Exelon Corp (EXC) — Q4 2018 Earnings Call Transcript

Thank you, Carol. Good morning everyone, and thank you for joining our fourth quarter 2018 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 are 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 on Exelon's website. The earnings release and other materials 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 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 measures. I will 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 year-end 2018 call. Before I begin, I would like to take a moment to thank our employees and those of other utilities who worked during the extremely cold weather to keep our communities safe and warm during the recent Polar Vortex. Our nuclear plants ran at nearly 100% during that week. The investment reliability we made in our system made a difference, and we had more than 500 crews out restoring service to customers in temperatures that reached a negative 23 degrees without including the wind chill factor. I’ll start on Slide 5. 2018 was a great year for Exelon and its operating companies. We executed on our strategy and delivered on our commitments to customers, communities, and shareholders. We are in a solid position to continue to bring value to our stakeholders in 2019. Our financial performance was strong. Full-year GAAP earnings were $2.07 per share and adjusted operating earnings were $3.12 per share, well ahead of the original guidance range. Joe will walk through the details later in the call. Last year we shared our goals for 2018 and are proud to report we met those commitments. Utility and generation operations had the best performance in multiple categories. I’ll provide those details in a few minutes. Last year, Exelon Utilities invested more than $5.5 billion in capital, primarily in infrastructure and technology, to provide a premier customer experience as well as improve reliability and resiliency, resulting in higher customer satisfaction scores. We were also effective on the regulatory front, completing 13 distribution and transmission cases in 2018. PHI was able to reach constructive settlements in all of its cases, including Pepco, and in Maryland – at Pepco in Maryland and D.C., for the first time since the 1980s. We shared the benefit of the tax reform with our 10 million customers, returning more than $675 million on an annual basis. Working with stakeholders to realize timely and fair regulatory outcomes helped us fund future investments in our system and continue to improve customer service. On the policy front, the Second and Seventh Circuit Court upheld the ZEC program in New York and Illinois. Although the plaintiffs have appealed to the Supreme Court, we expect these rulings to stand. New Jersey enacted the ZEC legislation, which will start this spring, and we are still focused on preserving nuclear plants in Pennsylvania. The Public Utility Commission of Texas adopted changes to the ORDC curve earlier this year. We are awaiting a decision from FERC on PJM’s fast start proposal and on PJM’s capacity market reform, and PJM is expected to file its reserve market reforms in the coming months. These policies, each in their own way, better compensate our zero-carbon nuclear fleet for the value it provides by addressing flaws in the existing energy and capacity markets. We are growing our dividend by 5% each year through 2020, with the Board raising the annual dividend to $1.45 per share on Monday. We are dedicated to corporate responsibility, and supporting the communities we serve is an important part of who we are and what we do. As part of our partnership with the UN HeForShe Initiative, we held inaugural STEM initiative leadership academies for teenagers in Chicago and Washington D.C. 95 girls participated in a week-long program designed to empower them through mentorship and creating opportunities to learn about STEM. We are expanding this program in 2019. 2018 was another record year for employee volunteerism and contributions. Our employees volunteered more than 240,000 hours last year, averaging seven hours per employee, and donated nearly $13 million. In addition, Exelon donated more than $51 million to charitable organizations throughout our footprint. We are committed to providing a diverse and inclusive environment for our 34,000 employees. We were named a Best Company for Diversity by Forbes, Black Enterprise Magazine, DiversityInc, and the Human Rights Campaign. We are also recognized for environmental stewardship. We received a score of A minus on both the CDP climate change and water surveys, the highest by any utility for each. We were named to the Dow Jones Sustainability Index for the 13th year in a row, and we had a series of commitments for 2018, and we delivered on those. The tasks for 2019 are beginning, and I will cover those at the end of the call. On Slide 6, we show the impact that Exelon's management model has had on our utility operations. Each of our utilities has materially improved their operation since the merger with Constellation or PHI. To put this chart in perspective, ComEd has improved its overall reliability by 60% since 2012; the hard work of our employees and the ability to share best practices across a large platform is paying off. In 2018, all four of our utilities ended up in the top quartile for safety or outage frequency performance, with ComEd in the top decile and PHI matching its best performance on record. Each utility achieved top quartile on CAIDI or outage duration, except for PECO, which missed the top quartile by only one minute. BGE and ComEd performed in the top decile. BGE and PECO had top decile performance in gas odor response for the sixth consecutive year, and PHI delivered top decile performance for the second year in a row. This level of reliability demonstrates that the investments we are making in our system are yielding positive results for our customers, but we still have more to do to confront climate change and our customer demands. Customer satisfaction was top quartile at at least three of the four utilities. ComEd, BGE, and PHI had the best performance on record in call center satisfaction. ComEd and PHI scored in the top decile for service level, and BGE and PHI had their best performance on record. Our utilities in the Mid-Atlantic operated extremely well in the face of record-breaking rainfall. D.C. saw more than 5.5 feet of rain, Baltimore 6 feet, and Philadelphia, 8 feet of rain during last year. Our safety metrics improved over the year as a result of the actions we are taking to correct course. We will continue to focus on improving our performance in this area. Turning to our competitive business on Slide 7. Our Generation fleet performed very well in 2018, providing an abundance of clean electricity that our country needs. In fact, Exelon generated one out of every nine clean megawatts in the United States, more than twice as many as any other generator. Our best-in-class nuclear fleet operated very well last year. Our capacity factor was 94.6%, exceeding 94% for the third year in a row and five out of the last six years. We generated the most nuclear power ever, at 159 million megawatt-hours, avoiding more than 82 million metric tons of greenhouse gas emissions in 2018. Our average outage duration was 21 days, a new Exelon record and 13 days better than the industry average. Exelon Power’s gas and hydro dispatch match 98.1%, and wind and solar captured 96.1%, or better than planned. In October, we acquired the Everett LNG import facility, and in December, we received a cost of service order from FERC for Mystic unit 8 and 9, which together will allow us to provide fuel security in the New England market through May of 2024. Our Mystic units are critical in keeping the lights on during the extreme cold temperatures we saw in January and February of last year. At Constellation, our C&I operating metrics remain strong: 78% customer renewal rates, an average customer duration of more than six years, and power contract terms of 24 months on average. We continue to see stable unit margins with our power customers and continue to focus on costs, which help us support operating margins. Constellation's strength lies in its durable relationship with its customers. That relationship is more than just power and gas but is built on Constellation’s unique ability to help our customers meet their energy needs, while also reaching their environmental and sustainability goals. Now I will turn it over to Joe.

Thank you, Chris, and good morning everyone. Today, I will cover our 2018 results, annual updates to our financial disclosures, and 2019 guidance. Starting with Slide number 8, we had another strong year. For the fourth quarter, we earned $0.16 per share on a GAAP basis, and $0.58 per share on a non-GAAP basis. For the full year, we earned $3.12 per share on a non-GAAP basis, which is at the midpoint of our revised full-year guidance of $3.05 to $3.20 per share and $0.07 above our original midpoint. Exelon Utilities outperformed our full-year plan due to higher distribution and transmission revenues with the early resolution of rate cases at Pepco and favorable weather. This was partially offset by the first quarter winter storms. ExGen performed in line with guidance. Realized gains at our nuclear decommissioning trust funds were offset by several factors unique to 2018, including higher allocated transmission costs. Overall, we delivered well on our financial commitments. Turning to Slide 9, it shows an overview of our 2018 rate case outcomes. Across our utilities, we received final orders in eight distribution cases. We reached settlements in six of the cases at PECO, Delmarva, Delaware on the electric and gas sides. Delmarva, Maryland, and Pepco Maryland and D.C., which is the first time we’ve had settlements at Pepco since the 1980s. Additionally, ComEd received 100% of its ask for the second year in a row, and finally in early January, the Maryland PSC approved 78% of the ask in BGE’s gas distribution case. Our focus on improving reliability and service levels is reflected in our rate case outcomes across our jurisdictions. On Slide 10, we compare the 2018 trailing 12 months blended transmission and distribution earned ROEs to 2017. Our constructive rate case results and the roll-off of the FAS 109 charge drove the improved earned returns this year. We are encouraged by PHI’s ongoing improvement, with earned ROEs improving by 70 to 140 basis points. Exelon Utilities earned a combined 9.7% ROE, up year-over-year. We remained focused on achieving our Utility earnings growth targets by improving the earned ROEs at PHI and sustaining strong performance at our other utilities. We expect that all our utilities will earn in a 9% to 10% range in 2019. On Slide 11, we roll over to our outlook for Utility CapEx and rate-based growth covering 2019 to 2022. Since the merger with PHI in 2016, we have invested more than $16 billion in our utility and plan to invest nearly $23 billion over the next four years. As Chris said, these investments are improving our system reliability and service experience for our Utility customers and preparing us for the future. As a reminder, the CapEx budgets we share with you reflect identified and approved projects. As we move through time, we generally find more investments due to additional system needs. When we compare our 2019 to 2021 CapEx outlook versus the same period last year, we plan to invest an additional $1.5 billion of CapEx for the benefit of our customers. This additional capital is spread across our utilities, with the biggest increase at our largest utility, ComEd. Since the PHI merger, we have added nearly $6 billion in rate base across the utilities. Over the next four years, we will grow our rate base 7.8% annually to $50.7 billion, adding $13.1 billion to rate base by 2022 or the equivalent of adding a utility almost the size of ComEd without paying a premium, issuing equity, or obtaining merger approvals. Rate base is growing slightly faster than the 7.4% growth we projected last year. As a reminder, the bulk of our rate base growth is covered under either formula rates or mechanisms like capital trackers. These support our ability to make additional investments to strengthen our system and have the opportunity 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. In the appendix, we provide a more detailed breakdown of the capital and rate base outlook for each utility starting on Slide 22. As you turn to Slide 12, we forecast strong Utility less holding company EPS growth of 6% to 8%, even from the elevated 2018 starting point, where we executed at the midpoint of our guidance range, exceeding the midpoint by $0.09 per share. Compared to last year, the outlook for 2019 to 2021 has improved with all bands increasing by $0.05 per share. The durability of our industry-leading earnings growth reflects a combination of strong rate base growth to support system needs for the more digital economy and growing environmental goals, along with concerted efforts to manage loss and focus on modest customer bill inflation. On Slide 13, we provide our gross margin updating our current hedging strategy at the Generation company. There is no change in total gross margin in 2019 from our last disclosure. Open gross margin increased by $50 million due to improving spark spreads at ERCOT, as well as higher prices at New York Zone A and NiHub, which were offset by our hedges. During the quarter, we executed $50 million in power new business. In 2020, open gross margin is up $150 million due to higher prices in most of our regions. Given our hedged position and execution of $100 million of new business, total gross margin increased by $50 million since last quarter. We are showing you 2021 for the first time today, which is down $250 million compared to 2020. The decline reflects lower power prices in PJM and ERCOT, plus lower capacity revenues in New England and PJM. Our Power and non-Power new business To Go numbers for 2021 are consistent with prior years. I should point out that these disclosures are based on 12/31 pricing and do not reflect any impacts from recently approved ORDC curve changes in Texas. We remain behind our ratable hedging program in all years. We ended the year 9% to 12% behind ratable in 2019 and 8% to 11% behind ratable in 2020, while we are $0.02 to $0.05 – 2% to 5% behind ratable in 2021. When considering cross-commodity hedges, our open market length is primarily concentrated in the Midwest in Texas. We are comfortable maintaining a more open position given our balance. Slide 14 shows our O&M and capital outlook at Generation. Our O&M forecast has been updated since our third-quarter call, primarily to reflect increased pension expense and the acquisition of the Everett Marine Terminal that serves our Mystic units. Like the others, the returns on our pension investments did not meet our planned returns, resulting in increased costs going forward. In total, these updates have added $75 million in O&M costs or about a 6% – or $0.06 per share drag in 2019 through 2021. However, even with these cost pressures, we expect to see a 1% annual decline in O&M over the next four years. Compared to our previous disclosure, our 2019 to 2021 CapEx is up modestly. In 2019, due to timing delays for our Midway plants and some retail customer-sited solar. In 2020, with modest increases in nuclear fuel costs related to the rising uranium prices where we had hedged with collars. We continue to look for ways to be more efficient in how we work and spend while maintaining the safety and reliability of our fleets. Slide 15 rolls over to ExGen’s available cash flow outlook for 2019 through 2022. We expect cumulative available cash flow to be $7.8 billion, which is $200 million higher than our previous four-year outlook. We will use the available cash flow from ExGen to primarily fund the increased utility investment, pay down debt, and cover a small portion of the dividend. We will invest approximately $600 million in growth capital, which is primarily customer-sited solar projects at Constellation and, as I mentioned, the completion in the West Medway plant in New England this quarter. As I mentioned earlier, we have identified additional capital investment at our utilities. As a result, we have significantly increased the amount of equity going into the utilities from ExGen by $700 million to a range of $4 billion to $4.4 billion. We will use between $300 million and $500 million of ExGen's free cash flow to fund the dividend not covered by the utilities. As utilities continue to grow, ExGen’s portion of the dividend decreased, even as the dividend itself grows. Finally, we have planned to retire between $2.2 billion and $2.8 billion of debt. With our strong credit metrics exceeding our internal targets, we felt it made more sense to shift cash plans for debt reductions to instead support the higher value-added and needed investments at our utilities. A big part of our value proposition is our unique ability to redeploy strong free cash flow from generation to fund utility growth without needing to go to the equity markets. This remains a differentiated advantage over our peers. Moving on to Slide 16, we remain committed to maintaining a strong balance sheet and our investment-grade credit ratings. We are comfortably ahead of our corporate targets for FFO to debt and well above the agency’s downgrade thresholds. As you are aware, Exelon and its operating companies are on credit watch positive at both S&P and Fitch. Looking at ExGen, we are well ahead of our debt-to-EBITDA target of three times in 2019. We expect to be at 2.4 times debt-to-EBITDA and 1.9 times debt-to-EBITDA on a recourse basis. We are actively following the PGE bankruptcy process. PGE is a sole off-taker of our Antelope Valley Solar Ranch or AVSR facility, which was funded by Exelon DOE loans and project financing at our non-recourse to Exelon. We, along with other owners of renewable generation under contract with BGE, recently received a FERC order affirming the Commission’s role to approve any modifications to existing PPAs, which BGE has challenged in the bankruptcy court. We will remain diligent in protecting the contractual value of AVSR and the role what assets like ours have in California’s clean energy future. From an earnings perspective, AVSR provides $0.03 per share to Exelon in operating earnings and is not significant to our credit metrics, given the non-recourse project nature. Finally, I will conclude with our 2019 earnings guidance on Slide 17. We are providing 2019 adjusted operating earnings guidance of $3 to $3.30 per share. Growth in earnings at the utilities is driven by the continued increase in rate base as we deploy capital for the benefit of our consumers, last year’s completed rate cases, and improvements in PHI’s ROEs. The decline in Generation earnings is a combination of normalized Illinois ZEC revenues, as we recognized $0.11 of 2017 Illinois ZEC revenues in the first quarter of 2018, and lower realized energy prices, which are partially offset by increased ZEC revenues in New Jersey and New York, as well as fewer planned nuclear outages. As you think about our 2019 earnings, the most notable new updates include the $0.05 per share increase to our Utility earnings band, the $0.02 to $0.03 of pension expense at ExGen due to worse than expected plant performance in 2018, as well as a roughly $0.03 per share drag from the recent Everett LNG facility acquisition, which represents a negative near-term impact, but is a positive value driver in the future with the Mystic cost-of-service contract beginning in 2022. These impacts are reflected in our O&M and other expense data in the appendix. We expect first-quarter operating earnings to be in a range of $0.80 to $0.90 per share. More details on the year-over-year drivers by operating company can be found in the appendix starting on Slide 61. I will now turn the call back to Chris for his closing comments.

Thanks, Joe. Turning to Slide 18, I want to discuss our key focus areas for 2019. We will continue to deliver operational excellence across our businesses, focusing on modernizing the grid and improving the customer experience at our utilities and running our generation fleets safely and reliably. We will meet or exceed our financial commitments, including achieving earnings within our guidance range and maintaining our investment-grade rating. At the Utilities, we will prudently and effectively deploy $5.3 billion of capital to benefit our customers, and we will file rate cases with the goal of achieving the 9% to 10% earned ROEs across Exelon Utility families by year end. Building upon successes in Delaware, D.C., Maryland, and Pennsylvania, we will advocate for policies in our state legislatures and commissions that will enable the utility of the future and help meet the needs of our customers. At Generation, a number of our nuclear plants are economically challenged due to market flaws that failed to value zero carbon nuclear energy for its environmental and grid resiliency benefits. As you know, we plan to retire TMI later this year, and as a reminder, all of the Dresden and portions of the Braidwood and Byron plants did not clear last year’s PJM auction. We will continue to engage with stakeholders on state policies while advocating broader market reforms at the Federal level. We will support PJM price formation changes like fast start and reserve market reforms with our states to implement the expected FERC order on PJM capacity reforms and preserve the authority of our states to advance their clean energy policies and continue our efforts to seek fair compensation for zero-emitting nuclear plants. We will continue to grow our dividend at 5% annually through 2020 and we will be a partner and ally in the communities we serve. Being a good corporate citizen for our customers, communities, and employees is key to who we are. Finally, turning to Slide 19, I will close on the value proposition that highlights our strategy and our commitment to shareholders. We have updated some of the numbers, but the proposition remains the same. We will continue to focus on growing our utilities, targeting a 7.8% growth rate base growth and a 6% to 8% earnings growth through 2022 rolling forward another year at above the Group trajectory. We continue to use free cash flow from ExGen to fund incremental equity needs of the utilities, pay down debt, and fund part of the growing dividend. We will continue to optimize the value of our GenCo business by seeking fair compensation for zero emitting generation fleet, selling assets where it makes sense to accelerate debt reduction plans, and maximizing value through the gen to load match strategy at Constellation. We will sustain strong investment-grade metrics, and we will grow the dividend annually by 5% through 2020. This strategy underpins this value proposition, which is effective in providing tangible benefits for our stakeholders. We are well positioned for growth to capture additional upside through needed policy and market reforms. We are very confident about the prospects for Exelon in 2019 and beyond, and we remain committed to optimizing the value of our business and earning your ongoing support at Exelon. With that operator, we can now open the call up to questions. Thank you.

Thanks. Good morning.

Hey, Greg.

On the Utility side of the business, obviously, pretty meaningful increase in capital opportunities across the entire set of companies. What’s the expected bill impact of the increase in spending? And as you look at the long-term and how much more sort of customer experience enhancing types of capital programs are you contemplating that are also affordable as we think about the opportunity, not just this year to execute on this new capital plan, but to continue to evolve your plan.

Good morning, Greg. It’s Anne Pramaggiore. I will start with your first question. When we put our capital plans together, LRPs each year we look at what the needs are in front of us. We challenge ourselves on O&M, and if you look at the O&M trajectory, it’s about a 0.3% increase over that four-year period. And we always look at affordability. We’ve got eight bills on the distribution rate side, and four of them – excuse me, three of them are roughly flat over that period that we’ve shown you. Four of them are trending less than inflation, and one of them will come in right at inflation, and that’s a combination of managing our O&M and also our energy efficiency programs, which are becoming a bigger part of our package here. So that’s basically what we are looking at in terms of affordability. The other question that we ask ourselves is, are there vulnerable groups inside that average that we look at in terms of billing and rates? We've been looking hard at the low-income side, and a lot of our initiatives include enhanced low-income programs along with it. So, that’s what we are looking at in terms of affordability, bills that are staying at or well below inflation and also looking at low income. In terms of looking forward, we think about investment in really three buckets. One is, reliability and resiliency, just the core basics and improving the material condition of our systems, the safety of our systems and, as the economy changes, as we’ve got more and more parts of the economy leaning on the electric system, how do you ensure that that’s reliable and resilient. The second area is really adapting to renewables and distributed generation. We’ve got a lot of flexibility and dynamism to add to the grid in order to deal with the kinds of changes we will see in terms of supply coming from many different places and many different actors, and demand being much more volatile. So, thinking about sensors on the system, artificial intelligence, distributed intelligence on the system that allow us to move operations on our assets from 16 to 18 cycles down to 6 to 8 cycles, that sort of thing. And then the last area is really thinking about electrification of transportation and what we need to do the system to – in expectation of that kind of shift. So those are the areas that we think about and look out. We watch our stakeholders very closely. We are starting to see legislation and policy come out of D.C. in December, a big piece of policy there. Pennsylvania came out with a clean energy and greenhouse gas reduction executive order in January. And so we watch what our stakeholders and our policymakers are telling us and how they are directing us.

Great. Thanks. And I’ll ask one more and then go to the back of the queue. Joe, I know that you were focused on the strong 2018 performance and the 2019 outlook. But I think it’s sort of déjà vu all over again with people just focused on the 2021 rollout of sort of the guidance pieces for ExGen. And once again we see, as we have in prior years, pretty significant backwardation and what the current state of players for the earnings outlook for ExGen based on the algebra you gave in the deck; it’s a $0.20 headwind on total gross margin, probably a $0.05 offset through prudent O&M. But still, much like we’ve seen in past updates that sort of two years forward, there looks today significant pressures on ExGen margin; what can you tell investors about how you feel about that as you think you roll into real-time over the next two years?

Hey, Greg. I appreciate the question. The first thing is, we are not in the business of giving EPS guidance beyond the prompt here, but having said that, I think as you’ve seen through time, our earnings have improved each year when you look at forward years, and by the time we get to those in the realized time period. When you look at the gross margin in 2021 versus 2020, there are two big drivers, very simply: as you mentioned, one is the backward-dated price curve and obviously, for us, the biggest impact is at NiHub and West Hub, and Jim could talk for a while about what we are doing. We are aggressively managing our portfolio. You see that we are behind our ratable plan. Actual spot prices last year were very, very strong. And then, secondly, Kathleen and her team are working very aggressively on policy reforms as well as PJM and others. So, I don’t think this story has been fully written there, and obviously we have a very large open position. The second piece of it is driven really by capacity, and some of it’s in New England, where the prices were lower year-over-year, and in PJM, where we had lower volumes clear year-over-year. But from my lens, I think the strength of our balance sheet affords us strategic and operational flexibility, and hedging is – less hedging is an example of that and through time, we’ve continued to improve our earnings and we will continue to work hard to do that in 2021.

Okay. Thank you guys.

Yes, just to add on. I mean, just to summarize that. You have got low or minimal liquidity in those years, 2021 and out – 2021 and out – you build the liquidity as you go through the prompt year into the next year, and you see the curves come up, and that’s been the pattern. Until we get these market reforms in, if it’s moving the plants in Illinois or some amount of the plants in Illinois to FRR, so we can get better capacity treatment that matches the state’s environmental needs, or if you look at price formation that’s working through, you look at reserve curves being revised, there is a lot of activity going. So, that’s why we are keeping more of an open position. We believe the market will strengthen.

Thank you, Chris.

Hi, good morning. Couple market structure questions.

Hi.

Hi, Chris. First of all in Pennsylvania, in terms of any chance to get to x. Could you give us an update there? And when would something have to happen for you to not have to close TMI?

So, the activities that Kathleen is leading with the other operating companies in Pennsylvania are promising. We have some strong support. It’s going to have to move this spring. We have to order a core by May, and we’ve let the stakeholders know that. So, if we can get this through in that period of time, we will be able to save the unit; short of that, we would be beyond the return at the end of May.

And is there any sense on what the targeted value of the ZEC is going to be in Pennsylvania?

I’ll take that one, Steve. This is Kathleen. I think that is subject to discussions that are ongoing among the lawmakers now. So we don’t have an estimate for you on how the program will look or how it will be priced. Those are discussions that are progressing, as Chris said, with some promising outlook.

Okay. And then, just, have to ask and probably hard to answer. Just, any better sense of where FERC may come out on the capacity market reforms? Is there any hinge from the changes at FERC and what happened with the New England auction and things like that where you might have a better idea?

I’ll take that one as well. I don’t think we have a better idea than we did on our last call of how they are going to come out. Clearly, there has been some delay in the schedule and I think that’s a function of the transition at FERC. The unfortunate death of the Chairman and integrating a new Commissioner, Commissioned with floor announcing her plans for retirement. So, while they have been able to get out a number of important orders, others have lagged, and the capacity market order among them. So, I think, as we are doing as you are doing, looking at the key leads and trying to make an estimate of where we think things will land, but we really have no signal yet from them as to when we will see their final decision in that docket.

Okay. Great. Thank you.

Thanks.

Hey, good morning. Can you hear me?

Yes. Hear you well. Good morning.

Excellent. Congratulations again. I wanted to follow-up a little bit more on the utilities side; can you walk through some of the more specific dynamics for the longer-dated 22 years? I mean, that’s just a pretty impressive jump at the end there. What exact dynamics? And also, what kind of earned ROEs are you embedding out there within the ranges? I mean, just perhaps once you get to 22, what are we going to be talking about with respect to the position of the utilities and also the rate case schedule, etc.?

Hi, Julien. It’s Anne Pramaggiore. Let me start by giving you a sense of what the investment patterns look like and what sort of – I think driving the trending that you are seeing, and then, between Joe and I, we’ll talk about the ROEs. So, we are – there are a couple of things that are happening there. One is the things that we have done in the last year. So we’ve gone through and accelerated our gas main replacement program as we move them from 30 years to 20 years. And so, you are seeing an acceleration of the gas investments. So, that’s one of the pieces that you are seeing trending there. One of the things that we are doing at PECO now is we are looking at some material conditions upgrades. But we are also doing a program to upgrade 4 KV feeders to 12 KV feeders in anticipation of more and more distributed generation coming on the system. You just can’t put that stuff on some of the feeders we’ve got in place right now. So that’s one of the areas we are looking at. And another program at PECO is really enhancing the underground replacement program. Again, underground cable program, again, some material condition work. I think you are pretty familiar with most of the PHI work we’ve got, D.C. plug that we are getting started, and we also are looking at some work potentially coming through off of the new legislation that was passed in December. At BGE, we’ve got some new EV investment that’s coming through after the order that just came out of the commission. So, some additional capital investment there. At ComEd, we are expanding the distribution automation program that we have in place. We are doing some more underground cable work and starting to invest across the utilities on security investments. We got about a program for security on our substations and cybersecurity; that’s about $900 million across the utilities over that period and some investment in some of our IT systems to get ready for, again, more flexible dynamic grids. So, those are some of the things that you are looking at that are driving that capital trend.

And just to jump on quickly in that, what’s driving that uptick from 21 to 22, though? What are the dynamics there, specifically? That’s a pretty big jump.

Julien, it’s Joe. Good morning. Specifically to your question, the jump from 21 to 22, Anne went through at each of the utilities the investments that we are making in the rate base. That compounding of those investments is one component of it. The second thing is we have a rate case in PECO in 2021 that has benefits in 2022, and then the third thing is there is additional spending under the formula rate at ComEd. So, those three things together get you to that outcome.

Excellent. All right. And then, turning back to the other side of the business real quickly. Can you talk a little bit about Everett and the contribution on the ExGen side? As you see that cost of service kick in 2022? And then also, how do you think about that asset as aligned, even at Mystic, if we are ultimately pulled out of the market, how do you think about the LNG asset itself contributing more structurally even?

Yes, I think, first of all, Julien, we acquired the Marine Terminal in Q4. As I mentioned in my prepared remarks, the acquisition is earnings negative from 2019 to 2021 driven by the increased O&M amounts, with about half of the $75 million increase in O&M or $0.03 a share being driven by Everett. The gross margin from the facility is included in our open gross margin calculation in our hedge disclosure and isn’t really material. What I would say is obviously the Mystic cost of service contract arrangement begins in 2022, and effectively the whole thing is bundled and it becomes accretive at that time. We committed, we had a capacity commitment prior to the last auction, and we were committed to honoring that commitment, and one way to do that was to acquire the facility. We were also very clear – to your question about how we would treat it in the future? We are very clear that with any type of asset that is economically viable, we are going to work for solutions and ways to try to make that asset viable. But I think you’ve seen with our financial discipline that when we’ve had to, we’ve taken the stance of making the necessary changes.

Excellent. Thank you very much. Congrats again.

Thanks.

Hi, guys. Thanks for taking my question.

Hi, Michael.

Hey, just to be clear on the ROEs at PHI, you are saying that for all of 2019 you will be at the 9% to 10% range, or is that like a run-rate at the end of the year?

That will be - by the end of the year, we will be in that range of 9% to 10%, and effectively that will be the trailing 12 months at that time.

Gotcha, okay. And then, on the ORDC, I understand that’s a dynamic issue and you are not going to provide a point number on that, but is one of the things we’ve tried to estimate it ourselves here around $25 million, perhaps of improvements for Exelon. I am just wondering if that’s in the right ballpark. Perhaps you can give some kind of hands as to what kind of impact you are thinking this might have on you?

Right. And to be clear – hi, it’s Jim McHugh, Michael. To be clear, we are talking about ERCOT?

Yes.

Okay, ERCOT ORDC; it is hard to put a pinpoint on a number on it. The way we are looking at it right now is, even before the ORDC change, we’ve been talking about the tighter reserve margins. You’ve seen the CDR reports, and we are in agreement with where they are coming in now. The reserve margins for this upcoming summer look like they are somewhere between 7% and 8%. So, I think with the ORDC changes, you are just making the likelihood that scarcity is going to play a bigger role in where the summer prices go. We’ve seen the forward market move up since the end of Q3 about $15 for summer on peak. Over the last month, it’s been more up and down and maybe a little higher, but more flattish. So, I think the market has been moving around its expectation of just how many scarcity hours there are going to be, which – to your point is hard to predict. Obviously, it depends on where coincident or high loads intersect with generation outages or variable wind. The one way to think about it perhaps is, a single hour at $9000 is a dollar on the CAL ATC price; it’s about $13 or $14 on the summer on peak price. So, I think what we are going to see the market do is really trade on a pretty volatile range as the assessment of how many scarcity hours there may or may not be can drive that summer $15 at a time just by adding an hour or two. So, putting an estimate on it right now is really just saying, how many hours we think there are going to be. But I think the way we like to think about it is, it increases the likelihood and sends the right price signal in times of tight market conditions.

And Michael, Jim is keeping a relatively significant open position and capability to extract value as we see volatility occur both in the forwards for the summer in 2019, as well as positioning ourselves well during that summer period.

Thank you very much for the help.

Hey, Joe and Chris.

Hey, Shar.

So, just real quick on the O&M profile change, post-2022, should we kind of assume this is the new normal? And then, as we are sort of thinking about some of the incremental revenue items that are not within plan, that could help mitigate or at least support some of this O&M pressures, especially as they are closer to 2021, can you provide some color there? I mean, I think you mentioned, Mystic is obviously one of them, and LNG is another one. Is there sort of anything else we should be thinking about from the revenue offset side?

Yes, the one thing I would say, and obviously, we haven’t given you a forecast of O&M, 2022 and beyond, but the one thing I would say, and I made the comment in my prepared remarks, the cost of service agreement at Mystic kicks in in the middle of 2022, and that would more than offset those costs to the O&M that we show in 2021 or so. So, effectively, it turns into an accretive outcome as I said in my prepared remarks.

And then, pension, as you know, the market for 2018 was not great on equities. December was pretty tough. We got some of that – a portion of that back in January. So, we will watch the pension. We will watch the pension investments, the interest rate and the return on the fund is what will drive the other half of what we saw the increase on this year. So, Everett and the pension. As far as the O&M discipline, we worked through the out years. We are far less than 1% all across the company, and you know that’s dealing with labor contracts, at 2.5% wage increases and other inflation forces. So, we do have a good plan on continuing to drive efficiency, hold the cost down and maintain that inflation rate as much lower at the generating company than utilities. But still, the utilities are less than 1%.

Got it. Got it. And then, as we are sort of thinking about the ExGen gross margin, I know we’ve talked about in the past maybe taking somewhat of a different approach when it comes to managing the portfolio, i.e. maybe operating some of the units more – from a portfolio portrait, so, like maybe FitzPatrick or Nine Mile, right? Are we sort of seeing any impact from this in your outlook, or is this sort of something you guys are still going through internally? And then, I guess, what I am asking is, also beyond FitzPatrick and Nine Mile, is there any sort of things we should be thinking about from taking a more holistic approach to the assets?

Yes, it’s Jim. I mean, if you are talking about New York, I think the way we are thinking about the portfolio in New York is, the capacity and the ZEC payment that we receive in New York has somewhat of an offsetting nature as energy prices rise. So we're in the – out in the outer years. We are looking to make sure we are hedging our portfolio along the lines of where we think that index is going to set as the ZEC price sets according to the structure, the index structure in the ZEC. So, really, there is not much of a shift in our strategy. I think what we’ve been doing is finding opportunities in the nearby years to on the energy side to understand if we think the market is slightly underpriced or slightly overpriced. And right now, recently, we’ve seen a pretty strong move in New York prices and we've been getting some good hedges off in CAL 2019 and CAL 2020 area to take advantage of those higher New York energy prices.

I guess, what I am asking is, have you seen any synergies for having these two assets so close to each other more from – less from a dispatch and hedging, but more from taking these systems, taking the units and operating as one. So there are clearly some synergies in there for owning these two assets so close to each other, right?

Yes, I didn’t get your question, first. I am sorry.

No, it’s okay.

So, the nuclear team is evaluating that. What they can do as far as management or what they can do as far as warehousing we have looked at combining security of plants. That’s a cost prohibitive item. But they are continuing to drive through that. There are definitely more synergies that we will be continuing to work on there as we complete the integration and the team has time to work through the regulatory process, and we have time to make the investments to make these consolidations.

Perfect. And those synergies are incremental to plants?

Right. They will be – if the ones aren’t included now, but there also are initiatives that are underway across the nuclear fleet. We are looking at how we centralize warehouses versus having overstock warehouses at each site. There are a lot of initiatives underway right now to take advantage as technology advances and built into the cost savings number. Now as an assumption that we centralize engineering since we have much more digital information and we can trend the equipment remotely versus having the engineers in the plant on site. So, there are things like that across the fleet that we are working on.

Perfect, Chris. That’s what I was trying to get at. Thanks so much.

Thanks.

Hey, Jonathan.

Couple of things. On the O&M at ExGen, just when you look behind the numbers that obviously have these new incremental pieces. Are you still going after the $200 million in additional cost savings?

Yes.

$100 million at services that you shared at EEI?

Yes, that’s still in the plan. We have line of sight on that and we will continue. Just to reemphasize, we are not going off plan on savings or efficiency. Two factors, pension underperformance in the market required us to higher state O&M and Everett, which reverses out and provides greater revenues in the 2022 timeframe. So, these are the things we have line of sight of; it’s not that the efficiency programs have been taken to pedal off of.

Yes, I just want to check, Chris, because you are showing it slightly differently. So, thank you for that.

Okay. We will get with you to clarify that.

And secondly, I see you removed the disclosures on New England and sensitivities, and we realized the Mystic contracts will be out in 2022. But is that just small enough to make it simpler or something else going on there?

There is really nothing else going on, Jon. We made a decision to collapse the New England region into Open Gross Margin because, with the changes to that facility and the inputs of gas and so on, and the associated contract change, the volume of our power generation output is falling. And then, you’ve got the gas acquisition of Everett that we’ve talked about, and that would all factor into that EREV calculation, and you would see changes that were quite variable quarter-to-quarter. Most importantly, the overall gross margin is very small compared to the total gross margin we provide you in the disclosure.

Perfect. Okay, thank you. And then, Chris, any update on sort of efforts to engage the legislature in Illinois coalition building, etc.? We did notice the bill that seems to be very renewables-only got floated this week, so I was just curious if you have any comments you’d like to share on that?

Yes, it’s very, very early in the legislative cycle. As you can imagine, we work within the coalitions within the state on what’s needed to continue to advance the environmental stakeholders, the customers, and sound investments. So, we have our folks communicating in those coalitions and communicating with the legislative folks. It’s premature to say what it looks like at the end of the day. But they are at the beginning of the sausage-making right now. And we will continue to have productive conversations.

In the FERC order, sort of a prerequisite for actually something happening this year?

Not on the utility side, and we are looking at other methods on the generation side. The FERC order definitely would be helpful to get out in a timely manner. But we don’t need it. You can go to use the current statute and achieve what we think we want to do.

Okay, I’ll leave it with that. Thank you, Chris.

Thanks.

Thanks so much. Hi, guys.

Hey, Praful. How are you?

Good. Thanks for this marathon session. So quickly on PJM, I guess, one last piece that was left was Fast Start. So just wanted to get any color or a view on timing of when that will come. We’ve been waiting for it for a while at this point.

Yes, this is Kathleen. And I think that’s within the scope of what I said earlier on the call. Unfortunately, there are – excuse me, a number of matters that are lagging, and that’s one of them. And I think the transitions at the commission have affected their ability to get big orders out. But just going back to the beginning of the Fast Start docket, recall this is something that the FERC asked PJM to file. So, we continue to feel confident about how it will turn out even if it’s going to take a little bit longer than we expected.

Gotcha. Fair enough. And then, Slide 15, that’s a very helpful capital allocation slide that you provide. In that, if we think about all of these benefits that are potentially coming on the ExGen side, right with Fast Start, ORDC, ZEC, all of them are incremental to the plan. How would we think about the allocation, given you’ve kind hit your utility investment targets, you are hitting your debt reduction targets, where does the incremental capital that potentially comes through go in your mind going forward?

Yes, the answer in my mind is very similar to what you saw with the plan – with the increase at the utilities. Anne talked about the way she is thinking about the three buckets of investment at our utilities and the benefits to our customers as it relates to those three buckets. We would continue to look at ways as we see projects that are beneficial for that. We would continue to look at investment there, and I think additionally, that incremental – those incremental dollars continue to provide us operating and strategic flexibility, and we’ve talked about what that’s worth in the sense of our hedging and the opportunity to be more aggressive with that and other things. So, we are going to continue to work hard to get those, and I think it gives us a lot of opportunities.

Gotcha. But share buyback is not one of those that’s in the plan right now, or contemplated in the plan?

Not contemplated in the plan, but all investments are bounced off to share buyback before they are made.

Gotcha. Perfect. Well, I appreciate it guys. Thank you so much.

Well, I want to thank everybody – all of you for participating today. I want to thank you, our employees for another good year, both operationally and financially. So, with that, we will close out the call and all have a good weekend.