Exelon (EXC) Q2 2026 Earnings Call Transcript

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DATE

Thursday, July 30, 2026 at 10 a.m. ET

CALL PARTICIPANTS

• Vice President of Investor Relations - Ryan Brown
• President and Chief Executive Officer - Calvin Butler
• Chief Financial Officer - Jeanne Jones
• President and Chief Executive Officer of PECO - Michael A. Innocenzo
• Executive Vice President of Transmission and Development - Carim Khouzami

TAKEAWAYS

• Adjusted Operating Earnings -- $0.43 per share for the second quarter, compared to $0.39 per share in the prior-year period, primarily driven by distribution and transmission rate increases and the absence of a prior-year Customer Relief Fund charge.
• Full-Year Guidance -- Reaffirmed at $2.81 to $2.91 per share, with management targeting the midpoint or better based on first-half performance.
• Long-Term Earnings Growth -- Reaffirmed near the top end of 5% to 7% annually through 2029, supported by disciplined cost management.
• Rate Base Growth -- Projected at 7.9% annualized through 2029, driven by $41.7 billion in planned capital expenditures over the next four years.
• Capital Expenditures -- Approximately $10 billion budgeted for 2026 to support grid reliability and customer-driven growth projects.
• Consolidated Operating ROE -- Targeted between 9% and 10% for the full year, reflecting regulated utility operations.
• Data Center Pipeline -- Refined to 36 gigawatts, down from a previous 43 gigawatts, as management utilizes Transmission Security Agreements (TSAs) to filter out speculative projects.
• ComEd Grid Plan -- Proposes $15.3 billion of investment through 2031 to support load growth and energy policy objectives, with a final order expected by Dec. 15.
• BGE Rate Case -- Filed July 2, seeking a $156.1 million revenue requirement increase to recover grid maintenance and reliability investments.
• Delmarva Power Delaware Case -- Seeking a $45.4 million revenue requirement increase, with interim rates implemented on July 9.
• New Jersey Battery Project -- A new 500-megawatt storage installation in Pittsgrove representing a $1 billion investment to provide capacity for 400,000 homes.
• Battery Project Benefits -- Estimated to deliver over $700 million in net benefits to customers through PJM market revenues and deferred transmission investment.
• PJM Capacity Shortfall -- Reached approximately 6.8 gigawatts in the most recent auction, equivalent to the missing supply of seven nuclear reactors.
• PJM Price Volatility -- Peak demand of 168 gigawatts in July caused power prices to surge tenfold from $80 to $800 per megawatt-hour.
• Simulated Clearing Prices -- Management noted that without a $330 price cap, PJM prices would have cleared at $555 per megawatt-day and $777 in ComEd.
• Transmission Security Agreements -- Include 4 gigawatts of data center load already backed by $1 billion in financial collateral.
• Debt Financing -- 86% of 2026 requirements are completed, including all planned issuances at the holding company and major utilities.
• Equity Financing -- 37% of the $3.4 billion needed through 2029 is priced via forward contracts, covering all 2026 and half of 2027 requirements.
• Average Credit Metrics -- Expected to remain at approximately 14% through 2029 to maintain strong investment-grade ratings.
• Reliability Performance -- Top-quartile performance in 2025 saved customers an estimated $1 billion in avoided outage costs.
• ComEd Storm Recovery -- Management restored power to 90% of 530,000 impacted customers within 48 hours following 16 major weather events in early 2026.
• MISO Competitive Bids -- Submitted two additional Tranche 2.1 competitive transmission bids in partnership with Invenergy.
• Customer Interruptions -- Declined by nearly 2 million since 2021 due to grid resilience investments.

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RISKS

• Butler stated, "the system should not have to operate this close to the edge," referring to extreme July heat events and PJM capacity shortfalls that strained the grid.
• Jones noted that Q2 results were partially offset by "$0.02 of higher credit loss expense at BGE and $0.02 of interest at corporate and PECO," reflecting ongoing pressure from financing costs and bad debt.
• Butler stated, "if critical work is deferred for too long, customers ultimately pay the price through more outages, more costly repairs, and higher long-term costs," noting the risk of regulatory delays impacting necessary grid maintenance.

SUMMARY

Exelon (NASDAQ:EXC) management reported second quarter adjusted operating earnings of $0.43 per share, attributing the results to realized distribution and transmission rates and disciplined cost execution. The company reaffirmed its full-year 2026 earnings guidance and long-term growth objectives, emphasizing that its diversified regulatory footprint mitigates the impact of adverse rulings in any single jurisdiction. Strategic discussion focused on a shift toward utility-owned storage and transmission to address resource scarcity highlighted by recent PJM capacity auction shortfalls. Management also updated its data center strategy, refining its project queue to prioritize high-probability developments backed by significant financial commitments to shield existing customers from infrastructure costs.

• CEO Butler described a supply-demand imbalance in the PJM footprint, stating, "demand is growing faster than supply, and the system is under increasing strain."
• CFO Jones highlighted the effectiveness of new Transmission Security Agreements, noting that the process has "weeded out speculative projects" and provided "proactive insight into what is real" regarding data center load.
• The company is advocating for an "all-of-the-above" energy approach, with CEO Butler stating that "utility-owned generation needs to be part of that mechanism as a cost-effective complement to market-based solutions."
• In Pennsylvania, management remains in dialogue with state stakeholders to address affordability while emphasizing that "investment in our system is required to maintain the reliability and growth" expected by the state.
• Khouzami noted a competitive advantage in transmission bidding, stating the company is "one of very few transmission operators that own and operate" 765-kV high-voltage lines, which are increasingly sought by regional grid operators.
• Management expects the 500-megawatt Pittsgrove battery project to save customers approximately $7.5 million during peak events, similar to savings that would have occurred during the July 2 to July 5 heat wave.

INDUSTRY GLOSSARY

• PJM Interconnection: A regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia.
• Transmission Security Agreement (TSA): A contract requiring new large-load customers to provide financial collateral to cover infrastructure costs, preventing speculative requests from burdening existing customers.
• Virtual Power Plant (VPP): A cloud-based network of distributed energy resources, such as residential batteries, that can be dispatched together to support grid reliability.
• Rate Base: The value of a utility's assets used to provide service, upon which it is permitted to earn a regulated rate of return.
• AFUDC (Allowance for Funds Used During Construction): A regulatory accounting method that allows a utility to recover the financing costs of capital funds used for construction projects.
• MISO (Midcontinent Independent System Operator): A regional transmission organization that manages the power grid and wholesale electricity markets across 15 U.S. states and one Canadian province.
• FERC (Federal Energy Regulatory Commission): The U.S. federal agency that regulates the interstate transmission of electricity, natural gas, and oil.
• MW / GW: Megawatts and gigawatts are units of power measurement; one gigawatt equals 1,000 megawatts.

Full Conference Call Transcript

Operator: Hello, and welcome to Exelon’s Second Quarter 2026 Earnings Call. My name is Josh, and I will be your event specialist today. All lines have been placed on mute to prevent any background noise. Please note that today’s webcast is being recorded. During the presentation, we will have a question-and-answer session. You can ask questions by pressing *11 on your telephone keypad. If you would like to view the presentation in full-screen view, click the full-screen button by hovering your computer mouse cursor over the PowerPoint screen. Press the Escape key on your keyboard to return to your original view. And finally, should you need technical assistance, as a best practice, we suggest you first refresh your browser.

If that does not resolve the issue, please click on the Help option in the upper-right-hand corner of your screen for online troubleshooting. It is now my pleasure to turn today’s program over to Ryan Brown, Vice President of Investor Relations. The floor is yours.

Ryan Brown: Great. Thank you, Josh. Good morning, everyone. Appreciate you joining us for our 2026 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 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.

Calvin Butler: Thank you, Ryan, and good morning, everyone. We appreciate you joining us for our second quarter earnings call. Halfway through 2026, Exelon is delivering where it matters most: performing today and preparing for tomorrow. Our utilities are providing safe, reliable service, driving affordability, and investing in the infrastructure that keeps our customers, communities, and economies thriving. This morning, we reported adjusted operating earnings of $0.43 per share, consistent with expectations, and are reaffirming our full-year guidance of $2.81 to $2.91 per share. Operationally, we continue to lead the industry, with all utilities projecting top-quartile reliability and ComEd and PHI projected in the top decile.

Those of you who are from Chicagoland know that this has been quite a year for storms. So far this year, ComEd has experienced 16 major weather events, more than it has seen in over two decades, while Illinois has recorded more tornadoes than any other state. Most recently, Monday’s severe storms impacted approximately 530,000 customers. Thanks to the extraordinary efforts of our crews and support teams, power was restored to 90% of affected customers within 48 hours. These results reflect disciplined investment in grid resilience and a sustained focus on delivering safe, reliable service for our customers when they need it most. Reliability is about more than metrics.

When the grid performs, businesses keep their doors open, hospitals care for patients, and families can count on the power being there when they need it most. In 2025 alone, our top-quartile reliability saved customers an estimated $1 billion in avoided outage costs. And annual customer interruptions have declined by nearly 2 million since 2021. And for every $1 million Exelon invests, an average of eight jobs are created or $1.7 million of economic output is generated. We are proud of the indispensable role we play in supporting the communities and businesses that depend on us every day.

Now, turning to regulatory activity, we remain on track in the Pepco Maryland and DPL Delaware electric rate cases, as well as ComEd’s grid plan. Earlier this month, we also filed a rate case at BGE, with a decision expected in January 2027. Jeanne will cover the details, but the filing reflects our approach to balancing affordability with the investments required to maintain a safe and reliable grid. To help manage customer impacts, BGE delayed its filing, deferred select projects, and prioritized the maintenance and reliability work most critical to serving customers safely. The work our men and women perform every day is critical to our communities, and we cannot delay any further.

If critical work is deferred for too long, customers ultimately pay the price through more outages, more costly repairs, and higher long-term costs. As demand grows and weather-related stress increases, the need to maintain and strengthen the grid remains. Long-term affordability depends on a strong, resilient system. Across Exelon, affordability and reliability are being addressed together. We manage expenses carefully, deploy capital where it creates the greatest customer value, and support customers through assistance programs and energy savings initiatives. We are also taking steps to ensure growth benefits existing customers rather than burdening them. As new large-load customers connect to our system, we are structuring agreements that require real financial commitments tied to the infrastructure needed to serve them.

FERC’s recent large-load dockets reinforced that approach, recognizing the need to protect existing customers while ensuring that large loads have real commitments behind their projects. This is exactly the principle behind our transmission security agreements, which are helping to protect customers by filtering out speculative requests before significant system investments are made, creating a clear picture of actionable demand. Despite these efforts, the extreme heat and system demand in July made one thing very clear: affordability cannot be solved through cost discipline alone. It also requires new supply. At the beginning of the month, PJM was pushed to its limits. Demand hit a record peak of 168 gigawatts.

PJM activated emergency procedures and called on demand response resources to maintain reliability, while power prices surged tenfold, from roughly $80 to $800 per megawatt-hour. Now, the grid held, and our teams did their job, but the system should not have to operate this close to the edge. And this is not a one-off event. This pressure is further evidenced by PJM’s most recent capacity auction. For the third consecutive auction, prices cleared at the FERC-approved price cap. Even so, the market fell short of PJM’s reliability requirement by approximately 6.8 gigawatts, larger than the prior 6.5-gigawatt shortfall, which is the equivalent of roughly seven nuclear reactors of missing supply.

Even more telling, only about 525 megawatts of new generation and upgrades cleared, indicating that even at the highest allowed price, the market is not attracting the level of new supply the system needs. Absent the FERC-approved price cap of $330 per megawatt-day, PJM’s own simulation shows prices would have cleared at approximately $555 per megawatt-day across the footprint and $777 in ComEd, indicating the underlying scarcity is even more severe than the headline price suggests. The July heat event, auction results, and market price signals all point to the same conclusion: demand is growing faster than supply, and the system is under increasing strain.

Our customers should not pay the price of a system that has been allowed to run too thin, and they should not have to wait years for solutions that are needed today. That is why Exelon is advocating for an all-of-the-above approach: transmission, demand-side solutions, market resources, and utility-owned generation where it makes sense. We are continuing the dialogue with our states and participating in FERC and PJM processes to advocate for policies that protect customers and help deliver energy reliably and cost-effectively. This is where the Exelon platform matters. Our scale, experience, and relationships across multiple states allow us to move from identifying the problems to advancing real solutions. First, transmission.

Exelon continues to lead on transmission expansion because reliability starts with the ability to move power where it is needed most. Transmission helps relieve localized constraints, connect new resources, and strengthen the grid as demand grows. That momentum continues with the recent submission of two additional MISO Tranche 2.1 competitive transmission bids in partnership with Invenergy. We will continue to leverage our scale, expertise, and strong development partnerships to pursue transmission opportunities across and beyond our footprint. Second, utility-generated power and storage. We are proposing solutions that give states more control, more certainty, and more direct customer benefits.

Utility-generated power and storage can add supply, improve reliability, and put downward pressure on long-term costs, with the accountability and lower-cost capital utilities are uniquely positioned to provide. This is not about ideology. It is about outcomes: reliable service, lower long-term costs, and greater energy security for customers. For example, during the extreme heat and record demand over the July 4 weekend, an ACE battery storage unit serving a New Jersey beach community was dispatched to support the grid. That one asset helped maintain reliability during a period of system stress, demonstrating the practical customer and grid benefits these investments can deliver. We have also seen these benefits play out elsewhere.

Earlier this month, ERCOT served a record peak demand of more than 91 gigawatts without emergency actions or curtailment requests, while power prices remained relatively stable at roughly $40 per megawatt-hour during the peak hour. Renewables and battery storage played a significant role in meeting that demand while supporting both reliability and affordability. Building on that momentum, we recently announced a significant new 500-megawatt battery storage project in New Jersey. And we continue to see storage as an important tool for customers because it is fast, flexible, and targeted.

Had our battery project been operating during the July 2 through July 5 heat wave, ACE customers would have realized approximately $7.5 million of energy cost savings that could have been returned to customers to help offset higher market prices. Storage solutions can provide peak capacity, improve reliability in constrained areas, support affordability, and help states meet their energy goals. The benefits are real, measurable, and already being demonstrated today. Lastly, energy efficiency and virtual power plants. Several of our utilities recently received approval for VPP programs that turn customer-sited resources into grid capacity. That helps reduce peak demand, lowers pressure on the system, and gives customers a direct role in the solution. Taken together, these are all practical solutions.

They also are areas where Exelon can deploy capital with discipline, where there is a clear customer need and strong execution visibility. We are not waiting for the market to solve this on its own. We are bringing forward actionable solutions that strengthen reliability, improve affordability, and give our states more tools to shape their energy future. Now, with that, I will turn it over to Jeanne to walk through our financial performance and provide additional details on our rate case activity and outlook. Jeanne?

Jeanne Jones: Thank you, Calvin, and good morning, everyone. Today, I will cover our second quarter financial results and key regulatory activity, discuss solutions we are advancing to support affordability and resource adequacy, and conclude with an update on our balance sheet and financing progress. Starting on Slide 5, we present our quarter-over-quarter adjusted operating earnings walk. Exelon earned $0.43 per share in the second quarter of 2026 compared to $0.39 per share in the same period in 2025. Results were higher by $0.04 per share year over year, primarily driven by $0.04 of distribution and transmission rates, net of depreciation and AFUDC, $0.04 related to last year’s Customer Relief Fund, and $0.01 of favorable weather at PECO.

This was offset by $0.02 of higher credit loss expense at BGE and $0.02 of interest at corporate and PECO. Our second quarter performance is in line with the expectations we discussed on the first quarter call and continues to demonstrate the value of disciplined execution across the platform. We are delivering on customer-focused investments that support top-quartile reliability while managing costs and timing items within the full-year plan. Looking ahead to the third quarter, we expect earnings to be approximately 27% of the midpoint of our projected full-year earnings guidance range.

This expectation contemplates the impact of weather, storms, and the PECO employee strike at the beginning of July, as well as normal weather and storm activity through the remainder of the quarter. As with historical practice, our quarterly shaping guidance also assumes anticipated revenue shaping and timing of costs across the utilities. Combined with results for the first half of the year, we anticipate the fourth quarter to benefit from the absence of one-time 2025 distribution and transmission rates, the unwinding of timing, and disciplined execution of bad debt and storm recovery efforts. We remain on track to deliver full-year operating earnings of $2.81 to $2.91 per share, with the goal of being at the midpoint or better.

Finally, we reaffirm our expectation to deliver annualized earnings growth near the top end of 5% to 7% from 2025 through 2029, supported by 7.9% annualized rate base growth, disciplined cost management, and a balanced financing plan that maintains strong investment-grade credit metrics. Turning to Slide 6, I will review the open base rate cases and other regulatory activity across the platform. These proceedings reflect our continued focus on recovering prudent investments that support safe, reliable service while advancing proposals that are responsive to customer affordability and the policy priorities of our jurisdictions.

Starting with Pepco Maryland, where a final order is expected next month for its traditional electric base rate case, this filing seeks recovery of critical investments that support reliability, accommodate growing customer needs, and strengthen the resiliency of the electric system, while also reflecting the impact of higher financing costs. Projects such as the White Flint Substation are tangible examples of work being done to increase capacity, reduce outage risk, and support long-term growth and economic development in the communities we serve. Also in Maryland, BGE filed an electric distribution rate case on July 2, seeking a $156.1 million revenue requirement increase to recover investments and costs necessary to maintain a safe and reliable grid under a historic test year.

The filing also reflects revised financing and storm restoration costs and includes proposals to establish a storm recovery mechanism and provide customers with additional payment flexibility. A final order is anticipated in January 2027. In Delaware, Delmarva Power’s electric base rate case continues to progress. DPL is seeking a $45.4 million revenue requirement increase to support investments necessary to maintain safe and reliable service, including system upgrades and reliability investments across its service territory. The filing also includes proposals designed to support affordability, including a new income-based rate and a bad debt rider. As permitted by Delaware law, DPL implemented interim rates effective July 9, subject to refund. A final order is expected in the third quarter of 2027.

Finally, at ComEd, the grid plan proceeding continues to move forward, with staff and intervenor rebuttal testimony filed earlier this month ahead of hearings in August. As a reminder, the plan proposes approximately $15.3 billion of investment through 2031 to support reliability, accommodate significant load growth, and advance the objectives of Illinois’ energy policy framework. An order is expected by December 15. Across these proceedings, our approach remains consistent. We are investing to support reliability, resiliency, and customer needs while remaining focused on affordability and cost discipline.

While our base regulatory filings remain focused on maintaining safe, reliable, and affordable service, we continue to advance additional solutions to help address growing affordability and reliability challenges, particularly in light of supply constraints highlighted by the recent PJM auction. Turning to Slide 7, practical and deployable resources, such as storage and virtual power plants, can provide capacity, reduce congestion, and help manage price volatility while supporting each state’s energy goals. Today, roughly 10 gigawatts of solar and wind across PJM go unused on any given day. Storage can capture excess generation and shift it to peak-demand periods, turning surplus clean energy into reliable, high-value supply.

Unlike many traditional solutions that can take five to 10 years or longer to develop, battery storage is a faster, scalable, and modular option that can often be deployed within approximately three years, even for large-scale batteries. In New Jersey, Atlantic City Electric, partnered with Invenergy, has advanced a 500-megawatt battery energy storage system using four-hour batteries to target roughly five peak-demand days a year in Pittsgrove. The project will be large enough to power approximately 400,000 homes and represents the single-largest battery storage installation in PJM. The Pittsgrove storage project was submitted in PJM Cycle 1 and represents approximately $1 billion in investment not currently reflected in our plan.

Combined with anticipated PJM market revenues, all of which will be returned entirely to customers, federal tax credits, the mitigation of energy and capacity prices, and deferred transmission investment, customers will see over $700 million in net benefits after the project is placed into service, importantly, without seeing any customer bill impact until at least 2035. Atlantic City Electric filed a request last week for regulatory approval of the mechanism to recover project costs, with a final order anticipated in the first half of 2027. In addition, we are pursuing similar opportunities in Maryland, where BGE and Pepco have submitted battery storage projects as part of the state’s distributed connected storage solicitation, which are currently under commission review.

Beyond storage, we are also advancing virtual power plant initiatives across our jurisdictions, which aggregate customer-sited resources to reduce peak demand, support grid reliability, and lower overall system costs. At ComEd, the approval to launch its first scheduled-dispatch VPP program is expected to increase the amount of battery storage available across Northern Illinois while providing compensation to participating customers. When paired with existing distributed generation rebates and incentives, the program creates a compelling customer value proposition while helping support the grid. Maryland also recently approved programs to allow a range of customer-sited assets to act as grid assets, and we continue to see momentum in New Jersey and Delaware as policymakers continue advancing distributed energy resource and VPP frameworks.

Together with continued transmission and distribution investment, these solutions provide practical tools to address affordability, reliability, and resource adequacy needs across our jurisdictions. Turning to Slide 8, we continue to execute our financing plan in a balanced and disciplined manner. Maintaining a strong balance sheet is core to our strategy and essential to funding the investment needed to deliver safe, reliable, and affordable service for our customers. To date, we have completed approximately 86% of our 2026 debt financing needs, including all expected debt issuances at the holding company, Pepco Holdings, ComEd, and BGE, materially reducing our remaining exposure to interest rate volatility for the year. In addition, our pre-issuance hedging strategy continues to provide protection against future rate movements.

We have already priced approximately 37% of our planned equity needs through 2029 via forward contracts under our ATM program, having priced all of our needs for 2026 and half of our needs for 2027. Our credit metric outlook also remains strong, with expected average credit metrics of approximately 14% through 2029, supporting the strategic and financial flexibility needed to advance our capital plan and capture additional customer-driven growth opportunities. We remain confident in our ability to deliver value for our customers and shareholders through disciplined execution, a strong balance sheet, and investments that support reliable, resilient, and affordable energy service. I will now turn the call back to Calvin for closing remarks.

Calvin Butler: Thank you, Jeanne. I will close on Slide 9. The story is consistent and straightforward. And as I said, performing today and actively preparing for tomorrow. Exelon is built for this moment. We have the scale, diversified footprint, operational excellence, and financial discipline to perform in a changing environment. In 2026, we remain focused on deploying approximately $10 billion of capital for the benefit of customers, delivering operating earnings of $2.81 to $2.91 per share, earning a consolidated operating ROE of between 9% and 10%, and maintaining a strong and resilient balance sheet. Just as important, we are pursuing growth where it creates real customer value, strengthens the grid, and supports the communities and economies we serve.

The environment is changing quickly, but our priorities are steady. We have the people, platform, and experience to navigate complexity, deliver on our commitments, and advance practical solutions for customers. That is why we remain confident in the path ahead. Josh, we can now open it up for any questions.

Operator: Thank you. As a reminder, to ask a question, please press *11 on your telephone and wait for your name to be announced. To withdraw your question, please press *11 again. One moment for questions. Our first question comes from Shahriar Pourreza with Wells Fargo.

Shar Pourreza: Good morning, Calvin. Good morning, Jeanne.

Calvin Butler: Hey. Morning, Shar.

Shar Pourreza: Calvin, PJM walked back from the EDC proposal that had the Members Committee supermajority in its letter. I guess, do you feel like where they landed meaningfully addresses the key issues in PJM? Do you have any plans to intervene further with FERC? I mean, it does not seem like you are waiting for an outcome here to step in. You proposed the BESS development. I am assuming that was not a one-off. So just kind of curious about the recent development. Thanks.

Calvin Butler: No. Thank you, Shar, and you captured it. We are focused on just really providing solutions, but let me first begin by applauding PJM’s efforts to address resource adequacy challenges with a sense of urgency and really looking at opportunities to bring new generation onto the system because these are important steps in the right direction. And we do believe that their measures may help address near-term reliability concerns, but they are unlikely to resolve any long-term affordability challenges. Ultimately, what we have always said, and we are very consistent, is that to really resolve long-term challenges on affordability, you need more generation to be brought online.

And we will continue to advocate for several important consumer protections in this effort, and we will continue to engage with PJM. But over the long term, we believe that states should play a central role in resource planning and procurement. And utility-owned generation needs to be part of that mechanism as a cost-effective complement to market-based solutions. And as we have talked about, you know, this is our Exelon Promise in action, and we will continue to drive this. But it is going to require a partnership and more active engagement with the states. Jeanne, anything you would like to add?

Jeanne Jones: Yeah. No. I think that covers it. And I think that, to your point about real solutions—and you noted it, Shar—the 500-megawatt battery solution, we have been working on this. We are pleased to see that, you know, we got through the filing, and we will work with the commission there. And to your question, no, it is not the only one, and we are working on others.

Shar Pourreza: Okay. That is perfect. And then your data center growth slide shows a combined 36 gigawatts. That is down around 11 gigawatts from the 43 gigawatts that you previously cited. Is that simply a reclassification or refinement of the queue? Any read-through there with PJM’s current dysfunction maybe causing some attrition or slower conversion in the pipeline? Thanks.

Jeanne Jones: Yeah. I will take that one, Shar. So I would say you are right. We did update it. I think this will continue to evolve. But I would also say we have always taken, as you know, a measured approach to the data center phenomenon, whether it was our position on co-location and ensuring fair cost allocation or the development of transmission security agreements, which, as you know, never existed in our regions. Right? And so we developed those agreements and made them part of our process. In addition to that, we also, throughout this, have kept our CapEx increases consistent with historical increases and really only put in capital that was certain and durable.

And I think that this update underscores that was the right approach. The TSAs are doing what they should. As we go through our cluster process, we said, you know, we are going to study the clusters. We are going to offer the customer a TSA. Sign the TSA, and then, importantly, put up collateral behind that. And so what this update reflects is we have now weeded out speculative projects, and it gives us proactive insight into what is real. And this is what you want management to do. You want us to provide real and durable growth.

And, importantly, our $41 billion of capital between now and 2029 remains unchanged due to this update because we have not put in speculative projects. And as I think about that growth, I would just say a couple of other things. You know, what is sitting in that 11 gigawatts? We have 4 gigawatts that have signed TSAs, and they are backed by $1 billion of collateral. The other 7 gigawatts in that high-probability category are projects that predated the TSA process but are further along, and we feel very comfortable that they will continue. And so the 11 gigawatts is significant, and we are going to continue to study the remaining 25 gigawatts that is on that slide.

But there is real growth, and it goes back to, you know, not just being focused on what is real on the T&D growth side, but how do we provide those solutions on the supply side to support that growth? And that is, you know, our first project out of the gate is the 500-megawatt battery.

Shar Pourreza: Got it. Perfect. Super comprehensive. Thank you, guys. Appreciate it.

Calvin Butler: Thank you, Shar.

Operator: Thank you. Our next question comes from Jeremy Tonet with JPMorgan Securities. You may proceed.

Jeremy Tonet: Hey, guys. Good morning. Appreciate your time. I guess maybe just going back to the regulatory front. You know, now a few months since the withdrawal of your PECO rate case, how do you think about filing the case moving forward? It just seems like we continue to see a lot of constructive data points out of the PA PUC. At this point, are there any inflection points you kind of hope to see before filing again? You know, what would encourage you to file at this time?

Calvin Butler: Yeah. Thank you, Jeremy. I appreciate that. And I think, once again, you captured it well. Let me just begin by saying that we share Governor Shapiro’s focus on affordability, and we have analyzed his letter and what his framework is, and I will ask Michael Innocenzo to jump in there. But let me just begin by saying that we have been having constructive conversations with not only the governor but his staff since day one. And like you said, we are seeing indicators that Pennsylvania is still a solid regulatory framework for us to operate in, and they view PECO as an economic partner and job creator in the state.

And we recognize also, and they have said it, that Pennsylvania needs financially strong, viable utilities and sustainable investments to encourage that economic growth. But understanding that, we will continue to partner, and we believe that investment in our system is required to maintain the reliability and growth that they expect, and we will do that over our long-term planning horizon. So I am going to give it to Mike to see if he has any detail he wants to share about the governor’s conversation.

Michael A. Innocenzo: Yeah. Thanks, Calvin. Thanks, Jeremy. I would say, you know, your point about data points—certainly, there are the data points, you know, the constructive settlements that have already occurred, constructive discussions on the active rate cases currently underway, and then it is our discussions. It is discussions with key stakeholders in Harrisburg. It is our discussions with the governor’s office. If you look at the key points that he is looking for and everybody is looking for, it is making sure that our investments are providing customer value and customer benefits, making sure that there is transparency on the ROE, and making sure that we are looking at every lever that we can to address affordability.

We think we have addressed that in multiple ways under the existing process, as others in the state are, and we are continuing to work with the governor’s office, the PUC, and the statutory intervenors, like the Consumer Advocate’s Office and the Small Business Advocate’s Office, having discussions to make sure that when we file again, we are addressing each of their concerns. And we feel confident we will be back in a way that will be very productive.

Jeremy Tonet: Great. Appreciate the insight there. And I just want to shift to the transmission front real quick, if I could. You know, to what extent can you tap into your identified $12 billion to $17 billion upside opportunity as we kind of think about the next plan? What win rate should we be thinking about as it pertains to upcoming competitive transmission windows for you guys?

Jeanne Jones: Yeah. So, hey, it is Jeanne. Of the $12 billion to $17 billion, I am just going to hit on a couple of things. I am going to turn it to Carim, who is head of our transmission and development group. So, the $12 billion to $17 billion is not dependent on one sort of theme. Competitive transmission is one of, I would say, probably five. Right?

So what we want to do is give insight into spending roughly that amount in our four-year period today, and so we see that continuing beyond 2029, driven by existing infrastructure over our 11,000 circuit miles, new business related to the data center pipeline, state policies around additional generation coming online, old generation retiring, the transmission needed to accommodate that, and, importantly, competitive transmission. And so maybe I will let Carim speak to kind of how we think about that.

Carim Khouzami: Yeah. Thanks, Jeanne. And, you know, I agree with everything Jeanne just said. And I would add, on competitive transmission, you have seen us be very active over the last 12 to 18 months in PJM and also in other RTOs, such as MISO. We are going to continue to do that, and you saw recently that we filed for two projects in MISO Tranche 2.1 in Iowa, the MARS and the EASL projects. We expect to hear back from MISO in the fourth quarter.

And what we would say is we think that we are very well positioned to take advantage of some of these opportunities based on our operational excellence and, importantly, our experience with 765-kV lines, so high-voltage lines. We are one of very few transmission operators that own and operate those types of lines today. And that is what increasingly more and more RTOs are seeking in their solutions. I would say I think we are very well positioned to continue to be successful, like we were in Western Pennsylvania this past PJM window. You will see us continue to be active.

Jeremy Tonet: Great. Makes sense. Appreciate the time there. I will leave it there.

Jeanne Jones: Thanks, Jeremy.

Operator: Thank you. Our next question comes from Paul Zimbardo with Jefferies. You may proceed.

Paul Zimbardo: Hi. Good morning, team. Thanks for the time. Just to follow up on the last one a little bit. Focusing on ComEd, that simulated $777-per-megawatt-day clearing price in the last auction, is that a catalyst for kind of unlocking even more incremental transmission and storage investments? I just think a lot more can pencil at that kind of potential price point, if you could share a thought.

Carim Khouzami: Paul, I think that is probably indicative of what we have been saying, which is we need an all-of-the-above approach. It is probably not just transmission. It is not just battery solutions. It is really all of the above. Transmission, as Calvin mentioned in his prepared remarks, provides the optionality of moving the electrons from where they are being generated to where they are needed. Battery storage is very effective in helping to shave off the peaks and avoid transmission, avoid peak pricing, and help to insulate customers from that. So, from our perspective, you can expect to see us be active on both those fronts, as well as others.

Really, what we are looking for is wherever those opportunities are for us to serve our customers, to help affordability and help reliability, that is where you will see us be active. And storage and transmission are two examples where we see a lot of benefits there.

Jeanne Jones: Yeah. And that was contemplated already as part of the $12 billion to $17 billion when I mentioned kind of state-focused solutions. So definitely an opportunity there. We have seen over the last several planning cycles 80% to 100% of our four-year capital increase be in transmission, specifically for these issues. The other thing I would say is the state is well aware of this as well. If you look at what was passed in legislation last year, the state not only expanded energy efficiency, but also our distributed generation rebate programs, two programs that are meaningfully helpful for customers but also are treated as regulatory assets that we earn on—good for customers and good investments for us.

They also are going to run a 3-gigawatt storage procurement this year, with, I think, 1 gigawatt of that 3 gigawatts this year. And then, importantly, they are taking a comprehensive view. Right? They are going to do their first integrated resource planning preview in November of this year. So pleased to see the state focused on this and that there are ways for us to lean in, as Carim said, not just in one area, but transmission, energy efficiency, DG rebates, and supporting through VPPs as well.

Paul Zimbardo: Okay. That makes sense. And then a higher-level question, if I could, but I think an important one. Just holistically, it looks like there have been some—I do not know, maybe—paper cuts across the jurisdictions, legislation, and some regulatory action. Overall, how would you frame the conservatism in the plan overall? And I know you had that cost-cut update in the first quarter, but just overall comfort in the plan would be helpful. Thanks.

Calvin Butler: Yeah. Thank you, Paul. I would say that comfort is not the word, but focused on execution is the word because we do not actually see it that way. We view that the strength of Exelon’s model is that we are not dependent on any single jurisdiction, regulatory outcome, or growth opportunity. As you just alluded to, when you think about what we have been able to accomplish with adverse rulings or inaction by some of our commissions, we have met and exceeded expectations that we have shared with you. And that is that diversity of our platform coming to life.

I always talk about—and you have heard me say it, Paul—the power of our platform and not having one jurisdiction outweigh what we are able to accomplish and being able to move capital around and put it in place for the benefit of our customers and the communities. So, yes, there are single paper cuts, as you referred to, but not one of them is driving the ultimate outcome of Exelon. So when we pulled the Pennsylvania rate case, the PECO rate case, we reaffirmed our guidance. We did not lower our capital.

In 2023, when ComEd’s grid plan was disallowed, the team got to work, met and exceeded our numbers because that is what we do, and that is what you should expect us to do. So I appreciate the observation, but we do not see it that way at all.

Paul Zimbardo: Okay. No. Excellent. Thank you for the answer.

Calvin Butler: Thank you.

Operator: Thank you. And our final question comes from Andrew Weisel with Scotiabank.

Andrew Weisel: Hi. Good morning, everyone. I want to first ask you to just elaborate a bit on the Pennsylvania commentary. I do not expect you to get too far ahead of the next rate case filing, but how are you thinking about CapEx levels and categories? Are your conversations pointing toward minimizing spending purely focused on reliability and safety? Or I heard you talk about supporting economic development. What does that look like? And is that specifically related to data centers and AI, or how are you thinking about that versus affordability? Other than, you know, how can you help other than the deferred spending that you talked about on the first quarter call?

Any more detailed commentary would be very helpful. Thank you.

Calvin Butler: No. Great question. I am going to ask Mike, who is serving as the CEO of PECO, to really give further clarification. And do not hesitate, if you have any follow-up, do not hesitate to ask, okay, if we do not scratch the itch.

Michael A. Innocenzo: Thanks, Calvin. Thanks, Andrew. Yeah. I would, you know, go back to—I think you even alluded to it in your question there—it is making sure that we are really clear on areas that have that customer value. And we have heard loud and clear from the folks in the state that economic development continues to be important to the state. So we will make sure that our investments are supporting that, both on the transmission and on the distribution level. Safety, reliability, and resilience—it is an area that has seen increased storms and emergencies. We know the value that a reliable grid and a safe grid provide.

As Calvin mentioned in his opening comments, PECO is a top performer nationally and is the top performer in the state. So we will continue to focus on those investments that are aligned with our long-term infrastructure improvement plans, both on the gas and electric side, also taking advantage of the DISC, and also looking for areas where we can drive affordability through other mechanisms. Including, just recently, PECO was awarded a RISE PA grant of $50 million for an investment that we will be making at our gas plant in West Conshohocken.

So it is really just making sure that everything that we do is clearly aligned with those key categories, is well communicated, and is justified not only through the rate case process, but prior to the rate case process as we go in.

Calvin Butler: And Andrew, let me just share. I think Mike captured it, and I just want to emphasize a point he made: communicating with all stakeholders on what and how we are doing it and the value that we are creating. Our number-one priority is always maintaining a reliable and safe system. We are never going to do anything to put that in jeopardy, but we will actively be communicating with all the stakeholders throughout this process.

Andrew Weisel: Okay. Great. That is helpful. And you mentioned the DISC mechanism. Does that seem like something you will be leaning on a bit more? That seems to be a theme that we are hearing more of.

Michael A. Innocenzo: Yeah. We have used it over the years already, so we will continue to do that. But as part of our going-forward conversations with the chair of the PUC, we will be looking for other ways that we can leverage that even further. That will be part of our plan going forward as well.

Andrew Weisel: Okay. Very good. Then one more, if I can. In Illinois, I know that there is the IRP process the state is pursuing. Can you talk a bit about that? Given that the state is in PJM, what exactly is the goal here? Clearly, there are issues. You talked about the shortfalls and the high pricing from the auction if there were not the cap. As far as I can tell, I do not think it is too likely the state will leave PJM soon. I know there is some talk about it. I have heard the name ERCOT-IL floated around, which is a great name, but I do not know how likely that is.

So maybe you could just talk about what the goal of this IRP is and what role you might be playing in that.

Jeanne Jones: Yeah. I think the goal, ultimately, is what we need each of our states to do is to get a better picture of what they need from a state perspective in terms of demand versus supply. And it gives them the ability—the ICC and the other agencies working with them—the authority to expand programs, right, based on that analysis. Do we need to expand energy efficiency? Do we need to procure more storage? Do we need to do more in distributed generation? How do we look at our state emission limits? Things like that.

So that is the goal, to say, how do we get more control over our own supply and demand situation within the state, which is something we applaud any state for doing. We are seeing Maryland study different procurement models. We are seeing Pennsylvania hire an independent consultant to study resource adequacy. Across all of our states, you know, Governor Moore is looking at supply solutions. This, I think, is the goal of all of our states, who are working very hard with PJM for long-term solutions, saying, hey, I have got to keep all options on the table.

And the first thing I need to do is kind of have a good view of what my specific state needs, and we think that is absolutely the right thing to do.

Andrew Weisel: Okay. Very helpful. Thank you, guys.

Calvin Butler: Thank you.

Operator: Thank you. At this time, I would like to turn the conference back over to Calvin Butler for closing remarks.

Calvin Butler: As always, I just want to say thank you for taking the time to join us for our Q2 earnings call. We appreciate your continued interest and support, and we look forward to sharing further progress in the months ahead. And with that, Joshua, this concludes our call.

Operator: Thanks to all our participants for joining us today. This concludes our presentation. You may now disconnect. Have a good day.

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