艾索倫電力 (EXC) 2018 Q4 法說會逐字稿

Good morning. My name is Carol, and I will be your operator today. At this time, I would like to welcome everyone to the 2018 Fourth Quarter Exelon Earnings Call. (Operator Instructions)

At this time, I would like to turn the call over to Dan Eggers, Senior Vice President of Corporate Finance for Exelon.

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're joined by other members of Exelon's senior management team, who will be available to answer your questions following our prepared remarks. We issued our earnings release this morning, along with the presentation, both of which can be found in the Investor Relations section of Exelon's website.

The earnings release and other 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, forecast 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'd 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 the week. The investment on reliability made on our system made a difference, and we had more than 500 crews out restoring service to customers in temperatures that reached to negative 23 degrees without including the windchill 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 I'm proud to report we were able to meet those commitments. Utility and Generation operations had best performance in multiple categories. I'll get to 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 improved reliability and resiliency, which resulted 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 in Maryland and D.C. for the first time since 1980s. We shared the benefit of a 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 continued 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're still focused on preserving nuclear plants in Pennsylvania.

The Public Utility Commission of Texas adopted the 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 coming months. These policies, each in their own way, better compensate our zero carbon nuclear fleet with 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're dedicated to corporate responsibility and supporting the communities we serve and an important part of who we are and what we do.

As part of our partnership with the UN HeForShe initiative, we held an 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're expanding this program in 2019. And 2018 was another record year for employee volunteerism and contributions. Our employees volunteered more than 240,000 hours last year, on average, 7 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 were also recognized for our environmental stewardship. We received a score of A- 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 the 2018 we delivered on. The task is for 2019 is beginning as big. And I will cover those at the end of the call.

On Slide 6, we show the impact that Exelon management model has had on our Utility operations. Each of our utilities have materially improved their operations since the merger with Constellation or PHI. To put this chart in perspective, ComEd has improved its overall reliability 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 4 of our utilities ended up in top quartile for safety or outage frequency performance with ComEd at top decile and PHI matching its best performance on record. Each utility achieved top quartile on CAIDI or outage duration, except PECO, which missed top quartile by only 1 minute.

BGE and ComEd performed in 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 3 of the 4 utilities. ComEd, BGE and PHI had the best performance on record in call center satisfaction. ComEd and PHI scored in 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 result of the actions we're 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 abundance of clean electricity that our country needs. In fact, Exelon generated 1 out of every 9 clean megawatts in the United States, more than twice as many 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 in 5 out of the last 6 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 matched 98.1% and wind and solar captured 96.1% were 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 New England market through May of 2024. Our Mystic units were 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 remained strong: 78% customer renewal rates, average customer duration of more than 6 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 cost is helping 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'll 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 #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 8 distribution cases. We reached settlements in 6 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 70% of the ask in BGE's gas distribution case. Our focus on improving the reliability and service levels is reflected in our rate case outcomes across our jurisdictions.

On Slide 10, we compare the 2018 trailing 12-month 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 remain 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 forward our outlook for Utility CapEx and rate base growth covering 2019 to 2022. Since the merger with PHI in 2016, we have invested more than $16 billion in our utilities and plan to invest nearly $23 billion over the next 4 years. As Chris said, these investments are improving our system reliability, service experienced by 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 investment 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 4 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 continue to forecast strong Utility less holding company EPS growth of 6% to 8%, even for the elevated -- even from the elevated 2018 starting point, where we executed the midpoint of our guidance range -- we exceeded the midpoint of our guidance range by $0.09 per share. Compared to last year, the outlook for 2019 to '21 has improved with all bands increasing by $0.05 per share. The durability of our industry-leading earnings growth reflect a combination of strong rate base growth to support system needs for more digital economy and growing environmental goals, along with concerted efforts to manage cost and a focus on modest customer bill inflation.

On Slide 13, we provide our gross margin update and 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 $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 a $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 crisis 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 the 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're $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 and Texas. We are comfortable maintaining a more open position, given our balance sheet.

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 the increased pension expense and the acquisition of the Everett Marine Terminal that serves our Mystic needs. Like others, the returns on our pension investments did not meet our planned returns, resulting in increased cost going forward. In total, these updates have added $75 million in O&M cost 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 4 years.

Compared to our previous disclosure, our 2019 to 2021 CapEx is up modestly: in 2019, due to timing delays for our Medway plant 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 fleet.

Slide 15 rolls forward 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 4-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 of 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 for 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 the utilities continue to grow, ExGen's portion of the dividend decreases 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 planned 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 to our peers.

Moving on to Slide 16. We remain committed to maintaining a strong balance sheet and our investment-grade credit ratings. We're comfortably ahead of our corporate targets for FFO to debt and well above the agency downgrade thresholds. As you are aware, Exelon and its operating companies are on CreditWatch Positive at both S&P and Fitch. Looking at ExGen, we are well ahead of our debt-to-EBITDA target of 3x in 2019. We expect to be at 2.4x debt-to-EBITDA and 1.9x debt-to-EBITDA on a recourse basis.

We are actively following the PG&E bankruptcy process. PG&E is the sole offtaker of our Antelope Valley Solar Ranch or AVSR facilities, which was funded by Exelon's DOE loans and project financing that are nonrecourse to Exelon. We, along with other owners of renewable generation under contract with PG&E, recently received a FERC order affirming the commission's role to approve any modifications to existing PPAs, which PG&E has challenged in the bankruptcy court. We will remain diligent in protecting the contractual value of AVSR and the role that 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 nonrecourse project financing.

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 deployed capital for the benefit of our consumers, last year's completed rate case 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 stance; the $0.02 to $0.03 of pension expense at ExGen due to worse-than-expected planned 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 detail 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 fleet 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/or 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'll continue to grow our dividend at 5% annually through 2020. And we'll 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 proposal -- proposition remains the same. We'll continue to focus on growing our utilities, targeting a 7.8% 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 at the utilities, pay down debt and fund part of the growing dividend. We will continue to optimize value of our Genco business by seeking fair compensation for our zero-emitting generation fleet, selling assets where it make 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'll grow the dividend annually at 5% through 2020. The strategy underpins this value proposition is effective in providing tangible benefits for our stakeholders. We are well positioned for growth to capture additional upside, though neither policy or market reforms are required. 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 earn your ongoing support at Exelon.

With that, operator, we can now open the call up to questions. Thank you.

(Operator Instructions) Our first question this morning comes from Greg Gordon from Evercore ISI.

On the utilities side of the business, obviously a pretty meaningful increase in capital opportunities across the entire spread of companies. What's the expected bill impact of the increase in spending? And as you look at the long term, 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?

Greg, it's Anne Pramaggiore. I'll start with your first question. We -- when we put our capital plans together, our LRPs each year, we look at what the needs are in front of us. We challenge ourselves on O&M. And if you can look at the O&M trajectory, it's about 0.3% increase over that 4-year period. And we always look at affordability. And we've got 8 bills on the distribution rate side. And 4 of them -- 3 of them are roughly flat over that period that we've showed you, 4 of them are trending less than inflation and 1 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 and bigger part of our package here. So that's basically what we're 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? And so 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're 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 3 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 and 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 be able to deal with the kinds of changes that we'll 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 to the system in expectation of that kind of shift. So those are the areas that we think about and look at. We watch our stakeholders very closely. We're 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're directing us.

Okay. I'll ask one more and then go to the back of the queue. Joe, I know that you were focused on the strong '18 performance and the '19 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 play is for the earnings outlook for ExGen. Based on the algebra you gave in the deck, $0.20 headwind on total gross margin, probably a $0.05 to offset improved O&M but still much like we've seen in past updates that are sort of 2 years forward, there looked like, today, significant pressures on ExGen margin. What can you tell investors about how you feel about that as you think we roll into real time over the next 2 years?

Yes, Greg, I appreciate the question. The first thing is we're not in the business of giving EPS guidance beyond the prompt year. 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 '21 versus '20, there's -- the 2 big drivers very simply are, as you mentioned, one is the backwardated 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're doing. We're aggressively managing our portfolio. You see that we're behind our ratable plan. Actual spot prices last year obviously were very, very strong.

And then secondly, Kathleen and her team are working very aggressively on policy reforms as well as PJM and others. And so I don't think the 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 is in New England, where the prices were lower year-over-year, and in PJM, where we had lower volumes cleared 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'll continue to work hard to do that in '21.

So Greg, just to add on, I mean, just to summarize that. You have got low or minimal liquidity in those years, those '21 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 plants in Illinois to FRR, so we can get better capacity treatment that matches the state's environmental needs, or if you look at priced formation that's working through, you look at reserve curves being revised, there's a lot of activity going. So that's why we're keeping more of an open position. We believe the market will strengthen.

Our next question comes from Steve Fleshman from Wolfe Research.

A couple of market structure questions. First of all, in Pennsylvania, in terms of any chance to get ZECs, 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 will be beyond a return at the end of May.

And is there any sense on what the value -- 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, how it will be priced. Those are all 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 reform? Is there any hint on 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're going to come. Really there has been some delay in the schedule. And I think that's a function of the transition effort, the unfortunate death of the Chairman, integrating a new commissioner, Commissioner LaFleur announcing her plans for retirement. So while they haven't able to get out a number of important orders, others have lagged and the capacity market order is among them. So I think as -- we're doing as you're doing, looking at the tea leaves 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'll see their final decision in that docket.

Our next question comes from Julien Dumoulin-Smith from Bank of America.

Wanted to follow up a little bit more on the utility side. Can you walk through some of the more specific dynamics for the longer-dated '22 year? 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 rate case schedule, et cetera?

Julien, it's Anne Pramaggiore. Let me start by giving you a sense of what the investment patterns look like and what's sort of, I think, driving the trending that you're seeing. And then between Joe and I, we'll talk about the ROEs. So there's a couple of things that are happening there. One of the things that we've done in the last year is we've gone through and accelerated our gas main replacement programs. We've moved them from 30 years to 20 years. And so you're seeing an acceleration of the gas investments. So that's one of the pieces that you're seeing trending there. One of the things that we're doing at PECO now is we're looking at some material condition 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 the kind of some of the feeders we've got in place right now. So that's one of the areas we're looking at.

Another program at PECO is really enhancing the underground replacement program again -- underground cable program against a material condition where, I think, you're pretty familiar with most of the PHI work. We've got DC PLUG that we're 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're expanding the distribution automation program that we have in place. We're doing some more underground cable work and starting to invest across the utilities on security investments. We've 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 grid. So those are, I think, some of the things that you're looking at that's driving that capital trend.

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

Specifically to your question, the jump from '21 to '22, Anne went through each of the utilities, the investments that we're making in the rate base. That compounding of that investment is one component of it. The second thing is we have a rate case in PECO in '21 that has benefits in '22. And then the third thing is there's additional spending under the formula rate at ComEd. So those 3 things together gets 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, in '22? And then also how do you think about that asset line? Even if Mystic were ultimately to be pulled out of the market, how do you think about the LNG asset itself contributing kind of 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 '21, 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 would we treat it in the future, we're very clear that with any type of asset that isn't economically viable, we're 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 a stance of making the necessary change.

Our next question comes from Michael Weinstein from Crédit Suisse.

Just to be clear on the ROEs at PHI, you're saying that for all of 2019, you'll be at the 9% to 10% range? Or are you going to be -- 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%. Effectively, that will be the trailing 12-month at that time.

Got you, okay. And then on the ORDC, I understand it's a dynamic issue and you're not going to provide a point number on it. But is -- one of the things, we've tried to estimate it ourselves here at around $25 million perhaps of improvement for Exelon. I'm just wondering if that's in the right ballpark or if you can give some kind of hint as to where -- what kind of impact do you -- you're thinking this might have on you.

Right. And to be clear -- it's Jim McHugh, Michael. To be clear, we're talking about ERCOT?

Yes.

Okay, ERCOT ORDC. It is hard to put a pinpoint number on it. The way we're looking at it right now is even before the ORDC change, we've been talking about the tighter reserve margins. And you've seen the CDR reports. And we're in agreement with where they're coming in now that the reserve margins for this upcoming summer look like they are somewhere between 7% and 8%. So I think with the ORDC changes, you're just making that 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 over so, 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's going to be, which to your point is a hard thing to predict. Obviously, it depends on whether you have coincidental high loads with generation outages or variable wind. The one way to think about it perhaps is a single hour at $9,000 is $1 on the Cal ATC price. It's about $13 or $14 on the summer on peak price. So I think what we're going to see the market do is really trade in 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 2. So to put an estimate on it right now is really to say how many hours we think there's going to be. But I think the way we like to think about is it's increased 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 of '19 as well as we'll position ourselves well during that summer period.

Our next question comes from Shah Pourreza from Guggenheim Partners.

So just real quick on the O&M profile change, post '22, should we kind of assume this is the new normal? And then as we're sort of thinking about some of the incremental revenue items that's not within plan that could help mitigate or at least support some of this O&M pressure, especially as you get closer to 2021, can you provide some color there? I mean, I think you mentioned Mystic is obviously one of it 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 '22 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 the cost of the O&M that we show you in '21. So effectively, it turns into an accretive outcome as I said in my prepared remarks.

And the pension, as you know, the market for 2018 was not great on equities. December was pretty tough. We bought -- we've got some of that -- a portion of that back in January. So we'll watch the pension. We'll 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 O&M discipline, we work through the out-years. We're far less than 1% all across the company. And 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 cost down and maintain that inflation rate. It's much lower at the generating company than utilities but still the utilities are less than 1%.

Got it. And then just lastly, Chris, that's helpful. And then as we're 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 that sort of something you guys are still going through internally? And then I guess, what I'm 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 at the assets?

Yes, it's Jim. I mean, if you're talking about New York, I think the way we're thinking about the portfolio in New York is the capacity and -- the ZEC payment that we received in New York has somewhat of an offsetting nature as energy prices rise. So we're out in the outer years. So we're looking to make sure we hedge 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's not much of a shift in our strategy. I think what we've been doing is finding opportunities in the nearby year or 2 on the energy side to understand if we think the market's 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 the Cal '19 and '20 area to take advantage of those higher New York energy prices.

I guess, what I'm asking is have you seen any synergies for having these 2 assets so close to each, more from -- less from a dispatch and hedging but more from taking these systems, taking the units and operating them as one. So like clearly, there's some synergies in there for owning these 2 assets so close to each other, right?

Yes, I didn't get your question at first. Yes, so the nuclear team is evaluating that. What they can do as far as management, what they can do as far as warehousing, we have looked at combining security plans. That's a cost-prohibitive item. But they're continuing to drive through that. There's 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 have time to make the investments to make these consolidations.

Perfect. And those synergies are incremental to plan?

Right. They will be if the ones are included now. But there also are initiatives that are underway across the nuclear fleet. We're looking at how we centralize warehouses versus having overstocked warehouses at each site. There's just a lot of initiatives underway right now to take advantage as technology advances built into the cost savings number now is 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 the site. So there's things like that across the fleet that we're working on.

Our next question comes from Jonathan Arnold from Deutsche Bank.

Just a 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? It was $100 million at ExGen and $100 million at services that you shared at the EEI.

Yes, that's still in the plan. We have line of sight on that. We'll continue -- and just to reemphasize, we're not going off-plan on savings or efficiency. Two factors, pension, underperformance in the market required us to higher state O&M in Everett which reverses out and provides greater revenues in the 2022 time frame. So these are the things we have line of sight of. It's not that the efficiency programs have been taken the pedal off of.

Yes, I just wanted to check, Chris, because you were showing it slightly differently.

Okay, we'll get with you to clarify that.

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

No, there's really nothing else going on, Jonathan. 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, 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.

Okay. And then could -- I don't know if this is timely or not, but Chris, any update on sort of efforts to engage the legislature in Illinois, coalition building, et cetera? We did notice a bill that seemed 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 in sound investment. So we have our folks communicating in those coalitions and communicating with the legislative folks. Premature to say what it looks like at the end of the day. But they're at the beginning of the sausage-making right now. And we'll continue to have productive conversations.

Is a FERC order sort of a prerequisite for actually something happening this year?

Not on the utilities 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 can do -- want to do.

Our final question comes from Praful Mehta from Citigroup.

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

Yes, this is Kathleen. I think that's within the scope of what I said earlier on the call. Unfortunately, there are 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.

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

Yes. The answer in my mind, I think, is very similar to what you saw with the planned -- with the increase at the utilities. Anne talked about the way she's thinking about the 3 buckets of investment at our utilities and the benefits to our customers as it relates to those 3 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 then I think additionally, that increment -- those incremental dollars continue to provide us operating and strategic flexibility. And we've talked about what's that worth in the sense of our hedging and the opportunity to be more aggressive with that and other things. So we're going to continue to work hard to get those. And I think it gives us a lot of opportunity.

But share buyback is not one of those that's in the plan right now -- or contemplated in the plan?

No, it's not contemplated in the plan. But all investments are bounced off of share buyback before they're made.

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

This does conclude today's conference. You may now disconnect.