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Hello and welcome to the Dynegy Incorporated Third Quarter 2016 Financial Results Teleconference. Please note that all lines will be in listen-only mode until the question-and-answer portion of today’s call. [Operator Instructions] I’d now like to turn the conference over to Mr. Rodney McMahan, Vice President Investor Relations. Sir, you may begin.

Thank you, Jo. Good morning, everyone, and welcome to Dynegy’s investor conference call and webcast covering the company’s third quarter 2016 results. As is our customary practice, before we begin this morning, I would like to remind you that our call will include statements refelcting 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, our Executive Vice President and General Counsel; Marty Daley, our Chief Operating Officer; Sheree Petrone, our Executive Vice President of Retail; and Dean Ellis, our Senior Vice President of Regulatory Affairs. We posted our earnings release presentation and management’s prepared remarks on our website last night. Following a few brief opening remarks, we will devote the bulk of our scheduled time to your questions. On the strategic front, we continue to wait for final approval to close both the ENGIE acquisition and the Elwood disposition. All financing for the ENGIE transaction is in place and our integration teams are ready to move, as soon as we receive their requisite approvals. Virtually, all integration activities have been completed. We remain on track to deliver synergies above the $90 million target highlighted at deal announcement, with the second round of synergies to be announced post closing. We have also continued to make progress on restructuring our Genco subsidiary, and since our last investor call on the subject, we have entered into a restructuring support agreement with Genco and an ad hoc group of Genco bondholders, representing approximately 70% of the outstanding Genco debt. To implement this agreement, Dynegy plans to launch a simultaneous exchange offer for the Genco notes in a prepackaged Chapter 11 solicitation later this month. Our goal of bringing the company’s overall net leverage to 4.5 times by 2018 remains a priority, and the Genco restructuring is a significant step forward. In addition to significantly reducing debt, this restructuring also lowers interest expense and simplifies the company’s capital and organizational structure. Financially, we are affirming our 2016 adjusted EBITDA guidance range of $1 billion to $1.1 billion. And our free cash flow guidance range of $200 million to $300 million as the year is materializing as expected. And during our previous earnings call, we indicated that our delivered natural gas costs for Ohio combined cycle plants had been better than expected, and we would continue to monitor as the year went on. While we are still seeing lower than expected delivered prices, that benefit has declined slightly since the summer due to power bases between our plants and their liquid hubs. We are also initiating 2017 guidance with an adjusted EBITDA guidance of $1.2 billion to $1.4 billion, and a free cash flow guidance range of $150 million to $350 million, based on commodity curves as of October 12, 2016. As we highlighted in the investor presentation, there are a few important items to note in the field of 2017 guidance. These include $30 million in O&M expense related to plant shutdown costs. These costs include such items as severance and decommissioning and are largely driven by Brayton Point, which is scheduled to retire at the end of May of 2017. This $40 million in major maintenance and capital removal cost for the ENGIE fleet, as 2017 is forecasted to have a higher than normal number of planned outages. Our initial ENGIE guidance ranges included this, however, treated it at the time as CapEx consistent with ENGIE’s accounting policy and forecasted cost structure. However, as the fleet is integrated into Dynegy and our capitalization policy is applied, these costs moved O&Ms. This is simply a reclassification of dollars and not a real economic change. And finally, there are $11 million in ISO-New England capacity revenue deductions that are scheduled for 2017, associated with peak energy rent charges at ISO-New England. As we look beyond 2017, we expect improved results for 2018 as the fleet returns to a more normalized outage schedule. The shutdown costs are completed and ISO-New England and PJM capacity revenues escalate. Going into 2017, we expect gross debt to decline by $1.1 billion. This reduction is driven by the previously noted Genco restructuring using the Elwood sale proceeds to pay down paid the ECP obligation and meeting our scheduled debt maturities. Further deleveraging will occur in 2018, with more than $200 million of scheduled debt amortizations, increased EBITDA driven by higher capacity payments, and lower planned CapEx and O&M costs. Given these factors, a 4.5 times net leverage ratio by the end of 2018 remains our target. At this point, Jo, I would like to open up the session for Q&A.

Thank you. We will now begin the question-and-answer session over the phone. [Operator Instructions] Our first question for today’s all is coming from the line of Mr. Julien Dumoulin-Smith of UBS. Sir, your line is now open.

Hi, good morning.

Good morning, Julien.

So, a quick question, if you can. I know you kind of went through the list here. But could you summarize what is the total here of items impacting 2017 as you go to 2018? I know you laid out the $30 million of kind of Brayton that’s going away, the major in maintenance obviously is a reclassification. But how much in terms of like the outage impact, if you can quantify that in 2017, reverse back to what a quote unquote normal level would be in 2018 and what, I suppose in aggregate, should that be?

Hey, Julien, hi, this is Clint. So in 2017, you’ve got about $35 million in elevated outage O&M cost, and that’s associated with major maintenance, capital removal, other O&M items. So on a normal kind of run rate basis, you would expect that to be on average about $100 million a year. In 2017, that’s $135 million. And so about a $35 million elevated spend in 2017. Now, I would also say that as you roll forward and look at outage schedules in 2018 and 2019, they are lighter than in 2017 and they are likely below that long run rate. So you will kind of go back and forth depending on your outage schedule, but I would say long run rate is, call it $100 million for those type of items, and you are about $35 million above that in 2017.

Got it. So, if you think about year-over-year, you are at least $65 million higher just adjusting for the retirement and the O&M, realistically something higher than that, but again, it obviously oscillates. Just to clarify also, just a strategic question here. Are you reflecting the additional synergies from the ENGIE transaction in that – in your 2017 guidance, to be specific? And the secondly, a strategic question here as well. We heard from some Ohio peers of yours that they are looking at co-owned assets. I’m curious how much could you potentially benefit from cost savings, shall we say, if you were to fully own some of those co-owned assets? Is there any kind of sense that you can provide?

Julien, your first question regarding the synergies, what’s built in really is the first round of announced synergies. So, that’s the $90 million and there’s a split there between what’s EBITDA and capital, if you will. There is a second round of synergies that we will announce once we get through the closing and verify certain things, primarily the up rates, which would be the, probably the biggest contributor to a second round of synergies, things of that nature or anything beyond that $90 million at this point in time has not been incorporated into the numbers. I think if you – so, your second question with Ohio to the extent that if there is, I think you said there’s a consolidation of ownership interest saying that if we have that as an example, 100% is

Yes, exactly. How much would that improve customer just spill [indiscernible], but, A, is that an interest? And B, if it is, how substantial could savings be there like I mean, kind of round numbers?

Well, I would say that we are highly interested in consolidating our ownership. And when I say that, it means that, we would like to own a 100% of

Got it. Excellent. Thank you.

Thank you. Our next question coming from the line of Abe Azar of Deutsche Bank. Your line is now open.

Good morning.

Good morning, Abe.

Good morning. With the recent sharp decline in gas prices, how different would the generation picture look today versus what you outlined on Slide 25, and does your hedging to-date limit any upside or changes there?

Well, I’ll take this first question and Clint can tag team on the second. But – so, yes, there has been a decline in energy prices as you go back through the year. If we looked at where would guidance be if we had this discussion going back, say, the first quarter of last year, I mean, we were – for the first-half of the year, essentially, we were actually above the range that we put out today. And if you go back, say, to the first quarter, you are well above the range. So, the thing with this portfolio right now is that we’ve got ENGIE coming in with 35 megawatt hours opened. And quite honestly, I wondered a guidance range out there that was very conservative. And if there is any adjustment during the year, it’s not going to be downwards, it would be upwards. And we think we’ve left ourselves plenty of room in this guidance range to absorb any negative factors that may arise during the course of the year, which would be unseasonably warm winter would probably be the biggest threat. But again, if you look back on how fast these curves can move and then you apply that to the amount of megawatt hours that we have open, there is volatility in our number because of that. But on the other hand, we don’t want to go out and hedge the ENGIE portfolio at this point in time, because you just don’t know when FERC will actually move, right, then you don’t want to be in a situation where you find yourself in a short position. I want to close ENGIE first, hedge it second, and not the other way around. So I mean, with that business, Abe, why don’t you repeat your second question to make sure that, in case I lulled Hank and Clint asleep with my answer earlier.

That addressed both parts of that.

Okay.

And just separately, can you discuss your strategy to get to the 4.5 times that target by 2018? Because on my math, you guys have pretty significant year-over-year increase in EBITDA from 2018 over 2017?

Hey, Abe, excuse me, this is Clint. So, yes, and again, when we target kind of a mid-4 type of ratio, remember, it’s net debt to EBITDA. And so, we’ve always kind of looked at 2018 as a significant contributor to getting to that type of target. And so as we roll through the end of 2016 and into 2017, we would expect to have $400 million or $500 million in cash on the balance sheet, year end, after we close the acquisitions. And then as you roll through 2017 then roll into 2018, you’ve got a number of factors going on. So in the presentation, we’ve shown that there’s about $1.1 billion in growth that is coming off the balance sheet by the end of 2017 as you roll into 2018. There is about another $225 million in gross debt coming off the balance sheet. When you then look at what the EBITDA is expected to do and some of the changes in not only EBITDA but cash, as you roll into 2018, you’ve got about another $250 million in capacity revenues that are coming your way from PJM and New England. You’ve got about, call it a $75 million improvement in O&M. So that certainly should be additive when you look at our maintenance CapEx, and we’ve said that it’s elevated in 2017. At this point, based on our outage schedules and plans, we would see that coming down by about $100 million. So from a cash standpoint, you will have some – potentially have some additional ELG spend in 2018, but those decisions will need to be made later as to whether they are actually made. But you can see that just with those factors, your EBITDA should be improving meaningfully, and I’ll kind of keep what expectations are around power prices and sparks, because those are changing every day. But just those factors alone contribute meaningfully to an improvement in EBITDA from 2017 to 2018 and contribute to cash, which factors into your net debt. The CapEx savings again contributes further cash into that net debt calculation. So as we kind of roll forward into 2018, between the EBITDA improvement, between the cash build between now and the end of 2018, and the debt reduction that you already have wired in, we can see a pathway to getting pretty close to that target, and there is a possibility that, maybe some other factors come into play, whether it’s assets sales, weather, et cetera, other things. But again, those are kind of the main building blocks that we see between now and the end of 2018 that certainly get us into the range that we are talking about.

Thank you.

Thank you. Our next question coming from the line of Steve Fleishman of Wolfe Research. Sir, your line is now open.

Yes, hi. Just a couple – just to kind of maybe close the loop on the question just before. When you talk to the 4.5 times in targeting, do you use kind of the current forward energy price environment in thinking that, or are you assuming some kind of recovery?

Yes, Steve, we typically are looking at market prices for the next couple of years and obviously, those are changing throughout the year as you are doing the calculation. But that is generally what we are looking at.

Okay. So you think you can get to a target of 4.5 times range on kind of something close to the current forward outlook?

Well, I think what we specifically talked about is 1.5 times to 2 times turn improvement. I think that that based on what we have seen and again, if you look at it over time, that seems to be achievable and are you in the 4.5 times to 5 times, and to get to 4.5 times, there are some other things that you need to do? Certainly possible. And so, there may be some things that we need to do to supplement that. But I think we get much closer than where, maybe 2016 numbers or 2017 numbers would imply, once we get to 2018 and roll through the year.

Okay. And then just in 2019, 2018 at least, right now looks like it’s a bit of a peak capacity period. So how should we think about beyond that? I know a lot can happen by 2019. But just are there things that offset the decline in capacity going forward to 2019?

Hey, if you’re going to look at them on a net debt basis on where our leverage is, I think, as Clint highlighted earlier, CapEx ticks down for the couple of years after 2017. So, your cash generation, so, on a net debt basis, you continue to have the right momentum to lower your net leverage. So, when have an uptick in 2018 around EBITDA, because you’ve got some O&M cost to go away and you’ve got the higher capacity payments coming in in 2019 with, again lower CapEx, you’ve got a little of cash flow, so your net debt continues to help maintain your leverage at the right level. But you’re, I mean, you’re right. The biggest item in all of that is you’ve got 140 million megawatt hours of generation, so it doesn’t take much for EBITDA to move an awful lot of it, the change is $1 to $2 alone, you can see the impact of $150 million to $300 million of EBITDA.

Got it. And just you had some really interest – good updates on the different states, like New York, Ohio and Illinois on the kind of nuclear subsidy issues. Could you maybe, just on New York, it seems like the debate is the zec [ph] versus rec. And maybe just clarify from the litigation you filed kind of how you see it versus what Exelon and others are pitching? And then in Illinois just, it sounded like you are kind of cautious about something getting chance of some legislation getting done there. Just how can something get done that works for you, but also works for environmentalists?

So, Steve, I will start out and then Dean Ellis will help me through this too. But on the New York situation, we see a substantial difference between the zec and the recs. I mean, recs are fully tradable, available to everyone, can be traded across state lines, whereas the zec is specifically for these three locations. You’ve got to prove you have a financial need, and it impacts the wholesale price formation, otherwise, these plants would shut down. So we clearly view that as very different from a rec and it’s is absolutely tethered back to wholesale price formation. Dean, would you add anything else for New York?

I wouldn’t add anything else, Bob.

Okay. And then for Illinois, I think the worst case basis for Illinois is this, if somehow Exelon is able to get something done for nuclear that sort of replicates what’s happening in New York, it doesn’t seem like that’s going to happen. We’ve been trying to work constructively with the state on dealing with the price formation of

Great. Thank you.

Thanks.

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

Good morning, guys. Thanks.

Good morning, Jeff.

Could you help us out – I’m just wondering if you could help us out with 2017 guidance just in terms of how big is ENGIE as part of that? What’s the contribution there? And just confirming what you said, the $90 million in synergies that is included in the 2017 guidance?

Correct. Yes, Jeff. So when we originally announced the transaction, we put out an adjusted EBITDA guidance range for the ENGIE fleet, I believe it’s $425 million to $475 million. Now since that time, the EBITDA and what’s reflected in our guidance for 2017, the EBITDA is about $100 million, $110 million, and actually lower than the midpoint of that range, kind of give or take. But that’s generally the order of magnitude, and it’s really comprised of two things that have changed. The first is just a re-class of O&M from CapEx into O& M, and that’s $40 million. So that’s just a left-pocket, right-pocket, as Bob said a little bit earlier, there is no cash impact. The balance of about $65 million to $70 million is a reduction in energy margin that we’ve seen. It’s primarily in New England and PJM, a little bit in Texas, but mostly in PJM or New England.

Okay, that’s helpful. Thank you. And on the goal to delevering, you mentioned that there could be some other item, such as asset sales. I guess, how seriously would you consider that? And is independent still thought of as a potential candidate, or any thoughts about what assets that might be?

Jeff, we are looking at different options of single asset or maybe bundling it with a couple of assets. But certainly, if we’re going to do it, it has going to be deleveraging. So, the price needs to be at a point where you are getting at a multiple that’s much higher than our leverage multiple, if you will. So we assessing now. We are reviewing the assets, we are working with our commercial floor on which ones would be the right ones to make sure that as – if we do anything along those lines, we are not weakening the portfolio. We’re not doing anything that takes kind of the gems from the overall portfolio. But if we were, we go in proceed and do something, we would do that likely after the end of this year going into next year’s. I think there has been a lot of assets on the market of late. And I don’t think right now is the best time to jump into that fray. So we are looking more on what are the right assets to think about in terms of doing it. And I think if I were to maybe go into a little bit more detail on what that could look like, I mean, certainly we don’t have scale in New York. So it’s a potential that Independence – but certainly they’re – we need to get through a strong winter just to, again, demonstrate the earnings power of Independence. And then I think the other thing we would look at is, we’ve got a pretty big collection of peakers in PJM, as well, is there something there that we should consider? But again, anything that we do, if it’s not a deleveraging event, then it’s probably not real interesting to pursue. So that’s kind of the internal analysis we are going through at the moment.

Understood. Okay. And then lastly, the recent $500 million was going to be used to pay down term loan. I don’t think that has happened yet. Is that still forthcoming, or are you thinking maybe that cash would be used if there is some consolidation of the assets in Ohio from an ownership perspective?

No, it’s going to be used to pay down the debt. We are just waiting to, we keep thinking we are going to be closing ENGIE in a matter of days. And certainly, economically, that may be the better way – the better place to pay down the debt, because it’s a higher debt. But we will certainly be paying down using the proceeds from the bond offering to reduce the term debt, and that will happen absolutely this year.

Excellent. Thank you.

We don’t – well, I would just say, Jeff, we don’t need to add to the portfolio. I mean, if assets are becoming available in Ohio and things of that nature, I don’t think you will see us on the acquisition trail at this point in time.

Okay. Thanks, Bob.

Thank you. Our next question coming from the line of Greg Gordon of Evercore ISI. Your line is now open.

Thanks. One – two questions, sorry, guys. First, you said earlier that because you haven’t been able to hedge the ENGIE fleet, you gave what you thought was conservative guidance that you thought would withstand some shocks. So does that mean that you’re not precisely marking the market at the midpoint? But that you put some risk adjustments in the model to take into account the fact that there’s things you can’t control until you close ENGIE? And so if I were to do a pure mark-to-market I might come up with a higher range?

Well, only the slippery question to get into. But yes, if you did a mark-to-market, you would not be at the mid-point of the guidance we put out there. You would be above that.

Okay, great. Thank you. And then the second one, just to make sure I understood, because you gave some very clear guidance on the way that cash and debt roll as you go forward. You said that you were going to end the year with around $400 million to $500 million in cash. You’ve given us how much the debt rolls down on page 20, how much the gross debt balance is? And then there is another slide where you give us the 2017 perspective free cash flow, and when I look at the capital allocation below free cash flow, at the mid-point of the cash flow guidance, is it right to just do the math and say there is not much incremental free cash in 2017 that the most significant incremental buildup in cash happens in 2018?

Yes, and I think that is the right way to look at it.

Okay, I just wanted to make sure. Thank you.

Thanks, Greg.

Thank you. Our next question coming from the line of Ali Agha of SunTrust. Your line is now open.

Thank you. Good morning.

Good morning, Ali.

First question, this retirement of Moss Landing 6&7, what does that mean financially, as far as EBITDA cash flow is concerned? And related to that, what’s the plan for Moss Landing 1&2 right now?

Well, for 6&7, we have built in some of the shutdown costs in our guidance for 2017, unless they are the two units that roll off the contract with Southern Cal Edison, so I think the EBITDA from 6&7 for 2016 was…

For 2016, you’re probably in the mid-20s?

Yes.

So that falls away and so then the plan is to then retire 6&7, we try to save some resource capacity, but the market out there is just, it’s just not a friendly market for generators.

Okay.

And sorry, Ali. Did you ask about 1&2, as well?

Yes.

So, yes, 1&2, and we will continue to look for opportunities to monetize the asset. So, the assets are receiving decent runtime right now in the fourth quarter, running well. So if we find an opportunity where we can monetize it, we will do so. But it’s again, got to be accretive.

Okay. But just to be clear coming back to 6&7, there are some embedded costs in 2017 that would be non-recurring? Did I hear that right?

There is a cost embedded in 2017 to deal with the shutdown and the severance related to Moss 6&7.

And Ali, just order of magnitude, it’s about $5 million.

I see. And then second, I wanted to clarify the point you were making earlier as it related to 2019, so as you mentioned, I mean, there is a downdraft on the capacity price. Energy prices right now are not showing an upside. So did I hear you right that directionally there may be downward pressure on EBITDA, but because of CapEx coming down, et cetera, the cash flow would be less, have I heard that right? I mean, just looking at the market as we stand here today, that there is directionally probably downward pressure 2019 over 2018?

Often, when we had this conversation, I think where somebody gets confused is that we are talking about, in calendar year of 2019, we will still have calendar year 2018 capacity prices in it. So, when you think about the capacity prices in 2019 versus 2018, they’re probably not that different on a calendar-year basis, because the planning years are split years. So we’re talking planning year may tick down, but on a calendar year, they don’t. So I think when you look at 2018 versus 2019 and roll in CapEx and the like, I don’t think you are seeing that much of a difference in cash flow. And you can’t see Clint shaking his head, but he’s shaking his head yes.

Yes, I mean, generally, they are in the same ballpark for that reason that Bob just mentioned. And again, at least, based on the current outage schedule, we would see it being pretty light in 2019. And so, what you have is is the EBITDA uplift in 2018, give or take, as you move into 2019, but what you also have is that you are continuing to generate cash. And so that again, to the extent that there is some downward pressure on EBITDA, you are on a net debt basis, you are supplementing that with the generation of cash that’s then following into that net debt calculation.

Got it.

Ali, one other thing I want to clarify, a couple questions have come up this morning as probably talking about 2017 guidance and synergies from ENGIE, the biggest synergy that’s flowing through in 2017 is around G&A, we’re consolidating the headquarters. So in terms of 2017 guidance, you’re probably picking up 50 or so million of the overall $90 million. The $90 million stretches in over a period of two to three years. So, I just want to put that clarification, there isn’t $90 million of synergies in 2017, the biggest impact, it’s just the G&A consolidation in 2017.

I see. Last question. We continue to see the transactions of assets in the private market, the TransCanada portfolio sale was announced. When you look at the kind of prices that we are seeing out there, and you look at what’s happening in the public market right now, as we speak of the Spark, is by the way, down 16%. Is the public market ever going to give you the right value for this portfolio? And is that really the right forum for this portfolio to be in?

Well, I view that as ENGIE generates and builds the free cash flow and utilizes that free cash flow in the appropriate way, and for us in the near-term, it’s around deleveraging that the appropriate value will ultimately be reflected. Certainly, I think when you think about the IPP model right now, I think some of the headwinds that we faced is really the construct of the sector, where in the country we wanted a national energy policy and we wanted competitive markets when we have a Federal Power Act, but you have state by state doing things that are not constructive to competitive price formation, and you also have the federal government itself doing the same kinds of things. And I think when you look at the IPP sector and valuations, I think a lot of the headwinds right now are somewhat self-inflicted because of those factors. And not allowing – the competitive power market was designed to bring the cheapest megawatt to the customer, and then you have the federal government and state governments, like what’s happening in New York, like what’s happening in Ohio, like what some people want to happen in Illinois. These are the things that prevent the economic generator from getting the lowest cost megawatts to the customer and getting their economic returns. And that I think is, as big of a headwind as anything that we currently are facing. But I think over time, I mean, we focus on building a portfolio that runs, we are just not a capacity play. We’ve got portfolio that generates 140 million megawatt hours that’s 70% gas that’s needed to support intermittence, or in the Northeast, where it’s running around the clock. So the cash generation and the returns ultimately will come, but it’s certainly every day you are fighting something else that somewhat is self-inflicted. And I think that, more than anything is impacting value.

Thank you.

Thank you. Our next question coming from the line of Neel Mitra of Tudor, Pickering. Sir, your line is now open.

Hi, good morning.

Good morning, Neel.

Now that you are moving to a more gas power fleet, and 2017 is a little bit of an anomaly with all of the O&M and outages, is there a certain way to look at, on a percentage basis, how you would convert EBITDA into cash flow? I would expect 2017 is definitely on the low side. If you were to kind of adjust to a normal run rate, is there a simple way to look at that?

I mean, I think we provide clarity around kind of where the segments are coming out. As far as EBITDA and free cash flow, or EBITDA relative to CapEx, I’am sure we can get back to you on kind of the right way to think about that. Obviously, the gas fleet has a much higher conversion rate of gross margin to EBITDA, and then onto free cash flow, because their OpEx and CapEx intensity is quite a bit lower than coal, so obviously, you would have much greater conversion on the gas fleet compared to the coal fleet, at least, in this price environment. But I don’t have kind of a rule of thumb for you right now.

Could you comment on maybe some of the changes that you would make that make that conversion rate higher, such as, I think you mentioned full ownership of some of the Ohio plants. Are there certain initiatives that you are looking at to increase that conversion rate at this time?

Well, Neel, I would say that that is a constant area of focus that’s really one of the prime reasons why we have our product program is to constantly focus on ongoing OpEx, on ongoing CapEx, trying to generate more gross margin out of the existing assets, and it really goes to the heart of your question. But that really is kind of the Genesis of the PRIDE program to try to convert every dollar of revenue into more free cash flow.

Neel, I would just add to that and we’re are in the middle now of negotiating some new rail contracts, as well. And so what we should be seeing is an improvement in our delivered coal costs for several of our plants. And again, what is obviously happening with the rail companies in their utilization of delivering coal that they are becoming much more price competitive. So things that are going to help us in the future that are not building to any of the numbers will be some of our rail and barge contracts that are under discussion right now for new long-term contracts. And I think once we actually get that across the line, we will be able to talk more freely about it. But we are seeing the opportunity for significant improvement from where we are today for several of our facilities.

I would also add that don’t forget that we also have already signed some rail agreements specifically around our Joppa facility that are in place and begin January of 2018. And so I think it’s just a continuation of that focus. But while there are some that are being more negotiated that should help us, we actually already have some that are in place, just have not started yet.

We think on some of these and I don’t want to go too far, except for the harder as Hank But as we complete some of these rail negotiations for some of these plants, they wind up being our lowest dispatch coal plays. To give you an idea on the benefit of pursuing new contracts right now in this environment, I think the rail companies certainly realize too that it’s in their best interest to work with us to keep these plants competitive against low-cost gas. So that’s what they are competing against, and it’s either that or they don’t deliver any coal. So it’s the right time to be working through these things.

Got it. And then I just wanted to quickly follow-up on the status of Moss Landing 1&2. Are they currently under contract, and are they both EBITDA and free cash flow positive at this point, or is there any risk of retirement for those assets? I know they are combined cycle versus the CTs that you announced yesterday?

Well, from EBITDA, they are not under contract. They are EBITDA and free cash flow positive, they have some maintenance higher up and some normal multi-year maintenance periods coming up in 2017, 2018 that takes the free cash flow down to about single digits, neutral kind of

No.

Thank you.

Thank you. Our next question coming from the line of Mr. Michael Lapides of Goldman Sachs. Sir, your line is now open.

Hey, guys, thanks for taking my question. Real quick, Hank or Bob, I would love your thoughts on some of the rule in market design changes in the New England capacity auctions, and what you think this means for auctions going forward relative to the last one or two auctions we’ve seen.

That’s a good question. There is a number of moving parts to the New England capacity market design that we are studying. And I think the general view of the marketplace is one that we share, that the range of outcomes although highly dependent upon market behavior and individual participants is somewhere in the $5 to $7 per KW month range, that’s what all the chatter is. There is currently an effort in play to change some of the dynamics in the slope of the line. And I think the bigger issue is to have the – is the longer-term outlook in terms of how does the market design incorporate the larger renewable initiatives that are out there? And that’s really the hard work that needs to be done is to put a lot of effort into accommodating and adjusting to the plans at the state level.

Got it. Okay. One other thing, just looking at the 2017 guidance, you talked a little bit about some of the O&M impact. But what’s the impact on EBITDA, and how should we think about the impact on kind of megawatt hour production that you would have, based on the curves you would normally have if you didn’t have the large maintenance outages?

Yes, Michael, we haven’t really looked at that. Keep in mind that when you schedule these outages, you try to schedule them when it is most economic, meaning that your – the value of your lost generation during the outage is minimal. And so as you think about those outages, I would think about the impact to EBITDA is more along the lines of the cost, the O&M associated with it, rather than the gross margin that’s lost, because again, that’s something that has really taken into account when scheduling these things. But as far as kind of the number of megawatt hours lost, I don’t really have an estimate of that. But just what I would want to give you is, this outage schedule relative to a normalized outage schedule and then what is the difference in generation? And then what’s the value of that generation and I just – I don’t have that.

Okay. Last item, we’ve seen over the last year, couple of years, a lot of announcements of new power plant development, a lot of guys building combined cycles. You guys doing 600 plus megawatts at brown field, but a lot of guys doing more expensive greenfield. Just curious, when you look at the marketplace over the next three to four years, do you think most of those assets actually get built, or there are parts of the country where some of those assets may be less likely to get built than others? And do you see the cycle slowing down, or do you still see a wave of combined cycle construction coming?

Michael, I think the way that I think about it too is that, we look back at history and we see a continual build of new generation that ends up ultimately replacing generation that’s retiring. And this somewhat ties to what I was talking about a few moments ago that there is a number of non-economic assets in PJM that should be retiring over the next couple of years. and that is primarily coal and nuclear. And the offset of the coal and nuclear in terms of capacity is essentially new gas. And as long as the market and PJM does an outstanding job of trying to protect their market, as long as that’s allowed to work without state interference, then I think the supply demand stays in balance in PJM and you get reasonable returns for existing generators. So I don’t think you have an issue with the market. The issue becomes if folks are successful in starting to re-regulate certain markets within PJM, which doesn’t make sense for the customer and doesn’t help the competitive design, or you get situations where out-of-market subsidies, for example, nuclear, which are being aggressively pursued that spends extraordinary returns to a company at the expense of consumers, and then again, for the economic guys out there, you are impacted by how prices are then impacted by that. So I’m not worried about the new bill coming, there’s always a self-correcting. We just got to make sure that the market design is such that the economic assets are the ones that get rewarded and the uneconomic ones don’t get out a market treatment, that’s the threat.

Got it. Thank you, Bob. Much appreciated.

Thanks, Mike.

Thank you. Another question coming from the line of [indiscernible] Barclays. Your line is now open.

All right. Thank you for taking my questions. I had two. So just in terms of your net leverage expectation, where do you see that at the end of 2017, and can you just run through it? I think you mentioned some numbers around the cash balance that you expected in 2017, as well. And the second question is really around the 4.5 times leverage target. So, do you see that as an absolute priority and what are the sort of factors that could lead you to move away from 2018, could you think about acquisitions of retail businesses as well? Thanks.

Sure. I think your first question was where do we stand on leverage at the end of this year. I think on a net basis, when you look at a net debt over, you can call at the mid-point of the guidance we put out there, we’d be about 6.8 times levered. And I don’t see it veering away from the 4.5 target. I don’t see a scenario that suggests we should veer away from the 4.5 times target by 2018. And I think as we look forward between now and 2018, we want to grow our retail business organically. We want to, obviously, run our assets and drive reliability, pursue our PRIDE program and get the most cash generation we can get out of the assets. And to the extent that, as we talked about earlier, have some slight modifications to the portfolio to assisting any of that 4.5, they are the priorities between now and 2018.

Thanks. Just to clarify, say that the 6.8 times, so that at the end of 2017?

Yes.

Okay. Thank you.

Thank you. Another question coming from the line of Ms. Angie Storozynski of Macquarie. Your line is now open.

Thank you. So I wanted to, I mean, I know a lot has been discussed about EBITDA. But probably the bigger surprise is that, even though EBITDA is rising $300 million year-over-year midpoint of your for 2017 versus likely 2016 results, there is really no improvement in cash, so, free cash flow. And I know that some of it has to do with planned maintenance, et cetera. But is this – when you compare your expectations for ENGIE’s portfolio from an EBITDA perspective, how does the free cash flow change here? Is this something you’ve seen, or is it somehow significantly worse than you had expected and that deterioration is just a function of the lower EBITDA?

Yes, Angie, this is Clint. I would say on a free cash flow basis, when we originally announced the transaction, we provided the guidance range for 2017 for both EBITDA and free cash flow. I think the free cash flow range at the time was $25 million to $75 million, with obviously a midpoint of $50 million. And that was as a result of the heavy outage schedule, as you alluded to. When I look at our expectations for that fleet in 2017, while the EBITDA has changed for the reasons that we talked about a little bit earlier, the free cash flow really has not changed meaningfully since then. As a matter of fact, when I looked at our expectations for the fleet next year, it would still be within that same range. And what you are seeing is, you are seeing a couple of different dynamics. On the one hand, as I mentioned earlier, you’ve seen some pressure on energy margins, particularly Sparks in New England and PJM to the tune of about $70 million. But at the same time, as we have taken a lot closer look at the CapEx, the cash CapEx expectation has come down by about $60 million. So there is a relative offset between the energy margins coming down, but so has CapEx a similar amount, and then you’ve got the O&M reclass from CapEx to O&M, but again, that’s not a cash item. So when you actually look at the free cash flow of the fleet next year, it’s still in line with our original expectations, because of the things that are being offset here.

Okay. Now, my other question, I think, you’ve somewhat alluded to it that the deleveraging is more important than any asset purchases. But do you feel like you can run this, or effectively hedge the size of a power generation business about bigger retail book? I just feel like that might be one of the reasons why you’ve been seeing as much of a pressure on your margins as you did, because you don’t have the direct sales of electricity?

Well, it’s certainly helpful having the retail book. I mean, we’ve got certainly a lot of our generation covered in

Okay. Thank you.

And I agree with what you are saying and I agree with the harmful, but I guess the new order of priorities, it’s not the top priority.

Thank you. Our next question coming from the line of Praful Mehta of Citigroup. Your line is now open.

Thanks so much. Hi, guys.

Hi, Praful.

Hi. So the first question is on the LMP pricing discount. You’ve highlighted in your 2017 guidance a meaningful discounts to help pricing. Wanted to understand firstly, what’s driving that,? And two, is that something you see across the forward curve, as in is it in 2018 and 2019 and beyond, as well? And if not, what – you reduce it or if it stays, what kind of keeps it there?

Before I let Hank give you the details around, I’d say, first, Praful, that one of the reasons that we put that in there, not that this is anything new or a new development at all, it was partly just to, again, as we work with our constituents sell-side, long investors and other hedge fund investors that there’s just a recognition that often liquid trading of prices not the same as LMP. So, it’s not necessarily something new. But we just wanted to raise it, because we have seen on more than one occasion that when individuals are putting together their analysis of us that they are simply just using liquid trading comp prices. And that’s we wanted to highlight, but that’s not necessarily the right way to model out the fleet for, not only for us, but for virtually anybody, because not many people actually get the liquid up trading price. But with that, I’ll turn it to Hank.

Sure. So the typology in the system, specifically in the eastern part of PJM has – is in a dynamic state and it has changed meaningfully over the course of this year, primarily driven by very inexpensive gas being delivered into Tetco M3. And so mostly conversation around basis should be focused around Exelon and Liberty. There is – there are two factors, one is the inexpensive gas being delivered, particularly during times of low load, and the other is the transmission upgrades that are in place between Maryland and Pennsylvania. They are increasing the transmission capacity. The project is expected to be completed in – by June of 2017. So, there has been some interruption and some constraints as they do that work. We think that will partially alleviate the congestion. But again, the system is in a state of flux as the pipelines and the transmission orders adjust to the new world order of very inexpensive gas up in the Northeast. So as Bob mentioned, we wanted to point out that there is some basis differential that’s been there, but certainly, over the course of this year. And we do expect it to partially correct itself, or reduce over the course of time as the transmission projects are in place, it’s worthy of note.

I just to add to that. The assets tend to have a wider basis, Liberty, Ontelaunee, Independence. And then you think about New England and Ohio assets, they tend to be more on the narrow side of that range.

Gotcha. And so just to clarify, because when you are modeling your 2018 or 2019 EBITDA, are you applying these discounts to the hub pricing when you’re modeling your own – in terms of views on EBITDA?

That’s right.

Gotcha. All right. Second question is on free cash flow. If I look at 2017, midpoint of guidance of $250 million, you’ve highlighted about $226 million of debt paydown from different buckets that kind of have produced the debt in 2017. But there is also environmental spend of $62 million, this gas operates, it’s before dividend. So when I add up all the pieces, it looks like the free cash flow that you’ve allocated, or expect to allocate in 2017 adds up to the top end of the free cash flow range. Am I missing something in terms of that, or are you expecting a little bit higher free cash flow to kind of meet all of these different capital allocation needs?

Yes, Praful, I think, maybe something that you need to make an adjustment for. When you look at things like our inventory financing, and that’s a debt roll off that will happen in 2017. That is inventory financing at Brayton Point. So we account for that it as debt that’s financed by a third-party. But if your model actually assumes that Brayton Point runs, that’s where it’s actually buying its coal from. So, as it procures coal, then that debt gets paid back, right. And so it ends up being a cost that’s embedded in your gross margin. And so is not a use of free cash flow after gross margin and costs and what have you. It’s actually paid back as you are buying coal to run the plant. The same can be said for the emission credit financing, there is roll off in 2017 associated with that. That is where we have put emissions credits into a warehouse facility with a third-party. And again, as part of your gross margin cost buildup, this includes the cost of emissions, but we are buying those emissions back. As we do that, that that rolls off. So I think maybe where the mismatch is, is at least related to those couple of things, where there – we treat both of them as debt. There is roll off and amortization in 2017, but you’re not using your free cash flow to do that. You are actually – it’s a cost embedded in your gross margin before you ever get to free cash flow.

I got you. That’s helpful. So the actual free cash flow that is being utilized to a debt paydown in 2017, is that the number you have, which is – what is this, $55 million from Slide 19, is that what the actual cash outflow is?

That’s right. And then you also have the PJM capacity modernization roll off. So that $64 million is still in your EBITDA, but you’re dedicating that cash to pay off that debt obligation, or that obligation that we classify as debt.

Gotcha, and that’s helpful. And then final question was on NOLs, given what’s the view of free cash flow, and that you have limitations on utilizations of NOL. Is that – what is the view right now in terms of the ability to utilize all the NOLs in time you expect to do that or not? And any color around that would be helpful as well.

Yes, I mean, I think our expectation is longer-term, you will end up using, at least, a meaningful portion of that. If you recall, when we acquired the IPH subsidiary and we acquired the ECT [ph] portfolio, both of those portfolios came over with very little tax basis. And so, we actually need on an ongoing basis, again, you can make assumptions around our prices and profitability and so forth. But longer-term, I think, the thought is, those entities are going to be throwing off taxable income just because of their lack of tax basis. To what extent did that get offset by some of the other parts of the fleet? But I think our expectation is longer-term, we will end up using. The one thing to also give some thought to, is to the extent that there are any asset sales, depending on which assets they are, those certainly could, given – depending on their tax base position could generate taxable gains that we would then use our NOLs to shield. The other thing to think about and again we are continuing to walk – to work through this is on the Genco restructuring, does that generate [indiscernible] income, that again, you would use part of your NOL to shield. So, I think as we go forward and look at some of these different pockets, I think the thought is that, our NOL certainly will be used to what extent and what the timing of that looks like. I think there could be some variability in that.

Fair enough. Thank you, guys.

Thank you. Our next question coming from the line of Nikhil Chopra of TCW. Your line is now open.

Hi, guys. Thanks for taking my questions. I just want to ask about the asset sales, given the market reaction today, would you consider accelerating the timeline for asset sales? I know you answered the question a little bit earlier, just wanted to ask you on the market reaction, how do you think about it?

No, I mean, our plan with asset sales was – is pretty much what I said earlier. I mean, we are looking to see if there is a right combination of assets to put out there. That’s something that we wouldn’t necessarily take to the market in Q4. It’s something that we would consider going into next year. But the underlying health of this company is fine. I mean, it’s strong, the cash flow generation is there. We put out conservative number on guidance, because we are sitting with 75 million megawatt hours of length that brings a level of volatility with it. So there is no need to look at suddenly selling assets, there’s nothing fundamentally different. I mean, if – our goal is to get through 2018 and have a leverage ratio in the mid-4s to the extent that we need some asset sales to help us get there along the way, it’s something that is on the table that’s being evaluated, but if it’s not deleveraging, it’s not worth doing. So whatever happens in the market yesterday or today or tomorrow isn’t necessarily going to change our thought around that.

Okay. And then how are you thinking about the 2019 maturities, it’s pretty sizable one at $2.1 billion?

Yes. That’s right, it’s $2.1 billion due in November of 2019. And what we’ve said is that those bonds become callable in the spring of next year. And so that certainly is something that we’re focused on, think of regularly. And I think as we look at it, it is a large maturity. I think it’s something that we’ve got time to manage. And again, I would see us chipping away at that over time, whether that’s with free cash flow, whether that is refinancing pieces of it at a time. I don’t think we would wait for one large $2 billion refinancing event. I think you need to take it in bite-size chunks. So again, whether that’s using cash generation of the company to do that, whether that is opportunistic refinancings and calling pieces of it, whether that’s using proceeds from asset sales, again to call pieces of it. I think it’s a multi-step process over a period of time.

Okay. And then lastly, I think on hedging, if there is any more commodity downside from here that could further put at risk your leverage target and other things? So could you – would you consider more aggressive hedging?

Once we get to the ENGIE portfolio, we will be absolutely out there hedging that portfolio and hedging the length that we have overall in the portfolio. So, certainly, our hedging strategy has tied to also our financial goals, including our leverage goals. So we’ll do that. And the issue with ENGIE is coming up for us. I just don’t want to hedge when I don’t own it, because you just don’t know when you are actually going to own it, because you get. There is absolutely no feedback whatsoever from FERC in terms of their process. And we responded to their nine comments back in July, and they have a period of upwards to six months from the time we file our response. So I don’t know how much of that six months, they are actually going to use to read the answers to the nine questions. So it just makes it difficult to go out there and do any hedging around that. But there is absolutely not doubt that hedging is an important part of reaching our financial goals.

Okay. Thank you very much, guys, I appreciate it.

Thank you. Our next question coming from the line of Mr. Michael Lapides of Goldman Sachs. Sir, your line is now open.

Hey, guys, so a simple question for you. What do you think is a normal level for maintenance CapEx? You’ve got $450 million in your 2017 guidance. What do you think of kind of post the ENGIE acquisition as a normal level? Can you also just comment about the trajectory of environmental CapEx? Meaning post-2017, do you think it’s kind of higher or lower than the level you mentioned on the right side of Page 19?

Yes, Michael, this is Clint. One thing to know, and I think we noted it in the script. But the $450 million in maintenance CapEx is before the LTSA adjustment, which is typically captured down in the other cash items. So and we do that so that people know how to kind of roll when they are modeling our company and modeling our PP&E and asset base for depreciation purposes, the $450 million is kind of what gets rolled into your PC&E. But when you adjust it for cash, look, there’s a cash adjustment for the LTSA payment stream that’s in other cash impacts. So when you look at what’s the total cash spent in 2017, after that adjustment, it’s about $370 million. So, on an ongoing regular cash basis, I think the way you should think about it for the combined fleet is about $300 million a year. So you can see that it’s elevated in 2017. As you roll into 2018 in 2019, I would expect the cash CapEx to be comfortably below that run rate average of $300 million. I would expect that to be well into the $200 millions, just because of the outage schedule that we’ve talked about. So first of all, that’s just something to keep in mind as you look at our guidance. But also, to answer your question on long-term – on a longer-term run rate basis, I think $300 million in cash is the right way to look at it. But again, that’s going to tend to be rather lumpy from year-to-year. It is higher this year, lower likely, and meaningfully lower in 2018 and 2019, I would expect that if that’s the case to probably step back up in 2020.

Got it. And environmental CapEx just kind of longer-term?

Yes. So for the environmental CapEx, that is in free cash flow. That typically is things like bags in the bag houses, it’s some of the chemical replacements and the catalyst replacements and all in the back-end controls. That usually runs about $20 million a year on a recurring basis. I think the thing to be sure that you are keeping an eye on, and we have in other disclosures is around ELG, big fleet CapEx spend, ARO spend, things like that which, again, I think we’ve provided separate disclosures on around ELG. Again, that the ELG estimates that we’ve provided kind of assume the current fleet and that there are no changes associated with it, obviously, with the size of those numbers, that comes into play when you are thinking about the long-term viability of a plant.

Got it. Thank you. Much appreciated.

Thank you. Another question coming from the line of Julien Dumoulin-Smith of UBS. Your line is now open.

Hey, guys, coming to full circle here. I just wanted to touch base real quickly. You mentioned that you wouldn’t necessarily be on the acquisition trail, if I were to use your words. But more specifically, obviously, corporate deal making would seem always an avenue. Can you comment on the palatability of coal within any such thoughts? I mean, obviously, you’ve made great strides toward relieving yourself of a concentrated position in that regard. And then separately, Bob, a little bit more directed to you, what’s your current situation, vis-à-vis contracts and succession planning, if you can comment on that at all?

You threw me with the second question. Let me get back to the first question. So acquisitions on – but again, I mean, when I think about acquisitions and the context that was asked during the call, thinking would we be interested in pursuing any acquisitions of small portfolios or additional coal plants, and the answer at this point in time is that is highly unlikely.

I meant more on the corporate side…

I think if you are taking into the context of a big transformational ones, that’s one of the things we never really think about until you actually see an opportunity really in front of you. So, if there’s something that generates enormous shareholder value, we certainly would evaluate it, and I think since, certainly since that I have been here, we constantly…

Bob, if I can jump in. A lot of your peers have a lot of coal. Is that something that the Board is kind of categorical about in terms of their thought process, if you will?

No. I mean, we’re not – the short answer is no. I mean if there was something that generated the right level of value, then it’s something that we would consider doing. We don’t have any type of thought that we can’t own a certain type of asset, right, I mean, if it makes sense for us to own, we would do it. So I wouldn’t categorically say no. But I would also say that it’s unlikely to see us actually buying anything, too. But there’s no previous position to shy away from coal. Now, again, I think when you think about what drives value right now, I’m not necessarily buying more coal, I wouldn’t necessarily probably put that on the list, given the state of play in the markets and CPP potentially coming all those other things. But there’s no predisposition against it. And just on the contract issue, my existing contract goes through April of 2018 and it has a renewable clause in there. And so there has been no decision that made by the Board or myself as to whether or not it gets renewed after April of 2018. And so maybe the shareholders have something to say about that, too. But I’m not worried about that at this point in time. And for succession planning, that’s something that the Board takes very seriously, and we have an active – a very active succession planning process that’s actually in place that we utilize a third party to help with that, as well. And that’s done throughout all levels of the company, but there is clearly the Board has asked for a very good structure process at the most senior levels of the company as well, which is in place and is actively occurring. As far as do I stay beyond April or 2018 or not, no decisions have been made.

Great. Thank you.

Thanks, Julien.

Thank you. That will be the last question for today’s conference. I will turn the call over back to our speakers.

Very well. Thank you. I know we ran a little long, but given the magnitude of today and the interest, I appreciate the participation and we look forward to continuing the discussions. So at this point, operator, we’ll disconnect. Thank you.