Dynegy Inc. (NYSE:DYN)
Investor Day Conference Transcript
January 17, 2013 2:30 PM ET
Robert Flexon - President and CEO
Clint Freeland - Chief Financial Officer
Carolyn Burke - Executive Vice President and CAO
Catherine Callaway - EVP, Chief Compliance Officer and General Counsel
Mario Alonso - Vice President, Strategic Development
Kevin Howell - Chief Operating Officer
Pat Wood - Chairman
Hilary Ackermann - Independent Director
Jeff Stein - Independent Director
Mike Gray - VP, Commercial Operations
Brian Despard - VP, CoalCo Asset Management
Alan Padgett - VP, GasCo Asset Management
Dean Ellis - Senior Director, Government Affairs
Dan Thompson - Chief Operating Officer, CoalCo Operations
Marty Daley - Vice President, GasCo Operations
Gregg Orrill - Barclays
Okay. Good afternoon. Thanks everyone for coming out to the Analyst Presentation that we put together. Hopefully, it will meet everybody’s objective certainly and talking with folks here, here today and speaking with a lot of our investors overtime.
There’s a lot of questions that have been coming up around, how do we see the earnings potential of the company, the liquidity, refinancing, capital allocation and our attempt today is to go through all of those issues with you and provide the detail that supports our thesis around why we believe Dynegy is a good investment.
With that, here we go, we’ll go through in terms of the presenters today and from the management team in addition to myself we have Clint Freeland, our Chief Financial Officer, who will obviously present the financial portion of the presentation. And then also the other members of the management team, Carolyn, Catherine and Mario are all here in attendance.
The one difference from the management team from the last time we’ve spoke publically is Kevin Howell, the Chief Operating Officer is transition back to semiretirement position. When I joined Dynegy back in July of ’11, Kevin was the first person I called and he was actually at Dynegy then before me. He immediately came down to help out and continue on and help with the restructuring. And Kevin now is, his plans always were to go back to retirement. We’re doing as much so can slowdown as we possibly can.
And Kevin is still on as an Advisor and certain things that Kevin has working on and particularly you’ll hear a lot today around. We are working to resolve the dispute with Southern [Kalidis] on the towing arrangement out in the west. Kevin is on point for that. He has developed the great working relationship to his counterpart over there and we are trying work through that in a very productive way and that’s one of the key area Kevin is focusing on.
And when we think about replacing Kevin, the thing that is a high priority to me is to get someone that is on the trade floor every single day. And so we've been looking for Chief Commercial Officer which when we talked about Kevin retiring, in the press release we announced that we would think we would have that person on Board or announce in the first quarter. And I’d say at this point in time we are very far long in those discussions and I’m very optimistic that that will be public in the next several weeks.
The Board of Directors, I guess that I -- I don’t know, I went in the wrong direction. I skipped which is never a good idea. But the Board of Directors was assembled by the creditors committee back in October and I’d say from the management perspective it’s an excellent Board, very involved, very proactive and very, very good experience is Chaired by Pat Wood and Pat is here in the audience today, in the back sitting next to Hilary Ackermann, also one of our new Board members and then, I guess, the three are right there together, Jeff Stein in the back as well.
So I know several of you know Jeff, Hilary and Pat. I just want to make sure that the whole room knows that they are here. So there is no advantage if you will and plus if you want to tackle them and not me that’s okay too.
So again from the Board perspective it’s worked out really well and we are thrilled to have as part of the team.
Other speakers today Mike Gray will cover the commercial area; Brian Despard to his left is our Co-Asset Manager; Alan Padgett, manages the gas fleet; Dean Ellis, Regulatory and Clint. And also we have Dan Thompson who runs the operations for CoalCo; and Marty Daley, who runs the operations for GasCo. So we’ve got a lot of our experts here and there is a few other folks from Dynegy spread out through the audience as well.
So that brings to the, why invest in Dynegy? What I want to do in my presentation is really to go through these three areas on why do we think on a risk-adjusted basis, on a value oriented play that Dynegy is a good investment.
We see it really pulls down the three things. We see limited downside risk. We see multiple ways in which earnings will develop within the company particularly at the CoalCo level, and finally, we have several capital allocation alternatives that we can do to drive value as well.
I’ll go through what I think supports each of these areas highlight on and then the balance of the presentation with our staff, we’ll go through and build out that detail to provide additional thoughts and support for those three areas.
So starting first around the balance sheet and say limited downside risk. We think about that in terms of liquidity, strength of the balance sheet, you can take a look at how we’re valued.
And we start up, I think, if our equity is trading at around $20 a share, we work through the debt that we’re carrying on net debt basis, you got enterprise value of $2.5 billion. If we say that all of the value is attributable to GasCo and divide that by -- if you take the $2.5 billion divide that by the megawatt of GasCo that comes out about $380 of kilowatt for GasCo.
And if you look on the top right-hand portion of the slide, shows comparable with how similar assets in PJM and NYISO have traded over the past year and $380 of kW for our gas fleet I believe a reasonable assumption, and I actually would argue it’s higher, but just in terms of relatively it's not out of the question.
So then I believes no value for CoalCo in our equity and in terms of our enterprise value, in terms of our equity value. And again, looking our comparable sales of coal plants that happened recently, say its $240 of kW, $240 of kW, we’ve got 3000 megawatts of coal that translates to additional $7 a share above where we are today.
So we believe in terms of how the market is looking and valuing us today, as well as other IPPs, there is limited value assigned to the coal generation assets. But additional downside protection we view through our hedging program and when we hedge our asset and Mike Gray will go into further depth around this. We view GasCo in the low gas environment is our stable cash flow and our hedging program is very much focus on a plant by plant basis within GasCo to lock down the cash flows.
We approach hedging for our coal fleet differently. We look at ways and how to protect the downside but allow the upside to remain and we utilize various caller strategies. So we are in a situation in 2013 where gas prices start falling because the winter doesn’t show up similar to last year than we have a put structure that puts a floor on the good portion of CoalCo’s earnings and we have an out of money call that helps finance that for a portion of our hedging.
So that leaves room for power prices to run and certainly the open portion of the fleet would greatly benefit from running natural gas prices. So our hedging program is to limit the downside allow the upside to exist.
The aspect of our portfolio from a limiting the downside risk is how the portfolio economically behaves. When you think about ‘14 and ‘15 where we open, largely open, generally speaking gas prices decline our GasCo assets run more, generate more gross margin, more energy revenues and it hurts CoalCo.
On the other side of that as gas prices rise you’ll see runtimes capacity factor than alike from the gas portfolio decline. But the offset of the rising gas prices benefit CoalCo far out way, far out way the amount of loss revenue that you’d see on the gas side.
So we've got an embedded hedge in the portfolio when its open, gas goes up, more valuable for the coal, gas prices go down, more valuable for the gas fleet and offset some of the loss on the CoalCo side. So we’ve got that embedded hedge within our portfolio.
Now moving to what’s going to drive some of the earnings as we go forward, the slide that I wanted to start with is a slide that John Bear who was the CEO of MISO came in and his team came in solace this past Friday. And we were talking with John, John had put together a presentational on how he sees the outlook for supply and demand for capacity prices within MISO in the next couple of years.
And I thought it was certainly an interesting discussion and I talked to John about sharing that information. So he actually took the presentation that they prepared for us and put it on the website this past weekend. This is one of those slides.
And the message from John is that as they factor in retirements within MISO and their retirement number is based upon their quarterly or semiannual surveys that they do with all the generators within MISO, how many retirements can they expect. So that’s factored in there. So you could see 12.5 gigawatts is what they’re forecasting in terms of incremental requirements from today.
The other aspect that John highlighted to me was you see on the potential gas fee rates which is for the winter resource adequacy. When they think about available capacity, if you don't have firm gas, you can’t consider that resource adequacy. It may not be available. Supply constraints peakers that aren’t going to contract the firm gas because they don't know if they’re going to run so they back that out.
So the message that John brought to us was we really are concerned about winter resource adequacy in 2015-2016 timeframe. They see a potential scenario that says they’re 11 to 12 gig short of generation.
And while he wants to talk about -- talk to the load serving entities around providing resource adequacy and locking in capacity, he recognizes that talking about the market design that looks like PJM in MISO is like the third rail that soon as you bring up RPM and the like, the members of MISO tend to automatically not want to engage in the discussions.
But the message that has John taken to on the load-serving entities is we really need to lock-in multiyear bilateral capacity contracts now. He feels that the first thing he needs to do is convince the member, the member of organization that we’re short. We’re short in the winter of ‘15 and ’16. And either there is going to be a harsh reality when that time come before we can smooth it out with multiyear bilateral capacity contracts. That's what I see happening.
As soon as this message starts to resonate more and more that you’re going to see the capacity payments starts ticking up. So we look at reserve margins in MISO using whether it's our own forecast or looking at third-party, everybody is really seeing the same type of tightening of the market, below 15%. And so value driver number one that I look to is capacity payments in MISO.
And we range that from $65 million to $130 million in the 2015-2016 timeframe. And the way we came up with the numbers, $65 million is based upon 2009 that 80% reserve margin and the clearing prices for capacity prices was $2 a Kw a month.
The way we come with $130 million is -- and Brian will talk about this is that we view that the market could converge where PJM RTO is and if you look at Northern Illinois, the capacity prices are clearing at $4 Kw a month that doubled to two that we experienced in 2009 when we had an 18% reserve margin. So if you take that, you multiply that against now that megawatts we had over the range of $65 million to $130 million of capacity revenue.
There is another impact that often is not thought about when you’re talking about retirements. It changes the dispatch effect. And what we did try to quantify that and what we came up with was another $85 million to $90 million of revenues is we reran 2012. So 2012, take the actual dispatch adjusted for the known retirements that are in the MISO central region, which is where Dynegy plants are and then re-run it and see where the margin of clearing price is.
On average that was a $4 per kW lift -- $4 per megawatt hour lift. We generate 22 million megawatt hours a year so the math there is simply the $4 times the 22 million megawatt hours annually and that’s $88 million. So again that's just running it through our dispatch models, redoing the stats for the plants that are there and the plants that had retired and how did that impacted the margin of clearing price.
The final value driver, I want to talk about is natural gas. Natural gas is the one that is most commonly viewed as the main value driver. For me, it's not only the retirement story and the impact on the dispatch and the impact on capacity. That will also put pressure on natural gas. The retirements are going to drive the higher electricity demand for natural gas, driving natural gas prices higher.
If you look at the curve, within our guidance, we used $3.46 for 2013 guidance. And then you look at the forward strip, it goes out to $4.38 in 2016. We also looked at what are the various proprietary views around natural gas in that range -- in that tan shaded area and you can see as early as 2015, say potentially gas could be $5. So where gas is then, obviously no one can predict today. I mean, you could do some level of hedging instead of locking in those values.
But if you work through our sensitivities to natural gas, that uplift from the $3.46 to $4.38 has a $140 million impact to EBITDA. Certainly, if it goes to $5 level, that may have significantly higher to $230 million of incremental EBITDA. So still a very, very much leverage to natural gas to the upside.
Mike Gray will talk more about this when you apply those sensitivities, one also needs to make some assumptions around heat rate and one of the things, one of our objectives today as well is to provide a little bit more detail. How you should think about heat rate in the natural gas rising environment.
PRIDE, I’m sorry -- this is the final value driver for PRIDE. We’ve continued to work on making our company more efficient, reducing the cost structure and we've had great success during 2012 on lowering our cost structure, funding gross margin improvements and certainly getting a lot of liquidity into the balance sheet by -- particularly by utilizing the first lien for our hedging.
We continue to work as opportunities in 2013. We feel confident that we'll have another $36 million of improvement during ‘13 between cost and gross margin. And when we think about 2014 and 2015, we've already identified project which, if successful can generate another $30 million to $50 million of incremental improvement. And between now and 2014 and 2015, there will be things that work, things that don't work but bottom line is we’ve got the opportunity to continue to drive value through just everything single day doing things better.
Next with the capital allocation, so what you do with all of the capital that we’re generating over this time period. What do we do with our liquidity today? First thing that I think about capital allocation is safety. Safety around our operations, environmental reliability, making sure day-to-day our plants runs as effectively as they possibly can, safely as they possibly can. And I think about safety on the balance sheet ensuring we’ve got adequate liquidity and we've got adequate management of the capital structure, the structure that efficiently as it possibly can.
So when I think about capital allocation, those are the first priorities that we have. Beyond that, all options are on the table. And this is a topic that receives a lot of attention at the management level, a lot of attention at the board level. And certainly, our goal in 2013 is to crystallize our plant and how we’re going to allocate capital.
The key to it is a strong balance sheet. And if you take a look to the left and our Dynegy leverage profile, on the net debt basis, we’re about 2.4 times in terms of net debt-to-EBITDA.
So from a leverage perspective, strong credit profile and if you look at our liquidity during 2013, we see upwards to $900 million of liquidity and that’s going to be driven not only from the operations but its going to be driven from more efficient capital structure that Clint will talk about, refinancing plans that we view that will release a significant amount of restricted cash and then also you may have saw yesterday we filed an 8-K where we entered into a new revolver at the GasCo level that provides $150 million of revolver capacity. So during the course of the year, we see over $900 million of capital available for allocation and Clint will go through where we see the uses of that capital.
One thing I want to talk about and particular about capital allocation. I've highlighted here what we think about for each of the different path. Certainly there is a much -- very much a growing sentiment around share repurchases, and share repurchases is getting a lot of discussion.
The one thing I want to highlight when we think about share repurchases we also think about how to execute the share repurchase plan. And right now with our average daily trading volume between 350,000 to 400,000 shares a day, if you look at the statutory limitation, if you look at the practical limitations to probably buyback about 50,000 shares a day, that’s about $1 million. So if you are going to engage an open market repurchase program just going to have to have a lot of patience for this going to take a long time.
The other thing that I think about and we’ve talked about it at Board level as well, is when we think about share repurchases, there could be some equity holders that came in via the restructuring that are typically holders of debt and not equity. There maybe opportunities for block share repurchases, so that’s something that we think about.
Again we have had no discussions with any third-party around that, but that certainly one way you potentially do is share repurchases as well. I just wanted to highlight some of the practical limitations of just an open market repurchase program.
So finally, just moving to the conclusion slide here for the first part, we certainly see the investment opportunity in Dynegy driven by these three things, between the limited downside risk, conservative valuation, the multiple path for earnings upside through retirement driven, capacity payments, energy revenues, natural gas price going up and then capital allocation opportunity.
So, with that, I’m going to turn it over to Mike Gray, he’ll go into the Commercial.
Thanks Bob. I’m Mike Gray. I’m Vice President for Commercial for Dynegy. I manage our term hedging activities, as well as our market analytics functions. I’m going to walk through briefly a -- some information on our earnings sensitivities both through gas price and heat rate moves, give you some an overview of our hedging strategies around our various assets. But, first, I want to embellish on what Bob was talking about in terms of our forward view on natural gas price.
The shaded area here represents the collective view of several industry experts that we have contact with and have pulled over last few weeks. The blue line is the January 2nd NYMEX forward curve. Our expectation is that the market is ultimately going to realize and settle above the NYMEX curve that shown there and within the range that of the predictions.
Some of the differences that we’ve seen in talking to somebody different parties are with respect to their view on the 2013 winter. How that's going to realize? How that could potentially do an early recovery in price or a delay in price recovery impact the supply response and what could occur in 2014 from a price perspective. As well as there are some differences in perspectives on retirements in the amount of natural gas that will be required to meet the power gen demand.
I’ll talk to a couple of the bullish factors that we see is driving the market higher. This top chart is the rig count that shown over the last three years and since by the end of 2011 until the end of 2012 we have seen more than 30% decline in gas-directed rigs. A lot of those resources were obviously redeveloped in the oil-directed opportunities we think as long as the crude markets stay at the $15 per MMBtu or so level that those resource are going to continue to be committed to those the oil-directed activities.
The -- we are seeing some continued increase in the natural gas supply in 2013, largely as a result of some of the debottleneckin activities in the pipeline infrastructure particularly around the Marcellus.
The bottom chart shows what the range of economic gas prices are to support additional drilling in the -- what we think the dry-gas plays that are ultimately going to be called on to balance the domestic supply and demand picture.
And while Marcellus has some opportunities in the $3 to $4 range, some of the other marginal fields are going to be requiring $5 -- $4 to $5 in order to attract resources to develop.
On the demand side this is a chart that Bentek developed basically shows the different components to the natural gas demand. The green area is associated with commercial/industrial demand and it’s basically just an assumption of return to a normal weather pattern, normal winter.
The red edge is what they forecast is to be driven by coal retirements and replacement of those megawatts through higher capacity packets on existing unit or incremental natural gas capacities added to the market.
So given our bullish perspective on the market, how does that impact Dynegy’s earnings? This slide is a sensitivity slide similar to one we provided previously. In order to really understand the impact to our earnings potential particularly around CoalCo, you have to combine the impact of both the natural gas price and the associate heat rate that you would realize in the market.
Topline takes a 500 heat rate change assuming a fixed gas price and holdings expected generation levels is constant. This is the impact to the different fleets particularly in an unhedge year in terms of how much value would we see through as a result of an improvement in power prices.
Second line is up and down is a dollar improvement in natural gas price, basically assuming seven heat rate.
And then the third line takes same sensitivity and says, if those gas prices were to realize and you were to see the current or the January 2nd equivalent heat rate in the different markets anticipate in, what would the impact would be?
One of the things to keep in mind as you are considering the common combined effect is the historical heat rate relationships between natural gas and heat rate we think are going to be changing as a result of a change in the Generation Stack and you're going to see unit that had operated as economic even though there may have been low capacity factor in at some in point, they were part of Gen Stack. When those are removed you are going to see compression in the stack basically a change in the slope and I think Alan has got a slide on that that he’ll walk you through in a moment.
This is the same slide that Bob showed you previously. Just want to spend a little time on kind of each of different strategies, the strategies to the right are weighted toward our CoalCo assets, strategies to the left are weighted to our GasCo assets. Our CoalCo portfolio is largely open to as a result of our view on forward natural gas prices and to take advantage of the upside that we see available in the gas market.
As Bob mentioned, we do have significant number of our megawatts in 2013 under the collar structure where we have hedged the downside associated with those significant portion of our megawatts and so now that we may recall.
So we do have some upside opportunity associated with those megawatts even though we do have the downside protection. We have GasCo assets that operate fairly deep in the money and when we look at those assets in terms of how we hedge those, we do hedge them from a largely intrinsic value to capture strategy. We will put our position on then we will optimize that position at a level where we are comfortable with the intrinsic value associated with the asset.
And then we have at-the-money assets that we monetize in the real-time and day ahead markets as well and the shorter term opportunities. All of those activities we do to inwards collateralization is possible. We have a lot of first lien relationships. We use -- that we draw onto hedge a significant portion of our position and put those different structures on.
We’re updating again our hedge levels for both CoalCo and GasCo. I think we provided an update at the last update, it was the third quarter earnings release. And so we’re updating to the beginning of 2013. You can see that CoalCo is currently hedged at about 54% on a volume basis. And the big step up between July and November that you see there was a result of the implementation of that collar strategy.
The GasCo fleet is currently hedged at 62%. We saw between February and April of this year, we saw an improvement in spark spreads and that let us to put positions on and increment the hedging and accelerate rate during that time period.
All of our hedge activity is tended to be risk reducing. And this next chart basically shows a gross margin distribution for CoalCo and GasCo and you can see the blue line represents completely unhedged portfolio for CoalCo on the left, GasCo on the right. The red line is basically how that distribution has changed as a result of the different strategies that we put on to hedge those assets.
Again CoalCo includes the impact from the collar structure that we have in place in GasCo's largely through the impact of forward sale of spark spreads. All of our assets fit on this continuum of kind of strategies as far as being out of money to deep in the money and we look at each asset. CoalCo assets kind of collectively sit to the right of that continuum. And I focus CoalCo is to basically capture intrinsic value and building a downside protection keeping availability or access to the upside in the market.
The combined cycle fleet since across that continuum, again we have deeper in-the-money assets and more at-the-money assets. Our intrinsic values largely hedged at our more in-the-money assets and at-the-money assets, we treat effectively as peakers.
So in summary, we’ve build this natural gas largely driven by the impact from coal retirements and kind of permanents switching from coal to gas. It’s going to occur in the various markets. We do look at each of our assets individually and develop a hedging strategy around each of those assets and specifically with an eye toward reducing the downside risk and maintaining an opportunity to participate in the upside market.
For the past year, we look at our cash flow requirements and hedge in order to meet those requirements and longer-term both our CoalCo assets, in particular, are open at the market to take advantage of what we believe will be upside market opportunity for the improvement in the gas market.
At this point, I want to turn the podium over to Brian Despard who is our CoalCo asset Vice President.
Thanks, Mike. As Mike said, I’m Brian Despard and I’m CoalCo’s asset manager. My review of CoalCo is going to focus on how we’re well-positioned in the Midwest ISO and also how we stand to benefit from market prices rising as well as plant retirements.
For 2013, we’re expecting a positive contribution from CoalCo. We have adjusted EBITDA at $60 million to $85 million. We have CapEx at $45 million with the resulting cash contribution of $17 million to $42 million.
Most of our margins is going to come from energy. We also expect that basis impacts in 2013 will be less than they were in 2012 and also our CapEx spend should decrease a bit from 2012 given the wind down of our consent degree of spending. There is a couple of things to watch when you're looking at CoalCo's performance over 2013, one is the basis variability. How much that changes due to planned outages whether different fundamental impacts? Another is the MISO annual auction for ‘13, ‘14 which is going to occur this spring.
As I’ll talk about in a second, we’re not expecting prices to rise significantly right away but there is a lot of uncertainty about the market. So we’re anxious to see what this first auction will tell us. One of the reasons we’re well positioned in the MISO market is our low variable cost structure when compared with other technologies, our dispatched cost is quite a bit lower than gas certainly in Illinois-base in coal.
We’re also lower than the other PRB coal producers in MISO. The main reason for that is very attractive real agreement that we signed for 2014 this past summer that gives us quite a bit of advantage. The timing of that was great. Other folks have signed contracts when the market was much higher. So we’re fortunate to have that advantage going forward.
The result of the variable cost -- low variable cost for us will be high capacity factors. We've had high capacity factors in the past 80% to 90% and we expect that to continue into the future. In 2012, we had a very weak winter. We had low demand throughout the year. We had low prices and we still achieved the 79% capacity factor. So we’re very confident that we’ll be able to keep our numbers going forward.
Another reason we’re well-positioned is our environmental CapEx disposition. We’re ready to go on all our environmental compliance requirements and we spent billion dollars on our consent decree that included four scrubbers at our largest four units and we’re fully ready to deal with MATS. One question that I’ve heard is what you’re going to do about Wood River. Wood River seems to be an issue in the mind of some folks.
Wood River 4, we do have a trade-off that we have between managing particulate matters as well as managing sulfur, I'm sorry carbon, mercury go to all the pollutants. Particulate matters versus mercury will be a little bit of a trade-off and we’ll have to optimize that on a monthly basis, depending on what our levels are. But we feel very confident that we’ll be able to do that and that won’t be an issue for us.
Our CapEx spend as we look out very, very low on environmental CapEx, $8 million in ‘13, $9 million in ‘14, $11 million in 2015. Our largest challenges basis, basis creates problem for us when it varies, expects various thing. So the basis is simply the difference between the price we receive at our power plants and the price that’s realized at trading hubs.
Basis variability is driven by transmission congestion whether it’s at the trading hub, around our power plant, various things that could affect the flow of electricity like line outages, planned outages, tornadoes that take volumes down, substation problems can all affect the basis. And why that’s important to us is one we rely on a basis forecast to project our revenues at each one of our power plant.
To the extent the basis doesn't come in as we expect, well then have a variance for our forecast. Also to the extent, we hedge at the market hubs which we do a lot. We have congestion of those hubs. Our hedges can become ineffective when the basis doesn't come in as we expected to.
Fourth quarter of 2012 was a very bad quarter for us as far as basis. We had a couple of things going on. One was the operation of the Prairie State Energy Center which is very close to our Baldwin facility to south of Illinois. That we expected to happen and we’ve included that in all of our modeling. For something we did not expect to happen was a very large number of transmission line outages throughout the state but primarily in the southern part of the state around our Wood River and Baldwin facilities. That’s an area that’s already congested to begin with.
To give you a sense for the amount of outages we saw, we tend to look at the fourth quarter as being the big outage, planned outage once for transmission projects and comparing fourth quarter of ‘12 back to fourth quarter of ’11, we saw planned outage days of 60% and we saw forced outage days twice in fourth quarter of ‘12 than they were in fourth quarter of ‘11.
I shall also point out that fourth quarter of ‘11 was the largest quarter looking back to the beginning of 2011. So that was significant impact from transmission outages in the fourth quarter of ‘12 and that’s not something we expect to continue going forward.
For 2013, our basis estimates are lower than 2012 and they are actually more in line with what we saw historically at 2009 to 2011. That’s a little bit misleading. With the overall values been somewhat what we saw during that time period, for 2013, we’re actually seeing our basis between the hubs and our Baldwin and Wood River plant is actually widening some compared to history.
A lot of that has to do with Prairie State’s operating. However, the basis at our northern plan, Hennepin and Havana, we expect to actually narrow some and there are several reasons behind that. One is those plants are most affected by the changing Gen Stack with gas prices being so low. They benefited from higher prices than do our southern plants.
To manage our basis, we have two initiatives but before I talk about those, on a day in and day out basis, we manage our exposure, congestion basis exposure with financial transmission rights that we procure through MISO options as well as diversifying our hedging, spreading it out to various hubs as well as doing bilateral nodal deals.
But to help further manage basis, we have two initiatives that will improve basis as well as improve the pricing we received at our power plant. One is our retail offering and the other is focusing on transmission upgrades around our power plants. We’re very excited about entering the retail space and we’re going to enter under the name of Illinois Power energy.
The primary reason for starting a retail effort is really to be a compliment to our generation fleet. It’s to secure sales closer to our plants. So that we can manage our basis risk better, but also it will generate some margin for us. So we’re very excited about that.
We’re going to began our marketing efforts this spring. And our focus is going to be on large C&I customers. And as our portfolio of retail contract matures, we expect to see EBITDA of about $9 million. At $9 million, we’re looking at about 500 megawatts of peak load that's probably a couple dozen contracts. And also a very important component in our estimate is our view that retail margins will be about 5%.
What we've seen in the market recently is retail margins have been higher than 5% but are quickly converging down to that number. Although it’s in PJM, the Chicago transaction was actually a little bit below 5%. So we see 5% as a very competitive level.
As I mentioned, we’re targeting large C&I customers in the Ameren, Illinois territory. There are about 85 large C&I customers that have loads, peak loads of greater than 6 megawatts. 75 of those have already switched to retail providers and another 10 have stayed with the incumbent utility. But that’s our market, it’s about a third of the entire retail megawatt hours in Illinois right now or MISO Illinois. It’s important to understand that market is growing tremendously especially on the residential side.
Our target market is about 12 million megawatt hours a year at the large C&I. And our expectation is we can capture about 20% of that. The reason why we think we can get such a large percentages is a competitive advantage we feel like we have in the state of Illinois, giving our coal fleet, and given the fact that we’re in the market everyday. We have 24x7 desk managing energy and will be able to serve a lot of cost of the retail products more cheaply.
As an example, there's a lot of volume risk that comes around in retail products in the way of shape, in the way of straddles, puts and calls, we will price those in its market levels as well as our competitors. But our competitors, especially those out of state will have to also price those in if they want complete back-to-back deals. We have to price those in the market levels as well.
So we can provide a lot of that risk management to our assets. So we can do it a lot cheaper and more efficiently than the competition coming in as well. Given our basis risk, we put a value on managing our basis risk. If we can get sales closer to our plans, that's something that we can share with customers.
We’re looking to make money on this but at the same time, we’re looking to manage our basis risk. So that’s going to be a good advantage for us. If I had to put a number on what kind of advantage I thought we had. Looking at it, we need to get into the market but we think we have at least $2 per megawatt hour advantage of the folks that are coming into the state trying to serve refill load. And that’s only 5% of retail margin.
The benefit again securing sales closer to the plans helps with basis. We get to collect the retail premiums but another effects, it’s important to recognize is the portfolio effect of combining contract. The volume, I’m sorry, the volume risk around contracts individually could be significant but as you compile a portfolio contracts. The differences between those contracts start to watch each other out and it becomes a much easier product to manage especially when we can back that with the fleet of physical power plants.
Another initiative is transmission upgrades, we’re focusing on transmission projects that will benefit congestion on our plants. We’re working with Quanta Technologies, identify opportunities in the MISO Ameren area, looking for areas where we can lead congestion usually around the plants. That’s going to come in the way of substation upgrades. We’re not looking to build any lines. We’re looking for common sense of small fixes. That will be around the transformers, voltage things like that.
And to give you a sense of the scale of these types of projects, we did a project in 2010 around the [Penna] transformer which -- which is the failure right here, which is upstream of our plans actually downstream of the plants but north. We partnered with the Ameren Energy Marketing on upgrading the transformer there. Total project costs was $15 million.
Our share was very small couple. It was a couple of million but the benefit to us was fantastic. We estimated it was $0.25 on the basis. But also we get annual revenue rights associated with our share of the project that pays over $1 million a year. So that was a great deal, not to say that all the deals are going to look exactly like that, but these opportunities are out there. It’s a bit of a win-win. We can get something that generates some annual revenue rights, as well as helps our congestion.
Now I’m going to talk about the upside, Mike Gray talked about the upside, an unhedge portfolio has the natural gas prices rising and as he said, a $1 increase in natural gas price, assuming heat rates stay the same and gases on the margin could be north of the $150 million in EBITDA benefit, which is certainly significant.
A lot of our focus lately has been however on retirements. We are looking at retirements in the market and we are confident that retirement is going to benefit both capacity revenues, as well as energy prices.
When we are talking about retirements, it is important to highlight how uncertain the market is right now. And we rely on survey that’s done quarterly by the Midwest ISO and what they do is a survey participants, generators and ask them, how they're going to compile with EPA requirements.
And the data is here on the slide and if you look to the left here, total gigawatts of 66 per coal, 18% or 27% say that there is no action required, we are in that group, we are good to go. We don’t have to spend any more money.
What’s a little bit eye-popping is, the group in the middle the 36 gigs, which say, there is going to be some controls that are required. These maybe folks that are already investing, these maybe folks that just plan to retire, they are not really sure yet, they want to see how the market plays out, that’s half the market. So half the market not set yet and we have less than two years for them to get set.
So within that two years that 36 gigs is kind of have to go to the bucket below, ready to go, where they are going to be appear in the uneconomic retire bucket and that's a lot of the decisions that has to be made.
Our view on retirement is that we’ll see a net reduction of 11 gigs in MISO. The MATS behind that is 5.5 gigs of retirements that are already announced. Also 7.9 gigs of expected retirements beyond the 5.5, then we see 2 gigs of additions, now the 7.9 gigs is really the important number there.
What we did to come up with that was go through a bunch of data, Bentek’s data, looking at power plants that were both small in size, old and also had the type of equipment that would require significant upgrade to compile with MATS. And we believe that the 7.9 of high risk capacity due to MATS, as well as economics that likely should leave the market.
Some of that is a generations that’s own by utilities and the utility IOUs it’s little bit of tricky animal. They can’t make decisions like the merchant players can, where the plants on economic they can just retire it.
So we look towards integrated resource plan, rate case filings, things like that to see, get a sense for what utilities are doing. There is a not a lot of transparent -- transparency into that, but we don't see utilities taking a lot of action to compile with MATS on their older units and I’m going to talk a little bit more about that later.
So if you think about 11 gigs of retirements and you think about reserve margins, right now we are at 27% reserve margin in MISO. For 2013 the planning requirement is going to be about 14.2%, when you drop 11 gigs the retirements on that and then you throw in the modest low growth of about 0.6, by 2016 we get to about 12% reserve margin and that’s below their 14% planning reserve requirement.
Bob mentioned that in 2009 reserve margins were 18% at the time the market price was $2. Reserve margins below 15% that's just unchartered territory. So we are anxious to see what happens once the markets get there. It’s also important to point out that in PJM there is a forward view on prices. So you can see the impact that tightening of the market will have, PJM RTO’s price is $4 right now.
In MISO we don’t have that forward view. There is a centrally voluntary auction which results in a fairly bilateral spot market, we’re not going to see those prices coming, it’s going to happen and then we are going to realize we are short. So that’s going to be a very big challenge for everybody trying to estimate when the prices are going to rise.
When we look at prices we see prices usually getting above $2 and we see them approaching $4, which is the PJM RTO level. I’m going to rehash some stuff that Bob mentioned, $2 on our fleet, which was also the 2009 level that’s $65 million in revenues. At $4 which is the PJM RTO level that’s a $130 million of revenues.
One other things that the ISO was concerned about when they came and met with us last week was how they can get folks focused on this capacity shortfall issue, something they were very frustrated with was they are not getting a lot of traction with PCs, they are not getting a lot of traction with the utilities, but they recognize that this needs to be addressed and they also recognized they don't have the mechanism like PJM to address it.
One other things that they're pushing and we certainly agree with is bilateral contracts, utility signing bilateral contracts to bridge through this period of uncertainty and also that will project some levels of value to the capacity market going forward.
We think prices are going up regardless. I think if there's a lot of bilateral contracting, it’s going to go up more of a stairstep, if there is no contracting and utilities don't recognize what’s coming and the PUCs as well then it’s going to be quick.
Here is a chart that Bob showed and it is so nice that we are going to show it to you twice. And this is the shift in the Gen Stack and how it would impact energy prices as a result of retirement.
The retirements would show up obviously towards the left side of the Gen Stack that has the effect of shifting the entire Gen Stack to the left and create space between where it is today and where its going to be after the retirements, that space reflect higher prices and the loads that we realize and MISO typically fall between and actually this is not all of MISO and MISO central, which is essentially Missouri, Illinois and Indiana, well, we are -- of course we are in Illinois, typically falls between the 17% and 23% -- 23%, I’m sorry, 23 gigawatt level most of the time, that’s where most of the megawatt hours are.
And there were some points on the Gen Stack where the difference in prices is much as $9 or $10. When we look at it across that whole gap between the two curves there, we come out to $4 around-the-clock, and given our generation of over $20 million megawatt hours $4 against that we are over $80 million using.
So to summarize, our fleet is well-positioned because of low variable costs, also because of our environmental CapEx. We think we are sitting very well relative to our competition. We are taking measures to manage our basis risk, as well as improve the prices we realized at our plan through for our retail offering and through transmission upgrades.
But also perhaps more importantly is there is just significant upside whether gas prices go up or they don't we upside, gas prices go up that’s an obvious upside on the energy price, gas prices don't.
We see retirements, actually frankly, we see retirements no matter where gas goes. Retirements we’re fairly certain going to benefit us certainly on capacity price side but also on the energy price side, so we see lots of upside.
With that, I’ll turn it over to Alan Padgett who is GasCo’s Asset Manager.
Thank you, Brian. My name is Alan Padgett, and I’m the Vice President of GasCo Asset Management. GasCo provides stability for Dynegy, particularly in the currently low commodity environment we are in, as Bob mentioned, provides natural hedge to our CoalCo fleet, sorry, fleet way.
I’m going to begin with, talk a little bit about EBITDA guidance and step into our California assets and how we think we are going to benefit particularly with the addressed renewable portfolio standard in California. Then I’m going to talk little bit about how PJM and our New York assets are going to benefit from retirement of coal assets.
And then, in addition, I’m going to talk little bit about fuel savings around, especially around independent facility as it’s been impacted by assets in the Marcellus Shale play. And last, I’m going to conclude with repowering opportunities at some of our sites.
Let’s turn the page to guidance. As discussed earlier, adjusted EBITDA is being reported by segment excludes corporate G&A. For 2013 GasCo segment adjusted EBITDA is in the range of $255 million to $280 million.
We’ve excluded potential settlement with SCE that’s the term -- that's the termination associated with the Morro Bay toll, as well as the Moss Landing our capacity contract, and we are clearly still negotiating with SCE and hope to kind of some type of resolution too in that.
A key driver to our stability that’s our stable earnings is in the form of tolling and capacity payment, capacity revenues and for we’ve approximately -- we take this approximately 75% of our gross margin for 2013.
As Mike indicated earlier, we are approximately 62% hedged in our portfolio for ’13. Those potential for upside as we see spark spreads to improve to the year, likewise in downside drivers would be lower spark spreads and basis risk -- our basis risk. We’ve mitigate some of our power based risk around Ontelaunee approximately 50% of it has been hedged or mitigated for 2013.
I’ll now talk about our EBITDA, please turn to next slide, and talk a little overview on our portfolio overall. As you can see we have a geographic diverse fleet. We have approximately 3300 megawatts located in the Northeast.
Our Kendall and Ontelaunee assets in PJM are could really locate in the load pocket in Philadelphia and Chicago. Likewise Ontelaunee and Independence are in the Marcellus Shale regions they benefit from their cheaper natural gas in Marcellus.
Now west we have the largest generation site in California which is the Moss Landing site, it is approximately 2500 megawatts, of that there is a little over 1000 megawatts, there are combined cycle units there -- basically combined cycle unit tend to run year around.
We also have Peaking facilities in the west at our -- at Moss Landing, Morro Bay and Oakland sites. Again, we see some upside in California in the renewables portfolio standard, we believe that standard has been oil exacerbate intermittent as they are experiencing today.
So, with that, my next slide, I’ve got, talk a little more about the renewables growth in California. As you can see here, California really ramping up their renewable portfolio in wind and solar and it starts to take off 2014, it continues on up through 2020. And likewise we wrote in expected retirements as well. So the big question for California ISO is how they are going to manage (inaudible) wind and solar?
We think part of the answer is around Moss Landing, Moss 6 and 7 units. The chart you see here is pulled from the California ISO Symposium they held back in September, and as you can see, base with, take -- they taken that an average winter load that levered in the impact of wind and solar.
And as you can see, they’ve got ramping issues, particularly evening peak, of course the 14,000 megawatts over a two hour period. Now most of the combined cycle units will be position in the 2x1 configuration already during midday, that leaves the combined cycle unit -- average combined cycle units approximately 200 megawatts at ramping range at about 10 megawatts to 15 megawatt ramp rate.
Now compared that to Moss 6 and 7 that can move from 50 megawatts to 735 megawatts combine that’s over 1400 megawatts of ramping capability. Likewise these units together would get close to 50 megawatts per minute ramp -- 60 megawatts a minute of ramping.
So as you can see there are some positive attributes here at Moss 6 and 7, hidden attributes that the market cannot recognize them. Our goal for 2013 to get in front of the California PUC NHI [LIFO] to inform entity as a valuable attribute here at the site. And also to take part in the -- and we are already taking part in the capacity market reform, the goal there is to get the value of these attributes recognize the capacity market reform to keep some type of revenue stream from these attributes.
So while we are working on these, while we already pursuing these fronts -- these efforts, we are also be working on trying extend the toll as well. We anticipate that the local utility will have an RFO process in summer, bidding process for the ’14, ‘15 timeframe and we will be participating with these assets.
Although, current market conditions aren’t as favorable as they were we execute our current contract, we do believe we are going to see -- we’ll see significant, we’ll do catch a significant portion of the contract that’s going off this year.
Now turning our attention to PJM and the capacity market of PJM, we think the key driver of PJM, the capacity market is of course the retirement. There has been over 80,000 megawatts of announced retirement and we believe there could be additional 3 to 6000 more announced retirement due to MAAC compliance.
To offset this is only approximately about 6000 megawatts in development that has got 2600 megawatts in early development. So net-net we believe that there will be downward pressure on reserve margins, which will support favorable capacity price in the near future.
From downside drivers there is of course will be the load forecast reductions and increase in demand response. However, we -- our expectations for the next capacity auction is roughly around $70 million to $80 million very similar to the last two auctions. In addition to capacity markets, retirements also have an impact on power prices in PJM that will have an impact.
In the next slide I have dispatch curve very similar to what Brian Despard showed, taken in consideration if you see -- the blue line is taken consideration announce retirements to date. But if you learn and make assumption of another 4600 megawatts retirement that will shift the dispatch curve and your marginal cost over to the left.
We are projecting roughly $1.35 per megawatt hour around-the-clock of additional costs that would equate to about $9 million to $10 million of added value for added energy margins for our facilities in PJM.
With that let’s turn the page and talk a little bit about New York ISO and capacity markets there. Very similar to what’s happen in PJM I think is occurring in New York ISO. They are using 1100 megawatts of announced retirement to ’13 and we see the net retirements by 2015 will be close to 2000 megawatts and with the announced retirements for ’13, as well as the favorable buyer-side mitigation ruling we had earlier in the last year, that’s obviously put pressure on capacity prices in New York and we’ve seen that ‘13 in the chart there. We have seen an enormous improvement in capacity prices.
And also as you all know we do have a favorable capacity contracts that’s going off in 2014. Opportunity is there to offset that of course will be the first state in either -- in the forward -- in the market at market prices either storing bilaterally the counterparties or participate in New York auctions.
If you would take the publish pricing curves for the ‘14, ‘15, ‘16 time frame and apply volume to it, you will see that we get -- it would equate to approximately $30 million annually over the ‘15, ‘16 time period. In addition to that revenue, we've also identified other savings and independence around fuel supply.
Traditionally, independent source of fuel in Canadian sources and we also relied on expense on transport contract. Of course, it would be Marcellus Shale play now, we’re able to source force cheaper fuel but this is cheap upon average on the forward curve and do have that gas to independence. We’re roughly about delivering close to 50% of Marcellus Shale independent and so I’m wrapping that up overtime trying to be at 100% by 2015.
Of course, the advantage of that is we can eliminate our needs for expense of transport contracts. So some of the savings you see are here in ‘15 and ‘16 of the transport contracts going off. If you take the $28 million in savings in 2016 and couple out with $30 million savings in capacity payment, revenue stream from capacity payments, that will give us approximately, sorry, over 50% of our contracts going off in 2014.
Turning our attention to repairing opportunities, first Oakland. Oakland is in a locally constrained area. And we think once we see a new capacity market, it assumes a right pricing figures for assets that are in constrained areas. We have an opportunity here to repower the peaking facilities.
Currently, they are all burning units until we have two options here. We could convert them over to natural gas burning peaking units or we can perhaps replace them with efficient -- more efficient fast start units less than 6,000. Of course, the market pricing, both capacity curve pricing will dictate, which option is very clearer.
On Kendall, there is a number of opportunities there, number of prior initiatives are underway. Perhaps we are looking at doing upgrades on our turbines there. We think right we could probably get 59 megawatts total. This is the tight closure by the way. It should be a total not for turbine. 59 in megawatts but do some upgrades along with software in-tuning upgrade as well.
It was planned forward march to that, to those megawatts when you give roughly $6 million to $8 million annually in additional energy and capacity revenues. I do not have a file on Casco Bay but a few things on Casco Bay before I conclude and wrap up.
Casco Bay as you all know is a challenged fuel supply area in New England and New England area seems to be having chance with fuel supply. However, we want to highlight it. We do anticipate deep enough to come to production line to start producing first half of this year, I believe the later stage is June. I believe that’s going to help offset and provide some relief to the Maritimes pipeline.
Second, there is a main PUCR process first quarter of this year. We plan of participating as well. They do own on behalf of all the utilities in the state. They are looking for both renewables and raise their power and (inaudible) optionality (inaudible) flexibility to do one by one configuration so forth. So it’s easily often used as just pass the facility or the full facility. So there is a number of options there that we can participate in our full process.
So just quickly wrap up, in conclusion, GasCo continued to provide strong earnings and cash flow for Dynegy. We’ve also benefited from cooling times taking place in most of our regions. And we believe that a good portion of our loss revenue is from the contract ruling off of the independent. It will be offset with capacity revenue as well as benefit from the Marcellus Shale play.
And last looking forward to redevelopment growth opportunities to ground our asset. With that, I’ll turn over to Dean Ellis who’ll give you a regulatory update.
Good afternoon. My name is Dean Ellis. My focus with Dynegy is federal regulatory affairs. In addition to federal regulatory affairs, I also coordinate regulatory positions across the enterprise. Today, I’d like to give you an update on several regulatory issues, most of which are what we perceive are highest priority regulatory issue.
We’ve identified these as highest priority based on their impact to the enterprise and hence their impact on shareholder value. We view regulatory affairs as yet another tool in our toolbox. We drive revenues and control costs. Regulatory affairs, of course, is inhibitive process of average the visibility, education and alliance.
We had a number of successes in different areas over the years. However, beginning in 2012 and continuing now in 2013 we’re going to sharpen our regulatory focus in a number of areas. We’re going to specifically increase our advocacy, our visibility, education and lastly our strategic alliances.
Two great examples recently last week we had a front page article, lead article in the Chicago Tribune astounding the benefits of Dynegy’s investment in its Midwest asset. Secondly, one of our competitors went away midwest Jan had filed for a pollution control variance to MPS CPS regulations and Dynegy was the first entity to strongly object comment and intervene in their proceeding to even beat the environmentalist.
Again we've identified several high priority regulatory issues. We view them as both revenue drivers and cost drivers. On the revenue side, we've identified market design and generator retirements and on the cost side, we’ve identified Coal Ash regulation and once your cooling regulation as our potential threat.
With regard to market design, we’re focusing on capacity market reforms. The energy markets has been the most part of course are largely standardized across the country. The capacity market, of course, are in various stages of maturity even 12 years into the regulations.
Two markets in particular are least mature. We view them as, of course, MISO and California ISO. And while Bob said capacity markets on the state level are viewed as the political third rail. We do see some room for incremental improvement.
We’ve identified several fundamental tenets, overarching principle that we’d like to see in the capacity market. Those tenets include things like forward-looking procurement firm and also spoke demand curve that’s anchored to the cost of new entry. Those fundamental tenet provide adequate price signal. They also provide more insurers return on investment and return on equity.
So again while we don't foresee in these two markets overnight successes, we do see room for incremental improvement particularly given that these two areas have biggest potential for reliability concerns. As Alan outlined and Brian outlined, both areas are facing potential retirement especially Midwest ISO. Significant potential retirement and there is a number of solutions to that.
One, of course, would be incremental improvements in capacity market perhaps even through potential bilateral long-term capacity agreements. Additionally, in California with it’s high renewable portfolio standard penetration to serve 33% or as some folks have projected down California as much as eventually 50% of its load through renewable energy, given that renewable energy had a high intermittency and variability. Conventional generation is going to be needed even more in that area to balance the intermittency and the variability of the renewable generation.
With regard to retirement, our approach has been two-pronged, one we vigorously advocate for a level of playing field. Our fundamental tenet of any market is that uncompetitive and non-environmental or noncompliant market persistence exits the market and so we’ve advocated again vigorously for level playing field.
Additionally, we’ve advocated for ease of exit from the market. It’s interesting to note that when it comes to competition for generations, it’s generally treated with a fungible asset but when it goes to exit the market, there is an extreme discrimination plant to plant, unit to unit.
So as we’ve done in a number of regulatory filings, we’ve advocated for ease of exit from the market especially for uneconomic and non-compliant generation. We are very pleased to see with Governor Cuomo’s energy highway initiative. They identified this as an issue. The governor actually stated that uneconomic generation should exit the market. It should not receive artificial subsidiaries or be propped up, yet recognizing the potential void that that generation leaves to stay in the local economy.
The governor said again that the generation should not be kept around but other means should be enforced or implemented in order to back over the potential void that would have created from generation retirement. We view MATS, the Mercury and Air Toxics Standard particularly in this low commodity price environment as a single largest driver of retirement.
The question that comes up is what is the likelihood that MATS would stand with the current judicial review. Well, MATS is undergoing a thorough development process, if you go back to the predecessor regulations, MATS has really undergone nearly 16-year development process. And as some subject matter experts have said in the area, EPA stuck strictly to the letter of the law in this rule.
Lastly, the EPA is under consent decree to issue MATS. For these reasons, we firmly believe that it’s highly unlikely that the court would bake the entire rule or even any part of the rule for that matter.
The clock is ticking on MATS compliance. MATS has a three-year default compliance window. There are optional fourth and fifth years that are available but seeing that we’re already one year into the regulation in the compliance period, the clock is ticking and giving the capital-intensive nature of the equipment that’s required to comply with MATS.
If generation owners have not contemplated how they’re going to comply with MATS by now, it’s too late, the time is up. Additionally, the ISO also stated that outage windows, long-term outage windows closer to 2015 have been all been used up. So even if a generation owner who has to begin start thinking about compliance now if they do need long-term outage window, they are not going to get it through 2015.
Again, there are extensions that are available fourth year as common. We call the state extension. The fifth year is commonly called the presidential exemption but there are key thresholds that need to be met.
In the presidential memo from the executive office to the EPA, memo stated that the liability concerns to get this fourth year must be justified and that we view the wording in the memo to state it. The fourth year would only be required for instillation of control.
For generation, owner is not going to use this fourth year simply to tread water and then decide if it’s going to be contemplating with MATS. Again, the clock is ticking and they need to be thinking about it now and even if they are thinking about it now, it’s too late.
Lastly, the fifth year, which is also called the presidential exemption will be available but again the threshold is even tighter than the fourth year. The bar is already set even higher to meet compliance with this presidential exemption. Key wording in the presidential memo is that the additional year would be used only in national security interest.
On the cost side, again we have identified Coal Ash regulations and went through Cooling regulation as our biggest potential cost drivers. The U.S. EPA recently filed in its court brief and issued that it’s facing from the beneficial coal ash were used in manufacturers and environmental groups that needs at least an additional year to issue final regulations. So we expect at the earliest, the EPA could potentially come out with regulations, final Coal Ash regulations at the end of 2013
Again a parallel track on the Coal Ash regulation is currently before the U.S. Congress. There is draft legislation to regulate Coal Ash as non-hazardous. We believe this is the most effective way, most effective pathway for compliance on Coal Ash regulation. This legislation has both bipartisans and bicameral work, which today given the state of the U.S. Congress has had quite a bit about the support that it has gained.
It does exist for this legislation. This legislation allows for state permitting program, state by state. If state permitting program fall short of the minimum requirement that the EPA set forth, the EPA has backed up provision to step in and regulate Coal Ash on a state-by-state basis.
But again, in addition to allowing Coal Ash to be regulated is non-hazardous or classified as non-hazardous. That has number of downstream beneficial effect such as the reuse, to continue to reuse the coal ash which had a downstream effect of reducing greenhouse gas because there is more coal ash that you can put as an aggregate in concrete, the best concrete you have to make.
Ultimately by designating coal ash as non-hazardous that will save a huge burden on our industrial consumers. Once you coincide, there is two separate parallel efforts, the first on the federal side, the EPA again has deferred final ones to cooling regulations. We do expect it as early as this July.
But we're also dealing with the California regulations on the state level in California. The regulations have, of course, been issued. We’re currently working with a state negotiating several aspects of our compliance. We’ve offered to move up compliance with some aspects of the regulation in exchange for extending the life cycle of our facilities out in California.
We believe we have a number of alternative technologies that will allow us to beat compliance and were largely drawing on the extends of experience we had in New York., New York has had once cooling regulation in effect for a number of years. We benefit from having worked with the state of New York on the regulations. And we have a deep mentioned internally when it comes to the detail of compliance.
Just wrap up and resummarize or summarize it again. Dynegy is going to build on some of our past successes. We’ve had a number of them recently beginning with our article in Chicago Tribune on the front page. Our market design efforts are going to focus on the capacity market.
We have a large footprint in the two markets that are in most need of capacity market reform that being in California and Midwest ISO. And those regions are also facing significant reliability concerns.
And lastly federal Coal Ash and Once Through Cooling Regulation do pose a threat on the cost side but we believe that we have ways to manage those threats.
With that, I’ll turn it over to Clint.
Thanks Dean. As we kickoff 2013 there are number of important areas for us to be focus on and starting with delivering on the financial targets that we are outlining today, not only are we providing consolidated adjusted EBITDA and free cash flow guidance, but we are also outlining financial targets on a segment level basis as well.
In addition to achieving those targets, we are going to continue to focus on the balance sheet, improving and streamlining our capital structure. We’ve taken a couple steps recently that have been I think very positive steps for the company, I’ll walk through those here in a moment.
But with also a focus on refinancing the capital structure in 2013 to really construct our capital structure this more appropriate for the company on a go forward basis. And as Bob talked about a little bit earlier, capital allocation is very important part of the financial management of this company. This is going to be a very high priority for us in 2013, really increase the capacity of this company to allocate capital to the highest risk-adjusted return opportunity that we come across.
Now before getting into the specifics around our 2013 guidance there are handful of things that I would note. Beginning with segment level adjusted EBITDA financial targets.
To me one of the more -- one of the most important question that we have to ask ourselves around the segment is, do each of these segments individually generate enough gross margin, enough cash to cover their own expenses, to be self-sufficient, do they generate enough cash to pay their operating expenses and to fund their own CapEx and then if they, excuse me, if they can do they generate extra cash that can then go to help pay for what is more traditionally corporate level expenses and D&A and interest expenses.
Because of the financial structure that was put in place 18 months ago or so for very different purpose. I think that structure and the fact that it pushes down a lot of the corporate level expenses to the segment along very predefine allocation schedule. I think I must have skewers the visibility into the cash generation of each of the underlying businesses and successive assets.
And so our approach in providing financial targets at the segment level was actually lift those corporate allocation off of the segments both G&A and interest expense to be able to make it more transparent visible and how much cash these segments are actually generating after covering their own expenses to CapEx.
Also as Alan spoke about earlier, our guidance for 2013 excludes anything related to the resolution of the SCE discussion that are ongoing at this point. At this point there is not enough visibility into the outcome of that and so we’ve just excluded that from our numbers. Now to the extent of that, is a resolution in 2013 to the extent that there is cash that comes in a company associated with that that certainly would be additive to the guidance that we are providing today.
I would also note that this guidance is based on commodity curves as of January 2nd of this year and at that point NYMEX natural gas prices were at $3.46 per MMBtu. And then finally, because we’re providing free cash flow guidance on a consolidated basis, I think it’s important to know the couple of significant assumptions around the refinancing that actually affect our cash flow guidance.
First is, we assume a refinancing takes place in August of 2013 and the reason for that is that the term loan become callable in August and so therefore we pivoted off of that call date.
Second, is that as part of the refinancing our expectation is that we would be able to achieve a refinancing that would unlock about $275 million in restricted cash from the balance sheet and for this purpose, we've allocated about $150 million of that cash to debt paydown with the remaining cash flowing to the company for general corporate purposes. Now no final decisions around that have been made but for the purpose of putting together our forecast for the year, so those are the assumptions that we made.
On the upper left-hand side of this slide you’ll see the coal segment adjusted EBITDA, segment adjusted EBITDA ranges $60 million to $85 million. One thing that I would notice, Brian mentioned, in 2012 basis was a significant issue for us and in our guidance for 2013 that the coal segment we assume that that basis really I guess reverted almost back to the main, to be more in line with what we've seen historically.
What’s in here is a gen-weighted around-the-clock average basis of $4.32, for the extended that’s throughout the year, our actual results are different than that that obviously would effect this range. The sensitivity on that is for every $1 change in gen-weighted round the clock basis that equate into about $22 million in gross margin to the upside and to the downside.
The coal segment after $43 million in CapEx we would see this segment generating again before corporate allocation of G&A generating $17 million to $42 million and in excess cash.
On the top right of the slide, we show the gas segment adjusted EBITDA again before corporate G&A allocation and showing a range of $255 million to $280 million and after $63 million in total CapEx segment would generate $192 million to $217 million in excess cash.
Moving down the slide our guidance for consolidated adjusted EBITDA for the company, for 2013 is $250 million to $275 million and that’s after $90 million in corporate level G&A and other expenses.
Now one thing, many of you probably have noted is that when you look at the total segment adjusted EBITDA range of $340 million to $365 million, the bottom end of that range of $340 million is not equal, the bottom end of the coal segment range plus the bottom end of the gas segment range.
One of the complexities around modeling this fleet really is the fact that that these fleets almost move opposite to one another, when one is performing well, the other one is performing not so well.
So as we thought about what’s the right approach, I think about this on a combined basis going forward, the approach that we took was to take the midpoint of each of those two ranges sum them together and that is how we came up with $340 million.
The upper end of the range is $365 is based on the top end of the gas -- full range and the top end of the gas range added together. So that’s how we came up with the consolidated range that everything then flows from.
The cash interest forecast of $120 million reflects the assumption that I referenced earlier on the refinancing. CapEx of $110 million is a sum total of both coal and gas CapEx, plus another $4 million in CapEx at the corporate level and then the restricted cash release and other really captures a number of things, but most notably the $125 million in restricted cash is released as part of an assumed refinancing there are some other items in there, including the cost of the refinancing, as well as some benefit from some of the working capital initiatives that we have going on in 2013.
Now, one of the things that we thought was important, one of the things that we’ve spoken about previously is that, we expect 2013 to look quite different than 2012. In order to be able to speak to that in particularly in relation to our guidance, we thought that it was important to give a preliminary view of 2012 numbers and as you can see from this slide on the right based on preliminary unaudited numbers for the year.
Our expectation is for consolidated adjusted EBITDA to be in range of $50 million to $60 million. Now I’m sure a lot of you will note that at the end of the third quarter consolidated adjusted EBITDA year-to-date was $98 million. Implying a loss in the fourth quarter on an adjusted EBITDA basis of anywhere from $38 million to $48 million.
I would note three things that contributed to that performance in the fourth quarter. First, as we spoken about throughout the year, we had significant settlements related to legacy put options those were expected, those were significant, they came through our financials during the quarter as expected, no surprises.
Second, Brain spoke a little bit about -- earlier about coal basis and some of the volatility and issues that we saw in the fourth quarter that was also a meaningful contributor to the quarter’s results.
And then in addition, we had a number of outages, some of our plans that again added to the downward pressure on earnings. Those three things in total added about $60 million in downward pressure to the quarter’s results and would be things that I would really point to you at this point to explain the result.
So, with that in mind, as we think forward to 2013 and why we -- would we expect 2013 to look different than 2012. I guess, I would note really three things, commodity prices, legacy put option settlements and basis.
The first is around commodity -- commodity price is being different and really almost kind of realize commodity prices being different. As we think about the gross margin generated particular by the gas fleet in 2011, a significant portion of the energy margin was actually hedged in 2010 and 2011, when spark spreads were much narrower.
And as we saw spark spreads improved during ‘11 and then into ‘12, we actually didn’t get the benefit of that. And we can see that in some of our expected hedged settlement at the beginning of 2012 where they were significantly negative to the tune of about $100 million and that spark spreads continue to increase through 2012 that number expended.
So, given where the commodity market has been, we actually did not really enjoy the uplift in sparks that one would have expected but as we have hedge ‘13 in 2012 we’re actually now capturing.
So to me that is a benefit the we should be in 2013 relative to 2012 back to the legacy put options, we expected those to cost about $80 million during 2012 that in fact is what happened the last settlement occurred in December, so that is behind us.
So I think between those settlements, as well as the spark spread settlement that I just mentioned that accounts for about a $200 million uplift year-over-year and than as we spoke earlier, our expectation is for basis in Midwest to fall more in line with what we’ve seen historically providing additional uplift to the company in 2013.
As we turn to the balance sheet, low commodity price environment really puts a premium on efficiency and minimizing the cash costs associated with running your business and as we look at the company as a whole, we find that that the balance sheet is really in area a very significant opportunity for us in 2013.
Our near-term priority, as I mentioned earlier, is to really focus on streamlining and driving efficiency from this balance sheet and between debt repayment that we made in the fourth quarter that we announced on the third quarter earnings call, as well as potential refinancing this year.
We think that there are upwards of $80 million the year in cash cost that we can take out of the business in form of cost of our capital and also free-up up to $275 million of cash that’s currently restricted that would then be made available to the company.
Longer term, we really see the balance sheet as a strategic asset of the company to be deployed and support of the highest risk adjusted return opportunities that are available to us.
As I mentioned, the way to unlock these benefits is through a significant refinancing and our current thinking about how to do that in the most efficient way, is to refinance both the gas term loan and the coal term loan together at the DI parent level and then the supplement that with the new corporate revolver.
You can see on the bottom of the slide, some of the additional benefits associated with the refinancing. At this point we are paying LIBOR +775 we’re all in 9.25% on our term loans. So as we reduced that through refinancing there are significant benefit associated with that and that’s how we are targeting that $80 million a year cash savings.
Now we also recognized that there are a number of different ways to execute refinancing and there have been question that we’ve got recently around different approach maybe to refinance the gas term loan and lead the coal term loan in place.
And we’re continuing to think about that, but I think our current thinking around that is that, it’s a very expensive structure to keep in place relative to where we believe that it could be refinance. We’re talking probably about $15 million to $20 million per year, thought to keep that structure in place relative to where it could be refinance.
And given that the coal business is the net cash of contributor to the overall company just seems like an expensive approach to take particularly given the upside in the coal business.
But, again, we have not made any final decision on exactly what we’re going to do, we’re going to look at our different alternatives, make the call at the right time, but that just kind of outlines what our current thinking is on that.
Now refinancing, obviously, is a very major event for the company, but in the spirit of continues improvement we’re not waiting for that to continue to drive improvements in our cost, excuse me, our capital structure and liquidity program
Outline here are a number of things we’ve done since the last earnings call, fifth again continue to push and push and to drive efficiency and improvement, we repaid the $325 million in term loan as we discussed on the last call, we did that in November, $250 million at GasCo, $75 million at CoalCo, and in so doing crystallize $30 million a year in cash interest savings.
Additionally, we’ve continue to make strive on becoming more collateral efficient since the call on November 2nd. We reduced collateral by another $30 million. So right now we’re right above $300 million until outstanding collaterally but we expect to continue to drive improvement in that in 2013.
And then finally just yesterday as Bob alluded to earlier, we closed on a new $150 million revolver at our GasCo segments. And to me that’s actually that significant for a number of different reasons.
First is that, post-emergent, we’ve now really established a very strong bank group for the company going forward, there are six world-class financial institutions that are part of this, that bring a significant very broad level of capability to the company that frankly we will need on a go forward basis.
Second is that, expectations for those commitments, when we do a refinancing to role into the corporate level revolver, and there are crediting mechanisms in there for the upfront fees to credit, I guess, fees that are paid now to ultimate cost to put in the new revolver in place.
So the way that I think about it is that effectively we have pre-syndicated $150 million of our new corporate revolver whenever that refinancing occurs, but we brought forward that liquidity to today and to me that’s important.
Now, another important element of this revolver that it sets a new pricing point for Dynegy family credit, as I mentioned earlier, the term loans today are priced at LIBOR +775 with 1.5% LIBOR floor for an all-in cost of 9.25%, this new revolver, it's a 364 day revolver, but it's priced at LIBOR plus 3.25. And so as we think about an ultimately a refinancing in 2013 having a new pricing point post emergence for Dynegy Credit I think can only help us.
And then finally, having a new contingent liquidity credit facility by adding liquidity to the system allows us a greater level of flexibility with what to do with our cash on capital allocation and what we end up doing with our cash.
Now again this is a short-term facility but to me it adds a level of flexibility that we did not have before as we were relying on cash balances and only cash balances for our sources of liquidity, which actually leads me the next slide around capital allocation and really increasing the capacity of this company to allocate capital to high-risk-adjusted return opportunities.
We began the year with about $458 million in total liquidity, really being restricted and unrestricted cash. And to me, as we think about increasing the capacity to allocate capital there really are two factors involved in that, one is increasing the absolute amount of cash liquidity available on capital that's available for allocation but also increasing the level of flexibility that we have with that cash and knowing that, we have a back-stop, as we allocate that capital we have a rainy day fund if you will.
And so as we think about those two factors coming together, one of the critical things for us in 2013, that will drive both of these things, is the refinancing. As you can see from this slide between free cash flow of the underlying business as well as the cash that we would expect to be released through the refinancing, that should add over $300 million in cash available to the company for general corporate purposes with the refinancing we would also expect to extend our revolver from a 364 day facility into a multi-year facility, again giving us that added level of flexibility.
So in total, as we look throughout the year based on where we start the year and then the steps that we're looking to take, we see, over $900 million in capital available to allocate to the business. Now as I think about where we are in the commodity cycle or hedging program and so forth, the way that I think about that $900 million is that, we probably allocate about $500 million of that to support the liquidity needs of the company.
And as we talked about earlier as part of our guidance in our modeling for 2013, we've allocated a $150 million, to debt repayment, leaving about $262 million for other initiatives throughout the company, now again this is at this point for this purpose, but no decisions have been made as far as the $150 million and $262 million.
So in closing, I think our focus really is three-fold during 2013, first is delivering on the financial targets that we've set out. Two is streamlining the balance sheet and really putting in place a capital structure that's appropriate for the company and that we can use going forward and then third is just increasing the capacity of this company to allocate capital to the highest risk-adjusted return opportunities that we find.
And with that I'll turn it back over to Bob.
Well thank you, Clint and here we've put out a lot of detail today to try to help folks get a better understanding of Dynegy, we want to be as transparent as we possibly can. But then each time of the year presentation, especially Mike's, there's always a memorable slide and when we did the bondholder meeting last summer it surely (inaudible) we published it, we thought or I suggested that we do, the slide that shows beginning EBITDA and $500 million on the other side of it. And in between we have some fuzzy bars and as much as people's got rulers out to try to figure out how do we get there, those fuzzy bars are even have any numbers, become quantified behind them.
But Laura and Clint forever got phone calls about that slide and they forever do, so I thought it would be appropriate for this presentation, let's do another one. So Clint and Laura will continue to get phone calls about $500 million plus. But what I did today on – for this particular slide is really just take everything that we've talked about, everything that we've covered in today's session around power prices, capacity prices, movements in natural gas and put everything together, isn't anything on this slide that we didn't talk about today.
To show if where we are in 2013, what could 2015 look like. I'm sure there's many items on the slide that you're agreeing with and then some of you may have a different view, what I wanted to provide here is our view. And if you look at the different columns just a couple of things to point out with CoalCo, two things I want to put out. First of all, around basis management, what we really have included there is the C&I retail effort, the rewards from the transmission work that we're doing is to be determined we're pretty far along in that analysis, hopefully some time in the second quarter we'll have much more firmer look on what are the opportunities there.
And the other point on CoalCo, as you can see down at the bottom is the negative numbers, and that's really largely a result of the new transportation contract that comes in, in 2014 you have some higher coal costs there, some higher O&M costs, some variable costs around back-end controls but the vast majority of that increase, $75 million to $85 million is related to the higher coal transportation cost.
Around GasCo, we didn't put any number in there for the ultimate resolution of the tolling of capacity contracts with SCE, yet I'm optimistic that we worked something through, outside the framework Kevin Howell, as I mentioned earlier is having continuous discussions with his counterpart at SCE, whether it's a new contract multiyear contract or whether it's some type of settlement we're looking at the range of possibilities and again it's just about getting the value in and realizing that value,.
And at the bottom of the GAsCo when you think about the exploration of the existing tolling or tolling contracts floor Moss Landing and the capacity contract up at Independence, offset by what we think could be a re-contracting rate out on the West Coast as well as the items that Alan mentioned around higher capacity payments in rest of the state as well as lower gas procurement cost or Independence. That range of negative 90 to 120 tried to roll all of that together. We certainly aren't kind of go in and break that apart, particularly we're going to participate in a our full process on the West Coast for Moss six and seven.
And then as Clint highlighted on the interest savings, certainly not an EBIT issue but in terms of efficiency in our capital structure, we view that $80 million as out there and hopefully we'll crystallize that in the very near future.
That takes us to the conclusion slide before we go to questions and again our premise and our message for you today is that we view Dynegy as a very attractive value or we get an investment limited downside risk and multiple pass the future opportunity, or future earnings and our gearing and our focus this year in terms of our execution and such strong operations.
And we're going to add to that list a very focused capital allocation process year. And again that's something that at the board level we're keenly aware of the capital allocation, there's a main topic under consideration and what we want to bring to the board is a variety of different avenues to pursue and recommend the highest rate of return on the risk-adjusted basis for our investments.
And with that I'd like to open it up for questions.
Sure, oh you don't want to handover the mic?
You asked a question and I'll rephrase to what I want to answer.
The vast number of targets (inaudible) how does it
So the question is how does M&A fit into the capital allocation framework and if so, what are the markets that we would be interested in. As I mentioned early and we think about capital allocation, we're looking at all the different opportunities where we can be involved in. Certainly, on the M&A front, you see a lot of, I don't know if instability is the right word but, when you look at all of the hybrid utilities, you look at private equity, the hybrid utility is continually say, we're going to refocus our efforts on the regulated business and less on the unregulated.
You'll certainly hear that from Dominion, you hear it from Duke, Edison International, Ameren had an announcement the other week as well. So there's a lot of portfolios coming into the marketplace. Same thing on private equity, they're always on both buying or selling as the case maybe. For us, we certainly want to look and understand what's available in the marketplace, it's a great way to sharpen your view on the market and what's happening in the market whether we enter the M&A transaction or something and certainly something that we'd have to bring to the board and debate on the [emergencies] is that the best use of our capital, is that the best use of our resources.
In terms of the markets that we're interested in, I kind of view that in a perfect world it's nice to be in a market that has a structured capacity market like PJM, so that we always put that at the top of our list, that said when you look and just draw a circle around where we have our plans and where we have our employees, Eastern MISO, is an area, obviously where our coal facilities are and we've got PJM asset in the Kedall to the north and then we've got obviously (inaudible).
So there is kind of center of gravity around those areas and again we have a strong California position. So if there was something particular interesting there we would think about it. But in terms of the geographically I view around the PJM MISO areas geographically desirable in terms of market structure, certainly PJM is the best market structure for us to participate in.
So the question is – is there - do we have a fixed time line on announcing whatever it is that we do for capital allocation?
I would say there is no fixed timeline. When the new board came on, on October 1st, we met at that time, we went through our strategic review of the company of the markets, we've had subsequent board meetings where we're really focused on how we see – the five years, next three to five years, playing out in the areas that we think are interesting for us.
We've reviewed our budget our forecast, and certainly the next as we continue to meet with the board, it's we need to bring our best thinking around capital allocation, I would not put a timeline as to when we actually do something, although we recognized the capital allocation for any company, is something that you always need to be – keenly focused upon and with our liquidity position and market structure that's out there and different opportunities that may or may not exist, we'll be actively looking and certainly there's many good things about the restructuring being over.
One of them is – you're focusing on the operations day to day running the plants really well and the commercial aspects of the business and finding the right opportunities to invest and looking at overall what's the best deployment of our capital, whether that's a share repurchase or whether that's a re-powering at Oakland or whether that's M&A and that's something that we need to bring well-though out conclusions to our boards so our board can ultimately endorse or not our ideals on where to invest our capital.
So I would not say there is a fixed timeline but continuously through 2013, it's keenly focused on by the board and management. Yes.
Yeah, this is a question I will paraphrase, the question was would we do a single asset acquisition or portfolio acquisition?
I'll preface it by saying, if we did an acquisition it could be – it depends on the opportunity and again the risk-adjusted rate of return if you will. I think, as an IPP, generally speaking we compete more effectively for portfolio than what we do for a single asset, and I would think it's probably – if we went down an M&A path, I see more opportunity that way.
I mean you take a look at again the different things that are available in the marketplace, single-asset is difficult for us in terms of how do you finance or work it into to your capital structure, I would view that if we were to go down the M&A route it would more likely be some combination of assets more than just a single asset where we can really bring the synergies and scale that Dynegy has to offer.
And Dynegy when you look back through just a couple of years ago, we've ran, 20000 megawatts portfolio, I think a great asset of this company, is our infrastructure and as Clint mentioned, when you look at the segments by themselves in this low commodity environment, they make positive cash flow, but if you overlay $80 million of G&A on it, and you overlay some of the – the capital cost, we only have 10000 megawatts we spread that across. So scale, as you know and I know you know the scale in this business does matter.
So we think about it along those terms, but again I always have to circle back to we will deploy our capital to the highest and best use that risk-adjusted rate of return will provide. And we recognize that the whole – beginning slide where I started where arguing that CoalCo is a fundamentally valued at zero. Well that's a pretty compelling buy from our side as well, that's not lost on us and again it has to be completely debated with the board.
These are on – specifically to PJM to MISO. So the question is when you take a look at Capacity prices and market signals, what is it that we should be looking at to – see if there is a fundamental change occurring, I guess then within the MISO market and I'll take first stab at it and Brian will look to – he maybe to add a little color on that.
I don't know we're going to see much in the auction that comes up, what is it April, Brian that's May. April-May timeframe, the message and the word around retirements needs to continue to build an I think two things are going to force that, one the obvious one which is MATS and the environmental compliance and there's a hard date that's coming up.
But the other is low gas prices. Then if we go through a very warm winter again and we see the system back up with gas and we see gas prices go down I think there's a number of these smaller standalone plants that Brian referred to, will feel the pinch of that and accelerate some of these retirements. I don't think that happens necessarily by the April-May timeframe, I do think it happens as you go through '13.
So I think the market signals to me will be in the latter half of '13 and entering into '14, when we're getting much more visibility around the retirements and what's happening in gas prices and the like. Brian is there any color that you'd add to that.
Yeah, I'll add to that could be we're not going to handle a lot of market signals. A lot of folks when they look to retire their plants they don't necessarily publicize that, and that's a benefit them. We didn't talk about the Vermillion retirement until we had actually ramped it down – stopping the shipment of coal. But as far as what to look for, certainly retirement announcements like the – it was constant (inaudible) that was the announced a while back that was unexpected.
So that's good market point, so there's been several studies, one from Brattle, one from Bernstein that the point to lower reserve margins, as well as the MISO research, and then like Bob said just the general market conditions, that's about all there is to look at.
But the one thing I'd add to that though, the one thing that from a regulatory side that we've been involved in is the Attachment Y process, which if a facility is going to go to MISO and try to get an RMR type structure for the liability in the past it was, we'll go and we'll ask for the RMR or ask for the reliability study and in fact it come back and say you're not going to get an RMR, then they discontinue to run the asset.
Now the Attachment Y process is, if you go in and say you're going to retire unless you get a RMR, because you need it for liability if MISO comes back does the reliability study and says, you're not needed, no guess what, you are retiring now. And that was a big change during 2012, that I would say could be a signal as well as that, someone filed an Attachment Y, it's kind of playing sudden death if you will at the (inaudible).
In terms of the within MISO the spring option going to multi-year auction, and talking with John Bear of MISO last week, his message to us was think movement along those fronts will be slow it won't be until the load-serving entities really start recognizing and the PUCs, really start recognizing around the shortage that's building up. And I think what they would be encouraging and what they are going to encourage is the multi-year bilaterals. I think you'll see it show up in that form rather than a structure that – like a PJM would have. To Brian.
Morro Bay, in terms of re-powering – the question are there re-powering opportunities at Morro Bay and Moss Landing and I'll start with Morro Bay and I'm going to ask you for some help on Moss.
Morro Bay, in terms of location is – it's neither in the North and it's neither in the South and it's outside of the load pocket. So I think repowering of Morro Bay in the near term looks challenging and I view is unlikely. Something would have to fundamentally change in the market whether it's due to the firming capacity that's needed, or some reason to supply there's a lot of title, right now California, we're seeing particularly in the South, but California tends to be long generation at the moment.
So I don't necessarily see that in the near term for Morro Bay, Moss Landing Alan?
Yeah. Well, real quick on Morro Bay, there is a renewables project – a solar project that's in the works possibly near Morro Bay and years a down the road but that we already developed, that could provide an opportunity for some peaking as we need this sort of solar project, it's to be located in – same transmission line of as Morro Bay, in terms of Moss Landing, you know, we've got plenty of land at Moss Landing kind of acreage there, we can using support redevelopment if this newly (inaudible) capacity moves in long term there.
So as we're thinking about ways down the future 6% to 7% or whatever reason had to where to retires, (inaudible), repower with a new site while those years still existed.
And then the Morro Bay project that Alan was referring to the solar project we own some transmission rights in our view and talking with the owner of that site, is a joint proposal to PUC where you've got both renewable and firming coming together and we've got transmission are the kinds of things we're thinking of in terms of other options and alternatives around Morro, assuming we don't have the resolution with SCE that results in a multiyear contract.
We'll have to repeat that whole question. You've talked about specifically the Casco Bay, [Baron's] question is around with additional gas resources coming into the marketplace, would that help relieve some of the issues we have procuring gas, for Casco Bay, and are those assets today somewhat constrained and not being fully utilized if you will, because of those constraints.
Alan, talk about Casco.
Okay, so Casco Bay, in the near term we hope will deepen up, be an offset for the price support, there's license ability more longer term, we can get fuel to the plant, it's just a matter of price the most part rather than why. So when it comes down to the cost of (inaudible) plus the gas better, you can feel (inaudible).
And I think more longer term there need to be more robust infrastructure development you know if you think there is this recent article – a report by (inaudible) a few weeks ago, about a month ago now, that really talks about the constraints around New England, I mean this is [Anadarko] (inaudible) Steve was talking about the constraints the (inaudible) being up there so, speaking that and as well as Maine, state of Maine, the governor's office, now where they feel constrained and so now you get more – if these are where even governments I think will be more pressure we support redevelop the infrastructure in Maine support in the long term.
There should be and now I think maybe you should build on that talking about how we've changed how we-ve
How do we bit it and dispatch it by separate in the unit.
And we finally got to, when we think it was – when you're bidding a plant economically, trying to get gas after the day at markets close, a gas is so that's more difficult to get, kind of by intra-day gas, so what we've done is we've got our plants up, (inaudible) dispatch one by one, two by one, it's to a unit, the optionnality which prior to that going would be the best to buy one, so buy doing that allowed us to have a basically bidding in, that first made perhaps cheaper economically no one can get that fuel for the first block.
[Can't know] if the cost would incrementally go up as you buy more fuel intra-day, you can take that in consideration, and where you -- it gives you a best (inaudible) of bid range to bid for your facility, we have been taking advantage of that. And I think we've done that in late September, I think executing (inaudible) been better, more enthused with some one-by-one opportunistically (inaudible) would have missed out on.
Certainly if you think for Casco a very good opportunity would be bidding in the RFO process for the main utilities would be a good outcome (inaudible).
Well I don't think it's a risk to us in terms of Power Generation, when we think of our assets in MISO and PJM, there's been a lot of wind development in California, I view it as a actually very supportive of the renewables coming on given the size and capability of Moss 6 and 7, certainly what Alan covered in his presentation the ramping capability of Moss 6 and 7 is very valuable for the State of California.
So for California I think the more renewables the better and Moss 1 and 2 are very modern combined cycle of 1100 megawatts, again becomes very valuable in that environment with the firm and capability that that provides. So renewables for us in California are positive. I don't see any significant incremental impact on our existing assets more towards the investments that we made. Gregg?
Gregg Orrill - Barclays
So the question that Gregg is asking is around, may be expand a little bit on the retail, entry into retail and how we would see it scaling up in 2013, '14, '15 and managing that business?
Dynegy historically has been in that business in the past. Some of the people that were with Dynegy when that business existed are still there. We have the expertise in-house today to do those and we really just view it as part of risk management. It's an effective way to get the megawatts to the market near where our plants bus bar is.
So from a risk management standpoint it's a good opportunity for us when we think about collateral management, making sure we get contracts that don't become collateral intensive. We certainly are addressing that and thinking about that, but largely we think it's more of a credit issue and who your counter party is, probably both parties and either posting collateral but you got to make sure you got credit worthy entity on the other side of the contract. We'll – I think we'll use 2013 to ease into it to make sure that we work through the issues and we understand what this business would like as it tails up and make the adjustments accordingly versus the big leap. Brian, any additional color on retail?
Yeah, the C&I market in Illinois is pretty diverse. There is not a concentration in any one industry and also its fairly sophisticated crowd. They've been doing this for a little bit of couple of years and they are also looking to hedge up short-term. Their focus is on price, they will throw some risk into that as well, but their main focus is on price. They know what they are talking about.
We are going to want to go in and be transparent, let them know where we have an advantage, where we don't, how it benefits our plants and speak to get the business with price. Lot of the larger C&I is to the south of the state outside of St. Louis along the river. We have plants right there. Ameren has a C&I presence. Their plants are a little bit further to the North and to the East and we feel like we have been an advantage over Ameren as well.
But for the most part a lot of our negotiations with the C&I customers it won't be like what you experience in the residential area where it's a cookie kind of contract. The terms are straightforward and you have to pick from the menu of four or five different prices. We have a fairly sophisticated marketing crew more than a origination type crew that can tailor product specifically to customers again with a focus on having a lower price than the competition.
A ceiling on MISO capacity from a utility perspective on what the ROE would be on their investment. I guess it could, but I think what at this point in time I think of the time that it takes to actually comply if you haven't started it's too late. So I really think it's more about securing the adequacy of supply as compared to the two alternatives at this time whether it's existing generation or investment in capital controls at the utility level. So while that certainly could be one of the things that one thinks about if they haven't made the investment, it just, you know they couldn't do it fast enough to comply at this point of time.
Well I think that in general when the rails have a chance to claw away money they will claw with you know they will viciously go after it. Fortunately our contract stretches for quite some time so I hope they get very aggressive and they take as much as they possibly can from others, but we are well protected throughout this decade.
I am sorry, I haven't done a good job of repeating the question, but the first one is around the rail and the benefits that we had from the rail negotiation for those listing on the webcast and we had risk once the market recovers. And my answer quickly was no we have a long multiyear contract so we are protected.
Next question is, if we go into the M&A sector how does FERC take a look at market power within MISO? It depends if they look at, I think it's the FERC and DOJ that looks at it. So whether they look at it MISO wide or whether they look at it on a state level basis has some level of influence I think on it. You know I think the generation is pretty well scattered across MISO. So I don't generally think that no matter who is feeling what within MISO there isn't, I don't roughly see any regulatory issue.
So the question was around leverage, where it levered lowered than peers and how do we think about leverage is that the right level or how do we think long-term about our leverage structure. Clint?
I guess the way, that I think about is this somewhat dynamic process. Right now going into 2013 based on this one of our guidance I think Bob highlighted that on a gross debt to EBITDA basis were around five times on a net debt basis, around 2.5 times. First of all that kind of highlights the amount of cash we have got. But I would also say that in this commodity price environment I would rather err on the side of a lower leverage profile than the more aggressive ones, but also say kind of erring for a more conservative leverage profile I think is appropriate given that we have gotten.
We got some meaningful hedges in place for 2013, but virtually nothing for '14 and '15. I think strategically we're trying to leave a lot of our fleet open for, you know our view that there is upside longer-term in order to position a company to take that position and to do it comfortably. I think you have to have the balance sheet and liquidity to support that. So I think with where we are right now, I think I am comfortable with our leverage profile given the level of visibility and hedging that we have in place. Now I think to the extent that would have changed that either the commodity price environment improved or that we were able to hedge longer-term and have a longer-term visibility into earnings from cash flows and I think then you could revisit that.
Question is talk about liquidity longer-term and the availability of liquidity to hedge in the out years. Mike I'll look to you in a second to provide some additional content, but all of our, first, all of our hedging, the vast majority of our hedging particularly longer-term hedging is based on our first lien structure so we are not utilizing the cash.
Sure, no I was going to get to that. So, when you think about first lien liquidity with our counterparties to me that seems to be more of the constraint than market liquidity. The market liquidity particularly around natural gas is there. When you think about hedging the coal portfolio when you look further out gas is a proxy for power and a longer dated scenario it's effective longer-term as you start getting closer to the [promp] year or promp quarter whatever then you want to do your conversion to a pure power hedge.
But if you are going to hedge now for 2015, you can do it with natural gas and have the correlation that you need to make it effective. But more of the issue that we see and that should go away or should alleviate some extent as we do the refinancing is the credit capacity that were allocated by our first lien counterparties and right now we have about half a dozen first lien counter parties or so and we are always looking to add to that.
As we go through the refinancing moving it up to the parent level. We would expect that capacity to get widened, but also I think the counter parties that typically offer the first liens with Dodd-Frank and various other liquidity rules has put some element of pressure on how much will they offer and how much are they going to continue to participate in the first lien. So I think that tends to be the constraint rather than liquidity in the market to hedge the power. Mike?
I guess the only thing that I would add to you that is and we talked about a couple times in the presentation. The fact that we do kind of have a natural hedge between the two fleets that we operate GasCo as gas prices increase typically you see a compression in the spark, but you see the opposite effect on the coal portfolio.
But I do certainly watch the backend of that curve. I was sitting there in contango higher up. That the volatility of the gas tends to be in the shorter period versus the longer, but we've seen that get up just close to $5 recently not too long ago, but there are going to be points in time when we start seeing the contango raising in the back that we need to think about starting to lock some of that [interim back] the type of growth that we want to see in our earnings stream. So that's something that we watch every single day.
Just following up with Steve I guess (inaudible)
So Julian let me just repeat and [X-ray]. I understood the question so when you think about the revolver that we just entered into how does that effect liquidity and cash available for capital allocation and can you utilize some of that capacity?
So as we go and do the refinance and bring things up to the parent level and then expanding that revolver up to $400 million, how does that effect capital deployment? That's largely in the slide that Clint presented. That's building all of those assumptions where you have a $400 million revolver, but now you have got a lot of capacity of its parent level. You have got a billion two in some type of debt, we'll call it term debt and that unlocked $275 million in cash of which $150 is assumed in our guidance that is utilized for debt reduction.
Today we have got $1.355 billion we take that down to a $1.2 billion and (inaudible) sized $1.2 billion just around looking at markets with an efficient point, within our capital structure what's the lowest cost of capital, but again those things when highlighted need to be revaluated as we go to the market as we review with the Board on how much do we want to use for debt reduction versus other things.
So I think the swing factor in that slide that showed about $262 million of available to capital allocation you could really put $150 million on top of that and to determine how much do you want to use for debt reduction versus other uses of capital allocation.
Then may a quick follow-up on the territory price (inaudible)
Yeah, I would say that for…
Can you repeat the question first.
The question was when we look at our hedges that are in place right now, are they meaningfully out of the money or where are they and did that somehow affect our guidance? I think at this point between coal and gas they are relatively neutral. I think coal is slightly positive, gas is slightly negative, but I don't think that had really any meaningful impact on guidance. And I meant to maybe add a few comments around maybe why our numbers maybe a little bit different than third parties.
Certainly there are some third parties that include the potential SCE resolution into those numbers which we obviously didn't. Obviously there could be a different date that people are basing their commodity curves off of, but then also when we entered into the new rail contracts, that rail contract begins in 2014, but as part of that in exchange for significant amount of benefit after that we did agree to adjust some of the pricing around the rail lease cars in '13 and there is an incremental cost associated with that above and beyond '12, but certainly not will step up to '14, but there is some incremental cost in there for that step up in rail lease cost and that maybe something that that certain people maybe missing.
I have to think about how to guide you, if I can follow-up with you, you there certainly is a bump in '13 it's more significant in '14.
Well, I think Julian on the slide I had highlighted in my first conclusion slide that showed $70 million to $80 million whatever the number was for higher costs that's largely the coal step-up and that's really comparing '14 to '13. So your question is from '13 to '12. We, I think the way Clint said it is probably a good way to think about it. If you look at the difference between largely what the street saw versus what we put out is two things. It's pulling out the SCE resolution and the other is the increased economics that we gave to the rail carrier for '13 relative to getting a new multiyear contract that was as you can see from that step up in cost in '14 very valuable. Any other question?
Okay, again I would like to thank everybody for coming. Hopefully this was helpful and we do have a reception right across the lobby. I mean this lobby right here upfront. All right, so hopefully we'll see you there and again thank you for coming.
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