from Exelon, until we have more certainty on those. But those are opportunities that we continue to work towards.

And financing that $10 billion to $15 billion a good rule of thumb, 30% to 40% equity, or I'm curious what would be a good rule of thumb to finance that incremental CapEx?

Yes, we have been using a rule of thumb of every new dollar is about 40% equity.

Great. I came across an article about the Illinois governor and quantum computing. It appears that Governor Pritzker is very supportive of quantum computing. Is this creating a bigger or unique opportunity for ComEd that might be different from the data center trends observed across the country?

Great question, and you pronounced his name correctly. Congratulations. I was at a panel last week with members of IBM and others discussing the quantum computing campus they established, and the State of Illinois is very proud of that. The CEO of PsiQuantum mentioned that if ComEd hadn't engaged in that process, it wouldn't have come to Illinois. That's very significant and reflects our partnership. To answer your question directly, there is definitely upside. We've already received requests from others wanting to be on that campus, which was the whole point. An anchor attracts others who want to be close and benefit from quantum computing efforts. It was a multi-day conference focused on that. Just to clarify, this information isn’t included in what we've shared because we plan to be very transparent about the timing and details when we roll it out to you. But that will be separate from anything we've discussed so far.

Maybe on, let's say, on the generation side of things, we've obviously seen some of your peers express a willingness to build regulated-like or contracted generation. So I'm wondering your current thoughts on whether that might kind of fit into your model? Is that something you would consider?

Simple yes. And it's based on how it's done; policy matters in this process, right? And we go back to those three tenets. We need certainty. We want to make sure we have a clear understanding of where the states are getting in control, and we also want to know what the customer benefits are. But we want to be part of the solution, and we do believe in that portfolio approach because what you're finding right now, David, is that the cost, the supply is not meeting the demand. So what can we do to be part of that solution? But how it's done does matter. And we're very optimistic that our states will do something. I think it was Paul that asked earlier where our states are engaging in this discussion, and we're engaged in those discussions every step along the way. And we want to partner, and we will continue to partner with PJM, but we do see it as an and, the competitive markets and regulated generation being part of the solution.

We believe that working with our states on regulated generation is the most effective approach. The states require certainty, especially if they are facing immediate economic development needs that demand additional generation. This regulated cap provides that certainty and enables states to choose the type of generation that suits their customers. By collaborating with them, we can offer this control, which also translates into customer benefits. We have a cost of capital advantage in this process and believe that proactive planning will yield further customer benefits. This approach is not unfamiliar, as many PJM states already employ a combination of regulated and restructured market generation. We think our states should seize this opportunity to gain control, certainty, and enhance customer benefits, and we are prepared to partner with them to move forward.

Okay. Great. I appreciate that color. And then wondering if you could elaborate on how data center discussions have been progressing recently. How quickly do you anticipate firming up more megawatts and kind of any reactions that you're seeing from the industry to some of the large load tariffs that you're rolling out?

We talked about we see significant activity in Illinois. We talked about the second cluster study that's being presented and started in August, which will provide more clarity as we go forward. And then let me just be very clear, we're also seeing data center activity across our other jurisdictions: Pennsylvania, Maryland. So this is not just a one state. You just see Illinois being in the top five of what we're doing. So understand it's driving forward, and you'll see more of those announcements coming in. But doing it the right way with reliability in mind is key. And I'm looking at Mike. I'm going to ask Mike if you'd like to jump in there.

Yes. The only thing I would add is timing, as Calvin mentioned. So we've got active cluster studies going in Illinois. We've got active cluster studies going in the Mid-Atlantic. We expect results in the third, fourth quarter. Once you complete the cluster studies, you have commercial discussions with the different applicants there. So I think you would start to see in the third and fourth quarter some announcements as a result of those cluster studies coming up.

Yes. We are monitoring the large load tariffs in various states. ComEd has filed proposed changes to its tariff with the ICC, aiming to better serve our new customers while also safeguarding our existing customer base. This includes acknowledging state-certified economic development priority projects for initiatives of 50 megawatts or more. It aligns with similar actions in other states, and the ICC will seek opinions from stakeholders on this matter.

Maybe just a quick follow-up on the large load pipeline. Is there any color you can provide in terms of the potential timelines for projects to progress through the different phases that you've outlined in that pipeline? And what the potential gating factors potentially impacting that cadence would be?

Carly, it's Jeanne. To address the second part of your question, we aim to provide information that is very reliable. At this stage, we believe we have met our initial studies, which gives us confidence to proceed. Therefore, we don't anticipate significant obstacles. Regarding the megawatts, we expect that 10% of the load will be operational by 2028, one-third by 2030, and three-quarters by 2034. We want to clarify where we are in the phases and how they progress in relation to the load ramps mentioned.

Got it. Okay. That's super helpful. And then maybe just a follow-up on the PJM capacity auction results and customer bills. Could you just talk a little bit about the bill impact with these auction results in place, especially with the BGE clear being lower relative to the last auctions? And then any shifts that you're anticipating in sort of the rhetoric around customer bills from here?

Yes, Carly. Specifically regarding BGE, the previous auction resulted in a higher finish, which is why this time we observed a smaller increase compared to last. We expect the impact on BGE customers to be approximately $1.5. We treat any increase in our customers' monthly bills very seriously, as even a $1 increase can be too much. In general, across our jurisdictions, we are seeing bill increases ranging from $1.5 to $4. We are actively working to mitigate this impact in collaboration with the states.

Yes. I think in terms of your comment around sentiment, I think there is a broader understanding and recognition that this is driven by the supply costs, right? And we need the investments necessary in the grid to attract the economic development, just like we need to address these rising supply costs. And that goes back to what we're doing in terms of working with our states, having them take control, thinking of complementary solutions to PJM. Now that may take some time in terms of generation back to what Calvin said, whether it's energy efficiency or demand response, those are the near-term solutions we really need to take action while we get these longer-term solutions in place.

And Carly, it also goes directly to why the commissions need to be directly engaged, the commissions and the governors because these other solutions, we can do some things today to offset some of the rising costs and customer bills, but it has to be very thoughtful. It's no longer, can you do one-offs and expect something to happen. It has to be that portfolio approach. And energy efficiency and demand response are clear examples of what some of our states can do today to decrease customer bills. But because it's out of their norm, you get hesitation, and we continue to work with them to think broader than just today's or the next decision.

Thank you very much, Gigi. And as always, thank you, guys, for joining. Let me just say that we are committed to working with our states to really drive financial excellence and operational excellence. And we appreciate your support. And we hope to see many of you in the months ahead as we continue to get out on our road shows, talk with you, and look forward to seeing you at our financial conference at EEI. So with that, Gigi, that concludes our call.