Exelon Corp (EXC) — Q1 2015 Earnings Call Transcript

Thank you, Britney. Good morning, everyone and thank you for joining our first quarter 2015 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 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 a presentation, each of which can be found in the Investor Relations section of Exelon’s website. The earnings release and other matters which we discuss during today’s call contain forward-looking statements and estimates that are subject to various risks and uncertainties. Actual results could differ from our forward-looking statements based on factors and assumptions discussed in today’s material, comments made during this call and in the Risk Factors section of the 10-K, which we filed in February as well as in the earnings release and the 10-Q which we expect to file later today. Please refer to the 10-K, today’s 8-K and 10-Q and Exelon’s other filings for a discussion of factors that may cause the 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 a reconciliation between non-GAAP measures to the nearest equivalent GAAP measures. We have scheduled 45 minutes for today’s call. I will now turn the call over to Chris Crane, Exelon’s CEO.

Thank you, Francis. And good morning everyone, thanks for joining the call. Before I go into the prepared remarks, I want to first start by addressing the situation in Baltimore. As a company with a significant presence in Baltimore, we are monitoring the unrest with great concern. As you know, Maryland’s Governor Larry Hogan has declared a state of emergency and Mayor Stephanie Rawlings-Blake has declared a city-wide curfew until next week. We join the rest of the business community in recognizing the issues that Baltimore is dealing with and needs to address so that this great city can heal itself and get back to economic growth for all. Moving on to the quarter, I am very pleased with our financial performance. We delivered earnings of $0.71 per share, surpassing our guidance range of $0.60 to $0.70. Jack is going to describe our performance in greater detail. I would like to focus my remarks on our priorities and how we are strategically pursuing value for customers and shareholders. We continue to operate in a challenging market environment, particularly on the generation side of our business, but our generation to load matching strategy continues to create value as seen in the first quarter hedge disclosure. Our advocacy efforts are focused on creating channels to capture value for the communities and customers we serve and for our shareholders. In our regulated business, we’re redefining the role of the utility of the future, in part by making needed infrastructure investments to modernize the grid. Over the next five years, our long-range plan has $16 billion of capital that will create approximately 6% compound annual growth rate with another potential $7 billion at PHI. Installing smart meter technology to enable customers to make informed choices about their energy consumption and promoting energy efficiency investments in innovation and resilient technologies at our utilities is a progressive and equitable approach across all customer types. You can see this reflected in the energy plan for Illinois' future build that we recently proposed through ComEd and Illinois. With these efforts, we’re bringing improvements to the lives of our customers in a way that creates value for the company. Our merchant business faced challenges primarily due to policies and market design shortcomings that have failed to fairly value the benefits of nuclear. As a result, we focused our advocacy efforts on ensuring that the reliable, environmental, and economical benefits of nuclear power are not taken for granted and that these plants are operated on a level playing field. In Illinois, we are working with state legislators on the low carbon portfolio standard that values each of these benefits. The bill was unanimously approved by the Senate Energy Panel and the Public Utilities Committee, and will now go to the Senate. We hope the same will happen in the House and that the bill will be approved within this legislative session. From a reliability perspective, we are pleased that FERC has granted the waiver to allow PJM to delay the capacity auction in order to further review PJM’s capacity performance proposal. It is clear from this action that FERC appreciates that the old rules are not sufficient to ensure reliability and that changes must be made. We look forward to a positive outcome. We continue to work through the process of finalizing a contract with RG&E for our Ginna facility. As these events play out, we’ve continued our best operating the plants and the utilities at high levels of efficiency, engineering our generation output through strong portfolio management while we expand our footprint and our profits in retail power and gas operations. As you can see, we are doing things on both sides of our business. We’re tapping into multiple channels to create upside and drive value for our customers and for our investors. This leads me to our proposed merger with PHI. As you know, we’ve obtained regulatory approval from FERC in Virginia and New Jersey, and we’ve reached a global settlement in Delaware that is pending Commission approval. That leaves Maryland and the District of Columbia. In Maryland, we’ve reached a partial settlement with several critical parties that has been presented to the Maryland Public Service Commission, and we expect a decision from them on May 15. In the District, we’ve completed our evidentiary hearings and we’re now filing briefs, and the Commission will commence its deliberations. We have said from the beginning that this merger and the commitments we have made clearly demonstrate this merger is in the public interest and should be approved by the regulatory commissions. While there is no guarantee that the Public Service Commission will approve the proposal and that there is no guarantee they will not impose conditions that would frustrate the transaction, we believe that the settlement and commitments we’ve made in the proceeding are more than sufficient to meet the statutory requirements for merger approval, and we look forward to orders approving the merger. We expect the merger to close late in the second quarter or in the third. In summary, we’re creating value today while actively pursuing public policy changes that recognize the benefits provided by our clean, reliable assets, and we’re working on all those fronts. I’ll now turn it over to Jack who will cover the financial performance for the quarter.

Thank you, Chris, and good morning everyone. We had a strong first quarter to start the year. My remarks will cover our financial results for the quarter, second quarter guidance range, and update our hedge disclosures and cash outlook. I’ll start off with slide 4. Starting with our first quarter results on slide 4, Exelon exceeded our guidance range and delivered earnings of $0.71 per share. At Exelon Generation, we once again realized the benefits of our generation to load matching strategy. Quarter after quarter, this strategy has paid dividends in a broad array of market conditions. During the first quarter, despite experiencing lower power prices than during the same period in 2014, we benefited from a lower cost to serve customers. We are realizing strong margins in our load business from contracts we executed last year after the Polar Vortex. In addition, our gas business performed above our expectations during the quarter due to favorable weather. While our nuclear plants performed better than they did at this time last year, we did have some nuclear outages that negatively impacted our quarterly earnings by approximately $0.04 relative to plan. That being said, we continue to push our plants to perform at our standard highest levels of performance. Our portfolio management team performed strongly and was able to more than offset these losses. On balance, Generation earned $0.35 per share during the quarter. Exelon’s utilities delivered combined earnings of $0.39 per share, an $0.08 increase over the first quarter of last year. Although we did not see a repeat of the Polar Vortex of 2014, with sustained extreme cold and wind, we faced a very cold winter with heating degree days 14% to 19% above normal in ComEd’s and PECO’s service territories. In fact, it was colder in Philadelphia this winter than the previous winter. Cold weather, a lack of severe storms, and increased distribution rates of BGE drove utility results this quarter. More detail on quarter over quarter driver of utilities can be found in the appendix on slide 16. For the second quarter, we are providing guidance of $0.45 per share to $0.55 per share. This compares with our realized earnings of $0.51 per share in the second quarter of 2014. We are reaffirming our full-year guidance of $2.25 to $2.55 per share. Since our last call, both PECO and ComEd have filed rate cases this year. On March 27, PECO filed an electric distribution rate case with the Pennsylvania Public Utility Commission requesting a $190 million revenue increase and a 10.95% return on equity. This is PECO’s first rate case filing since 2010 and the first time filing based on a fully projected future test year. In addition, if the PAPUC approves the new System 2020 plan, an additional $275 million will be spent during the next five years to install advanced equipment and reinforce the local electric system, making it more weather resistant and less vulnerable to storm damage. We expect the PAPUC to rule by the end of the year on the rate case and System 2020 plan with new rates going into effect in January 2016. On April 15, ComEd filed its annual formula rate filing with the Illinois Commerce Commission. ComEd requested a revenue decrease of $50 million. This reduction is a result of a continued focus on cost management and operational efficiencies that are being realized from a stronger, more reliable grid with fewer outages. EIMA and the smart grid investments are working. Since 2012, there have been more than 3.3 million avoided customer interruptions including 1.2 million in 2014, due largely to increased investments in distribution automation or digital smart switches that automatically route power around problem areas. Outages will save customers an estimated $175 million. More detail on each of these rate cases can be found in the appendix on slides 20 through 22. I’ll now turn to our first quarter gross margin update on slide 5. During the quarter, we saw a drop in natural gas prices, while power prices were steady and heat rates expanded further. The market is finally incorporating the change in the generation stack due to coal retirements as evidenced by the heat rates seen today. Approximately 10 gigawatts of coal plants that PJM have or will retire this year, with the majority of retirements occurring in April and May. We hedged close to a ratable amount during the quarter in both the Mid-Atlantic and Midwest regions. At the end of the quarter, for 2016 and 2017, we remain considerably behind ratable in the Midwest where we continue to see upside. Total gross margin is relatively unchanged across 2015 through 2017 from our fourth quarter disclosures. As I mentioned, Constellation had a good quarter and executed $200 million in power new business and $100 million in non-power new business. In addition, we’ve raised our power new business target by $100 million because we have line of sight for continued success in the balance of the year. This increase was offset by our nuclear outages resulting in a net $50 million improvement in 2015 total gross margin. Slide 6 provides an update on our cash flow expectations for this year, projected cash from operations of $6.7 billion. I’d like to point out that we have increased our CapEx projections at ComEd by $200 million. In finalizing the investment plan for 2015, ComEd identified an incremental opportunity to invest in infrastructure, including grid resiliency and security, storm hardening, and smart grid. These investments will continue to improve the reliability of ComEd's system. As a reminder, the appendix includes several schedules that will help you in your modeling efforts. Thank you. And we will now open the line for questions.

I have been hearing a lot of concerns about the Pepco acquisition and probably some of the Maryland comments, both out of the MEA and the Governor's office. Can you just kind of share your thoughts on how you guys addressed maybe the market power considerations or issues that are raised and how you guys moved past that to get this deal done?

There are some that have mentioned a loss of competition and as you all know, Pepco, Maryland, and BG&E do not compete. Each of these will be standalone in the future as they are now. Rate cases will be decided by the Public Utility Commission in Maryland. We work at the will of the Commission. The benefits that we show from bringing PHI into the Exelon Utilities with best practice sharing, being able to leverage procurement, and the commitments that we made we think meet the test of being in the best interest of the consumer. The Governor has not taken that position. The Governor has remained neutral since, as he said, he came into this late in the process. There were rumors that he was against it; that was clarified with the letter he sent to the Commission saying he has faith in the Commission that they will do the right thing, and he is neither for nor against; he is neutral on it. That’s the support that we have received from Montgomery County and Prince George's County is significant. Those were the major customer bases, representing the majority of Maryland customers, and we have strong support from both counties.

I guess just to play devil's advocate, but if Pepco were not to close, you guys have funded the equity component of that transaction well in advance. How would you guys use that capital if you ended up having to deploy it in a different direction?

Obviously, we don't anticipate that to happen. We anticipate a successful outcome here. To the extent that the terms of approval were onerous or we were rejected outright, we would look to cash settle the equity forward that we had issued, and we would look to utilize the capital raised from the convertibles to either fund growth in the business or return value to shareholders through other means.

I guess just one last question on the prioritization of capital. Obviously, the ERCOT CCGTs are out there, but there has been more conversation about the prospect of the LNG project that you guys are an early investor in, as well as stories about the UK office. Can you just clarify how you guys are prioritizing those capitals and maybe address any of the issues that might be around what we have been hearing in the media?

You can see based off our capital spend, our highest priority is in the regulated investments. We’re making, as I said, $16 billion of investment over the next five years with another potential $7 billion with Pepco as PHI comes in. So that is seen as a good solid investment needed for the infrastructure for the customers and to benefit the shareholders. The CCGTs in Texas are still a very good investment, with a very positive net present value. It continues to match our generation to load strategy as we continue to grow that load book in Texas in ERCOT. We said at the beginning that we are getting these plants at very good terms; they are under $700 per kilowatt on our brownfield site where we will have expense advantages by combining them with our existing facilities. The nature of those plants, the efficiency and flexibility of them, will allow for effective dispatch in that ERCOT market. This remains a positive investment. The LNG project is a good, strong option. We’re the fifth largest in handling merchant gas. We have core competencies around our gas portfolio, and continuing to grow the gas business is a logical move, we believe. However, the nature of that project is it would be a contracted long-term type arrangement that significantly de-risks it. If we are successful in obtaining contracts and permits, then we would make the investment to continue to develop our gas business. So that’s the strategy around utilities. The strategy around competitive electric and gas continues to be the primary focus. The story in the UK is not an equity story at all. Exelon Nuclear Partners has been invited into the bidding process to be the operator on a couple of projects potentially in the UK. We have a very small office that we rent month to month that those folks are working out of. Part of the process of doing that is understanding more about the UK market, so there has been some due diligence around that, but we have no plans right now on becoming an equity owner in the UK at this point. Those clarifications needed to be made.

Just a quick one on Illinois. Chris, you were saying you still think you are hopeful that you will get things across the finish line in the spring session. There has been talk that there might be slippage into the veto session, and obviously with the PJM auction delayed, the state might want to wait and see the outcome. What’s behind your conviction that we’re still on for the spring?

There is a hearing today that we’ll be continuing to address the issue. So it is being discussed and worked even with all of the other business that has been going on in Springfield around budgets. We got strong support, unanimous support out of the Senate Energy and Public Utilities Committee in March, and there are hearings on both the House and Senate this week to continue discussing it. So we remain positive, cautious but positive that we will be able to get something through in this session. If we don't, the likelihood is that we’re not going to get a bill, and we will have to address the long-term profitability of the units, and we will decide that as we see the legislative session end.

One other issue, Dan asked about the UK and you responded about the nuclear operator bidding process. There was also a story that you’d been linked to looking at an investment in a CCGT, which appears to be similar next-generation technology like you are working on in Texas. Any comments on that?

Yes, I learned about that when you did in the clippings. So there is market intelligence that’s going on at a lower level in the organization, but there are no plans to enter into equity positions at this point in the UK.

Your expected generation guidance for 2015 to 2017 in New England is 2x, 2x plus today versus what it was in the fourth quarter release. You haven't acquired any assets, so can you explain how you’ve been able to double your expected generation in that market, and the flow-through impact it is having on your expected gross margin which looks like it’s up marginally over the next two years, but then down marginally in 2017?

I will speak to that, and you are right to notice that our expected generation in New England in all years has increased appreciably. As such, the generation percentage hedge has declined with that increased output of generation. Very simply, we had disclosed in Q4 2013 that we had worked with a field supplier to restructure a contract that we had. Remember back then, our generation had dropped by about 50% in that quarter over quarter at that time. That contract restructuring has been terminated and it will be effective at the end of June this year, and the contract itself will revert back to its original terms and conditions. It has two impacts. One, you’re seeing the generation impact and the hedge percentage impact, and the notification of that termination was at the end of the first quarter this year. So really, you’re seeing it flow through on an immediate basis. The gross margin impact was very minimal across the horizon. As such, it’s just mechanically when you look at the hedge disclosure, the dollars of the termination of the contract restructuring, as well as the increased value of the generation output and the margin associated with that, are all flowing through the gross margin line and it is very minimal. So really it is a volume change that you see with a little dollar impact.

So then what’s the economic rationale for the termination if it’s more or less NPV neutral? Are these fuel contracts for gas plants that have optionality associated with price volatility? Are they baseload? Why would you terminate that contract if it wasn't increasing NPV appreciably?

I can't say too much due to the confidentiality of the nature of the agreement, but what I will say is the contract termination was the right of the supplier and they held that right. From our perspective, as I said, the economic impact was very muted. I can't speak to the supplier's perspective on why they terminated it, but it’s related to a long-term supply arrangement that we have.

I wanted to focus on the CP product if you could. First, with regards to your expectations on the future retirements, I’m curious, do you see this CP product as proposed, driving retirements as you go to a 100% CP market? Is that conceivable and what kind of units? And then subsequently, obviously with the Supreme Court waiting on the DR decision, how do you see that ultimately impacting the base of CP products or any eventual auction here? Does it appreciably impact CP, or is it more of an impact from the base auction?

I think to your first question around retirements, we don't see a material impact. The rationale is, first and foremost, obviously to improve the reliability of the system and to do that, you need a couple of ways to go about it. One is to harden the units themselves, which have a cost associated with it. The second thing is to ensure you have firm fuel on-site for these units, and there is a cost to do that. When you look at the economics of all that, we don't believe there will be a material impact on retirements. I want to say though, given this structure that’s been laid out, if it is implemented, I would expect that there would be an increased risk premium effectively in the marketplace given the fact that the penalty structure is changing rightly so to ensure reliability. But I don't think outright there will be material impact on the retirement side.

And on demand response?

I guess from a demand response perspective, there is a lot of flux around the rules, but looking at this auction, we would expect to see the demand response activity continue as it has. As rule changes evolve over time, if it changes, whether it becomes a retail product as opposed to a wholesale product, we will have to see how that pans out.

And then just turning to the renewables business, obviously the yieldco phenomenon continues to evolve. Have you given more thought about the degree to which this business is core as we’ve seen the market evolve?

Julien, with respect to the renewables part of our business?

Exactly, just not with creating a structure yourself, but ultimately whether you could garner better value in the public markets of late?

As you know, we have an extensive business both in solar as well as in wind renewables. How we have improved the returns in that business over the last number of years has been through the extensive use of project financing as a means of returning capital to the corporate coffers to reinvest either in the growth of the utilities or fund some of our other expansion efforts. For example, the peaker that we are building in New England or the combined cycles we are building in Texas. Certainly, we do watch and evaluate and consider the potential impact of value that a yieldco could have on our assets from the perspective of yieldcos as potential buyers of those assets or through the potential to create our own yieldco. We continue to evaluate that within our project financing efforts. We have retained that option to do that. I think one of the key elements though to a successful strategy around yieldcos is having a significant and visible pipeline of assets that you could drop down. We have a good amount of assets. We have elements like our LNG facility that if we decide to pursue that and we had a long-term off-take agreement that would provide attractive revenues that could fit into that type of structure. But at this point, we don't have any plans to pursue such a structure and continue to have a candidly wait-and-see approach.

I was wondering on the holdco side, how much more debt are you able to support after the Pepco acquisition closes now that you are more regulated?

Neel, as you know, we have significant debt issuance forthcoming that will be used to finance at the holding company, the PHI transaction that we would look to bring to market once we have visibility around a successful path in Maryland. We continue to evaluate the balance sheet capacity and the space that we have at that holding company. As you know, we’ve said we will utilize that holding company as a potential vehicle to finance regulated growth. I think an important element to this is the interplay between the growing earnings mix of our utilities business relative to our merchant exposure on how the rating agencies perceive us. To the extent that the rating agencies continue to evolve in their thinking around the risks embedded in our business and see us as a less risky credit, I would say that is the biggest mover of balance sheet capacity. Obviously, some elements around whether it’s capacity performance, the Illinois Clean Energy Legislation that would be additive to the company's cash flow and earnings would also be helpful to our ability to add further leverage to the holding company.

And then assuming Pepco closes, what’s the latest update as to when the dividend is fully funded by the regulated side?

We project that towards the latter part of the decade into the 2020 timeframe, but we will continue to evaluate that based off of rate case outcomes.

That’s specific to – from a free cash flow standpoint, the utilities being able to not just from a payout ratio standpoint, but from a free cash flow funding standpoint, Chris’ point on the latter part of the decade is when that cash would be available to potentially consider growing the dividend.

And then last on the Illinois legislation, if something isn't reached by the end of May, what are the options to maybe keep the process going through 2015? Or is it kind of done for the rest of the year if you don't have an outcome by May?

We expect the session, this is Bill Von Hoene, to conclude at the end of May. It conceivably could be extended if the budget impasse continues, but it’s unlikely that the energy legislation would be considered during that period of time. There is a six-day session, veto session in November and early December, which requires a supermajority on any votes that pass during that period of time. That would be the next time the legislature would convene after the conclusion of this regular session.

And a supermajority would require a 60% vote, is that correct?

That’s correct.

The point on that though is in May of 2014, we committed not to make any decisions based off of economics for a year. We’re coming to the end of that year, and we need to make decisions that start the planning process if we do not see a success path.

So I wanted to focus again on Illinois. It seems like you guys are bullish on energy prices in Illinois, and that’s why you are not hedging much of your portfolio. You are also bullish on capacity prices. At the recent PJM, you just had this spike in MISO capacity prices. So how does it all add up? Because on one hand, if capacity prices rise then you have less volatility on peak energy intervention which potentially lowers heat rates. So how does it reconcile with your outlook on heat rates?

I think what I would say is if we talk just about energy prices in Northern Illinois for a minute using prices as of the end of the quarter, we do still see heat rate expansion. We don't think the market has priced in all the upside, really driven by the back of the change in dispatch stack. If you think about two different timeframes like 2016, 2017, we probably see less upside than we do when you get out to the 2018, 2019 timeframe, probably to the tune of $1 to $2 accordingly. Just as importantly, we also have a view that we think natural gas is underpriced at this point which, in addition, would drive prices higher net-net because you would see a slight heat rate decline with the rise in natural gas. But net-net, it would be a positive outcome. And your point is right that from a hedging perspective, we continue to remain behind our ratable hedging plan in the Midwest to the tune of about 10% in 2016 and 2017 approximately just given those views.

And you also think that the carbon legislation in Illinois is not going to have any negative impact on forward energy prices in Illinois?

No, we don't.

Secondly, in ERCOT, you keep saying that you have a cost advantage for the new build, and you clearly do. But forward curves are showing on-peak spark spreads of $15 to $16. So the conclusion or your dedication to the project is driven by your outlook on where these spark spreads are going to go as opposed to what we’re seeing? Can you give us at least a sense of what kind of spark spreads you are assuming in your calculations when you think that the IRR of the projects is still interesting?

We continue to be comfortable with our investment in these plants because, as Chris said, the cost advantage, the technology advantage meaning the heat rate efficiencies and the responsiveness of the plants. We’ve seen spark spreads bounce around a lot in ERCOT. The lack of volatility recently has driven them down. Our long-term fundamental views are what I would say conservative, and we’re still confident in the investments, very confident actually.

Just sticking with the RSSA with Ginna, is there an update on the filing? And then just counter with the EDF put option, how should we think about an assumption that you may own the remaining portion of this plan? Is there an option that you can get an expanded RSSA contract if the timing works?

The RSSA contract was approved by FERC effective April 1, but with two adjustments being required in the contract which have been sent back, and a compliance filing will be made by Ginna to reflect that. Then there will be a process by which the contract itself will be evaluated and potentially settled through a FERC procedure. So that is going to go forward for probably the balance of the year based upon precedent in other circumstances, although the ability to collect on a cost-based rate is effective now. The put is exercisable by EDF January 1, 2016. We do not know and don't speculate as to what would happen in connection with that. Regarding the potential extension of the RSSA agreement, it’s predicated on the period of time that’s necessary for the New York system to find alternative ways to deliver the same reliability that Ginna currently is required to deliver. So we would not anticipate in the absence of the failure of the New York system to do so that there would be any basis for extension of the agreement.

And then just one lastly, sticking with the Illinois carbon portfolio, have you quantified what could potentially be available under the cap using, let's say, the 2014 rates? And then additionally, am I correct to assume that there is an opportunity to breach that cap if somehow credits are being constrained?

No, the cap is the same, essentially a 2% cap that applies to energy efficiency in RPS, and I think that’s been calculated by a number of folks. There is no provision by which the cap could be breached under the legislation as it’s currently proposed.

And then you haven't quantified what could be available under the program using pre-existing rates, right?

No, we have not.

A quick question on Illinois. With the Attorney General's office kind of weighing in on the MISO auction, is that entering the discussion in the Legislature?

There has been attention, not surprisingly, to the MISO auction in connection with the Legislative deliberations, and I think it’s relevant in the minds of a number of legislators. From our standpoint, however, it has virtually no impact on the health of our plants. The Clinton plant, which was a price taker in the auction and had sold in advance a significant portion of the power, benefited the auction results by only about $13 million. That’s far short of what would be necessary and doesn't obviate the need for the low carbon portfolio standard for that plant or elsewhere.

I wanted to clarify, I may have missed this, I think you were mentioning that, on the forward prices versus fundamental view, if I heard you right, you thought the Midwest was probably about $2 lower than what the fundamental view would be? I wanted to confirm that and what’s your thinking on mid-Atlantic for PJM right now, forward versus fundamental?

What I said was there are two components to our view. The first is just fundamentally we still expect to see heat rate expansion in Northern Illinois across the time horizon. If you look at calendar 2016, 2017, we would expect to see heat rate expansion, which is probably in that $1 to $2 range. Additionally, we see gas price upside which would also increase the power price beyond that upside. So those are two components to our view, and as such, we’re behind our ratable plan in 2016 and 2017 from a hedging perspective to the tune of approximately 10%. Importantly, there is some seasonality associated with that in our hedging profile, and within a given year, our hedging profile reflects that, meaning we see time buckets that are more valuable relative to the market than others.

One other thing, on the retail side, a quick update on the competitive environment and the $2 to $4 margin that we've historically been benchmarking, just to give us a sense of where we are as new contracts are rolling in?

I think in general, our load business has done very well, whether we’re talking about our retail book of business on the commercial and industrial side, or our polar procurement business on the wholesale side. After the Polar Vortex last year, we saw that folks may be pricing the risk more prudently from our perspective as it relates to managing a retail contract. That’s one element of it. Then from the margin perspective, using that $2 to $4 benchmark that you laid out there, we’re well in line in the range of that $2 to $4, whereas we were sitting here a year and a half ago struggling to be even at the low end of that range. So we’ve seen improvement across the board, both from a risk pricing perspective and a margin improvement perspective in our load business from both wholesale and retail.

This is a bit of a follow-up to that last question, but how long do you expect this magnitude of the load matching benefit that you got in this quarter to extend? Can we think about this extending through the full year and beyond, or was there something in the quarter that gave you even more benefit on the load matching side relative to what we could see later in the year?

I think there's a couple of answers to that question. The most important one is we’re seeing the changeover in the generation stack that we expected to see with retirements and low gas prices. You’ve seen the heat rate expansion that we have been discussing for some time. I think in addition to that, I think that going forward, we should expect to see increased volatility and both upside and downside volatility. I think that has an impact on load following contracts because you need to make sure that they are priced accordingly. So we have got the benefit of what I would call lower load serving cost in the first quarter; they’ve come down on a mark-to-market basis for the balance of the year. Nevertheless, our expectation is, given that market volatility, we would expect to see that it would pass through to continuing appropriate risk premiums in our load serving business and appropriate margins.

I just want to circle back a little bit on PJM. We keep seeing a lot of announcements or people attempting to get new combined cycles built. We’ve obviously had a lot to clear over the last few years, gas base is still pretty low meaning it’s still pretty wide in parts of PJM relative to where Henry Hub is or even where TETCO is. Just curious your kind of multi-year thoughts about whether lots of plants actually do get built, meaning or do a lot just kind of disappear by the wayside? What does this mean not only for – your view of are we kind of at new build economics in PJM? Does the concept of building merchant combined cycle in PJM make sense to you here? Just kind of broader thinking about gas plant economics in that market.

There are a couple of questions there. Let me try to pick them off one by one. The first relates to the turnover of the generation stack. I think it’s clear that we’re going to see retirements of generation assets. In our fundamental modeling, we have an add back of an appreciable number of gas-fired generators in PJM, with most of them on the eastern side of PJM because that is where the economics are more favorable than toward a territory like NiHub for example. You are talking about a long-term investment asset with a combined cycle plant build and you are looking at a market with spark spreads that are a much shorter dated time horizon. In PJM, unlike some of the other markets, the capacity price comes into play and is part of the equation. Clearly, we don't see new build economics working on the western side of PJM. On the eastern side of PJM, it’s a much more marginal exercise. That being said, we don't think the long-term view in PJM is as robust as folks may think. I think that if you continue to look at health and what is clear, the PJM market fundamentals are overly reliant on gas and driven from our perspective by inexpensive gas prices, more than anything else. In the Midwest, we remain cautious on long-term build out economically as well.

One real quick follow-up if you don't mind. You all talked a little bit about what the resolution on nuclear fuel means. Can you talk about what that means for fuel costs on a per megawatt hour basis for a typical nuclear plant? Like how material is the change on a dollar per megawatt hour? Are we talking $0.05 or $0.50, just trying to get my arms around it.

You’re talking about the DOE fee?

Yes, please.

It's a little less than $1 per megawatt.

Got it, $1 per megawatt hour, so something that may have been 750-ish is now well below 7?

Thank you, Britney. This concludes our first quarter call. Thank you everyone for joining us this morning.