DYN - NASDAQ

Hello, and welcome to the Dynegy Inc. Third 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, Jane. Good morning, everyone, and welcome to Dynegy's investor conference call and webcast covering the company's third 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 bulk of our scheduled earnings call time to your questions. On Slide 4 provides several key takeaways for the quarter. Highlighting our financial performance. First, we remain on track to meet our full year adjusted EBITDA and free cash flow guidance ranges despite unplanned outages and the impact of mild summer weather. We tightened the high end of the 2014 guidance range by $20 million for both adjusted EBITDA and free cash flow, which is primarily attributable to the mild summer weather. Our commercial and retail teams continue to execute incremental MISO capacity sales at attractive prices. During the third quarter, we executed over 500 megawatts of additional MISO capacity sales at prices in excess of $2 per kw-month or over 4x the most recent MISO auction clearing price of $0.51 per kw-month. As outlined in the presentation slide, approximately 80% of our MISO capacity remains available to sell over planning years 2015, 2016 through 2019, 2020. The 20% sold to date represents approximately $265 million in capacity revenues that will be earned over the next 5 years. If we are successful in selling the remaining open capacity during this time frame at $2 per kw-month, which is well below the capacity prices transacted at to date, that would result in additional capacity revenues of almost $800 million over the same 5-year period. For calendar year 2016, MISO capacity sales to date account for approximately 30% of available capacity and will contribute nearly $60 million in revenues, well in excess of the 2014 capacity revenues. Spark spreads for 2015 and 2016 have increased significantly since our second quarter earnings call, rising 10% to 24% across PJM, New York and New England. As a result of these rising power prices, we updated and are raising 2015 adjusted EBITDA guidance to a range of $1.35 -- I'm sorry, to $1.35 billion to $1.55 billion and raising free cash flow guidance to a range of $600 million to $800 million. This assumes the acquisitions of Duke and EquiPower are closed by January 1, 2015. The company's 2015 hedge profile increased during the quarter as these power prices were climbing. The pending acquisition of the Duke Midwest merchant fleet and EquiPower remains on track, and our integration efforts are well underway. With the recent run-up in power prices, the company's 2015 free cash flow profile for the combined company has increased, and using the midpoint of the aforementioned free cash flow guidance, the free cash flow yield is approximately 16%. At this point, Jane, I'd like to open up the session for Q&A.

[Operator Instructions] Our first question comes from Jonathan Arnold with Deutsche Bank.

The -- one question regarding the guidance for 2015. It looks like you priced that as of October 20 forwards. Can you give us a sense of what it might look like -- what the delta would be if you marked to current prices?

Sure, Jon. This is Clint. You're right, when you look across the fleet and compare what we assumed for guidance versus where the market is today, what you basically see is, across the combined company coal fleet, prices are up $2 to $3 around the clock for 2015. Across the gas fleet, sparks are up about $2 per megawatt-hour around the clock. And for Brayton Point, Mass Hub is up about $15 for January and February. So you're right, price certainly has strengthened despite the fact that gas prices have also strengthened. One thing I hesitate, to kind of mark guidance to market because, obviously, curves move all around. It could be very different next week. But I think directionally, you're right that there's been a meaningful move, since our guidance, that would be additive to the numbers that we've put out.

And just following up on the sensitivity. Supply, I notice, didn't seem to have changed. But you did mention in the prepared statement that you'd added some hedges on the fleet you're acquiring -- or the fleets you're acquiring. Can you talk about that and also whether that sensitivity is still good?

Well, the hedges that we added were more on the existing fleet. So what you see in the slide deck, the hedge percentage to the coal fleet particularly has gone up to 66% for 2015, which is a bit of an uplift from where we were at our last earnings call. In terms of the fleets at EquiPower and Duke, there's no changes there. We haven't done any hedging in anticipation of acquiring those fleets.

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

So first question for you, as you're speaking about the company now repositioned, and I don't want to be too presumptuous here, but really, what about the use of cash for next year? Are there organic opportunities you're thinking about, M&A opportunities beyond what's contemplated? I mean what do you think about over the next 24 months as you finally start to stabilize the business and the outlook and look forward?

Julien, I would say the near-term priorities -- and some of this depends on whether we sell California or not. But I would think that, right now, the 3 primary uses of cash flow over the near term will be, obviously, we'll invest in the fleet as we need to, to drive reliability, our PRIDE projects and things of those nature. But beyond the ordinary capital that we will continue to invest in the existing business, I view it, 3 things. We'll look at our balance sheet to make sure we've got the right credit metrics. And whether or not we do any adjustments to the balance sheet, as an example, if we do sell California, do we need to do some level of debt paydown or not, regarding the amount of EBITDA that goes away when California goes away to keep the leverage in check and consistent to where we are. So that's 1 thing that -- a filter that we would look at. Another will be within the portfolio, and I would say, in particular, within the new PJM portfolio, I think there's a lot of opportunity for some incremental megawatts at existing locations. And we're looking at -- Kendall, we did the advanced gas path work that increased the output of the plant by 80 megawatts by 2016. 40 are place in already. But we also see that opportunity at other locations within PJM as well as we're looking at various chilling technologies for the fleet. The Duke combined cycles have chilling technology. Our combined-cycle assets and the EquiPower combined-cycle assets do not. So there's an opportunity for some incremental investment there that will get additional megawatts out of the existing locations on a very cost-effective basis. And then the third element, I would say that we would certainly be evaluating return to shareholders in some format, and that's something, again, we review with the board at every meeting and will certainly be on the agenda at the upcoming meeting as well. But I'd say those are the 3 priorities beyond just ensuring that we're doing everything we can do to drive reliability, realize our PRIDE projects and things of those nature. We'll -- environmental compliance. So -- but beyond it, those are the 3 priorities that I see in the near term.

Great. And you kind of preempted my next question. How are you thinking about the merits for the California divestment? A, if you could review a little bit the thought process behind it. And then secondarily, where is the value? How do you think about some of the assets, like a Morro or an Oakland site value, et cetera?

Yes. So the decision to explore the alternatives for California is driven by the fact that we don't have scale there. And as you know, within all the markets, there's such a level of resources that you need to allocate around the regulatory around the markets. Then you also get benefits of having plants located near one another, where you can leverage staff, spare parts and things of that nature. California doesn't offer any of those things for us, plus the market design in California is not as good as it is, say, in PJM. But when we look at those things and particularly, the lack of scale for us in California, we want to focus our attention on, really, successful integration and operation of assets from Illinois up through Maine and really focus our efforts there. So taking the assets to market to see if there's the appropriate value, we'll find out. And around the timing on that, we would hope to have some price indication before Thanksgiving and then going into the first quarter of next year, finalize bid process and determine whether or not there is attractive values out there and whether we hold it or not. So that's kind of the timing of the sale. But when you think of the portfolio, there are obviously combined cycles for Moss 1 and 2, 55% capacity factors, very good assets, built early 2000 time frame, so there's good value with those assets. Moss 6 and 7, certainly, the peaking -- the fast-ramping capability on those peaking assets should be a value driver as renewables continue to penetrate the market in California and offers good firming capability. Morro Bay, we've preserved the transmission rights that we have out there. And we've been looking with a partner on alternatives for Morro Bay, and potentially, someone looking to develop would be interested in Morro Bay. And in Oakland, the same thing. Oakland is, in fact, in a load pocket and offers the opportunity to have some gas peaking assets put in there.

Great. And then a last quick question, if you will. Does all of your capacity in PJM qualify for the CP scheme? Others have kind of hedged their bets a little bit. Just could you comment both on your coal and your gas fleet kind of pro forma for the transaction?

Yes. I mean, there's certainly a lot to -- for us to think about in terms of the capacity performance market, and certainly, when the rules are finally settled down, then we can give a more complete answer. But I think about it in terms of a few different ways. First of all, the gas fleet, we view, would qualify. And with the long-standing debate or confusion in the market whether you need firm gas or not, I'm going to answer under my understanding that, currently, you don't have to have firm gas. And if you take that perspective, you look at the Duke combined-cycle assets and then you look at Liberty, which is EquiPower, you look at Ontelaunee, they -- those assets have no issues getting gas through the winter. And if you look at last year's polar vortex, they did not have any constraints on getting gas. And I think the work that's been done around those gas plants over the past year, everybody has been making investments in winterization and doing the things that you need to do to ensure in the high-demand periods those assets available to run. And so a lot of work has been done around winterization with or without CP because it's in our best interest to have that -- have those investments made. The coal fleet is one I should probably worry about a little bit more than the gas fleet because coal fleets tend to have more outages than the gas fleet. And from there, we have been doing the investments around winterization and the like, and certainly, we think they all qualify as well, I think. I was out at the

Our next question comes from Michael Lapides with Goldman Sachs.

Just wanted to check in, was reading -- thinking about New England and was reading through the ISOs filing to the FERC that it made regarding FCM 9. And one of the tidbits was, I think, they commented about almost 8,500 megawatts of potential new capacity has kind of indicated interest in bidding into this auction. Just curious for your thoughts on, a, how much new capacity are we likely to see in New England; b, how New England may be different or similar to PJM, where I think a lot of folks have been surprised about how much new megawatts have cleared there.

Michael, this is Hank Jones. I'll take a stab at that. The -- our assessment of the net change in sold capacity for the next auction is about 1,000 megawatts between a brownfield site and some renewables, that we expect about 1,000. Now there's a much larger number of projects that are in various stages of either early consideration in terms of requesting permits and other consideration. But we try to -- given the time frames and the difficulty to get things rolling, we try to focus on those that we think are highly likely. So we see about 1,000 megawatts coming into the next auction. And the -- and one thing to keep in mind, of course, is that there's been a structural change in the market design -- the capacity market design up there with the slope demand curve. So there's an earlier signal -- or there's more value assigned to tight capacity markets in New England and the new capacity design than there was previously.

Got it. And just curious, when you look around the existing Dynegy fleet, where do the best, I guess, options or alternatives exist for potential brownfield development? Similar to kind of what you did at Kendall adding 40 megawatts or so, but when you look across the portfolio, where are the sites where you think, "Hey, we think the site has room, has space inside the fence or next to the fence where you could do an easy either upgrade or repowering there?"

In the east, a site that can lend itself well is Independence, and we're doing some work around transmission studies to ensure that if, in fact, we want to do it there, you can get the power out. But Independence lends itself well to that. Kendall is another unit that has the space and has the infrastructure to add another unit. Again, we're looking at that as well, and then we're also looking in -- within the MISO territory at some of our existing sites or even at the Vermilion site, which has been shut down. You've got interconnection down at Vermillion where you could look at possibly doing a combined cycle down at Vermillion as well. Within -- further, within PJM, I think whether it's Liberty or the Duke locations for combined-cycle units, there's space there. We haven't done any -- necessarily any work at this point on evaluating is one better than the other. Ontelaunee doesn't have the space, although the development rights adjacent to it, right now, are held by LS Power. But potentially, one day -- I don't know whether that investment would be made there or not. But I think, for us, I would prioritize the ones, right now, in, say, Independence in New York. Kendall and Vermilion is -- are the ones that we've done the most work around.

When you look at forward power pricing, meaning when you just look at the curves, does -- do greenfield economics make sense in any market in the U.S. yet?

The only market that I would say, potentially, it could would be New England. I think I'd still rather do -- rather buy assets than build. I think development, I'd rather go incremental megawatts than a large expansion project. And I think one of the questions to be answered in all the talk around the PJM capacity performance project -- or capacity performance product is what is that going to do to new build in PJM because now you have a capacity product that has variability to it where the maximum you can get in capacity revenues is CONE and the maximum penalty that you can get is 1.5x CONE. And you don't know what you're going to get until after the winter. So how financeable will new build be in PJM going forward, given that construct to that particular product? So I think -- and New England have some of the same type of dynamics now with their performance products. So I think new build actually is getting tougher with these new rules coming in because your surety of cash flows coming from capacity has been turned upside down from where it used to be.

Our next question comes from Keith Stanley with Wolfe Research.

So gas prices in the Marcellus and Utica have been very volatile lately. Looking at the pro forma fleet, how do you think about your overall sensitivity to Marcellus, Utica gas prices? And I know you're overall still levered to the gas as a whole, but within sort of the Duke fleet and taking into consideration all the combined cycles you have in PJM, do you think of yourselves as necessarily long gas in the Marcellus, Utica? Or are you short gas? And how do you think about gas bottlenecks and whether that's good or bad for you?

So this is Hank. I'll take a stab at a portion of that. The combined-cycle assets of Duke hang around Washington or Fayette are right on top of the most competitively priced gas in the eastern interconnect. With ample access through high-pressure interstate pipelines to those basins that are, in certain times of the year, captive because of limited long-distance capacity to remove the gas so therefore, the gas prices are suppressed. We see a lot of pipeline projects and additional capacity put on the board to remove that bottleneck. With the differentials that are there, with Dominion priced at $1 to $1.25 under the NYMEX, there's a great deal of motivation to liberate that gas with additional capacity. The easiest paths are to go east to west for either looping lines or adding compression as opposed to trying to go through more densely populated areas towards the east. And once that gas starts to move west, the price gets rapidly diffused because it's not bringing a tsunami of inexpensive gas to Chicago. It's actually -- the gas is displacing other deliveries going to Chicago and is also trying to access growing demand in the Gulf Coast. We see the Dominion market tightening up, and when combined with the year-on-year carry in the Henry Hub prices, we actually see the price of gas going up in Dominion. So we feel like we have a competitive advantage in that we are -- do have access to the cheapest gas in the system. And as this system is relieved, we don't think it is damaging to our coal fleet. The -- so in that instance -- instant, if I'm -- I'm not sure I've got my nomenclature correct, I believe our view is that we're short Dominion gas and that has -- and that works to our advantage. In terms of our -- of the post-acquisition coal fleet, the -- our fuel prices are very competitive, in that our Kincaid facility in PJM is PRB coal. On 4 out of the 5 Duke facilities, we are -- they are aggressively blending Illinois basin coal with Northern Appalachian coal. And of course, Illinois Basin coal is 8% to 10% cheaper on a Btu basis. So as we compete with other coal-fired stations in PJM, we're very well positioned from that perspective as well.

Okay. And one separate question. Pro forma, you'll now own a lot of assets in Illinois and a lot of assets in Ohio, and both states have a little bit of a unique situation going on with some PPA proposals in Ohio and some efforts to have some type of carbon pricing mechanism in Illinois. What are your strategies to deal with the proposals in both states as we move forward over the next year?

Well, certainly, we're against the subsidies for the nuclear that are being pursued, and we're certainly against out-of-market contracts being given to uneconomic units. So just like the others that are participating in the regulatory arena to try to get this type of special deals that we have to be very active in trying to defend the market and letting the market determine what price gets paid for various assets. So we're engaging -- we're very engaged in Illinois. We're very engaged in Ohio. And certainly, EPSA as well is supporting the fight against what's happening in Ohio to intervene there. So we're actively challenging what's there, and again, we're very much pushing just for market solutions. And every time subsidies are introduced, whether it's to nuclear or to other coal units in Ohio that are uneconomic, I'd rather see the market address it rather than trying to create special schemes that just distort the market signals. And then you end up in the situation where the more efficient units are being penalized, and the signals for new build are being distorted. And then, longer term, it's not good for anyone. So it's a very political arena that you have to be engaged in, and we certainly, over the past couple of years, have become much more involved in the regulatory framework in all of these states. And we continue to dedicate and allocate a lot of resources to be heard through this inside influence as much as we possibly can for market solutions and not out-of-market solutions.

Okay. And one last very quick one. You noted, I think it was in the slides or in the prepared remarks, there was a $45 million step-up in MISO capacity revenues from -- by 2016 from 2014. Just thinking about your 2015 guidance. Should we assume that there's a step-up between '15 and '16 in already booked MISO capacity revenues?

Yes, there is. And I don't -- would you know the number?

I don't know the specific number that's in there, but there certainly would be a step-up from '15 to '16.

Yes. But you're right, I mean, what we had in '14, including retail, was in the $10 million to $15 million range. And of course, '16, we have booked roughly $60 million. So it's going to be somewhere in that range, probably kind of the midpoint of the difference, order of magnitude.

Our next question comes from Neel Mitra with Tudor.

I had a question. With the Duke coal assets that you're acquiring, are the hedges coming on with it? And would they be kind of at market or above market or below market? How would you kind of mark them with the '15 guidance?

This is Hank. I'll try to give you a profile. The -- we're assuming that the Duke assets are substantially hedged for the first quarter of the year and less so for the balance of the year. I can't speak to whether they're -- to their price level.

And Neel, just further to that, one of the dynamics that we have is that we don't have perfect visibility into exactly what their hedged positions are for the first quarter. In our guidance, we've made some assumptions that they are somewhat out of the money but not significantly so. And I think that's really as much information as we have.

What about the longer-dated hedge profile beyond '15? Are there hedges -- substantial hedges past '15? Or is it just for 1 year out?

There are -- there's a modest hedge position that goes out into '16, but not that big.

Great. And then a question on -- now that you have a substantial New England exposure, how do you see New England playing out with capacity performance-type proposals like PJM? I know they've kind of been using a temporary fix that was approved by FERC for this year, but it seems like they have similar problems and they're using somewhat of an out-of-market solution. So how do you see that playing out?

Well, I mean, I think the positive changes are they've introduced the slope demand curve, and so they're getting a better functioning market. I think some of the issues around the penalty structure are -- I think are a bit onerous. Particularly if you have a transmission outage, you're holding a generator accountable for a transmission outage, which doesn't seem to be appropriate to us. But I mean, I think they've made improvements along the way. I think really the only issue that we probably have with it is just some of the penalty structures and how that's designed.

Okay. And one last quick question. You kind of mentioned that 25% of your new England gas plants have firm transport. I'm assuming that, that's kind of advantaged gas from the Marcellus. How long are those contracts? What's the typical duration before you have to re-contract at perhaps market rates?

So the transportation contracts have renewable -- renew rights on them, and they're valuable asset to the fleet. So year-on-year, there's opportunities to renew.

Would you renew at market? Or would you get an opportunity at discount?

It would be at the existing contract price.

Our next question comes from Andy Bischof with Morningstar Research.

Looking at the synergies from Duke and ECP, you've mentioned you expected to see additional opportunities. Where are you seeing those additional opportunities? And when might you expect to provide a little bit further clarity on that?

Regarding the timing, I would expect to do it in the March, April time frame after we've had the assets for some period of time. And whether we do -- probably do an Analyst Day, probably in April, or whether we do it as part of the year-end call would be the time that, I think, we would go out with a new number. But I see the opportunities are going to be around operations, and that could include procurement. That could include some levels of investment around the viability around some of the coal locations. There's additional costs that we're able to charge the co-owners, where we're the operator, that we did not include in our synergy number. So that will add a little bit to the number as well. So I think we'll see, as we get into the assets, just how robust those opportunities are. But we're already identifying some of those areas. I just want to go out with a number once we've had a full look at the assets from the inside and not just from the outside.

Our next question comes from Angie Storozynski with Macquarie.

It's actually Andrew Weisel filling in on a busy earnings morning. My first question is around the Duke deal. You're pretty clear that you're expecting it to close before January 1, and you're including it in the full year guidance for '15. Duke says it will be more like the end of the first quarter. So how do I reconcile that? And how big of an impact might that have on your guidance for '15?

Yes. So on the guidance, being that we obviously don't know when either deal is going to close, we just pick what a full year would look like. And in terms of the timing of where we are in the process, and I think, actually, it's almost reversed. Like, we're the ones that have been saying more towards the first quarter, and Duke has been a little bit more vocal saying December. But as far as where the process is, November 10 is when I think we'll have at least a little bit more clarity. November 10, we should hear back from the DOJ on the Hart-Scott-Rodino filing. And then also, the comment period for the FERC filing process also closes on November 10. So I think once we get some color around what we hear back on November 10, I think we'll have a better indication of what timing looks like. And I think, where we stand on things, I think, it's still realistic to assume that Duke has the opportunity to close before year-end and ECP, probably some time -- right now I would say optimistically, maybe the first half of the first quarter. But we'll know much better on November 10, but that would be my best guess right now.

Okay, great. And then lastly, the coupon on the debt financing is 7.2%, I believe. How soon would you be able to refinance that? And how much lower might that be able to come down?

Yes. The -- I guess, the first opportunity that we'd have -- we issue debt with 5-, 8- and 10-year maturities. The 5-year charge, I think, is $2.1 billion, and it becomes callable in year -- I guess, in 2.5 years. So I think that's really the first opportunity that we'd have to start to refinance that debt complex.

We have no further questions at this time.

Thank you very much. I appreciate everybody calling in, and thank you for participating.