Exelon's CEO Presents at 2013 Sanford C. Bernstein Twenty-Ninth Annual Strategic Decisions Conference (Transcript)

| About: Exelon Corporation (EXC)

Exelon Corporation (NYSE:EXC)

2013 Sanford C. Bernstein Twenty-Ninth Annual Strategic Decisions Conference Call

May 30, 2013 3:00 pm ET

Executives

Christopher M. Crane – President and Chief Executive Officer

Unidentified Analyst

Good afternoon. Thank you all very much for joining us. We’re very pleased today to have Chris Crane, the Chief Executive Officer of Exelon with us today. Just one quick word on Chris’s background; he is Mr. Nuclear. He has come up through the nuclear operations at Exelon, running that fleet and then took position as Chief Operating Officer and finally our Chief Executive Officer. But I think he has had most at home inside probably boilers and control rooms, but now he is running the whole shooting match. So let me turn it over to him. He will give a brief presentation, providing an overview of the company. Then we’d invite you to submit your questions on using the 3x5 card and we can incorporate them into the Q&A. Thank you very much.

Christopher M. Crane

Thank you, and appreciate the opportunity. I know some of you in the room, but for others that don’t know about Exelon, I’ll provide a brief overview and for your reading pleasure, we have the forward-looking statement.

Exelon is one of the nations’ or is the nations’ largest competitive integrated energy companies with the 35,000 megawatts of generation, 52% of that is baseload nuclear, 28% natural gas, about 10% hydroelectric renewable and then there is the other very small portion of coal.

We merged with Constellation last year giving us the leading competitive energy provider in the U.S. Exelon is a standalone with very heavy baseload, long on generation, Constellation has established a very good platform for wholesale and retail sales, and they were short, so the merge really put us together to be able to better get to market with our products.

And the other part of Exelon is our regulated business, those first two are competitive, is our regulated businesses where we hold Commonwealth Edison, the utility in the Northern Illinois area; PECO, the Southeast Pennsylvania; Philadelphia Electric and Baltimore Gas and Electric in Baltimore were serving 6.6 million customers across three diversified areas and we have an opportunity, I’ll talk a little bit more about on some significant investments there with quality returns on our investments.

We are probably the largest from a national presence. We are selling gas or electricity in 47 states and also the providence of Alberta, small holdings there. We serve about two-thirds of the Fortune 100 companies through our Constellation business. And as I said, the utilities give us that large urban presence for operating in across the states.

We have a unique combination of scale and scope of the industry. You couldn’t create the diversity that we have today. We have some small upstream business in exploration that’s mostly strategically done for market Intel, understanding the cost instance, gases, setting our margins staying close to the gas and oil industry helps us out there.

We have our conventional generation, as I mentioned, the 52% nuclear low cost baseload clean generation with gas after that. A couple of years ago, we started to move into the renewable area, acquisition of John Deere wind. We’ve continued to grow that out. We have about 1,500 megawatts of wind and we’re continuing to grow in solar in the southeast part of the country.

The electricity, the gas and the electric business is the annuity in the portfolio. But we’ve done a lot of work around better rate recoveries on that, our retail and then beyond the meter. But we create value through some core values on operational excellence. We are an operation focused organization not only on the nuclear side, but driving the discipline for safe, reliable and repeatable operations across our fleets.

A disciplined growth and investment, we’ve made some significant investments over the last couple of years that have paid off for us and we continue to approach that financial discipline as a core competency of ours as is regulatory advocacy working within the markets and I’m sure we’ll talk about the latest capacity options and we’ll talk about our actions around that in one of the questions.

We currently have significant investment opportunities in the out years. The current five year plan has $16 billion of growth investments that are currently in the plan, $13 billion at the utilities and $3 billion at the Genco. With our operational excellence and our financial discipline, we believe we’ll be creating 5% to 6% annual growth rate at the utilities and continuing to make investments in mostly contracted renewable generation that de-risk the portfolio over the next couple of years.

If you look at the incremental growth drivers including operational efficiency, we have the intrinsic value creation and we have the opportunistic value creation. The intrinsic, we continue to pursue strong balance sheet as some of you may know, at the first part of the year, we reset our dividend policy to be more in line with the current market. We had a 40% reduction in our dividend. We stress that dividend reduction to make sure it was sustainable in all market scenarios, ups and downs and it really is pegged up by 2017 after a significant spend out in the utilities that the utilities would carry the burden of the dividend allowing us to use the balance sheet and the growth capital on the growth side of the business for other opportunities.

We continue to work on productivity improvements, investing in the utilities and we have some uprate – one uprate that’s under work now, should complete within a year or so. And we have a few other uprates on our nuclear reactors that we’ve suspended just because of market conditions, doesn’t want the investment at this point.

The opportunistic, we’re having the scale and the scope and the access to be able to take advantage of our portfolio. We can continue to work on contracted generation and potentially conventional merchant generation if it’s in an attractive market and we see it as accretive. The regulated is not something that we would be working on right now. We have seen things that the total regulated utilities are trading at a premium and we think we’re undervalued. So you would not want to be trading your equity at that time.

But on a fully open basis, $1 of gas increase equates to about $5 of megawatt hour and that for us the upside is $1 billion in gross margin on a fully open position. So as it’s been pointed out, we have the most sensitivity to the recovery in the gas and electric markets rather than any other in the sector.

So our company and our value proposition we believe in clean energy and competitive markets. We have our challenging days. We have our ups and downs. It’s a market that we’re in and we’ll be staying in. Our management model for our fleet operations is world renowned not only in the nuclear side, but as we continue to develop our skills on the running the wires business. With the Constellation merger, we do have, as I mentioned, the leading retail and wholesale platform. And we do have a track record of making sound investments for growth over the last few years and we’ll continue it. So we are focused on value return to the shareholders, sustained a dividend with opportunities of growth in the future, pursuing opportunities of earnings growth either with business efficiencies or opportunistic or intrinsic investments. And as I said earlier, an unparalleled upside to the commodity price recovery. So that’s a quick overview there.

Unidentified Analyst

Thanks, Chris. Again, if you have any questions, just hold up your cards, we’ll collect them and add them to the Q&A. So maybe we’ll just attack the PJM capacity auction results, first thing. The RTO capacity price fell from $136 megawatt day and $15.16 to $59 megawatt day and $16.17 MATS capacity prices fell from a $167 to $119. Maybe you could talk to us little about the expected gross margin impact of that? Is that more or less the magnitude of the gain that you’ve enjoyed from higher forward prices since the beginning of the year or how do you think about it?

Christopher M. Crane

We’re disappointed in the auction. It seems like every couple of years we learn something new in an auction and then we go to work to make sure we can either adjust the rules or better model for the change. We, like everybody else, did not anticipate the imports that came in and 35% of them not having transmission. And I don’t think we fully appreciated the desire for risk to be taken on developing new assets, unsubsidized assets in the RTO.

That said, it’s disappointing, but not devastating. We’ll look at it, we’ll analyze it, we’ll see if there is anything to work on in the stakeholder process and as the weeks come ahead, we will learn more about it. We do believe that we did not disrupt the upside that we see in the energy markets. As we said at the first of the year, we saw $3 to $5 upside as the coal units retire and as supply tightens, the coal to gas switching new capacity having to come on in some areas to cover that, that will improve the market.

Although there maybe some small effect of the new capacity coming in, we don’t think it will have a significant effect on those prices. So now our thinking that we’ve seen the dollars plus come in since the first of the year on those forward prices as more liquidity trends into 2015 or comes into 2015, we should see the rest of the upside. And again, from the first of the year, on a fully open position, that would be about $1 billion, about twice the amount that we lost in the single year, but it would be repeatable year-over-year. And so still feel like it’s a solid upside and we’ve got the right position for with our fleet.

Unidentified Analyst

Do you see – I don’t know if you can hazard a guess this far out, but do you see capacity prices continuing to hover in this relatively low range that we’ve seen over the last three to four years or?

Christopher M. Crane

I’ll qualify this. We needed to do more of an analysis and get more details, but from what we’ve looked at over the week end, we do not think it’s sustainable. You cannot get a return on your capital at $60 a megawatt day on a new build. And if you look at the basis differential on the energy cost where the energy market, where these inputs are coming from, they are actually leaving higher priced markets to come into a lower priced market to take advantage of a capacity payment, not sure of the arbitrage there when you’re wearing the risk of transmission. So we’ll have to learn more. I have not heard who won or if anybody has issued a press release congratulating themselves on the win. But $60 a megawatt day is not sustainable from our modeling on either new build in the RTO or imports of existing assets with the transmission risk and in some of the locations we’ve heard it might be coming from.

Unidentified Analyst

Just to press that a little bit further, is the cost of new build really the relevant benchmark any longer or is the success of the auction and keeping capacity prices low evidence that the marginal cost of supply is set by something else, demand response, uprates, imports from the plants that are relatively close by?

Christopher M. Crane

Well, it did show that this year that there was bidding behavior that entities were willing to take more risk. Again, this is just on a couple of days review. We do not think it’s sustainable. We think that cost of new entry is a pertinent number. There’s some variation around it. If you own a brownfield site that a switchyard is already in, is it the $180 megawatt day or is it a $120 megawatt day? So there could be some variation that makes it relatively relevant, if that is the right way to phrase it. But at $60, we don’t understand how you’re just throwing capital away.

Unidentified Analyst

For folks that maybe a little bit less familiar with your long-term energy price forecast, may be you could just take us through the key drivers of your view that in 2015-2016 we’ll be looking at materially higher energy prices than those that are embedded in the forward curves?

Christopher M. Crane

Keeping on a higher more simplistic level, we have, because of natural gas prices and environmental rules, there is 20,000 megawatts retiring, we believe, will be retiring out of the system by 2015. And that date is set by the implementation of the EPA MATS rules and we’ve seen 16,000 megawatts of those amounts. We know in this auction 10,000 megawatts of coal did not clear. So we see that our 20,000 number we believe is a realistic number and it could be slightly more than that. That retiring and what the cost is of the marginal producer after that would put it into that range in the high level. There is many more variables in it. You can talk about where the new plants are being built versus where the plants are being retired, transmission constraints other things, but that’s where our confidence comes from.

Unidentified Analyst

What are the other elements of your power supply business? You’re running an important retail power marketing business, I don’t know maybe if you could comment for us a little bit on how that complements your wholesale generation and then maybe we can talk a little bit later about just the profitability of that business and the direction of those profit?

Christopher M. Crane

Sure. We have, with Constellation being part of the portfolio in Exelon Generation, it creates optimality for us that we did not previously had. We are building a retail organization, but we’re in it, it was in its infancy and mostly supplying to C&I customers; commercial and industrial customers versus residential. Having the ability to take the baseload and some of the [mid market] peaking assets into that portfolio management concept that we have the optionality of moving the power either through the wholesale markets or into the higher margin C&I market or into the mass market, which is the residential.

We have transfer pricing mechanisms within that organization that build in risk each step of the way, it’s less risky to sell a baseload, base product into a wholesale market than it is to sell to a C&I on a shape basis or into a residential on a shape basis, which means it goes with the weather cycles, the daily curve of demand and how you have to cover that or hedge for it.

So if we see the margins tightening, which they have in the retail market, we can stay more in the wholesale side through portfolio optimization. As we see the margins continue to improve, we can move power in to the other segments.

What we’ve seen in the last year and it’s actually started to improve is very tight margins on the residential side. There has been a lot of competition. There was a more of land grab terminal philosophy we think in the competitiveness of the market. Some of the states like Illinois opened up to municipal aggregation, where the city actually went out and bid with competitive suppliers to supply the electricity at a discounted price. There was some very competitive pricing put in on that. We won a very small fraction and we are okay with that. We don’t – want to wear that risk or have those type margins.

As that process was going on, we started to see more reasonable pricing come in. still – the last big one was the City of Chicago, we’re down selected to the two finalists and we did not win that one and we’re okay with it. We understand the margins that we have and the profitability around it. So we like the business. We like the margins when the option is there, but we prefer the optionality of moving the power to where we feel we’re getting the best return.

Unidentified Analyst

What type of retail power margins are you seeing now? Where do you think they will normalize over time?

Christopher M. Crane

So you know they’ve stepped down over the past couple of years, I think, we quoted at the first of the year, the $2 to $4 margin area that we thought was in retail and we’re seeing that on the lower side right now. As we are going to market in providing pricing to new business or to sign up existing business, we’re coming in with higher prices as our competitors and we’re seeing a slowing of sign up or resign.

So I think we’re in that transition phase that the prices will start coming back up in what the new business in the customer base will look like. The customers have enjoyed for the past five years at constantly decreasing price and this is going to be the first time where we’ve hit the floor and start to come up on the back side.

So it will change and it will tighten, I think, a little bit more. Our folks are having to make the decision do we go for lower margins with higher sign up rates that depends on basis differential, depends on weather opinions, it depends on the risk parameters that we want to put into it. We do not intend on going in and losing money on these. So we’re maintaining the discipline.

Unidentified Analyst

You mentioned that I think every dollar on the gas price was about $5 on the round the clock power price and about $1 billion of gross margin.

Christopher M. Crane

On a fully open position.

Unidentified Analyst

Fully open position. How does it work with retail margin? You say you’re at the bottom of the $2 to $4 range. What would happen to your gross margin if it went to the top of that?

Christopher M. Crane

I’d have to look at those numbers. Jack is here, okay. It was $60 to $80. I’ve got the brains over here, our CFO, so $60 million to $80 million on every dollar margin.

Unidentified Analyst

Okay. Now that’s a business retail power supply or let’s say supply in full requirements retail or electricity is a business that in many ways is filled with risk because you’ve got to accurately predict load profiles and supply and procure and supply the power to meet that load profile. A number of competitive retail suppliers have incurred significant losses when they did that incorrectly.

For example, [Jackson] in the very hot Texas summer two years ago and there are other examples sprinkled around the industry and estimates are proved to be wrong simply because of range of weather. So what’s your estimate of the risk of that business, you can hang in back from some opportunities where the margins were too low?

Do you think that at current margins you are being adequately protected against the risk of some of these mis-estimates and consequent losses incurred in the supply of power?

Christopher M. Crane

So first of all, we are quite experienced on covering shape loans. We did it for PECO during the transition, we did it at BGE, we did it at ComEd. So we wore the risk and covered the shape product. We look at each region a little bit differently. Texas is the most volatile. You have to understand your position in Texas. We try to match the load with our generation and maintain margins. We have some high heat rate units that are our insurance in Texas. But you keep some length and you prepare for that. We do make sure we have our anticipated hedge. But we understand the volatilities there and how to protect it.

If you go to, if you had gone to New England typically and I think this winter changed that a little bit. You don’t have the volatility in the summer that you’d seen in other places. In the winter, we’re starting to see more volatility. So how we cover the winter load and commitments in gas with the gas constraints coming into New England and New York is somewhere in the middle. I think we manage it well.

Unidentified Analyst

One of the sort of fascinating things in the way about Exelon is that you run this very low cost, very high capacity factor portfolio. But it’s comprised of a bunch of plants that nobody could afford to build today, particularly in a competitive environment. So you can’t grow your business by adding that type of capacity that will grow your business if you grow it at all by adding capacity as competitive today, which might be combined cycle gas turbine, and I take it from your earlier comments, did you think even that’s not rewarded by current energy and capacity prices. So how do we think about opportunities for growth on the generation side of the business? Is it purely a matter of energy and capacity prices recovering or are there things that you can do to contribute to higher gross margin through uprates or efficiency improvements or anything else?

Christopher M. Crane

So your first point is right on. There is no way to duplicate the portfolio that we have ownership in the 24 nukes low cost bases and we do operate them very well. You can think about them as mines with about 30 years left in them. So they’ve got a long runway but they have a defined life and one day they will be tapped out. So we watch the investments closely to maintain those and we continue to analyze opportunities to take that free cash flow and put it to work.

And if it’s and growing, in renewable space or it’s growing in natural gas, it would not be growing a generation – conventional generation in PJM. Right now the 2016 auction shows there is a 21% reserve margin. It’s not the time to be building with a $60 a megawatt day price put on capacity. You’re not getting the signals to build or and we understand there is no need based off of the reserve margin.

There are other markets to grow into Texas, if we have some resolution this summer on the potential capacity market, I think that will give us more clarity on investing either buying or someday maybe even building in Texas, but it would CCGT’s lower capital intensity faster to market, lower – shorter dilutive period. I do not see in the competitive market with the current technology and I’d say in my life time, it might be too long, I hope it’s too long. But the ability to spend $16 billion on a six-year capital cycle to install a dual unit, 2,400 megawatt nuclear side, it just that the market is not designed for it, we wouldn’t be able to take the risk. That said, we do see technology being developed in the small modular reactor where the capital cycle is much shorter, it’s much smaller and you buy the units, you put them and you start gagging them and you can build it up if the market signals there. So that would be the savior to nuclear when demand comes back in the competitive market, otherwise, you would just build gas or if there is a cold technology that becomes competitive and clean that’s a potential, but we don’t foresee that.

So we have to look at opportunities one, outside of PJM, where we do have some market power issues; two, in a market that it will reward you for a new build or for growth. But it’s not a looming crisis. As I said, we have a pretty good runway on the majority of our fleet and if they run safely and reliably, they would be the last things to come out of the stack on conventional generation in the right market desire.

Unidentified Analyst

It is a fleet harbor that has fairly significant CapEx requirements despite the fact it’s not growing; it’s the fleet that requires a fairly high level of maintenance CapEx. You may, if this is a question for you, you may face some additional environmental compliance cost associated with 316(b) and the cooling water intake regulations. Can you talk about that at all, I mean, what is the level of capital expenditure that you see is required to maintain this fleet at its drilling capacity and what might be required incremental to that for environmental compliance?

Christopher M. Crane

So over the last 10 years, we’ve been putting more capital into the assets to prepare them for plant life extension and nuclear asset, they’re originally licensed for 40 year life. There is a provision that you can extend them by 20 years or when you extend them by 20 years, you need to replace turbines, replace rewind generators, replace transformers, pipes, valves, control systems, so we’ve been going through a spending plan that actually does increase the value of the assets. It’s not just maintenance, it’s extending the life up.

We’re coming to an end on that period. We just filed for two more license extensions at Byron and Braidwood plant in Illinois. We only have two license extensions left to file in our newest plants which are LaSalle County and the Clinton Plant in Illinois and we’ll be working on those over the next couple of years.

So we anticipate the maintenance capital to start to go down across the fleet. We see that excluding nuclear fuel which we buy on the capital side and amortize it over the utilization of the fuel. We see that going down below $700 million which would be a reduction in what we’ve been averaging which is over a billion for the past years. And as the units age and they come closer to the end of the life, we have one plant that will come off line in 2019. We analyze that capital spend to make sure it’s still accretive and we get a return on it. You get to start to pull back on the capital as we have on the units because it’s coming to the end of life in New Jersey and we try to keep that in balance.

Something happens towards the end of the life that is a large capital expenditure; you make the decision to shut it down earlier on that’s in our models also. 316 (b), I’m sorry. 316 (b) is cooling water for entrainment and impingement of fish – aquatic life at cooling plants across the country. We have worked closely with the industry groups and with the EPA, we think the rule will be finalized in the June timeframe; we’ve got a couple of iterations on it. We feel that there will be capital to be spent, but we don’t think it’s going to be material, that’s contingent on the definition of best available technology and not teaming a cooling towers of best available technology, so some very technical phrases that we’re in one of the iterations of that. But I think we have worked well with the EPA to fix. We’ll spend money, but it won’t be to the point that we’re questioning the viability of plants.

Unidentified Analyst

Okay. One regulation that’s looming is EPA regulation of CO2. They have proposed a standard for CO2 emissions from new fossil fuel plants when that’s finalized, which may occur this year, they’ll be obligated on the Clean Air Act proposed emissions limits for existing plants. The other view on how those regulations are likely to play out, what the implications might be for energy prices in PJM?

Christopher M. Crane

Nobody has a bigger upside to CO2 rule on existing plants than Exelon. The position we’re taking at this point, we need to stop all regulation changes. Let’s let this market settle out, but included in that is stop the production tax credits in subsidizing one generation over the other. We are all having a very difficult time looking at where we should be putting our capital. We think we need to understand what the goal is if we’ve had a coal to gas switching, what’s the CO2 loading on the country, what should the rule be, how should it be constructed disadvantaging one over the other on the production tax credits has a negative effect. So we’re saying let’s have a holiday. We don’t need the distraction, we need the market to settle, we need those to retire that are going to retire, we need those that are being subsidized to stop being subsidized and for future growth and figure out what the new norm is, so we can create some predictability.

Unidentified Analyst

You may get a holiday on the PTCs and ICTs because those are sort of subject to annual renewals and if I remember correctly the last renewal was for projects that program by the end of 2013. So it might capture some projects that come on line in 2014. Seems unlikely that you would get a holiday on this particular regulation, the CO2 regulations because to obtain the holiday would require some amendment to the Clean-Air Act and right now Congress isn’t in a mood to get much done. So maybe I can press little bit harder and ask you to say what you think the outcome is likely to be there whether that’s a potential upside or not?

Christopher M. Crane

I’d have to go back and look at it. My understanding is under the clean – I did not believe and I could be wrong and Robby or Andy jump in here that CO2 was part of the Clean-Air Act. I think it was an add-on or it’s a conceptual add-on. But again I could be wrong on that and we’ll verify. I think it will be a terrible distractive fight right now to try to push it through on this Congress and it creates some lack of predictability. If we could have a bipartisan conversation on Clean Air standard that could take into consideration all the sources and what the desire was for the sources, we’re looking at projections in California potentially negative pricing during the middle of the day because an over application of renewables. We see in Illinois, 8% of the time at a few of our plants negative pricing because when demand is down, the wind turbines are blowing. We are trying to make decisions on investments in reliability not only transmission, but on the generation side for stack that exist today and a market that exist today. So like I said we could step back and say let’s have the fight for CO2 because we have the biggest upside, but I don’t know if that’s the right thing for the market at this point. Are you guys checking on that?

Question-and-Answer Session

Unidentified Analyst

We have a few questions from the audience here that some have to do with the capacity results, capacity auctions results or some have to do with the price of natural gas. Let met put these ones to on natural gas to you first. First question as pointed out, there are large and increasing natural gas resources being developed in the Marcellus and Utica shales and underlying the PJM power market. The questioner points out that could continue to pressure prices on the power markets, can you restructure your business model to live with low prices for energy and now apparently under the PJM side for capacity over a five year timeframe?

Christopher M. Crane

So we have stressed that we don’t anticipate that this is the case. But we have stressed the balance sheet on our fully open position with the restructuring we’ve done on the dividend. We survived that long run fully open position $3 gas. We don’t see $3 gas as being a long run number. As we look at it to gain the return on a capital floor, the E&P folks depending on what the location, wet or dry, it goes from $4 to $6 depending on if it’s offshore and even higher.

So we believe the price today is in play. We still see the upside. Today that’s probably about $430 on the spot market. We use the forward strip as our base case. We don’t use the belief that we’re coming up another $1 in natural gas or $1.50, the new norm is going to be $580. But we just deal with what it is. Currently on this trip, it stresses to what we think is an unreasonably low number on a fully open position and it’s sustainable, not advantageous, but sustainable.

Unidentified Analyst

Next question is kind of related to the prices of gas and power. The questioner asks, could you please walk through your hedging strategy and in general terms, your hedge booked; position hedge for 2013, 2014 and 2015 et cetera?

Christopher M. Crane

Sure. We do have a belief that there’s – we have a ratable hedging strategy and so what we’re doing is selling a third, third, third of our forward capacity into the market. So when we come into a prompt year January 1, that year is usually about 90% sold forward, 60 somewhat percent following year and 30 somewhat percent after that. So it’s a ratable strategy. We have within our risk tolerance. We have some parameters where we can go ahead or behind that ratable by some 8% to 10% based off of our view of the markets.

If we think the market is really strong in the forwards, we may capture some of that upside and go above ratable. If we think the markets weakened as a reflect, we can go slightly below ratable and right now in the forward years, in the out years, we are slightly below ratable. We protected in some cases using gas options, put options, we protected the floor on some of that lengths that we have. We would preserve the upside, so we’re probably using more options now than we have in the past. But slightly behind using more options, we hope to capture the upside on the out years.

Unidentified Analyst

A couple questions go to the kind of integrity of the PJM capacity market. One question that points out that First Energy believes that the PJM capacity market is broken as if you share that view. Second question is a little more specific and goes to whether the penalties in the PJM capacity market for generation and demand response that clears, but do not show up or sufficiently stringent. And so I guess proportionally I’m kind of asking your perception of the quality of the market and whether it needs to be performed in an important way?

Christopher M. Crane

So I don’t think it’s broken. We’re disappointed in the auction, but we participate in all the competitive RTOs and by far the PJM capacity auction is the best structured. We have over the years had to work on elements. It’s only in 11-year old or 12-year old market and we’ve had to take lessons learn, if there was demand response and have that evaluated and rules adjusted around that through a stakeholder process that has all the – not only the generators but the end users involved in it. We most recently made some significant improvements on the minimum offer price rule on subsidized generation and I think that has helped. And this is – it’s very early in the review to say it, but this is an unanticipated, I think auction where more inputs came in and maybe we’re bidding zero and have a very tough time to secure the transmission.

We’ll have to evaluate this circumstance and like before there’s things to change or adjust if you’re Terry Boston and you’re PJM, you would say I had a very successful auction of a 21% reserve margin. I was able to lower their costs for the consumers and that would be their opinion. It very well maybe the right and then we have to reevaluate what we think the circumstances are to change, but I personally believe that the $20 a megawatt day penalty may not be enough versus the optionality that it creates.

My understanding the intense of the capacity mark is to assure there’s adequate capacity in three years out and that capacity is directly tied to reliability and you do not want any games being played with that, it needs to be delivered and the commitment should be there to deliver it. It shouldn’t be a speculative market that you’re looking for optionality in and if that is the case, I think the rules need to be adjusted for that.

Unidentified Analyst

Just to be kind of 100% clear, I guess you’re basically saying that you think that perhaps the penalties for generation and demand responses does not show up and may not be quite stringent enough, what would all the penalties right now, you have to disclose your capacity payment and pay a $20 per megawatt a day penalty or?

Christopher M. Crane

Yeah, it’s the 20% or $20 a megawatt day whichever is higher. And so on a 60 megawatt or 59 megawatt a day clearing price, if you don’t deliver on day one and you haven’t procured in the aftermarket capacity auctions, if you haven’t procured to cover that, you would pay $80 back.

There is an optionality play depending on the size of the megawatts we have to evaluate. I don’t want to induite the process until we know more about it. But definitely it shouldn’t be structured for optionality; it should be structured for true delivery to create the confidence in reliability.

Unidentified Analyst

We are getting close to end of our time, but I wonder if you could just have a quick look at the regulated business about half of your $5.5 billion in annual CapEx goes the regulated business with the exception of PECO, those businesses have for years earned returns that are blow Exelon’s cost of capital. Can those businesses be restored to acceptable levels and how and over what period of time?

Christopher M. Crane

I think we’ve done that. I think we’ve accomplished that in the last year. In Illinois, we’ve worked with the State Legislature to come up with not only an investment plan to install smart meters, to upgrade the grid, to have better intelligence on the operation and the optimization of the grid, storm hardening and we are putting a significant amount of capital to work under a newly structured formula rate. We had that past. There were some issues that we had to deal with at the commission level. We had to go back to the legislature. We were able to fix that. So now it’s essentially 580 basis points above the treasury as interest rates increase as they should, our returns increase and so we feel much better about Illinois than we have in the past.

Pennsylvania is a fairly robust regulatory environment and the writers that they have in the state allow us for a large expenditures on gas and electric way to recover. In Maryland, things have improved greatly. Our last rate case gave us a much improved return on equity. I think we – you can say it’s one of the best rate cases without any controversy around it in many years, it’s understood that we’ll be filing on a regular basis. We have filed again as reporting in the capital.

The larger capital that’s being spent in Maryland is around the smart meter and storm hardening and we have had support at the administration level and at the commission level on going forward with that. So we think we’re in a much better place than we were a year ago, two years ago and we’ll continue to work on those relationships.

The number one thing that’s going to be key there is no rate shock, which we think the lower energy prices perversely will help in that to allow us to make those equity investments in a higher level of customer satisfaction through reliability. I think putting the three utilities together is helping us on that sharing best practices when storm – when the Hurricane Sandy came, we rolled hundreds of trucks from Illinois, we positioned them at PECO and BGE. We’re able to get our customers recovered in fairly quick turnaround, and then move on to help other affected areas. But the size and the scale that we can bring to bear to drive that reliability and customer satisfaction also is a key for us to have the right regulatory compact in the States.

Unidentified Analyst

Good. I’m afraid that’s all we have time for it, thanks so much.

Christopher M. Crane

(Inaudible)

Unidentified Analyst

Thank you very much.

Christopher M. Crane

Thanks.

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