Hello, and welcome to Exelon's First Quarter Earnings Call. My name is Amanda, and I'll be your event specialist today. All lines have been placed on mute to prevent any background noise. Please note, today’s conference is being recorded. During the presentation, we will have a question and answer session. It is now my pleasure to turn today's program over to Dan Eggers, Senior Vice President of Corporate Finance. The floor is yours.

Thank you, Amanda. Good morning, everyone, and thank you for joining our first quarter 2021 earnings conference call. Leading the call today are Chris Crane, Exelon's President and Chief Executive Officer; and Joe Nigro, Exelon's Chief Financial Officer. They're joined by other members of Exelon's management team who will be available to answer your questions following our prepared remarks. We issued our earnings release this morning along with the presentation. All of which can be found in the Investor Relations section of Exelon's website. The earnings release and other matters which we discuss during today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. Actual results could differ from our forward-looking statements based on factors and assumptions discussed in today's material and comments made during this call. Please refer to today's 8-K and Exelon's other SEC filings for discussions of risk factors and other factors, including uncertainties surrounding the planned separation, that may cause results to differ from management's projections, forecasts and expectations. Today's presentation also includes references to adjusted operating earnings and other non-GAAP measures. Please refer to the information contained in the appendix of our presentation and our earnings release for reconciliations between the non-GAAP measures and the nearest equivalent GAAP measures. I'll now turn the call over to Chris Crane, Exelon's CEO.

Thanks, Dan, and good morning, everybody, and thanks for joining us. As you've seen from our earlier releases and notifications, we had mixed results in the first quarter. We performed well across our businesses outside of the challenges from five days in February due to the Texas weather event. Overall, our first quarter GAAP loss was $0.30 per share and our non-GAAP loss was $0.06 per share. Exelon Utilities performed well operationally and financially during the quarter, delivering $0.72 per share, which is $0.11 better than the first quarter last year. At ExGen, we lost $0.58 per share overall, with the February weather event costing $0.90 in the first quarter. The event was unprecedented. We continue to investigate the multiple complex factors that led to our plant outages. And we are working with ERCOT regulators and other stakeholders to ensure an event like this does not happen again. As you saw in our 8-K last week, we updated our full year losses to $150 million due to the updated load meter data in ERCOT default payments that differed from our original estimate. In addition, we reaffirmed our full year guidance of $2.60 to $3 per share. We continue to work on mitigating this approximately $1 billion loss, and expect to offset the loss by $410 million to $490 million after taxes through a combination of mostly onetime cost reductions and deferral of nonessential maintenance and revenue opportunities. Joe is going to go into much more detail on that in his presentation. Turning to the operations. Despite the extreme cold winters and the winter storms, the pandemic conditions, our utilities had strong operational performance, delivering reliability, affordable electricity, and gas for our consumers. All the utilities achieved first quartile operating performance in outage duration and frequency. BGE, ComEd, and PHI were in the top decile in outage duration. Customer operations metrics remained strong across the utilities. PECO and BGE's customer satisfaction levels were top decile. ComEd was top quartile. And PHI just missed top quartile but improved year-over-year. On the generation front, in the face of extreme temperatures and winter storms, our nuclear plants provided 37 terawatt-hours of reliable, resilient, and clean energy to the grid of the citizens of Illinois, Pennsylvania, New York, and Maryland. The fleet's capacity factor of 95.3% was what we reached for the quarter. The spring has been active on the policy front with momentum building at both federal and state levels for policies that recognize the value of existing nuclear and would put the country on a path to a net-zero future. Both ExGen and the Utilities are well-positioned to benefit from these policies and the transition to a clean energy economy. On the federal level, the Biden administration has set out an ambitious goal to reduce greenhouse gas emissions by 50% to 52% by 2030. Nuclear provides more than half of the carbon-free emission electricity in the U.S., with Exelon plants providing 12% of all the carbon-free energy in the United States. The administration is clear that preserving the existing nuclear fleet is key in meeting the goals that they have set. The administration's infrastructure proposal, the American Jobs Plan, would enact policies to help reach the goal. It includes a clean electricity standard that would require 100% clean electricity by 2035, with existing nuclear qualifying as clean; incentives to build 500,000 EV charging stations by 2030; and for 20 gigawatts of high-voltage transmission lines to be built to support the renewable build-out. We're encouraged that the administration and members of Congress recognize the importance of preserving the nuclear fleet to meet the country's clean energy and climate goals. The timing and the outcome of federal legislation is highly uncertain. And in any case, it will be too late to reverse the retirement decisions for Byron and Dresden. Our states are also advancing clean energy policies. In Illinois, six energy policy reform bills have been introduced that would drive the transition to clean energy and address climate change. The legislative leaders are meeting to craft a package from the various bills that can be considered this session. We're encouraged by the expression of support for the continued operation of the nuclear plants. However, the details really matter. A bill needs to pass before the end of the regular session, and it needs to provide adequate support for continuing to invest in the Illinois fleet. Current market prices do not allow us to continue to meet our payroll, pay our property taxes, and cover other significant costs and risks of operating these assets. Without adequate policy, as I've stated, we will retire uneconomic plants beginning this fall. If you take a look at what happened in New Jersey last week, the Board concluded that the financial challenges faced by nuclear plants there justified a maximum ZEC of $10 per megawatt-hour. The same voices that are arguing in Illinois that our plants are profitable were overruled in New Jersey's decision. The commission in New Jersey emphasized that maintaining the existing nuclear plants was critical to achieving the state's emission goals and significantly less costly than replacing nuclear with other zero-free carbon generation. This is true in Illinois. Keeping the nuclear plants running is a better option for customers than trying to replace them with all renewables and storage. At twelve times the higher cost than preserving the nuclear plants, it would cost Illinois consumers over $80 billion more to achieve the same emissions. We've been advocating for policy changes in Illinois for more than two years because I feel that we have a duty to our customers to preserve every opportunity to correct flawed policies and keep these critical energy resources running. But we're almost out of time, and we will prematurely retire these assets in the fall if the policy reforms are not passed in this session. Turning to clean energy policy in Pennsylvania, the Senate is moving forward on a bill that would set a state goal for transportation electrification and authorize electric utilities to develop EV infrastructure and plans that authorize a recovery for these investments. We support these federal and state policy efforts and stand ready to enable this important transition to a clean energy future. Joe will talk about what our utilities are doing currently on EVs. Moving on to the separation update. Our team is working to complete the separation. We filed our applications for regulatory approval at FERC, the NRC, and New York Public Service Commission in February. The NRC has indicated that our application is complete and they expect to rule by November 30. In New York, comments are due on May 24, and we requested that the commission rule no later than their December 16 meeting. We're on track to get the necessary approvals so that we can close in the first quarter of next year. With that, I'll turn it over to Joe to provide the financial details.

Thank you, Chris, and good morning, everyone. Today, I will cover our first quarter results, quarterly financial updates, and our hedge disclosures. Turning first to Slide 9. As Chris mentioned, we recorded a loss of $0.06 per share on a non-GAAP basis for the first quarter, driven by the losses from the February weather event. Our utilities performed ahead of plan for the quarter, delivering a combined $0.72 per share this year, which was $0.11 per share higher than the first quarter of 2020. This was primarily driven by strong operational performance as well as the impacts of distribution rate cases. ExGen reported a loss of $0.58 per share for the quarter. Excluding the five-day weather event in February, ExGen would have earned $0.32 per share as we had anticipated. However, specific to the weather event, we incurred a loss in the first quarter of $0.90 per share. A portion of this loss is due to some penalties or charges associated with our natural gas business that we ultimately expect to be reduced through waivers and/or recovered from customers later in this year. As we disclosed in our 8-K last week, we estimate our full-year loss from the weather event to be approximately $900 million to $1.1 billion pretax or $670 million to $820 million after tax. We also continue to expect to offset between $550 million and $650 million pretax or $410 million and $490 million after tax for the full year 2021. These offsets will occur primarily at ExGen through a combination of enhanced revenue opportunities, deferral of selected nonessential maintenance, and primarily onetime cost savings, and are mostly expected in the second half of this year. Holdco recorded a loss of $0.20 per share for the quarter, which was a larger loss than is typical in the first quarter and was driven by a tax adjustment required by GAAP to partially offset the tax benefit recorded at ExGen due to the Texas losses. This amount will reverse over the next three quarters and ultimately will not have an impact on full year results. As Chris stated, we are reaffirming our guidance range of $2.60 a share to $3 per share, and you can see the details on Slide 16 in the appendix. Moving on to Slide 10. Looking at our utility returns on a consolidated basis, our trailing 12-month ROE as of the first quarter has improved to 8.9% from 8.7% last quarter. The 20 basis point increase was primarily due to higher earnings across the operating companies in the first quarter. As a reminder, the calculation is backward-looking. So you should continue to see some pressure on ROEs over the next couple of quarters as we work off the impacts of COVID-19, low interest rates at ComEd, and the 2020 storms. We do expect to be in our targeted range of 9% to 10% by year-end. And looking into the future, we remain focused on delivering strong earned returns at the Utilities in supporting our growth targets. Turning to the next Slide 11. Since the last call, there were some important developments on the regulatory front. First, on March 30, PECO filed an electric distribution case with the Pennsylvania Public Utility Commission. PECO is seeking a revenue increase of $246 million for continued investments in electric distribution infrastructure, which will make the local energy grid stronger and more resilient, enhance service, and help the company deliver safe, reliable, and clean energy for consumers. In addition, the filing proposes customer relief offerings for eligible residential and small business customers, and we expect an order in December of this year. Second, ComEd filed its annual distribution formula rate update with the Illinois Commerce Commission on April 16, seeking a $51 million increase to electric distribution base rates. This year's formula rate update is ComEd's first request for a distribution rate increase in four years. The filing will support investments to expand access to clean energy through private and community solar and support the growing demand for electric vehicles. Additionally, we continue to make investments and fortify the power grid against severe storms, such as those experienced in Northern Illinois last year. We expect to receive an order by early December. We also have several rate cases still in progress, including orders in multiyear plans for Pepco D.C. and Pepco Maryland, which are expected in the second quarter. We continue to have constructive regulatory relationships across our jurisdictions, and are working with our regulators, states and communities to support their clean energy and climate goals. More details on our rate cases can be found on Slides 20 through 28 of the appendix. Slide 12 provides one example of how Exelon Utilities are working with our regulators and states to make investments that will address the climate crisis and help our customers. Our utilities play a critical role in advancing electric vehicles in our communities. This includes both the installation of publicly available charging stations and investment in the system to support this infrastructure. Exelon Utilities have been leaders in this rapidly growing space by expanding charging infrastructure, offering rebates and incentives and innovative rates, while electrifying public transportation to deliver convenient, affordable, and accessible clean transportation options. Our clean electric transportation programs aim to support nearly 100,000 current electric vehicle drivers across our service territories, aligned with state climate goals, and improve overall air quality for all our customers and communities. To date, electric vehicle programs have been approved in Maryland, D.C., Delaware, and New Jersey, with approval pending in Pennsylvania as part of PECO's recent rate case filing. ComEd also has several ongoing educational and outreach initiatives. Several of the bills Chris spoke about would provide incentives for EV infrastructure. The transportation sector currently represents about one-third of total U.S. greenhouse gas emissions. Urban areas, like many of our service territories, are disproportionately affected by air pollution and the negative effects of climate change. One way we aim to help address this is by advocating for and helping to usher in cleaner, zero-emission transportation, particularly in underserved communities. Our programs are designed to reduce common barriers to electric vehicle adoption, including range anxiety, total cost of vehicle ownership, and lack of education and awareness among consumers. Cleaner vehicles on the road help our cities and states meet their environmental goals, reduce their carbon footprint, bring cleaner air to communities, and create economic opportunities through job creation and reduced energy costs. Additionally, Exelon's utilities are leading by example in setting an aggressive goal to electrify our fleet, including both light-duty and heavy-duty vehicles. We have committed to electrify 30% of our fleet by 2025 and 50% by 2030. Electrifying 50% of the fleet could avoid more than 65,000 metric tons of emissions cumulatively from 2020 to 2030. That's the equivalent to the carbon removed by one million trees planted and grown for 10 years. On Slide 13, we provide a gross margin update. For 2021, total gross margin is down $150 million versus the fourth quarter call due to the increase in the estimated impact of the February weather event. The midpoint of our current estimate of the gross margin impact from this event is $950 million. This number is lower than the midpoint of our loss range of $1 billion because it does not include bad debt, which is captured in O&M. Excluding the impacts of the February weather event, gross margin is flat to last quarter. Open gross margin is up $300 million relative to our prior disclosure, primarily due to higher prices in NI Hub and West Hub. Our mark-to-market of hedges was down $200 million due to our hedge position, offsetting the increase in open gross margin, partially offset by the execution of $100 million of non-power new business. We also executed $50 million in non-power new business during the quarter. Thank you. And I will now turn back the call to Chris for his closing remarks.

Thanks, Joe. Turning to Slide 14. I'll close on our priorities and commitments. We will deliver or exceed our financial commitments, achieving earnings within our guidance range while maintaining a strong balance sheet. We will complete preparations to separate the businesses, including obtaining regulatory approvals. At Exelon Utilities, we will prudently and effectively deploy nearly $6.6 billion of capital to benefit our customers and help meet the needs of our state's energy policy goals. We'll work with our regulators to ensure timely recovery on these investments. We'll continue to advocate for clean energy and climate policies with the new administration, Congress, and our states to put our country on the path to meeting our carbon reduction goals. And we'll continue to engage with the support of our customers and the communities we serve. So thank you all for joining us. And with that, we'll open it up for questions.

And your first question comes from Stephen Byrd with Morgan Stanley.

I wanted to just get your latest thoughts on ERCOT and market design. We've certainly seen a lot of activity. And you all gave some prepared remarks on that. But just curious, it strikes me it looks like it's a little less likely that the state may go in the direction of sort of fixed resiliency or capacity light payments. But just curious what you're sort of seeing and what direction you think we may take in terms of market design.

Yes. Let me have Kathleen cover that.

Yes. I think there are a number of ideas under discussion in the legislature. I wouldn’t say that it’s less likely that the state will ultimately choose to go down the path of setting a reliability standard. That idea does have some support and is being discussed openly, as are other changes, for example, to the ORDC curve to sort of lengthen it and lower the cap. There are also other ideas out there as well. So I think there’s active discussion in both the House and the Senate over whether and when the legislature should act. There are some who think it should move forward and set some expectations and let the PUCT work on a market design over the balance of the year, whereas others are thinking they may wait and do it later in the year. So, it's a little bit early to tell how those conversations are going to land. But I think the concept of setting, as all the other markets do, a reliability standard and letting the market operator design a market-based way to get there is still under active discussion.

That's really helpful. And then maybe going to PJM and FERC. And we've seen a lot of activity around the treatment of MOPR, and I'm just curious there as well your latest thinking on sort of where we may be headed and kind of broader implications, given it looks like we may see a reversal.

Yes. There are sort of two avenues where that's being discussed. First, at the RTOs themselves. As you know, PJM has a stakeholder process to work through how to reform MOPR; they have direction from their board that they should reform it. But the question is how, and they've laid out a proposal, and they'll be taking comments and working towards the FERC filing in the summer to express their view of how it should be reformed. Ultimately, of course, it will be up to FERC. You have two commissioners who are open that they think MOPR should be reformed. The other three, less transparent in terms of how they would vote. So I think there’s certainly going to be an effort on PJM’s part to make a change. And then, the question will be how the votes line up at the commission once that filing is made.

And your next question comes from Steve Fleishman with Wolfe Research.

So a couple of questions, I guess, focused on the nuclear. So first, in Illinois, I know there's been several proposals. The most recent, I think, was from the governor, related also to the audit that he set up. Could you give your views on whether that proposal would be sufficient to keep the Dresden and Byron open?

Yes. I mean all of you have written on the economics of the plant and the reality of what the bill is starting at. From what we've heard, it's open to negotiation. But just going from the Street analyst opinion and what we've seen, its starting point is not adequate to keep the plants’ continued operations going.

Okay. And then just to be clear on Illinois, in the event that maybe they just can't get a bill done this session, and they try to go to the veto session. Obviously, you're targeting to shut the plants before then. So can you just confirm clearly whether, if they just don't get something done this session, the plants will shut, Dresden and Byron?

Yes. Sure. We've been really clear about that, but we're still optimistic. Most state or legislative bodies, the work comes to an end towards the end of the session. There's a lot of stakeholders involved here. There are a lot of voices providing input. The legislature has a tough job of building a single bill out of six suggested bills and making sure that they take care of their constituents as well as all of the other stakeholders involved in the process. So we're not giving up. We're confident that we've got adequate support within the administration and within the legislature, and we'll see how it goes. That said, we have been clear for a couple of years. And it's just the reality that we cannot continue to run uneconomic plants and challenge the balance sheets of the generation company or the holding company. We've got commitments. As I said earlier, we're going to make payroll. We have to pay pensions. We’ve got to pay our bills. We have to have an investment grade credit rating that we can access capital markets. When you have plants that are uneconomic and pulling you down, it's a tough decision, but it's one that we've made. We’ll continue to be optimistic that we can work with the stakeholders and the legislative body and the administration. But short of getting something done, we'll have to start to proceed with the planning for the shutdown. You can’t order fuel. You can’t do capital improvement. You can’t do a lot of stuff in the face of uncertainty, which causes you to spend hundreds of millions to billions of dollars on plants that just aren’t going to support themselves.

Okay. One final question on nuclear. There was a story on Bloomberg this morning about a nuclear EPP being discussed in the Biden administration and among legislators. Could you share what you’re hearing about that and whether there’s momentum for it as part of the Biden infrastructure plan?

Steve, this is Kathleen. I can take that one. As Chris mentioned, the Biden proposal is for a clean energy standard. That's inclusive of existing nuclear and is technology neutral. That is what their proposal is. That's on the table. We saw the story this morning as well. But of course, their plan does not currently include a PTC for existing nuclear, nor has one been introduced in either chamber. It is helpful that there is a growing focus on the fact that the existing nuclear fleet is integral to getting to any of the carbon targets that have been set. We welcome that sort of change in focus and a growing understanding. The challenge remains that we're not yet even at the point where we know, is Congress going to move forward on a bipartisan basis? Does a bill need to be drafted that would be consistent with reconciliation? The timing and the outcome is just far too uncertain for us to make any decisions here based on that. Obviously, to the extent something happens in Congress, that’s a long-term positive for the company. But just one news story is not enough for us to make decisions accordingly; we have to make decisions based on current economics and current policy.

And your next question comes from James Thalacker with BMO Capital Markets.

I just want to touch briefly on the governor's legislative proposal. And I guess his proposal for an application of an $8 a ton carbon mechanism. I know it’s early. And as you — but as you think about the final market structure and a pretty clean generation stack in Illinois already, how do you see the pass-through of this potential tax on power prices? In New York, you've seen about a 25% to 35% pass-through, but it's not clear to me how you can sort of tax on the state supply from Wisconsin and Illinois. So where do you guys kind of see the potential uplift in power prices in its early stages, understanding the final market structure is yet to be determined?

It's difficult. I'm going to let Kathleen get into the technical details. But it's difficult for a single state that is an island surrounded by other states without the same policy not to have leakage coming in. As we pointed out, if we shut down those four reactors that we're discussing, they will be replaced by leakage, the energy coming in. So we will go backwards in that area. How you monitor that and tax on it is a very difficult thing in an island. Kathleen, I don’t know if you want to go into more technical details.

I think you covered it. I mean, I think the issue is when you have a national carbon price, you would see a high pass-through rate given the amount of fossil fuel that's still in the stack. But when it's a single state, our estimates are that there would be a very small impact on carbon energy prices due to out-of-state plants running more frequently.

Okay. Great. And I just wanted to see if you could kind of give me a quick update on the outage with the cell plant and what's your outlook for the cost and the timing for its return.

Brian Hansen, he's our COO of generation. You want to cover that?

Yes, thanks, James. Yes, the LaSalle Unit 2 reactor was out of service for an extra 34 days when we found through maintenance activities higher than expected deterioration of 2,000 reactor recirculation system. Because of the size and location of these valves, we had to design and deploy special welding and machining tools to make the necessary repairs required prior to returning that unit to service. It involves several hundred people, given the difficulty of that work. That unit has since been returned to service. The cost was a significant impact for that particular plant. These types of risks are the kinds of things that we have to take into account when we assess the financial viability of each of those plants. But that unit has been returned to service and is ready for a summer run.

And your next question comes from Shahriar Pourreza with Guggenheim.

Chris, Joe, have you had any conversations with the agencies kind of about the SpinCo since the fallout we saw in Texas? Just trying to get a bit of a sense if this is more of a structural risk going forward as we're thinking about sort of the general business model for the IPPs or just kind of an anomalistic situation. I mean, especially as we're sort of thinking about the standalone ExGen entity and maintaining IG ratings post spin. And obviously, we understand that the metrics are extremely healthy. But I'm just kind of curious how they're thinking about the business — maybe a little bit more qualitative factors post the weather event. I just have a follow-up.

Yes, sure. As you could imagine, we've had numerous contacts with the agencies since the event in February. After the announcement on our fourth quarter call of separation, Moody's and S&P published some preliminary thoughts on both generation and on the RemainCo or Exelon. On the 29th of April, S&P came out and updated some commentary on ExGen and affirmed their investment-grade rating and stable outlook. It’s important to note that they also delinked them from the corporation from the standpoint that we’ve announced separation. We continue to have dialogue with each of the agencies. All three of them have generation rated investment-grade currently, and we continue to expect that to happen in the future as we manage our business.

A key to that is managing the business and managing the risk and understanding the risk. It was an unprecedented weather event that was beyond potentially the design basis of the plants. We have to take that into consideration as we look at our risk profile going forward. We will not continue to weather risks like that that could challenge the balance sheet and investment-grade ratings.

Got it. And then just lastly, there’s been some noise building on the Chicago franchise agreement. Is there sort of a path forward there? Any sense on timeline? Anything on expectations you can share? I mean, I just were curious if this is going to turn into a San Diego situation or not.

Joe Dominguez, do you want to cover that? I believe he's on.

Yes. First of all, Chicago is a world-class city, and we're privileged to serve it. We want to continue that relationship. We've been working with the city for some time on terms for a new franchise agreement. As you know, the franchise agreement continues until a new one is approved or until a new franchisee is selected. They are going to explore all their options, and I think they are going to follow a blueprint like San Diego to solicit ideas. We have an RFI that's been issued. We'll participate in that RFI and see if others do. We’ll see what ideas come out of that process, which is expected to close on May 28. In the meantime, we are continuing discussions around the new franchise agreement. We’re pretty confident that ComEd is going to be successful at the end. We have a lot to offer. We're leaning in on the city's priorities around energy efficiency, jobs, support for low-income families, clean and renewable energy and more. The most important thing for the city, and they’ve been very clear about this, is making the study reliable and resilient against some of the storms. We’ve talked on these calls about some of the storms we've experienced. We added ratio in August, where we had 110-mile-per-hour hurricane-force winds across our service territory. Fifteen tornadoes landed. It was the second most expensive storm in the U.S. this year. Unfortunately, that event has not been an anomaly. We saw unprecedented flooding coming off the lake in the summer. Just maybe 12 months earlier, we saw a polar vortex that brought with it negative 30-degree weather. The city is rightfully concerned about the changing weather from the climate crisis. Notwithstanding these weather events, Chris reviewed earlier some of our performance. We're not only top decile in SFI and Katy, but I think best-in-class in both categories, first time for this company to achieve that. We’ve been able to make the investments, keep residential rates low and so on. Serving cities alone is a pretty expensive proposition. The infrastructure is expensive, and doing any work in the city is expensive because of the density of existing infrastructure. You tend to have a more concentrated low-income customer base in the city for a variety of reasons. It’s more expensive. When the city is part of a broader Chicago system, and the city accounts for about one-third of ComEd, we have the ability to use the horsepower and talent, not only within ComEd but the Exelon family of companies to come in, repair the system when it’s damaged as a result of weather. We also have the financial wherewithal of the industry and the businesses and the people that live outside of Chicago in the suburbs to cover some of the costs for the city’s more economically challenged citizens. We think the whole package is going to be valuable. You mentioned the San Diego process. We’ve followed that for some time. I don’t think there was, at the end of the day, anyone who actually competed for the franchise there. But it is a process. It’s a transparent process that we need to go through, and we appreciate that. In the meantime, as I said, we’re going to lean into it. If the city decides to go in a different direction, they would have to pay ComEd upwards of $7 billion for the system, depending on the timing of the transaction. Because these systems were built in an interconnected way, we anticipate that there would be about $5 billion or more in separation costs that could take upwards of a decade to complete new substations, control centers, and computer platforms alike. This is going to be a long road if the city goes in that direction. We understand this move within the fabric of the negotiations that we've been having with the city. I’m confident that the proposal we’re going to offer is going to allow us to continue this long-standing relationship. We would be very fortunate to be able to continue to serve this great city.

And your next question comes from Michael Weinstein with Credit Suisse.

On electric vehicle charging infrastructure. This is still pretty early days, I understand that. But at what point does this become a significant portion of CapEx opportunity? What do you think that opportunity is? And when do you think it really starts to kick in?

Michael, this is Calvin. I would say we continue to look at EV infrastructure and partner with all of our jurisdictions on how we go about it. Chris, I think it was no Joe outlined in detail what we're doing in each of our jurisdictions in terms of EV adoption, charging infrastructure, and the like. Right now, it is not a significant piece of our capital plan. Chris alluded to the $6.6 billion that we will execute this year; it’s just scratching the surface. At the end of the day, it is part of our business priorities moving forward. As you laid out, 50% of our fleet will be electrified internally by 2030. We continue to work with each of our jurisdictions to encourage them in that way in investing in infrastructure. The bottom line is that it’s a small portion of our total capital investment, but it is on our plan to continue to grow.

The infrastructure investment beyond the EV charging stations is something that our engineering units are working on between EV and distributed generation. Upgrading lines, changing voltage levels gets into a lot more complicated, but it’s a bigger part of the investment.

Is there a tipping point or a point where the curve starts to really kick in gear? What year do you think that approximately happens? And is this a 2030s type opportunity or more of a late 2020s?

Yes. It’s something we’re working on now more for the distributed generation. There’s analysis that goes into the circuits to make sure that we’re not overloading them. We’re upgrading them as we see the demand go up. I think we’re investing now. A tipping point, I think it’s going to be a gradual investment over a 10-year-plus period. It’s not going to all of a sudden hit immediately one day. I’ll give you an example; Philadelphia Electric and BGE are upgrading their voltages on their distribution systems from 4.160 to 13.8 in anticipation of more distributed generation, but that will also support EV. It’s so it gives us more capacity on the circuits to allow the customers to get the services they want.

Got you. Just one last question. On the New York Public Service Commission filing for separation, is there any reason why you think it might take longer than the end of the year to get an approval there?

This is Kathleen, Michael. I can take that. I mean, we haven't even seen comments yet on the New York application. They were due at the end of the month. We had to ask for action by the end of the year, and we think the agency is capable of acting in that period. But of course, we need to see what the comments are. We’ll have a better sense once we do. We've targeted close in the first quarter of next year. If we need a little bit extra time, whether in the New York case or at the NRC, we've accounted for that. But again, we think that acting by the end of the year is doable in New York.

And our final question comes from Michael Lapides with Goldman Sachs.

Two questions for you, actually unrelated. One, some of the potential draft Illinois legislative approaches have pretty decent changes to how Commonwealth Edison's ratemaking process would work. Could you just give an update on what you think the puts and takes are? What are the things that are actually the benefits to ComEd's earnings power? What are the things in there that could be a headwind if implemented to ComEd's earnings?

Joe Dominguez, do you want to cover that?

Yes. There are several proposals being considered at this time, Michael. The main aspect of all these proposals is that we would move away from the formula rate. Historically, the formula rate has resulted in a return on equity that is much lower than the national average over the past 10 years, leading to significant savings for our customers. As we transition away from the formula and adjust to a more standard return on equity, there will be potential for increased earnings at ComEd. One of the advantages of the formula has been our ability to plan our work several years in advance. We typically do not make drastic changes year-to-year; instead, we consistently invest in poles, wires, smart devices, and similar initiatives over time. The formula provided us with certainty about continuing these investments, allowing us to coordinate with our vendors for better efficiency in both supply and labor. My concern about moving away from the formula is related to the planning process. Will we continue to experience variability from one rate case to another? Some of the proposals under consideration aim to present a long-term, transparent investment strategy that the commission can review. For instance, the labor proposals would require us to submit reports every four years detailing our planned investments, giving stakeholders insight into our objectives. While we may not receive formal approval for these plans, it would clarify our investment goals, particularly related to renewable energy integration and enhancing system resilience. To maintain the reliability we've achieved, manage storm challenges, and accommodate increasing electric vehicles, we need to keep investing in the system as we have with these technologies. The formula has offered a clearer pathway for this. My concern with simply reverting to traditional ratemaking is that we would lose year-over-year clarity, potentially introducing variability in rate outcomes, which could affect our workforce and supplier efficiency. These are the key factors as I perceive the current legislation. Policymakers have been meeting regularly about this, and I believe these are also their concerns.

Got it. And then one quick follow-up, unrelated, on taxes. You can’t necessarily rely on ERCOT or the PUCT to act quickly and make market design changes. Often, they've been very reticent to do so. Is there anything you're thinking about doing, either from a contracting standpoint or something physical at the plant, like, maybe backup generation on site with storage tanks or something like that to forestall potential risk like what just played out happening in the future?

Right now, the design of ERCOT does not compensate for reliability, availability. It's a pure energy market only. We would have to take into consideration, as ERCOT and the commission continue to deliberate on what the design could be, what we could afford to invest into those plants for that resiliency. In PJM, it's a very resilient market. We're compensated. And we're penalized if we don't produce. That is not the structure that ERCOT has taken in the past. It leaves the generators competing against significant amounts of wind suppressing prices during the shoulder months. You have to look at your return on capital to make the investments for that. Going to dual fuel, making modifications to the design basis for temperatures can be an expensive proposition. If you're not getting rewarded for that and the market doesn't prioritize that, it would be difficult to do.

Got it. Okay. I was just thinking, is it materially expensive to add things like fuel oil tanks to some of the gas plants that could store a couple of days for use in emergencies only? Is that prohibitively expensive relative, I guess, if I were to compare it to what just happened?

No, it is expensive, but it's more complicated than just having oil on site. The plants are designed for temperatures, and we’re starting to see those temperatures expand in the variants. You have to do more than just put oil tanks on in dual fire, make the modifications on the firing jets, in the turbines — excuse me, in the generators. It is much more complicated than just a couple of oil tanks to ensure that the resiliency is there. And then you've got to make sure that you're being compensated, like PJM does, for those investments. We stand up. We made those investments in PJM. We also know that we'll be penalized if we don't produce in PJM. If and when ERCOT decides that the availability and reliability of the fleet is a priority, which thus far, they have not, we would be able to participate in that market and make whatever modifications make economic sense to weather the storm. Pretty good cliché there. Okay. Thanks, everybody, for joining the call today. I hope you all stay safe and your families stay healthy. And with that, I'll close out the call.

That does conclude today's call. You may now disconnect. Thank you for your participation.