DYN - NASDAQ

Hello and welcome to the Dynegy Inc. Third Quarter 2015 Financial Results Teleconference. [Operator Instructions] I would now like to turn the conference over to Mr. Rodney McMahan, Managing Director of Investor Relations. You may begin, sir.

Thank you, Bob. Good morning, everyone and welcome to Dynegy’s investor conference call and webcast covering the company’s third quarter 2015 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 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 James, formerly known as Catherine Callaway, our Executive Vice President and General Counsel; Sheree Petrone, our Executive Vice President of Retail; Dean Ellis, our Vice President of Regulatory Affairs; and Carolyn Burke, our Executive Vice President of Business Operations and Systems. We have 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 time to your questions. I would like to start this morning by acknowledging that the third quarter has been a difficult one for our shareholders as the energy sector and IPPs have experienced sharp declines in equity values following the overall commodity sell-off. Mild summer temperatures compounded the challenges. Lower demand reduced price volatility and masked the impact of retirements we will ultimately have on energy prices. For the items within our control, we responded quickly by further increasing our PRIDE improvement opportunities that produced additional liquidity supporting our action to accelerate the share repurchase program. Our uprate projects have progressed and we continue to work on plant reliability. We had significant success during the quarter in capacity sales through auctions and bilateral transactions in all of our markets, including California. We made a very difficult decision about our Wood River facility, but it was the right one for our shareholders as the EBITDA and free cash flow profile does not support the ongoing operation of Wood River. Moving to the quarter and year-to-date results, our safety performance as measured by our total recordable incident rate significantly improved during the first nine months of 2005 versus the same period last year. The gas segment year-to-date is at top quartile performance and overall the year-over-year improvement in safety performance from our generations fleet has been driven by the legacy locations. Adjusted EBITDA for the second quarter was $350 million versus $90 million during the same period last year, highlighting just how important the recent acquisitions are to Dynegy. Third quarter contribution from the newly acquired businesses was $240 million. The acquired combined cycle plants have access to lower cost natural gas supplies, which results in strong spark spreads, even during periods of low demand and low commodity prices. Four of the acquired combined cycle facilities in PJM had capacity factors in the mid 90% range during the quarter. Recent portfolio developments include notification from NYISO in New England at 70 megawatts of uprates, and NYISO in New England have qualified for the 7-year capacity rate lock should these megawatts clear the upcoming auction for planning year 2019-2020. 60 megawatts of uprates at the Hanging Rock facility and PJM are expected to come online in the fourth quarter of this year. Recent capacity awards include 1,825 megawatts from Moss Landing; 1 and 2 from Southern California Edison; 575 megawatts for 2017; 400 megawatts for 2018; and 815 megawatts for 2019. Within MISO, the Illinois Power Agency procured 1,033 megawatts of

Thank you, sir. [Operator Instructions] Our first question is from Mr. Julien Dumoulin-Smith from UBS. Your line is open, sir.

Hi, good morning.

Good morning, Julien.

So, perhaps just to pick it up where you left it off there, on MISO you have gained the regrets to the employees of the station. I would be curious when it comes to implementing solutions here, what are you seeing? Is there the potential for real reform prior to the next option in April?

Julien, I would say that the reform for the upcoming option would be limited. I think we are probably looking more towards the auction that takes place in ‘17-’18 versus ‘16-’17.

And do you think, just in terms of what you are giving out there at Techno Conference, etcetera, that you can credibly get a black and white market distinction, such that you would have a clear market signal in that in the

Yes. I mean we are certainly looking Julien, for more of a competitive framework. And I would say that the various stakeholders that are involved in all this are as I have mentioned in the opening comments are beginning to understand the seriousness of the situation. There is a lot of momentum building. There has been a working group within MISO that’s comprised of MISO, ourselves, Exelon and some others, that have put together a proposed framework that could accomplish those things. So I think we can actually get there and the technical conference, I think put forward a lot of good ideas as well. I think they have not complicated ideas to put in place. It’s more just getting everybody onboard, which seems to take a little bit more time that it should. But the solutions are pretty straightforward.

Excellent. And then just related to IPH, you are guiding for $150 ex-allocation, up material year-over-year, can you talk a little bit about the factors, is that just capacity improvement or are there other elements that play?

Julien, it really is mostly around increased capacity, as you mentioned. Next year, IPH will be sending roughly 300 megawatts of capacity into PJM. That certainly will give IPH a nice uplift. And in the balance between some of the kind of upsize contracts that IPH has as well as increased MISO capacity sales, really accounts for almost all of that incremental uplift.

Got it. And then a quick last one here, just expectations on New England, I suppose your written comments suggest expectations for capacity price uplift after Pilgrim, what are you expecting in terms of regional breakout [indiscernible] or do you expect the entire region in New England to see the higher prices as a consequence of Pilgrim?

Julien, with the combination of Northeast mass and Southeast mass Rhode Island into one zone, some additional transmission work that comes into the equation, we don’t expect the zones to separate.

Great, excellent. I will jump off to let others. Thank you.

Thanks, Julien.

Thank you. Our next question is from Mr. Mike Lapides of Goldman Sachs. Your line is open.

Hi guys. Just curious, Bob or Clint, how are you thinking about what’s the timeframe and what are the things you need to see there with your business or the market or both, for making a decision about capital allocation with that excess $250 million to $450 million of capital?

The main thing I would say Michael, is let’s go through the winter and see how the winter shapes up because we still have some open link, particularly Brayton Point is a big swing factor in the winter period, where you have open capacity there. And that’s where you have some extreme pricing when – if you had a reasonable winter. So I would say that we would probably be prepared to make a decision, probably either at our year end call or our first quarter call. So I would say as we are finishing up the winter.

Got it. And when we look at your 2016 guidance, what are you guys assuming in terms of output at some of the key coal units, I am thinking the capacity factors at the MISO units as well as maybe something like Kincaid as well. It’s just, we have seen a ton of coal to gas switching this year in 2015 forwards for gas and especially for gas basis in the Marcellus and Utica, that might impact your Ohio units is having an impact as well, more combined cycles coming online. Just curious about how you are thinking about how hard your coal units are expected to run next year?

Michael, I think in general, we would expect the coal plants to run with capacity factors generally in kind of the 55% to 70% range depending on individual assets. One of the things that we have seen this year is some operational challenges in the Ohio coal fleet. I think there has been a lot of work done, a lot of investment made to remedy some of those specific problems. So I think I would expect and we would expect to see some improvement in that fleet relatively to this year. But again, back to kind of a 55% to 70% capacity factor range across the fleet is generally what we would expect.

And I would say Michael, as well particularly as it relates to Ohio, we saw a third quarter where we are buying gas in that market for our combined-cycle unit at times below $1. And you still see that our capacity factors on the Ohio coal units or I should say our own economics actually – uneconomic hours are quite low. So I can’t imagine much more of a difficult gas scenario than our coal assets in Ohio competing at when you are already competing with gas prices of about $1. But still you are seeing the uneconomic hours being anywhere ranging from 5% to 15% or so. So it really comes down to the balance of that time being, how are we doing on reliability. But beyond economic hours, I really wouldn’t expect – I got to imagine, it can’t really get much worse when you are competing against $1 gas. And sometimes even below $1. The coal units are still economic because the coal units are needed to clear the market in PJM. So I wouldn’t expect any difference on the uneconomic hours. I would expect higher capacity factors because we have got the reliability situation improved in Ohio. And I would say right now, it’s immersed in the middle of a $47 million outage that’s very much targeted to improve the reliability of that particular facility.

Got it. Last question, when we think about O&M and G&A in 20 – that’s embedded in your 2016 guidance, how different relative to what you are actually going to show in kind of your 2015 level or more importantly what do you think the decline in O&M and G&A is next year?

I think G&A is relatively in line with this year. You will have a little bit of step up. One of the differences in the total cost is going to be the fact that we will have a full 12 months of ownership of the new fleets versus nine months this year. So that’s an adjustment that you ought to think about. But generally speaking order of magnitude, it should be in line when you look at the run rate for the last nine months of this year.

Got it. On the G&A side and on O&M kind of a quarterly run rate, higher, lower, flat year-over-year?

I would say on a run-rate basis, I think you are relatively flat. And you may have some lumpiness along the way. We have got an unusual number of outages in our gas fleet next year and you have some O&M related to outages. But again, that’s not going to move the needle materially.

Michael, I would say I like the way you phrased it. I always like to think about how much will G&A declined every year or 2 years so.

Understood. Thanks guys. Much appreciate it.

Thanks.

Thank you. Our next question is from Mr. Neel Mitra from Tudor, Pickering. Your line is open.

Hi, good morning.

Good morning Neel.

I had a follow-up question on the MISO capacity market. I know you got a lot of criticism from stakeholders once you moved up to $150 a megawatt-day and one of the issues is that in

I am not – I will let Hank answer this question, but I think it comes down to the market design and there is really three key principles that we are pushing that we think we will accomplish that. But Hank, I will let you go through the trip?

Certainly, also there are three primary market design issues in MISO. One is the vertical curve, demand curve versus the slope demand curve. And as you know in a vertical demand curve, there is no value attributed to any megawatts in excess of the planning reserve margin. So to the extent that assets are offering in at cost as opposed to regulated utilities generally offering in as price takers, those megawatts are going to be on reserve margin received no capacity compensation whatsoever. So as noted, our average capacity price given the 3,000 megawatts day problem in the present market design for ‘15-’16 was $59 per megawatt-day, which is insufficient to invest further. And so the slope demand curve is the first and foremost request. The minimum offered price really which serves as a buyer side mitigation is critical. And the third piece is to have a longer term planning horizon between the timing of the option in the beginning of the planning year. And presently, it’s 8 weeks, which is insufficient to make any meaningful CapEx decisions or commitments.

I think one of the key points in all of that, Neil, is that minimal offer price rule, where again the utilities, these regulated utilities are just delving in there with zero, distorting the market. And then for companies like Exelon or Dynegy, we are in there relying on a capacity market where every other participant is putting in at zero, because they get reimbursed through a different channel. And so that is really critical to making it work where you just can’t have people coming into the capacity market putting in zero, because they are compensated in a different manner.

So when we think about

MISO has adequate resources system wide and they have come out and they continue to say it. So, we are competing against regulated utilities from every other state in 14 or so states within MISO. So, I would say essentially all of them are putting in at zero. You just look at the clearing prices of all of the prior capacity options and you see it’s basically at zero. And I think it’s for two reasons. One again, they are fully reimbursed for 100% of the generation via another way, And I think the other aspect is I can’t imagine they would want to go back to their local PUC and say, we didn’t clear all of our megawatts, because they are not needed. And that’s probably a bad message going back as they are getting reimbursed for it from all the customers within the state. So, I think essentially, it’s only the competitive guys that are putting in a real price.

And Neil, one factor to keep in mind also is that some capacity is able to be imported into

And I would say that my discussions with the legislature within Illinois, they are starting at a real appreciation that the design of Central and Southern Illinois is putting their jobs, their economic base at risk, and it needs to be changed. And the Illinois Commerce Commission has two work sessions coming up to address this. MISO is looking for their recommendation from the ICC as well and we are certainly working with legislature on what we think our proposed legislation could possibly look like. That would straighten this out.

Great. And last question, in California, with the 3-year RA agreement with Moss Landing how do you look at that market now? Is it something you see yourself staying in or are you going to try to remarket the assets maybe not through an auction process, but just maybe reaching out to potential buyers?

Yes. First thing I would say, Neil, is that the capacity awards out there are three 1-year annual capacity products. It’s not a one 3-year contract. It’s three 1-year contracts, if you will, in terms of the recent auction. And I review it as it provides more clarity, certainty around the economics of Moss Landing and we are still waiting – we will hear later this quarter on where the rate case is settling out. And I think once you have got clarity on all of those things, there could be some bilateral discussions at some point. California is not a market that we want to be in for the long haul. It’s a market that’s changing rapidly because of the obviously all the renewable efforts and longer term if you don’t have a fleet of speakers, you are probably at the wrong fleet for California. So for us, California is not the place that we are going to be investing money.

Thank you very much.

Thank you. Our next question is from Mr. Steve Fleishman of Wolfe Research. Your line is open.

Yes, hi Bob. Good morning.

Hi, Steve.

Hi. Just on the cash available and that rough range in 2016 and maybe even thinking beyond that, kind of what’s your kind of priorities of how you are going to use that cash?

Steve, I said I want to talk to the board about. I think what they will need to be looking at is looking at our leverage, looking at our share price, looking at our various opportunities. But I would certainly say that one of the things that’s clearly on the table is part of that it’s maybe more so than what we looked at this year is making sure we have got the balance sheet positioned the right way and we are continuing to trend in the right direction. So, I would say it’s a combination of looking at where is our high yield debt trading in the marketplace? There are some opportunities for some open market repurchases. They have potentially, potentially some more share repurchases. I mean, I think probably the main two priorities, because anything else around the portfolio tends to be – we are not a buyer of single assets, that’s kind of the way that I view that for this company. We bring the ability to integrate platforms into our platform in a very cost effective measure. Buying a single asset does not create synergies and I think it actually puts pressure on the balance sheet ends up using liquidity, putting incremental leverage. Next thing you know, you are refinancing down at the project level or asset level creates a balance sheet with cash traps. So, I would view it’s really a decision between – at this point, my main two priorities for that was probably between the right balance between debt and equity.

Okay. And then just for the – in MISO just for this next auction between stuff you are sending to PJM and retail and all that stuff, how much capacity is actually available to sell in the next auction?

So, we have approximately – we have 7,000 watts of installed capacity. You cap with about 6,400 and so at present we have about 3,500 megawatts to place for the planning year. A portion of it will continue to pursue all of our channels, which is we expect more retail activity. There are ongoing multi-year bilateral conversations or wholesale conversations. There is some bilateral brokered activity. And of course, the exports, everything else will go into the option, so out of the 3,500, it will be able a function of how successful we are in the other channels to market.

Okay. And then just lastly just on the Wood River shutdown, I assume maybe you just give a little flavor of what that asset was doing and what I assume their savings from shutting that down?

Yes, if I look at it over a longer period of time see when I think about a recent completion of our 5-year plan, that’s Wood River, depending on your assumption of different market factors and the like the negative free cash flow burn on that was in excess of $50 million.

It was actually higher than that. It was closer to $100 million.

So, any – call it $80 million to $100 million is my guess...

Yes, between negative EBITDA as well as CapEx.

Okay. And just, I mean, are there more assets like that where you have negative cash flow if things stay like they are, if things don’t change that you would potentially need to act on?

Steve, I think that’s an important question. When we come through this next auction, in April for MISO, we have the situation where we have got assets still that are not clearing and not getting any capacity payments. It clearly puts assets at risk and there could be additional retirements if we are not getting the right price signal. And that’s why pressing upon the State of Illinois and the like that we have really got to get urgency around getting the designs proper, because we are not going to let our shareholders absorb these fiscal losses of these plants, because the market is not designed in the right way. We have to take action on these things. And the next point in time, the measure of that will be what happens in the upcoming auction this coming spring.

Okay, thank you.

Thank you. Our next question is from Mr. Mike Wartell from Venor Capital. Your line is open.

Hey, Bob. How are you doing?

Hi, Mike.

Quick question on the IPG bonds, just wanted to get an understanding, obviously, they haven’t fared as well as your holdco bonds. The 18 maturity trades at probably around a 14%. And as we look forward to kind of refinancing that out, I wonder if you could maybe touch upon your thoughts as to how you think about that?

I would say two things about that, Mike. First of all, I mean anything that we do at the genco level and that our day-to-day decision making is completely around what’s the best decision to make for the bondholders of genco. And when we look at the cash generation capability of all of our facilities and specifically as it relates to genco, we will always look at what’s the best decision to improve the liquidity for the bondholders and to make it re-financeable in 2018. And without showing our hand too much on some of our ideas, we have ways that we think we can strengthen the collateral package for bondholders or through a refinancing that makes the fleet very re-financeable for 2018. So I mean we are very optimistic that we are going to be able to refinance the ‘18s. We have got liquidity in the box down there now and it really comes down to what’s the best way to optimize that. And we will do what we need to do to make sure we are successful in refinancing it.

Okay. Thanks Bob.

Thank you. Our next question is from Mr. Praful Mehta of Citigroup. Your line is open.

Thanks. Hi guys.

Hi Praful.

Hi, I had a quick question also on coal plant life and really, it’s around – if you have gas prices the way they are right now and if in PJM you have new gas coming in this replacing inefficient peaking units, how do you see as environmental compliance costs increase as you have laid out in your notes as well, how would you see asset life for coal plants in PJM as well going out if gas were to stay around these levels?

Well, I think it’s clearly a scale play. I mean the smaller units will struggle. Specifically our units, I mean what we are saying particularly when you think about the Ohio units and Kincaid is that they have a good level of scale, they are environmentally compliant. They are receiving excellent capacity payments within PJM, which is obviously very helpful as well. And the view is that they are – particularly Ohio again, has the economic hours. They just have to get the reliability. So the type of assets that are going to struggle, I think for the balance of the decade in the market or it’s going to be nuclear and it’s going to be peaking units that don’t have the capability to meet the CP requirements. But the coal units will have the right level of reliability and functionality and economics to continue on. I don’t see any risk of our Ohio units being subject to retirement.

Got it. Thank you. And then in terms of gas units, clearly you have had a great quarter in terms of capacity factors and spark spreads. If the capacity factors being at these levels, 95%, 94% levels, are these sustainable for CCGTs or do you see them designed to run at these levels or if they can continue to run as base load units, do you see any risks or unreliability at some point?

No. I mean, we have our long-term service agreements with GE. And when they hit their scheduled maintenance based upon run time or start time or whatever the metric is given the situation, the maintenance is done. So I think the most would say that the most difficult time for a combined cycle assets is when it’s actually starting up. And once they are running, they are just running and the units have a high level of reliability and we don’t see any issue whatsoever with that.

Okay, great. Thanks so much, guys.

Thanks.

[Operator Instructions] Our next question is from Mr. Mitchell Moss from Lord, Abbett. Your line is open.

Hi, I had a question, I want to understand this IMA metric that you referenced in the press release, just because it’s – I am looking at Slide 7, the fleet performance of your presentation. And if I compare that to the IMA, is that – I mean, how can I think about tying those two together, is it sort of the light blue and is it like the dark blue divided by the dark blue plus the light blue, is that the IMA?

First of all, the IMA is basically the design that when the asset is available to run, how many economic hours did it actually answer the bell. The Slide 7 disclosure shows – I think the IMA gets caught up in all of this because the uneconomic hours would be kept separate from the IMA calculation. So it would really just be around the light blue and the dark blue that would be influencing the IMA.

Okay. And so if I look at the Newton plant – for Newton and Joppa, it looks like those are the ones where they had a relatively high uneconomic percentage and you mentioned how Joppa has – you are working on a new rail agreement or you have a new rail agreement in place, what are some of the factors that we can think about for Newton, perhaps that could hopefully reduce that uneconomic – bring that down in line with some of the other coal plants?

Yes. I mean, the primary benefit for Newton is going to be we are addressing congestion, and I will let Hank speak about that for a moment on what we are doing there.

Sure. So Newton has suffered from some congestion, in part due to the ongoing MTEP projects, the big transmission projects have come across the state as well as routine maintenance. And we have been working closely with MISO and the transmission operator on a particular – a generation runback or operating guide where as a basis or congestion mitigation measure. It was intended to be a temporary measure where we would provide operational flexibility to the system in exchange for removing some of the contingencies, thereby increasing or excuse me, decreasing the basis between the Indy Hub and Newton. Along the way, through a lot of negotiations and discussions, what’s happened is the line work that was required in this particular case to improve the basis has been accelerated by 2 years to 2.5 years and actually went into service October 28. So what was a temporary mitigation measure really only lasted for a short period of time, but it did result in the acceleration of some work there, so we expect congestion relief to be meaningful and only time will tell but we expect congestion at least to be meaningful and to provide an uplift to the economic hours for Newton with immediate effect.

Sorry, immediately – so into the fourth quarter and the first quarter winter, you should hopefully see some more economic hours at Newton?

Again, it remains to be seen, the true economic impact of it. But there is clearly a – there is a strong view that the basis – we will experience basis relief and it’s only been a few days or a week we already have. But we need more time to truly measure that, but that’s certainly the expectation.

I mean, can you give us a sense on how much of a different basis is it for Newton versus some of the other coal plants that they have been experiencing?

I don’t have that off the top of my head, I am sorry. There has been basis issues around Coffeen and Newton. Those have been the primary vendors, we have seen basis improvements across the DMG fleet in part because of the Baldwin Transformer work, and there is additional re-conductoring that’s part of that investment over the next 18 months to 24 months. The Coffeen and Newton have borne the brunt of the congestion issues and we think we found a real solid solution or partial solution at Newton.

I would say just not having all the empirical data in front of me, but just looking at the on-peak pricing every single day, it’s not unusual to see Newton on-peak hours clearing in the day ahead market $5, $6, $7 lower than our coal assets to the North. There is a north to south separation that tends to happen. Newton tends to be on the low end of that. And again, you are seeing $5 plus on a regular basis on peak pricing in the day ahead market.

Okay. And on Slide 19, when you talk about freeing up some collateral, how much of that collateral is tied to low gas prices, so if gas prices go back up, do you – do any of your collateral requirement change?

So Mitchell, what we tried to communicate here is that what we have really done here is not necessarily reduce the potential collateral calls. What we have done here is to convert how we satisfy those collateral calls when they come. And so historically around gas purchases, those are done under our first lien collateral arrangements, but only really up to a certain threshold. And beyond that, we need to post collateral immediately, the same day with our gas suppliers. Historically, what we have done is we have used cash, because it takes two weeks to negotiate LC forms and all that kind of thing. And so we have used cash for that purpose. And as a result, we always needed to keep extra cash on our balance sheet just in case we would need it to satisfy those collateral requirements. What we have done now is we were actually reached out to all of our major gas suppliers and pre-negotiated LC forms. And in fact, we have even issued initial letters of credit to them in very, very small amounts, but we have those out there to where when that same day collateral call comes, instead of having to give them cash, we can simply call our LC issuing bank, have them change the number on the LC and issue it same day. So, what that means is, is that cash that we have historically kept on our balance sheet for this purpose can now be reallocated to other purposes, because what we have done is we have transitioned that collateral risk, if you will, that liquidity risk, over to our revolver and away from our cash balances.

Okay. And is that then – does that change the, I guess, any of the risk or commitment factors that go into thinking about bidding behavior around CP?

Not at all. It’s just a matter of just what’s the most efficient collateral. So, it has no impact whatsoever on that.

Okay, thank you guys.

Thank you. Our next question is from Mr. Eric Lee from Caspian Capital. Your line is open, sir.

Hey, guys. Just had a follow-up question on IPH, would you be able to expand on what you meant by potentially enhancing the collateral at the Genco box and how that might look, for example?

Yes. Eric, I think it’s probably premature for me to get – I am already getting a lot of nasty looks from my group here, but it’s probably premature to go into that. But certainly, when you look at the IPH enterprise, it has a retail business and there is – it has sister plants in Duck Creek and Edwards and they all kind of work as a package together. So, it’s one of those things where we need to think about what’s the best way to support the Genco operation. You have got long-term power purchase agreements between all of these parties. So, at some point, we would need to try to untangle all of that and create what’s the most efficient structure for the different entities within that entire complex. But I can’t really – I don’t really – it’s probably premature to get into too granular at this point.

Would you consider perhaps...

I am sorry, Eric. You broke up there.

Bond repurchases at that box or was it your comment earlier perhaps more on that?

I am sorry, Eric, I missed the first half of your question. I think you are asking, would we consider debt repurchases at the Genco level versus the parent level? Is that the question?

Yes, that was the question.

When talking earlier about the – any potential repurchases up at – with the available cash that’s at the Dynegy level. So that would be Dynegy level, parent level, decisions around debt versus equity would not be at the Genco level. We continually say that the parent company is not sending cash down into the IPH complex. So then the solutions for Genco and IPH will come from within IPH and Genco.

Okay, great. Thank you very much.

Thanks.

[Operator Instructions] And our next question is from Mr. Michael Lapides from Goldman Sachs. Your line is open, sir.

Hey, guys. Apologies. Quick follow-up for Bob, Hank, can you give any disclosure about hedged pricing? You gave volumetric disclosure or percent of generation. Can you give me any disclosure about just kind of directionally where hedged pricing kind of resides? And if there are some parts of the fleet where you are more hedged within coal co or gas co than others?

Sure. I guess, there is multiple things to talk about here. I appreciate the question. One is our hedging strategy is driven by – the overlay is our view of the impact of tightening reserve margins on the system that when in periods of high demand, the volatility will increase and that overall prices will increase and that will be reflected in the forward market. Regrettably, with the milder weather this summer, the system wasn’t tested. And certainly, it doesn’t look like its getting tested in early November. But when high demand periods come, we expect appreciable increases in volatility and price. And when we look at our hedge profile, I think it’s important to keep a few things in mind. On Page 23, there is a breakdown of our gross margin composition in 2016. 39% of our gross margin is locked in through capacity payments. We benefit greatly from our critical mass in New England and in PJM in the form of capacity payments. And we are certainly encouraged by what we are seeing in New York. Just as a sidebar, the 2017 capacity market has increased by $0.60 to $0.70 per KW a month in New York in light of the Fitzpatrick retirement announcement. And carrying on, on Slide 23, 26% of our commodity – or gross margin is in the form of hedged commodity exposure. We have 18% in un-hedged sparks and 17% in un-hedged coal fleet. We will talk about the un-hedged sparks for just a moment. Over the course of 2015, those spark spreads throughout the Eastern Interconnect have widened. And we view our open spark position with purpose and that is that it’s a defensive play against declining natural gas prices. Gas prices are dropping off faster and in larger proportion than power prices. Power prices are stuck, because there is a number of expensive, high heat rate units or units that are burning expensive cap coal that are setting the price. So, we view our un-hedged spark position as a defensive position against gas and again it’s been expanding over the course of 2015. 17% of our gross margin sits on our un-hedged coal fleet. And there is some – a few – there is a little bit of color I would like to provide around that. Part of that is our Brayton Point facility. Brayton Point, as you know, is on a glide path to closure. So, there are – there is limited CapEx investment in the facility and the reliability factor becomes an issue. So, there is a substantial portion of that asset that we won’t hedge. We will just take it into the daily markets, so that we don’t get stung in a cold spell with finding ourselves short at the very far end of the pipe in a volatile situation. Further, in our coal fleet, specifically in MISO, we are – we try to minimize our correlation risk meaning the time – the relationship between our traded hubs and our busbar. And we reach our limit at some – in the 50% to 65% range depending on the availability of FTRs and busbar sales and our retail activity. So, there are some boundaries around what we can accomplish in our coal fleet. Just to add little bit of color, the coal hedges there are – about 55% of the on-peak volume is hedged. At IPH, all the hedges come through our retail business for collateral reasons and depended upon retail business flow. And what we have – we found really interesting and intriguing is the off-peak spark spreads in PJM and New York. We have got 45% to 50% of our off-peak volumes hedged in those areas for calendar ‘16. They have widened out to substantial levels. So, that’s a long way around the block to give you some color on where we sit.

Got it. Thanks, Hank. Much appreciate it.

Sure.

Thank you. Our next question is from Mr. Praful Mehta from Citigroup. Your line is open, sir.

Hi, guys. Sorry, just one final follow-up question. On your un-hedged sensitivity on Slide 23, just wanted to understand you have $0.50 of movement in gas upwards leading to $107 million EBITDA uplift. Is that linear as in does it go both ways or how does that change? I know we have discussed that in the past. And just quickly on the gas segment declining in EBITDA as gas goes up. It’s good if you could just touch on that as well?

Sure, Praful. The sensitivity that we have provided is linear, up and down. And when you present it this way, you need to choose one of those for the change in gas, because as an example, the gas segment goes the other way. So, you need to know how to represent that on the slide. When we kind of step back just from a process standpoint, where do these numbers come from? I think we discussed it to some extent at Analyst Day, but, specifically for this slide, what we did is we looked at over the last 12 months how forward gas prices and forward power prices have traded in each of these markets. And as gas prices are changing, how are power prices changing as well and looking at those relationships over that 12-month period. And so then applying a $0.50 change in the delivered cost of fuel at each of the locations and coming up with the numbers that are represented on this slide, I think directionally and intuitively, it makes sense to me that the gas segment is moving in the opposite direction of the coal segment. And so there is a level of offset there, certainly on an un-hedged basis and that flows through when you apply the level of hedging that we have at each of the segments. That’s where you come up with the hedged sensitivity. So, I don’t know if that’s helpful or if you need some additional color on where these numbers came from.

I think that’s really helpful. I appreciate it. Thank you.

Sure.

Thank you. Our next question is from Mr. Jeff Cramer of Morgan Stanley. Your line is open.

Hey, guys. Good morning. Just a few follow-ups on the discussion, the thing about 2016 guidance what if any have you included from PRIDE Energized?

Yes. Jeff, we included our full $135 million for PRIDE Energized in our 2016 guidance. And you see that, it really kind of runs through really through the income statement depending on where those initiatives are whether that’s in gross margin, G&A or OpEx. But really all of the PRIDE initiatives that we have identified are in there and it totals $135 million.

Okay. So, we will see a full year run rate of that then next year?

That’s right.

Okay. And just quickly on Wood River, given you have got a few coal plants kind of in Central and Southern Illinois is it safe to say that, that was the most unprofitable kind of on the outlook? And that’s why – also why it was chosen.

One of the things that impacts Wood River is congestion as well down in the southern portion of the state. So, while it’s cost structure is okay and it doesn’t get impacted on the power price, now it’s also a plant that has – that will need further environmental investment as well. And one of the things that is different this quarter versus last quarter, the ELG rule comes out, finalized and it now applies to units that are greater than 50 megawatts and not just units greater than 400 megawatts as the market had anticipated and much more in line with what we thought would be the outcome. So Wood River with two units below the 400-megawatt threshold but above 50, it impacts their environmental cost as well. So it’s a combination of congestion on the pricing and the environmental spend that that plant would have to make over the next few years. And again, all into that goes the fact that we know that there is a number of megawatts that won’t clear the auction. So when you think about those three things together, Wood River was the unit selected for retirement.

Okay. Thanks. And maybe for Clint, it seems like there is a renewed focus on repaying debt here, has your leverage – your targeted leverage metrics changed or could you just remind us what those are?

Yes. I think what we have said before and what remains true today, is that our objective over the medium-term is to migrate closer to BB type of credit metrics. And as Bob said a little bit earlier, as we think about our 2016 capital allocation program, we will need to give that some thought and be sure that we continue to move in that direction. So I don’t think there is really any – has been any change in the direction that we want to go in and what we like to see from our balance sheet. We just need to continue to monitor that over time and make decisions as appropriate.

Yes. And I would like to reemphasize that point Clint just made is that when we make a decision on capital allocation, we always looked at the balance sheet to ensure that balance sheet is in an area that we are comfortable on. And that is the first decision before we make the decision on the repurchase element. So that’s just part of the normal ongoing thinking. I don’t want to signal the changes suddenly we are going to be going after all debt and no equity or all equity and no debt. It’s the same way that we have been doing it all along and looking at both and making the right decision to make sure we have got it calibrated the right way. And I don’t want to leave the impression that that suddenly has shifted from before. And that’s a decision that we will take to the Board once we get through the winter and what our recommendation is on what we actually do with the available, uncommitted cash and make the decision at that time based upon the facts and circumstances then.

Okay. Thanks guys. I appreciate it.

Well speakers at this time, we have no more questions on queue. So I will give the call back to you.

Great. Well, thanks Bob. And again, thanks everybody for calling in and participating in the call this morning. Thank you.