Hello, and welcome to today's webcast. All lines have been placed on mute to prevent any background noise. Please note that today's webcast is being recorded. During the presentation, we will have a question-and-answer session. [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, Mary. Good morning, everyone, and thank you for joining our first quarter 2020 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 senior 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, both 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 the uncertainty surrounding the impacts of the COVID-19 pandemic 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 measure. I'll now turn the call over to Chris Crane, Exelon's CEO.

Thanks, Dan, and thanks to everybody that's joined today. I'll first start off with the first quarter results. We had a strong quarter even with one of the warmest winters we've seen in a long time. The GAAP basis earned $0.60 per share, non-GAAP basis earned $0.87 per share. Joe is going to cover all those details in his remark. We had very solid operations throughout the first quarter. First quartile outage frequency and duration and record-setting nuclear refueling outages that I'll go into further as we continue. Hearings on working groups in Illinois on Clean Energy legislation, which is very critical right now, are meeting. The discussion is going on, we still haven't determined how the legislature will get back into session to resume work, but I think they all understand the priority of what needs to be done, not only for energy, but the capital budgets and other issues in Illinois. So we will continue to work on that through May. Our number one focus throughout this pandemic has been focusing on the safety and wellbeing of our employees. Our employees are on a mission. They know we are mission-critical in as many as possible of working remotely in supporting the critical infrastructure. We have approximately 17,000 people, employees and another 8,000 contractors working remotely and being able to execute on their tasks without any faults. So our frontline workers, the 17,000 frontline workers and the contractors that are maintaining the electric gas system in the power plants, we’re protecting with PPE, social distancing and pre-screening. We have not laid-off or furloughed or reduced hours or pay as a result of the pandemic. We've done a couple things. Employees diagnosed with COVID remain in pay status and no charge to sick leave. Overall, we've had 102 employees have been diagnosed with COVID plus 25 contractors. 82 of those total count have returned back to work. And so we are continuing to focus on the health and safety and the wellbeing. We give full pay to employees that are being quarantined. If they've become in contact through our tracing mechanisms that we're providing at all of our facilities, we quarantine them from the required amount of time, which allows us to keep not only them and their families safe, but also other employees. We also expanded access to backup care for dependence. So those frontline employees are supporting frontline employees that need to be in the workspace out in the field do not have to worry about their children out of school or their elderly parents. So that's another service we are providing to the employees to keep everybody focused on their own safety, the job, one, keeping the grid up and keeping the gas flowing, and keeping the power plants running. On Slide 4, you'll see a big part of what we do, what we've always been doing and what we will continue to do is support our customers and communities. As you know, and you heard all the utilities suspended disconnects, waived new late fees and we did reconnect or reach out to customers that had been disconnected since the March 1 and offered to reconnect those individuals who had been disconnected. And this gives us the ability for people that are laid off or people that are in financially challenged times to have one of the most critical social and needed energy sources that we can provide. We also, at the Exelon Foundation and our companies, have contributed over more than $5.9 million to relief organizations, ensuring food banks and other programs can be supported during this time of need, and we'll continue to focus on that. But at the core of everything, after safety in the community is our operational excellence, which is even more critical right now. Keeping the lights on in this crisis, keeping the hospitals with power, healthcare providers, grocery stores, medical food production facilities, you can see the list of the priorities that are there. And we have to, as a company and an organization continue to have reliable service, and that is strong at the utilities. We've had spring storms already this year. We restored more than 350,000 customers across the service territories in late March and early April. We've been able to do that and test ourselves on moving in resources and being able to adequately and safely shelter our employees, but allow them to work safely in the field to restore the power. On the power side, the nuclear group has completed seven of eight refueling outages, all better than planned. There's one refueling outage left to go that will be closing up later in this month, a major rewind on the Ganey Station. But if you look at the majority of the plants, it's been world class performance with the outages being performed between 16 and 18 days. If you look about these trying times, we've only had 25 employees that have – 29 including contractors, 25 employees have been infected with the COVID virus, and all but four have returned to work. So the work that we are doing with PPE, social distancing and allowing the critical resources to come in and operate the facilities that are needed, has been very critical to us. And as I mentioned earlier, we've expanded our care to those families that need extra resources. We've completed 26 maintenance outages at our power facilities readying for summer readiness, and all done without issues. So with that – that's the overall view of the operations and what we are focused on. And I'll turn it over to Joe to go through the financial.

Thank you, Chris, and good morning, everyone. Today, I will cover our first quarter results and our updated full-year guidance, including the financial impacts of COVID-19 and sensitivities for the remainder of the year. Starting with Slide 10. We earned $0.60 per share on a GAAP basis and $0.87 per share on a non-GAAP basis, which was slightly below the midpoint of our guidance range. We are particularly pleased with the results considering we had one of the warmest winters on record. Temperatures in the Mid-Atlantic were five to seven degrees higher than average in January through March, costing us $0.14 per share between Exelon Generation in our non-decoupled utilities. This quarter was the most impacted by weather of any quarter since the PHI merger. Exelon Utilities delivered $0.55 per share net of holding company expenses. Our non-decoupled utilities, PECO, Delmarva, Delaware and Atlantic City Electric were impacted by the warm winter weather. Across these territories, heating degree days were down 18% to 22% during the quarter. These impacts were partially offset by O&M timing across the utility. ExGen was also impacted by weather, earning $0.32 per share in the first quarter. The weather impact on gross margin and unplanned outages at Salem and FitzPatrick were offset by favorable O&M and nuclear decommissioning trust fund gains. Turning to Slide 11. Efforts to combat the spread of COVID-19, including stay-at-home orders in our states have caused dramatic changes in electricity demand and the national economic outlook. Taking into account the impact of COVID-19 unfavorable weather and lower ROEs at ComEd, we are revising our 2020 full-year guidance range from $3 to $3.30 per share to $2.80 to $3.10 per share. While typically we would not change guidance so early in the year, we want to provide a complete picture of where we stand at this point in the year and include our best estimates of the COVID-19 impacts. Let me start by saying that none of us has ever experienced anything like this before. The full impacts, including the duration and structural changes to the economy continue to evolve. In developing our revised guidance range, we looked at the load and economic data we were seeing in April, talk to our customers about their expectations for the year and considered different economic outlooks. In Q2, we expect commercial industrial load to decrease by 9% to 15% and residential load to increase by 4% to 7% depending on the region. Over the remainder of the year, we expect commercial, industrial unfavorability and residential favorability to diminish as the economy recovers. We've taken a cautious view of the world and you can see the assumptions on this slide that underpinned our new guidance range. We also recognize that the situation is changing rapidly, so we show a number of sensitivities to our guidance on the following pages so you can calibrate. I also want to come back to a point on actions we are taking. We challenged the organization against the current backdrop, identifying and pursuing initiatives across the company to lower our costs and improve our profitability. These provide $250 million of offset to other pressures which we reflect in this updated forecast. At the utilities, the $0.10 per share degradation from prior guidance can be split into a little over $0.05 for lower distribution ROEs at ComEd due to the drop in the 30-year treasury and a little less than $0.05 for the record mild first quarter weather. For COVID-19-related impacts, we expect to be able to offset the impact of lower loads at our non-decoupled utilities through cost reductions and the assumption that our regulators allow for timely recovering of expected higher bad debt. At ExGen, the $0.10 per share degradation reflects $0.05 of drag from the very mild Q1 weather and then $0.05 of COVID-19 impacts on load net of our cost and business initiatives. In addition to the O&M savings, we remained focused on cash at ExGen and have lowered CapEx by $125 million in 2020. We expect our earnings to be most impacted in the second quarter and have provided adjusted operating earnings guidance of $0.35 to $0.45 per share. Looking at the impact of COVID-19 on the utilities on Slide 12. As you can see, 70% of the Exelon Utilities are decoupled and the revenues are not subject to load fluctuations. The majority of volumes that are non-decoupled utilities, PECO, Atlantic City Electric and Delmarva, Delaware, are commercial industrial customers. In the table at the bottom right, we provide sensitivities for load by customer class and ComEd's distribution ROE for the remainder of the year. Each of our utilities is working with the regulators on COVID-19 cost and bad debt recovery mechanisms where we do not have them. Atlantic City Electric and ComEd have existing bad debt recovery mechanisms that result in no earnings impact with the cash being recovered in 2021 and 2022, respectively. Last month, the PSCs in Maryland and DC issue orders to authorize a regulatory asset that tracks prudent COVID-19-related costs incurred, which will allow for an assessment of recovery of incremental bad debt or atypical costs related to the pandemic. We are currently engaged with our commissions and stakeholders in Delaware, New Jersey and Pennsylvania regarding the potential recovery of costs. On Slide 27 of the appendix, we provide more detail on these efforts and current bad debt recovery mechanisms. Turning to Slide 13, the impacts of the Constellation business are like those of a non-decoupled utility. Constellation delivers around 210 terawatt hours annually of customer load through its wholesale and retail channels. In retail, Constellation’s 2019 customer breakdown was 90% commercial and industrial and of those customers, 70% of them were on fixed price contracts. When we look at volumes for the rest of the year and exclude index contracts, we have about 125 terawatt hours of normal annualized load exposed to COVID-related demand destruction. For the last nine months of the year, we assume Constellation load is down 6% in total with C&I down 9% and residential increasing 2%. I know there've been questions about how Constellation’s fixed price load contracts are impacted by COVID-19, so let me take a minute to explain. These fixed price contracts assume that the customer will use a certain amount of electricity and are impacted by fluctuations in customer usage in three ways. First, margin; second, commodity value; and third, through collection of fixed price charges and we are seeing the impacts of lower load on easing the current environment. When load is lower, Constellation loses the original sales margin on those unconsumed megawatt hours. Customer contracts can become in and out of the money over time. When a forward contract is signed, it assumes a price for electricity over the term of the contract. If the power procured for the customer is at a higher price than the current market and then the customer consumes less than forecasted, the generation must be sold into the open market at a lower price creating a gap in revenues. Finally, customers are billed for capacity and transmission charges that are charged by the ISO. Although these are typically fixed charges, for many customers we unitize them over the expected quantity of electricity and collect them on a dollars per megawatt hour basis. So when the customer consumes less, we under collect the fixed charge due to the ISO and are responsible for the shortfall. These fluctuations can be positive or negative to our bottom line. In a normal world where load fluctuations are primarily driven by weather, the risk is priced in and assumed in the contract. That assumption of risk could not have predicted the demand shocks and impacts that we are seeing due to the pandemic. In 2020, where C&I load is significantly displaced, we are seeing pressure on our gross margin, which is reflected in our guidance. We also expect the drop in profits to be limited to the period in time that the pandemic drives very wide differences in actual and assumed usage. Looking to the future, the Constellation business will return to profitability levels similar to those under normal conditions. And besides this highly unusual situation, having our load be primarily commercial and industrial customers remains key to our strategy. First, C&I customer usage patterns are aligned with our baseload generation portfolio, as C&I load is much more predictable and stable than residential load. In normal circumstances, C&I customer load is less exposed to weather fluctuations due to its higher load factors than residential customers. Second, C&I customers allow us to achieve scale that cannot be done with residential customers. Finally, although the gross margins maybe higher on residential customers, these margins do not account for the cost to acquire these customers, which are higher than C&I. You can see the impacts of weather and COVID-19 on our gross margin on Slide 14. In 2020, total gross margin is down $300 million. $100 million is due to Q1 weather, which can be pretty evenly split between lower volumes on our power and gas customer businesses. As a reminder, our gas business makes most of its margin in the winter. We’ve entered $200 million lower due to the impacts of COVID-19 on the balance of a year. During the quarter, we executed $100 million and $50 million in powered new business and non-powered new business respectively. In 2021, total gross margins down a $100 million primarily due to lower power prices in PJM in New York as well as some modest carry over of COVID-19-related drag on the load business. Since the end of the quarter, we have seen power prices rebound a levels above the start of the year, recovering most of the gross margin decline. We also executed $50 million of powered and non-powered new business during the quarter. We've remained behind our ratable hedging program in both 2020 and 2021. We ended the quarter slightly more behind ratable in 2020 then at year end at 8% to 11% due to the reduction in load offsetting hedges made during the quarter. 2021 is 2% to 5% behind ratable. We continue to see some upside in certain markets, but are not expecting a significant rebound in power prices or volatility. Slide 15 provides our 2020 projected sources and uses of cash. Our free cash flow is down $775 million from our last disclosure. The utilities cash flow accounts for $600 million of the degradation, largely due to timing of accounts receivable and bad debt, which we expect to reverse. ExGen's free cash flow is down $100 million reflecting the gross margin decline, but is mitigated by cost reductions and lower CapEx. Our liquidity position is strong. As you know, in March there were significant disruptions in the commercial paper markets and we temporarily drew down $1.5 billion on ExGen's $5.3 billion credit facility, which we repaid in early April. Given the uncertainty in that market in a $900 million [June] holding company refinancing, we issued $2 billion in April at corporate, which gives us additional flexibility. We are confident that we have ample liquidity to meet our needs. We also remain committed to strong investment grade credit ratings. Our FFO to debt is projected to fall to 18% and is below our 19% to 21% target, which reflects the combination of lower FFO and higher debt in 2020 due to the pressures I previously disclosed. We expect to see improvement in our FFO in 2021 as some of the cash timing issues that the utilities resolve next year and the impacts from COVID unwind. If they were to persist, we have levers we can take to enhance our credit profile. We talked to the rating agencies and their understanding of the current market environment. I'll now turn the call back to Chris.

Thanks, Joe. The pandemic has brought unexpected challenges to our business in 2020. We have found ways to offset much of the financial impact of this unique challenge, but we're not done. We'll continue to look for ways. We can increase profitability and cash flow through the next three quarters. The impact on the COVID-19 does not change the fact that Exelon's fundamental business is strong and our strategy remains strong. Our utility rate base is growing over 7% annually for the next four years. In that time, we will add more than $13 billion in rate base, nearly equivalent to adding a utility the size of ComEd. Our utility operations are best-in-class first quartile – first quarter performance in reliability and customer satisfaction are continuing the solid performance for the rest of the year. Constellation is a premier integrator in their competitive platform. It's the most effective way to bring our generation to market while providing customizable solutions to fit the needs of customers. Our generation fleet is the cleanest in the nation. We are delivering one out of every nine megawatts of Clean Energy in a significant portion of the nation's Clean Energy. We continue to advocate for policies that will compensate our nuclear fleet for the essential role it plays in reducing carbon and air pollution and ensure their continued operations. If you look at our value proposition on Slide 18, I'll close with this. The value proposition is unchanged. We're focused on a growth of our utilities, targeting 7.3 rate base growth and a 6% to 8% EPS growth through 2023. We're confident in our rate base growth and the continued needs for these investments for the customers that we serve. But we're also mindful of the impact that the current 30-year treasury rate has on ComEd's distribution ROE and the impact on EPS in growth rates, if that rate was to stay this low. We will use the free cash flow from ExGen to support utility growth, paydown ExGen debt and support the external dividend. We will continue to optimize the value of our Genco business by seeking fair compensation for our zero-emitting generation fleet, closing uneconomic plants, monetizing assets and maximizing their value through Constellation. We will sustain a strong investment grade credit rating metrics throughout this period. Operator, we can now open it up for questions. Thank you.

[Operator Instructions] Our first question comes from the line of Stephen Byrd from Morgan Stanley. Your line is now open.

Hey, good morning. Hope you all are doing well?

Hope you are too.

Thank you. I wanted to just first talk to – thanks for the thorough update and disclosure, very helpful. The Illinois legislative process, we're trying to follow this as closely as we can. I guess the Illinois Department of Public Health gave some guidance around sort of how the legislature might be able to – under what circumstance they could reconvene. Do you have a sense for sort of the process and sort of the potential for the legislative session to go through the summer, just given the formal ending date in May, obviously, does not coincide very well with the state’s plan to sort of reopen. But it does look like there's some potential that the legislature maybe able to meet if they meet sort of these health department guidelines. What is your sense in terms of the ability of the legislature to meet and do business?

We have seen in other jurisdictions, legislative bodies be able to work through and convene. Kathleen, you want to talk specifically to the path forward here in Illinois?

Sure. Good morning, Steve. And then – as you know that stay-in-home order does extend through the end of May. So it is good – a good sign to see the Department of Public Health guidance to the legislature on how they might bring people back to the capital safely. That is good progress, but it just remains to be seen whether the leaders will decide to bring folks back to Springfield this session. Even if they cannot come back in May, they can come back in the summer by agreement of the Senate President and the Speaker. They could call a session after May 31 or the Governor himself could call a special session under the constitution. So we're glad to see that there has been guidance provided. There's just not yet any indication about when exactly they will come back.

Understood. A lot of uncertainties there. And then just I guess in a related matter in terms of operational decisions for your nuclear plants in Illinois, Chris, you had mentioned a lot of refueling has been completed and quite quickly as well. But are there any operational considerations you all would have to make, for example, if legislation is not passed in this, call it, some recession? Or do you have some flexibility, so that you can get the legislature a bit of time just given, obviously they have a lot on their plate to address in Illinois?

Yes. It's tough to speculate with everything going on with the COVID, what the outcome of this legislative session or being able to go into an extended session. What we've stressed to all the stakeholders is PJM is committed to run the auctions, and their stated time was towards the end of the year and that could be extended. We haven't gotten any public statement that it was extended that I know of. So we're up against a clock. And once those auctions are run, we're highly confident that minimal or any of our clean megawatts will compare in that capacity auction, they’ll be replaced by fossil units, which is detrimental to the states goal of being 100% clean by 2030. So the clock is ticking. And I wouldn't speculate on timing of decisions right now. But we're just stressing the importance to the administration and the key legislative stakeholders and others about not only the importance for the nuclear megawatts, but the importance for the renewable megawatts. So they have been invested in the state of Illinois to continue to be able to operate with a profitability that's reasonable. So that's where we're at right now. We're continuing the dialogue. Kathleen, Bill Von Hoene are leading the conversations through the state legislators and the stakeholders, and we'll continue to push on that.

Very good. I'll let others ask questions. Thanks.

Yes.

Next question comes from the line of Steve Fleishman from Wolfe Research, LLC. Your line is now open.

Yes. Hi, good morning.

Hi, Steve.

Hey Chris, I wanted to – I guess just get a little more color on the comments on the 6% to 8% utility growth rate. And you mentioned you'd be mindful, I think, you said, of the Illinois ROE and just – can you maybe give a little more color on how to think about – it's obvious what you're embedding now for 2020. But how about for the kind of broader growth rate and if rates don't get better, are you still within that range? Or just what you've been assuming in there?

Yes. We have continued to work our five-year plan. I think we report out in some places a four-year plan, another is a five-year plan, but we're continuing on our long range plan and it has helped us significantly in customer satisfaction and reliability and it's also allowed us to maintain a cash flow and profitability while doing so, in the last three rate cases, we actually gave a rate reduction. So as you can imagine, as you would expect, we look at multiple scenarios. And if the economy continues to degrade, impact on customers, whatever it could be is out in the future. The plans can be adjusted. But at this time, we don't plan on adjusting. We plan on continuing to do the much needed reliability and efficiency modifications and prepare the system for the onset of much more distributed and renewable energy coming on. It won't be able to happen if we don't make the investments and facilitate it. If we see a day that we're not getting that return or don't see a path to go back. I mean, we haven't seen that day and we haven't seen that in the near future. So we're continuing on with the investment and watching the treasuries and watching the recovery mechanisms.

Okay. So – but just to clarify the – if we're in these kind of lower rate environment, I don't know exactly where the whole forward curve of 30-year is? You're still expected to be within the 6% to 8% range?

Yes. Go ahead Joe.

We're not changing the target of the 6% to 8%. As Chris said, we're moving forward with the investment that we plan to make. We update that target once a year. We also show you sensitivity related to the ComEd ROEs. Obviously they've dropped some since the first of the year has an impact. We also give you earnings bands that we gave you out through 2023 and we're still well within the bands that we gave you and we'll continue to look for ways to challenge ourselves in this regard.

Okay. Thanks, Joe.

At this point, it would be very short. It would be very shortsighted for us to start, stop, start, stop depending on an interest rate. The most efficient way is to get the long-term investments prudently done and support the customer's needs.

Got it. I see what you're saying. So you're saying, Chris, that you're not going to hold back on investment in the state because of the temporary rates being lower. Got it, okay. Just one other question, yes. One other question just for – I guess for Joe, you mentioned levers on your credit. You have levers on your credit profile. If I guess things stay weaker there, could you just give some color on what those levers are?

Steve, I think we've got a track record of proving that we continue to challenge ourselves on our cost structure. I mean, we're reducing our costs by $250 million this year with actions we've taken and we're going to continue to challenge ourselves in the future in that regard. We've been clear that we have some on economic power plants and we're working hard to rectify that. We would have to address that. Those would be two big levers that we would have to address.

Okay. Thank you.

Thanks.

Next question comes from the line of Shar Pourreza from Guggenheim. Your line is now open.

Hey. Good morning, guys.

Hey, Shar.

So a couple of questions here. Realize with Illinois, there is significant uncertainty over 2022 with PJM, but can you speak a little bit at a high level to how gross margin is developing? Maybe just directionally ignoring the upside or downside from capacity reform. And I realize this is secondary at this point, everything going on, but do you still think something can get done in Illinois at the veto session?

We're still working. We still have significant support on what we have to do. Where it gets done, we would hope that it would get done before the end of the session. That's what we've stressed to give the IPA time to be able to develop their own auction process, that will allow us to breakaway on capacity needs for the state of Illinois from PJM. As I said earlier, it's a very tight timeframe. If they were able to come in, in a summer session and we had assurances, they were going to address this in a summer session under the requirements by the Illinois Health, we would continue to work with them on that. But there's a lot of things that have to get done in Springfield, but they also realize that this is a very important issue to address and along with the state budget in some other large issues. So we know there's a will to get to work. It's just the way to get to work and how fast we can get this done.

Got it. And then just what kind of C&I attrition are you guys expecting in your assumptions? And sort of how do we sort of think about contemplation more broadly as we look at 2021 and beyond? And does the current situation present any strategic opportunities in your view, maybe on the retail side? Or does sort of some of the reprieves we've been seeing at the state level, on the retail side push off any potential acquisition opportunities as you guys look to tighten up that natural hedge?

Jim, do you want to – Jim McHugh, do you want to cover that one?

Sure, absolutely. I'll answer kind of two parts. I think what we expect from the low decreases we're seeing now is as the states reopen and as things recover, we're seeing about a 15% reduction in that C&I on average in these front-near months. By the end of the year, as Joe mentioned on the call that's more than a probably 4% to 6% range and coming back in through mid next year. So from a load perspective, it's temporary and I think we expect that to bounce back. I think from a strategic perspective, a couple of things, we definitely for acquisition space, we'll continue to look for any value of books that comes to the market. There could be some suppliers that would need to look over their books. We've talked about our strategy before. We'll stay the same, which is we would be looking to buy things, buy books of business that we could easily fit into our platform. We've developed, I think, a world-class platform over the years that we can integrate easily. And we've shown that before when we bought books of business. And then lastly, I think strategically it's just product development where we'll look to either continue to refine the products we sell now and look for demand charges that could be either faster or more associated with the customers fixed charges and look for other products that we can develop to give them access to data analysis and sustainability targets that they have.

Got it. And just lastly, Joe, I know you obviously highlighted that the rating agencies understand how transient in nature the cash flow dip is in 2020? Can you just remind us just from a perpetual ongoing perspective, how to think about the $250 million cost savings and the ExGen CapEx reductions for our modeling perspective?

Yes. I would say right now most of the $250 million we're viewing as a one-time item. And some of it's being driven by the situation when you think about with things like reducing contractor spend, reducing non-critical IT spend, when you look at reductions in travel spending, consulting spend, holding vacancy rates in our organization, all of those things are contributing to the reduction in O&M. I will say though, when we go through our planning process, which begins here late in the second quarter and through the end of the year, we've had a track record of continuing to challenge ourselves and find ways to reduce costs. And given the environment we're in and some of the things, quite frankly, we've learned we maybe able to carryover some of these cost savings as we look at future periods. We just haven't made a determination on that yet.

Terrific. Thanks guys. I'll pass it to someone else. Thank you.

Operator, next caller please.

Next question comes from the line of James Thalacker from BMO Capital Markets. Your line is now open.

James, you there?

Can you guys hear me?

Yes, we can now.

Okay, thank you. This is obviously a little bit more of a granular question, but just looking on Slide 14, there was a $100 million, I guess change from December in the non-powered new business to go. I was just wondering if you guys could talk a little bit about what's exactly in that bucket.

Yes. The $100 million non-powered new business to go is attributed partially to execution and partially, as I said in my prepared remarks in Q1. We had impact both on powered and non-powered related to weather and we took a reduction for the balance of the year. That's all embedded in a total $300 million that you see in the gross margin change in the hedge disclosure.

Okay. I was just wondering, was it a specific product that you guys are selling that where you saw the weather impact? Or just trying to understand…

What's embedded in that non-powered to go, the bulk of it is our – big piece of it is our gas business. And since that's so seasonal and related to the winter, you see the impact there.

Got it. So it was just retail gas. Okay. Perfect. Thank you very, very much.

Next question comes from the line of Durgesh Chopra from Evercore. Your line is now open.

Thanks for taking my question. I just have a quick clarification question. You answered most of the things I had. In terms of just states or territories where you don't have riders on COVID costs like bad debt, just want to clarify that you’re assuming recovery of those in the future, right? So the $250 million kind of targeted cost reductions don't cover that.

No, they don't. This is Calvin. In all of our jurisdictions where we are not – for our bad debt and we do not have a rider, we are working in partnership with the commissions to sit back and establish regulatory assets. As Chris alluded to in his opening comments, Maryland and DC, both of their commissions unanimously passed regulation allowing the utilities to set up regulatory assets and also set aside what identify prudently incurred COVID-related costs. And we will operate under the same standard that were used to operating on, showing that it's just and reasonable. We are working with the Pennsylvania commission and Delaware commission and we hope to have rulings from them in the next week to 10 days to drive that. So at the end of this, all of our jurisdictions, we believe will be operating under a regulatory asset to show what those are bad debt costs and the COVID-related costs are.

Got it. Perfect. That's it for me guys. Thank you very much.

Next question comes from the line of Julien Dumoulin-Smith of Bank of America. Your line is now open. Julien Dumoulin-Smith: Hey. Good morning, team. Hope you all are well.

We are doing good. Hope the same for you. Julien Dumoulin-Smith: Excellent. Thank you. I wanted to follow-up, perhaps clean up a little bit on some of the questions thus far. First, with respect to the earnings CAGR and how you're thinking about that. But for the oscillation in the 30-year treasury, anything else shifting in your outlook? Obviously, the slide is slightly different here, so I just want to make sure we're not missing anything, coming back to Steve's question.

Julien, there's nothing else shifting that CAGR other than the 30-year treasury. Julien Dumoulin-Smith: Okay. Thanks. Glad we've set that one aside. Separately, if I can keep here on the Constellation business and ExGen overall, when you think about the sensitivities to further – you saw a faster or slower improvement here. Can you give us a little bit of a sense, and I mean that more in the context of C&I sales degradation improvement as well as some of the portfolio optimization of volatility dynamics here as well. And how that could play out in 2020 as well as what are you reflecting in 2021, just to be extra clear about that.

Jim, do you want to cover that? I'm not sure we've covered 2021 yet, but we can cover 2020.

Sure. Glad to do it. Thanks, Julien. The way we think about the balance of this year, and then I'll talk about 2021. You see the sensitivity on the slide that for every 1% change in C&I load, you see about a $15 million net income impact and resi is about a $7 million impact. We've assumed, as we said, a slow return through the balance of this year and into next year. So what the 1% sensitivity at least allow you to do is say, well, if across over those months, it moves up or down 1%, that's the number you would expect. I think as far as the optimization activity with this – with these gross margin estimates, we've given you, we see line of sight to being able to hit our normal optimization activity in the remainder of the new business to-go bucket. So we don't expect too much impact there. We basically realign these targets now with these adjustments to have good line of sight to balance of the year. For 2021, we've included about $50 million of impact for COVID and that is more a little bit of an impact on the load trickling into the year, but it also represents the fact that some of the new business activity to sign customers up has slowed down just because of the status of work that people are in. We've been tracking that and we feel like that's a really good estimate right now and we've been able to maintain a pretty good signing up of new customers. A little bit of dip in the win and renewable rates for the month of April. As we get granular on really being able to understand which those are impacted by how much, those win rates and renew rates bounce back up to, I think more on normal levels and the $50 million we've included is a good estimate. Julien Dumoulin-Smith: Okay. Excellent. If I can just clarify your prior response very briefly. With respect to what the date as of for the 30-year treasury that you are assuming in that EPS CAGR, I just want to be extra clear. Again, I don't know if you have a specific date or curve that you're using, you want to establish that.

Yes. 3/31 is the date we're using, the end of the first quarter. Julien Dumoulin-Smith: End of the first quarter for the 30-year treasury, so.

Yes. Julien Dumoulin-Smith: Okay. Excellent. Thank you.

There are no further questions at this time. Mr. Chris Crane, do you have any closing remarks?

Yes. No, thank you all for joining the call. I want to thank our employees for their commitment and dedication in these unprecedented times. And I hope that all of you and your families are safe and healthy. And with that, I will close out the call. Thank you very much.