Exelon Corp (EXC) — Q1 2017 Earnings Call Transcript

Thank you, Josephine. Good morning, everyone, and thank you for joining our first quarter 2017 earnings conference call. Leading the call today are Chris Crane, Exelon's President and Chief Executive Officer, and Jack Thayer, 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 on the Investor Relations section of Exelon's website. The earnings release and other matters which we discuss during today's call contain forward-looking statements and estimates that are subject to various risks and uncertainties. Actual results could differ from our forward-looking statements based on factors and assumptions discussed in today's material and comments made during the 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 non-GAAP measures to the nearest equivalent GAAP measures. We have scheduled 45 minutes for today's call. I'll turn it now over to Chris Crane, Exelon's CEO.

Thanks, Dan, and good morning, and thank you all for joining us. We are off to a great start in 2017. In March, we marked our one year anniversary of the merger between Exelon and Pepco Holdings. Since they closed, PHI has successfully executed on merger commitments achieved synergy savings and made significant progress towards full integration. We also continue to work hard on the regulatory front. Since the beginning of the year PHI closed up the Delmarva Maryland rate case and reached a settlement for our Electric and Gas rate case in Delaware. We are now down to just a Pepco DC case from our first plant cycle of rate case filings. That said, our regulatory team has already started the second cycle of rate cases at Pepco Maryland and ACE’s plant. At ExGen we completed the acquisition of FitzPatrick power plant representing the 25th nuclear reactor where we have an ownership stake. We welcome the new employees to the Exelon family. We also announced the Exelon Generation renewable joint venture which is allowing us to recycle capital at a valuation meaningfully above the value implied for our ExGen at our current share price. The JV allows us to make even faster progress on our debt reduction goals without diminishing our commitment to renewable power. We continue to focus on the legal challenges to the zero emission credits or ZEC in New York and Illinois. We remain confident that our arguments will prevail. We’ll cover these points in more detail on the call, but I wanted to highlight what we have done while staying focused on the day-to-day operations. As shown on slide 5, on a GAAP basis we’ve earned a $1.07 versus $0.19 a share last year and on an operating basis we earned $0.65 versus $0.68 last year which puts us at the top of our $0.55 to $0.65 range and above consensus of $0.62. Moving to slide 6, our first quarter operational report was strong, our colored block charts highlight operating performance and customer satisfaction for the utilities. Legacy Exelon utilities remain almost entirely first quartile. PECO actually had its best customer satisfaction rating ever during the first quarter. BGE experienced the best ever CAIDI and SAIFI performance of all time. At PHI we are encouraged by the progress we are making and our customers are seeing the benefits. For example, by using a common Lockout-Tagout process, a procedure that establishes a zone of protection while restoring equipment, we were able to send over 400 employees and contractors from BGE, ComEd and PECO to support the storm restoration at Delmarva during winter storm Stella. As a result, Delmarva customers had their power restored two days sooner. Our thanks to everybody that helped accomplish that speedy recovery. The power of Exelon utilities platform has significant benefit to our customers. We continue to improve upon these metrics to meet reliability commitments we have made to provide better service to our customers. The nuclear team had a great quarter also. They completed three refueling outages and achieved a capacity factor of 94%. They also had the fastest refueling outage ever for Calvert Cliffs nuclear station 2, running 20 days. In the power business, we realized a renewable energy capture rate of nearly 96% and a power dispatch match over 99%. Our two new combined cycle gas turbine plants in Texas have both achieved their first firing and are now selling test power onto the grid. The state-of-the-art plants, which total nearly 2,200 megawatts, are on budget and on schedule for full commercial operations in the second quarter. We expect that they will be ready to participate in Texas this summer. At Constellation, our highly hedged portfolio in 2017 mitigates the impacts of weaker power prices and lower demand given the mild winter weather. Even in this recent low volatility environment our commercial and industrial business has been able to hold on to margins and keep customers renewable. On slide 7, we view 2016 as a great success in delivering our commitments and preserving some of our nuclear units by securing compensation for their clean energy attributes. For 2017, we are focused on executing on these gains we made last year and, more importantly, affirming the ZEC programs in the quarter. In New York, litigation is further along at this point. On March 29, the judge in New York Federal court heard all arguments on our motions to dismiss. We made strong arguments at this hearing and believe the outcome lies clearly on our side. We did ask when we expect a decision, but the judge has not given a specific timeline or deadline for issuing a FERC order. If we prevail on the motion to dismiss, we would expect the other side to appeal that decision. If the judge denies the motion to dismiss, we will move forward with the planned cases. As I have said previously, we are confident in the strength of our case. In Illinois, two groups of plaintiffs have challenged the ZEC in Federal Court and the cases are being overseen by one judge. The plaintiffs filed for a preliminary injunction on March 31; we intervened in that case on April 10 and filed motions to dismiss. The judge has held a preliminary injunction motion while he receives full briefing on the motion to dismiss. He will then determine whether there is a legal basis to proceed. That briefing will be completed by May 15 and the judge is scheduled to inform the parties of his intention on May 22. In the interim, we will start recognizing ZEC revenues in New York on April 1. In Illinois, the utilities have filed tariffs to commence collecting the ZEC payments on June 1. We don’t expect the actual ZEC procurement process in Illinois to conclude until later in the fall. We remain confident that the ZEC programs will be upheld in the courts to the benefit of the state, the communities, and these valuable resources. As we discussed last year in our carbon policy principles, we see state programs as an essential mechanism until we have a more cohesive federal policy that values clean baseload generation. The Energy Secretary’s recent directive to look at the importance of preserving baseload generation is early but encouraging. We appreciate the Secretary’s focus on promoting the needed market reforms to compensate these assets. We will support the DOE’s efforts as they move forward. Turning to the upcoming PJM auction, we understand the investment community is paying close attention, particularly after the disappointing MISO capacity auction results. Joe Nigro is available to answer more detailed questions if you have them, but let me share a few thoughts regarding the auction. To the positives, we are going to a 100% capacity performance for the first time which will put a higher performance burden on the entire fleet. We still think this should lead to more responsible bidding given the higher risk around non-performance. The CETL numbers, or the import capacity into ComEd and EMAAC LDAs, have tightened this year versus last year. The tightening can flag more constrained market conditions than last year in these zones which could help with separation. The negative, PJM load, has a demand forecast again for this auction and the approved seasonal aggregation will allow products that otherwise would not clear to participate in a 100% capacity performance environment. Finally, we have the risk of more uneconomical generation being built primarily in Pennsylvania and Ohio. These drivers are important, but we still expect clearing prices to come down to bidding behavior. You have seen us bid our assets in recent auctions to reflect the underlying economic needs of the individual plants, which in turn has led to some of our plants not clearing. You should expect us to bid our assets in the same responsible fashion in this upcoming auction. Now let me turn the call over to Jack to walk through the numbers.

Thank you, Chris, and good morning, everyone. My remarks today will cover our first quarter results, an overview of our current rate cases, an update on our gross margin disclosures, and a review of some of the events that occurred this quarter. Turning to slide 8, we had a strong quarter financially and operationally across the company. For the first quarter we delivered adjusted non-GAAP operating earnings of $0.65 per share, at the top of our guidance range of $0.55 to $0.65 per share. This compares to $0.68 per share for the first quarter of 2016. Exelon’s utilities delivered a combined $0.47 per share versus our plan, and utility results were impacted by unfavorable weather at PECO and PHI, which was more than offset by operation and maintenance timing across all the utilities. With 70% of our distribution rate base and decoupled jurisdictions, including ComEd starting in 2017, we experienced less volatility on our utility earnings from record warm weather in January and February than we would have without these programs. To help put this winter into context, this was the first time in 146 years when there was no snow on the ground in Chicago for both January and February. Looking across PJM, January and February were the warmest on record since data began being collected in 1950. Generation had a strong quarter relative to plan, earning $0.18 per share. We had good performance from our nuclear assets with better capacity factors than budgeted, and our Constellation team once again delivered strong results despite weak power prices and low volatility. Turning to slide 9. The $0.65 per share in the first quarter of this year was $0.03 per share lower than the first quarter of 2016. On the positive side, we benefitted from a full quarter of contribution from PHI relative to only 8 days last year, which added $0.09. The other utilities benefitted from rate relief and a higher rate base, partly offset at PECO with milder weather than last year. ExGen was down year-over-year primarily due to the effects of lower capacity prices and power price realization, as well as more planned refueling outages. Turning to slide 10, we are reaffirming our full-year guidance in the range of $2.50 to $2.80 per share. We expect to deliver operating earnings of $0.45 to $0.55 in the second quarter compared with $0.65 last year. Our second quarter results will include contributions from the FitzPatrick plants and the plants of the New York ZEC program that started on April 1. The Illinois ZEC legislation will go into effect on June 1, and plant procurement is expected to occur later this fall, with plants receiving contracts recognizing revenues retroactive to the June 1st effective date. Moving to slide 11. Our utilities continue to execute well, delivering strong earned returns in the quarter. Looking at the trailing 12-month booked ROEs, we saw nice improvements even relative to what we showed last quarter. At PHI we saw all of the utilities register gains, with some coming from revenues from the first cycle of rate cases starting to flow through to results. For the Legacy Exelon utilities, we continue to see strong earned ROEs over 10%, which led the consolidated Exelon’s utilities platform to nearly 10%, including PHI. We have plenty of work to do at the utilities and with our regulators to keep improving the product we are delivering to our customers, but we are happy with where the overall business is performing. We are obviously pleased with where our earned ROEs are trending, but I want to remind you that there will be variability in the earned ROEs for different utilities as we move forward. The timing of rate case implementation, weather comparability, and in-service dates will all impact results. We think the ability to earn strong ROEs and the plan we laid out at PHI to improve their ROEs will be the key to our future success. On slide 12, we have an update on our rate cases. Since our fourth quarter call, we have closed out the Delmarva Maryland case with a revenue increase of $38 million. We’ve also reached a unanimous settlement in our Delmarva Delaware Electric and gas cases for $31.5 million and $4.9 million respectively, and would expect commission approval during the second quarter. From our first cycle of planned rate cases, we are now down just to the Pepco DC case, but we expect the commission's decision later in July. We are proud of the hard work from our utilities and regulatory teams; these efforts are helping to get PHI’s revenues and earned book ROEs back on course while we simultaneously improve performance for our customers. As we have shared with you many times before, we’ve always viewed the turnaround in PHI earned ROEs as a rate case cycle process. To that end, we filed our second rate cases in ACE and Pepco Maryland this quarter. Combined with the outstanding cases from the first cycle that I previously mentioned, we are currently asking for $252 million in revenues which reflect recovery on multiple years of capital investments made to improve the reliability of the grid across these jurisdictions. We expect the final ruling on Pepco Maryland and ACE likely in Q4 2017 and the first quarter of 2018 respectively. We plan to file a second cycle of cases in most, if not all, of PHI’s jurisdictions in 2017, with all completed by the end of 2018, putting us in a position to earn between 9% and 10% ROEs in 2019. More details on the rate cases and the schedules can be found on slides 29 through 36 in the appendix. Slide 13 provides our gross margin update for ExGen. In 2017, total gross margin is flat compared to our last disclosure. During the quarter, we executed on $150 million of Power New Business and $50 million of Non-Power New Business. We are highly hedged for the rest of this year and have moved towards a generation-to-load matching strategy. Total gross margin decreased in the first quarter by $50 million in both 2018 and 2019 due to the impact of price changes on our order portfolio. We ended the quarter approximately 12% to 15% behind our ratable hedging program in 2018 and 8% to 11% behind ratable in 2019 when considering cross-commodity hedges. The majority of our length is concentrated in the Midwest to align with our view of spot market upside. Although we have increased our length in other regions as well, we are comfortable being more open when we look at market fundamentals. For example, oil and regional natural gas prices today are over $1 per MMbtu higher than they were last year, yet the forwards for power are only about $1 per megawatt higher. We do not believe that is a sustainable situation. To that point, I should note that power prices have risen since the start of the second quarter and have reversed about half of the first quarter price declines. On slide 14, we have highlighted some key recent events. On March 31, 2017, we executed on the creation of the Exelon Generation renewable joint venture, which will provide us with $400 million of pretax cash, including allocated debt, that puts the total JV enterprise value at approximately $1.7 billion, with the price implying an EV to EBITDA multiple over ten times and $1 per kilowatt value over $1,200. The JV consists of 1,296 megawatts of renewable generation capacity, which is about 35% of our renewable output and has an average contract life of 14 years. The JV structure provides the option to drop down contracted renewable assets from our portfolio in the future. The proceeds from these sales will be used to accelerate our deleveraging strategy. Also on March 31, we closed on the acquisition of the FitzPatrick nuclear station from Entergy, adding 838 megawatts of nuclear capacity to our portfolio. The FitzPatrick plant is part of the New York ZEC program and will receive ZEC payments for the next 12 years, which started on April 1. The plant is now operated by Exelon, and I am happy to report we had a clean cutover of FitzPatrick onto the Exelon platform. We are excited to have the FitzPatrick employees as part of the Exelon family. Our Exelon Generation Texas partnership, commonly referred to as EGTP, is a portfolio of 3,476 megawatts of gas generation in Texas. In 2014, we raised $675 million of non-recourse project finance for the assets, which currently has a balance of approximately $650 million. With a downturn in ERCOT power markets, these assets have been under pressure, with a debt rating at a discount from their base value for some time, and the plant is struggling to generate adequate cash flows. Due to the combination of challenged cash flows and our decision not to inject additional equity, we have come to terms with the lenders to pursue an orderly sale of the assets. The modest current earnings and all of the debt are still included in our financial outlook. However, we see the ultimate exit from these assets being accretive to our EPS and debt to EBITDA multiples starting in 2018. In light of this process, we are not in a position to expand further out in this transaction. Finally, during the quarter, we decided to discontinue the sales process of Mystic 8&9 assets. We were exploring a sale of these assets as a direct result of interest received from potential buyers. However, during the sales process, we encountered some issues with the fuel supply agreement that needed to be addressed. As we stated, we would only transact if we realized a price greater than our expected value. Continuing to own these assets does not impact our commitments for our debt-to-EBITDA target and debt reduction plans that we have already shared with you. Turning to slide 15, we remain committed to maintaining a strong balance sheet and our investment-grade credit rating. We are forecasting to be at 3.2 times net-to-EBITDA at ExGen by the end of 2017 and have a clear path to our long-term target of three times debt-to-EBITDA. On a recourse debt basis, we are already well ahead of our target, and taking into account the sale of EGTP, we would be on track overall. As we said before, we will look to dispose of the project once we have reached the three times target at ExGen. I’ll now turn the call back to Chris for his closing remarks.

Thanks, Jack. This brings us back to our value proposition shown on slide 16, which remains unchanged from our last earnings report, and we remain committed to these points. We continue to grow our utility rate base at 6.5% annually through 2020 and regulated EPS by 6% to 8% annually through 2020. We continue to use free cash flow generated at ExGen to fund the incremental equity needs of the utilities of $2.5 billion and pay down approximately $3 billion of debt over the next four years at ExGen and the Holding Company. We are focused on optimizing value for the ExGen business by seeking fair compensation for our carbon-free generation fleet, closing uneconomic plants, opportunistically selling assets where it makes sense to accelerate our debt reduction plan, and maximizing value through our load matching strategy. We continue to focus on sustaining strong investment-grade credit metrics and grow our dividend in a consistent and visible manner. Thank you for your interest, and we are now ready for questions.

Hello, good morning.

Good morning, Greg.

I noticed that when you gave the update on your cash flow projections for the balance of the year that it’s several hundred million dollars higher. I don’t remember exactly the slide number; it’s slide 18. It looks like the utilities are the major contributors to that with a modest decline and expected ExGen cash flow. Can you give us a little more color on that?

Sure, Greg. It is the utilities and some of its energy efficiency timing and some of it's just working capital, so we are about, I think, $200 million roughly higher than our expectation.

Okay. Is that sort of a – is that a sort of a permanent effect in terms of as I think about rolling the balance sheet forward, or is that more of a timing issue on when you are going to collect cash flows or spend capital?

The working capital is more of a timing issue; some of the energy efficiency is permanent.

Okay, can you give us the sense of what the split is there?

$100 million energy efficiency, sorry.

Okay. Thank you very much. Second question, and maybe it’s not something you are able to really engage with me on the call on, but one of the reasons why I think the stock has underperformed is because people are looking. Obviously you’ve had a little bit of softness in the 2018, 2019 curves. You already told us that’s bounced a little bit but if people are looking forward to the sort of 2020 role coming this fall and looking at the open theoretically open position and worrying about the capacity market print and thinking, while 2020 is going to be another down year. So I don’t know if you can comment on how that looks today and also how that dovetails with what you continue to do with vis-à-vis debt reduction at the – at ExGen. Because while the balance sheet looks like it’s in absolutely great shape today, if EBITDA keeps going south, there is sort of a bar keeps going up every year in terms of what you have to do with your cash flow to keep it at that level of leverage.

A couple of thoughts, Greg. One, I think it’s probably, given the liquidity in the market, premature to forecast our 2020 ExGen earnings. But one thing to keep in context, on a recourse basis by 2020 we’ll have $4 billion of debt. That is the most pristine balance sheet I think in this sector. So, from a strength perspective with the balance sheet and the ability to deal with the cyclicality of markets, I think we are well positioned. Our fundamental perspective would be that as liquidity returns to the market prices are going up across the board, and our hedging approach and the lengths that we are carrying relative to ratable is a master of that. So I think it’s meaningfully premature to be trading on 2020 in 2017.

Fair enough. Thank you, guys.

Good morning, guys.

Good morning.

Question on, you mentioned I think that you would be bidding the units in the PJM auction and the same I think you said responsible fashion. Can you give us any insight into what you see as different in the PJM auction set up with respect to, say, the MISO auction, which has the ZEC and Clinton, which obviously cleared at a low price in MISO? Is there anything we should be thinking about as we compare those two situations?

Good morning. It’s Joe Nigro. I’ll take that question and answer it. I’ll start by saying we have a longstanding practice of really not discussing our bidding strategy around the capacity auctions and where we think it will clear. I think there is one thing that we have to take into account; it’s the timing of the auctions. The MISO auction was for June of this year through May of next year, and the PJM auction obviously is much further out in the curve. When you think about the operations of the power plant and the fuel loaded in the plants, for example, that plant was going to continue to operate during that period. What I’d mostly say about QUAD cities in the bidding is that we are going to continue to remain responsible in how we bid our capacity reflecting the underlying economics of our plants, and that’s consistent with what we’ve done with past auctions. I think the major question mark with this option continues to be, as Chris mentioned, bidding behavior from the existing generation, as well as the discipline associated with new goals. As it relates to existing facilities, we continue to see economically challenged plants that have cleared previous auctions, and in addition to that, we see the economics of the new goals being marginal. In your last auction, we cleared about 27 gigawatts of base capacity, which was about 16% of the total procurement, and it remains to be seen how that 27 gigawatts would participate in this auction. But the big variables, as I mentioned, will continue to be the bidding of all the plants, and we will remain disciplined in that regard with all our facilities.

Thanks, Joe. Could you quantify or describe your exposure to Westinghouse as a supplier, particularly in the field business, and are there any concerns you have regarding the bankruptcy?

It’s something that we follow closely not only as a supplier but for the industry. We have reviewed our positions that we have commercially with them. We’re not concerned at this time, but we’ll continue to watch it closely for fabrication. We continue to see that as an ongoing entity in the services business. We continue to gain support to see that as an ongoing entity. None of us know how it’s going to shake out yet, but we have minimal exposure there.

So, can you give us sort of percentage of the fleet that service or supply fuel too perhaps?

I can get the number for you. We continue to competitively bid our reactor fuel suppliers between multiple suppliers, and we move that around based off of pricing, but we are not held hostage to a single entity on fuel fabrication.

All right. Thanks, Chris.

Yes. Hi, good morning. Just wanted to get your thoughts on this DOE review going on baseload generation, and maybe we also just have this FERC Conference and how these might tie into the state-by-state ZEC process that has occurred so far. We're trying to get a handle on how this is affecting generation. What could come out of DOE?

Yes. Let me start by discussing the Technical Conference that took place over the last few days. We identified three main areas of focus. The first is carbon pricing in the market and how FERC can support states interested in this initiative. The second area is related to the Mopar issues, specifically PJM Grid 2020, and the third involves energy reforms. All three topics are also connected to the discussions with the Secretaries. To elaborate on these points, there was a productive discussion regarding the limitations faced by states in implementing aggressive pricing strategies. There seems to be an increasing recognition that explicitly including carbon in the market would help address several challenges. Moving to the Mopar issue, this relates closely to state ZEC and REC programs. The New England proposal does not consider existing baseload generation, consistent with FERC’s precedent, and thus would not impact state programs. However, the PJM proposal does account for existing resources. Historically, we have not supported that proposal, but we acknowledge the important changes PJM has made that were discussed during the Technical Conference. We believe that the Mopar issue can divert attention from some critical work that FERC and PJM should prioritize. Unfortunately, there’s been a misconception suggesting that the challenges facing the IPP sector stem from ZEC and REC policies. In reality, many in our sector experienced a significant drop in equity value before ZEC even became a topic of discussion. Consequently, we don't believe the Mopar approach will effectively address what states are trying to achieve. Regarding MISO Zone 4, if we hadn’t resolved the Clinton matter in the auction or if we had been excluded by Mopar, prices in MISO could have skyrocketed from $1.50 to $5 per megawatt, which would not help resolve the downstate issues faced by ING and others. We concur with Chairman [Indiscernible], who questioned whether it makes sense to tackle these problems with additional Mopars for units receiving state environmental payments. New York ISO, MISO, and others seem to agree. While we disagree with the direction of the Mopar, I’d like to highlight something significant that emerged during the session. We cannot ignore the energy market design issues that undervalue baseload access anymore. We have frequently discussed the energy pricing challenges like negative pricing, resource over-commitment that drives uplift costs, and other technical issues. We haven't begun addressing these issues, which is causing states and our customers to miss out on resources that enhance resiliency, fuel diversity, and yield environmental benefits. At the conclusion of the Technical Conference, several participants, including California, urged that we set a deadline for finalizing the energy market reforms we’ve discussed. In our view, focusing on Mopars or other distractions before resolving energy market issues is like putting shoes on before pants; it just doesn’t make sense. Once we establish a new framework at FERC, we will prioritize these energy price reforms. Secretary Perry's memo provides an opportunity to tackle these unresolved areas, and we see potential in what was discussed in recent days and in the DOE's plans. We need to push these issues to completion.

Great. Thank you.

Good morning, everyone.

Good morning, Julien.

So, perhaps just to take it back to a couple of questions here, can we talk about the non-nuclear generation strategy? Specifically, I wanted to just follow up a little bit on the renewable sell down. First, what's the remaining EBITDA that could be eligible to be sold down if you want to qualify it that way? And then secondly, can you talk about whether or not you would eventually review the Mystic sales? Is this something about restructuring the fuel arrangement and a matter of time, or is it probably something that it’s going to be on the back burner for a little bit? And actually, I’ll throw the third question at the same time. With regards to Texas, it’s not very clear about this deal. The new Texas combined cycle assets are a separate discrete process to the extent which you ultimately divest and/or lose control of the ExGen Texas asset. Is that correct?

That last question is correct. And they’re totally separate and would be operated that way. They are not part of the divestiture process. On the first two questions, Jack.

So Julien, with the JV structure we have the opportunity to sell down further assets, the two that come to mind are our AVSR solar facility, which is in 2019, but that would not occur until 2019. We’ve got to get through the ITC recovery period for that. The second asset would be our Albany Green Energy facility, a wood-burning plant that has a contract with off-takers down in Georgia, that’s coming online this year, which could facilitate to drop down at the end of 2017, more likely 2018, and that’s all contemplated as part of the overall structure with the JV. With respect to the EBITDA, I’m not going to drill down into that, and with respect to the GDP given the sales process that we’re working with the lenders on, I just don’t think it’s pretty appropriate to disclose that. And then with respect to Mystic, again, I answer that.

Yes. Would you revisit Mystic, just to follow up on that one, or is that something that’s off the table for now?

We’re not going to talk a lot of details, but as we see an asset in that portfolio as a potential to create value and recycle capital, we’ll look at them. We will look at it on an annual basis. We have some work to do on that one site, but we’ll continue to evaluate it going forward.

Excellent. Just to understand the JV structure a bit further. On the renewable sale, why not sell down the whole entity over time as part of a wider deleveraging? Why opt for this kind of JV structure?

We’re still committed to clean energy. Being in the renewable business is still part of our strategy. At this point, maintaining operational control and the management of other facilities is important for us for our investment. We’re getting a fair return from those, but at this point we felt that the valuation we were getting in the market allowed us to recycle capital. So we’re not exiting the renewable business, and we continue to put about $125 million a year into solar at the commercial and industrial level for some of our national customers. We’ll continue to look at that portfolio on how to best manage those investments going forward.

Excellent. Thank you for your patience.

Hi. Good morning.

Hi, Steve.

I wanted to follow up on Steve’s question on the Department of Energy review. In terms of potential agencies or entities involved, in your mind, is that most likely to be FERC or federal legislation? I guess I'm struggling to figure out how the Department of Energy itself could provide economic support for baseload generation, whether nuclear, coal, or gas. What sort of entities would be most likely involved? I'm thinking if the states are providing value for environmental benefits from ZECs and the ISOs are providing the reliability benefits through capacity performance. What other elements are not being captured? Or what other tools are potential here?

Let me address that in a couple of parts. First, we believe the Department of Energy has a key role in shaping policy. Implementing that policy could, in some cases, require new legislation or involve regulatory changes at the Federal Energy Regulatory Commission concerning nuclear energy, which would engage the commission. In our view, the DOE will play a significant role in this policy discussion and influence the overall direction, even if not all objectives can be met. The DOE possesses certain tools, such as the Section 202(c) authority under the Federal Power Act, which allows it to secure necessary resources in the market. This power has been used infrequently—only twice in history—but discussions are ongoing about its potential use for baseload resources. Concerning environmental attribute payments, we are currently in a wait-and-see mode regarding the administration's stance on carbon, and generally speaking, we don't expect immediate developments from the department. The broader question is that while states are addressing environmental attributes and PJM is handling liability, there are still gaps. One significant gap is resiliency, which differs from reliability. Reliability assumes that essential pipeline infrastructure is intact, and PJM operates under that assumption, indicating some reliability impacts might be addressed. Resiliency, however, delves deeper into the effects of pipeline disruptions on natural gas generation and the necessity of factoring those scenarios into our models. Is there a quantifiable benefit to resiliency? Additionally, fuel diversity is currently undervalued in the market. As our market shifts increasingly toward natural gas, customers face long-term exposure to fuel price volatility. Although the short-term market dynamics are accounted for, Secretary Perry’s memo specifically acknowledges these issues in its second bullet point.

That’s very, very helpful to think through. Really appreciate that. And then just I wanted to revisit your nuclear operational capabilities and appetite for growing your ownership of nuclear plants. I mean, you acknowledge as a very strong nuclear owner and operator. Under what circumstances would you think about increasing ownership of merchant nuclear generation? What kind of criteria would you think about in terms of your appetite for doing so?

Yes. We have interest in increasing merchant exposure across any technology. What we would look at is only contracted secure revenue streams going forward; it’s pretty straightforward.

That makes sense. But that could include state-to-state sort of determinations, payments rather than classic PPAs, is that fair?

Yes. That is fair.

Okay. That’s all I had. Thank you.

Thanks. It’s time for one more question, operator.

Hey, guys. Good morning.

Good morning.

Just a real question on how you sort of think about the dividend and you’ve got utility that’d eventually to fund the dividend and cover the whole co-interest. What data points are you looking at where you could sort of think about revisiting the growth rate? Is it sort of clarity around PJM? Is clarity around ZECs? What sort of a data point should we be thinking about?

Yes. We updated our dividend policy about a year ago and gave you clarity through 2018 on annual 2.5% increase of the dividend. As we said at the time, we want to give you a longer-term view on dividend policy. What we need to do is execute on our rate cases and our efficiency at the utilities, and in costs and operations. 2017 is going to be a big year to continue to have that focus. As we come through 2018, we can have a dialogue with the board looking at whether we’re achieving or close to achieving the goal towards 2018, 2019, and where we are going financially in our focus and strategy. So this year is going to be big for performance. Next year is a year where we should be working very hard to give you a longer-term view.

Excellent. And then just lastly on retail, just maybe a little bit of an update. I mean, obviously there are some businesses that have changed hands. There’s some consolidation. There’s some obviously some trends, segment turning into a bit of an oligopoly. So I'm curious on just from a generality standpoint what you're seeing as far as the margin environment, and that would be helpful?

Good morning. It’s Joe Nigro. I’ll answer the last question first. Our retail margins for commercial and industrial origination still remain between that $2 to $4 we talked about, well within that range. The market hasn’t seen volatility and we continue to monitor that. The consolidation overall helps because there are fewer participants in the marketplace; we’ve acquired companies ourselves, and all the big entities have come into this space that haven’t been there historically. That’s been a positive. We have seen some aggressive bidding behavior by some smaller entities in certain sectors like government contracting and other things, but overall we continue to monitor this very closely, and we are comfortable with the projections we have in our margins remaining in that net $2 to $4 space.

Got it. Terrific. Thanks, guys.

Thanks, Pour.

Thank you. We appreciate your time and interest in Exelon. We really are off to a great start in 2017 and look forward to executing on the commitments we’ve made to you. So appreciate your time today, and I’ll end the call.