Dyne Therapeutics, Inc. (DYN) Q1 2016 Earnings Report, Transcript and Summary

Hello and welcome to the Dynegy Incorporated First Quarter 2016 Financial Results Teleconference. Please note that all lines will be in a listen-only mode until the question-and-answer portion of today's call. [Operator Instructions] I would now like to turn the conference over to Mr. Rodney McMahan, Managing Director, 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 first-quarter 2016. 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 relate strictly to historical or current facts are intended as forward-looking statements. Actual results, though, may vary materially from those expressed or implied in any forward-looking statements. For a description of the factors that may cause such a variance, I would direct you to the forward-looking statements legend contained in last night's news release and in our SEC filings, which are available free of charge through our website at dynegy.com. With that, I will now turn it over to our President and CEO, Bob Flexon

Good morning and thank for joining us today. With me today our Clint Freeland our Chief Financial Officer, Hank Jones our Chief Commercial Officer, Catherine James our Executive Vice President in General Council, Sheree Petrone our Executive Vice President of Retail, Dean Ellis, our Vice President of Regulatory Affairs, Carolyn Burke, our Executive Vice President of Business Operations and Systems. We posted our earnings release presentation and managements prepared remarks on our website night. Following a few brief opening we will devote the bulk of our scheduled time to your questions. Our safety performance is measured by our total recordable incident rate, had two different story lines. First the gas segment which had five of our PG&E combined cycle generations stations, set first quarter facility productions records, achieved zero recordable during the quarter. The coal and IPH segments on the other hand had 10 recordable injuries, primarily strains and bruises. We’re working close with our union and non-union employees as we are determined in match the outstanding performance the gas segment achieved during the quarter across the entire fleet. Adjusted EBITDA for the first quarter was $251 million versus $85 million during the same period last year. The significant increase was primarily driven by the $209 million contribution from the EquiPower and Duke Midwest acquisitions that closed at the beginning of the second quarter of 2015. Although the Central and Eastern portions of the country had winner temperatures well above normal, the fleet’s advantageous access to lower cost natural gas, provided healthy spark spreads and generation volumes. The MISO capacity auction results for planning year 2016-2017 will release nearly three weeks ago. Our units without existing capacity commitments were bid in at a cost as approved by the independent market monitor. Dynegy did not clear any of its 2,197 megawatts of unsold capacity, as the current price was below unit cost. The lack of compensation from the MISO capacity auction continues to be a derivative of a hybrid market design that mixes utilities outside of Illinois with competitive generators located in central and southern Illinois. The utilities do not relay in this auction for their compensation and bid there units in at zero cost, which drives down the auction clearing pricing, resulting in insufficient compensation for the Illinois based competitive generators. With no relief inside from MISO towards the state of Illinois taking a proactive position, we’re self-correcting the cash flow deficiency by shutting down the capacity in excess of our retail and whole sales, sales volume to substantially eliminate our reliance on the annual MISO capacity auction. As a result, we are we are shutting down Baldwin units 1&3 and Newton units 2. An additional 500 megawatts is targeted for shutdown later this year. On June 2016 the 465 megawatt Wood River plant is being retired. Over the next five years, we estimate the free cash flow saving from shutting down Baldwin and Newton units to be close to $200 million or substantially higher if the Newton scrubber isn't completed. This is in addition to the roughly $100 million in free cash flow savings to be realized over the next 5 years from the retirement of from the retirement of Wood River. As we reposition our MISO portfolio now is the appropriate time to address IPHs Genco subsidiaries. While Genco has sufficient liquidity today the combination of weak energy prices, unsold capacity, higher cost units, upcoming ELG and CCR spend and $300 million debt maturity in 2018 warrants the pursuit of a permanent fix for the entity. Discussions will be initiated with the debt holders in the near future and we aim to amicably resolve the situation during 2016. Resolution will either be a more sustainable business model or transitioning ownership of Genco's three plants to the debt holders. Finally, we are reaffirming our 2016 adjusted EBITDA guidance at $1 billion to $1.2 billion and free cash flow of $200 million to $400 million. At this point operator I'd like to open up the sessions for the Q&A.

Thank you. We'll now begin the question-and-answer session. [Operator Instructions] And our first question comes from Jonathan Arnold, Sir, your line is open.

Quick, to start I guess the 500 megawatts that you are -- you say you are still looking at, can you give any color into where those -- which Coal or IPH and then maybe talked to the might or might not lead to the scrubber needing to be built in the scenarios you are laying out?

Jonathan, I'd say the 500 megawatts was not decided upon at this juncture, but it depend if we can loose from existing commitments from some other units like at the IPH subsidiary, some of the units have commitments into PJM and if we are unable to move them, that would rule out shutting down any of the units that have those types of commitments. But when you look geographically the assets in the north get much better pricing than the assets towards the south. So you would look towards the assets, towards the southern portion of the state. And again, I guess the highest cost unit is going to be -- is probably Newton because of the scrubber requirements, so that would be a potential candidate. But they do have commitments to PJM, so that may require us to look out square.

So putting those comments together, if you are able to kind of shift the PJM commitment that the other Newton unit has and you'd be able to -- that one would be up -- you would be able to close it and then you wouldn’t have to the $200 million?

It would make it a likely candidate, but I wouldn’t go as far as to say that’s been decided and then the whole issue around the scrubber, I think that’s one that we’ll be taking as we go through the restructuring of IPH. So right now we’re still committed and require to keep on target with the variance that we have to continue the spending around that, but we will take a look at that in the coming months as we look to resolve the ongoing structure of IPH. But to the expense that we are able to move some of the commitments we can meet the multi-pollutant standard without the scrubber, so ideally if we can get there, it would be to eliminate the full scrubbers spend. And then the free cash flow savings over the next five years we jump from $200 million that I mentioned a moment ago to probably north of $400 million by eliminating the scrubber.

And is the scrubber sort of yes or no, it doesn’t flex down because one of the units is closing, is that correct?

Well, I mean you can scale it down, but it’s still a substantial spend even with just one of the scrubber coming up.

Okay great, and then on similar topic when we look at that Slide 23, you showed the PSA, the value transfer and subsidies sort of $150 million annually into Genco. Presumably that’s -- is that the value of the retail hedges that are currently allocated to Genco?

Jonathan, I mean we are trying to highlight on that slide is that the IPM has all the wholesale and retail contracts, the way the power supply agreement works just the calculation, it actually overstates the amount of compensation that Genco is currently getting. And if the Genco box were to be separated we would likely cancel the power supply agreement that’s there and that’s what we did on Page 22 is to highlight that, it’s getting actually a subsidy of about $150 million between the wholesale contracts and the way the calculation is done, and that’s why on that following page on 24 we tried to show what this Genco looked like on a standalone basis and again with the pricing in the South, Newton in particular and Coffeen, faced a lot of congestion so they tend to have the a larger basis spread than the other asset to the north. So Genco on a standalone basis without the PSA, without the over allocation of revenues coming in from these contracts is -- faces significant financial challenges.

So there is that value in a Genco [indiscernible] go away ends up being something we are retaining within IPM and IPRG, correct?

That’s right.

Okay, and then so I was just -- one other thing on just as you -- presumably that you didn’t see significant impact towards the current capacity market, clearing construct from these assets that you are identifying for closer because they didn’t clear. But what about on an energy price look and would there be impact on the congestion basis that you have been seeing around Baldwin and Newton from retiring, some of the units and would that be a help?

Well, definitely we see lower LNP prices in the South than the North and you face congestion. Whether not shutting down these units relieves that congestion or not, we don’t know that for MISO to go through and do the analysis around transmission system, but certainly overall the assets down there, routinely face issues with congestion.

But that’s not something you are willing to make a stab at?

No.

It could be factor?

No, I’ll leave that to MISO.

All right, well thank you very much.

Thank you Mr. Arnold of Deutsche Bank. Our next question is from Julien Dumoulin-Smith from UBS. Sir, your line is now open.

So two quick follow up there and couple of others. Just to clarify, the PSA value that you identified, do you retain that so you can opt to get out -- cancel the contract with Genco, but is that full value retained back at the Dynegy and Ameren boxes?

The PSA are cancelable with six months’ notice. So yes we go through our restructuring in discussion, I mean that’s something that we will considered. To date we haven't done that and we intensely have not done that, we’ve been doing everything we possibly can to support the Genco subsidiary. So that just comes into the discussion around restructuring.

Got it and then just to clarify, the timeline on the deciding the last 500 megawatt increment?

Going to be later this year.

Is there something specific you are waiting for, just to be clear?

Again, I think what had mentioned to Jonathan a moment ago that some of the units have commitments and so we have to take a look to see if we’re able to transfer those commitments to other facilities.

Okay, and maybe where I am going with this, what are thoughts on legislation and MISO reform? And how much does that drive your thought process here? And I’ll be curious actually, what you think of the MISO reforms in terms of driving improved pricing signal here? Or do you really need legislation?

No, I would said Julien, unlike some of the utilities to our east, we are taking matters into our own hands and we are not waiting around for a legislative solution here. We are willing to right size of portfolios to match our retail obligations and wholesale obligation and not rely on the capacity market going forward. The reforms to which I think you are referencing around Zone 4. I mean MISO is doing what they can, I mean they’ve got the issue of stakeholders with competing interest, than you know the vast majority of the members are utilities and utilities don’t want to see any change to the model, they’re quite comfortable the way it works for them. So they are trying to do what they can do restructure Zone 4, right now in looking at a forward capacity options with a slope demand coverage it’s being targeted for the local clearing requirement which we saw drop from over 8,000 megawatts to 5,000 megawatts this year. And there is no reasonably to believe that that’s going to stop shrinking as the transmission continues to come in, the local clearing requirement we would expect to go down and when the resources are up than 10,000 megawatts. We are not optimistic that that’s going to solve anything.

Got it, and then just coming back here on IPH, what's the timeline you are looking at here I mean how do you expect to proceed? And I want to follow up a little bit on the nuance there. You talked previously that asset contribution how does that stand in the contacts of any restructuring?

Well, we have actually some -- I guess our first meeting with group of the debt holders later this month and so there we are just going to just have to start the dialogue and just look at what are they -- how are -- we really think both parties want to understand how each party is thinking about how do we move forward in a way that’s constructed for both. So at this point in time it’s -- we’ll have our meeting and start exchanging thoughts on what's the solution here.

Got it. And then just if you can comment briefly, you alluded to it on the power markets the east obvious we see the latest afford with the PPA efforts in Ohio, any commentary on what the next steps are at FERC or otherwise?

Well, I mean obviously FE has filed the next, I guess it's been characterizes their Hail Mary. We will continue to strongly oppose it and I guess AEP is about to file something as well. I mean there is virtual PPA where they are going to rate base something that's not in rate basis, an interesting twist on it, but it's clearly an end run around FERC and my view is that PUCO, the Public Utilities Commission of Ohio proves this, they outta be run out of town. But we’ll stay with the process, where it leads, but we are going to continue to be an advocate against just unilateral parts trying to end-run the system.

Thank you. And we have a question coming from the line of Steve Fleishman of Wolfe Research. Sir, you may now ask your question.

Just on the kind of commentary related to the retirement you mentioned several times that you like to -- you are interested in talking to Illinois about options, could you just maybe talk about whether there have already been some discussions with Illinois and what would be your preferred option that help these plants.

I mean we had discussion over the course of the past couple of years and certainly Exelon has been trying to do similar things. I have to say that it hasn’t gotten much traction, the state is preoccupied with budget issues and infighting while the utilities to the west are just taking over the generation responsibilities for the state of Illinois. I mean that we’d love to see a solution that allows a competitive generator to compete on equal footing, I mean ideally the solution for us is to scoopers with the competitive generators I mean we want to be in the competitive market hybrid models don’t work, this also goes back to Ohio. What AEP and FirstEnergy are trying to do is create what MISO is and we don’t want that, we would like a pure competitive market and as Illinois decided that the whole state should be PJM, would be the ideal solution for us. Short of that is just the other alternatives that we put out there is, either you take the Central and Southern Illinois in that if you can’t beat them, join them philosophy and just make that regulated along with the rest of MISO and that takes care of that problem, whether or not Illinois wants to do something in between that is up for them to decide, we’d love to save these plants, we’d love to continue working, these plants are low cost plants, they are environmentally compliant plants, probably a lot more efficient than some but plants that the utilities are utilized and so it would be best for Illinois to preserve these plants to preserve the jobs, but as long as the market is designed this way and MISO, we’re mixing utilities with IPPs, you are going to see incredible stress put on our units as well as any other competitive generators, Exelon is facing the same challenge.

Okay. And just from a logistical standpoint I think you meant, you said you are mothballing the plant, when would something has to be done by either Illinois or MISO for the plants to kind of not go from like mothballed to actual full shutdown and is there like a -- also point in time where you could not bring them back, like permitting everything is gone.

And let me look to Dean for a second. Dean, is there a statutory duration on the mothballing?

Yes, Steve. This is Dean Ellis. So, our interconnection rights are preserved for three years. MISO will, of course, in the next six months, study whether there is a reliability need driven by the mothball provision. So, there's a couple of checkpoints here along the way. But the short answer is that, for three years, we have the preservation of the interconnection rights.

Now we have Ali Agha of SunTrust. Sir, your line is now open.

So the plants that you are retiring if I saw this right, you are looking at about 200 million of free cash flow savings over that next five year period, but from an EBITDA perspective that is essentially neutral if that right?

Ali. This is Clint Freeland. That's right, over the next five years in total the plants the units are slightly EBITDA negative, but not meaningfully. I mean it's breakeven but slightly to the negative. The issues for the plants though is just the CapEx spend and that's what really drives that free cash flow profile. So as an example over the roughly 200 million I take a 160 of it is related to CapEx and the balance is related to EBITDA.

I see okay. And then looking beyond just the actions that you've correctly taken and then I understand you are saying you are balancing your fleet in the Midwest, but overall from a bigger picture perspective, is coal a fuel source you want to be in? Just given how these markets are and given what's been going with gas and power prices or strategically do you want to more gasify this portfolio or how are you looking at this portfolio beyond just these actions?

We've already have a significant moves towards gas and particularly once we close the handy transaction that our portfolio -- again, from an EBITDA standpoint is 90% gas 10% coal, but I do think there is a value to have -- to continue to have the right sized coal element within the portfolio because it essentially makes you non-natural gas and obviously natural gas being a commodity goes through those cycles. So, we get a particularly significant uplift in arising gas environment around your coal assets, so I think that’s an important part of our portfolio going forward. We just have to make sure that its right sized, we’re utilizing the right scale of it and we’ve got the channels to market for our MISO portfolio which is our wholesale origination efforts as well as our retail business. But we definitely want to remain in the coal generation business because I think it offers something that, if you’re just a gas generator then you just don’t really have the upside that you have when you have the coal element in the portfolio.

And so your thought there just to follow up there, is that there is a cycle you see where gas and hence power prices could once again go back to levels that we saw like six, seven, eight, years ago?

I mean certainly with the demand in place for natural gas whether it's through export or generation or industrial use or the like, I mean the gas market swings and have to have that protection in our portfolio with the coal generation assets I think is a real plus for our portfolio. So, I am very much bullish on our coal portfolio, do not want to see it rationalized any further than what we’re discussing today. So I think we’ve got at this point, we’ll have it right sized and it's going to be important part of us going forward.

And where do you stand in terms of your California assets, what’s your latest there?

Not much of a change we’re still waiting to get the ruling on the gas tariff for Moss 1 and 2, Moss 6 and 7 the contract expires at the end of the year. There doesn’t seem to be much appetite in the state for re-contracting that particular asset. So it's a little bit -- right now is in steady state. We think that ones we get that gas tariff, ruling comes out than we’ll have a much clearer path to exit California. There is still some folks looking at the portfolio, but I am not optimistic that we can actually exit California prior to understand that the gas tariff comes out to be.

And last question and looking at the energy markets as you’re seeing them in your core areas of concentration. Are you seeing much differential between your fundamental view and what the forward curves are telling us right now?

Sorry I missed that, we have a difference here on the fundamental curves between --.

I am saying that in the markets that you’re focused on PJM, you’ll soon be entering ERCOT with the energy portfolio in the Midwest. Are you seeing a much big -- a big differential between what you think is a fundamental pricing view versus what the forward curves are telling us right now in any of the regions?

This is Hank. Our view continues to be that with the rationalization of capacity over the last two-three years driven by low gas prices and mass compliance issues that the system is tight -- it just hasn’t been tested, it hasn’t been tested with high demand periods for the last two seasons and I think that will tell us a lot about where it goes. So our view is if forward markets don’t project that tightness and it's further exacerbated in the northeast with the absence of any kind of winter this last winter, a lot of the scarcity premiums associated with natural gas were worked out of the system and each new season is a jump and the clock has to be reset. So there is still deliverability challenges in high demand periods for natural gas in the northeast. The continued delay in pipeline projects to bridge the west to east gas deliverability gap. All those things continue to perpetuate that situation. So there is -- our view is that that forward markets don’t project that value.

Thank you. And we have a question from Neel Mitra of Tudor, Pickering. Sir, your line is now open.

Given that you have a large amount of cash flow suites to service the energy deck going forward. Are there any additional assets beyond Moss Landing in California that you view as non-core that you could possibly monetize given that you have a much larger asset fleet at this point?

First of all on the cash fleet, I wouldn’t -- we haven’t done the financing yet, so we don’t know whether we have cash suites or not. But on the remainder of the portfolio what we are looking at there is I think a couple of peaker assets in PJM that were considering now whether we hold them or go for some level of price discovery to see what value the market would place on those assets. And then I would say the other one is in New York which we are just one asset we have, a very good asset in New York been independence 1,200 plus megawatts combined cycle access to Marcellus gas. That’s one that were also doing price discovery on. So depending on whether or not the market values it appropriately that could potentially be something that we would monetize and that’s something that we’ll have a better view on probably by the end of the second quarter of this year.

And my second question, now that you have started the negotiation discussions with IPH bond holders, what’s the ultimate goal that you’re looking to get to, is it to ultimately consolidate IPH into the Dynegy balance sheet, just making it credit accretive or credit neutral, or do you still want to keep it ring-fenced?

I mean, the ultimate goal is no lawyers. But we haven't had our first meeting yet, but you can see the outcome from more extreme being, they take three units, the other extreme would be, we bring it on to the Dynegy balance sheet if we had -- if we got the right level of capital structure for IPH. So, there would be a significant reduction in the debt for us to go to that extreme. But to me, they are the two bookends that's going to be in play and it all comes down to where can we meet on this. But I mean ideally in the perfect world, we’d have all of this things together on the Dynegy balance sheet and you wouldn’t have separate ring-fenced, independent Board members, a whole other Board that we deal with, corporate commercial protocols and we’ve got the strongest ring-fenced we ever could have possibly put in place but that brings the level of cost and inefficiency with it. So ideally you can eliminate that through this process, so the question is going to be, if we can’t get the right capital structure then the assets go to the debt holders, that on the other hand if you can work through an agreement with them, it would be great to, just eliminate that inefficiency that we’ve created that was designed to protect Dynegy from the debt becoming, recourse to the balance sheet.

Got it and then I just wanted to lastly follow up on the MISO coal closures, Could you kind of reiterate or explain why you are choosing to do that ahead of the MISO capacity reform discussions, I guess that will started to in the second half of the year, I guess do you still preserve you the option value by mothballing the assets, could they come back. Could you just kind of walk through your thought process with that?

From looking at they are mothballed, the assets can indeed comeback. But again our view on the redesign of the redesign of Zone 4 from MISO, while MISO is doing every attempt they can to improve the design structure, we’re at outnumbered outgunned by that 14 different utilities in the process. So the reformed made to Zone 4, we’re not optimistic that they are going to make a big difference and we made a discussion, we’re not going to run free cash flow negative on new assets and we saw that the auction this year, 2,000 megawatts this year at the auction, disappeared of demand and if you look at the bid curve, that we had in the presentation that was on Slide 14, if we had the same level of demand as last year, all of our units could have cleared, but 2,000 megawatts demand disappeared. And so every year, something else with the way this capacity option works and you just can’t keep that in Zero, so it’s one where we decided to take matters into our hands, let’s just right sized the portfolio. So you know as we’ve always said the capacity option is the last channel that we look to monetize our capacity and being two year in a row were we’ve had unsold capacity in excess of 2,000 megawatts, it’s just time to match the generation supply with the retail and wholesale sales that we have and eliminate the exacts that we don’t get paid for. Particularly, for these assets as well, since they are in the South, and as we mentioned earlier face congested and lower LMP pricing. Again you’ve got the utilities to the west that just go on must-runs. So whether their plans are economic to run or not it as doesn’t matter, they just run them. So it causes a cycling of some of these plans as well which increases the maintenance cost and the reliability challenges. So it's just time to right size the portfolio and move forward. Again as you said and I said at the beginning, these units are mothballed. So suddenly, if the construct looks like it has real appeal to it than we can make a different decision, but the way it looks now it’s not going to happen, it’s not going to happen any time soon. Really the only thing that can make a difference is the state of Illinois to wake up, which for two years they haven’t and I know that it’s a source of frustration on our part and other generators parts -- we just can’t wait around for it.

And to that point, you mentioned, I guess, one of the only ways it would work was if you could move into PJM. What's the constraint there? Is it a lack of transmissions for the southern Illinois plants? Or is it the fact that you are in the Ameren zone and the T&D Company decides what interconnect you are in?

Yes, it's the latter. I mean, you know I was talking to Andy Ott about it at PJM, and I asked Andy, I said, how long does it take to do a conversion to go from a MISO to PJM from a technical standpoint? He says about 10 minutes. It's the political process that will take you years. But right now, the transmission provider is the one that makes the determination, and that's Ameren. And Ameren has no desire whatsoever to move from MISO to PJM. So one of the things that the state of Illinois can do is they can legislate that the state of Illinois will be part of a different ISO. And that's one of the solutions that we think that the state of Illinois should grab onto.

And we also have Jeff Cramer from Morgan Stanley. Sir, you may now ask your question.

Just thinking about solutions for IPG, and you talked about potentially consolidating at the Dynegy level. Just with the assets free cash flow negative, can you just kind of talk about how you view leverage from that perspective, and if you were to go down that road?

Well, I mean, again, the only way we would ever bring it to the balance sheet is if it had -- it would have to have a very low amount of debt on it. And the assets we'd have to have confidence that they are free cash flow positive. Again, I would say that the assets combined with the retail book and everything, it's -- you can have a nice portfolio but you've got to get the right capital structure in place to be able to do so. And at this point, I mean, I don't want to speculate what that capital structure is or the amount of debt that would have to be reduced in order to do something like that. Again, I think the two extreme outcomes are the debt holders get the plants or we consolidate it on to the balance sheet because we've got such a significant discount on the debt. It's somewhere -- you know, they are the bookends. And where it ends is somewhere either within that range.

Got it. And just the two liquidity facilities that you signed during the quarter, $100 million at the Dynegy level and $25 million at the JV level, is this in addition to the Dynegy revolver? Or what are these?

Yes. This is Clint. There are several banks that have come into the acquisition financing, and as part of that have provided us commitments to other upsize their commitments or increase their commitments to the DI revolver. And that's about $100 million at the DI level. One of the banks came in at the JV level and provided a liquidity facility commitment to the JV. So in total, $125 million -- $100 million at the parent, $25 million at the JV at the DI level. It's just simply upsizing our existing revolver by those commitments.

Understood, okay. And then, the capacity payments that you modified, where those all sourced from assets in RTO? We assume those are the capacity prices that will be paid out?

I believe that's right.

Okay. And then just kind of the way it was structured, if -- I mean, if there's nonperformance or penalties, how does that work? Given the relationships?

Yes, we retain the upside and downside of penalties and bonuses. So it's just the base level of payment that we expected to receive for both the base and the CP that was monetized. But again, any rewards or penalties are retained by us.

Okay. And then just lastly, there were some changes quarter over quarter in the PJM in the level of PJM commitments. It was one of the slides in the Appendix. Is this following the monetization? That didn't appear to add up. We are just kind of curious what drove some of the changes there?

This is Hank. I think you may be referring to some of the true-up activity that occurs in the incremental auctions. There are opportunities to either sell additional capacity or to buy back portions of incremental -- of capacity. In the most recent incremental auction, there was -- capacity was sold by PJM as an artifact of their transition to the CP environment. They had excess capacity in the system and it was liquidated at levels at which we purchased some as replacement. I think that's what you are referencing.

Okay. So that can change quarter to quarter, based on that?

Yes

Thank you and we have a question from Greg Gordon of Evercore ISI. Sir your line is now open.

So, I'm just going to go back to beat a dead horse and make sure I understand what's going on here on page 29 in the Appendix. So, when you shut these units down, essentially the savings that flows to us as investors and shareholders, is the $200 million of cumulative savings from the reduction in the capital expenditures. The reduction in operating cost essentially is offset by reduction in gross margin and you are looking at a neutral EBITDA impact. Correct?

Yes. I mean, I will fine-tune that a little bit and Clint can check me on this, but for Baldwin and Newton, the savings -- you've got $160 million of savings there in CapEx. All right? So that's $160 million. And if you put into their additional negative EBITDA from the units over that same five-year period, it rounds up to about $200 million over five years. And then incremental to that would be the Newton scrubber, if it's not built. Right? So, Wood River, the Wood River savings, between negative EBITDA and the CapEx, is another, what, $100 million.

$100 million. That's right. And what we tried to do on slide 29 is to show at the top part of the slide, as people are modeling these plants going forward post these unit shutdowns, what should they be assuming for cost structure? And so, Baldwin at $50 million of OpEx and Newton at $30 million, Wood River and Brayton Point each at $5 million. And one of the reasons that we tried to put this out there is that I think there would be a temptation to assume, well, if Wood River and Brayton Point, as an example, are retired, that that OpEx would go to zero. And that's not really correct, because you have things like property taxes, insurance, security, other costs like that that need to be considered. And again, for Baldwin, you are shutting down two of the three units, but that does not necessarily mean that there is a two-thirds reduction in the O&M. So, we tried to lay out kind of the ongoing post-shutdown cost structure so that people could model it correctly. And then looking at those costs relative to kind of what historic costs have been, and what's the total reduction over the next five years just in the cost structure alone, that's what's on the bottom part of the slide. But like Bob said, when you think about it from a -- let's say, on a free cash flow basis over the next five years in aggregate, what do we think the benefit on a free cash flow basis is? It's about $200 million.

Right. No, that's very -- that clears that up for me very well. The other thing that just jumps out, which is fairly obvious to me is, I think other people have alluded to in their questions, is just given the ring-fence structure at IPH, and how profitable Illinois Power Marketing Company is, is there a scenario where we just lose Illinois power-generating company and then have a pretty profitable retail operation?

So the retail business is outside of Genco. Right? Is that what you are essentially saying, Greg?

Yes.

Yes that’s right.

And Greg, the way to think about IPM is that that is the market-facing entity for IPH. And so, for retail contracts that are allocated to IPH for bilateral capacity sales or so forth, they all run through IPH, and then those dollars are allocated to Genco and IPRG through the PSA agreements. So, that's how to think about IPM. At the end of the day, IPM is simply a flow-through entity where new contracts are provided to IPM through the Dynegy wholesale and retail teams. And then as those dollars come in, then they are allocated under the PSA's.

And generally speaking, Greg, the retail and wholesale obligations are not unit-specific in general. There might be a small exception here or there, but largely, they are not unit-specific.

Got you thank you guys, very clear.

Thank you. And we now have Ms. Angie Storozynski of Macquarie. Ma'am your lien is now open.

I wanted to go back to IPH, surprisingly. So, last quarter, you guys made some comments about what a big discount you trade at, given the EBITDA composition of your earnings basically coming primarily from gas. Yes, you are mentioning that IPH could offer some gas option, but you do have a coal-core portfolio in Illinois and also some other coal assets in PJM, which arguably could be actually a better gas option. So do you think that sticking to IPH through some debt restructuring actually could create more value than walking away from this ring-fencing structure that could in turn potentially boost your EBITDA because you wouldn't have that coal drag on your multiple?

I mean, it depends, Angie, on just at what cost. Right? So I mean, there's a value where it's worth retaining and there is a value where it's not worth retaining. So -- and we have to go through the discussions with the debt holders to see. But it's got to be very clear to us that it's value-accretive for our shareholders to do something like that. Again, I was just putting out really the two bookends on what could happen. I'm not saying that our goal is to move it to the parent, but if the economics were so compelling that something that -- it made since, I wouldn't rule it out either.

But do you really think that IPH is a good gas option?

Are you talking IPH or just Genco?

Just Genco, yes.

IPH, I would say definitely is because the pricing for Edwards and Duck Creek certainly get much better prices than you get in the South. It trades much more in line with Indy Hub.

Okay, but Genco?

Genco again is a little bit more challenged. Now you have PJM commitments at Newton, and we have an upcoming PJM commitment at Joppa for 240 megawatts. And Joppa is one of our lower-cost units and it has a new rail contract coming in. Its dispatch cost is going to be less than $20.

Okay. And then on -- can you give us any update, if there is one, on financing of the ENGIE acquisition? Potential financing?

Yes, Angie, I think at this point, we are planning for an early fourth-quarter close. And I think when we start looking at the calendar on when would be the optimal time for us to go to market, to me that's probably June/July timeframe. We'll make that decision a little bit later this month kind of based on market conditions. But that's what we are preparing for. The way that I want to prepare for this is to be ready to go at the end of this month after Memorial Day, and then kind of pick our moment when the market is right.

And that would be a bond offering or --?

Yes, I think we are still taking a look at this. What we've seen is, since we announced the transaction, the high-yield market has meaningfully improved. And so, at this point, we believe that we will be able to finance the entire 2.25 to 2.3 amount that we outlined in the transaction announcement, and not need to use the ECP bridge. I think most of that is likely to be term loan B or some type of secured instrument. We are just going to have to see what the condition of the market is at the time as to whether or how much second lien or unsecured notes would be involved.

Okay, thank you.

Thank you. And we have a question from Shahr Pourreza of Guggenheim Partners. Sir, you may ask your question.

Most of the questions were answered at this point, but just curious, on the service fee that you were collecting from IPH, I think it's sort of made up between some G&A and O&M support -- and I understand IPH is sort of ring-fenced, but in a situation where you were to just hand the keys of the assets to the bondholders, is there sort of any liabilities that could come up as a result of that? Or any sort of prolonged mismanagement of the assets or anything that can come up?

No. I mean, we -- when we originally established the ring-fence and the service agreements, and the energy management agreements, it was all done utilizing arm's-length transactions that were reviewed and verified by outside third parties. I would also say that on the Genco allocation, we've been doing things to actually give Genco a little bit of relief. We actually had not even been collecting the fee this year, which runs about $3 million -- a little over $3 million a month. It's just been an accrued payable to us at this point in time this year, just to make sure they are comfortable with the right level of liquidity down there. So, we feel again, with the ring-fence structure that's been put in place, third-party review of it, the verification, not only by the outside third parties but also by our Genco Board members, that it's a fair allocation. And we've played this right down the middle. And we wanted to make sure that, from day one that we operate in the very best interest of the stakeholders of Genco. And we continue to do so. And in the discussions this morning around Genco, I mean, I also want to be respectful of the bondholders as well. We want -- we are going to have our first meeting in a couple of weeks and have discussions about what's the art of the possible here? We want to work through this jointly. We don't want this to turn into a situation where it becomes very contentious and becomes a very large legal exercise. We don't think it has to be that. And from our standpoint, we've made sure that we've done everything we've needed to do over the past few years to ensure that there isn't any issue whatsoever around how it's been -- how Genco has been run and how we've managed the liquidity. I think the decisions that we have to make around shutting plants and the scrubber, everything, is done in the context of making sure that this is in fact in the bondholders' best interest. I don't think there is any bondholder out there that would say, gee, we really need to spend $200 million right now for a scrubber. I mean, the facility just doesn't have -- the subsidiary just doesn't have that type of liquidity. So, again, everything that we are doing, whether it's service agreements or how we run the business day-to-day, is to ensure that we honor the ring-fence, and we do what we need to do in terms of our fiduciary duty towards the bondholders.

That's reassuring. Thanks, Bob.

Thank you. And our next question is from Praful Mehta from Citigroup. Sir, Your line is now open.

So quick question on I guess IPH, which is one of the options clearly is, you kind of consolidate obviously the need to take, or the debt holders need to take, a meaningful hit in terms of what the value of the debt is. I guess in exchange for that, is there a consideration that they could get warrants or something up top? Because I'm assuming if they take some form of a hit on their own value of the debt, they would look for some at least option value on the upside if IPH were to turn out to be meaningfully positive.

It's probably getting a little too granular. I mean, we have to have discussions with the bondholders, and I think those discussions will happen behind closed doors for the time being. Our first meeting is really we are going to just put out our position and make sure that we wanted to come forward today with as much public information that we felt that the first meeting would be productive without asking bondholders to get restrictive. So, that's the plan just for now is just to exchange ideas and thoughts around this thing, and we haven't thought anything about what a settlement looks like. We need to understand their position and they need to understand ours, and then we'll build from there.

Fair enough, completely understand. And then secondly, on this MISO capacity position, for all your uncommitted megawatts now, given the plant shutdowns, which you clearly laid out, makes sense, how do you see that? Is there enough market you see on the bilateral side or through the PJM side to kind of clear the uncommitted megawatts? And how are you thinking about those uncommitted in the ’18-’19, ’19-’20 timeframe?

Well, I mean, what we've seen in our retail businesses, our Homefield Energy business is doing quite well within Zone 4. And that kind of was borne out last quarter when we announced how we picked up nearly 1,000 megawatts from Good Energy at close to $4.50 a KW a month for the capacity. Right? So what we are seeing is that other retail providers don't necessarily like to come into Zone 4 because they have to buy capacity or be short capacity and take it to the auction. And you said that this last auction, if you look at that bid curve, if that demand moves by 500 megawatts or 1,000 megawatts, it's an entirely different price. So any retail provider coming into the space without generation is making a big bet on what capacity is going to clear at. And certainly now going forward, if Clinton were to retire, if you have -- you know, you had these assets coming out of the marketplace, I mean, all the slack is gone out of MISO. So coming in and selling retail, unless you have generation, is -- and what we are seeing is not something that outside retail providers actually want to come in and do. So, a matchbook for us is the right strategy in that market. And I'm not worried at all about not being able to move the megawatts through our retail book in 2018/2019. We've got a great retail team, and we've got the right assets spread across the state to back that retail business.

Yes, that makes complete sense. Thanks, guys.

Thank you. And our next question is from Michael Lepides of Goldman Sachs. Sir, you may now ask your question.

Two questions about the Northeast power markets. First of all, New England, and I'm sure you've addressed this over the last couple of months. There are some market design changes that are well underway, including the kind of the convex demand curve and the shadow bidding. And the market cleared long in the last capacity auction. Can you just talk a little bit about your expectations going forward from here, in terms of New England supply and demand for capacity? That's question one. And question two is, with the cancellation of Northeast Energy Direct and continued delays in Constitution, can you talk a little bit about what that means for your gas power plant fleet, thinking Independence in New York but also the entire New England fleet?

Sure. This is Hank. The -- in terms of the changes in the Northeast there in the capacity market and the available -- the supply and demand balances, there is still 4 or 5 gigs of high heat rate steam units that are at risk. And in a performance incentive environment, they will struggle. And our expectation is that there are a lot of assets on the bubble. The -- we were encouraged by some of the recent developments, pending confirmation, that the -- that there is some transitional curves that are a big part of the conversation to smooth out the transition from the present construct to the downwardly convex zonal curves that are proposed. The -- again there's -- along with pipelines, there's still a lot of -- our expectation is it's difficult to build in New England, that [indiscernible] slows a lot of this stuff down. We think the market will -- the power generation market will remain tight up there. And it is -- the curve is highly-leveraged to incremental supply, but there is a lot of generation that's at risk up there. In terms of the Northeast Direct and Constitution, the -- this last winter, there wasn't the normal separation from West to East in terms of gas basis. In the wintertime the East is, as you know, goes to substantial premiums when demand is high. And there was -- it was extraordinarily low gas demand, because it just wasn't cold in the Northeast. So that separation didn't occur. We see incremental capacity inching its way towards the Northeast to liberate some of the trapped Marcellus gas. But these delays or cancellations and -- would perpetuate the notion that the -- that we would see premiums in the East in the wintertime, and that we would see continued strong negative basis for Marcellus and Utica gas, which directly feeds our New York Independence asset as well as our CCGT's Liberty, Ontelaunee, Washington, Hanging Rock and Fayette. They buy some of the cheapest gas in the United States and our view is that they will continue to do so. Because these pipelines not being built or being delayed continues to leave a lot of gas trapped in that region.

Got it. Thank you, Hank. Just one quick follow-up on New England. Any thoughts about why -- we are in our second year of having the performance program in New England similar to CP and PJM. Any thoughts on why some of those high heat rate steamers -- I mean, I think there's 5 to 6 gigawatts of oil units -- continue to clear in these auctions, despite having some very different risk parameters in what they had three, four, five years ago and beyond?

I can't speak to the behavior of what other folks are thinking, obviously, but the -- until the performance incentives payments -- until the penalties actually occur, it might be that the risk profile is being underestimated.

Got it. Thanks, Hank. Much appreciated.

Thank you. And we will now take our final question from Ashwin Reddy of Venor Capital. You may now ask your question.

Ashwin?

[Operator Instructions]

Just a quick question for you. When we are thinking about Zone 4 over in MISO, I was curious to see kind of what your thoughts are on other guys kind of doing similar things to where you guys are, to kind of help correct the situation in the market? Obviously Exelon is out there and everyone is debating what's going to go on with Clinton, but wondering if you could just talk a little bit about that?

Well, I mean there's obviously no question that Exelon is going to try, I think, to reinvigorate the low carbon portfolio standard. I mean, ideally, we would rather see a solution that helps everyone. I would say in our discussions with unions and our discussions with the legislature that the interest is around getting the situation correct for all the generators in central and southern Illinois. So, while I understand while Exelon wants to pursue a fix, because they obviously suffer from the same shortcomings in the market that we do, a solution for the state I think is a much better outcome for the state. And I would say the unions and the legislature in our discussions are thinking more broadly than just helping one company.

Okay, thanks.

Thanks, Ashwin. I guess, operator, that concludes our call this morning. Thanks, everyone, for their interest and we'll look forward to any follow-ups. Thank you.

Thank you. And that concludes today's conference. Thank you for participating. You may now disconnect.