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. [Operator Instructions] 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 5 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 cost a $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 at $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 in 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 a 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…

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 5-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…

Thanks, Joe. Turning to Slide 14. I'll close on our priorities and commitments. We will deliver or exceed our financial commitments, delivering earnings within our guidance range and to maintain strong balance sheet. We will complete preparations to separate the businesses, including the 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 states 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 partner with the support of our customers and our communities that we serve. So thank you all for joining us. And with that, we'll open it up for questions.

[Operator Instructions] 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. And I guess 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. And then there are 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 maybe they'll 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 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. And 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. And then, 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. I think it's -- from what we've heard, it's open a 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 build on 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 real 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's a lot of voices that are inputting into it. And 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 we cannot continue to run uneconomic plants and challenge the balance sheets of the genco or the holdco. We've got commitments. As I said earlier, we're going to make payroll. We've got to pay pensions. We got to pay our bills. We have to have an investment grade credit rating that we can access capital markets. And when you have plants that are uneconomic and pulling you down, it's a tough decision, but it's one that we've made. And 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 what we are already doing the planning proceed 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. Just the -- there was a story, I think, in -- on Bloomberg this morning, talking about a nuclear EPP being discussed in the Biden -- with the Biden administration and legislators. Could you talk about what you're hearing on that and whether we're seeing momentum in that 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 -- for existing nuclear nor has one been introduced in either chamber. So it's obviously 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 has been set. And we welcome that sort of change in focus and a growing understanding. But the challenge remains that we're not yet even to 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? And 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 Reuters story is not enough to -- 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 the - 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 35% -- 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 a 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. So as we pointed out, if we shut down those four reactors that we're talking about, they will be replaced by leakage, the energy coming in. So we will go backwards in that area. How you monitor that and how you tax on it is a very difficult thing in an island. Kathleen, I don't know if you want to go into more technical.

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 that's still in the stack. But when it's a single state, it's just -- 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 34days when we found through maintenance activities higher than expected deterioration of 2,000 reactor recirculation system. And 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 which were 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. And these types of risks are the kinds of things that we have to take into account when we are assessing the financial viability of each of those plants. But that unit has been returned to service and 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. And you saw, after the announcement on our fourth quarter call of separation, they -- that 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 affirm their investment-grade rating and the stable outlook. And it's important to note that they've also delinked them from the corporation effectively from the standpoint of the fact that we have announced separation. So 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. And we have to take that into consideration as we look at our risk profile going forward. We will not continue to weather risk like that that could challenge the balance sheet and the 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 time line? 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, we'll let cover that. I believe he's on.

Yes. First of all, Chicago is a world-class city, and we're privileged to serve it. And we want to continue that relationship. And 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 franchise -- or franchisee is selected. They are going to explore all their options. And I think they are going to follow a blueprint like San Diego used to solicit ideas. We have an RFI that's been issued. We'll participate in that RFI. We'll see if others do. And we'll see what ideas come out of that process. That's expected to close on May 28. In the meantime, we are continuing with the discussions around the new franchise agreement. And 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. I think 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 have 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 in-forced wins across our service territory. 15 tornadoes landed. It was the second most expensive storm in the U.S. this year. And unfortunately, that event has not been an anomaly. We saw unprecedented flooding coming off the lake in the summer. And just maybe 12 months earlier, we saw polar vortex that brought with it negative 30-degree weather. So the city, I think, is rightfully concerned about the changing weather from…

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 is there -- 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. And 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, and it's just scratching the surface. But 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. And we continue to look at working with each of our jurisdictions to encourage them in that way in investing in infrastructure. So 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 that gets into a lot more complicated, but it's a bigger part of the investment.

Yes. That's what I was thinking of. Is there a tipping point or a point where the curve starts to really kick in gear? And what year do you think that approximately happens? And is this a 2030s type opportunity or more of a maybe 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. And we're upgrading them as we see the demand go up. And so 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. And I'll give you an example. Philadelphia Electric and BGE are upgrading their voltages on their distribution systems from 41.60 to 13.8 in anticipation of more distributed generation, but that will also support EV. 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. And we'll have a better sense once we do. We have targeted close in the first quarter of next year. So if we need a little bit extra time, whether in the New York case or at the NRC, we have 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 put and takes are. What are the thing that are actually the benefit 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's a lot of different proposals at this point, Michael. I think the common thread in all of them is that we would come out of the formula rate. And so -- as you know, the formula rate historically for the last 10 years, really throughout the entirety of EMA, has produced an ROE that is significantly lower than the national average. And that's resulted in billions of dollars of savings for our customers over that period of time. As we emerge from the formula and we come to a more normalized ROE, there will be an opportunity for expanded earnings at ComEd. At the same time, one of the things we very much liked about the formula is our ability to plan work for years in advance. We don't -- as you well know, we don't do radically different things year-to-year. We kind of continue to invest in poles, wires, smart devices, those sorts of things over the course of years. And the formula had given us some certainty that we were going to be able to continue those investments, and that allowed us to kind of make arrangements with our vendors so that we could maximize efficiencies there, both from a supply standpoint as well as from a labor standpoint. So one of the things I worry about coming out of the formula is that planning process. Are we going to continue to see volatility from rate case to rate case? So some of the ideas that have been proposed are aimed at looking at a longer-term transparent investment direction coming out of the company and being reviewed by the commission. For example, the labor proposals would have us produce reports every four years, showing all the investments that we're going to make. And it would give…

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, aka 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 continues to deliberate on what the design could be is 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. And so it leaves the generators competing against significant amounts of wind suppressing the prices during the shoulder months, especially. And then you have to look at your return on capital to make the investments for that. So going to a dual fuel, going to a different design basis for temperatures can be an expensive proposition. And 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 emergency 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 have designed for temperatures and we’re starting to see those temperatures expand in the variants. And so 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. And so you would -- it is much more complicated than just a couple of oil tanks to make sure that the resiliency is there. And then you've got to make sure that you're being compensated, like PJM does, for those investments. And we stand up. We made those investments in PJM. And we also know that we'll be penalized if we don't produce in PJM. So if and when ERCOT decides that 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 cliche there.

Okay. Thanks, everybody, for joining the call today. I hope you all stay and your families stay safe and 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.