Hello, and welcome to Exelon's First Quarter Earnings Call. My name is Lateef, and I will be your event specialist today. All lines have been muted to minimize background noise. Please be aware that this webcast is being recorded. During the presentation, there will be a question-and-answer session. It is now my pleasure to hand the program over to Andrew Plenge, Vice President of Investor Relations. The floor is yours.

Thank you, Lateef. Good morning, everyone. Thank you for joining us for our 2025 first 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.

Thank you, Andrew, and good morning, everyone. We appreciate you joining us for our first quarter earnings call. 2025 is off to a good start. We're reporting operating earnings of $0.92 per share, representing strong growth over the first quarter of 2024, and ahead of expectations, which keeps us on track to deliver on our 2025 operating earnings guidance range. Reliability and safety performance continues to be very strong as well despite a number of high wind events throughout the winter months that challenged our operators who remain the best in the business. ComEd and Pepco Holdings are projecting top decile outage frequency and duration performance while BGE and PECO are in the top quartile. We have a relatively lower level of base rate case activity this year and our two open rate cases remain on track at Atlantic City Electric and Delmarva Power, which Jeanne will cover in her remarks. We have also been actively engaging in a variety of legislative and regulatory reforms to ensure energy policy keeps pace with the industry and broader economic trends. Ensuring reliable and affordable energy for all customers is critical to our jurisdictions and the nation as a whole as they work to realize their economic and energy policy ambitions. The first quarter of 2025 has already seen great progress on that front. In Maryland, the legislature passed several energy bills that take important steps around energy security, including prescribing a competitive process to procure new dispatchable resources and capacity while providing a path for alternative approaches should they be needed. They also lay out ambitious goals around developing battery storage at both the distribution and transmission level, offering us and developers further opportunity to shore up the state's energy supply. And the state also outlined for the first time in law the recognition of a multi-year plan construct, prompting a robust discussion that highlighted its merits of increased transparency, planning, and alignment while giving stakeholders a greater say in how much and where their dollars should be invested. We now look to the commission to conclude its multi-year plan lessons learned process, so we can move the state forward with confidence in meeting its energy and economic goals. Our other states are also considering legislation to address elements of energy policy, including a focus on the energy security and cost allocation implications of large load growth. We expect to have more to share on those sessions as the year advances. There has been significant activity at the regional and federal level as well. First, PJM has made considerable progress to address suboptimal outcomes in its capacity market construct. We have been pleased to see that FERC approved a number of solutions put forward by PJM via 205 filings, including its temporary price collar and refinement to its deactivation process. We are also encouraged to see the response to its reliability response initiative, which has generated applications worth almost 27 gigawatts worth of nameplate capacity. In February, FERC initiated a 206 proceeding requesting that PJM and its transmission owners investigate whether the tariff remains just and reasonable in rates, terms, and conditions of service that apply to colocated arrangements. We are pleased with the leadership shown by FERC in working to resolve this issue in a timely manner, along with PJM's efforts to meet the aggressive timeline to address a very complicated topic. We're also encouraged by the consensus that PJM transmission owners were able to reach on a complex topic in such a short period, and we look forward to assisting the industry in aligning on a policy that equitably supports the national critical issues of energy security and economic development. More details on the progress we're making across these forms can be found in our appendix. Maintaining momentum across these policy arenas is key to meeting the task ahead of us and we see no abatement in our opportunity for new large loads in our territories. The 17 gigawatt pipeline of opportunity that we communicated in our fourth quarter earnings call remains fully intact. We are also conducting advanced studies on an additional 16 gigawatts of high-density load, which we anticipate will result in significant incremental commitments from customers upon aligning on investment needs and timing. We continue to focus on ways to enhance our process to ensure we are offering unparalleled service to new customers in our territories while continuing to ensure existing customers are protected and benefit from the new load. And the pace of new business seeking to connect to the grid makes it even more critical for stakeholders to collaborate actively and with urgency on policy that balances the common goals of reliability, affordability, and progress toward a cleaner energy future. We look forward to providing further updates on our new business prospects in future quarters. As a reminder, this is just one of the elements that contributes to our visibility into $10 billion to $15 billion of transmission opportunity beyond our plan. As we laid out in our fourth quarter call, the need for investment in our high-voltage network is real and growing. We are proud to have Carim Khouzami now leading those efforts with his extensive background in commercial, regulatory, and operational roles ideally suited to industry tailwinds and our unique transmission assets and capabilities. I also want to congratulate Tamla Olivier for her promotion to BGE President and CEO. Her effectiveness leading increasingly large organizations during her 15-year career here will continue to ensure BGE's 2 million electric and gas customers receive high-value service. Congratulations to you both. Lastly, I'll remind you of our expectations for our four-year outlook. We reaffirm our plan to invest $38 billion over the next four years for the benefit of our customers that will drive 7.4% rate-based growth and be financed with a balanced mix of debt and equity. In fact, we have been able to de-risk a large portion of our financing needs for the year with all of our planned corporate debt issuances completed and 60% of our $700 million annualized equity need priced. By earning a fair return on that investment plan, we expect to deliver annualized earnings growth of 5% to 7% through 2028, generating consistent growth and long-term value. I'll now turn it to Jeanne to discuss our financial performance and provide further details on our rate case activity.

Thank you, Calvin, and good morning, everyone. Today, I will cover our first quarter financial update and progress on our 2025 regulatory activity. Starting on Slide 5, we present our quarter-over-quarter adjusted operating earnings block. Exelon earned $0.92 per share in the first quarter of 2025, compared to $0.68 per share in the same period in 2024, reflecting higher results of $0.24 per share over the same period. Earnings are higher in the first quarter relative to the same period last year, primarily driven by $0.14 of new distribution and transmission rates in effect across our jurisdictions, $0.03 of favorable weather at PECO and $0.02 of tax repairs timing partially offset by $0.03 of higher interest expense due to higher levels of debt at increased interest rates. As anticipated, results are also impacted by timing at ComEd, which totaled $0.09 for the quarter and includes $0.02 due to the lower revenue recognition in 2024, as we awaited updated rates from the rehearing order and eventual approval of our refiled grid plan. The remaining $0.07 is due to year-over-year revenue shaping and O&M timing including higher storm and IT project-related spending in the first quarter of 2024. We expect the revenue shaping and O&M timing to reverse in the balance of the year. These results are slightly ahead of our indications on the fourth quarter call primarily due to this timing of O&Ms as well as the timing of tax repairs. As we look ahead, our second quarter earnings are expected to be approximately 14% of the midpoint of our projected full-year earnings guidance range, which contemplates partial reversal of the ComEd timing along with normal weather and storm activity. In combination with Q1 results, this would result in recognizing 48% of projected full-year earnings in the first half of the year, consistent with seasonal shaping in prior years, allowing us to 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 are reaffirming 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, we currently have two base rate cases open at Pepco Holdings. The Delmarva Power gas distribution rate case filed last September remains on track with interim rates, which went into effect on April 20 subject to refund. The rate case seeks to recover continued reliability investments such as aging piping upgrades and upgrades to its LNG plant, which helps protect customers from supply price volatility during peak periods. It will be open for intervenor and rebuttal testimony in July and September before evidentiary hearings are convened in November. An order is expected in the first quarter of 2026. Our second open base rate case is at Atlantic City Electric where we are seeking recovery of grid improvement and modernization efforts in line with New Jersey's Energy Master Plan and the Clean Energy Act. The proposed procedural schedule was approved by the judge in March with settlement discussion set for late April to early May. Evidentiary hearings are scheduled to begin in late July and continue into early August with an order expected by the end of the year. ACE is also anticipated to implement interim rates on August 21 subject to refund. In Maryland, we continue to work to close out our final reconciliations from the first BGE and Pepco Maryland multi-year plans and remain engaged in the lessons learned process as we approach our next rate case filings. We are encouraged that the legislature recognized the multi-year construct in the recently passed Next Generation Act. This legislation provides greater direction and alignment between all stakeholders on the future investments needed to support our customers. Now that we are on our second NYP at BGE and our fourth one in Maryland, we feel better prepared to support a multi-year investment plan without a reconciliation and we look forward to working with the commission and our stakeholders to continue to demonstrate customer benefits in future multi-year plan filings. We steadfastly believe that forward-looking plans are the most planful and cost-effective way to ensure the reliability and resiliency of the system while meeting the state's energy and economic goals. We await the commission's comments on the lessons learned to fully ensure our next filing aligns with the PSC's recommendations that accommodate the new legislation and the lessons learned proceedings. Finally, in Illinois, ComEd filed its annual performance evaluation and request for annual adjustment under 2024 base distribution rates on April 29. The requested adjustment of $268 million is primarily driven by operating under lower revenue requirements throughout 2024 relative to the final approved order and it includes the revenue impact of achieving a performance metrics adder of over 5 basis points. ComEd's actual revenue requirement in 2024 closely aligns with the final revenue requirement approved in December 2024. Direct and rebuttal testimony is expected to occur throughout the summer at hearings and an ALJ proposed order in the fall. A final order on ComEd's reconciliation is expected in December. Turning to Slide 7, I will conclude with a review of our balance sheet activity. From a financing perspective, we took advantage of the favorable market conditions in the first quarter and made substantial progress on our 2025 capital needs. First, we have completed nearly 50% of our planned long-term debt financing transactions, having successfully raised $650 million for the Pepco Holdings utilities and all of our $2 billion of debt financing needs at corporate, including $1 billion of hybrid debt. The strong investor demand and attractive pricing for our debt securities continue to be a testament to the strength of our balance sheet and to our value proposition, positioning us well as we seek to finance the energy transformation in the most cost-effective way for our customers and our investors. We also continue to execute on our pre-assurance hedging strategy implemented in 2022 to further protect us from interest rate volatility. As it pertains to equity, as a reminder, in our last guidance update, we estimated we would finance 40% of our incremental capital investment with equity, resulting in total equity needs of $2.8 billion over the four-year plan and implying approximately $700 million of equity on an annual basis. For 2025, we successfully de-risked nearly 60% of our annualized needs through our ATM issuing approximately $175 million worth of shares and pricing an additional $250 million under forward agreements for issuance later in the year. As you heard on our last earnings call, we project to continue to have 100 basis points to 200 basis points of financial flexibility on average over the plan for our consolidated corporate metrics above the Moody's downgrade threshold of 12% approaching 14% at the end of our guidance period. We continue to advocate for language that incorporates repairs for calculating the corporate alternative minimum tax and we are encouraged by the recent bipartisan legislation introduced in the U.S. House to advocate for this change, which will lower energy costs for our customers. However, we will remind you that our plan assumes that the final regulations will not allow for repairs, 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. Thank you. I'll now turn the call back to Calvin for his closing remarks.

Thank you, Jeanne. In closing on Slide 8, I'll reconfirm our focus as we look to add another year of execution to our track record as a premier utility. Our talented and dedicated employees will continue to deliver operational excellence investing $9.1 billion in the system to deliver high reliability service to our customers. We are also constantly working to find the right rate-making mechanisms that allow us to fulfill our responsibility and privilege to serve the 10.7 million customers that count on us for their energy needs. Those mechanisms need to provide accurate compensation for our investors while allowing for the critical feedback and collaboration necessary to ensure we are only investing where our jurisdictions want us to invest. We recognize some of our customers are broadly struggling with economic uncertainty as we all navigate updated tariff policies, federal budget reprioritization, and increased energy supply costs. Weather extremes like our first cold winter in years only exacerbated those pressures. We do feel that we are relatively well-positioned to protect our customers as it pertains to the proposed tariff policy with approximately 90% of our supplies sourced domestically, we have estimated the impact to be around 1.5% of our four-year capital and O&M investment plan before any mitigating efforts with the majority impacting capital. The impacts will also be delayed as a result of our inventory levels and long lead time requirements. With our size, scale, and deconcentrated investment plan and the culture of cost discipline, we expect to be able to manage any tariff-related impacts highlighting the value of Exelon's platform. And while we are advocating for the continuance of the tax credits under the IRA law, we are not directly exposed to any reductions in those nor to any transferability restrictions. As Jeanne mentioned, we remain committed that we will be able to improve our position with respect to the corporate alternative minimum tax associated with that law. We will continue to leverage a variety of tools to assist customers including deferred payment plans as well as suspended disconnections and associated fees and we are advertising budget-building options throughout community forums in custom and community engagement events. Additionally, our policy advocacy has focused on solutions that enable PJM and our states to acquire new power supply as cost-effectively as possible while serving large new loads equitably. As I noted earlier, we have made good progress thus far in legislative and regulatory forms. Finally, we also stress the degree to which we try and maximize the dollars that we need to invest in the grid to serve our customers. We focus on forward-looking recovery mechanisms because it allows us to collaboratively determine where best to invest their dollar and do it efficiently. In fact, over the last five years, over 98% of the net profits we earn at our utilities, all of which are established and reviewed through rigorous regulatory proceedings, we have been reinvested back into the business for our customers. And for every $1 million of capital investment we make at our utilities, it supports eight jobs or $1.6 million in economic output. So customer affordability continues to be a big part of our focus this year, which complements our efforts to drive economic development to further benefit our jurisdictions. And of course, as always, you can count on our continued discipline in executing our financial plan, earning a consolidated ROE of 9% to 10%, maintaining a strong balance sheet and reported earnings within our guidance range of $2.64 to $2.74 per share. We look forward to making 2025 our 25th anniversary of Exelon, another year where you can count on us to deliver consistent growth and long-term value. Lateef, we can now open it up for any questions.

Our first question comes from Nick Campanella of Barclays. Please go ahead, Nick.

Good morning, Nick.

Hey, Nick.

Hey, good morning, everyone. Hope everyone's well. So I guess, just you have this new Maryland legislation that's out there. It does prohibit reconciliations after Jan 1, 2025. And I'm just wondering if you can maybe kind of talk about how you think that could impact the outcomes in the BGE or the Pepco reconciliations. And if an order were to kind of go against you there, is the guidance resilient to that and maybe you can kind of give some more color on that. Thanks.

Thank you for the question, Nick. To address your point directly, we anticipate the reconciliation process to proceed soon, and our plan is firm and ready to implement as we've evaluated all options. We don't see anything that could hinder us from achieving our goals. Regarding Maryland, it's important to note that recent legislation was passed, which includes key elements I want to highlight. Firstly, it now allows for NYP approvals without reconciliations. Having gone through this process multiple times, we are confident in our ability to collaborate with stakeholders and allocate resources effectively to meet budget expectations for future NYPs. Secondly, the legislation includes specific provisions on large load colocation, ensuring that infrastructure upgrades and reasonable costs do not unfairly burden other customers. This will impact loads exceeding 100 megawatts with a capacity factor greater than 80%. We're committed to maintaining affordability in our jurisdictions, and Maryland has formalized this commitment. Additionally, the new legislation emphasizes battery storage, directing the Public Service Commission to procure 150 megawatts of distribution battery storage from each utility, with a majority owned by the utility. It also mandates the PSC to initiate a procurement process for 1.6 gigawatts of transmission battery storage by January 26. This demonstrates that they recognize the challenges and are making strides forward. I also want to commend the two new commissioners appointed, who bring a wealth of regulatory experience and will be crucial as we progress. In summary, we aren't worried about the reconciliation aspect of the legislation, and we are confident in our collaboration with the state to meet future demands.

Thank you for the information. I appreciate it. Regarding the FERC 206, I’ve noticed some power companies have requested to settle on this issue, which was suggested a week or two ago. I'm curious about your thoughts as a transmission and distribution entity. Are you open to settling the colocation issue, or do you believe it needs to go through the full process at FERC? Any insights would be appreciated. Thank you.

Thank you, Nick. I would say, we're always open to discussions and have been from the very beginning and that hasn't changed. We continue to move forward as a T&D to meet our customers' expectations. We talk about the 17 gigawatts and another 16 that we're considering. So our process is continuing. I think the transmission owners coming together and putting forth this statement, EEI putting a transmission owner unified statement to FERC goes a long way. So our principles have not changed one bit, Nick. And we are right there and in having discussions with the IPPs, we're open and we're open to make sure that we get this done quickly and equitably for all of our customers and that has not changed.

Thank you. Our next question comes from the line of James Kennedy of Guggenheim Partners. Your line is open, James.

Hello, James.

Good morning. So one of your peers has been talking recently about the introduction of legislation in Pennsylvania to support potentially regulated generation. I guess, what's your degree of involvement in that process and any views on REG generation versus potential long-term PPAs and other mechanisms? Thanks.

I want to emphasize that we will support anything that benefits our customers in terms of resource adequacy and affordability. Our teams are actively engaged in discussions at both the legislative and regulatory levels. It's important for us to maintain a balance and ensure that we have a clear path for recovering investments. As my CFO has stated, we need a straightforward approach where recoverability is well-defined in legislation. We are aware of the implications and are collaborating with the state to address these needs, prioritizing affordability and energy security for our customers.

Okay, perfect. And then just on the data center side, thanks for the incremental color in the appendix slides on the phases. Is there like a rule of thumb that we should be thinking about for how you convert between the phases and ultimately shift into the capital plan? Just any kind of timeline considerations. Thanks.

Yes. Hey, James, yes, we don't really have a rule of thumb because every project is different and we always start with how do we be most cost-efficient for all of our customers. And so as you can imagine, therefore it depends. But what I will say is that the $38 billion that we have in the plan, $5 billion of that is for new business. And when I look back to our last four-year plan that was an increase of $900 million. So we can expect to continue to see more incremental capital necessary to accommodate the new load. As we outlined in our fourth quarter call that $10 billion to $15 billion beyond the planning period, at least $1 billion is related to this new business. So as we know, the investment is needed, we build it into the plan. But as you also know, we don't put anything in that isn't certain. So of the $38 billion, $5 billion related to new business and that's at least a $900 million increase from our last four-year period and we expect that to continue.

Thank you. Our next question comes from the line of Julien Dumoulin-Smith of Jefferies. Please go ahead.

Hey, Julien.

Hey, good morning, team. Nicely done, guys. Hey, thank you again for your time.

Thank you for that.

Absolutely. Just following up on some of the last questions, if I can press a little bit further, if you don't mind. First, on the data center front, I mean, you all are framing these as 80% and 50% probability. They're fairly high numbers in isolation. How do you think about the timing here and how that it perhaps is juxtaposed against the backdrop of this FERC ongoing process? Again, I think we all take it for granted that maybe one sort of precludes the other. But how do you think about it? 80% probability is non-trivial, particularly given the metric that you define them as being having already achieved.

I want to emphasize that none of this is reliant on the colocated FERC 206 process. This pertains to traditional front-of-the-meter transmission and distribution customers within our service area, and we’re not experiencing any delays as we navigate that process. We announced 16 gigawatts for the fourth quarter of 2024, and those remain very robust with a high probability. Additionally, we’ve provided further details on Phases 1, 2, and 3 for those 16 gigawatts. This time, we also offered insight into what lies ahead, as we have another set of 16 gigawatts. To clarify, they both refer to 16 gigawatts, but one is a new addition. Twelve of these gigawatts come from a cluster study we are conducting in the ComEd service area, while the remaining four are spread across utilities on the East Coast. We are seeing ongoing progress focused on front-of-the-meter initiatives, independent of this process. As Calvin mentioned, we’re continuing to work through the FERC process simultaneously to accommodate all types of customers. When we consider the distribution of projects, around 70% falls into Phase 1, 20% into Phase 2, and 10% into Phase 3. We are confident in the additional 16 gigawatts, which can be thought of as aligning with the Phase 1 timeline. We aimed to clarify our approach and are adapting to demand by employing more cluster studies, allowing us to provide customers with improved insights regarding timeline and costs. As the cluster study concludes and we progress with the four additional gigawatts, we will move the 16 gigawatts into the other phases and keep you updated regularly.

All right, excellent. Thank you for clarifying that, it remains distinct and separate. I appreciate that. And then related just not to nitpick too much on the prepared comments, but just curious, when you talk about assisting the industry with respect to the backdrop here on leadership at FERC, how do you think about what that timeline looks like and what that settlement process could be? I know that there's several different forms where you could have another PJM stakeholder process, that there could be more of a FERC oriented process here. How do you think about potentially finding a joint arrangement or settlement here amongst a litany of different parties?

Good morning, Julien. It's Colette Honorable. How are you today?

Great. Thank you.

Julien, can you hear me? Okay, good. Let me address your question. First, let's examine the docket itself. We really see significant agreement within the docket. Calvin mentioned the filing by EEI, which represents a majority of the industry, the NERC filing, the filing from the Independent Market Monitor, and the United Transmission owner group, all of which show FERC that there is a record and consensus on how to handle this load. When Calvin stated that we appreciated the commission's efforts, it was to move quickly, so we can gain the clarity we need. That’s where we began in this matter. Therefore, we are not surprised by the progress of the docket. As Calvin noted, we are open to discussions of any kind, but our primary goal is for FERC to issue a decision swiftly, so we can all achieve the clarity necessary to support the significant load that Jeanne described, while also ensuring affordability and energy security for all our customers.

Got it. So looking for FERC to take action principally before anything else with a firm decision?

We think there is a record before them to do so. As Calvin mentioned, should the commission determine that settlement discussions are appropriate, we would be more than willing to participate in that exercise as we have been very constructive partners in the past. If you look back at our record here, we were the ones that really started in the forefront of this issue. So we've demonstrated that we will be constructive and collaborative partners, but we're ready to continue supporting this moment in time.

Excellent. Thank you all very much. See you soon. Cheers.

Thank you, Julien. Thank you.

Thank you. Our next question comes from the line of David Arcaro of Morgan Stanley. Please go ahead, David.

Good morning, David.

Hey, thanks. Good morning. Maybe a quick follow-up on the data center side of things. Could you give a sense of the timing for when that load is expected to ramp up within your forecast period? I'm also considering your infrastructure and any limitations there; when will you be able to connect in new large loads, given such a big pipeline?

Yes. So as we think about the 16 gigs that we have on the slide, we think about 10% of the load will be on by 2028, another a third of it by 2030, we have three-fourths of it by 2034, and then the remainder beyond that. So that kind of gives you an insight into the view as we see the load coming on. And then your second question again, it depends on the customer, I mean, I think at times where it's 36 months, we're always trying to push to be faster for our customers. Other times it can be a little bit longer. But in all of our discussions, the most important thing we hear from our customers is just understanding the timeline and being upfront with that, which is why these studies are so important.

Let me add there, Jeanne. David, also I think it was last year we talked about how we restructured our customer strategy organization and we created a centralized group to talk with the data center developers and really to understand what their needs were. And by strategically working with them ahead of time, what we found is that we can meet their needs and understand how much they need to ramp up in a timely fashion and also determine appropriate sites where they can connect quicker onto the system where the infrastructure was already there or in large part there, so it required less. And that's the partnership. Give you an example, just about a month ago, we had a EEI hosted and we hosted with them a large key account meeting in Chicago. And we had sidebars with all the large data center developers to talk about their needs and where they were going. And we looked at all of our six jurisdictions to say if this is what you need, here are sites that we've identified and that's that partnership. So to Jeanne's point, all very different, but it's a very collaborative approach in how we're targeting it.

Okay, excellent. Thanks for that. And wanted to touch on affordability. We've seen some states may be louder than others, but seeing with the impact of PJM capacity, pricing increases, an increased focus on affordability, wondering how you're kind of approaching that, getting ahead of that and managing affordability challenges and concerns broadly across your portfolio.

No, you nailed it. It has become the primary topic of discussion this past winter. As I talked about in my prepared remarks, this was the first cold winter we've had in several years. And as an example, BGE bills were up approximately 50%, with 80% of that increase due to weather, commodities and just legislative changes that were made. Our Delmarva Power & Light, DPL had no real changes in gas distribution rates, but equally high increases. We continue to see weather volatility and supply costs, which are the primary challenges we are working to address and mitigate for customers. And as I talked about, what we're doing proactively, we're helping our customers manage the cost. We're talking about energy efficiency. We're going out to customers, homes and small businesses, really driving what they can take action on to mitigate some of those. We're deploying our tools to assist customers. We've already suspended disconnections. We've delayed or extended payment plans, removed any additional charges. And I think the biggest piece for us is that we're out in our communities at a robust level, holding community forums and connecting with them and ensuring that the assistance that may be available at the state and local level, we're connecting them with that. So that is the key. Are we done? Absolutely not. Do we recognize the hardship that many of our customers are facing? Yes. As I always say to my team here, $1 increase for some of our customers is $1 too much. So we're not taking it lightly. And so we're having conversations at the state and local level about how to partner. And I think a good scenario that you can think about the Maryland legislation that I was talking to Nick about earlier, they allocated $200 million from a fund that they had established. And I think that fund was called, it was the Strategic Energy Infrastructure Fund directed at companies and it had about $300 million in. They took $200 million of those dollars to help people with paying their bills. Now how can we partner with them to let those dollars go further? And we're having those discussions. So you're right. Key issue, the key issue, and we're meeting those challenges.

Thank you. Our next question comes from the line of Bill Appicelli of UBS. Please go ahead, Bill.

Hey Bill.

Hey Bill.

Hey, good morning. Just wanted to go back to Maryland for a second. Maybe on the lessons learned docket, can you just remind us on the timeline and maybe what's the range of outcomes there? Given the legislative development, is there any concern around not continuing the NYPs, beyond the current plan or what sort of is maybe a range of scenarios that we could look to there?

I want to emphasize that this year's discussions surrounding NYPs showed that the state legislature recognized their importance. However, we still have the discretion on whether to proceed. We believe that our multi-year collaborative approach and engagement with stakeholders is the most effective strategy. So far, nothing has indicated that we would deviate from that plan. I'm glad that the commission has initiated the lessons learned process, which has continued into this year, likely affecting the timeline. We anticipate that the recent legislative session will lead to a ruling shortly. As you might remember, we conducted a thorough process to ensure we chose the best option. I expect we'll have a decision soon, likely by the end of the second quarter regarding the lessons learned. Throughout this process, everyone has submitted their comments and participated, from the Office of People Counsel to large industrials and residential customers. We have made sure that all voices were considered, which was our goal.

Okay, great. And then just going back a little bit to the resource adequacy debate. You're indicating an ever increasing amount of load that's interested in coming on. The queue, I think for new capacity additions remains pretty small. I think there's only about 6 gigawatts of gas in the queue for PJM. I guess, the FERC is going to be having this technical conference here in June. But I guess, where do you guys stand in terms of addressing the resource adequacy concerns as you look out to the amount of load that wants to come on over the next, call it five to seven years?

We do believe it's a portfolio approach, meaning that there's an approach that PJM and all of our states can take that we can't limit how we get the generation resources to the table. We should be looking at everything. And if it's a delay of closings of certain plants is it's allowing gas to come in and build. And we talked about this, utilities, owning, generation, all of that needs to be on the table because as you just said, we see we're at a critical time in this industry where we have to meet the need. Having said that, it has to be a very balanced approach and you have to balance it with the affordability issue. And I think that's why it's all coming to the table right now. So our discussions is portfolio approach. Let's be open to it and get it done sooner rather than later. And also put the right policies around it where you don't shift the cost from one customer group to another because we're running too fast.

Yes. And I think to add to that portfolio approach just a focus on energy efficiency, distributed resources, demand response, and engaging with our states there to say, how can they happen, those programs, whether we have them today and we expand upon them or can we implement new programs to continue to add to that portfolio approach.

One of our ongoing challenges is that some jurisdictions are relying on outdated regulations to tackle contemporary issues. It is essential to update these policies to meet future needs, which is our current focus. It takes time to advance regulatory bodies in a way that aligns with market demands, and that is where we are concentrating our efforts.

And I think one of the slides we talked about, to Calvin's point, about the portfolio approach, right? We're active at FERC, active at PJM, pleased to see PJM putting forth proposals on the capacity auction. FERC already approving some of them. But then also, to Calvin's point, working with our states, Maryland has already made progress here in the first legislative session with the outlining a competitive procurement process for 3 gigawatts of in-state generation. So I think we're pleased to see all of our stakeholders working with a sense of urgency, and we're right there at the table to help drive those solutions.

Thank you. I would now like to turn the conference back to Calvin Butler for closing remarks. Sir?

Thank you. Thank you, Lateef. And let me just say to everyone, thank you for your interest and support of Exelon. I hope as we continue to move these things forward, we're providing you with valuable information, and we appreciate you all taking the time to join us today and for your support. Lateef, that concludes our call.

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