Dyne Therapeutics, Inc. (DYN) Q4 2016 Earnings Report, Transcript and Summary

Welcome to the Dynegy Incorporated Fourth Quarter and Full-Year 2016 Financial Results Teleconference. [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. Good morning, everyone and welcome to Dynegy's investor conference call and webcast covering the Company's full-year and fourth 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 reflecting assumptions, expectations, projections, intentions or beliefs about future events and views of market dynamics. These and other statements not relating strictly to historical or current facts are intended as forward-looking statements. Actual results, though, may vary materially from those expressed or implied in any forward-looking statements. For a discussion of 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 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; Dean Ellis, our Senior Vice President of Regulatory Affairs; and Carolyn Burke, our Executive Vice President of Strategy. We posted our earnings release, presentation and Management's prepared remarks on our website last night and prior to opening up the call for questions I want to highlight a few items from the fourth quarter and several recent developments. Our 2016 adjusted EBITDA was $1.007 billion versus $850 million in 2015. The year over year improvement was primarily driven by the full-year contributions from the Duke and Equa power plants in 2016 versus the nine months in 2015. Partially offsetting this benefit were lower energy margins across most segments, primarily due to mild temperatures in the first quarter of 2016 and lower capacity revenues in PJM and Isa, New England as a result of lower previously cleared capacity pricing. 2016 adjusted free cash flow was $263 million versus $186 million in 2015. Both adjusted EBITDA and adjusted free cash flow were within the Company's established guidance ranges. We're affirming our 2017 full-year adjusted EBITDA and adjusted free cash flow guidance ranges today. While weak winter weather has negatively impacted market power prices and spark spreads, Dynegy's hedging program has provided a meaningful offset. Additionally, our 2017 O&M and capital expenditure budgets have been revisited in light of the current commodity price environment and the five-week delay in the NG closing. These cost reductions together with cash interest savings from the recent term loan repricing completely offset the market price weakness we have seen today. On February 7, we closed the acquisition of NG's U.S. fossil generation portfolio and settled out our obligation to NRG capital partners. As planned Dynegy issued 13.7 million shares of its common stock to ECP at closing for total consideration of $150 million or $10.94 per share and simultaneously Dynegy paid $375 million for the purchase of ECP's interest in Atlas Power, a subsidiary that purchased the fleet. The acquisition at 9 GW of primarily high-quality natural gas plants in the desirable markets of PGM, New England and ERCOT. Transactions energies have been increase from $90 million to $120 million, with the bulk of these synergies related to adjusted EBITDA improvements including lower LTSA costs, gas plant operates, improved outage management and eliminating redundant corporate overhead costs. Consolidation to a single headquarters was completed day one and approximately 75% of targeted synergies have been achieved. We would expect to capture about 90% of the synergy target by year-end. With the transformation of our wholesale generation fleet largely complete, refining the portfolio and strengthening the balance sheet has moved to the forefront. During the fourth quarter, we closed the sale of the Elwood facility and received $173 million in cash proceeds. We also entered a prepackaged restructuring process for IPHs Genco subsidiary which culminated with its emergence on February 2, the restructuring eliminated $825 million in unsecured Genco notes with the 92% of participating bondholders receiving $113 million in cash, $182 million in seven year unsecured Dynegy Inc. level debt and warrants for 8.7 million shares of Dynegy common stock with a $35 strike price and tenor of seven years from closing. Bondholders who did not initially participate in the exchange have 165 days from the emergence dates to do so. If all remaining bondholders elect to participating, it would result in additional $27 million in consideration from Dynegy in the form of both cash and notes. At this point of the restructuring, however, the net debt taking on by Dynegy is roughly 1 times IPH's forecasted 2017 adjusted EBITDA of four G&A allocations. Consolidating ownership of the Ohio joint operating units or JOU's, continues to be an objective of the JOU partners. In connection with this we've announced be transfer of our ownership of the Conesville plant to AEP in exchange for their ownership in the Zimmer plant. Conesville is operated by AEP, whereas Dynegy operates Zimmer. While no additional consideration will be exchanged, a $58 million letter of credit previously posted by Dynegy to AEP will be returned. Regarding other co-owned plants, we're in advanced discussion with our partners concerning the potential mid-2018 retirement of the Stuart and Killen plants which are operated by AES, if both retirements occur 2,900 MW of base-load coal generation would leave PJM. Dynegy acquiring the remaining a steady stake of Zimmer and Miami Fort also remains a possibility. Also announced today is a signed purchase and sale agreement with LS Power for the sale of two PGP peaking units, Armstrong and Troy, recently acquired from ENGIE, the sales price is $480 million or about $380 per KW and we expect the sale to close in the second half of 2017. Proceeds from the sale will be allocated to debt reduction. Over the course of the year additional portfolio changes are likely in order to meet our required market mitigation actions in Southeast New England as well as for other select asset sale opportunities. In one final comment before we move to the question and answer session. We have established 4.5 times as our targeted net leverage ratio by the end of 2018. Based on today's market curves and actions discussed today the ratio projects out to be about five times. Our commitment to get to 4.5 times will be achieved by doing what we do best and that is working our available levers through pride, through synergies, portfolio management, debt reduction and just grinding it out 0.1 turn at a time. At this point in time I'd like to open up the session for Q&A. Ashley?

[Operator Instructions]. Our first question comes from the line of Greg Gordon from Evercore ISI. Your line is now open.

So I know somebody's going to ask you this question, so I might as well just get it out of the way. When you look at the guidance range of $1.2 to $1.4 billion todays, forward curve's never the offsets you've articulated. Would you say you're at the low end of the range today, the midpoint or posted at the high-end?

First, Greg, I appreciate you asking the question to get this one out of the way. The only thing I'd want to say about the guidance is that we have the range of $1.2 billion to $1.4 billion. We're within that range. When we established the guidance at our call for the third quarter of last year, we talked about having a little bit of conservatism in there in case we have a kind of a winter bust which seemingly has occurred, so I wouldn't say it's really that much different from where we were at that point in time. In addition to the changes that we've made in some of our O&M spending and the like, so we're able to manage through that. Rather than doing guidance based on normalized weather, we've ratcheted it back a little bit so we remain relatively where we were back in November.

Great. I mean when I look at the details you've given and I look at slide 28, it looks like you've modestly improved the capacity revenue uptake through 2019 by selling more MISO capacity. Looks like $35 million a year, 2017 through 2019 and you -- the numbers here in terms of cash maintenance CapEx interest and principal payments are -- in terms of uses of cash -- are significantly lower. I should look at that as improvements from sort of the Reg G that you gave in the 8-K, is that right?

That's right. That's right and you can see on that slide as well where we have the significant reduction in the CapEx say in for 2017 and the O&M and use of cash is down, what's roughly $141 million. I think it was. Something like that.

That's right. The one piece you didn't explicitly call out though and maybe you're not willing to and that's fine is you said that you've reduced capital expense, interest expenses down, capacity payments are up. You've also said you've right-sized O&M, but you didn't give us sort of a quantification of how much lower that might be relative to what the plan was in the EI.

So Greg, this is Clint. Good morning. So from an O&M standpoint, we've reduced from our original guidance forecast. We've reduced O&M by $45 million to $50 million. That order of magnitude and it's really kind of throughout the fleet. There's been some adjustments for NG, Summit IPH. We've made some adjustments to Stuart and Killen, given the challenges they face and the discussions that are ongoing around retirements. And then also on the DI side, so really throughout the fleet, we've taken a new look at that and again, cut O&M by $45 million to $50 million for this year compared to the original forecast.

Thanks. Two more questions then I'll let someone else ask stuff. One, have you done any incremental hedging since -- did the deck you're giving us is from February 7, based on the footnotes? Has there been any incremental hedging done subsequent to that, especially in Texas? And then can you articulate what your asset sale aspirations are for the remainder of the year now that you've Peakers behind you?

Greg, this is Hank Jones. I'll take the hedging question. Post-closing of the ENGIE transaction we aggressively hedged the output, particularly at ERCOT. The updated percentages for our hedge position in 2017 and 2018 in ERCOT is 40% and 30%, respectively.

Thanks. And plans for further asset sales?

Well the next one that I would say is it moves to the front of the queue is we have to do the market mitigation in Southeast New England. So we have two assets that we will be taking to market there and it's likely to be Milford, Massachusetts and Dighton. And on Milford, you may have noticed, Greg, in the slides that we cleared an upgrade for Milford and it was the size of which allowed the entire facility to qualify for seven-year rate lock so Milford, Mass which I think is I think just over 200 MW has known capacity payments for the next 10 years. So we viewed that along with Dighton to be two very attractive assets. That should garner pretty good bit of interest and we're getting plenty of incoming calls on those as we speak. So that's next up in the cue, I would also say that on the Peaker sales that we just hit, the two our original intent actually was to sell three. And on the third, we had a value, a different view on value, so we ended up with two sales. So it's likely that there's probably be another Peaker sale during the year as well, but when you're doing these other asset sales you also get inquiries from the buyers about having things are taking things out. You'll see during the course of the year that there could be some more movement just even beyond the market mitigation effort that we need to do next.

Thanks a lot, guys.

Greg, I think Clint wanted to make one additional comment.

Yes, Greg, back to one of your questions about slide 28 around interest expense, you noted that the interest expense, the cash interest for this year is down about $30 million compared to what we shared in the fall. And it's really due to two things. First is the repricing that we did on the term loans for the NG acquisition. That's about half of it. That should be permanent going forward, obviously. There's about another $15 million that's more of a timing issue related to 2017 versus 2018, and it has to do with the bond that we issued, the $750 million bond that we issued in October. I think the payment dates on that are January and July and since we issued in October what you'll end up having, excuse me, is the next payment will be in July and that will be for all accrued interest to date. But all of the remaining interest for the balance of the year will be due in payable January of 2018, so it will fall outside of 2017. So that's more of a timing issue. So as you think about the cash interest for this year, I would say half of that is more permanent in nature. The other half is more timing related to issuance and payment.

Okay, but that's reflected in the $617 million you expect 2018?

Yes, that's right. That's right because then we get on a more normal schedule.

Our next question comes from the line of Praful Mehta from Citigroup. Your line is now open.

So firstly on the maturity and the debt schedule, 2019 clearly is still the big majority. Wanted to understand how covered are you right now, how are you looking at that maturity and any other plans as we should think about that maturity?

Well, the way that I think about it is we've got this tree in 2019 that we're going to takedown and it's going to be done one swing at a time. So we do these Peaker sales so that you can see there's $500 million right away that's allocated to pay down the 2019s. We've got some of our cash proceeds or cash balances, they are a little higher than what we forecasted because we needed less for ENGIE and the IPH cash was greater, so we can allocate some of that cash and market mitigation asset sales will go to that. So we will continue to keep chopping at that and I would say by the end of 2018, the amount of outstanding 2019 bonds which should be relatively inconsequential. The first call day is May of this year. At what, $103 million, $103.5 million?

Yes, $103 and 3/8 million.

So we will just continue to attack that over the course of the next year and a half. Again, it matures November of 2019, but by the time we get to 2019 I don't expect much left of that balance and that'll be through pay down and potentially some smaller chunk could be refinanced as well. So it's certainly one of our priorities. And when I think about the balance sheet, two things really stand out. You get to our 4.5 times which I'm sure we will talk about more this morning. And the other was take care of the 2019s well in advance of 2019.

Got you. That's helpful. And getting on that 4.5 point, clearly asset sales, like you said, is an important element of that to bridge from the five to the 4.5. Given, it sounds like there's going to be a bunch of assets in the market, right? You're looking to sell it sounds like there are other IPPs who might be looking to sell assets. Do you see there to be enough appetite still in the market? And what prices do you expect there to be any weakness in pricing or how are you looking at that strategy because clearly, you want to be able to manage what pricing you can get for the asset sales.

Yes, I think from our standpoint we want to maintain price discipline, make sure we get the appropriate value. And again, we just kind of demonstrated that with this Peaker sale as well, but the assets that we have coming to, potentially coming to market are very high-quality assets. I think they'll compete very well. There's still significant amount of buyer interest out there and not only of, say, U.S. private equity firms. You're seeing a lot foreign interest as well. And when you have plants like Milford, Mass that have10 years of visible capacity payments, it will bring the right buyers. And overall to get to the 4.5 times, it certainly asset sales is a component of it, but the other component of it and kind of described internally here, I mean we've just got to hit a bunch of singles to get there. This is not something that's necessarily easy or we want to just say trust us. This is things that we've just got to grind out and we've talked about hitting signals to describe that this isn't the line drive up the middle. These are the bumps that you really have to really sprint to first to get there, but we'll just keep working at this to get it done, the 4.5 through cost improvements, through portfolio changes, asset sales, we will get the but we'll just have to dig in and do the things that get us the last 0.5 turn that we need verses where the market projects as out today.

Got you and just finally one last thing. On the zero emission credit FX, how are we looking at that from, regarding that administration fork. Any views on how that would play out now and you probably get a little bit more support from other IPPs who have activists coming in there? Is there any other further support that you think comes in from other participants on the IPP side and how do you see the administration looking at it, the current administration looking at it, any change in perspective?

Yes, I think there's multiple fronts of that we'd kind of refer to. Maybe I'll start with FERC and having Cheryl Lafluer as the Chair is an excellent move and Cheryl understands competitive markets, she's a defender of competitive markets and recognizes that what's happening at the state level is pulling apart the competitive model that was designed to work. And stacks are right at the heart of that. So I think you've got, I think we've got a sympathetic ear in Washington with someone who understands what's going on. I would also say through EPSA, with membership of EPSA and our overall organization is that we're absolutely focus on this and all of the participants EPSA which is our peer companies, whether it be Calpine or NRG or Talon or others, they're all, we're all absolutely focused on defending the competitive market. And so that is something that we will continue to do. I would also say in our meetings with PGM as an example [indiscernible] is very focused on this and understanding what this is doing to the PGM marketplace and changes that need to be made in how energy and capacity price formation needs to occur given the various state initiatives so what are the things that PJM can do that can work with the states, where they can -- the states can accomplish their objectives, but yet not compromise how price formation actually happens.

Joe Bowring, the independent market monitor is a tremendous advocate, for getting the market to work right, so it's coming from all directions now where's there's a lot of momentum to get it right. Maybe the final thing I would say is that we will to everything that we can to educate public on what actually is happening, why you shouldn't pay $8 billion dollars for three plants in New York and why that doesn't make any sense. Or why in the state of Illinois do you want to pay $3 billion over the course of 12 years for two plants that are completely uneconomic. Why throw the money down the drain? There's better ways to spend that money in the state. There's better ways to invest in the communities and the neighborhoods and the like, rather than sticking this money to invest in a great company and just dividend it out to shareholders. So we're going to be working all those fronts to fight against stacks, of course the legal cases in New York and Illinois are coming as well.

Our next question comes from the line of Devin McDermott from Morgan Stanley. Your line is now open.

I wanted to follow up actually on Praful's question in terms of hitting the 4.5 times, that the EBITDA target you mentioned the potential for some smaller singles in achieving that goal two of which would be the cost improvements and also potential additional synergies. Given how lean your cost structure already is relative to peers, can you talk a little bit about any additional cost opportunities or additional symmetry potential, what that could look like in common? And magnitude as well?

Sure, I'll give you a couple of examples, Devin. I'll start first with one that's obviously known in IPH so we restructured IPAs we bring it on to the Dynegy level balance sheet and will bring it on it one text -- 1X, net that to EBITDA. And I'll refer to Clint here in a moment. But it takes Stuart and Killen, two plants that have roughly speaking breakeven to negative EBITDA and negative free cash flow. We have moved had a 10 and Joppa into PJM where they otherwise would be bidding into incremental auctions as far more efficient for us to take our capacity obligation for Stuart and Killlen, put it over to Hennepin and Joppa. These plants, Hennepin and jump, in free cash flow approach up I has a new rail transition contracts of these are very viable plans and that will allows us to support and endorse the retirement of killing and a Stewart and we will be eliminating negative EBITDA, significantly negative free cash flow and that would be accretive to our balance sheet and we don't have to lose the capacity revenues from those two facilities because we've positioned Hennepin and Joppa and PJM and their opening PJM. So that's an example when you can maybe put a little bit finer point on the numbers what it looks like for those facilities over the next two years ago

Devon, this is Clint. So as we kind of look at the potential shutdown of Killen and Stewart Encana put it means, once you take those capacity revenues, from Stuart and Killlen and reallocate those to Hennepin and Joppa, than what you have is, you've got plans that over the 2017 2018 timeframe on EBITDA basis where breakeven to may be slightly positive and that's with the capacity revenues, right? And it certainly gets was significant as we get out into 219 and 2024 and when you reallocate those capacity revenues and you look at the fact that that cost structure at Killen and Stewart are going away, well, that's a meaningful, basically kind of an effort to EBITDA los in free cash flow plus what you put CapEx on top of that. I would say over the, just to give you order of magnitude, over the next five years, 2017 -2021, the EBITDA benefit to us of this 's order of magnitude called $150 million in aggregate. And then on a CapEx, between maintenance CapEx that you're not going to spend an big Creek CapEx that you're not going to spend on those 2+, that's probably another $200 million. So on a free cash flow an actual cash flow basis in the net of the ARO's, net of severance, shutdown costs what have you, you were talking about $300 million to 20 $50 million of cash benefit, again over a five-year timeframe. And a lot of that is from 2019-2021, since the plants will still be in operation, 2017 and for partial year 2018 but what we have yen or 2017-2018 is Kenneth give our expectations for 20 These plants. We have gone and taken a fresh look at the maintenance schedules and be O&M that were spending in the CapEx investments that we originally were planning to make a week that those back again, I think when you look at the impacts of this, particularly the 2019-2021 timeframe, it can be very, very significant pivot data.

I would give one more example since we're on the JOU and as a mentioned in the opening, we still have an interest in working with AES to bring in the remaining share of Zimmer and Miami Fort. And if we did, if we to accomplish that, if you look at maybe the investment over the EBITDA ratio, it would be well below, significantly below on the fixed target. So that again, with chip away at it. So we've just got a whole lot of things on our list of things to do if you get.05 here, point.05 here,.1 here and point when typical like so, we just have to grind it out to get there but we've got a list of things that we're going to work through to get there.

That all makes sense and very helpful to tell. I wanted to shift over then to the retail strategy. Your showing some good success I think on panic growth in the retell this is. Longer term what do you see as the right size for this business? And I guess as a follow-up to that, any plans to enter text retail with their position there.

As our previously expressed, the first and foremost goal is else should go and as we do that, I do see, when we think about our commercial portfolio, very much like where we're with the wholesale fleets, we would benefit from additional retail. And our position in Illinois and Ohio is solid and growing. We're moving into Pennsylvania and Massachusetts organically. But it would be a nice add to our portfolio to add competitive retail around the generation assets, whether that's in ERCOT are up in the Northeast and will continue to look at what opportunities are there. But it can run in conflict with the balance sheet. But if we can do it, we will. But it's a second order of priority.

Our next question comes from the line of Julien Dumoulin-Smith from UBS. Your line is now open.

First perhaps a good question. It's about value, the asset transaction about what you're expecting and can you comment more broadly on the transaction to common in terms of implied multiples that you're looking for or should be of these think of them as being higher at a minimum?

Well, we're talking about to for types of asset, so for peaker assets if you look at recent transactions, I think where we ended up at roughly $380 per kilowatt is consistent with where the market has been for some time. If you look at comparable transactions and seven exit multiple, again I think it's kind of consistent. The peaking plants are plants that private equity likes to buy. Have minimal Acquirements, minimal staffing and if the third model quite well. So I think it's consistent. Maybe we sell another peaker, one, maybe two I think our sales now more migrate to some of the combined cycle so the market education I mentioned earlier being CCGT's should set a higher price. The cc GT's, beware I think but it, is they will bring a fair amount of deleveraging because there, your multiples will be North, well North of seven times. And the dollars for per KW much higher than the 380 I would expect that to be different in going forward and maybe one of the packages whether it's the mitigation, we also have one further package that has a couple of CCGT's that depending on where things look like on a Marcus whether we pulled the trigger or not, but we have that process about to go as well and maybe this a peaker in there but I would expect is multiple dollars per KW much for perspective of what the cc TG in the Northeast especially these days.

All right, excellent program than raptures on the second tide of this, obviously Ohio, you're talking about some shifts here, can you talk about first one the potential synergies of the shift in the asset transfer? And then two in Ohio come in can you talk what the potential for the DT Albert and to create a separately in how you're thinking about the potential third plant retirement here of Stuart. Is there really being driven of the outcome of the auction here?

While the economics of us owning 100% of Zimmer and Miami Fort for us, being we're the operator so we're running it in a manner which we've run plants. So we've invested in those plants, was taken the forced outage rate of Zimmer from call it 30% to right now is running at 5%, 6%, I mean less than 10% will say were just seeing much greater levels of reliability. So we took another example and we've got Miami Fort and Zimmer that they Mayor John Burgess was $5000 per year. This past year we spent $400,000 on such a significant ways to find valuable been doing that a we really love those two plants. They run well. Is invested in them a we went to have just full ownership of them. For Stuart and Killlen, as Clint mentioned earlier, the free cash flow profile for those plans going out for the next several years is in the hundreds of millions dollars negative there's no capacity auction that's going to save those two plants. It's just too far out of the money. Stuart has had a history of reliability problems. And so I would expect that 2900 MW these that market. And as you and others have talked about with new builds coming on, you should be seeing some changeover in nature of the portfolio. And this is and if it was 2900 MW. I would expect will not be bidding into the upcoming PJM auction because those plans will be slated for retirement program and then head out is refer you about Julia's question regarding any potential separation of the capacity auction purpose. We have no region to think about the date PowerLite energy will separate from the car

Got it. Adjusted less point following up on Greg's question about that's poker you're assuming probably the asset sell the peaker to close midyear which would implicitly take out a certain chunk of EBITDA the would otherwise planned for in maintaining your current edits. Is that stuff fair?

The peakers are in fact, they are in began it's and again roughly that's about $70 million of EBITDA. If it closes midyear, I'd be very surprised, being that FERC doesn't have enough commissioners and these are backing out. I'm not very good at conditioner predicting when CCGTs will actually closer transaction ing of 043 the past three years. Some the best want to ask. But it seems to me that they don't expect a full quorum for FERC its launch of Memorial Day, sometime after Memorial Day and I don't know how far better than Memorial Day. And then dishes a whole lot of work, obviously the staff is still there working hard trying to get done. But, it's hard to say what. I would really be surprised if it's before the fourth quarter.

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

So most of my questions were already asked and answered. But when you say that the asset sales are at seven exit, what year are you referring to a particular with the capacity prices all over the place?

Abe, this is Clint. This kind of generally on average over the next 3-4 years. In to see an increase in EBITDA in 2018 simply because that's the shape of the transient thing capacity in the because back to 2019 relatively where we're in 2017 Bob mentioned work can of $65 million-$75 million in EBITDA of this year and as you go further out into 2018 and 2020, do you see a similar impact in profound bumps up Lebed to 2018 Kenneth Zaslow the next several years on average, you wrap about seven times.

And when you look at your net debt to EBITDA target of 4.5 times and a doing a similar analysis looking at several years beyond 2018, how does that look further out and are there additional steps you need to take to keep it up 4.5 times rather than just get there and turn back up.

Abe. I think if all you do is a sermon that the curbs liquidate as they stand today that was to just that you have additional work to do beyond 2018 to maintain the 4.5 ago assuming that curbs liquidate as they stand today assuming that nothing is there with the cost structure estimate that you said nothing else, to change the company or the financial position of the company, then there would be more work to be done. Asset of the planes you already have to shut the assets that you talked about?

Okay. And then shifting to New England, this your locking in the New England capacity payments for three years forward imply that you expect prices to fall for the in the future and what are your expectations? The look for the origination deals?

Yes. Abe, we have a very active origination group. We're interacting with customers in all the major regions and tried to reduce our dependency upon the auction for all of our capacity with like to position New England with this series of 27 or eight year rate lock from the rates in the auction and we highlighted to 75 MW three-year traits, one that was unless you're at $7.50 and one that was end this year at $5.50 for a three-year stretch. So we look at it as risk mitigation.

Our next question comes from the line of Ali Agha from SunTrust. Your line is now open.

Just a little more clarification and granularity on the EBITDA numbers. So I think in the slide you talked about, 6.8 times as your starting point at the end of 2017. But can you just give us an approved former basis today where we're that net debt to EBITDA?

Yes, Ali i'm not sure that we would kind of update that. I think the 6.8 is kind of what we would intend to go with right now. But that's what I'm saying is at the end of 2017. We are sitting at the beginning of 2017. So where are we today on those numbers?

Yet, Ali across [indiscernible] very close to that prescribing the six when it assumes that hundred $70 million in cash which we actually are at that if that higher than that today. And then the only difference in your gross debt is going to be amortizations throughout the year. Which are fairly modest in relation to the total debt title think it would change all that much.

Okay. And then also to that point, clearly be big move from that 6.8 6.825 is EBITDA improvement. Can you just remind us again. Just quantify those buckets that you are showing us? How much is EBITDA, how much is the debt amortization, how much is cash just to get a better feel of this?

Yes, so for an earnings up list, it's about 1.4 times prescribed in between the cash build and the debt amortization, that's about another 0.4 to 0.5.

Okay. And then if I heard you right on the remarks on your EBITDA improvement, you mentioned looking at where the curves are aware the at the capacity auction, profile, is it fair to say absent any other moves etc. that we're looking at 2019 currently sort of bending back down versus two 2018 given with this macro factors are right now?

Yes, Mike mentioned a little bit earlier, if you assume that the curves today just simply liquidate as they are quoted and you assume no changes in our cost structure. You assumed the changes in our business, that I would suggest that met that calculation or that ratio is going back up and you have some work to do to keep it where it is at 4.5.

And that factors in all those 2019 maturities as well etc. that you will be tackling?

That's right.

Okay. And then Bob, just to clear up on the asset sales, it sounded like there are various different portfolios or packages as you call them, that your short of contemplating, some related to mitigation, others market et cetera. Can you just give us a better sense? I mean, how many packages are we talking about? I know in the past you talked about venting, use of independence. We haven't really seen the right buyers there. So can you just give us what you'd consider core versus non-core to be monetized in this portfolio?

Yes, I'll break it down into three groups. Group 1, would be peaker sales. And kind of the-based panel deep store sales was that we'd have roughly 3 peaking units that we would take to market. So obviously we just did to so there's another one that we would continue to think about group one is peakers and proceeds used to deal with the 2019 maturity. The second basket would be market mitigation. That's too combined cycle units up in iso-New England and that's going to be Milford, Mass. and that. So those two units combined in around versus just under 4 MW and Milford, Mass. is the one that has 10 years of capacity payments. So that's group 2. We have six months from -- were seven to sign a PSA under our agreement with FERC as part of the Andes transaction. Ended the third group would be too combined cycle units. One would be in PJM and one would be in iso-New England. And I always say this with a little bit of hesitation because these are two very high quality combined cycle units that we will take the market, whether we go all the way through it enough depends on if we see is to market Chris wears are levered took a sense. Again, we want to do this in a structured way. We've got 2017 and 2018 to work with. But if we see that the forward curves are not should venting and the like and to get the 4.5 times we need to before, we've got 30 packets, these would the two very highly desirable units that would set a very strong price per and we're not talking mostly or independence. We're talking about head of the best of the best. One that continually set production records, great access to low-cost gas, very good viability. So these would be to very attractive assets in the marketplace.

Okay, and it hurts saying it so we've decided just the right thing to do or not but we will be taking it to market

Okay. And just to be clear, so this Group C may or may not this year depending on market pricing but the other two groups should be completed this year. Is that the way to think about it?

Yes. And the last remaining peaker, that's also a PJM, yes.

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

Bob just to clarify on the debt reduction that you talked about the months in the singles and just not talking about the group 3 combined cycles which I guess would probably because or two triples, I mean is that definitively on the table? Or is that really of two 2017 and then in 2018 you would revisit that, revisit selling be too combined cycles?

No, we're engaged in that. We've got the same set to go. With over the that room in the very near future so we're going. We're going because the top priority is to get to 4.5 times. And you're right. Those units, that a single or a double. That's at least a standup triple.

And maybe just shifting to pride formidable kind of assume a letter private the balance sheet said provide their system was of their I think just on the connections, the $50 million LC from AP, the similar dollars from IPG once is finalized. It's and see those on slide 27. Are there other pluses or minuses to liquidity or balancing initiatives that in addition to those and what's on slide 27 we should consider?

Yes, I would say that there are a number of initiatives that we're pursuing but I would say that there advanced enough at this point to talk publicly about them. I think the 58 certainly is front and center as an additional injection of liquidity to the company as we get that letter of credit back.

And the 60 also, from IPG?

That's right.

Okay. And those are the--two kind of remaining items from the various transactions, there's the others?

That's right.

Okay. And then the $65 million pride EBITDA target for 2017, that is part of guidance?

Yes.

Okay. And then just lastly a cleanup item on Stuart and Killlen, how much of those are the balance sheet for?

Stuart has been fully written off. Killen is currently at $20 million in the balance sheet and obviously will be reviewing that this quarter.

Next question comes from the Angie Storozynski from Macquarie. Your line is now open.

I wanted to talk about in a day. I know a bit of a Monday morning quarterbacking but so you're considering shutting down a number of assets. You acquired from not that long ago. You just completed a transaction for a portfolio of gas plants and PJM. I mean, how would you defend potential skepticism about this M&A strategy which would be that you are buying a portfolio of gas plants that's peaker diminishing spark spreads, how diminishing spark spreads going forward and your shutting down assets that you've recently acquired. I mean, I note that there are changes in for power curves but how would you which the strategy? The M&A strategy?

Sure. So I would have to go back to 2012 would we exited our restructuring ahead 9000 bigwigs. 5500 MW which still are running today. And if we had to nothing, we wouldn't be having this call today. And what we've done over the past several years is to build a portfolio, great market, rate assets with longevity. And the differentiating thing in doing that is that we combine mixed portfolios of gas and coal and we bring something to the table that no one else does and that's the best cost structure in the industry. So we bring, our platform, we get significant synergies, you can see from our numbers in the slides, we're the most efficient guy out there. And you can every single plant, you get every single plant in the portfolio you buy is perfect? If not at the overall portfolio, the synergies that you get and the shift to guess path transformed this company that otherwise would be stuck with coal assets in my so. So I think what I think within over the past few years, the transformation of our portfolio of 2012 to 2016, we've done more to actively manage this portfolio then anyone and we've done it on the tax of being the most efficient guy out there. And they're going to be assets that were going to have to's "there will be some assets we have to shut down but we're still left with some of the best of the best. Were the largest combined cycle generated New England access to low-cost gas, these plants are having four of the six PG of combined cycle plants that production levels this year. So yes, there are some things in there that shut down the late but net, we're much better sugar company today with what we've done and will continue to try to lever our strengths that way.

And Bob maybe if I could and what the you look at assets particularly the ones that are being retired, none of them are surprises and virtually all of them were known as trouble plans are challenge plans at the time of acquisition. Brayton point, we knew it was going to be retired in 2017. Stuart, we knew that that was a very challenged plant economically and factor that into the acquisition consideration. Killen, not quite as challenged's Stuart but certainly was on the radar screen. Knew, we shut down a unit there that we acquired from and when. We made that plant was challenged because of the struggle requirement that's so that would have to be done there and again we didn't really pay much or pay much of anything for MRN anywhere as you kind of look at the visual just interested of assets that are being retired, I would say that through the due diligence Winsted that those plans were challenged. [Indiscernible] additions economics of that and factor that into the original transaction. And then as you look at the peakers that we're selling now in PJM, those are at relatively sell market value and if it is consistent with how we would have thought about paying for them in the past. So I think as you look across the fleet at the steps that have been taken particularly around the retirement certainly nothing uses the price and it was no inconsiderate at the time of the deal announcement through that great. Just one follow up. This one is on California. So the CPC and Kiesel are holding seminars on potential reform to the resource adequacy market or system. What do you think? Could this make a difference to your place in the market must and what's a general strategy and handling for it for California?

Okay. For us, where [indiscernible], again where not a natural owner of assets in California so for us is continue to see at some point in time with of that asset, we can sell it for a reasonable value or not. So that's kind of us in California.

Our next question comes from the line of Neel Mitra from Tudor, Pickering, Holt & Co. Your line is now open.

Most of my questions have been answered that one question that I had, now that you're looking at retiring some of your uneconomic plants in Ohio, have you thought about what you're going to do with the O Creek in Texas now that you own the NG portfolio?

With collateral, we have a new well agreement that goes into the facility. So it continues to be economic. The question for O is going to be what happens with the regional haze and bark rulings in Texas. If they come through where we have to put on wet scrubbers that would really challenge the longevity of O. If that doesn't happen, it's a positive contributor to the with the new well agreement that we just signed that just became effective this year.

Okay. When think about the economics of its way to from a fleetwide prospective do you think you, it's contributing as a whole to the portfolio such as if you were to retire it would it benefit the rest of your gas assets? Or are you looking at its standalone?

We just look, is the asset is adding economic value to us from the free cash flow distemper. And again, I think really the decision on Colletto is really going to kind of to the federal ruling as to whether we need to put scrubbers on it or not.

Okay. So basically be take away is that the plan will stay open so long is there are no environmental CapEx?

At this point in time, yes. Operator. Our next question comes from the line of Michael Lapides from Goldman Sachs. Your line is now open.

One operational one and I'm looking at what I think is slated 40 in your slide deck and it shows the output levels of all your

Yes, and it shows that year-over-year. And the most interesting bar to us is the orange bar, the unplanned outage bar. Were except for maybe Zimmer and a little bit on the margin with authentic, there haven't really been big year-over-year in this bar.

What are the things you can do in Q2 to do to help reduce the number of unplanned outages which adds cost, meaning it adds O&M and therefore get the output level of these plants up which would at some margin?

Well, the core of our always around driving reliability and these are the things that we to with analysis of where plants are vulnerable. It tends to be first and for more most in the boiler in boiler tube and so we do our various tracking and tracing an inspection programs. With that. So I mean we continue to try to drive the reliability through our pride programs and I'll refer to Marty for any additional colors. Yes, I think that's Repko I would. We have will recolor boiler to program assessment program and the spend the primary reason for many of these outages in the unplanned outages and the call the. But generally speaking, I don't think Dave materially affected our markets considerations and MISO. I think we've at some of those that a better relatively weak passing situation so I think again, I think our investments in targeted against the areas that look like boiler to failures and what we can do about them. So again, I think we've done a fairly decent job of managing costs but also targeting the right investment of those assets pretty I would also add that if you look at the trend since 2012, we really have invested and reliability and the lost opportunity costs have actually come down significantly. The reliability has improved significantly. One thing I would say that Marty alluded to, when plants are in a shoulder order or in a period of price weakness, you don't work around the clock on an unplanned outage. You don't want to encourage the overtime or the stress on the work force or the like for the costs of trying to accelerate responding to an unplanned outage. So you look at the economics analysis of whether makes more sense just to kind of stretch it out and do it by eight. Of soffits or if it is a high demand. Within absolutely do it. That's part of the story here that's not told. I think the thing that would probably provide a little more clarity around this is what are the lost opportunity costs associated with this? And that something that was certainly Trican will make our decisions on how fast do we want to bring it back on, it definitely ties to it happening in market prices. But pride is in Marty's organization and it has just a happy, heavy lead on what can we do to get more gross margin? And that comes through things like reliability.

Got it. Another follow up and apologize, this is a little bit down in the weeds. But when I look at your modeling assistance page on slide 28, the environmental capital projects which you really put into different buckets. One to include in adjusted free cash flow and another you exclude from adjusted free cash but it's still cash flow. That second line, so the $62 million, the 151 million does, the $40 million, how optional is that? Meaning do you have flexibility around the in mind that you're likely to spend, the years you're likely to spin this in our whether this gets suspended all-purpose.

Yes, Michael. That line is predominantly DLG spend. And to the extent that the plan is economic and has a feature, that's the investment that we need to make in that plant to have it continue on to the future. So at this point, this spend is envisioned. It is forecasted for the fleet recall and the situation under which that spend the change would be if it plant is ultimately going to be retired Internet was to make that investment to keep it around. But at this point this is our forecast.

And which plants need that spend the most? I mean, are we talking about head of core unit like Baldwin or are we talking about some of the stuff were a lot of this coal is focused on potential retirements of units, whether it's Stuart or some of the other Ohio plants.

It's really throughout the fleet and its just a matter of time you. And it has to kind of go back and look at the individual users to give you specific plants. As you can see it's ticked up in 2018. So as an example, Belfort has a meaningful DLG spend it to the things he was really throughout the fleet.

And then last question in this one either for Bob or Hank. When you look the Ford energy markets across your core region, so Texas, New York, New England, PJM, MISO, where do you think the energy market are most wrong? There is not a lot of liquidity weight out in the Ford markets after about 12 to 18 month or so. When you look at the curves, where do you think the curves are most wrong?

So it shound like a trick question. I wouldn't say any of the curves are wrong. They are, the power curves are thinly traded and I think there are several things that could be jarring to the market, I'm sure several of which we can imagine what they might be but they'll happen that the other is and could go either way. But I think the lack of a scarcity premium event in PJM and in ERCOT has put a sense of calm in the marketplace and people are not attaching these premiums, oh voluntarily. My experience fleet has been that just everyone gets comfortable all that changes. So I would look for scarcity premium defense in ERCOT and PJM in New England as potential drivers for a meaningful change in the future. Those are all reliability were put in place for a reason and that has yielded some results which has improved reliability across the aggregate fleet. But I think there will be events along the way that can spark a price movement.

Our next question comes from the line of [indiscernible] from Barclays. Your line is now open.

Thank you for taking my question which is essentially that when you think about the 2019 maturity, are you looking to really take that out this year and then you're talking about possibly refinancing a portion of that maturity court level would you think that refinancing and then what form? Thanks.

Yes, I would say as it relates to the 2019's as Bob talked about it a little earlier, my intention is to chip away at that throughout the year through various means whether it's through asset sale proceeds, we have some additional cash on the balance sheet the be able to use or cash from ops. I could also see if there was a window in the financing markets to refinance a portion of that. I think we would certainly look at doing that. I guess I don't have a particular target for the end of the year. But certainly intended to make a meaningful dent in it throughout 2017.

And I think of the target by the time we get to 2018 is just to have the vast majority of the 2019's already addressed [indiscernible] and that's sort of the end of 2018 per you'd like to sort of the bluff majority address?

Yes.

Our next question comes from the line of Shar Pourreza from Guggenheim Partners. Your line is now open.

So I think was my questions were answered but I think if you sort of look at the call today, you infused a lot of concerns how you would bridge from five to how you would bridge from 5 to 4.5 times. But if you sort of look at sort of your building blocks and how you would further delever whether it's one off singles are the CCGT's and you throw in your cash flows and synergies a potential sale of Moss landing, isn't far-fetched to assume that you could breach 4.5 times?

Well I can live with that upside. I think maybe the wildcard in all of this is that when you think about 2018, we have 85 million MWh opened today. And that will certainly be hedged, but our price and our EBITDA may be more so than others because we generate more megawatt hours than our peers now. But you get eight dollar move in the curve and there's $85 million right there and obviously that's very significant and EBITDA has so certainly a more impactful part of the equation when you think about the leverage ratios. So I think the wildcard in all of this is what happens to the forward curves over the time period and where do we lock it in.

And just to give you an order of magnitude or a sensitivity, 0.1 turn improvement is equal to $33 million in EBITDA in 2018. So to Bob's point, a one dollar move on the 85 million MWh, that's a 0.25, almost a 0.3 turn improvement right there before you do any of the other things we've talked about this morning. So that kind of gives you an order of magnitude of how meaningful that component can be.

Okay so that's helpful. And then just lastly, just taking that sort of sensitivity just sort of provided and shifting it over to Texas and then obviously ERCOT how are you sort of thinking about layering on additional hedges in ERCOT especially with I don't know six, 6.5's of coal assets operating at negative free cash flow's especially with the recent downturn in gas. Are you sort of comfortable on where your hedge profile is in 2018 or are you looking on bearing on additional hedges?

So we aggressively hedged a portion of the ERCOT fleet in the days after the close as I mentioned earlier. All that happened before the precipitous fall in gas price on Monday of this week. So for the moment, that feels like a good position to be in. We'll now start to focus a lot on our, specifically on Q3 of 2017 and will continue to watch it closely. I think you're right that the big potential catalyst is the [indiscernible] plants and also, any of the [indiscernible] premium events we talked about earlier. Those are the two triggers that we would see as having a meaningful impact on ERCOT forwards. And Hank, on the hedging, for Texas, you mentioned earlier for 2017, were up to just over 40% and off that if you looked at it on peak for 2017, we're up mid-50s.

Right.

Our next question comes from the line of [indiscernible] from Wolf Research. Your line is now open.

One quick clarification, Bob, I think you said you were expecting the CCGT's, obviously though get a higher dollar per KW presbyter think you said you also expected them to get a higher multiple on sale caused by just want to confirm that. And is that based on indications of interest you gotten on some of the combined cycles?

I absolutely expect to get. Is better than seven times. And I would say that's my view of the market. And these, whether it's the mitigation package or the other CCGT's, these are just very valuable assets so that's my expectation. I wouldn't say that anybody's putting in offers nor I would, not anything else is where the process that would be commenting on it anyway. But the expectations when you look at other comparable transactions that have occurred in the market over the past 12, 18 months, it clearly shows that it would the above seven.

Our last question comes from the line of Greg Gordon, Evercore ISI

Just a question of clarification, guys. Back in November at EEI, you give the debt rolling comfortably 5 times and 4.5 with a little self-help. You basically said the same thing today, I just want to make sure, you did announce the asset sales so is the five times target still before any sales help or is the five times target inclusive of the asset sale already announced?

The five times is before the self-help and that's just looking at where we're today, looking at the forward-looking curves and where we expect our earnings to be in 2017 and 2018 under existing hedge levels and market curves. Okay, Ashley, I think that's it pretty

Yes, you may go ahead and proceed.

Okay. Thanks everyone for joining us.

Thank you and that concludes today's conference. Thank you all for joining. You may now disconnect.