Good day and welcome to the Chesapeake Energy Conference Call. Today's conference is being recorded. At this time, I'd like to turn the conference over to your host, Mr. Jeff Mobley. Please go ahead, sir.

Good morning and thank you for joining today's conference call. I would like to begin by introducing the other members of our management team who are with me on the call today Aubrey McClendon, our Chief Executive Officer; Marc Rowland, our Chief Financial Officer; Steve Dixon, our Chief Operating Officer; and Mark Lester, our EVP of Geoscience. Our prepared comments should last about 15 to 20 minutes this morning and then we will move to Q&A. Out of courtesy to other companies with conference calls this morning, we will try to wrap up the call by 11:30 Eastern Time. Now, I will turn the call over to Aubrey.

Thanks, Jeff. Aside from the large loss caused by a ceiling test write-down under the conservatism of full cost accounting, we delivered a very solid operational and financial performance during the very challenging quarter for our nation's economy. However, before we get into the details of Chesapeake's achievements for the quarter, I wanted to take a moment to address head-on some of the recent media coverage regarding my new employment agreement. As I think you know and can certainly tell from the details contained in Chesapeake's press releases over the years, Chesapeake prides itself on transparency and direct communication with our shareholders. For that reason, on January 7, 2009, the company filed with the SEC a very detailed 8-K that provided a thorough explanation of why the compensation committee and the board took the actions they did at the end of last year. And why they concluded that entering into a revised employment agreement was in the best interest of the company and its shareholders. On the same day, we filed the 8-K, I e-mailed a copy of the document to approximately 45 analysts, large shareholders and reporters, and asked that if anyone had any questions about the new employment agreement to call me, and I would be happy to discuss it with them. I received several phone calls and e-mails that expressed support for the new employment agreement. On the other hand, I did not receive back a single complaint, nor I recall any reporter or analyst publishing a negative follow-up comment about the employment agreement immediately after the filing of the 8-K. So it is a bit surprising to me that after the issue, that the issue has become such a hot topic four months after we initially disclosed it. I do sincerely apologize to all shareholders for…

Thanks Aubrey and Good morning, everyone. Thought of appropriate place for me to begin, this morning, is to discuss cost trends, we are seeing in our operations. Clearly, service costs are rapidly decreasing but have not yet reached a level reflective of today's $3.50 gas market. We honestly doubt they will be able to decline that far and the good news is since they can't, we won't have $3.50 gas for a long time. Now, for some examples of what we're seeing for what I consider to be equivalent wells in each one of the shale plays. Barnett well averaged $2.95 million in Q4 and Q1 '09. Today, that well is $2.6 million for a 13% reduction. Likewise, in the Fayetteville, during a similar time we averaged $3.5 million, today, $3 million, for a 14% reduction. In the Haynesville and in the Marcellus, where we have had a lot of science and experimentation in these new plays, the Haynesville wells were actually up to nearly $9 million of cost and in late 2008. Today, we're spend being $7 million for a 27% reduction and in the Marcellus, again, with a lot of science and new play experimentation, we got up to $5.8 million in late 2008, today four million for a 31% reduction. Every well we begin now has lower bids in most every category than the previous well. It will take time for our larger service partners to ring out extra costs from their supply change but this will continue to happen over the next six months to nine months in our opinion. For example, spot prices for steel, in April, are down 25 to 30% in just one month. We continue to ring out our own costs and capital expenditure levels are falling fast. Although, with nearly 160…

(Operator Instructions) We will take our first question. It comes from Michael Hall with Stifel Nicolaus. Please go ahead, sir.

Just quickly on cost reductions, you mentioned you don't think costs can come in enough to kind of correct for the price decline. What are the stickiest parts of the cost equation in your view and maybe how much can cost declines kind of reset the break-even price the industry needs?

Sure. Well, my comments were directed, of course, to a price environment in the third and fourth quarters of '08, that built up to reflect a 1600 plus drilling count on gas side and over 200 on total rigs, when we were seeing prices in July that were in excess of $13 on NYMEX. Now with 350, that percentage reduction, of course, is much greater than the 35% to 45% or 50% that we're seeing across the service sector. There is a lot of equipment out there but a lot of it is being laid down and coal stack particularly on drilling and on the fracture stimulation equipment side of things. Some equipment being stacked, though, doesn't reduce necessarily the operating cost of the rest of the equipment. And until layoffs are seen and salary cost reductions actually of course diesel costs for all of our field operations including those of our service providers are down by about 50%, but it is just unlikely it is going to continue to go down further. So putting it in the context of seeing prices decline 75% or 80% and seeing the ability probably for the service guys to get their costs down 50% or transferred into pricing down 50%, you see the gap. That is why my comment about $3.50 gas prices on NYMEX today with field prices much lower than that. It just doesn't yet reflect in the service costs what has happened more dramatically in the revenue side. Now, we're going to continue to push our costs down, I mentioned steel prices coming down. There are some beliefs around our shop that steel prices will continue to come down some. But obviously there is a limit, with iron ore costs and transportation costs to get the steel out in the field as to what that can be.

And then, I am thinking about supply side of things, just industry-wide and in particular the backlog of completions and/or just kind of a backlog or of activity that is out there. Can you talk about Aubrey maybe how quickly you think that sort of backlog completion can come back on to kind of hamper declines of supply?

Michael, I'm not sure it is really knowable what is out there in terms of backlog wells. For example, ourselves we have let's call it 300 wells that haven't been completed, but 200 of those are waiting on pipelines and only 100 are really been kind of voluntarily curtailed. So, we don't think it's nearly as big an issue as maybe I have read about, but more importantly we just think that by the end of the first quarter of 2010, gas production will be down 10% in North America and so whether or not it happens by the end of the fourth quarter, we don't spend a lot of time thinking about that. We just believe that by the summertime the EIA-914 data will clearly show a trend that cannot be interrupted and once it starts to dig in, we will kind of accelerate on itself and I think will bring us back to some more reasonable pricing probably more quickly than most people think.

We will take our next question from Shannon Nome with Deutsche Bank.

Marc, on the 2010 hedge position, you mentioned '09, but it looks like '10 moved considerably lower and you still have got a slug of knockouts. What is your rationale or strategy there?

We took off some of the 2010 back-half of the prices or back-half of the positions Shannon when the prices fell here just the last couple of weeks. Our belief is consistent with what Aubrey mentioned. By the back-half of 2010, we could see remarkably higher prices than what we are shown on the curve today. We moved some of those positions forward, protecting our Q1, but you're right overall and for the year, it has moved done. My belief in working with these kick-outs over a long period of time is that there is an ideal time to sort of approach those, as it gets closer to the expiration date. We're a long way off, so the puts have a lot of value with respect to the way they are structured and that makes taking the position off and restructuring a lot harder. Most of the 2009 positions that we took off, for example, I did in the November-December period for the first two quarters of '08, I took them off in December and November of '08 just to be clear and then worked our way from the back-half of '09 out in the first quarter of 2009. So my view is that we will by the second half of 2010 be able to put on prices a lot higher and we will continue to work those into either collars or swaps that are on there. And so I wouldn’t be at this point in May of 2009 we have got many, many months before the first one comes about. And I think you will just see us act consistently with what we did in 2009.

Okay. Thank you. And then just a follow-up, on the Barnett shale joint venture. I know it is a smaller piece of business in relative to your last three JVs but just curious what types of industry participation you're seeing in these discussions. A lot of your peers have designs on either selling assets or doing joint ventures akin to what you all have done. And I am wondering, is there any interest from non-industry investors in these types of assets or is it really just mostly just the usual suspects that we have seen do these before?.

Thanks Shannon. There is some financial interest. And what we have tried to do is target a part of our Barnett shale assets. And we think our total base is worth about $10 billion. And so we have sold that or peeled out about a $1 billion subset in a discrete geographical area that is reasonably kind of rural. So there are not too many concerns about some of the operational hassles, of being closer in to town. And we think the structure of that might appeal to some financial folks. The most obvious candidates would be companies that are seeking to get their feet wet in shale and I think we have previously discussed that those would likely be international energy companies. And I think there is a lot of appeal to working with Chesapeake, our track record of working with other companies, size of our asset base and I think our technological lead is something that bigger companies than us based overseas find attractive. And so, these talks, they move slowly. And just as ours did in 2008 but we do feel like it makes some sense for us to try to do one of these and establish another JV partnership with another company. So, it won't be in the second quarter but more likely in the third or fourth quarter before we get anything done there.

And we will take our next question from Brian Singer with Goldman Sachs.

Thank you, Good morning.

Hi, Brian.

You now have some of your Haynesville wells that have reached or near their one-year anniversary and I was wondering if you could provide some color on what decline rates you have seen and whether and when you are seeing production leveling off.

Yeah, Brian we have a pro forma decline curve, that I will let Steve Dixon go through with you I think the first year decline rate, its close to 80%. But I will let him answer this.

Yes. Its over 80, about 86. And Brian I really haven't looked at, or have numbers here with me on particular wells. We only have I think, two wells that are over a year old and those would have been our very early wells with not very many stages and not long laterals. Really don't have a well set yet to a have full-year's decline -- as everyone knows the Haynesville now is a very steep first year, and how that will break, is still a little early yet.

Steve, you want to go through…

Do you have second and third-year declines for the Haynesville compared to say, the Barnett?

Well, our pro forma now is 29.5 in the second year, and 20.5 in the third year for the Haynesville but again, there is just pro forma, we don't have that knowledge today.

Okay.

Compared to Barnett --

Thanks.

But we are going to try to give you a comparison to the Barnett but go ahead with your question and we will look that up.

I guess can you talk in a little more color on the quarterly trajectory of capital expenditures, just given that a material decrease versus first quarter is being fuelled for he remainder of the year. You did highlight wells that are being drilled for you with your carries. I guess what is the risk? Or what would have to happen between drilling midstream, leasehold acquisitions you would up spending either higher than your guidance or lower than your guidance?

Well, I think, the quick answer on that is that our guidance is what we believe is going to happen. I tried to highlight the very strong move down, in the trajectory, of both rig count and of course resulting expenditures noting the lag. When we move a rig count at 158 in August I guess, started that trajectory down throughout the last half of the third quarter and the fourth quarter down to 119 in the beginning of January and now, are down to 96. These wells take anywhere from 15 to 75 days to drill depending on where we are and then the completion expenditures start typically when we do a service in the field. The invoice doesn't come to us until 30 days to 45 days later. By the time it goes through our system it is another 30 to 45 days and so what we're seeing from the beginning of a rig, being laid down, to the actual money changing hands and the invoice hitting our books, so to speak, is at least 90 days and in some cases 120 days. So the wave of drilling that we built up in the third and fourth quarters, sort of started peaking out from a cost standpoint in December and January. In fact, I think January was our high month. So in looking forward, I don’t expect there to be anything from a drilling rig count standpoint other than the possibility if prices were to stay low, we would reevaluate whether our estimate of the number of rigs we need to run needs to be further lowered. It is hard to imagine a drilling scenario, where we would ramp up in this year, given where we think prices are going to remain for the remainder of the year. Our carries are solid with people that are paying, and as I noted also we're just beginning really to see the advantage of the Marcellus joint venture, I think, Steve, we have actually just build them one time I think have we not? Maybe we have got a second bill out to them but it is a very low activity rate.

It just started here.

So I hope that answers your question, Brian. I really think we are going to be pretty close on to what we're doing. And the acreage area, which has always been a question of expenditures, I noted how far down we have come. Our current budget for the remainder on a run-rate basis is $250 million on the carries. So very -- what we might have spent last year in one month we are going to spend in the next 12 months.

Than you. And If I could ask one last numbers question, were all of the realized gains or losses related to I guess they would be gains, related to the 2010 hedge restructuring booked in the first quarter, are there any one-time gains or losses, cash gains or losses that were fixed back in the second quarter with regards to 2010 hedge restructuring?.

Brian the way those work is that none of those gains flowed through either the first quarter or the second quarter. If a restructuring is done for 2010, the cash is either still a receivable, from our counterparty or perhaps some of it is paid to us, but the accounting gain for whatever happened in that remains a deferred gain, and will only be recognized in the month of production, that the original hedge, was booked against.

Thank you.

So, the $519 million of hedging gains, are all related to January, February, March of 2009 only.

We will take our next question from David Heikkinen with Tudor, Pickering and Holt &Co. David Heikkinen - Tudor, Pickering, Holt &Co: One quick question on 2010 hedging. Can you give us a rough idea for quarterly splits for percentage hedged?

I will look that up David. I don't have it right in here front of me. But let me see if I can dig that up.

We might have to get back with you David. Do you have any question? David Heikkinen - Tudor, Pickering, Holt &Co: I thinking about your joint ventures and having to deal with BP and Statoil. Can you talk at all about having the impact of having on account of Statoil employees in your operations kind of impact on operations and then kind of the BP counterpoint to that of, are they just still writing checks or how active are they in the Fayetteville?

Yeah all of our partners are very engaged. Statoil is the only company that we have 600 employees working here. Steve, we have a dozen or 10 or what are the..?

No, we have six and they really are just started' we only have three of them in place. I think. So --

Okay. First of all, it is not the easiest thing to get somebody into the USA these days unfortunately. I thought we were ramping up to around 10.

That is in year or two.

I will get to you in a second. So what will be the peak.

I think 12, I think it is up from six..

Okay. So six this year, twelve next year. BP is engaged, very much with us. We have monthly to other periodic meetings with their teams. [Sam McLean], I think we meet every month with Mclean and it is a very cooperative relationship and those guys have a lot of input and…And so, we're thrilled to have partners that are obviously financially stable and capable, but also are willing to get engaged technologically and offer their opinions as well. And so I am extremely proud of the quality of our partners and they are far from just check writers, they are active and engaged and non-operators with us in the whole process. David Heikkinen - Tudor, Pickering, Holt &Co: So, no operational inefficiencies or any impairments as far as how you would like to run things versus how any of your partners would?

No. I mean I think we are all on the same page and we have certainly discussions about what is the optimum level of rigs certainly when they are paying a disproportionate share. But, for example, in our BP deal, it is contractually written how many rigs we have to run and Statoil and PXP. We have requirements to spend a certain amount of money, either in total over a period of time or per year. So, those things were all pretty heavily negotiated during the negotiation of the contracts themselves. David Heikkinen - Tudor, Pickering, Holt &Co: And any indication from any of the parties as far as desire to continue leasing kind of updates on status of leasing arrangements with Statoil, BP and Plains?

Yes. I think it's a little bit of a mixed bag. I think it is well known that each of our deal does contain a promote, and so I think for competitive reasons and fairness to them, I will let you do a little work to see who wants to buy more acreage and who doesn't. Those that have decided not to, I think are doing so, only because the level of promote they might consider too high. But others see the value in that. So it's a mixed bag at this point. But we are, in all three areas, continuing to buy new leases, regardless of whether our partners are choosing to participate in those purchases, we are buying acreage at values that we think are extremely valuable and are happy to own the additional acreage 100% if our partners don't want it. David Heikkinen - Tudor, Pickering, Holt &Co: And the status of any of the equity leasing, any additional thoughts about the amount of shares that could be issued, status there?

Yes. We have still got a couple things out there that might be settled in that way. I think in the first quarter around $250 million of our leasehold was in settlement of kind of troubled transactions from 2008, sort of ability to use stock was kind of a way to share some upside with some of those guys and, in return, we were able to reduce the purchase price. So there are still some situations out there that we're working on, a couple are in litigation and those will just resolve themselves out over time. David Heikkinen - Tudor, Pickering, Holt &Co: So, out of your cash for leasing and acquisition or your expected capital for the year, should we think about similar split of the total amount kind of 50:50 for 2009 and 2010 goes out with equity and the rest is cash?

Nothing in 2010 would be equity, and there is only a couple of possibilities for 2009 from here for equity. So pretty much from here on with the exception of a couple things, it will be cash only. David Heikkinen - Tudor, Pickering, Holt &Co: And then your rig count ramping in the Marcellus and Haynesville, Marc's comments about not ramping rig count overall. Where do you end up producing rig count in 2009 or do you see an exit rate that is higher than your current 96 rate?

I will let Steve address this, but basically what we continue to do is peel rigs out of kind of conventional areas and areas that are held by production and put new rig to work in the Haynesville and Marcellus.

Yes. As I said, we're taking it out of the Mid-Continent, Permian, south Texas, and adding into those areas though we do think we will be up just over 100 by the end of the year.

100 total rigs, right.

Yes.

Of which, how many will be in the big four, something like 80 something?

92.

Okay. By the end of the year, we will have close to 90% of our activity in those four shale plays where as, David, when we were at 158 rigs, I believe we had about 50 big four shale wells. So, we will have reduced our conventional drilling by about 90% in the course of one year. And I think that is huge testament about really two things. One, the attractiveness of the shale's and the attractiveness of most everything else and why we remain more convinced then ever of production declines to come that will more than balance the gas market in the next 12 months. David Heikkinen - Tudor, Pickering, Holt &Co: Okay. Thanks for all the answers.

And David, it appears that about 32%, 33% of our volumes for the entire year are located in Q1. And then, similar slightly less amount in Q2. So, I am going to estimate that 60% to 65% of the entire volumes hedged, as we have listed, are located in Q1 and Q2 with you with the balance of roughly a third or 35% distributed into Q3 and Q4.

2010.

This is 2010 volumes.

We will move next to Tom Gardner with Simmons & Company. Tom Gardner - Simmons & Company: Aubrey, I wanted to get your thoughts on, I guess the assumptions embedded in your gas macro outlook with respect to gas demand and L&G imports and perhaps if you could speak to it in terms of 2008 demand in L&G I can understand it?

We don't have any special information on gas demand. We read the same stuff that most everybody else reads. Some of it written by guys like you. So I am always nervous when you all admit you don't know where gas demand is going to go. But I will say that it appears to us that the economy is probably in a process of bottoming and we find that encouraging. But we just account for that lack of knowledge by saying, we know that these declines will set in and we know this market will be balanced within the next nine months or so by the end of the first quarter of 2010. If the economy picks up, our intuition would tell us that we will see signs by the end of this year, but to be safe and conservative, we're satisfied to say 2009 will be bad and 2010 will be a lot better, given that the gas market always surprises us. It would seem to me that the surprises are likely to be that gas prices would move more quickly in 2009 once you get past the summer of 2009 and past L&G imports. We know that you can't fill up storage more than actions, so whether or not it fills up on October 1st or November 1st, it is kind of irrelevant. You can't put more in there than around 4 Tcf. So at that point then it's just a matter of how unbalanced the market will be in 2010 and we think there will be a very powerful self-correcting mechanism underway in 2010. So we just kind of stay focused on '09 being bad and '10 and '11 probably being quite a bit better if you had to make us put it bet down, it would be that it heals more quickly rather than more slowly. Tom Gardner - Simmons & Company: I appreciate your comments on the drilled uncompleted wells. I am trying to understand the delay from rig move off to when a well is placed on sales. Can you give me an estimate of what the average figure for Chesapeake might be?

I will let Steve talk about that because it will also involve a comment about multi-wells on single pads as well as big components shift.

Tom, probably average first sales from rig release is close to 60 days and so then you put the accounting and dollars paid, delay that another 30 or 60 days, so the dollars don't quit coming in until 120 days after rig release on average. So that is that part of that roll-off from our higher rig counts. Tom Gardner - Simmons & Company: One last question sort of an accounting question, if you will. Just trying to understand this capitalized interest expense, specifically the fluctuations from quarter-to-quarter. Can you walk us through why the big increase relative to total interest expense?

Sure. I can illuminate the way we're required to account for that. This is a function of our average interest rate costs applied against the unevaluated leasehold that has not been evaluated and put in our full cost pool. Under full cost accounting any increases to that require us and result in an increase in the amount of capitalized interest and likewise, going forward, with less acreage being acquired to begin with, more of it being paid by our partners and third, more of it being evaluated as a percentage. I think we have moved a couple of billion dollars of unevaluated leasehold, this quarter, for example, into the full cost pool, resulting in less on evaluated acreage, in dollars at the end of the quarter. So going forward, actually, it will kind of reverse from what has been the trend the last couple years. He will have less capitalized interest and more GAAP income statement interest, which is why we projected a increase in interest cost in our outlook, for GAAP purposes on the income statement going forward. Tom Gardner - Simmons & Company: Thank you. That was very well done.

He's our chief financial officer, what about that? Tom Gardner - Simmons & Company: That's all, guys. Thank you.

And we will go next to Biju Perincheril with Jeffries and Co.

Hi, Good morning. Couple of quick questions. Aubrey I think on the last call you mentioned you were close to having leaseholds on your east Texas Haynesville well. Anything more you can say on that today or generally what you're seeing in east Texas?

Yeah, actually we have completed two wells there, Biju that are waiting on pipeline and they had very successful tests. We have not been willing yet divulge what those results are but we're pleased with them and are building pipelines to them and I think we're probably another 60 days away. Though, most of the gathering infrastructure and these are in [Pinellas] or Harrison. These are in Harrison. Most of the local gathering infrastructure is set up for wet gas and course gas so we have to lay our own pipelines in there. The third well we drilled is a well called the [Harvey], down in Shelby county. And that well is I think just about finished up drilling, and it is in a new area as well. So we will probably keep results there pretty tight as well. I will say that, I will stand by what we have said in the past, which is that we do view that kind of a center of the universe is a area in DeSoto Parish and part of Red River Parish, and parts of Southern Cato, and as you get further out from that area, you know you're not going to see the 20 million a day type completions. So we have never thought that Texas and say Harrison and [Pinellas] counties would be as good as say, across the river into Louisiana. So they are successful wells. They will be successful wells but they are not 20 million a day type wells for us.

Fair enough. Would you say the results that has been coming out of east Texas, that the results have been published, those are representative or, are there other operators still coming up a learning curve.

There have been a lot of companies report troubles with drilling these wells and completing them. It is just a reminder that if do not spent a lot of time drilling horizontal shale wells it is not the easiest thing to get a hang of. So we have not had any trouble given our expertise in the area. I can't really tell you that what you have seen to date means too much. I would say that there are a lot companies struggling to come up the learning curve and when they will get there it will just take some time. In the meantime we will be running 30 to 35 rigs, completing a new well every two days, in the Haynesville and we will have a pretty significant head-start.

Okay. And then one question retting to your joint ventures. Is there sort of any provisions there, meaning you talked about the benefits of service calls coming down but is there any provisions that is tied to activities or somehow indexed to service costs the drill carries amount?

No, that is one of the great benefits of course to us is that those dollars were to provide that during the time of peak asset value. Yet they are going to be spent during a time of low cost. And so, as Marc mentioned in his field, we think that $4.5 billion of carry, will end up acting like about $6 billion of carry, which, in fact, is our entire drilling CapEx budget for '09 and '10. So wouldn't be surprised at the end of the day, for those carries to end up creating for us as much as 4 TCF of free gas, which [funded] by itself to be a top 10 company in the US in terms of proved gas reserves, I think. So it is a very, very powerful asset. Frustrating that we can't put it on a balance sheet and showcase it, but it will certainly come in over the next couple of years and I think we will end up leading the industry in funding costs and maybe right up there in terms of growth rate as well.

That's all I had, thank you.

We will go next to Ellen Hannan with Weeden And Co.

One follow-up on the Barnett shale with your 20 rigs you said that you are running there. What is your outlook for production out of the Barnett by the end of this year?

Steve you want to handle that.

Yes. Pretty much flat to where we are at, we are close to a Bcf gross, 660 net. And we really don't grow production at or at least in the short term, 20 rigs rolling off of a 40.

I think the gross returns in like 13, 14, 15, something like that once you get the base.

Right. Once we get through that the hump, kind of hump of 40 rigs.

So you come down in a little bit of a dip Ellen and start to build in the mid teens.

So, we should look for something slightly below the 660, kind of by the end of the year?

No, I think we just said it was going to be flat.

It would be pretty much flat.

Okay. The other question, in terms of the drilling that you plan in 2010, vs. '09 in the Fayetteville, the decrease, is that because you're being carried?

Oh, we have been discussing that with our partner and we are at 20 rigs today. But they have expressed a preference in 2010 to run fewer rigs. And so I think we have budgeted 16 for 2010. Really and we would be happen to run 20 but in deference to BP we said we would run 16.

Great, that’s it from. Thank you very much.

And we will go next to David Tameron with Wachovia

Hi good morning. Just following up on Ellen's question in the Fayetteville. It looked like your gross production kicked up for the year but your working interest moved significantly higher. Is that just a function of wells in the JV or can you talk about that?

David were you picking our the working interest preference to Fayetteville?

Well I was just looking at gross versus net?

I think it is because net is higher because of Seeco’s activities there really kicked it up. So our net production is up.

It is not related to working interest. It is related to how much gas is coming from our non-operated wells mainly by Seeco, which gets added to our net production.

Okay.

Our gross operated wells and so, you get that…

Okay so its the non-OP.

We continue to kind of average probably oh, with BP at 25%, my guess is our working interest averages between 50 and 60%.

Right at 60.

Right at 60% in the Fayetteville.

Okay, thanks. And then Aubrey I think last year you had mentioned some horizontal West wash wells and then obviously West Virginia has come out, new field drilled some. Can you talk about if this was the same play you were drilling I think you mentioned these last summer. I could be off on the timing, but could you talk about what you guys have done as far as horizontal granite wash?

I am going to let Mark Lester take that. It is a little bit of a frustrating situation in that sense that these granite wash plays actually for us can compete with the shale but they really don't get the attention that the shale do. We discover for example, a field called Colony Wash in [Washton] Custer County, Oklahoma about three years ago. I think we have drilled more than 50 wells there. Mark will probably have some numbers for you in a minute. But this is actually our highest rate of return area in the entire company. We have started to drill holes only in the Texas Panhandle and in other places in the Anadarko basin for these wash plays. So we think all in all it has got more than two TCF of net exposure to us but it just unfortunately doesn't get as much play as shale play. So I will let Mark Lester who is our Executive VP of Geoscience take it over from here.

Yeah, David. The Colony Wash has been an outstanding play for us. Unfortunately, it doesn't cover the geographic extent of some of our more higher profile plays like the Haynesville and Marcellus but outstanding play nevertheless. We currently have rich TD on 52 wells, have 47 wells producing at a combined rate of about 31 Bcf and 2,100 barrels of oil. From those 47 wells produced so far current daily rates about 47 million per day and 5,700 barrels of oil per day and we currently have I believe four to five rigs dedicated to that play. And just in addition to that, those statistics are last, more recent four wells in that play, have all IPed at rates between 15 to 20 cubit feet equivalent per day and there is a pretty large oil component to that. So the finding costs approach close to $1 per Mcf on those most recent four wells. So that has been an outstanding play and just an example of some of the other things we have been able to do here at Chesapeake, as we continue to test additional formations across our asset base.

How big is your position there?

Well, I think he's referring to Colony Wash.

There some 60,000 acres in Colony Wash and Jeff what else do we show for our other count?

About 285,000 acres in our other wash plays.

Not including colony.

Not including colony.

It does appear to be the clash of all the other granite washes.

And the 2 Tcf…?

We have been successful in drilling some of the other washes also, but Colony has been the star so far.

Okay. That 2 Tcf number is that referring to the 60,000, is that colony wash or is that what you referred to…?

That is gross for the whole Colony Wash area.

And then one more question. CapEx split over last three quarters of the total budget. Can you talk about what that looks like ramping down a little bit or how should we model?

Over the next three quarters, is it kind of linear or does it continue to peel off from the first quarter?

Yes, that is the question I'm asking.

Okay. For '09.

For '09, yes.

Well, the Q2 ramp down is going to start with drilling CapEx, as a point of reference for the March month was $337 million. I mentioned that we think that by the end of Q2, certainly by the beginning or so of Q3, that that will be approaching and go below 200. So generally we have been moving down between $50 million and $75 million to $100 million of expenditure per month in the last three months, and our projection would be to continue that trend slowing and then our rig count, Steve, I think is beginning to look up a little bit right now at the end of Q3, is that approximately right?

Right. So, we're projecting three and four to basically be flat at under 600.

Yes. I think Jeff just said that Q2 would be $650 million, drilling CapEx and then Q3 and Q4, both 575.

Moderator, I think we have time for one more question.

We will move to our last question. It comes from Rehan Rashid with FBR Capital Markets.

Just a structural question maybe and using Fayetteville as an example. If I use risk 39 reserves and then call it expected '09 production in the Fayetteville area, your RP ratio on that 3P basis is about 70 years. How do you think about this RP ratio, is there an optimal lower number that you would want to be gearing towards, maybe just some thoughts on this longer RP ratio?

I think we would like to have it all produced in one day and just get paid for it and would be done. But that's not the way the earth works. And so, when you look at our acreage inventory of 440,000 acres and you look at a well every 80 acres, you have room for about 5500 net wells there. And I don't know how many net wells we have drilled so far, but my guess is, not more than Jeff may have it exactly but probably not more than 1,000. And so, it is just matter of how much money do you have to apply to a play. And then, how much gas can a market take at any one time. So clearly, I think what happens over time Rehan is that the conventional plays in the US slowly dry up or get [bell bowed] aside by the shale plays and that this production continues to increase over time and that that RP comes down. Right now, the RP doesn't really -- the reserve side of it doesn't get bigger over time, except this technology improves and we have already disclosed and southwestern has as well that we're running 30% better than our 2.2 pro forma. So we're somewhere between 2.8 and 3 these days. So that number kind of stays out there, and then as your production grows obviously that RP shrinks over time and as you're able to afford more drilling and as the market can absorb more gas than you can accelerate. Jeff tells me that our net drilling so far in the Fayetteville has been 313 net wells.

Net PDP wells.

Net PDP wells out of a potential of about 5500. So, we have only drilled 6% of our potential wells in the Fayetteville today.

Just to echo that Aubrey, just adding to that we show about $25,000 acres drilled today that will be entire acreage position. And if you're really to think about a true RP ratio on just proved reserves and not trying to expand it to the whole universe of what might ultimately be drilled, we have just over 800 Bcf of proved reserves books. So I am not sure how much will produce this year Steve in just the Fayetteville on a net basis, but current is 200. I don't know what the year is projected.

That would give you a true indication of what really the RP that most people think about of production versus book proved reserves.

On the CapEx one really quickly the 575 for Q3, Q4 is that before reimbursements from the JV or net of it?

That is after, that is net of.

Okay, thank you.

Okay, thank you, and looks like that is the end. So, we appreciate it very much. If you have any follow-up questions for us, please give Jeff or Mark a holler. Thank you.