DYN - NASDAQ

Hello, and welcome to the Dynegy Incorporated Second Quarter 2014 Review Teleconference. [Operator Instructions] I'd now like to turn the conference over to Mr. Andy Smith, Managing Director, Investor Relations. Sir, you may begin.

Thank you, Shirley. Good morning, everyone, and welcome to Dynegy's investor conference call and webcast covering the company's second quarter 2014 results. As is our customary practice, before we begin this morning, I would like to remind you that our call will include statements reflecting assumptions, expectations, projections, intentions or beliefs about future events and views of market dynamics. These and other statements not relating strictly to historical or current facts are intended as forward-looking statements. Actual results, though, may vary materially from those expressed or implied in any forward-looking statements. For a description of the factors that may cause such a variance, I would direct you to the forward-looking statements legend contained in last night's news release and in our SEC filings, which are available free of charge through our website at dynegy.com. With that, I will now turn it over to our President and CEO, Bob Flexon.

Good morning, and thank you for joining us today. With me today are Clint Freeland, our Chief Financial Officer; Hank Jones, our Chief Commercial Officer; Catherine Callaway, our General Counsel; and Sheree Petrone, our Vice President of Retail. We posted our earnings release, presentation and management's prepared remarks on our website last night. Following a few opening remarks, we will devote the majority of our scheduled time this morning to your questions. Slide 4 from presentation deck highlights the key takeaways for the quarter. First, the company's financial performance continues to improve, adjusted EBITDA for both the second quarter and the first 6 months of 2014 significantly improved over the comparable periods in 2013. Year-to-date adjusted EBITDA was up nearly 4x the level achieved during the same period in 2013. Despite what is turning out to be one of the mildest summers on record, combined with lower-than-expected generation from IPH, we are increasing our 2014 guidance for adjusted EBITDA and free cash flow. Adjusted EBITDA guidance has been raised to a range of $330 million to $380 million from $300 million to $350 million. Free cash flow guidance has also been increased to a range of $45 million to $95 million from $10 million to $60 million. Improved results from our Coal segment, combined with strong spark spreads at our Gas segment and our internal cost control and margin improvement program or PRIDE are the primary drivers of these increases. Second, we continue to execute forward capacity deals through multiple market channels, including bilateral annual capacity sales, exports to PJM, post-sale origination transactions and through our retail business. Over the next 3 years cumulatively, we have committed capacity sales for 4.5 gigawatts from both the Coal and IPH segments. The weighted average capacity price to be received for these sales is approximately $3.50 per kw-month as compared to the most recent MISO clearing price of $0.51 per kw-month. Every $2 per kw-month of capacity price on the entire Coal and IPH segment equates to a combined $150 million per year in EBITDA. Third, as energy prices climbed during the first half of 2014, the commercial organization significantly increased the 2015 power hedge position. The Coal segment at the beginning of Q2 had approximately 10% of the expected generation hedge for 2015. Today, that stands at 41% with the increased position put in place at near peak 2014 price levels. Finally, in addition to updating our guidance, we also refreshed the company's earnings potential on a unhedged basis which we first introduced at Investor Day earlier this year. Adding back the impact of the financial hedges on adjusted EBITDA and similarly, the generation hedge provided by our retail business which we previously did not include in our Investor Day however, as referenced during our Q1 call, these retail hedges have the same characteristics as third-party hedges. The company's 2014 earnings potential on an unhedged basis exceed $650 million. Our presentation and prepared remarks also highlights the MISO independent market monitor report issued in June. The independent market monitor or IMM highlights the more realistic near-term reserved margin in light of the historical performance of demand response within MISO versus MISO's planning assumption of 100% performance. Furthermore, the IMM cautions on capacity shortages as noncompliant generation assets retire. Our own analysis provided in the presentation is consistent with the IMM's observations and details the trend of increasing power prices and power price volatility. With generation assets that currently provide 5% to 6% of the power supply in MISO expected to retire, this trend is likely to continue and have a pronounced impact on power prices. Dynegy's low cost base load Coal fleet should benefit from this trend. At this point, Shirley, I'd like to open up the session for Q&A.

[Operator Instructions] And our first question comes from Michael Lapides with Goldman Sachs.

Actually, I have a couple of questions. They're a little bit all over the map in terms of different topics. Can you talk a little bit about -- you mentioned in your prepared remarks about using more refined coal at the Illinois coal plants. Can you talk about -- I don't know, how should investors think about what the economic impact of that is maybe on a dollar per ton or a dollar per megawatt hour, what the impact on the -- in terms of the lowering potential fuel cost is across the coal units? And how much -- how many of the coal units, or what percent of the coal units will realize this benefit?

Michael, the goal is to have all of the IPH and Coal segment units on refined coal by the end of the year. By the end of this past June, all of the IPH units had refined coal installed and in operation. And we hope to have 3 of the Coal segment plants in operation by the end of the third quarter with the fourth one, being Baldwin, sometime during the fourth quarter. And from a modeling standpoint, I think, a safe assumption is, if we assume that at lowers our fuel costs by $1 per megawatt hour -- sorry, $1 per ton.

So I mean if we think -- if it were open market, you're buying PRB 8800 somewhere in the -- kind of pick a range, it just depends when the market moves but $12 to $14 a ton range you're saying here cut that number by $1?

Yes.

Okay. One other one. Just on the balance sheet, you also commented about having excess capital of around $200 million. Just how do you get to that number? And how do you think about how much -- kind of, how much incremental gap this business could hold given your kind of outlook for the next few years?

Yes, Michael. I think when we think about that amount of liquidity that we need to run the business, I think, what we've spoken about in the past is that we need about $500 million in cash. And that addresses a number of contingent needs like cash collateral against some of our hedging programs. Also some -- to the extent that some of our first lien arrangements around gas purchases go away, we need to collateralize those through cash. So things like that. Plus what we deemed to be an appropriate cushion would get us to about $500 million in total cash that we need to have on the balance sheet to run the business and then have an appropriate cushion. So when we look at our cash balances of, well over, $750 million, that's where we get the excess capital on the balance sheet in excess of $200 million, you're just taking the cash balances in excess of $500 million.

Okay. And then how do you think about how much incremental more debt you think the business could hold, or the business could service meaning to where your coverage ratios, your credit metric ratios wouldn't deteriorate beyond your comfort level?

I think right now our -- I think, our net debt-to-EBITDA -- and I'll speak specifically to the DI side of the balance sheet and, kind of exclude IPH from the analysis. But right now, I think our total net debt-to-EBITDA is around 1.8x on the DI side of the balance sheet. I think it's fair to say that, that could increase whether that's somewhere, maximum amount call it 4x -- 3.5x, 4x net debt-to-EBITDA. But I think that would be kind of the max that you'd want to think about on that side of that business with our current fleet.

Your next question comes from Jon Cohen with ISI Group.

I was wondering if you could help us sort of understand that $663 million of unhedged EBITDA in 2014? And specifically, how much of that is due to the much higher winter prices? So if you had sort of average winter prices or winter prices like that we're seeing in 2015, what would happen to that $663 million?

Yes I think -- first of all, the way to think about the $663 million is to think about our business as if we didn't have any financial hedges in place and assuming that the retail business -- that their contracts were selling power at market prices instead of the fixed prices that we have on our contract. So on an unhedged basis, what is the earnings power of the company in 2014 with the prices, A, that we've seen so far this year and what the curve suggests. So that's kind of an open earnings look for adjusted EBITDA for 2014.When you think back to the winter, one of the things that we provided on the first quarter call was a look at the impact of the winter weather on first quarter results. And at that point, our analysis was that the winter impact was about $45 million on a reported basis. And the way that we got to that was to look at the forward curves for January and February as of year end and say, going into 2014, what did we expect to earn in January and February? And then looking back at -- about the end of the first quarter, what did we actually earn? And so, that number was $45 million on a reported basis. On an open basis, when you adjust for the third party hedges and for the retail hedge, that number is about $166 million. So $166 million is part of the $660 million open look for the whole year. But I would also note that if you're looking to try weather normalize for unusual weather, I would also highlight that the summer weather that we're having this year, which in of itself is very unusual. And when we look at what the expectations were for June, July and August that were embedded in our original guidance as of February 10 versus what's in our new guidance as of July 16, on an open basis, it's a little over $70 million negative. So I would suggest to you that if you're looking at kind of weather normalize that taking both into account probably make sense.

Okay. But just to clarify, the 160 was at February 10, or was that at July 16?

No, the 166 was the actual result. So when you look at what we expected to make during January and February as of year end versus what we actually made in those months, it was $166 million difference on an open basis.

Okay. But that does not include the rest of February and March, the realized prices...

I think what Clint is saying, Jon, is that if you went back and you looked at price, forward prices at the end of December, last year, before any of the weather came in and then you compared what happened versus those prices at the end of December, the uplift was $166 million for January and February.

Okay. But it seems like we also saw some pretty strong prices for the rest of February and the rest of March.

That takes into account the rest of February. So it's a full month of January and the full month of February.

Got you. Okay.

And then the other part that Clint highlighted too was if you look at our February guidance and compared that June, July and August of what actually has happened versus February 10, you have the opposite situation where you had over $70 million reduction because of the, again, unusually cold weather that this time occurred in the summer.

Right. Okay. And a question about the, just the liquidity, IPH and also the cash flow profile including recent hedges and just on forward curves. How much runway do you think you have there before you start running into some liquidity issues? Years or time?

I mean, I think it really depends on your view of forward curves. I think when we look forward obviously this year, we have a negative free cash flow outlook for IPH. But as you go forward and you have some of the capacity contract that Hank has spoken about and then you have some of the PRIDE initiatives that we're working on and then our expectations around what power curves do, I think we feel pretty good about where IPH stands.

When we originally did the acquisition, Jon, we felt that we have liquidity that takes us to roughly 2017. I would say at this point in time that the results have been better than what we had previously forecasted. The CapEx requirements are lower, particularly around the Newton scrubber. So I would say that, that profile now probably extends us into 2018 and beyond, assuming current prices. But again, I think what's developing in MISO is by the time you get to 2015 and then particularly, when you get into 2016 as we highlighted, the volatility and the capacity market and the energy prices in MISO should, really, experience even more volatility than what we've seen in 2014. It continues to grow. And we think by 2015, '16, '17, you're going to be -- and really what could be the peak of volatility in this market given the forecast of reserve margins in MISO and the lack of new build.

Okay. And then one more for me and then I'll just get back in the queue. But on your -- is it your view that the volatility that we've seen reflects the tightening supply demand fundamentals on the power side, or is it -- and I'm looking at your Page 15, it seems to me that a lot of this was driven by what was going on, on the Gas side more than the power side. I mean, you had much higher gas prices and if you were to look at that, the same chart using key rates instead of absolute power prices, would you see -- would it be a different picture? So do we have yet to see that sort of power price volatility from tighter supply demand on the stack?

So I think, you're right that the winter phenomenon was primarily a natural gas scarcity event in certain locations. We think it's indicative of the type of volatility one might experience when there's actually a generation capacity shortfall. The -- there were a lot of production problems or reliability problems throughout that cold period. And when we look -- which is -- which would also simulate a lack of generation capacity. But when we look at the structural change that is imminent with retirements, April of '15 and April of '16, we would expect those volatility events to be more frequent, more intense and longer in duration.

And the only thing I'd add to that is the retirements in MISO so far has been roughly a few thousand megawatts. So the heat rate impact of retirements I think, is yet to come. So you probably have some element of that but I think '16 will be different in that respect.

Your next question comes from Julien Dumoulin-Smith with UBS.

So first, following up on the open EBITDA number again. Could you split that out by chance between the Gas and Coal side? Is that possible?

Julien, I'll need to get back to you. And I assume that you're asking about from a guidance standpoint?

Yes, exactly, there's the $663 million and obviously, it's a little bit tricky to do. But I'd just be curious how much of the uplift you -- is ultimately coming from the Gas side and expansion in spark?

Julian, I'll need to get back to you on that. When we look at the third-party hedges and the settlements, it's more heavily weighted toward Gas than the Coal. But as far as specifics between the segments and then factoring in retail for IPH on a full year basis, that's something that we'll need to get back to you on.

Yes, I can imagine it's tricky. Then secondly, on the capacity side could you comment briefly, you talked about a cumulative megawatt committed average price of $3.50 kw-month. Could you talk about what you're seeing that by year? I mean, how much of a step-up as you roll forward by year, are you seeing one? And then secondly, how big is the addressable market for these bilateral sales? You talked about deemphasizing the MISO capacity option. But how much of an alternative sales channels do you see? Can you commit all of your capacity into those other channels?

No, I don't think you can commit all of the capacity in those channels. I think, it's going to be continuing to pursue all of those into the bilaterals, continue to comment as we highlighted, that's cumulative over 1,000 megawatts so far. The exports to PJM, we have the 850 megawatts we're selling '16 and '17 and '17 and '18. We have another 240 megawatts that we've got able to move into PJM. We just need one more leg of a transmission and TVA to be able to do that. So it will be 240 more megawatts moving through the incremental options in '17, '18, and then they'll be bid in full in the '18, '19 option for PJM. But I think it'll be continue to pursue -- retail takes, certainly, the majority of the IPH capacity and then the wholesale origination. We continue to do bilateral deals on the origination side. But I think it's going to be a combination of all. Right now, if you look at those 3 years that's roughly, 1/4 of the capacity that we've moved through those markets. Maybe the goal will be, by the time we get into the '15, '16 timeframe, we're still building that level up but I wouldn't think it would be -- I think it will be less than 50% that we would move by the time you get to the auctions in '15, '16, '16, '17 time frame. So I think there are limits. But when you look at the average prices per year on a weighted average basis and the amount of megawatts that we talked about are, pretty much, even through those 3 years. But it ranges from a low of call it $3 in '16, '17 to a high of nearly $4 in '17, '18. So I would look at '15, '16, '16, '17 at roughly $3. And I'd look at '17, '18 at roughly $4.

Great. And then moving on over to the M&A side of the equation. Can you talk a little bit more about your fuel preference right now, as well as geographical diversity if you don't mind?

Sure. I mean, and this will be completely consistent with what we've talked about in the past. I think an advantage of the Dynegy portfolio versus others is it's -- it is -- it's the balanced portfolio between scrub coal and modern combined-cycle plants. And for us, when we continue to look to build the portfolio, we'll continue to build on upon both of those platforms. We've got strategic competency and running coal assets and gas assets. And for us, building on both the gas assets provide good protection in a falling gas environment. It still generate positive free cash flow and then, in a rising gas environment, you've got the fuel mismatch where the coal assets do particularly well. So for us, we're going to continue to build upon both coal and gas as we go forward. We still have the opportunities that we have continually assessed. And obviously, just -- today, we've done one acquisition and it was all coal. But I would continue to try to have a balanced portfolio between the 2. And in terms of markets our preference, certainly, is to the more well, structure the market is in terms of market design or our preferences, PJM is the one that I'd point to first, as being the market that has better market design than the market say, for example, like MISO. So we'll continue to look at opportunities in Coal Gas and look for those competitive markets that have good market design.

Your next question comes from Angie Storozynski with Macquarie Capital.

So I wanted to start with the second quarter result. So IPH, the 0 EBITDA contribution, the very low contributions from the Coal segment. I see the explanation with some week off-peak prices and congestion. So could you tell -- talk to us about the transmission congestion? What's going on with the basis both for the Coal segment and IPH? Any chance of actually, relieving the congestion over the next couple of years and also about the expectations for the net capacity factors for these Coal plants going forward?

So I'll start on the congestion piece. The -- first of all, in terms of basis expectations, we continue to view a percentage of INDY Hub prices as the appropriate measure of forecasting tool for basis, as we previously discussed. So when the INDY Hub prices have come down, the basis -- the absolute basis number has reduced as well. In terms of some of the specific congestion issues, the most of the primary constrained flowgates around our IPH fleet will be addressed over the coming years through IMM type projects that the projects are on the drawing board for MISO. There has -- there's occasionally and certainly in the second quarter, some specific work and issues, ongoing maintenance that have caused some congestion around Newton. And with the IP -- excuse me, with the Coal segment, we are moving forward, making progress on the upgrades that we've discussed in the past around the Baldwin Transformer and the re-conductering. We're making progress on the contracts to get that work started.

But should we still assume that there's about a 15% negative basis versus INDY Hub?

Our -- it's probably about 12.5% for IPH and 17.5% for Coal just to -- so the average is around 15%.

Okay. And what's the main reason for the low off-peak prices? Is this -- does it have anything to do with winds?

I think primarily, it was driven by extraordinarily mild weather. When the evening temperatures drop down low enough that people are willing to open up their windows that causes us some problems. There is an impact from wind. But primarily, it's a function of extremely pleasant weather.

And that has an impact on off-peak, more so than on on-peak?

It has an impact -- it probably, has an impact more on on-peak than off, but it certainly does impact the off-peak prices. When the overnight lows are 75 degrees plus with humidity, people keep their air conditioners running. When the low temperatures, and there have been some extraordinarily low temperatures in the late spring and early summer, people just don't turn their air conditioning on. So it does effect the off-peak as well.

Okay. And my last question is on the capacity revenue. So Bob, you mentioned that about 1/4 of the capacities sold through these premium channels, so what should we assume for the rest of the capacity? I mean, do I take the price from the auctions, or do I assume that there are no capacity revenues for the unsold portion of capacity in MISO?

You mean, going forward for '15 and beyond?

Yes.

Yes, I mean I think -- to me, the market that I would use for '15 and beyond, we're seeing quoted market prices for '15 in the $1.50 range or so. $1.50 to $1.75 range for '15 but when you get into '16, '17 and '18 timeframe that's when we're seeing numbers that range from, say a low of 2 to a high of approaching 3.

I know. But the problem is that those bilateral contracts seem to have very little liquidity. Like 100, 150 megawatts a week in transactions, right? So will you be able to sell the entire portfolio, also these channels?

No I don't think so, Angie. I think a good portion will go to the capacity auction. But my proxy for saying that, I think the capacity auction will have to converge with what we're seeing in the bilateral market. And particularly, if MISO starts improving the rules around the capacity market, you'd see a dramatic increase in prices. But I just think that, where the auctions have to clear in the future, it's going to have to start converging with these prices. And our fundamental view would certainly back how we look at it internally.

Your next question comes from Andy Bischof with Morningstar Research.

Maybe an add-on question to the previous question. So you point to the issues identified by the MISO market matter. What is the process going forward in terms of MISO accepting and possibly incorporating some of these suggestions into the next auction, particularly in terms demand response treatment?

Well, I mean MISO will determine whether they actually try to change the rules or not. We will continue to try to influence MISO and make the case that, these things need to be corrected if you're going to have a market that actually functions. And to avoid what looks like a market that's going to become very short in just a couple of years. So all we can do is try to influence MISO to do it. And MISO needs to go through, make the changes, get the approvals from FERC to be able to actually, make those changes. But we'll do what we can to influence it.

And can you provide a little more color on the IPH fleet in the quarter, you spoke to some planned and unplanned outages there?

Yes, I mean, I -- it's just a combination of scheduled maintenance that we had. But there were just a number of short outages, primarily around boiler 2.

First quarter, we had some coal handling issues at our Duck Creek and Newton facilities, and those have been rectified.

One of the things that we've done, Andy, is that we've really accelerated some of our projects that we believe will reduce the EFOR of the IPH fleet. An example, say at Duck Creek where they had drainage problems around the coal. We've already gone through in the coal yard and modified the drainage characteristics of the Coal yard there, to avoid wet coal clumping and things of that nature. So we've gone through and looked at each location on what are the near-term improvements that we can do on whether it's sections of the boilers? Whether it's coal yard, whether it's conveyors? And we've done between the 2 fleets about 18 specific projects that, we view, will reduce the EFOR of both. But we've really targeted the IPH fleet.

Our next question comes from Julien Dumoulin-Smith with UBS.

Just wanted to follow-up if you don't mind on MISO reforms if you don't -- if you wouldn't mind digging a little bit to the details on the zones, obviously there was some talk earlier, about combining the zones. But there's clearly been some petitions on your side to shift them as well. Could you kind of elaborate on where you think MISO class reforms are going, specifically around your Illinois zone?

You're right actually, Julien. There was talk earlier in this year, where I believe MISO was considering combining

Your next question comes from Mitchell Moss with Lord, Abbett.

You mentioned some of the Newton CapEx expectations. Can you give us an update on what those CapEx expectations are looking like?

Are you speaking specifically to '14? Are you speaking to the Newton scrubber which I commented earlier?

The Newton scrubber.

So on the Newton scrubber, we have gone through and we have refined our estimates around the costs that we incurred on that. And the third-party costs, our latest estimates are approximately, $216 million to complete it with owner's cost of about $22 million. So that will be $238 million to complete. And then the spending profile on that is $18 million in 2015. $29 million in '16, $27 million in '17 and then it ramps up in 2018 and 2019. 2018 is roughly $76 million. And then the balance in '19.

And is there any effort to -- do you want to shift that to be more frontloaded, or I mean, is there any reason why it, I guess, the cash flow profile is still scaled up towards the 2018-2019 timeframe?

We've looked at different alternatives on what would be the most efficient way to get the units constructed. And concluded that with our recent work with the third-party EPC firm that firming up the costs with that spending pattern, with that construction pattern is the best way for us to move forward. So we're not looking to accelerate any spending over the next several years. Again, we've considered different alternatives, but the most economic for us is the profile that I just reviewed with you.

Okay. And when we think about some of the fixes and some of the EFOR issues that you guys encountered in the second quarter, maybe I'm not sure if I missed it. But when do you think that those can start to really show up improved availability, I guess, in the fleet?

Well, we've seen improvements in June and July for the things that we've done. So it's a -- I think you can measure it in -- and you'll see near-term improvements. This is not something that's going to take 3, 4, 5 years. I think that incrementally, we look to get better each quarter. But I would hope that this time next year that we'll have a substantial improvement versus what we saw in the second quarter of this year. These aren't the, I would say, large complicated issues to fix. We just have to go through and find the weak points in the various plants and address them, and typically it's around sections of boilers.

So in other words, I guess, if I think about what overall generation could look like on the IPH fleet, it shouldn't, I guess it -- there -- it shouldn't be significantly lower for -- it's only a temporary phenomenon, some of these issues.

Yes. I think that's a fair characterization. Again, we disclosed in the prepared remarks, I think the lost megawatt hours from the IPH fleet in the second quarter was somewhere between 900,000 and 1 million megawatt hours. So I would expect when you go forward and look at 1 year from now that your picking that up.

Your next question comes from Jon Cohen with ISI Group.

A couple of questions on your Gas sensitivities on Page 41. First of all, what is the relevant gas hub that sets the price in MISO around those 2 plants? Is it Columbia, PCO or Chicago City Gate, or a combination?

So the most relevant liquid hub to -- that we would use as a proxy for INDY Hub pricing at present is the Chicago City Gate.

Okay. And the gas sensitivity that you show on Page 41, is that anchored around a certain gas or power price? So in other words, you showed $1 per MMBtu upside. Is that from a certain point, or is it just more illustrative?

Illustrative, just a generic $1 move in gas price.

Okay. And is there -- is that linear? Do you think there's symmetry, I mean, there's been a lot of concern about negative basis migrating west from the Marcellus, Utica as some of these wrecks and others are completed. Would you expect to see the same sort of downside to lower gas prices, or is it sort of capped at some level or has floor?

I think it's probably -- it has floor and a cap on it at some levels. But to speak to some of the pipeline expansion activity, the forward natural gas basis market has -- appears to have already priced in a lot of the expectations around pipeline expansions with the Chicago City Gate, 2015 versus 2017 has the markets projecting the gas prices in Chicago will be $0.20 to $0.22 cheaper on a basis from -- strictly from a basis perspective than they are today. And there's also a commensurate uplift in the Marcellus prices. But there's still a great disparity between Marcellus prices and delivered Chicago. And the other notion that I think, it's important to think about when we talk on Midwest Gas is as the expansion moves East to West to bring more Marcellus Gas into Chicago, there is -- there -- a lot of the Western and Southwestern sources of natural gas that are headed to Chicago are actually trading at meaningful premiums. And that Gas will be displaced by the Marcellus Gas. So it's not as if there is a -- an extremely large pool of gas conversion on Chicago without demand. It will back off deliveries from the West.

Got it. And then one just other question on some of these bilateral capacity contracts that you've been signing. Can you give us a sense for the types of customers? Is it just mostly munis and co-ops? And I guess another related question, what type of customers are not signing up that you think should be signing up for bilateral capacity contracts?

So our customer base is primarily munis and co-ops on the longer-term activities. There are -- as well as the short term. The other participant in the prompt year capacity markets are some of the load-serving entities that have retail businesses in the area. So we're actually very encouraged by the fact that munis and co-ops with long history in the industry, as well as long history in the region are recognizing the value of security of supply and are willing to contract forward and these are entities that typically have a very strong credit ratings as well.

Okay. But I mean is it your view that there are certain customers that are, just given the likely capacity shortfall, should be signing up capacity but are waiting to see what happens in the next voluntary auction or...

I think there's a -- I don't know there's a particular type of customers. I think there are all customers that wait. Some -- everyone has different motivations. Some motivation -- some would have motivations just not to break ranks with everybody else and to make sure that they're not disadvantaged by being in -- they may not be compensated for being an early mover. So at the end of the day, they all have to buy -- everyone has load has to buy capacity or account for capacity. So one way or the other, they -- everyone gets drawn into it.

Your next question comes from Michael Lapides with Goldman Sachs.

Little bit of an operational one. Casco Bay, can you give a little-- you gave a little bit of detail on the prepped remarks. What are you thinking about what is normal for Casco Bay going forward? And when do you think you can actually get to that normal in terms of outlook levels?

Well, I think we're getting close to that now. I mean, with the increased gas supply, we've seen the capacity factor go significantly higher than what it was last year. So I think we're getting to those normalized levels now. I think there's one issue with Casco Bay this year. There is some transmission work that happens to be happening at the moment that may restrict some of the capacity. But I think when you look at -- look at next year -- this year, we had a goal of getting the capacity factor up to 25%. I think in the second quarter, we were up as high as 38%.

Yes, yes.

So I think when we get into next year, I think, you'll start seeing it being more like what we're seeing now. I think the challenge for Casco Bay will -- and new England is in the very peak high-demand periods of winter, getting gas tends to be a little bit more of a challenge than it does for the other times during the year. But I don't see why the capacity factor at Casco Bay, can't start settling in upwards to the 40% range or so.

Got it. And for Ontelaunee, can you talk a little bit about kind of at current gas price levels, the -- right around $4, may be even a hair below, what you're just seeing for Ontelaunee in terms of coal to gas switching, is Ontelaunee running full bore at these gas price levels? And what's happening with some of the coal plants that sit in and around Ontelaunee?

I would say Ontelaunee continues to run as a baseload plant. I think in July, they set a production record.

[indiscernible]

Yes. So July was production record month for Ontelaunee. But it's basically a baseload plant now. And I think with the Coal plants in the East, particularly if they're using Appalachia coal, there being displaced by units like Ontelaunee at this point in time.

Last question. Coming back to the refined coal comment in the earlier discussion. Why isn't everybody doing this?

Well, I think for some element, I mean, there is -- I know there is other units that are out there have done it somewhat before. And they've had some level of operational problems. But you also have to have the right counterparties that are willing to sign up for it. And there is limitations on -- I think there's, really, just a couple of counterparties you can deal with out there. So there tends to be limits on how many units can actually get it. You have to be able to secure the equipment for it.

And we have a question from Ryan Caylor with Tudor, Pickering, Holt.

Can you talk briefly about your view on pending nuclear retirements in Illinois and kind of a timeline for when we may see some of these retire? In terms of Clinton, if it retires, is there an opportunity for your fleet to have received additional MISO capacity payments? And what the uplift would be?

Well, I think if Clinton retired, that's taking a 1,000 megawatts out of the zone which I think would make the zone particularly tied in. And I don't know if MISO would, from a reliability standpoint, allow that to go out of the market. And we still have Edwards one running, which is roughly 100 megawatts on a SSR that we would like to shut down. So I don't know if it could actually come out of the market or not. That's probably a question for MISO but that's a lot of megawatts to take out of the market. But certainly, they are financially challenging. And it's in Illinois. So whether they keep them on life support through a system service request for reliability is I think, it's possible now certainly. There's a lot of, I think effort underway by Exelon and others to try to find some type of, out-of-market solution or like some type of nuclear welfare plan or something to keep them alive. But our goal is to have a market-oriented market that is fuel neutral and everyone competes based upon economics. And we're certainly against any type of out-of-market adjustments that are being proposed for nuclear. And we plan to fight against that.

The next question comes from Gregg Orrill with Barclays.

On the retail, $99 million add back to the -- and calculating the potential EBITDA. I know you touched a little bit about this on the first quarter call. But how do you think about the sustainability of that going forward? And kind of, what was the driver for adding that back this time?

Yes, Greg, the way that I think about that is that really, retail is the means by which the IPH wholesale generation sells a large part of its generation. Retail enters into a fixed price contracts with its customers. And so in essence, what's happening through retail is that the IPH generation is fixing the price of its power. So it really behaves very similarly to hedges with third parties. And so when we look at the pricing of those contracts and the portfolio of those contracts relative to market, that's where the $99 million delta comes from. So to the extent that those contracts are serviced and rolloff and are replaced with market-priced contracts, you should see that uplift come through, all other things being equal.

And certainly as -- we know, these contracts go from anywhere from 1 to 3 years and you're selling into a rising market. So you'll have the situation where you'd have the add back now that the following market with the other situation where it will be a reduction.

But particularly with your slides on increasing volatility, how are you seeing that? I mean, are you seeing margins on retail?

Yes, I mean we're seeing margins on retail expand. We're selling at better prices, so for the contracts that we're putting in place now, for '15 and for '16 it's reflecting the higher prices.

And Gregg also the thing that I would note is that $99 million is specifically the -- in essence, mark-to-market on the energy component of the retail pricing. So the margin that Bob was just talking about or the capacity sales or what have you are not included in that $99 million. They're really is just marking to market the price of the Energy embedded in those contracts.

Thank you. At this time I'm showing no further questions. I'll turn the call back over to the speakers.

Very well. We appreciate folks dialing in this morning. We know there's a lot of other calls today, and thank you for your support.