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Hello, and welcome to the Dynegy Incorporated, Fourth Quarter and Full Year 2014 Financial Results Teleconference. Please note that all lines will be in a listen-only mode until the question-and-answer portion of today’s call. [Operator Instructions]. I'd now like to turn the conference over to Mr. Andy Smith, Managing Director of Investor Relations. Sir, you may begin.

Thank you, Julie. Good morning everyone and welcome to Dynegy's investor conference call and webcast covering the company's full year and fourth quarter 2014 results. As is our customary practice, before we begin this morning, I would like to remind you that our call will include statements reflecting assumptions, expectations, projections, intentions or beliefs about future events and views of market dynamics. These and other statements not relating strictly to historical or current facts are intended as forward-looking statements. Actual results though may vary materially from those expressed or implied in any forward-looking statements. For a description of the factors that may cause such a variance, I would direct you to the forward-looking statements legend contained in last night's news release and in our SEC filings, which are available free of charge through our website at dynegy.com. With that, I will now turn it over to our President and CEO, Bob Flexon.

Good morning and thank you for joining us today. With me today are Clint Freeland, our Chief Financial Officer; Hank Jones, our Chief Commercial Officer; Catherine Callaway, our General Counsel; and Sheree Petrone, our Vice President of Retail and Dean Ellis, our Vice President of Regulatory Affairs. We posted our earnings release, presentation and management's prepared remarks on our website last night. Following a few opening remarks, we will devote the bulk of our scheduled time to your questions. Highlighting our financial performance first, adjusted EBITDA for 2014 increased by over 50% versus last year. Realized prices for the Coal segment increased to over 20% year-over-year, while realized margins at the gas segment more than doubled versus 2013. These higher realized margins bolstered by PRIDE initiatives and the addition of IPH more than made up for the reduced capacity and tolling revenues from contract expirations at the Moss Landing and Independence facilities, as well as higher rail transportation costs at the Coal segment. Forward MISO capacity sales now exceeds 7,000 megawatts at a weighted average price of $3.11 per kw a month for planning years 2015, 2016 through 2019, 2020. This includes 1,400 megawatts of bilateral sales at prices four times higher than last year’s capacity auction clearing price of $0.51 per kw a month. No market for bilateral sales existed in 2013 and this is indicative of the tightening MISO market conditions as load serving entities looked to meet their future capacity requirements as supply declines due to Coal plant retirements. Overall these capacity sales will contribute $277 million of EBITDA over the next five planning years. Only 20% of our capacity has been solid and 80% remains available to sell. So the remaining potential EBITDA increase is significant. For every $2 per kw a month increase and capacity sales across the MISO fleet, it generates approximately $150 million in adjusted EBITDA. As PJM prepares to launch its capacity performance product, we recently solid 200 megawatts of capacity performance at a price of $170 per megawatt day in the MAAC region of PJM for planning years 2018/2019 through 2022/2023. This transaction locks in over $12 million per year of capacity revenue for five years, but more importantly represents a $50 per MW day increase versus the most recent capacity auction clearing price. As a remainder, every $10 per MW day increase in PJM capacity prices through our pro forma fleet increases adjusted EBITDA by approximately $40 million. We are updating the 2015 adjusted EBITDA guidance range to $825 million to $1.025 billion and free cash flow guidance to $100 million to $300 million. Guidance assumes that the pending acquisitions of the Duke and EquiPower assets close by April 1 and utilizes price curves and actually year-to-date result as of February 10. Compared to our previous 2015 adjusted EBITDA guidance range, the updated range is approximately $525 million lower, reflecting a roughly $200 million net impact from lower commodity prices and a $325 million impact from the three month extension in the assumed transaction closing date. Finally on the strategic front, we filed our response for the January 16, 2015 FERC comments on February 6, which included the settlement we reached with the PJM Independent Market Monitor. Our response requests a 15 day comment period and a transaction approval date of April 1, 2015. The 15 day comment period was granted by the FERC and it expired this past Monday with only one repeat comment received, accordingly we filed with the FERC yesterday that we have no further comment and again requested an April 1, 2015 approval date. In connection with the California portfolio sales process, second round bids were substantially below first round bids and what we consider to be the portfolio’s value under our ownership. Accordingly we terminated the sales process and will continue to own and operate these assets. At this point Julie, I'd like to open up the session for Q&A.

[Operator Instructions] The first question is from Julien Dumoulin-Smith.

Hi, good morning. Can you hear me?

Yes, good morning Julien, loud and clear.

Great, excellent. So I wanted to first clarify your updated ‘15 guidance here. What portion of EBITDA is from ECP and Duke that sort of is been ‘lost’ by the delay and the deal close?

Julien approximately $300 million is the impact from the timing being pushed from the guidance been set as of January 1 to now being set as of April 1.

Got you, excellent.

If you look at the difference between the midpoint to roughly $500 million, $ 525 million, $325 million was the three month delay in the start and $200 million is associated with price curves.

Got it. And then in terms of MISO capacity auction expectations, it seems like there have been a few different rule changes of late, tweaks if you will. What are your expectations going into next month if you can be a little bit more explicit?

Well, with MISO auctions Julien you never quite tell what’s going to happen, so that’s why we look to move as much capacities as we can outside of the auction process. But the recent developments around that, I think a minor change was a tariff change that allows any generator that plans to retire as a result of Mass, that they can do that. They do not have to offer into the upcoming capacity auctions. So that allows some level of slight positive there, if those generators had any thoughts of biding in because of the tariff, they no longer have to do that. So that’s a slight positive. There will be exports from zone five; I think that’s a positive as well. 1,000 MW is still the restriction coming out of the energy [ph] zone, so I think that remains to be a positive and you saw the other day the FREC rules on some of the requests that are coming in, for those that are looking to avoid supplying capacity and energy in the market for the six and half week period between the Mass Implementation and the end of the planning year and two of the generators received that waver and two of them were denied that possibility and there is another two waiting for a final resolution. So overall there is a win and a loss in there, so. Generally speaking what we see on the bilateral sales is that still there’s a lot of interest coming, so you still see eight to nine gigs being retired in MISO over the next 18 months or so. So I think versus last year it should be a more favorable result versus last year, but how much we’ll see.

Great, excellent. I wanted to follow up on the PJM deal you signed in the quarter. Is this really recognition of where you think capacity performance is heading and to what extend is there a liquidity premium baked in there versus this being a very good illustrative data point on what the CP prices will be assuming rules are approved?

Yes, I’ll start the answer and then I’ll let Hank provide his perspective as well Julien. But for us when we had the opportunity to sell five year capacity product at $170 MW per day we think that’s a pretty good print relative to the last auction cleared at a $120 MW per day, so that $50 per MW day, 50 MW per day uplift is significant and you think about the leverage that our portfolio has to capacity prices in PJM was every $10 on the portfolio equaling a $40 million uplift. So it’s quite substantial. So we just viewed it as a solid print. I think it’s probably the first visible print in the market prior to the auction, so whether that’s marked or not we’ll find out, but we just thought was a good print for us to look in for five years and Hank may be you can talk about liquidity in the market that you seeing.

Sure, Julien we’re encouraged to see a bilateral transaction out there of some size in PJM that’s has been absent lately. There are some other conversations going on out there, our people are looking at numbers over a longer term, so that’s very encouraging to us from a risk management perspective. This is 200 MW for five years. It will represent post acquisition 16% to 18% of our available capacity in the MAAC region and something in the order of 2% to 3% of our total capacity in PJM, so it’s a small sliver. We’re encouraged by the pricing of it and also encouraged by the – what we hope is some interest in bilateral transactions away from the auction process.

Excellent. Well thank you all very much for the time.

Thanks Julien.

The next question is from Steven Fleishman.

Hi, good morning. So just a question on the guidance change related to the delay. So just losing that one quarter was $325 million, which I think the whole deal on a full year was suppose to be about $900 million. So obviously losing the first quarter was a lot bigger than a normal quarter. I assume that’s just a seasonality of New England prices in particular.

Yes, that’s right Steve. Of the $325 million its roughly evenly split between ECP and Duke, although ECP is a little bit more, but it is roughly evenly split. But when you look at the change since our original guidance, it’s really the ECP side that has come down more materially and that’s really driven by Brayton Point, given how profitable Brayton Point is during the winter. So you are right. I think when you think about the seasonality of the fleet, the first quarter is very important, particularly for the ECP fleet.

Okay, and you know just thinking a little bit on let’s say hopefully this is closed by April 1, but if it ends up being May 1 or June 1, those months I assume are not as meaningful and then it’s back to kind of the summer that really matters.

That’s right, it’s a shorter quarter. There are a lot of maintenances done during those time periods. So April in particular I think is the weakest month.

Yes, that’s right.

Okay, okay, and I guess a question in terms of use of capital. You don’t mention anything about buybacks. I assume that’s because you obviously lost a lot of cash flow from this delay in 2015. So should we assume that that’s something that could be on the table in 2016, if you think about it that way? How should we think about that?

Yes Steve, I wouldn’t say we’ve concluded to any year, but I think your premise is correct that with later closing date of the transactions, also not monetizing California, and Clint had a slide in the deck around capital allocation that showed our cash forecast by the end of the year being in the mid-700s or so. I mean that’s a comfortable level for us, so I would say that your premise is generally correct at ‘15 probably unlikely, but ‘16 very much on the table and that really is depended upon how is the summer. Is the summer going to be like last summer where it’s a weak summer or is it going to be a strong summer on demand and prices and the like? So that will weight into it as well, but I think it’s very much on the table for ‘16 and for 2015, again no conclusions. We haven’t bought anything to the board around this, but the key is getting these things settled and closed in 2015 and then really working on the integration synergies and things of that nature and ‘16 will probably be the year for capital allocation for us.

Okay and then one other question on – you talk about the – related to PJM capacity and CP, you talk about the majority of your MW being available for CP. Is that kind of – can you be maybe a little more specific. Is this like 55% or 95% or a little more flavor on what you mean by majority?

Yes Steve, I won’t put necessarily a number to it, but I would say the vast majority will be eligible for CP. Some of the things that we have to consider will be around, we’ve had this continual problem with Kendall when you’ve got the wind coming out of the North and who would ever thought that the wind will come out of the Northern Chicago in the winter, but the inlets tend to have some level of freezing up then we get [indiscernible]. So things like that we need to consider. But in terms of the absolute number of MW, it’s clearly the vast majority. So I wouldn’t think about it in terms of 50% to 60%. I would think of it somewhere North of 80%. We’ve got to do our fine tuning around this as we prepare for the auction, but the vast majority will be in it.

Okay, thank you.

The next question is from Jonathan Arnold from Deutsche Bank.

Hi, good morning.

Good morning Jonathan.

Just curious on the, just on the PJM, CP deal. Is that contingent in any matter on the PJM actually going forward with CP or you pay this in any event?

We have a contingency in the contract for a price reduction if the CP does not get approved on a rolling year-by-year basis.

Okay, and you won’t share what the price was sort of net of CP I’m guessing.

Jonathan, I’ll intercede here and I won’t put a number out there, because Hank won’t want me to say anything, but it’s above what the last auction cleared at, so it’s above the 120.

Okay, and then secondly just looking at February 10, you marked the guidance certainly PJM and ADHub prices look like they are up reasonably, a couple of dollars since then. I guess may be Spark’s as well we should look at. Can you comment at all about directionally where guidance would be? How do you use like yesterday’s price?

Jonathan, I’ll just give you may be a little bit of color on the process, because this seems to happen every call that whenever we pick a date for the guidance that the market has a move and a broad move in one of the directions. So we utilized our year-to-date results through February 10, we use price curves as of February 10, and then that’s the guidance that we take for internal approvals and the governance approvals around the order committee and the like and so that’s what’s approved. And when we do that, when we set our guidance range of, we’ve 825, to $1.25 billion, so midpoint of $925 million. When we set our guidance the actual point estimate, you can always assume its somewhere between the midpoint and the upper range and that way we give a little more cushion to the down side. So that’s kind of where the starting point was. Since the February 10 date prices have certainly strengthened. We’ve seen expanding of spark spreads and Ontelaunee, Independence, Kendall, all have done particularly well in February. On the coal plants they have done well. Kind of Central Illinois and North, unfortunately there is a planned transmission outage at the same time as the weather event that impacted basis a bit for Baldwin, for Coffeen and for Newton. But I would say, when you take all of those factors in to consideration that certainly if it’s an uplift, if we were doing the range today, we would essentially have been higher because of those things. So when you think about your starting point is probably in the midpoint, between midpoint and the upper part of the range has clearly put you more towards the top of the range, but obviously these things can change quickly as they do, but that’s currently I’d say the best way I could describe where we are.

Jonathan, one thing that I would add and just something to give some thought to, that particularly with the Duke portfolio, the coal and gas leads tend to move opposite one and another. So not necessarily always additive. As a matter of fact when we looked at the impact in the change of pricing between our last guidance range and this guidance, there really was minimal change in that fleet, simply because the uplift in the gas fleet was offsetting the down draft in the coal fleet and so it’s relatively flat. So that’s one thing that to think about when you are looking at prices, it’s not just to look at the generation time to change in price, but also think about the dynamics between those two fleets, particularly within PJM.

So the $200 million is largely I guess the MISO and New England move.

That’s right.

Since the last guidance? And just not to push you tide on to it. Is what you’re saying that if we did the guidance today the midpoint would probably be around the high end?

The midpoint would be higher than what it is today.

Okay and then just finally on the timing of the acquisition. Is there chance you could get these done for some of March, I guess that it’s very FERC dependent now, but do you feel April 1 is just the middle of the road estimates or could we see it kind of...

The way that I’ve learned to predict these things, is not to predict these things and you know we’ve asked for April 1, we do know that on March 19 there is a scheduled FERC hearing, which the agenda comes out at March 12. So if for some reason they are going to look at it in March, you would think that it would show up in the March 12 agenda for the March 19 meeting. Other than that I requested to date it April 1. I think FERC is, they will need their time to review the things that have been submitted and we are optimistic that April 1 is the date that gets the final approval, but we really have no insight to where they are in the process or whether it’s March or April or May or whatever. I would only say that I think a good positive sign was they accepted our request for a 15 day comment period, which after providing a delivered price test that’s probably on the shorter end and then comments received to our filing there is only one comment and it related to New England, which the questions FERC had in their initial letter to us was around PJM and the question on New England was the same question that had previously been raised. So it seems like this has been out there for a long time. The most subsident comment we had certainly was the Independent market monitor in PJM. Everything there has been settled. So we think it should be a clear path for approval.

Okay, great thank you.

The next question is from Gregg Orrill from Barclays.

Yes, thanks for taking my question. On California I think you mentioned in the remarks that you didn’t go forward with the assets sale obviously and just wanted to get some background around your thought process and how it all went?

Sure Gregg. So when I guess the last time we spoke publically about it, we had a first round completed. There was many involved in the process. The first round bid you always kind with a grain of salt, second round bids we had a much more limited group that we elected to work with and what we all as we went through the processes that the final bids, they didn’t look like the opening round bids, they were quite different. I think for different reasons, I think one reason is that some of the buyers tend to look at the situation like this were Dynegy is this substantial portfolio in the mid-West and through the North East and you’ve got a smaller position in California that is just out there. So you got – so not that I think you are going to sell at any price, so folks to trying to do a little bit it of bottom feeding on us. I think that’s one element of it. I think another element that we are looking for conclusion of the once through cooling approvals there and that scheduled for the final California water resource board approval in April. Once you have that, that really clears up the issues around once through coolingfor the portfolio, but that’s still an open issue. You don’t have 100% surety, so I can’t emphasis with the bidders around that. You don’t have the final answer, so it’s hard to pay full value for that consideration and I think may be the third element to think about in California is that it’s not an easy market. If you are putting new steel in the ground you get off takes and if you have steel in the ground your fight for RA capacity and your fight for new contracts coming from utilities and when the once through cooling is not fully resolved, our participation in those contracts is pretty much you are not participating in it, because you need a certain amount of number of years of surety before utility will contract with you. So I think that had an impact on it. So I think when you put all those factors together and we looked at many different ways from accretion and dilution and one that I tend to look at the most is we have a view of index several years what the present value of this business is in our hands and you compare that to the bids and the more accretive action for us was to keep the assets and we could continue to do over June we’re going to get the ones through cooling settlement hopefully completed within the next six weeks and we’ll work with the utilities on off takes for the assets and then continue to pursue development options to some of the sites outside of Moss Land and be in Oakland and more of that, so that’s where we are with it.

Thank you, Bob.

The next question is from John Kiani from Teilinger Capital.

Good morning Bob, Clint, Hank.

Good morning John.

I’m trying to understand the revised maintenance CapEx of $285 million. I understand based on the slides that $30 million of future period or CapEx was pulled forward into 2015, but I would have thought that base line starting maintenance CapEx for 2015 would have been lower because you only assets for nine months. Could be please help me understand that a little bit better?

Yes John, and the point you make is actually an important one in understanding the free cash flow for the year. During the first quarter you typically don’t have a lot of outage and maintenance work, most of that begins in April and then carries on through the rest of the year. So what you really have is the situation where the last nine months of the year is where virtually all your CapEx is and all your maintenance work is. So when you think about the free cash flow guidance, what you really have is virtually a full year of CapEx but only nine months of gross margin from the acquired portfolios. So it’s not evenly split through the year.

Right and is there any working capital adjustment or anything like that with the counter parties for that type of cost?

Well, there is a working capital component that will be coming over with the businesses in total. It’s about $300 million in total working capital between the two fleets, and there are some adjustments I’m not sure that there is that they really need adjustments associated with the CapEx.

Got it and just a few more question – that make sense. Just a few more questions on the subject please. What made you all decide to bring forward the $30 million of CapEx from future periods?

This is all around reliability spent and as we prepare for capacity performance products, certainly we want to start driving reliability and in 2014 when you look at lost opportunity cost, they were upwards to $90 million or so in the lost EBITDA and you will never have zero loss opportunity cost. But certainly when we benchmark our fleet on reliability on equivalent availability factors and the like that these projects have pretty quick payback and rather than taking outages and dealing with sections of the plant that have shown to be problems in the past, let just address them now and not take lost opportunity cost. So these are projects that generate strong returns, quick pay backs and they focus on specific areas of the individual plants that have shown to be the risk areas around outages and I have to say, if you look at our fleet performance year-to-date and we’ve been focusing along time on reliability through PRIDE and other initiatives, but our performance year-to-date has been very, very good and when you think about pricing opportunities that exist in whether it’s a shortage event or a high demand periods, that’s when the plants get under stress and to drive the liability has a very quick payback and the decision there is really just accelerating; outages that should be done sooner rather than later, address weak points in the various plants. So it was discretionary on our part, we didn’t have to do it, but I think from a prudent operator point of view and the financial analysis suggest that it’s worthwhile in doing it. So that’s why we’ve accelerated these things.

And the other thing to keep in mind John is that as you go forward by accelerating some of those outages from ‘16,’17,’18 into ’15, you won’t have those in your maintenance CapEx in those future years because you’ve now taken them into this year and so there certainly should be a free cash flow benefit in the future years for having accelerated it into 2015.

Because we still believe John that the key years here are ‘16, ‘17 and ‘18 when you have all the plant retirements, spark spreads widening, Dark spreads widening and driving reliability and being ready for reliability for those periods makes good financial sense for us.

That’s helpful. So Clint to your point, what should we use for ongoing maintenance CapEx since this year has future period CapEx accelerated into it?

Yes, I think what we’ve said in the past is typical maintenance CapEx spend for the combined company going forward should be in the range of call it $200 million to $250 million a year. We still see that being the case obviously, you’ll have timing issues sometimes that may put it in higher in the range or lower in that range, but that should be generally where maintenance should be going forward.

Got it and then what should we think about for environmental spending on an annual basis. I know it’s not necessarily ratable and IPH has some lumpier stuff later in the decade, but how should we think about that portion of your CapEx is well pleased?

Yes, I think in 2015 we’ve got about $45 million in environmental CapEx. As you go forward I think it will be something similar next year, kind of similar range stepping up likely in ‘17 and obviously you got the Scrubber work in Newton in ‘18 and ’19. So it will be stepping up pretty materially during that period. So it is fairly lumpy, but should be around that $45 million to $50 million a year for the next couple of years.

Got it, thank you for the time.

Thanks John.

The next question is from Michael Lapides from Goldman Sachs.

Hi, guys. Some kind of nuts and bolt stuff. When you look at the capacity factors at CoalCo during 2014 and especially during the fourth quarter, but it’s really a full year thing. Prices were higher, output was lower. Help me get my arms around that. Was that just planned outage schedules although it doesn’t look like because availability factors were pretty high. Was it time of day just kind of if you give some more color on that that will be great?

Well, I think your planned outages will certainly have an impact on it and we try to highlight that on the fleet to show the differences, but I would say there’s two other factors that come into it. One is certainly the outages and I mentioned a moment ago that we had lost opportunity cost during the year that lowers the capacity factors. I think the other thing I would highlight though is that it was a very weak summer and you have units go up for economy and we only bid into the market, we only run in the market I should say when its economic to do so. So there are points in time during the summer and fall where it was an economic to run some of the plants and so that feeds into it as well. I think that’s a portion of it. So when you look at the difference of the five points may be year-to-year portion of that is related to economy and a portion of that is related to just availability.

Got it and also when you give, and you do this is slide 17 kind of towards the back, the average hedge prices for both IPH and for CoalCo on a capacity sales. What’s going on that drives the spread between the two? Meaning on a percentage basis and I know we’re talking about a low dollar per KW month. I’m just curious why one would get much higher or very different capacity payment and bilateral than the other.

There is a couple of reasons and I’ll through it and Hank can fill in where I don’t get it quite right. But first of all when you think about IPH and lot of their capacity basically all of their capacity had going forward is sold through retail. So retail monetizes IPH capacity, so that’s kind of the build in hedge there. So as retail contracts are signed we point the capacity of IPH to the retail books, so that drives a lot of the megawatt. IPH also has two legacy supply contracts for our capacity that go well into the next decade and even beyond that. So that accounts for another chunk of my IPH as higher and then there is one another origination contract that plant specific because the off taker is located very close to that particular plant. So those three things right away put more capacity builds towards IPH versus Coal segment and then the bilateral sales tend to end up in the Coal segment, because when we look at our hedging protocols and ensure that we have the right governance around the two entities and honoring the arms length relationship between entities underneath the Dynegy umbrella, that Coal segment tends to have less capacity sales in IPH to under the protocols they get most of the bilateral sales and then also ever ending credit requirements that IPH typically doesn’t have the credit and in that case coal segment will get the capacity hedge to extent there is a credit requirement. Hank is there any you would add to that?

The only thing that I would add to that is that our exports to PJM are from the IPH fleet, so there is a forward capacity commitment into PJM for a portion of that volume.

Yes, that’s 825 MW of capacity from the IPH plants that goes into PJM starting in ‘16, I think it’s 825, 847, so that’s another big chunk.

Got it, thanks guys. Much appreciated it Bob.

Okay Michael.

The next question is from Ashwin Reddy from Venor Capital.

Hi guys, how are you? Thanks for taking my question. Quick one on the transmission projects that you had kind of alluded to with respect to Baldwin. Do you have a sense yet as to how that may help out with the basis differential there and then I guess the second part of my question would be kind of on a longer term basis with those projects also help that kind of generally basis and kind of all the CoalCo’s less IPH plants or would that be just Baldwin specific?

First thing I want to say Ashwin that I just surf, so I don’t confuse the point. I commented earlier that there were some transmission outage. These were planned outages that MISO took as they prepare for spring outages for transmission work so its unrelated…

I was referring to the – I think you guys had referenced a transformer project and then a longer term project that you guys are going into with the – that would be completed in 2017.

Right Ashwin, so I just wanted to differentiate that. So there wasn’t a point of completion and I was going to let Hank speak about the transformer project at Baldwin.

So the Baldwin transformer is scheduled to be replaced and in place operational by the end of June of this year, working closely with Ameren on that project. There were various reconductoring projects that occur over the following 18 to 24 months to complete that portion of it. Our starting point was to look at the various congested flow gates in and around our fleet and determine which of those had the highest impact for the lowest cost and these were – the Baldwin Transformer, the reconductoring projects were on MISO’s list at a lower priority level over the next few years. So to accelerate those to the top of the list, we participated in funding those projects. So they are seen as key bottlenecks in and around the area. They will benefit not only Baldwin, but other assets in Southern Illinois. In terms of modeling the basis, it is somewhat of a circular process that we’re trying to look forward and look at the impact of the big inter [ph] projects and compare the results of this investment versus a projected outcome based on other things that are going on in the system. So we see it as a net positive versus the non-mitigated case and see a positive return with that activity. The other source of potential return on these assets is the award of the ARRs in the process, which we can monetize by converting the FTRs or taking those to the auction and that’s an ongoing process.

Got you. So am I understanding it correctly that kind of in a longer term basis that you would or a longer term kind of view point you would have a basis benefit from not only Baldwin, but kind of all of ITH and kind of most and the CoalCo plants that are kind of affected by that.

Yes, I think Ashwin that in addition to our products obviously within Ameren the multi value projects will continue to be done, which are all designed to flow with the power more efficiently. So your basis hasn’t really been much of an issue for us in the past 12 months or so. Obviously we just had some in the past few weeks, but that was a planned outage that caused it. But I think overall with the amount of transmission investments being made in the territory that between what we’re doing, what’s being done there that it should continually get better and some of the projects that we elected not to do, we elected not to do it because they are actually scheduled to be done in a couple of years and rather than us pay for it, they are going to be done anyway in the ‘17, ‘18, ‘19 timeframe.

Okay. And then you kind of alluded to this in the back of the remarks here, but it looks like it was from our standpoint there seems to be a decent amount of positive things going on with respect to the IPH suite. I was wondering if you could kind of maybe speak to that a little bit and talk about how you guys are thinking about it. I mean with the capacity prices, the bilateral capacities we’re seeing and various things like maybe possible transmission improvements and obviously a possible uplift in energy prices given what might happen in MISO capacity over the course of the next couple of years. Kind of curious if you can just kind of touch on those items with respect to IPH a little.

Sure. I think I’ll highlight some of the items. And my point of comparison is to when we originally made the acquisition of the IPH fleet that there’s been a number of changes since then. Obviously the capacity market continues to tighten. We’ve done origination contracts there, retail continues to build its book. Our wholesale energy business that’s been growing since we acquired it and that’s the path for the IPH to monetize as I said early, much of its capacity. We have 825, 840 megawatts going into PJM with another 240 megawatts scheduled to go into PJM later this decade as well. So all of those things are more bullish than what we have I think we originally had forecasted. The Newton scrubber, we’ve converted that contract from basically a target price we’re somewhat open ended and your subject to inflationary pressures as well. We’ve converted that to a fixed price with no escalation. That has reduced the cost from our estimates by about $30 million. As our fleet expands, the charge for corporate services to IPH is going to go down by about a third, so that’s going to leave more cash down in the IPH entities just from the simple fact that it’s a lower charge and our PRIDE initiatives and driving reliability and the like for IPH. The fleet is run better than expected, but we continue to make investments as we do with the Coal segment fleet to drive the liability, because still ’16, ’17 and ’18 I think in MISO are going to be really bullish years for the results of Coal and IPH during those time periods and then again having plans that are reliable at the time we really need it.

Okay. Great, thanks guys. I appreciate you taking my questions.

One other thing I would add Ashwin too, the exports, the PJM and we highlighted on the slide are eligible for the CP as well and they will be a beneficiary of that as well assuming prices come in higher.

The next question is from Neel Mitra from Tudor Pickering.

Hi, good morning.

Good morning Neel.

Most of my questions have been answered, but I wanted to get a little – just a little bit more detail on the PJM CP agreement and possible future liquidity. I know this one is in MAAC, but when you look at maybe kind of the zone in PJM or the type of off take or the duration, I guess this one is about five years. What probably makes the most sense for next contract for you guys or more liquidity in the market. Do you think it varies on those factors or its just kind of – its something that we don’t know yet.

So Neel, this is Hank. I think part of the opportunity here is with the shifting, landscape and the market design. It will encourage people to look more closely at the values and in terms of some of the circumstances that might drive these things, if there are commitments to capacity markets that are made and based on new construction and new construction gets delayed, there maybe opportunities there. We’ll have an opportunity to have more customer interface to our retail business in Ohio post acquisition, which will also give us another, a touch point in terms of capacity. So we are encouraged by the activity and just as we did in MISO, we have some manpower dedicated to customer contact in PJM to the retail and wholesale functions and we’ll try to cultivate some more opportunities along those lines.

Perfect, thank you.

The next question is from Jeff Cramer from Morgan Stanley.

Hey thanks, good morning guys. Just on some of the capacity price assumptions, what have you guys included in your 2015 guidance for the outcome of the MISO capacity option this year.

Jeff yes. So as we look at – I guess there are a couple of considerations. One is, we’ve assumed that not the entire fleet clears. So roughly 50% of the fleet clears and then when we look at price and I hesitate to give anything specific, but I think our expectation would be at least for guidance purposes that the price clears somewhere between $1 and $2.

Okay, thanks. And just am curious, when you integrate the portfolio later this year and you mentioned the mark-to-market has increased in the last couple of weeks. You guys have a better sense whether it’s for – I’d be curious actually both on a hedge basis in ’15 and then from an open perspective you provided the sensitivity of the gaps, but what does that look like to the downside. I’m guessing the sensitivity isn’t quite as large given the introductions of the additional CCGTs and I’m just trying to get some color around that.

So, let me try – this is Hank. I’ll try to take this down and make sure. If we’re not getting to your question, let me know. I think that we see – the gas story needs to be looked at on a regional basis. For example the Duke fleet that’s 3CCGTs right on top of the Marcellus, have access to Marcellus gas and our independence facility also has access there. So spark spreads are expanding and on a downward move in gas prices and the power price is sticky in some cases, because of the higher priced fuel and less efficient units that are often setting prices during mid to high level demand periods. For 2015 as you know, we’re 70% hedged at our Coal segment and the IPH and which gives us a lot of downside protection in terms of gas movement there. On our legacy fleet on the gas side we’re about 50% hedged. We locked in very healthy spark spreads in that and with those hedges and in 2015 we’re seeing expanding spark spreads as we go to delivery for the open position on the gas fleet. I think one of the other issues is as your question you start talking about the subsequent years, I think it’s important to comment on the structural change that’s coming. The retirement, there’s still a significant amount of retirement that have yet to occur and I think we don’t know the full impact of those on the energy markets until we go to delivery in high demand periods over the next 18 months to get a look at what that structural shift does. I think while gas prices will continue to be important to us for obvious reasons, I think they become less important as the – less of a driver as the reserve margins tighten up post April ’15 and post April ’16.

Okay, I guess the $360 million is the EBITDA upside to $1 increase in gas. I don’t know if you had a similar number to the downside.

Yes, I think it’s relatively symmetrical, because I think this is really driven by your coal fleet.

Even with the new, the additional CCGTs in the portfolio.

I think it gets muted to the downside, because of the balance between our gas fleet and our coal fleet. Again particularly, any assets that have such great access to Marcellus gas. The spark spreads expand as gas prices are coming off and at some point you’re into higher priced units setting prices and our Coal fleet as we compete with other coal units, our objective is to be a low cost provider. We do that by becoming aggressive on our purchasing strategies, aggressive negotiations on our transportation contracts and in the post acquisition fleet, the Duke Ohio fleet there is already aggressive blending of less expensive Illinois basin coal with some of the Northern Appalachian coals. We’ll continue to pursue that and try to push those frontiers to make sure that we are competitive with other coal units that are setting in a price through a number of the hours.

Hey Jeff, just stepping back from it all, within PJM we got a very balanced fleet between coal and combined cycles that they do tend to offset. MISO is obviously coal, so we have a difference between the two and I think what we would need to go back and take a look at the downside a little bit more, to put more precise numbers around your question, because I think as Clint highlighted earlier, the moves that we’ve seen in Ohio are largely within the Duke Ohio state that largely offset each other when the gas moves on cycle, it gets the larger spark and gets dispatched in front of coal and then vice versa.

Well, in the dynamic that the 360 does not take into consideration, which I think is getting to Bob’s point is that this assumes that prices change based on a 7,000 heat rate. So to the extent that coal gets displaced higher heat rate units, then the relationship begins to breakdown and the impact begins to be more muted. So I think this is more of a relatively kind of hard wired relationship between changes in gas prices and changes in power prices where maybe that relationship is different, in different markets, but also again its higher heat rate units, displays coal at lower gas prices.

Okay. Thanks and a couple on IPH if I could, just the decline, it looked like there was a $38 million of EBITDA during the fourth quarter was the cash decline was $44 million, pretty big _ between the two. And included $60 million at IPG and moved down in cash. It’s kind of what drove that and give the free cash flow outlook for ’15?

Yes, I think when you look at the free cash flow for IPH for 2014, what’s not captured in kind of the reported free cash flow is that we talk about EBITDA and free cash flow on a segment basis. So that’s before the allocation of G&A. So there are those G&A payments that are made to DI that again would come out of the cash balance. So that is a lot of the different between the free cash flow and the change in cash that you are seeing. It’s that and then you’ve got some collateral movements in and out of IPH that also would be separate. So once you add those two factors in, that explains kind of the delta in the numbers that you are looking at.

Okay and just lastly, it sounds like a lot of the IPH capacity is already committed. I’m just curious, what’s available for the next, for this upcoming auction? Like what’s remaining, kind of what’s the upside that’s still there?

Well, there is a substantial position of the fleet that’s still open and available into the auctions. The real issue around the auction besides the mystery about what the price openly becomes is what quantity clears. And it remains to be seen in terms of calculating the upside. It remains to be seen how both of those factors come out, the price, as well as the volume that clears. So we’ll certainly know more about six or eight weeks but right now around them, we see about 22,000 megawatts committed. It’s a 4000 megawatt fleet and adjust that for [Indiscernible] you are talking probably roughly 1,500 or so megawatts available.

For IPH.

For IPH.

Right thanks guys.

Okay.

The next question is from Paul Patterson from Glenrock Associates.

Good morning.

Good morning Paul.

Just a sort of follow-up on the CP contract. It seems substantially below net CONE and just looking at like the filings and everything that PJM was sort of asking for in terms of bidding and have you. I was just wondering if you could sort of give us a feel. I know it’s a five year contact and obviously its benefits with respect to that. But how do you think about that in the context of the upcoming auction what have you.

I mean for us I mean it was a price that we were willing to transact at for the upcoming auction. I don’t know this is indicative of what’s going to trade out or not. But this for us is locking in a five year revenue stream that obviously is substantially above a price clear. So we’ve got a large fleet in PJM that we have to place and that we could move 200 megawatts at this price. That was our decision point. Whether it actually clears or not it’s a new product and we will find out shortly. For us this is a good entry point to at least place the first 200 megawatts.

I got you, but I mean does it reflect any perception that you might have in terms of what the longer term outlook might be as just assuming it looks like the capacity performance is pretty much excepted as filed. In other words, do you see a declining curve potentially for CP over time or I guess that’s what I was trying to sort of gather from the decision to go ahead with this. Does that plan into this at all, or do you have any thoughts about that?

I wouldn’t say we see that at all. I mean its again, it just more of a solid transaction for us to enter into and the investments that are going to be, need to be made across various company’s fleets and people bidding in. The cost of doing that should be I think bullish for CP for some time to come. So I don’t think of us locking it in for five years at this price is a indication that we think it’s going to slide in the out years. This was just more. It’s just a good print for us.

Okay and then in terms of the majority of your plants that are pretty close to CP compliance, and that includes with respect to the nominal or minimal cost to achieve is that right?

Well, the thing with CP and driving the liability is like I talked about earlier. There’s so much money that you leave on the table, but you are not reliable penny wise. So we are making reliability investments all of the time. I think with CP some of the things that we are dealing incrementally around that, in addition to all the things, that you want to do at a coal plant to ensure the liabilities, around the gas plants we are looking at additional lateral that go into the facilities, do what we need to do to insure that we don’t have any type of interruptible gas. For us they are not significant investments, but the coal plant reliability investments that we are making and we talked to you earlier about, the CapEx is associated with it. I mean you do that anyway, but they are significant investments and CP just makes it even that much more important to do it, because of the penalty structure and I think one of the things that we highlighted I think in Hanks script that we have well over 60 units in PJM. So you get a lot of risk mitigation by having 60 units in capacity performance. It was the old days where we just had basically two units and in PJM. If one goes down you got a problem during a shortage of it. So there is a lot of risk mitigation anyway. But we spend a awful lot of time effort and resources on driving reliability and whether that’s – some of that’s whether its CP or no CP you do it because you need to do it and we will be bidding those costs into the auctions as prescribed by the rules in PJM.

Okay and then with respects to seams, I mean it’s a lot time since we talked about it, but there has been some activity. It goes slowly, but it does go. Any thoughts about that or any – I mean you guys just have the perfect SEMS. Well, not the perfect, but you guys have both elements, both sides of it. Any thoughts about how the PJM/MISO seams that you might ultimately resolve here. Any timing on that?

Well, we continue to try to get transmission into PJM and we have anything that we are looking at to take into PJM. The whole seams issue between the two tends to be a wrestling match. So we just continue to look for past and we do the various transmission studies on both sides of the markets to see where we can enter. And again, the most recent success we had was around JPA, to move 240 megawatts of JPA into PJM later this decade. That’s how we are pursuing and as far as MISO and then PJM working out their differences on seams and how you bit, it should be able to bid capacity and the like. I think the PJM rules are very firm, and we need firm transmission, a suite on control of units in MISO to qualify for PJM. So that’s where our efforts and investments are.

Okay, thanks so much.

Thanks.

The next question is from Julien Dumoulin-Smith from UBS.

Hi, just following up here.

Hi Julien.

Actually one of the other issues here relating to PRIDE. I’m kind of curious you talked about accelerating that. How of a benefit is accruing into ’15 and also kind of if you think about it, the 16 upside on kind of the PRIDE reloaded square to whatever we want to call it.

I think you can take it right from the slide that the incremental benefit of pride in 2015 built into the numbers is $45 million and one of the things that was always a concern point that often spoken to with investors was around the they looking the capacity contract up in New York and that’s $70 million plus a year of lost revenues because of the above market contract and independence had. Well that $45 million of PRIDE goes a long way to filling that hole and then you add in what you are getting from the New York capacity market and alike, you pretty much have fill that hole that was created by loosing that above market contracts. So we’ve got that $45 million built into it. We haven’t yet set any targets for 2016, for a new consolidated fleet PRIDE. I think the next number that we would update for you is the synergies around Duke and ECP, which the last public disclosure around that was $40 million of synergies and I would say when we do update it, which will be post closing, but you can expect that number I would say to at least double from where it is today.

Great, that’s a good data point there. And then lastly if we can go back to it just to be very clear about it. It seems if by committing to a fixed price from the scrubber, it’s a firm commitment at this point. Do you intend to move forward with the new scrubber, is that kind of good way to view it? [Cross Talk] but…

I mean I would say two comments on that Julien that. First, to comply with the multi-pollutant standard in Illinois, we have to move forward. If for some reason something change, the contact does have the ability to terminate it, but our requirements, our plans, our intentions, the reason we converted this contract to what it is to get surety of cost. So as we start planning the liquidity, needs for IPH this gives us a much clear view around the spend around the Scrubber. And again, the majority of that spend is happening in ’18 and ’19 and when we – the question came up earlier around IPH. Our liquidity forecast day for IPH is better than what it was when we originally made the acquisition. We clearly get into it through ’17, the questions going to be around the $300 million or debt that’s maturing at that point in time and the ability to refinance it. But assuming you can refinance that debt, we have the liquidity that we need to make the investment and the scrubber comply with the multi-pollutant standard and with the strengthening MISO market in ’16, ’17, ’18 we feel that we should be successful from being able to refinance and we’ve got some ideas along those lines as well, which as we get close to the data we’ll share more info on.

Great, thanks again.

Okay. Julie, I think we have time for one more question.

The last question comes from Jason Mandel from RBC Capital Markets.

Great, thanks for taking one more question; I appreciate it guys. Just actually two quick ones. One is just a follow-up on the IPH question from earlier with the fee cash flow number expect for ’15. The way its guided, I understand is for basically neutral, but again before the G&A allocation. So in reality we expect $30 million to $40 million negative for ’15. Am I thinking about that right?

I think that’s right. Yes, we are guiding to basically breakeven free cash flow and so after G&A allocations I think you are in the right zip code.

Okay, perfect, and then just a bigger picture questions. I didn’t hear it asked. Understanding you still have two material acquisitions to close in the near term, thoughts on M&A going forward. There are certainly number of assets still available, still on the block. So just any thoughts you might have in terms of markets or interests.

No, right now Jason all of our focus is around the existing acquisitions, closing them, integrating synergies and the like. I wouldn’t say we are very active looking at anything at the moment.

Okay very good. Thanks very much.

Thanks Jason.

Julie, that will wrap it up for us. I’d like to thank everyone for calling in.