The company believes it has an accumulation there. It has about 130,000 acres plus or minus there, and an accumulation between 40 million and 70 million net acres. The reason that EOG has been developing this relatively slowly with one rig up until recently is, that it has waited until it had shot a 3D seismic survey over the area and got the 3D seismic interpreted. The company has now ramped up the activity to 3 rigs, but the size of this resource of 40 million to 70 million barrels warrants at least 3 rigs drilling in this area. EOG expects to have 3 rigs and possibly more than that running throughout the rest of the year in this play.

What are those wells costing you to drill?

The company will get 10 wells per rig per year and with the one rig that it had operating in there, it has gotten its costs down to about $4.25 million per well, that is complete well cost. It is going to take some time to get these other two rigs up to that level of efficiency. The company is estimating about half a million barrels per well reserves and that comes out to be about a 60% return, after-tax rate of return, using oil prices of about 55 bucks a barrel for a long-term forecast.

What are you doing in the Cotton Valley play or some of the Cotton Valley the extension play over there?

The company has got a reasonable acreage position, not a huge one, and all of EOG’s wells over there so far have been vertical ones, standard. Before year-end the company will try a horizontal well over there.

You noted some geographic variation With Johnson County wells. Are there lithologic, digenetic differences causing the recoveries to be different?

It is more a matter of gross thickness, which is well correlating with net thickness. The digenetic factors, the lithologic factors are well clotted, but they are evenly distributed through Johnson County, so the overall thickness is what is controlling that. The primary factor is the completions. The company is seeing better rates not just in its monster wells but across the board with these new completions.

Is the greater recovery of reserves changing your IP declines rates at all?

No, it is not changing the shape of those curves. It is changing what the initial production rate would be. There are still sharp declines in the first two or three years and they still end up after the first four, five years at a flat long-term decline, so it is what kind of initial production rates the company is getting out of the wells.

You are having good results in terms of efficiencies with your fit-for-purpose rigs. Do you ever see a time where all you will be using are these specially-designed rigs when you are dealing with these infill plays?

Yes, especially on these shales where the company is looking at measured depth which is somewhere around the 12,000 feet. There will be a big sea change. EOG is going to have almost 100% usage of these fit-for-purpose rigs. It has seen differences in time to drill these wells, with these fit-for-purpose rigs. The company is making a lot of progress with the use of the rigs, as well as just the technology in directional drilling today. It was pleased with one of the recent wells that it drilled in the western Johnson County area, where it was finally able to pick up a motor and drill out from under surface to TD in one trip.

Are you seeing any services costs reprieve in the Barnett?

In the Barnett, the company has not seen much. Overall throughout the US the company has seen a 5% reduction but it has not been of real magnitude at this point.

Last quarter most of your PUDs in the Barnett were in Johnson County. Could the DD&A rate drop as a result of booking more PUDs there?

The Barnett DD&A rate will exert a leavening influence on the company’s total US DD&A rate, because the Barnett will be a lower DD&A rate than everything else the company is doing in the US. As the Barnett mix increases, it will leaven the DD&A rates. The company will be booking, because now it is drilling in the western counties more than it did last year. There will be more PUDs booked at year end this year in the western counties than they were last year.

Is it one PUD for each well drilled?

The official rule is two PUDs for one if there is an offset in either director from a horizontal well. Because of the way the company is patterning these developments and is drilling patterns of wells to keep from frac-ing already frac-ed rock, the actual number will turn out to be less than that in practice. EOG’s production growth in the Barnett is lumpy because what the company does is it drills about 5 or 6 horizontal wells, literally 500 feet apart in Johnson County, and has wider spacing in the western counties. It drills them all and then it does not produce any of them, and fracs them all in a batch and then turns them all on at the same time.

What is your takeaway capacity with the new pipelines to Hill?

The company is not hurt on takeaway capacity anywhere right now. It does not have a problem because it can put its rigs where it has pipeline takeaway capacity. In Hill County, the company will get its pipeline later in May and that is why right now it has placed two rigs in Hill. The company does not have any well reports to give on Hill County because it just placed those rigs. That will come in subsequent quarters as to what the company is doing in Hill. The same thing is in Palo Pinto County, that well connection or pipeline connection is going to come in the third quarter.

Were there any items in the quarter where you saw the benefit of using horizontal drilling in an area where you had not used it before?