Hello, and welcome to today's webcast. My name is Tamara, and I will be your event specialist today. 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 phone over to Dan Eggers, Senior Vice President of Corporate Finance. The floor is yours.

Thank you. Good morning, Tamara. Good morning, everyone and thank you for joining our Fourth Quarter 2019 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'll 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 contains 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 factors 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.

Thank you Dan, and good morning everyone. Thank you for joining us for our 2019 fourth quarter earnings call. I'm going to start on slide 5. On almost all accounts, we had a very good 2019. Exelon Utilities and Generation remains focused on delivering for our customers and their communities. ComEd had its best performance ever. The nuclear fleet had its best capacity factor and we delivered financially. As you can read, the full year GAAP earnings were $3.01 per share, and the non-GAAP earnings were $3.22 per share above our revised guidance range and midpoint of our original guidance range. Joe will walk you through the financial details later in the call. I want to address the operational details as we go forward. Last year, Exelon Utilities invested $5.5 billion in capital and $150 million – which is $150 million more than originally planned. These investments were primarily in infrastructure and technology to provide a premier customer experience, improve reliability and resiliency, modernization of our gas system resulting in best-ever customer satisfaction at each of our utilities. We had a productive year on the regulatory front. Pepco D.C. filed its first multiyear rate case and Maryland's PSC is moving forward with the multiyear rate plans. We received a constructive settlement at BGE and at ACE. PECO's transmission formula was approved by FERC, and ComEd's formula rate provided the third-rate decrease in five years helping to keep the average residential customer bill flat from where it was a decade ago. On the policy front, the United States Supreme Court upheld the Illinois and New York ZEC programs. New York Supreme Court – Superior Court affirmed the ZEC program and New Jersey implemented their ZEC program in the spring. Governor Wolf in Pennsylvania announced plans for Pennsylvania to join RGGI, and the Pennsylvania State Senate passed legislation setting a goal for electric vehicles and deployment. FERC approved PJM's fast-start reforms. PJM filed its proposal to reform the reserve market and scarcity rules. We made our commitment to grow the dividend by 5% annually through 2020 with the Board raising the annual dividend to $1.53 per share in January. We're good partners also with the communities we serve. Our employees volunteered a record-breaking 251,000 hours in 2019, that’s 11,000 more than in 2018. During National Volunteer Week, we sponsored 452 events in 16 states and 128 cities with 5,400 employees which is another record. In addition, Exelon donated nearly $52 million to charities and organizations throughout our footprint. We are committed to providing a diverse and inclusive environment for our nearly 33,000 employees. We were once again named Best Company for Diversity by Forbes, DiversityInc, and the Human Rights Campaign. Our total diversity supplier spend exceeded $2 billion for the third straight year, accounting for 27% of our overall supplier spend. Exelon companies continue to prioritize partnerships with local-based diverse businesses by offering development programs. We also continue to be recognized for our environmental stewardship and were named to the Dow Jones Sustainability Index for the 14th year in a row. We are focused on operating at world-class levels delivering on our strategy in supporting clean energy policies in their state. The hard work and the commitment of our employees to provide safe, reliable power, and natural gas to our customers led way to the greatest performance we had in 2019. We delivered on our commitments to you our shareholders, but also our employees and our customers and our communities. However, this year was not -- last year was not without challenges including subpoenas we received from the U.S. Attorney's Office in Northern Illinois. As we said before, we are limited in what we can share about the investigation. However, I want to reiterate that we are fully cooperating with the U.S. Attorney's Office and taking the situation very seriously. The Board appointed a special committee to provide oversight of the investigation led by outside counsels to determine if any changes are needed to ensure that going forward we operate at the highest possible standards. At the end of [Technical Difficulty] our commitments for 2020. Turning to slide 6, we're committed to operating our utilities at the highest levels for our customers. Since 2016, we have deployed nearly $22 billion across the utilities and plan to invest $26 billion over the next four years. These investments enhance reliability, resiliency, and modernize our electric and gas systems. We've been able to make these needed improvements while keeping the boards -- the bills affordable. The rates in all our major cities; Baltimore, Chicago, Philadelphia, and Washington are 13% to 18% below the average for the largest U.S. cities, and 2% to 7% below the national average. These investments are producing tangible benefits for our customers. Customer satisfaction is the highest level it's ever been at each one of our utilities, reflecting a strong system performance that has come from our investments. Frequency of outages has decreased significantly, down near 50% at ComEd and 30% at PHI. Outage duration has also decreased by 52% and 38% at ComEd and BGE respectively. 2019 was the best reliability performance for ComEd and the second best for BGE. On the gas side, PECO and BGE have replaced more than 200 miles of cast iron and bare steel mains and nearly 30,000 metallic gas services in 2018. These investments will help our customers' current and future needs while reducing gas leaks and greenhouse house gas emissions. Moving to slide 7, our states are focused on ensuring the electric and the gas systems are ready to meet the changing customer needs, more reliable and more resilient and are prepared for renewables in electric vehicles and are ready to meet the challenges of climate change. We are working with each state to get the right mechanisms in place to be able to make these needed investments. Our states are providing support through a range of regulatory tools, including alternate rate making such as formula rates and multiyear rate plans as well as tracker mechanisms for reliability and gas infrastructure programs. Turning to Slide 8, FERC's recent order on PJM capacity. The Governors in Illinois, Maryland, and New Jersey are firmly committed to having their electricity be supplied by 100% clean. These states are leading the way to a clean energy economy and we share that goal, and we'll work with them to achieve it. Unfortunately, there is a clear conflict between clean energy goals of our states and our customers on one side and the resource decisions being made by PJM and FERC on the other. Unless states take action to protect their clean energy programs, FERC's December order on the PJM Minimum Offer Price Rule or MOPR will result in clean resources supported by the states being pushed out of the capacity market only to be replaced by carbon-based generation. This would result in billions of dollars of additional costs for customers and threaten the progress being made in retaining and expanding our clean energy. Our states as well as many others oppose FERC's MOPR decision and are evaluating what actions may be necessary in response. We are working with policymakers and stakeholders to protect the clean energy programs from the negative impact of FERC's MOPR decision and enable the transition to 100% clean. On Slide 9, we show our operating performance for the year. Each utility continues to have outstanding customer operations, all achieved first quartile in performance and service level and abandon rate. And I mentioned, we had our best ever scores on customer satisfaction index with BGE ComEd and PECO achieving top decile and PHI's performance significantly improved in the last three years missing first quartile by 0.01 points. Reliability performance was mixed this year due to a very active minor storm season throughout the Mid-Atlantic. For instance, PHI had 32 minor storms for 2019 compared to eight in 2018. Minor storms are not excluded from these calculations. However, ComEd achieved top quartile in both outage frequency and duration and BGE achieved top quartile on outage duration. Turning to generation on Slide 10, our fleet -- generation fleet performed one of its best years ever, very good in 2019 providing a significant portion of the country's clean energy. Exelon generates 12% or one out of every nine clean megawatts in the United States. Our best-in-class nuclear fleet operated very well last year. Our capacity factor was 95.7% our highest ever. We generated 155 million megawatt hours, avoiding 81 million metric tons of greenhouse gas emission in 2019. Our average refueling outage duration was 21 days, matching the record set in 2018 and 18 -- 14 days better than the industry average. Exelon Power's gas and hydro dispatch matched 97.9% and wind and energy capture at 96.3% were better than planned. Our Constellation business remains the industry leader. A vast majority of our retail businesses is with C&I customers where we have the largest retail platform with 25% market share delivering 154 terawatt-hours of electricity and 67 terawatt-hours more than our nearest competitor. Our retail operating metrics remain strong; 79% customer renewal rates, average customer duration of more than six years, and power contract terms of 23 months on average. We continue to see stable unit margins with our power customers. Our focus is on cost and helping support operating margins. Constellation's strength lies in its durable relationship with our customers. We work with our customers to provide them solutions to meet their energy needs while also reaching their environmental and sustainability goals. We provide our customers with much more than just a commodity. And now I'll turn the call over to Joe to review the financials.

Thank you, Chris, and good morning, everyone. Today I will cover our 2019 results, annual updates to our financial disclosures, and 2020 guidance. Starting with slide 11, we had another strong year. For the fourth quarter we earned $0.79 per share on a GAAP basis and $0.83 per share on a non-GAAP basis. For the full year we earned $3.01 per share on a GAAP basis and $3.22 per share on a non-GAAP basis, which is above our revised full guidance -- full year guidance of $3.05 to $3.20 per share and $0.07 per share above our original mid-point. Exelon Utilities delivered a combined $1.91 per share net of holding company expenses. Utility earnings were higher relative to original guidance, due to favorable O&M, including the lack of major storms, and favorable weather at PECO and BG&E, as well as higher distribution revenues of the PG&E. These were partially offset by the impact of lower treasury rates, on ComEd's ROE. ExGen earned $1.31 per share, exceeding its guidance range of $1.20 to $1.30 per share. ExGen's outperformance was primarily due to favorable O&M, including incremental nuclear insurance distributions, and recognition in the fourth quarter of the research and development or R&D tax benefit, for the years 2010 through 2018 tax years. We expected to record this benefit, but it was more favorable than we had planned. This favorability was offset by the unplanned outages at Salem, Handley Station and a contracted asset during the year. Overall, we delivered well on our financial commitments. Moving to slide 12, the consolidated PHI utilities earned a 9.2% ROE for the trailing 12 months, up 90 basis points from year-end 2018. The improvement is driven by the constructive distribution rate cases, across the jurisdictions as well as incremental transmission revenue and a decrease in O&M, partially offset by an increase in depreciation. Earned ROEs for the legacy Exelon Utilities were above 10%, slightly improving from year-end 2018. Looking at our utility returns on a consolidated basis, we earned a 10% ROE for the trailing 12 months, which compares to last year's 9.6%. As a reminder, we targeted 9% to 10% consolidated ROE at our utilities. And expect that we will move around in that band over the course of time. And we remain focused on earning fair returns across all of our utilities. On slide 13 we rolled forward our outlook for utility CapEx and rate base, covering 2020 to 2023. This year we expect to invest nearly $6.5 billion, in our utilities and a total of $26 billion, over the next four years. These investments are improving our system reliability, service experience for our utility customers, and preparing us for the future. Our capital forecast reflects identified and approved projects. As we move through time, we identify more investment needs across the system that will provide additional benefits to our customers and communities. Since the initial disclosures for the 2018 to 2022 period, we have identified nearly $4.9 billion in additional investments, including an additional $1.9 billion, since last year's fourth quarter call. As Chris mentioned, these investments benefit our customers, by helping to drive our operational excellence, overall customer satisfaction, and meet state resiliency and environmental priorities. Since the PHI merger in 2016, we have added more than $9 billion in rate base across the utilities. Over the next four years, we will grow our rate base 7.3% annually to $54.2 billion, adding $13 billion to rate base by 2023 or the equivalent of adding a utility between the size of PHI and ComEd, without paying a premium, issuing equity or obtaining merger approvals. As a reminder, 65% of our rate base growth is covered under either formula rates or mechanisms such as capital trackers. These support our ability to efficiently invest in our system while also allowing us to earn a fair and timely return on our capital. Where we do not have these mechanisms, we will continue to work with stakeholders to establish more timely recovery tools. Chris touched on this earlier, but I want to remind you all that we have been able to make these important investments while maintaining lower customer rates compared to other large urban areas. When we look at our projected residential bills, we continue to see bill inflation around/or below the rate of inflation even as we make these important investments. In the appendix, we provide a more detailed breakdown of the capital and rate base outlook for each utility starting on slide 23. Turning to slide 14. We continue to forecast strong utility less holding company, EPS growth of 6% to 8%. When you consider the drop in the 30-year treasury that lowered our EPS outlook for ComEd by roughly a nickel compared to what we had showed you last year, we've been more than able to offset in the back end of our plan through the increased CapEx program across the utilities for the benefit of our customers, which brings us to the durability of our industry leading earnings growth, which reflects the combination of strong rate base growth to support system needs for a more digital economy and environmental goals, successful cost management and a focus on customer bill affordability. Before discussing our gross margin update on slide 15, I want to remind you that given the lack of clarity around the outcome of legislation in Illinois and the fact that PJM has not yet held a capacity auction for the 2022, 2023 delivery year, we will not be providing any ExGen disclosures beyond 2021. So turning to the table, there is no change in total gross margin in 2020 or 2021 from our last disclosure. Open gross margin declined by $400 million and $100 million in 2020 and 2021, respectively due to declining power prices across most regions offset by our hedges. During the quarter, we executed $50 million of power new business in 2020. We remain slightly behind our ratable hedging program in all years. We ended the year 6% to 9% behind in 2020 and 3% to 6% behind in 2021 when taking cross-commodity hedges into account. We continue to see some upside in certain markets, but are not expecting a significant rebound in power prices or volatility. Slide 16 shows our O&M and capital outlook at generation for 2020 and 2021. Compared to our previous disclosure on our fourth quarter call, last year our O&M is down in each year. The updated forecast reflects O&M cuts we announced on last quarter call, pension benefits and nuclear savings. The return on our pension investments in 2019 significantly exceeded our planned returns, but this favorability was partially offset by the drop in the discount rate. Taking both into account our pension expense it's about flat to plan in 2020 and is down by approximately $25 million in 2021. Turning to CapEx. We expect lower cash outlays than we projected last year. We have reduced the growth capital in 2020 and 2021 given the focus of recycling ExGen cash and the increased need for equity investments at the utilities given their growing capital needs. Nuclear fuel costs are also lower in 2020 and higher in 2021 versus last year's disclosure, primarily due to a shift in deliveries. Overall, we continue to see a constructive outlook for the nuclear fuel costs looking out over our planning horizon. We will continue to look for ways to be more efficient in how we work and spend to improve the cash flow profile of ExGen while maintaining the safety and reliability of our fleet. Moving to slide 17. We remain committed to maintaining a strong balance sheet and our investment grade credit ratings. Our consolidated corporate credit metrics are consisting with our targeted ranges and above S&P thresholds. Looking at ExGen, we are well ahead of our debt-to-EBITDA target for 3.0 times. For 2020, we expect to be at 2.4 times debt to EBITDA and 1.9 times debt to EBITDA when excluding non-recourse debt. This year we will be active in the capital markets, as we support our utility rate base growth. At ExGen, we plan to retire $1.5 billion of long-term debt this year, including the $1 billion maturity we paid off in January. As a reminder, this in addition to the $600 million of long-term debt retired in October of 2019. Finally, I will conclude with our 2020 earnings guidance on Slide 18. We have provided 2020 adjusted earnings guidance of $3 to $3.30 per share. Growth in utility earnings is primarily driven by the continued increase in rate base, as we deploy capital for the benefit of our customers as well as carry through from the 2019 rate cases. We will see offsets from lower treasuries on ComEd's earned ROEs, higher depreciation and some regulatory timing drags between investment and rate cases most notably at PECO. Our consolidated range in 2020 for utilities less HoldCo is $1.80 a share to $2.10 per share. The decline in earned ExGen's earnings is a combination of lower realized energy prices and capacity revenues, more planned nuclear outage days and the absence of nuclear decommissioning trust gains. These are partially offset by a full year of ZEC revenues in New Jersey and increased ZEC revenues in New York. We expect first quarter operating earnings to be in the range of $0.85 per share to $0.95 per share. More detail on the year-over-year drivers by operating company can be found in the appendix starting on Slide 55. With that, I will now turn the call back to Chris for his closing remarks.

Thanks Joe. Turning to Slide 19, I want to discuss our key focus areas for 2020. We will continue to deliver operational excellence across our businesses, focusing on modernizing the grid and improving the customer experience at our utilities, while staying focused on safety and reliability. We will meet or exceed our financial commitments delivering earnings within the range and maintain our investment-grade credit ratings, as Joe mentioned. At the utilities, we will prudently and effectively deploy $6.5 billion of capital to benefit our customers and help meet the needs -- our states' energy policy goals and we will work with our regulators to ensure timely recovery on these investments. We will support the enactment of state and federal clean energy policies with major initiatives in-flight in several states. We will -- and we will partner and ally with the communities we serve. This is key to who we are. Slide 20. I will close on Exelon's value proposition, which highlights our strategy and commitment to shareholders. We will continue our focus on growing our utilities targeting 7.3% rate base growth and 6% to 8% earnings growth through 2023 rolling forward another year at this above-group trajectory. We will use free cash flow from ExGen to support utility growth, pay down 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 generating fleet, closing uneconomic plants and monetizing assets as we see value is there, while maximizing their value through generation to load matching strategy at Constellation. We will sustain growth investment-grade metrics -- excuse me, strong investment-grade metrics and we will grow our dividend at 5% through 2020. The strategy underpinning this value proposition is effective in providing tangible benefits to our shareholders. We remain committed to optimizing the value of our business and earning your ongoing support to Exelon. Operator, we can now open the call to questions.

Thank you. [Operator Instructions] Your first response is from Greg Gordon with Evercore.

Thanks. Good morning. Congratulations on a great year and the outlook is encouraging. A couple of questions. The utility growth outlook has obviously improved as we go out through time, despite the headwind from ComEd. The CapEx is up significantly, but the rate base growth numbers look like they're not moving as much in tandem. I skimmed through the whole deck. I understand, you've also moved capital around the different jurisdictions as well, but can you just comment on sort of that modest level of dissonance between CapEx being up and rate base growth looking like it's not up as much?

Yes, Greg. Good morning. It's Joe. Yes. The issue isn't solely that the incremental CapEx that we mentioned of approximately $2 billion isn't falling to rate base. It's about all of the CapEx and what we get into is the timing of when these projects go in service. So, we've updated some assumptions as it relates to the schedule of when the projects are finished and then they go into service. In addition to that, we could have changes in things like depreciation that would also impact that. So, it's really just a movement of when we see project timing and other things.

So AFUDC is not -- or CWIP and AFUDC are not contemplated in those calculations then?

No. They're not contemplated in that calculation.

Okay. That explains it. Thanks. In terms of the cash flow profile, I know that you haven't given us an update because we do have obviously significant uncertainty with regard to ExGen and Illinois. But as you look at most scenarios there, whether it's getting some sort of deserved incremental revenue for the clean attribute to your plants or having to use self-help to rectify the earnings issues, under most of those scenarios do you still see the utility being funded by the cash flow of the corporation without needing equity through this forecast period?

Yes. Greg, so the first thing I would say is, based on the current plan, as I mentioned in my prepared remarks, we don't incorporate any equity issuance in the plan. And going forward, we can meet the funding needs and maintain the investment-grade credit metrics under most scenarios that we look at, because we do look at this under a range of different possibilities.

Okay. Two more questions and they're quick. One, since the Q -- since the EEI deck, where you usually give us your update on where you think O&M and capital are driving it at ExGen, things have improved on the margin. Can you comment on how you've pulled forward some of the O&M and CapEx trajectory?

Yes. I think the big thing is when you look at the improvement in ExGen earnings, it's really driven by four variables. As you could see in 2020 and 2021, the gross margin hasn't changed, right? But what has changed is we announced the O&M reductions on the third quarter call, that’s been a benefit. Lower property taxes has been a benefit at ExGen. Lower depreciation is also a benefit. And then, finally, we do have some lower interest expense, when you think about the retirement of debt. So those four variables have driven improvement to the ExGen earnings.

Okay. Final question, Chris. The time flies. It seems like yesterday since you made the commitment to grow the dividend 5% through 2020, and here we are in 2020 and you've made good on that commitment. At what point do you go back to the Board with a recommendation on the dividend policy post 2020?

So I would anticipate, the discussions with the Board will be in the fall time frame, when we have further clarity on what the future looks like. If we are able to enact some of the policies and programs in the states we're working on, and it provides us with certainty that we can provide certainty to the Board that maintaining the health of the balance sheet while creating shareholder value, we should have a better picture at that time. So, I would expect us talking to you around year-end time frame about that.

Thank you, Chris. Take care, guys.

Thanks.

Thank you. Your next response is from Stephen Byrd with Morgan Stanley.

Hi. Good morning.

Good morning

I had a couple of broader policy questions. We've certainly been seeing quite a bit of evidence of -- especially, in the PJM states, a movement away from fossil fuels. And on the merchant side, I think I understand some of the moving parts there, but on the regulated utility side, what is your sense of the degree to which states are now pushing to move away from fossil fuels? And how do you think broadly about pivoting and sort of reacting to that shift at the utility side of your business?

So as you know Stephen, our utilities do not have any generation and are restricted from having generation in the states that we serve. What you see in our planning years that you're looking at for the utilities, they incorporate what we believe needs to be done to support the states' needs which calls for more robust distribution system investments to allow two way energy flows, which is going to require transmission buildout to take care of importing the wind [ph] from the pockets of the service areas that we serve. And that's what's anticipated right now in the capital plan that we have in front of you. We have got to keep up with the state's policies, legislative agendas, or whatever is going to change the system so our customers can benefit from these policies that the states are enacting.

Understood. And then just shifting over to the PJM capacity process, I wanted to just get your latest thinking on next steps procedurally. I'm thinking about sort of the broader process under which PJM would refine their approach and the timing under which they have an auction. I guess I'm thinking also about the possibility of pretty significant litigation around the -- whatever comes out of the PJM and the FERC process here. How do you see that unfolding? Just wanted to get your latest thoughts there.

Hi, Stephen, it's Kathleen Barron. I can take that question. I'll start with auction timing. As you know there's a large group of stakeholders including clean energy advocates, consumer advocates, renewable developers and most importantly the states who have asked PJM to take their time in scheduling the next auction. There's just been such a fundamental change in policy here that states need time to evaluate what the impact is on their customers and to design appropriate policies to protect their customers from the significant impact of this new policy on customer bills. So we of course agree with that perspective and are going to continue to urge PJM when they're developing their next filing effort which as you know is in March to propose an auction timing schedule that takes into account the states' needs. And in terms of litigation, you're right that there have been a number of requests for rehearing that have been filed. That would be the next step for FERC before this case could go to litigation. FERC has no time line in which to ask -- to act on requests for rehearing, but I think the more important point is they have been developing this policy for years. I mean they laid out in an order in ISO New England three years ago that MOPR is their standard solution and they have carried that through to PJM. I see no future where they change their mind on that policy and I think therefore the states are right in looking at what their alternatives are to continue participation in RPM.

Understood. And just to follow-up there Kathleen, can the auction proceed if there is pretty significant litigation from multiple states sort of questioning the fundamentals of the FERC order?

Well technically, it can. I mean I think from a good governance perspective, of course as I said before PJM should take into account the fact that some of the states need some more information to figure out what the impact is going to be on their citizens. They're going to need to do an internal evaluation. But from a legal perspective, the FERC order is final. And once the compliance filing is submitted and approved then PJM will be allowed to conduct an auction unless there's some sort of judicial stay imposed.

Understood. That's helpful. Thank you very much.

Thank you. Your next response is from Steve Fleishman with Wolfe Research.

Yes. Hi, good morning.

Good morning.

Can you hear me okay, Chris? Thanks.

Yes, perfect. Yes, we can.

Great, great. So just on the Illinois process, could you just maybe talk to I guess an update of the legislation and just trying to make sure that -- I think the hope is that there'd be more of a long-term framework in place for treatment of nuclear and renewables. And just how much is that likely to be part of any legislative activity in the state?

Well it's definitely -- there's two focuses that Exelon has in the legislation. One is the ComEd side ensuring that we have adequate recovery mechanisms for capital investments being made, while trying to maintain the customer protections that we need by caps on bill increases. So that part is very critical. Kathleen can address the Genco parts. She's been heading that up in Springfield in and around the state.

Sure Steve. I can jump in on the -- on your point about having a longer-term framework which is exactly the point of the legislation that's pending in Illinois. And the idea of using the Fixed Resource Requirement provision in the PJM tariff or the FRR provision is to give states that kind of flexibility to provide for example for renewables that may want to have contracts of differing lengths exactly that flexibility for them to have those contracts. And likewise for their broader clean energy goals for them to be able to differentiate when they're procuring capacity resources between clean resources and emitting resources. And having that ability to design their capacity procurement to meet their state policy on a longer-term basis is one of the key benefits of the FRR strategy.

Okay. And any sense on when we'll get kind of a more -- kind of full bill with more details proposed to get a better sense on just the details of a potential bill?

Yes. I think you should expect to see further discussion and public hearings about what the bill should look like. As you know there are a number of proposals that are alive in the legislature in Springfield and so there needs to be some discussion in public hearings of how the state's policy on all the issues that are pending will come together in a comprehensive approach. So I think over the course of the spring session those details will become more evident. As you know in most legislatures, it usually takes until closer to the end of the session for all the details to be worked out, but I think you'll start to see over the coming weeks and months more detail emerge.

Okay. And then a broader question just on -- I guess it's an ESG/nuclear carbon question. Just -- maybe for Chris, just how do you feel about your ability to get credit? It seems like there's a lot of focus on ESG and renewables and not necessarily as much focus on the benefits of nuclear and carbon reduction as you said 12% of the megawatt hours you produced for the country last year. Just how do you feel that you're going to be able to get credit either Republican or Democrat for the benefits of nuclear? Just how both sides are kind of looking at that right now including the FERC side?

Yes. I think over the last two to three years, you've seen a greater recognition of the benefit of nuclear as it's contributing to a cleaner environment low carbon and also other emitting gases. So as we work with stakeholders explaining electrification and the benefits of electrification and that electrification is coming from clean sources that are highly reliable like baseload nuclear, and there's been quite a few environmental organizations and government legislative folks that agree with that. The dialogue is going on, on how do we keep these assets so the states can make their goals and that's going to be a critical part going forward. We've shared numbers with you before that if we shut down a couple of nuclear units in a single state, we can totally destroy all the investments that were being made in the renewables and we're just going to go backwards with our carbon emission. So we have to do our job as -- not only as a company, but an industry and we're trying to do that. The Nuclear Energy Institute has done a very good job on their campaign to communicate that to greater and broader masses and we'll continue to do it ourselves and work through things like the legislation that may be enacted or policies that may be enacted in states. We've seen the ZEC and the recognition in New York. We saw the ZEC and the recognition in Illinois. We're going to have to go a little bit further to be able to save these plants and that's where we're talking about FRR. And it's also -- another part of it is, it's more than just environmental. The reliability they provide, the jobs they provide, the economic engine for the communities that they serve is very impactful. And to not have these assets or them to be replaced with carbon-based assets will just send the states not only financially, but environmentally backwards.

Thank you.

Thank you. Your next response is from Shar Pourreza from Guggenheim.

Hey, good morning guys.

Good morning.

Just focusing a little bit on the Genco. If we get to sort of the November veto session and find energy legislation gets pushed to 2021 and we assume that there will be a PJM auction in, let's say, December and January and another one roughly six months after that. Can you just walk us through how you'd be thinking about the auction participation and the timing of potential closures? And do you feel that the MOPR order has catalyzed the states to act on CJC?

We're not speculating right now on that. We surely hope for many complicated issues that the states are able to enact and given time to enact the policies that they desire that will allow these plants to still operate. I've said for the last four or five years on almost every earnings call that if we can't see half to financial stability for each one of these assets that we will have to retire them and we're not going to speculate today on which ones or when. But we've shut down Oyster Creek, gone into decommissioning with a decommissioning company. TMI is off. There was no path for financial stability. And as I've said in the past, we must watch the balance sheet and our debt commitments and the negative cash flow assets will only send the fleet backwards and our goals on strong investment-grade will allow us to maintain our commitments to operate plants safely and meet our financial commitments on retiring our debt. So, we'll work hard through this legislative session to convey the importance of it and we're not going to speculate until we have no longer have a path to profitability for the assets.

Got it. And then if let's just say Illinois does FRR, how are you thinking about maybe the potential impacts on sort of the rest of the RTO fleet like in Pennsylvania and Maryland, especially given obviously the IMM has been taken somewhat of a bearish tone on the impact?

Yeah. Shar, this is Kathleen. I can take that one. I mean, there are a number of estimates as you know out there about the impact of one, two, three, four, five states choosing the FRR option. We have not conducted an analysis of what that means for the rest of the pool so I'm not going to speculate on which ones of those analyses are accurate. But I will just say with respect to the market monitor, and the suggestion that the MOPR is going to have no impact on capacity clearing prices, it's -- and I note that that's been repeated by a number of the fossil companies, yeah, it's just it's a little bit concerning. I mean, it's exactly these state programs that they -- that were the reason that multi-litigation was brought by these companies. Recall when the first lawsuit was filed in New York, when New York adopted the ZEC program they said the point of the lawsuit was that ZEC programs were suppressing market prices by $15 billion over the course of that program's life. The whole purpose of MOPR was to raise capacity prices. Commissioner Glick estimated that he's going to raise capacity prices by $2.4 billion annually across the pool. Other independent analyses have gone there too. So it's just not credible for them to be now saying MOPR is going to have no impact.

Got it. That’s helpful. And congrats guys, its very solid result.

Thank you.

Your next response is from Joseph Gutowski [ph] from Bank of America. Please go ahead.

Hi, it’s Julien, can you hear me?

Yes.

Thank you guys for the time. Super quick. Let me come back to some of the numbers that we start with Greg earlier. Just in terms of the guidance I know you mentioned the AFUDC and the reconciliation of the CapEx and rate base. Can we talk about the earnings? Obviously, rate base unchanged; EPS guidance higher. Is that principally due to some of these changes in AFUDC that isn't formally reflected in that rate base and obviously is reflected in that CapEx? Or are there other changes? Obviously the cadence of the trajectory of the earnings in 2020 and 2021 onwards has shifted a little bit as well but just wanted to clarify that. And then also on ExGen, similar dynamic around what's causing the offset versus the open margin. I think you had a little bit of a quick brief commentary about basis potentially. Just want to elaborate quickly on that as well as maybe the tax piece for ExGen year-over-year.

Yes, Julien. Good morning, it's Joe. On your first question remember we're giving you guidance for the combined EU and HoldCo, so there's a couple of variables even though we're investing CapEx and rate bases are rising. When you look at it the interest rate – the interest expense at corporate is projected lower which drives EPS as one variable that's positive to the earnings. We are – when you look at these projects, right you could still see there is additional CapEx growth and then we've had some improvement in ROEs versus our prior plan as well based on some of the regulatory actions and performance. So there's a number of variables outside just the incremental CapEx that would drive the value. Your second question on the offsets at generation it's – when you look at the prices falling use 2021 as an example where we're less than 70% hedged. You see that you would have the open gross margin come down. However that's a price at a common trading point. When you look at the values associated back to where the generator busbars are for example those prices move every day as well and there were some offsets associated with that. So that got us down to flat.

Got it. Excellent. And then just to come back to the broader strategic points here. At what point in time do you need to make decisions here? It sounds like there's latitude through the course of this year. And then related to that are you expecting any kind of FRR developments ahead of these auctions themselves? Or would the outcome of the auction and the outcome of any ultimate resolution of how to run this auction prove to be a decision point for states outside of Illinois? I just want to understand the cadence of events given where we stand today. I know there's a lot of moving pieces and that could be a long question but I'll let you respond to as you peak that.

We are definitely responding to the MOPR in our commentary to FERC in PJM if they need to allow the states to enact whatever policy or legislation they are pursuing prior to running the auctions. There's adequate capacity in – within the system that we don't need to rush to secure it until the rules are clear. So it would be an unfortunate event if the auctions ran before the states were able to take action, which means you'd be looking at 2024, 2025, before you'd be able to enact and that's a long time with negative cash flows that many of the units would be facing at that point. So we want to work with every stakeholder we can within the states that we serve to help them enact the policies and explain what we can on the economics. If the bill, as we've seen it and draft towards the end of last year is enacted, it actually has a significant benefit to the consumer. It's not a bill increase as being communicated by some are understood by others. It actually as Kathleen pointed out, could cost as much as $2.6 billion to the PJM customers. And you take just Illinois alone, that's about 15% or a little over $400 million on an annual basis on an increase to those customers. So there's a customer benefit here. There's – as drafted or inputted previously there is a cap on the -- and what can be increased on both sides of the investment to support the renewables or the cost of the energy capacity in the system. So we need to be able to have the time -- or the states need to be able to have the time and there's discussion in multiple states right now that they want to look at something differently. And we hope that PJM respects the states' needs and allows them time to enact the policies that they desire.

Perfect

Thank you. Your last question come comes from the line of Michael Weinstein from Crédit Suisse.

Hi, Joe and Chris.

Hey, Mike.

Hey. Maybe you could explain a little bit why the hedging program is still -- is a little bit more behind ratable? And I guess you talked about not expecting a significant balance in power prices going forward. Just wondering what the -- what your thinking is.

Yes. I'll let Jim McHugh answer that.

Yeah. Hi, Michael, it's Jim. We have shifted our positioning in the markets through time. I think we -- at this time of year 18 months ago or even 24 months ago we were carrying a position behind ratable primarily in the baseload regions looking at the markets and where they were trading. What we've done is we've shifted some of that to different regions. For example one of the areas we've -- with a backward-dated curve in ERCOT for example. We see opportunities in different seasons in Texas with ORDC pricing being more relative for the future. So there's just we're picking and choosing our spots I would say and it's spread out across multiple regions. And it's just a smaller overall position but we're looking at where the opportunities are. And then not -- a little bit relative to your question I would just highlight too that the vast majority of our new business would not come from that type of optimization activity, but 70% to 75% would come from our load sales and customer-facing business in retail and wholesale. So we see a good strong pipeline for those activities. And you saw the win rates and renewal rates that Chris spoke to during the call which is another opportunity for us to continue to make our new business targets.

Right. Still pretty well-balanced. Hey, and on the capital program would it be fair to say that it's -- that you're being conservative on it given the uncertainty over PJM and CJM? Could the capital program actually be higher next year if we see some more resolution more certainty over that?

Michael, what I would say is our capital program reflects what we think is -- the projects we've identified as I said in my prepared remarks at this point in time. I think that you've seen the uptick in what we put in in 2019 versus what we're putting in in 2020 and we'll continue to challenge ourselves for the benefit of our customers. But right now I would tell you I think what we're showing you is a fair reflection of where we are and what we expect to do.

Michael, this is Calvin. I would also say when you look at 2019 we added $150 million additional capital all around gas main replacement and really adding to the overall customer experience. And as we've built out our plan whether it's transmission or distribution additional capital it's all around meeting those customers' expectations and our stakeholders' in terms of reliability and resiliency. So we feel we have a solid plan and can execute to it.

The only thing, I'd add to that is every quarter we look at the total bill of the customers and we're very sensitive to making sure the investment is prudent. It drives efficiency reliability and benefit to the customer and we also watch the affordability.

Got it. One last question. Hey, Calvin. So the PHI multiyear rate plan filing for this year are you guys -- would it be fair to say that the ROEs tick up from the low 9s could go up to the high 9s if you get that approved later on?

No. What we anticipate -- we do not first right now we expect the DC Commission to come out with a ruling in the fourth quarter of this year. And along the way we've adjusted our ask in terms of those multiyear plans. But we have a very solid understanding of what those ROEs are so I'm comfortable with where they are right now.

Got you. All right. Thank you very much.

Thank you and thank you for participating today. Before we end, I want to thank our employees for staying focused on safety and delivering another good year both operationally and financially. And with that, I'll close out the call. Thank you.

Thank you for joining us today. We hope you found this presentation informative. This concludes our presentation. You may now disconnect and have a good day.