Exelon Corp

NASDAQ:EXC

Hello, and welcome to Exelon's First Quarter Earnings Call. My name is Latif, and I will be your event specialist today. [Operator Instructions] Please note that today's webcast is being recorded. [Operator Instructions]

It is now my pleasure to turn today's program over to Andrew Plenge Vice President of Investor Relations. The floor is yours.

Thank you Latif. 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 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 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 are 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 to 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 top quartile. We have a relatively lower level of base rate case activity this year, and our 2 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 involved, the recognition of multiyear plan constructs, prompting a robust discussion that highlighted its merits of increased transparency, planning and alignment, while giving stakeholders a greater sake in how much and where their dollars should be invested. We now look to the commission to conclude its multiyear 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 loan 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 refinements 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 co-located 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 time line 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 crisis 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 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 4-year outlook. We reaffirm our plan to invest $38 billion over the next 4 years for the benefit of our customers that will drive 7.4% rate base growth and be financed with a balanced mix of debt and equity. In fact, we have been able to derisk 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 walk. 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 spend in the first quarter of '24.

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&M as well as 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 2 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 intervener and rebuttal testimony in July and September before evidentiary hearings are convened in November and 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 discussions 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 multiyear 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 multiyear construct in the recently passed Next Generation Act (sic) [ Next Generation Energy 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 MIP at BGE, and our fourth one in Maryland, we feel better prepared to support a multiyear 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 multiyear 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 proceeding.

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 a hearing 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-issuance 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 4-year plan and implying approximately $700 million of equity on an annual basis.

For 2025, we successfully derisked nearly 60% of our annualized needs via 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 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 protested in 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 adequate 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 exasperate 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 supply sourced domestically, we have estimated the impact to be around 1.5% of our 4-year capital and O&M investment plan before any mitigating efforts with the majority impacting capital. The impacts would 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 billing options throughout community forms 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 5 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 -- 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 8 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 reporting earnings within our guidance range of $2.64 to $2.74 per share. We look forward to making 2025, our 25th anniversary at Exelon, another year where you can count on us to deliver consistent growth and long-term value.

Latif, we can now open it up for any questions.

[Operator Instructions] Our first question comes from the line of Nick Campanella of Barclays.

So I guess just you have this new Maryland legislation that's out there. It does prohibit reconciliations after Jan 1, '25. And I'm just wondering if you can maybe kind of talk about how you think that can 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.

Yes, Nick, let me just say this. First, thank you for the question. And to your direct point, I think Jeanne hit it well, is that we do expect the reconciliation to come forward in short order. And our plan is solidified and ready to operate as we considered all alternatives, there's nothing on here that we believe that will prevent us from meeting our objectives. That's one.

But let me turn it also, Nick, to where we see Maryland going. As you know better than most that Maryland this year had a legislation passed. And I think there's -- it's important to focus on 5 key areas I'll point out. One, for the first time, it provides language that MYP can be approved. And as you talked about, it doesn't have reconciliations. Well, we've kind of gone through this process a couple of times now. I think Jeanne said we're in our fourth one. In Maryland.

So we know how to build this up and know how to work collaboratively with the stakeholders to ensure we spend on the right things, and I'm very comfortable that we will meet the budget for future MYPs.

Second, specific language in the legislation this year stated on the large load colocation issue, which was very important. It has provisions in there that requires that any load that for infrastructure upgrades and other reasonable costs behind the meter, it's balanced and it does not shift the cost to other customers on the system. That's very important. And that would apply to any load over 100 megawatts with greater -- with 80% or greater capacity factor. So that's just very important. And it's important to note that we continue to drive this on an affordability front within our jurisdictions, and Maryland has codified it.

The next piece is that battery storage was a big item within the Maryland legislation. It directed that the Public Service Commission established and solicit 150 megawatts of distribution battery storage from each electric utility with a target of 70% owned by the utility and 30% owned by third parties. It also required that the PSC start a procurement solicitation of 1.6 gigawatts of transmission battery storage by January '26.

Again, all indications that they recognize the issues and they're driving the state of Maryland forward. And I just want to also give kudos and just acknowledge the 2 new commissioners that have been appointed. They are -- they have a strong track record of regulatory experience, and I think they will continue to be vital voices in Maryland as we move forward. So long answer, but to your direct question, we are not concerned about the reconciliation rollout of the legislation, and we feel very confident that we will work with the state to meet the needs going forward.

I appreciate that. And then maybe on the FERC 206, obviously, there's been some requests to settle by the power companies, and that was put forward a week or 2 ago. And I'm just curious what your response would be as T&D. Do you think or are you open to resolving this colocation issue via settlement perhaps? And -- or does this kind of need to go the full distance at FERC? Any comments there would be helpful.

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 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.

Our next question comes from the line of James Kennedy of Guggenheim Partners.

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?

I would tell you that anything that is good for our customers to address the issue of resource adequacy and affordability, we will support. As you can appreciate, James, our teams are actively involved in those discussions at the legislative front and even having the discussions at the regulatory side. So we just needed to be balanced, and we need to ensure that the recovery of us getting into that.

I will quote my CFO is that we need to have a very straightforward approach and that is recoverability is very clear and outlined in legislation. So our -- we know what we're getting into, and we're partnering with the state to meet those needs. But it's all about the customers in terms of affordability and energy security and adequacy.

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 time line considerations.

Yes. James, 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 4-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 4-year period and we expect that to continue.

Our next question comes from the line of Julien Dumoulin-Smith of Jefferies.

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% probably. These are fairly high numbers in isolation. How do you think about the timing here and how that 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 nontrivial, particularly given the metric that you define as being -- having already achieved.

Yes. I would say -- I would start with saying that none of this, as a reminder, is dependent on that co-located FERC 206. This is all front of the meter, full T&D typical sort of customers that we have in our service territory. So none of that is dependent on that process. And in fact, we're not seeing any slowdown as we work through that process. So we've got -- we announced the 16 gigs in Q4 of '24. Those 16 gigs remain very solid, high probability, and we've even given more color in terms of Phase 1, Phase 2 and Phase 3 for those 16 gigs.

What we did a little bit different this time is also give you insight into what's around the corner, and we have another 16 gig. So sorry to confuse you with those 16 gig number, but it's another 16 gig, 12 of that is a cluster study. The second cluster study we're doing in ComEd service territory and then 4 of it is just spread across the East Coast utility. So continued momentum, all in front of the meter, not dependent on this process. But as you heard from Calvin, we continue to work that process in parallel because we want to meet all -- any and all types of customers.

As we think about the buckets, you can see, again, Phase 1, Phase 2, Phase 3, I would say 70% is probably Phase 1, another 20% Phase 2 and 10% in Phase 3. we feel very confident in the other 16 gig. And I think you can kind of think of them roughly in the Phase 1 time period, too, but we wanted to be clear about how we're thinking about those and the fact that we're moving more because of the demand we're seeing more of a cluster study approach where we're looking at customers together. So that we can give them better insights into time and cost and things like that.

So continuing to evolve our customer service there. But as that cluster study is completed, as we work the other 4 gigs, you can expect us to kind of move that 16 gig into the other phases as we continue to update you on a quarterly basis.

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 time line looks like and what that settlement process could be? I know that there's several different forms where you could have another PJM stabler process that 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.

Julien, it's Colette Honorable. Okay. Let me get to your question. One, let's take a look at the docket itself. We really see quite a bit of consensus in the docket. Calvin referenced the filing by EEI, which represents majority of the industry, the NERC filing, the filing from the independent market monitor. And then the united transmission owner group really demonstrate to FERC that there is a record and a consensus about how to treat this load. We -- when Calvin said we appreciated the commission's efforts here, it is to move quickly so that we can all have the clarity that we need. That's where we started in this matter. And so we're not surprised at all by how the docket is progressing.

As Calvin mentioned, we will be open to having discussions of any sort. But what we really want is for FERC to issue a decision quickly so that we can all have the clarity so that we can support the large load that Jeanne described as well as going back to Calvin's point, ensuring affordability and energy security for all of 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.

Our next question comes from the line of David Arcaro of Morgan Stanley.

Maybe a quick follow-up on the data center side of things. Could you give a sense as to the timing of when that load looks to be ramping up within your forecast period? And I guess from your -- I'm also thinking in the context of your infrastructure and any limitations there. When can you connect in new large loads at this point 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 1/3 of it by 2030 and 3/4 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 there's at times where it's 3 to 6 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 time line and being upfront with that is why these studies are so important. So I think.

Let me add to that, 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 understanding 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 a large part there, so it required less. And that's the partnership.

To give you an example, just about a month ago, we had an 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 6 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. And I 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 and increased focus in 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 their cost. We're talking about energy efficiency. We're going out to customers' homes and small business, 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 forms 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 Strategic Energy Infrastructure Fund (sic) [ Strategic Energy Investment Fund ] directed at companies, and we had about $300 million. 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.

Our next question comes from the line of Bill Appicelli of UBS.

Just want to go back to Maryland for a second. Maybe on the Lessons Learned, docket, can you just remind us on the time line and maybe what's the range of outcomes there given the legislative developments, is there any concern around not continuing the MYPs beyond the current plan? Or what sort of -- is maybe a range of scenarios that we could look to there?

I would tell you that the fact in the debate this year, around MYPs, the state -- the legislature did a wonderful job of understanding the value of MYP. But we do have the discretion to your point, on whether we do. We do believe that, that multiyear collaborative process, the engagement with stakeholders, forward-looking is the most productive. So I don't see anything to date that would take us away from that. And I am pleased that the commission did embark on the Lessons Learned process. So it extended into this year, likely delaying the timing, but we believe that this legislative session that we just had will start a ruling very soon.

As you may recall, we went through an extensive process to determine that it was the best option. And so I think we will have a -- I'm looking at Carim and Tamla here, we will have a decision in the short order. We anticipated by the end of the second quarter that we will have a decision on the Lessons Learned, and we continue to involve in those states. Everyone has submitted their comments. Everyone has engaged in the process from the Office of People's Council to the large industrials to residential customers. So everyone's voice has been heard, which is what we wanted, and that's what we were driving to.

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, right? 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, 5 to 7 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, if 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 -- how can 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.

And part of our challenge, and we've been saying this for a while now, is some jurisdictions are using more, let's call it, outdated rules, outdated rules to address modern issues. And we need to keep the policies updated to address the needs of tomorrow. And that's what we're working on. And I'll just -- yes, it's very -- it takes some time to move regulatory bodies forward in a timely manner to meet the needs of tomorrow. And that's what we've really been putting our attention towards.

And I think one of the slides we talked 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 within 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.

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

Thank you. Thank you, Latif 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 Latif that concludes our call.

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