Dynegy Inc. (NYSE:DYN)
Barclays CEO Energy-Power Conference
September 08, 2016 11:45 AM ET
Bob Flexon - Chief Executive Officer
Unidentified Company Representative
We're happy to have Bob Flexon here, CEO of Dynegy, to take us through the Dynegy story and he'll do that and then we'll do some in room Q&A and then there's a break out after this in the Riverside Suite. So, Bob?
Good afternoon, everyone. I'm not sure if it's a blessing or a curse to be going last. But I guess all the angry people have left. So that should help. Basically what I want to try to convey in the presentation today is that when you think about Dynegy and the kind of expression - this is not your parent's Dynegy. This is one that has changed dramatically over the past 18, 24 months, and it's a very different portfolio today than just a few years ago where it was dominating by coal and being in the MISO marketplace and the other portion of the fleet being in a different country out West in California. So, it's just – we’ve got back to civilization, we're back in the East, and other than New York it's nice to be back East, put it that way.
So, I guess the Canada sales pitch here is when you think about Dynegy, first of all, we think we build a portfolio that has longevity. These are the assets that run. These are the assets that are needed to firm in a minute type of capacity that's showing up in the markets. And these are the assets that actually have access to low cost fuel sources such as natural gas and PGM and for us here in New York as well as New England and then certainly with the leverage that we have in the Illinois marketplace and Ohio around coal, we've got some leverage where we can get aggressive pricing on both not only just coal, but also probably the more important piece being rail.
So, it's really evolved into a strategy of having the right assets that are in the right markets and the right markets being the ones that are well constructed with capacity market design and proper price formation, things that a competitive market really needs in order to ensure that there's proper price formation.
Then the other thing that I would highlight and we'll talk more about in the presentation is what I think is going to be a core competency that we’ve developed out of the gate and that's building a very low cost scalable platform. From day one we've focused on what are the ways to make Dynegy a very low cost enterprise that can add assets without adding G&A. And we can talk more about that as we go forward.
So, the portfolio today, and this is kind of a pro forma look at the portfolio where as once we complete the ENGIE acquisition, which we would expect to be in just the coming weeks and we have some retirements under way, that our portfolio once all those things settle down through the balance of this year and into the next with Brayton Point up in Massachusetts is that our portfolio going forward will be 31 gigawatts, 22 of that in gas fired assets, the balance being in coal.
But then you see, also started looking, where are those assets? PGM is going to be about 50% of where our assets are located and then with the acquisition of ENGIE, ERCOT gets to be a fairly sizable market for us at 19% with the gas assets and we've got 7% more on the coal side, 7% of the assets on the coal being ERCOT and Coleto Creek. And then New England, again, another very well structured market and then more the legacy markets around Illinois, MISO, and California. But again, kind of the take away point from this is that the gas fired assets we had being the biggest combined cycle generator in the East.
We're the biggest in New England, we're the biggest in PGM. We've got access to low cost gas. So, our portfolio on the gas side is a very strong generator of free cash flow in today's environment. When you look at pricing, even like today in PGM, in the $40 and $50 on peak, we're still buying gas at $1.25, $1.50. So, very strong sparks spread and that gas advantage has been a year round phenomenon for us, you know ever since we've acquired these assets. So, our assets in Central Pennsylvania, Western Pennsylvania, Ohio are running as base load assets, running all the time and buying the gas at a very substantial negative basis to Henry Hub.
Then on the coal side that offers some of the outsized return in the portfolio, the view is natural gas is going to rise. Our coal portfolio benefits from that. But our philosophy around our coal fired assets, they're either generating positive free cash flow or they'll be retired and we've aggressively done that. We've retired Wood River, which was 450 megawatts of generation. We've retired Newton unit 2, which will be shut down and then permanently retired mid-September.
So, that's taking out another 600 or so megawatts and we've mothballed Baldwin units 1 and unit 3 which is another 1,200 plus megawatts. And they'll be mothballed, they'll still be required to bid into the capacity option, but they will be bid in at a cost level that would have to justify bringing them out of the mothball status. So, if the coal assets are not generating free cash flow, they're being either retired or mothballed and we've been doing that probably more aggressively than others.
So, today when you look at the construct of the portfolio, how has it changed over the last couple of years? Before, if you look again by MISO, we were 72% MISO, now 47% PGM. That's quite a shift. MISO goes down to 13% and our strategy around MISO is while there's a lot of talk about correcting and improving the design of the capacity market in MISO, we're not actually going to wait for that. We are matching it with our retail book, we are taking any excess generation that we have above that trying to get into PGM.
We recently just agreed to move 260 megawatts from our [indiscernible] facility in the PGM and 240 megawatts from Joppa will be going into PGM, both Pseudo tide into PGM in - I think it's in the summer of 2018. So, we're moving the excess megawatts into PGM. Other than that, it's the matched retail book. We have some limited length in MISO and again if the prices come back strong or the capacity market develops in a much better length, we've got Baldwin 1 and 3 kind of sitting in the wings where we can bring that back if the economics so dictate that.
And so by fuel type, and again, going back to opening comments, this isn't your parents' Dynegy. Where it used to be three-quarters coal and a quarter gas and the gas was basically peaking units, it's now 68%, 70% gas at this point, modern, fuel efficient, provides cycle units. In fact, I know Caplan that was just in here, and I assume if Caplan's not in here, I can say nasty things. Is anyone from Caplan left? No. In Caplan, one of the things they like to comment on is they've got the youngest fleet, which when you look at the overall portfolios, it's true. But if you look at the gas fleet for both companies which are almost now similar size, we're the same or slightly younger once we have the ENGIE portfolio. So, this is a very well constructed portfolio in the right place with assets that have the longevity.
And then you take a look at how the company has changed in terms of by region, it picks up from the slide a moment ago, we view the premium market as being - PGM, New England, and now ERCOT, if you look where we were back at the end of 2014, that was 25% of our portfolio. Today we're sitting at about 80%. That's our portfolio. And then some of the legacy markets, like California and MISO has gone from being three-quarters of the portfolio down to just about 20%. So, again, another huge transformation and that also flows right through to the bottom line. You look at where does all of our EBITDA get generated from in today's environment. It's from the gas portfolio where it's kind of the 80-20 rule, 80% coming from gas fired assets.
One other thing I didn't necessarily comment on, on the earlier slides, one reason that being in PGM and MISO in New England is the capacity structure. You look at the capacity payments that's embedded in our portfolio, roughly 40% of our gross margin is coming from capacity revenues out of a forward three year look. So, when you think about volatility and hedging and things of that nature, we get as a percentage of our revenues, percentage of our EBITDA, more from capacity than what some of the other generators are getting because of our location.
And along the longevity line, when we talk about these are the assets needed to run, when you look at actual megawatt hours generated, even though we are not - NRG is certainly more sizable than us in terms of name play capacity, but when you look at the three main IPPs, ourselves, Caplan, and NRG, where are the megawatt hours being generated. Even though we're at 31 gigs, we'll have more generation than what NRG has, just again showing that these combined cycle units that we have particularly in PGM, New England, and New York are running around the clock as base load units and we're just getting a lot of megawatts out there. It's more than just clipping the capacity coupon. These have strong energy margins as well as getting the capacity. And you think about longevity, these assets are going to be around for quite some time due to their favorable location in the right market.
And going back again to some of my opening comments around why we wanted to have the skill of leveraging our scale and how we've done with that over the year, what this slide tries to highlight is exactly how it's transformed. So, when we arrived, when the existing leadership team arrived at Dynegy back in 2011, they just came off a year where the G&A was $137 million and the first thing that we wanted to address as a unit is to make sure we've got a platform that is cost efficient and both scalable and again, on arrival at Dynegy, very good IT systems, a lot of good money previously spent to build the infrastructure, which historically had run a bigger portfolio.
But there was certainly a heavy cost structure around it. So, right out of the gate we took that G&A spend down quite substantially, you can see the $137 million down through the $86 million. Again, that's the same amount of megawatt hours that were being generated at the time so we were able to reduce the G&A by roughly a third and bring our cost per megawatt hour down in terms of our overhead cost per megawatt hour down from $3.54 to $2.21 and through a series of acquisitions then we were able to take that original $3.54 per megawatt hour of our overhead costs and bring it all the way down to what today would be about $1.12, representing nearly a 70% decline.
And you can see in this slide the various acquisitions done along the way, the impact on G&A and the impact on the amount of generation that we had. So, again when you're taking your generation from 39 million megawatt hours, going up to 130 million megawatt hours and you're seeing your G&A really just getting back to where it was when we arrived, that's really taking advantage of the scale in an efficient cost structure. And the next thing, like I said - I'll skip this slide and come back to it.
When we talk about PRIDE, it's an initiative we started right out of the gate where it's our method of enhancing and driving cost efficiency, innovation within the company, finding ways to lower your cost structure, finding ways to generate incremental gross margin whether that be through things like low cost up rates for some of the existing assets or could be just cost structure within the corporate headquarters or cost structure within the plants, driving reliability, force outage rates down, things of that nature.
We've been doing this since we arrived. And some time during the course of this year PRIDE projects and PRIDE is the improvement program we talk about but in terms of improvement projects that have generated a positive return, we kind of log all of them, all of them are audited to ensure that our disclosures are indeed substantiated and tested.
We'll come to our 1000th project this year and that's going to be kind of a mini celebration in the company for whoever brings forward that 1000th project at PRIDE since we've been doing this since going back to 2011 and it really is - when I think about the legacy of Dynegy and what do we really want to be known for, we want to be known for running a very cost efficient operation, very strong reliability from our plants, great safety record, very good environmental record and we can use that platform to be a scalable portfolio that you can lever and lever that base and the PRIDE program is in fact our calling card for that.
When I think of all the things we've done, the most important thing that we've put in place is that philosophy of always getting better. And you can see under the EBITDA one, historically in 2011, 2012, the first thing that PRIDE was aimed at was getting the right G&A structure in place post the G&A, we find other opportunities to pursue around reliability, around the plants, around different ways to get up rates from existing plants and things of that nature.
So, I go back one slide and just talk about the balance sheet, I think the other thing in terms of things that are within our control that we need to work on is just improving our leverage and again over the last couple of years it's been if we didn't get the right portfolio in place, the leverage of the company would overtake us. And we've been in a lot of difficult situations, but now that we've constructed a very durable portfolio in the right place and the right structure, it's now again - now to recalibrate our balance sheet. So, when I think of our activity in the past as being more around portfolio building, this will be more around now going forward the next couple of years, the portfolio shaping and now bringing the balance sheet back into what we think would be the sweet spot.
So, here we are in 2016, carrying a net debt to EBITDA around 6 or so. There will be of course events over the next few years that should bring that down 1.5 to 2 times and the first one, the embedded debt reductions. We have about $450 million of debt that will structurally come out over the next couple of years just because of the way it's structured in the balance sheet. A big portion of that, around $240 million or so is around our forward capacity sales that we made for 2017 and 2018. So, when 2017-2018 comes, and we then actually receive those capacity payments, they will go to actually just replace that forward sale of capacity payments that we have. We have got $84 million of term B that will mature during that time period and then another big chunk, around $130 million, $140 million is associated with financing around our emission credits and inventory that is already, if you will embed it in our EBITDA when we actually purchased some of the portfolios that came with a bank of emission credits, we actually warehoused them to the bank as a source of liquidity and had them hold on them.
And as we utilize those emission credits, which are built into our forward curves, we'll actually take the proceeds from net energy sales and effectively pay back that financing warehouse for those emission credits. So, the combination of term B maturity, the prepayment of the forward capacity sales and the natural amortization of the emission credits and the inventory financing around some of our coal purchases that you have about $450 million of debt reductions between now and 2018.
During that same time period we'll have capacity payments that are strengthening as we go into 2018. I think the legacy portfolio has about $200 million increase in capacity payments or so, so you get a natural rise in EBITDA, which in effect by calculation brings down your leverage and then the final element in the third column there is the growth in free cash flow, having the ENGIE portfolio, the stronger capacity payments.
I mean, the sustaining thing around our balance sheet would be strong free cash flow generation, which drives the net debt number down and I think the general philosophy will continue to be not to hoard cash on the balance sheet. We would actually, as a first order of priority take that cash and reduce our debt, our third-party debt. So it's not going to be one where suddenly you've got this lump of cash on the balance sheet, net debt looks good, and then you use it for something else. This will in fact, we're committed to actually paying down that debt and getting the leverage down within a timeline.
Now, what's not on here, which could also affect the timing of the leverage pay down is we will continue to look at certain assets we potentially will monetize as we trim the portfolio. The timeline on that I think the first order of business right now is to get the finally ruling on the ENGIE acquisition. I don't think they're going to ask for divestment of anything, but if they did it would be in New England. So, there could be a possibility that we might do something in New England. We should find that out, I imagine, again, just in the coming weeks.
We've recently sold our other half of the Elwood facility and we'll be getting the proceeds back by the end of the year as well. But there could be other asset sales beyond that, potentially a peak or a combined cycle and we'll continue to look at what are the best ones that would do that. And I think again timing for that, we'll kind of agree on which assets they are over the course of the balance of this year. Right now there's a lot of M&A activity out in the marketplace. Buyers are very caught up in different portfolios that are out there and then we will again I think be looking to see if there's any opportunity as we go into 2017 to do any type of asset sales during that timeframe.
So that's specifically to the company. The other element I wanted to talk about is just some of the market dynamics that are happening in our core markets. And what we try to do on this first slide on the current market dynamics is really just kind of highlight how our qualitative assessment of the different markets and what are the strengths and what are the weaknesses in the various markets and much as I've alluded already with the PGM market is the one that we continue to do that. It's the best structured markets where we want to be the best priced formation and I think PGM, maybe more so than some of the other ISOs defend their marketplace and tries to ensure that things that are done out of market are addressed appropriately.
They take the leadership as New England on capacity performance and performance incentives. They've got the nice forward-looking. So, it's just a well designed market for us and again the type of asset we have in those markets and where those assets are located is a real differential versus, say, our competitors. If you've natural gas fired assets, you want them, Central Pennsylvania, to the West. That's where the fuel advantage is, not to the East. So that's why PGM is so attractive to us. So, you can see I don't need to go through all of them. You can see where our megawatts are concentrated in the markets we tend to prefer.
MISO for us, again, a work in process. We're not relying on market design. We're relying more on our retail business moving our wholesale generation. There's not many other competitors selling retail in zone four. So, if they do, they actually have to buy the capacity from someone. We're the biggest player on capacity. So, the retail book is the method in which we will run our MISO business. And I'll get more into MISO in a minute but I think they're going to have some structural issues around enough supply in the marketplace.
I won't beat on California. It's too easy a target. Maybe again, I'm getting a little bit redundant here with the PGM overview but if you look at the dispatch curve, the red dots on the slide are just highlighting where our assets fall on the curve and on the high end of the curve there are peak assets and on the low end of the curve that tends to be the combined cycle assets. And we've got some coal assets down there as well. So, I think for Dynegy we're very well positioned there.
I think the main take away from this slide, and again when we were putting this together the thing that just kind of really resonates with me when I look at the slide is how much the generation in PGM comes from coal and nuclear. You put those two slices together, it's 72%. And in 2015 the independent market monitor came out and talked about the coal plants, and talked about roughly 60% of the coal plants in 2015 were cash flow negative. So, if that one wedge of 37%, 60% of those are losing money. And then nuclear, the other 35% there, I think it's pretty well known that virtually all nuclear is losing money, other than say in Virginia where it's regulated.
So, I don't know what the percentage is and the IMN didn't address it but it's got to be 70%, 80% of the nuclear capacity is probably losing money as well. We know Exelon's trying to get support in Illinois and we know First Energy's trying to get support in Ohio and Three Mile Island didn't clear the capacity option. Susquehanna, also in Central Pennsylvania, is competing against $1 gas and even just to use this weekend as a marker.
Over the past several days off peak pricing in that territory has been $9. So, if you're running a nuclear unit and getting $9 off peak, it's not a pretty scene. At least if you have a coal plant you can either cycle it down or cycle it off. Nuclear obviously is running just continuously base load around the clock. It's a very tough asset to have in PGM with Marcellus and Utica gas being right there.
So, there tends to be a lot of focus on G&C, we've got 3,000 megawatts of new build coming. The question is and I think the question in all investor's minds is how long can these assets lose money and stick around. I know for our coal plants in Ohio, Zimmer and Miami Fort, free cash flow positive. They're doing okay. But on the other hand, our share of Stuart, we know that Stewart is a very challenged asset and Stewart is going to have a little bit more of a challenging future.
And before you make investment decisions to comply with Effluent Limitation Guidelines or ELG or 316B or 316A, whatever the regulation that you need to comply with, you really have to think from a capacity performance perspective as well as the driver reliability investments, are you going to make that investment now? You can no longer lean on base capacity product. It has to be CP. You've got to start making those decisions now to spend on ELG.
So, there are coal plants that are going to have to come out of the stack. And I know that for some of our coal plants in Ohio, some of them are more challenged than the others and much like we've done in MISO, we're not going to let assets stick around that are free cash flow negative. And I think others are going to have that decision. And everything around nuclear subsidies in these different markets are going to play into it. And if they're not getting subsidies, then I think Exelon's been clear of late around this, I think Quad cities would be at risk of shutdown along with Clinton and MISO.
You can't just keep running in the negative. So, I think that's the big takeaway with PGM. How does capacity performance, 100% that's going to squeeze out some demand resources, is it going to squeeze out some coal, is it going to squeeze out some nuclear along with the fact that it's just the pricing because of low gas environment is going to continue to challenge the economics of those plants.
New England, it's not that much of a different picture. Again, we're low on the dispatch curve. These are our gas fired assets. The big change for us will be retiring Brayton Point at the end of this next winter. So, when we get to May of 2017, Brayton Point will be in its final stage of shutdown. You'll also have Pilgrim leaving the market not far thereafter. So, the takeaway with New England is really two things.
One, that you can't build anything new there and we've seen that even one thing that we support reluctantly was if utilities want to rate base new gas lines to bring new gas into New England, we supported that as generators since we don't want to be against everything. Sometimes we are. But that was knocked out by the Supreme Court. So, no rate based gas pipeline.
So, now it's like merchant gas lines trying to come up into New England and for our assets in the Southern portion of the state, and 25% of it has firm capacity, it's on an evergreen contract. So, our plants are okay, but when it comes to winter time, New England is gas constrained. So, it's always going to create in a high demand period, it's going to create shortage pricing. And it has in the past. It didn't this past winter because New England never really had that situation. But nobody's building anything that's going to solve that in the near-term. The other thing with New England that's been a bit of a threat to us is again political ideology.
And in Massachusetts, we saw recently the legislature there approve -- they wanted to find 2,600 megawatts of the highest cost stuff they could possibly find. They were able to do that so they approved offshore wind and Canadian hydro that will be about 10 times the cost of conventional generation because they think it's going to save the world and will reduce their carbon footprint. I did tell them, it will reduce their carbon footprint because everybody's going to leave. Right?
So, I think that's the challenge in New England with again out of market things were competitive markets were built around a theory that let the lowest cost megawatts serve the customer. And it works as long as the states don't get involved and Connecticut's talking about subsidizing Millstone, if -- and again I'm meetings with the governors and governor in Connecticut was we have to please first make them prove to you they're losing money. And they said they would do that.
So I don't know if Millstone makes money or not, but it comes through the January legislature. I think they probably have a lot of momentum behind them to try to get something for Millstone, which will be challenging of course. We'll get to New York in a moment. But I think the kind of the takeaway on New England is short on fossil capacity because you can't build anything. Short on pipeline capacity coming into New England. So, in high demand periods in the winter the gas goes to heating requirements rather than generation. So, it creates shortage pricing.
Things to watch is going to be will they ever build offshore wind where the Kennedys can't see it so they can actually do it. And will they actually bring Canadian hydro in and pay the freight for a transmission line that goes through 60 miles of granite. I guess it's the Big Dig 2 coming your way in New England and then the Canadian cost. We don't think it effects the capacity market. They've mitigated out if they were actually to bid in, but carving out a 2,600 megawatts out of the energy market has an impact on the competitive generators so now they're competing for a small amount of merchant megawatts than otherwise they would have to.
ERCOT, I think, I know Thad was just in here and they certainly are more versed in ERCOT than what we are at this time since we're just moving into it. So, for us, it's a new market for us. We're picking up four efficient combined cycle units well located near load pockets. Kind of our decomposition of our purchase price, we said, we're entering ERCOT at about 250 or so per KW, which is obviously one quarter of replacement costs. So we're getting in there and I think at a very good price.
Coleto Creek is the one coal plant that comes with it. Coleto Creek is free cash flow positive if regional Hayes comes into play. It still is free cash flow positive. We'd have to put a DSI scrubber in. Whether we do that or whether we come up with some other type of implementation plan that would give a runway to the facility of something to be determined, but I still see Coleto Creek free cash flow positive even if you put in a DSI and have to hire on [indiscernible] the cost that comes with having a DSI in operation.
So, it still looks like a viable entity. We're making about $20 million of free cash flow for that particular market. I think the question for the ERCOT market is going to be with the penetration of wind and with the potential penetration of solar, how is that going to effect the non-flexible resources, being nuclear and to some extent coal? And if you're in a non-attainment area, which Coleto Creek is in an attainment area, if you're in a non-attainment, whether regional haze goes through or not doesn't matter. If you're non-attainment you're going to have to meet the same type of environmental retrofits. So, the question is going to be does TFC do anything with their coal plants? Does NRG do something with limestone or not? And it gets back to the conversation we had at an earlier time.
New York, I want to pick this up. I'm down to three minutes. New York, the whole story there is we've got independence, 1,200 megawatts, buys gas from Dominion South. So, we're getting gas again, $1.50 or so in this market. Strong sparks spread in periods of time with high demand. We're selling at prices that the marginal megawatt cannot get gas at our price. So, if this is a true gas by wire plant, it's a very strong spark spreads. The issue with New York is Governor Cuomo feels compelled to give $8 billion to Exelon to keep three plants running in upstate New York and to give the one finger salute to Indian Point.
So, the challenge for us is going to be we're going to have to challenge that. Again, if you let economics work, these plants lose a lot of money and the whole issue with this is from our perspective, this impacts wholesale price formation and probably the simplest way to demonstrate that is Fitzpatrick gets retired without the subsidy. With the subsidy, Fitzpatrick runs. This effects wholesale pricing. This effects wholesale pricing beyond New York. You've got imports that come into New York. Our view is this is the jurisdiction of FERC, not New York. And you can't do it. But I think this will be challenged in the coming weeks and months and it's kind of really an important litmus test for the IPP space of trying to make sure that subsidies don't enter into the market and have an impact on price formation.
I talked about MISO. We're all coal in MISO. We do have a little bit of gas peakers that we brought back from the dead that Cameron had mothballed. We spent $5 a KW to bring them back. That's what's on the far end of the dispatch curve. The issue around our MISO assets, I mean, MISO's getting short on capacity. And the St. Claire fire didn't help that. That took out another 1,500 plus megawatts. And MISO is at the point where they might not have enough megawatts to actually even have an auction and if that's the case, you're going to get pricing of $7, $8 per KW.
So, nobody's building anything. There's still a lot of renewables that come in from the West, but MISO because of the weakness and the design of their capacity market, nothing's being built, a lot's being retired. They're going to find themselves short. Clinton obviously is a big decision for Exelon in the coming weeks. We've made our retirements. We presume that Clinton probably goes away as well, making matters even more difficult for MISO and meeting the supply demand.
So, kind of the final wrap up, our priorities in the near-term is get the ENGIE acquisition closed, realize the synergies, and then if we close before the quarterly call in November for the third quarter results, if we close before that, I presume we'll come to the market with an updated synergy number, kind of the next round of synergies. Get the transaction closed and continue to identify which assets would we want to take to the market and see if we can do a credit accretive transaction around that.
I think in terms of how we need to emphasize some of our resource allocation internally, it's really raising the game right now on defending the competitive model. And we just see it attacked from multiple sides. Massachusetts with the renewables, Connecticut with their subsidies and again some out of market hydro. Ohio with First Energy and AEP and Illinois with Exelon. So it's a fairly long list. We've got just to continue to try to support the market as much as we can so we get again the proper environment for an IPP to survive.
And capital allocation, the one thing I haven't touched about, we're going through the restructure with IPH. I think we should have very good clarity on that by the end of the year. And bottom line on capital allocation is to manage to our leverage targets, by or sooner than the end of 2018.
So, with that, that's the conclusion of the presentation.
Unidentified Company Representative
We'll go straight to the breakout in the Riverside Suite. I'd like to thank Bob for coming and spending time with us today.
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