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Exelon Corporation (NYSE:EXC)

Sanford C. Bernstein Strategic Decisions Conference Call

May 29, 2014 02:00 PM ET

Executives

Chris Crane - President and CEO

Analysts

Hugh Wynne - Sanford Bernstein

Hugh Wynne - Sanford Bernstein

Good afternoon. Thank you all very much for coming today. It’s my pleasure to introduce Chris Crane, President and Chief Executive Officer of Exelon. Prior to Exelon's merger with Constellation in 2012, Mr. Crane was President and Chief Operating Officer of Exelon. And his [backrun] is on the power side of the business. Chris was became President of Exelon Generation in 2008 and became Chief Nuclear Officer in 2004. Including his 15 years at Exelon, Mr. Crane has accumulated over his career more than 30 years in the Nuclear Power business having worked with nuclear power plants across the country including Browns Ferry, Comanche Peak and Palo Verde which is the nation's largest.

So, today we are going to start off with a brief presentation by Mr. Crane followed by a fire side chat and questions. We have a lot of ground to cover. So I encourage you if you have very important specific issues you'd like us to address write on down on your cards now, we'll have somebody pick them up after the presentation and that’s certainly preclude as we will be taking further questions later. Chris come on in.

Chris Crane

Thanks Hugh. Thank you everybody for coming. I'll give you the look forward statement, give you a little bit of an overview of Exelon first and then go into some of the current themes or trends that we're seeing in the marketplace. What is referred to as a competitive integrated electric and gas supplier, Exelon Generation is made up of two business segments, the power generation segment in our retail sales organization. We have as you see over 35 gigawatts of capacity a significant footprint on the nuclear side. We are the largest nuclear operator in the country with responsibility over 24 assets, and we are the third largest in the world.

We have a significant gas generation, natural gas generation and we continue to optimize as the market changes and we have been growing a renewable business wind and solar over the last five or six years. So our generation portfolio is contained within all competitive markets.

On a constellation side, constellation came in as part of Exelon a few years back as Hugh mentioned. It’s the leading competitive energy provider. We have over a million customers on the competitive side as large part of that is our commercial from the sales perspective as commercial industrial, we also have a retail division that handles supplying at the residential level.

The portfolio allows, the portfolio generation assets allows our portfolio management organization in our Baltimore operations at constellation to really optimize and we are uniquely positioned to be able to take whether commodity cycles and different weather fronts going forward.

On the right hand side, you will see the Exelon utilities, currently as ComEd, PECO and BGE. We’re one of the largest electric and gas suppliers in the country. Those three utilities are primary urban based Baltimore, Philadelphia and Chicago as there is a significant investment we are making in our utility business over the next five years $15 billion of capital spend on that side that would not only provide good returns in the future for shareholders but also improve reliability and the customer experience going forward.

What we have seen if you follow our stock at all, there has been a marked improvement since the 1st of the year from what we have seen in the last couple of years. Previously, last two years, recent, there has been a lack of volatility in the market. There hasn’t been any significant weather events and it was driving most of the consumers to buy on the spot market. But as you can see from this very busy scatter shot 2013, 2012, you are on a much lower side on pricing. If you look at 2014 and this NiHub is -- we are great on acronyms in this industry but that’s the Northern Illinois region of PJM which is the regional transmission operator. You can see a whole lot of volatility that’s come into the market.

On the right hand side you can see what’s happened to the forward strip on the reaction of the volatility in the spot market. We think that the behavior changed during the polar vortex, we think it now is sustainable. We have been modeling this increase over the last couple of years and it was pushed faster and on to the forward based off of what we saw during this winter.

Portfolio value and positioning, we have some sensitivities on the bottom. You can see what happens to our gross margins, plus $5 a megawatt hour, minus $5 a megawatt hour. But since our last disclosure on March 30th we've seen our net hedge increases by 430 go up by $350 million in ‘15 and $600 million in ‘16. There has been some tempering on those prices may be about 50 million to 100 million up respectively in both years but they're still very positive.

Our hedging strategy has been as we've announced it, somewhat more opportunistic, we still stay within this what we call a ratable hedging strategy. We try to sell a third of our product through on the forward year. So as we come into a prompt year January 1st, we’re about 90% sold forward. And so you drive that through the forward three years and you would see a third, third, third a hedgeable strategy.

We're on that strategy or actually slightly ahead in a zone in PJM called West Hub. We see that 2015 prices are fairly priced, we see upside in ‘16 and beyond. But in NiHub, as I referenced earlier on that previous side, Northern Illinois, we still see some upside. So instead of putting hard sales on, we're still using hedges with gas where about 10% of our sales in 2015 are on gas hedges right now. So that will protect any downside, but also allow us to get the upside.

Capacity markets, we earned money on our plans from two different revenue streams, one is the energy that I just showed you on the forward price strip; the other is capacity, having units available to meet the demand is on auction process to ensure that that’s run through the different regional transmission operating groups. You can see the results between 2016, 2017 over to 2018 New England’s auction cleared this last auction cleared at a much higher level than we’ve seen. I think it’s a record high for that and we do believe that that will be sustainable for few years until more infrastructure either gas pipelines or transmission lines coming to the New England zone. PJM the results were announced last Friday on its most recent auction, the prices doubled. In that there is a lot around that. I am sure we’ll get into the question answer on our bidding strategy so I will forgo use questions on that. But we’ve seen much, we’ve seen an improvement in bidding behavior overall including ours. We’ve seen reduction in demand response a limit of imports coming into the zone all of that has driven to a much better price across the RTO which is the terminology used for those market areas that don’t breakout or have other constraints to drive prices up.

So going forward on top of these more positive results with the auction. We’re still working on different rules and different segments of the market. DR refers to demand response. Demand response has been considered just like generation in the capacity market. So people are compensated at peak periods during the demand period to turn off their load and they get compensation for that. So it’s looked at as a generator. There has been some interesting rulings that have come out on the courts on demand response in that market we think has been turned on as ear for right now and we will have to see how that comes out, but we expect it will be upside for true iron in the ground generators.

There is an issue with speculation in the capacity market where demand response providers and individuals that potentially wanted to build new units if they got the right clearing price would do so, they had been and they would if the prices weren’t right or they could see greater profitability, they would buy that back or sell that demand back in subsequent auctions which is a speculative action that is not the place for the capacity market. So we will continue to work on changes there and we have also been very public about either getting the right compensation for our nuclear assets or we will have to shut them down. In this last auction at PJM we had five units in PJM that did not clear, overall the clearing price was beneficial to the total fleet, those units did not clear and that gives us an opportunity to work with the state and work with the RTO on the value that they provide not only as a firm fuel during any weather event, but also provide a clean energy source that if taken away would be very difficult to meet the new mandates that will be coming out next week on the greenhouse gas log.

So I am doing everything at a high level because I know we are going to go much deeper into this as we go forward. We announced most recently strategic acquisition of Pepco Holdings Company. This acquisition was in a competitive bidding process, it was a 25% premium at purchase price of 27-25. And there is multiple strategic regions, we are not growing for the sake of growing but this helps us in multiple ways, one it drives a contiguous footprint between what we have now in the light blue in the green which is the BGE zone, in the PECO zone two of the utilities we mentioned before and we get the Washington DC area which is Pepco the Delmarva, which goes into Maryland also the Delmarva peninsula which is I guess its orange or something in Maryland on a peninsula Maryland and Delaware and then Atlantic City Electric which is South Jersey. And the blue on the side is the Chicago area, Northern Chicago area.

But the way that this helps us, it does diversify our earnings flow, but previously we had been recognized about the rating agencies in a more conservative manner since our riskier business, the generation company was servicing the dividend and the debt at the holding company by buying Pepco and continuing at the $15 billion that we are spending in the utilities that dividend and dividend policy will be shouldered by the regulated entities or it will be able to be periodically serviced by the regulated entities ensuring that we have the dividend at the right size and allowing us to use the earnings from the generating company to continue to grow strategy.

So from the balance sheet perspective it makes a very good strategic move but opened up about $4 billion of access to debt while maintaining a significantly strong balance sheet and it also has a strategic and industrial logic by having this contiguous system that we can leverage operating experience and drive synergies and procurement contract to utilization and efficiencies, mainly to drive the customer experience to a higher level. So that’s the latest acquisition.

You can see the transaction numbers here. The accretion, even though it was a higher -- on the higher range of premiums being paid lately, it’s accretive in the first year and that accretion increases into the second year of $0.15 to $0.20 a share. You can see the rate base growth increase that we will be able to achieve based off of adding it on and our mix of operating earnings unregulated Pepco and in the existing. This is not a fixed formula that we want to have earnings of a certain percentage be on one side or the other, the focus is truly at if we have a dividend and we have debt at the holdco that the regulated -- the profitability off the regulated entities which is a goal of 65% to 70% of the earnings and dividend up to the holdco will be the basis of the dividend, the remaining is always ploughed back through as capital is required, cash is required, returning shareholder equity into the capital spend plan.

We have been working on the regulatory approval process. You can see the run rates there, long-term run rates are roughly 120 million to 140 million. 60% of the synergies will go to the ratepayers through rate cases but in the mean time will allow us to sure up getting much closer to the allowed versus the actual earned. We have come up with regulatory concessions pre-package for this as we did with the Constellation BGE acquisition we expect to get into the regulatory approval process with our filings dropping for most of the entities in the middle of June and start the proceedings from there. So it's a transaction significantly accretive EPS and it also helps us in rate base growth.

So our long-term position that we're looking at as you can see here, it's a diversification in assets, regions and business models and a major portion of us looking forward is keeping abreast of major technology advances and macro trends that are happening in our industry. The one thing that we are seeing in the last couple of years and we think will accelerate over the next decade is a significant advancement on what has been a pretty stable or stagnant industry as far as technology utilization, technology advancements and distribution equipment, transmission equipment and distributed generation. Our utility strategies need to continue to evolve to be supportive of all these coming through and while maintaining a fair return for our investors.

So that's the big picture high level. And with that we'll go to that fireside chat.

Question-and-Answer Session

Hugh Wynne - Sanford Bernstein

Thank you. Does anybody have a question that like to pick up, so just raise your hand and we'll -- So Chris, just to kind of follow-up on the company overview and for the benefit of folks who perhaps are evaluating this investment with the possibility for the first time, how should the portfolio manager think about Exelon? What are the three positive drivers that could cause the stock to move materially higher?

Chris Crane

Well, on one side, we have our utility business that is continuing to grow. We have as I said $15 billion of investments on highly insured regulatory processes for return which is always an issue with capital spending and earnings lag off of that spending. The other side on the generating business, there is a couple fronts. We still think that energy prices have upside. We’ve seen a good run up but we don’t think that they’re fully priced in as of yet. There is on the capacity side, there has to be recognition in the upcoming deliberation on the capacity market design issues around PJM and other capacity markets for the nature of the asset, the firm fuel on site and its ability to run. During polar vortex, there were many days that we could not get natural gas to our assets that were being called on to run because of low supplier or transmission constraints on natural gas. There is not a coordination between gas transmission and electric generation today. And we don’t see that happening in the near future, although the conversation is started so for the grid to be maintained in a reliable state, especially with this new winter peak and high gas demand, dependency on gas. We see that there is changes that can have some upside for the assets.

One of the biggest thing is coming out next week out of the administration is finally a path forward on greenhouse gases. There was a move as we were all involved a couple of years ago to have a federal greenhouse gas legislative fix in that field miserably when Bipartisan support eroded. We see what the EPA is doing now and instead of her legislative fix going towards a regulatory mandate as a positive. We know that has been tested in the Supreme Court and the Supreme Court’s issued notice that that is the requirement and the responsibility of the EPA.

So, next week we'll get the first draft of what is called 111D delta. It should be the regulation that dictates to the states how they should be looking at greenhouse gas reductions. It's been very closely held. So we don't have a lot of details on it, we have the high level. We know there will be a baseline of carbon emissions, there will be a demand on reduction of carbon emissions and there will be period of time that these carbon emissions will have to be reduced from.

One thing that we know from our own models and from what we've seen in California, you can't maintain the current emission’s level unless you keep the nuclear units viable today. And you surely can't reduce if you start taking them off. Tens of billions of dollars have been spent in California on subsidizing renewable generation to nuclear units come off. We retired prematurely in that carbon output from the stake went up 35%.

So, we think we're uniquely positioned to be able to take and work through a state level design that will compensate the assets adequately for the support of approximately, not only in capacity, but in environmental.

Hugh Wynne - Sanford Bernstein

And then looked at the other way, if someone want to buy Exelon stock what are the three things that should scanning these, the headlines for that could drive the value materially lower?

Chris Crane

You know there is -- we don’t see it now but regulation at the RTO or at the state level can cause concern. If we stay on the path to over subsidize individual generating sources like the production tax credit for wind or the investment tax credit for solar, those can have a disruptive element on the generating stack as we have seen price suppression, artificial price suppression from over generation of subsidize assets within some of the earnings around the plant is one of our major concerns that we have been voicing over last couple of years. We see that situation improving but still as a risk force.

Hugh Wynne - Sanford Bernstein

Actually one of the questions that we receive goes to that is Exelon better or worst positioned than other utilities with respect to your exposure to subsidize wind or distributed solar generation?

Chris Crane

Well, on the wind we are probably in a worst condition than most others. The concentration of wind development in the Midwest and heading up into the upper plain states flows across the seam from MYSO into PJM at Illinois border where we have 11 nuclear plants. So we have been seeing more of an issue from our company than others, although others have been hurt but not to the magnitude of us.

Solar is not as prevalent in our areas as it has been in the South West. We expect more distributed generation to come in including solar, but that one has not really had that much of an effect on us.

Hugh Wynne - Sanford Bernstein

Some of the other questions that we received really goes one of the upsides. How should investors think about the potential earnings upside for Exelon in the CO2 constrained environment, does that depend on the form of the regulations with the state [takes] or what type of sensitivity of your earnings is to that regulation?

Chris Crane

If you, there is two probable ways forward that the states could take on designing a market or a program that would allow compliance there is probably more that will come out when more people come to the table. But the two that we have looked at is a clean energy standard that would compensate or have some clean energy credits for generation that is carbon free. We think that that is a potential probable path in some of the states including Illinois. There is also another methodology called the regional greenhouse gas initiative which states ban together and combine their efforts by putting a price on carbon and that has a market effect of reducing carbon since sensitivities $1 of carbon tax is about $0.25 of megawatt hour. Right now we see the regi that’s operating in New England, down to about $5 that’s $1 per megawatt hour. We don’t think that that is enough to sustain the reductions that are required.

New England is in a little bit different situation. We see a regi model being much more powerful. But we first came out is the carbon taxes are being looked at in Washington, it was open $25, I don't think a regi standard would be a $25, but so $1 of carbon is $0.25 a megawatt hour, you can do the map from there.

Hugh Wynne - Sanford Bernstein

Let's do math a little bit. So that's $0.25 a megawatt hour on your competitors, I assume right. That’s where you are talking about totaling the gas volume fleet. How many millions of megawatt hours of call them free generation do you have?

Chris Crane

We have 200 million megawatt hours on an annual basis, of that most of it is nuclear. What is it? 175 is carbon free and if you pick up a buck just in Illinois alone, a dollar would be a 100 million in gross margin increase. So it's kind of simple rules firm to go by right.

Hugh Wynne - Sanford Bernstein

Okay. Now let's talk a little bit about your strategy. You mentioned I think in your 2014 segment earnings guidance that you expect with the regulated businesses to contribute about half of earnings in '14 and the acquisition of Pepco when it closes in the middle of next year could raise that to 60%. What's your preferred mix of regulated and imperative assets and how is that influencing your annual capital budgeting and you acquisition and divestiture decisions?

Chris Crane

It's not as much a hard percentage any longer. What we're looking at is where we can put capital work to create value. But stepping back from that, we want the utility earnings to be able to theoretically cover at a nominal dividend to the parent rate of 65% to 70%. We want the dividend to be covered, potentially be covered, theoretically be covered by the utilities. We’re getting close to that on a standalone prior to Pepco with Pepco coming into the Exelon utility families will get there a year sooner. That allows rating agencies to take a totally different look at us as a holding company and the subsidiaries. So, and then any further dividend strategy would be really focusing on what’s the growth of rate base and utility earnings that would support any advancement of the dividend going forward. It was at the time when the dividend was being covered by the generating company, the disruptive technology, fracking wasn’t considered, the return of a $1 Btu gas or $2 as we’ve got down to the bottom was not considered. So I think we’ve rightsized the dividend, we’ve got an investment strategy that maintains the dividend and any debt that’s required from the regulatory entity.

If we went back to 75-25 with the corporate holding company commitment still being made by the utilities or theoretically the utilities, I don’t think we would scoop the rating agencies, again it will be a good day for everybody. But, so it’s looking at value.

Hugh Wynne - Sanford Bernstein

Just to follow-up on your comment that you’re putting capital to work where the returns are highest, what is the practical implication of that, is it the regulated business absorbing virtually all your CapEx, are there conditions where you can materially increase the amount of capital that you would extend on the nuclear fleet or is that not expected?

Chris Crane

So, as I said we’re putting -- we have $15 billion of growth capital over the next five years going into the wires business, mostly on pre-approved programs that covering state mandates or legislative actions. We have about $3 billion in growth CapEx going in on the generating side at this point today, over the next five years. We have capacity to increase that as earnings increase and cash flows off of those assets increase, but it's all opportunistic. It's not growth for the sake of growth; it's growth that provides us a strategic diversification on that generating side and some counter cyclical investments that can help dampen the commodity cycles.

Hugh Wynne - Sanford Bernstein

What type of generation assets are you targeting now?

Chris Crane

We have been looking participating in natural gas assets that are coming to the market; we have assets that we see are coming economic to potentially build in ERCOT. So they’re around those type of investments. We have an upstream gas strategy that we're implementing. Today we’re the 10th largest marketer of gas. We handle about 1.2 in the country, we handle about 1.2 trillion cubic feet of gas, some of that's for our own generation, some to it for our retail gas prices but also we manage it for others. So, continuing on some upstream side of the gas and looking in all parts of the gas cycle is strategic focus right now.

Hugh Wynne - Sanford Bernstein

So, digging a little bit on the Pepco acquisition, the agreed acquisition price size Pepco at almost $7 billion, on the day you announced the deal Exelon lost a $1 billion in market value, suggesting that the market disagreed with your valuation of Pepco, how do you think about the price to put on Pepco, what makes the compelling acquisition for you?

Chris Crane

So the first day it did go down, but on the second day it came back, mostly came back. We did surprise people and it wasn’t our intent to make the announcement on what was the prescheduled earnings call. We intended to make the earnings call to be able to show the upside, this was a competitive process that was run by the advisors of Pepco. We didn’t hold the full control of the timeline.

So as we have explained this to shareholders, their appreciation of the strategic change primarily around the balance sheet was better understood in conversations with our largest shareholders today that they do get it. It was opportunistic, it’s strategic, it’s not a view that our vision of the competitive market is dead and we have to diversify. This was not done with the gun to our head as others that had to diversify because of rating agency implications.

So there is the industrial logic or the contiguous footprint and what we can do around that there is the strategic logic on what it changes the view for us with the rating agencies and how we can now access more capital than previously allowed. But it also is accretive and it does provide a good return for the price. Can we do more? We will be working on trying to optimize more and ensure that we meet the synergies that we have committed to. It helps as some of those flow back to the consumer during rate cases but some of them are retained at the merchant side also.

Hugh Wynne - Sanford Bernstein

But When I look at the return on invested capital at Pepco over the last couple of years, it seems to be somewhat below 5% and that compares with the return on your assets in excess of 7%. You are increasing your invested capital through the acquisition by about 14%. So I guess my question here is given the financial launch, again trying to put capital to work where returns are highest, what are you contemplating in the medium term given those returns out?

Chris Crane

We have modeled what Pepco has modeled which was getting up to an 8% ROE. We do believe there is opportunities through driving synergies and operational efficiencies to improve that. We after acquiring BGE, they had historically over a 10 year period average 5% or less of the -- 5% or less of the ROE, return on their equity and now we have it up to just about 9%. So the ability that we have as a larger entity to share best practices, to be able to drive efficiencies, if it’s in procurement, if it’s in outage response, contracts negotiated, it has been our case that both ComEd and BGE that more efficient operations helps you out in rate case recoveries.

We had two very positive outcomes from our rate cases as we’ve acquired BGE. The model is drive reliability to higher levels, drive customer satisfaction to higher levels, be prudent in rate based ads but also look at opportunities to drive efficiencies and expense and we believe we can improve as we have with the other two entities with that model.

Hugh Wynne - Sanford Bernstein

One of our questions points out that the regulatory environment in Maryland and DC is quite challenging. Do you think that you can move the regulatory framework in which these company’s operate in a positive direction or is more a question of trying to improve operations given the regulatory framework that exists?

Chris Crane

The regulators have a touch job in all our jurisdictions, they have to justify to the consumer that they are only allowing prudent expenditures and a fair return this risk adjusted. We don’t see any of these jurisdictions any more complicated than the ones that we currently operate in. We operate in Maryland today. We think Maryland’s commission as we saw act on our merger and to regulatory filings for rate cases with BGE since then has been a consistent commission. We have meet, it will continue to meet in Washington.

Washington provided one of the more progressive recovery mechanisms to drive a significant investment in capital for undergrounding, there is not many regulatory jurisdictions that we have taken that on. So there have been historic issues in most regulatory jurisdictions, some stay above the radar or off the radar, but if reliability is not right, the customer satisfaction is low, it typically means you are going to have a bad rate case outcome. And so our job is to make quality rate case filings that are driven on the recovery of smart efficient investments while driving the customer experience to a higher level.

Hugh Wynne - Sanford Bernstein

Another question, what should we think or what are the principal risks associated with Pepco regulatory approval process, are there rate concessions assets divestitures that could cause problems for you and which state perhaps is the most problematic?

Chris Crane

So one of the major differentiating factors between this merger, our acquisition in constellation, there is no competitive merchant generation. This is a straight regulatory approval on the basis of the test that the regulators have to satisfy that there isn’t a benefit of the consumer. I think our regulatory filings will show through our as we used in Maryland previously that the $100 million contribution to the funds within the states, regulators for them to use as they wish, in constellation it was a rate rebate. We found that that makes it a little difficult for some of the regulators but providing money for them to put into energy efficiency low income programs, however they want to use, it’s $50 per customer and above and beyond that we’re committing to make reliability commitments that if we do not make the reliability numbers that they can hit us as a rate case they can come back and disallow a portion of our allowed return.

So I don’t think one is going to be more difficult than the other, I think they are all fairly professional organizations that we just have to do our job to prove to them that we can meet the tests. And that's the approach we took in Maryland previously and see approach we'll take across the five regulatory jurisdictions that we need to get approved.

Hugh Wynne - Sanford Bernstein

Going back to expected returns and your funding of the deal, if I recall correctly you explained at the time that one of the reasons this was an opportunity for you had unique access to very low costs capital at the holding company today that deal obviously doesn't close until second quarter, third quarter of next year and you are material increasing holding company leverage what have you done to walk in those costs and anticipate from the closing?

Chris Crane

So there is three elements to the financing mechanism: One which was already underway was some asset divestitures. As we look at how assets we're selling on the market in some of our non-core that are not necessarily supportive of our portfolio management, we had proceeding with divesting those, we've committed $1 billion of that cash to the deal. There is $1 billion in converts and $1.7 billion in straight equity approximately that we're looking at and the rest of the $7 billion is on debt.

At this point, what we're using prior to the debt issuance is hedging interest rates, so we can protect the low interest rates and we have a bridge loan that's outstanding right now, we don't anticipate to it was the surety that the Pepco needed to approve the deal that we've been able to have the money to close it on as they’re looking for their shareholders now a cash deal. So we would want to move sooner versus later to do away with that bridge loan, have the equity in place, the cash in place, the debt hedged. And if there are other strategic opportunities that come up on the other side of the company, we’re not constrained by any kind of covenants of the bridge. So that’s what we’ve been working on thus far.

Hugh Wynne - Sanford Bernstein

If I return to the competitive side and focus first on the outcome of the latest PJM auction, so in that auction the price in the rest of RTO region basically doubled from $59 a megawatt day to $120. What were the drivers of that increase in your view on what could be implied for the direction of capacity prices in future auction?

Chris Crane

So what we saw in this auction is overall slightly lower demand from the last auction but then we saw a reduction in imports, capacity being bid in from outside the system. We saw a reduction in demand response bidding and clearing. But probably what and there is more analysis to be done is bidding behavior was adjusted. In the last auction, over two thirds if not about three quarter of the participants in the auction took themselves in as a price taker which means they bid zero in not their full (inaudible) cost rate, their ACR; they just said whatever it is, we’ll take it and that caused quite a bit of pain with the clearing price just right under $60. We anticipate now, the way that the RTO cleared, there is much more discipline in bidding, where people did bid their full ACR as we did on our plants. We typically would bid zero on our nuclear plants and committed to that in the merger proceeding with Constellation and the settlement with the market monitor.

As we had multiple units, five units in PJM, two units in other RTOs continuing to struggle around profitability, we've been very public on it. We had a provision with the market monitor that we could present a full and justified ACR that was independently validated and which it was we bid that in on those units and unfortunately did not clear. But it shows to the regulators, to the RTO, to the stakeholders in the area that these nuclear assets that are very valuable for reliability and even more valued for environmental, we need some kind of market designs that need to be adjusted.

So, we'll go to work on that, now that we've got a clear view on what 111(d) will be next week and the with the capacity market completing getting into the stakeholder process to further evaluate that.

We think this is a more of a sustainable level and we’ve all been surprised in this auction before, every couple of years there is something that happens that was unanticipated, some of the market rule changes that were implemented and some more that we're trying to implement should take the volatility out of it and be able to adequately recover the required value that we should be receiving for the assets. More work is going to done on demand response after the DC circuit court ruling. We are not sure how that ends up but it looks more like -- less like a supply and more like a demand element. We are not sure by what -- how they ruled, who is going to manage that. We see speculation elements still to be addressed as we read the FERC ruling on that. It’s unfortunate that we didn’t get anything in this last auction but I think that was a driver in some of the bidding behavior changes on DR and new units coming in. We will continue to work on that so we feel much better about our future where we are going than we have in last couple of years fighting through some of these issues.

Hugh Wynne - Sanford Bernstein

Some of the factors that are like to stay with us longest are the rule changes and possibly this court decision. Could you explain what the [public] court determined and what the possible implications are for demand response in PJM?

Chris Crane

So there is a couple elements about the way the court looked at it. They thought that one FERC did not have jurisdiction that this was a retail component and not a wholesale component. And there is implications around that that it’s not FERC that has jurisdiction who does, so that has to be cleaned up. It also said that even if FERC did have jurisdiction, they were overreaching on the way that they would compensate or allow compensation to be granted in the marketplace as an asset, you get not only the DR but you are also getting the [L&P] for the area. So, it’s -- I can’t tell you, we are all working on it now, what’s the path forward and we have even seen the suggestions on the path forward but we know but we know it’s not going to look anything like it has in the past. We have all voiced our issues about the way DR has been compensated. We put a lot of money, hard capital in the ground to create a reliability. And they are getting compensated for flipping a switch. So, I have heard some numbers that this could change specially on the seasonal DR instead of $50 being profitable, the prices would have to go for that product to $300 to $400 but we’ll have to see how it works out over the next couple of months. We do see it as upside.

Hugh Wynne - Sanford Bernstein

Let’s switch for a moment to the energy markets. Could you describe the pressures upward and downward pressures that you see on the wholesale power price in ComEd and the eastern MAC zones, in particular I would be interested in your view on the outlook for gas transportation infrastructure, LNG exports from the eastern part of PJM, what that might do for gas and power prices and what cold plant retirements and new wind capacity might do for energy prices in the west?

Chris Crane

So in the west, we are seeing, just over the last couple of months, we are seeing a much more consistent and higher price on the ATC and as we watch the hourly LMPs and the five minute LMPs, the price suppression for some reason this transmission constraints or whatever has something setting the market higher. We do not see, there is not a lot of gas infrastructure built in Chicago or NiHub right now; there is a potential conversion as we have seen from NRG’s acquisition of EME taking it out of bankruptcy that will have a potential upside just because of the dispatch on those units. There’d be more of a capacity play than energy play. So we do see a continued upside in Northern Illinois power prices and that's why we again using our hedging strategy as more win gets developed that will have a dampening effect and that's why we’d rather get into the [regi] or the clean energy standard approach versus what we currently have today with individuals being subsidized.

Other considerations that we continue to talk about is a much more liberal standard on developing transmission to take this constrained renewable power further east where low pockets are in demand for it. So there is more there.

On the Eastern MAC side with gas prices, I have not seen anything that shows a significant impact on gas prices from LNG exports. We've got the Maryland facility is being developed by PJM, that's about the biggest one of the East Coast that we see. And with the supply that leads into the Marcellus any infrastructure that's being built around, we see that as being supportive to a long-term gas price $4.50 to $6.

Hugh Wynne - Sanford Bernstein

Good. And I think we’ve run out of time. So thank you very much. I appreciate it.

Chris Crane

Good conversation. Thanks I appreciate it.

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Source: Exelon's (EXC) CEO Chris Crane Presents at Sanford C. Bernstein Strategic Decisions Conference (Transcript)
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