Replies to This Discussion

Permalink Reply by Les Bamburg on July 18, 2008 at 17:41

For wells currently being drilled in the "core" area, 90+% should reach pay-out. Outside of the "core" I do not have any specific % but have just seen some of the initial flow rates. Part of this is some of the smaller companies without experience trying to generate production in the "iffy" areas of the Barnett Shale. This is the reason the larger more experienced companies (Devon, XTO, Chesapeake, EOG, etc) are staying focused on the core area even though that means paying higher lease bonuses in metro Ft Worth.

Permalink Reply by Snake Stewart on July 18, 2008 at 17:17

You lost me there Les B.

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Permalink Reply by Les Bamburg on July 18, 2008 at 17:32

SS, I was just commenting about your statement concerning no dry holes in the Barnett Shale. Some of the wells outside of the core area produce at such low gas rates, the operator will never recoup his cost. The last statement related to some of the geological complications in the southern and western parts of the Barnett Shale.

Permalink Reply by Snake Stewart on July 18, 2008 at 17:48

You are correct Les B. The bragging CEO's didn't cover poorly producing wells as I am sure not all will be better then the last.

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Permalink Reply by Les Bamburg on July 18, 2008 at 11:26

SS, wells will never drop to that level. Plus remember there are surface facilities required also. For 640 acres the capital cost would probably be about $50 million for eight wells. This means capital cost of ~ $78,000 per acre.

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Permalink Reply by insomniacnla on July 18, 2008 at 12:08

I read a June, 2008 projection cost for a Haynesville horizontal well, I think in the Holly Field, and it was $8.5 million dollars. The price to drill a well is not the end of what it costs. This particular company estimated drilling costs to be $6.5 or $7 million and then the rest was for completion, pipeline, etc. This estimate was given to the investors as to show what they were going to spend to get a well.

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Permalink Reply by Snake Stewart on July 18, 2008 at 17:27

Numbers per CHPK CEO are generally higher than expected cost and future wells will be less expensive due to less testing costs and infrastructure will be in place for future wells.

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Permalink Reply by Snake Stewart on July 18, 2008 at 17:24

All the numbers I used come from CEO's and their phone conferences.Sorry if I skewed the data . Since the numbers I used were for one well , that would equal $9750 per acre on your paper.My jacked up way of figuring came to $9375.We ain't that far apart. I haven't seen 8 well sections yet. Not to say they aren't on the way. I will work on a new source tho. I don't trust them guy's either Les B.

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Permalink Reply by Kevin McCarthy on July 18, 2008 at 17:26

Because you can't get 100% royalties unless you pay for the drilling yourself on your own property. Duh!

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Permalink Reply by Skidmark on July 18, 2008 at 17:48

I think it comes down to relative values. If drilling is about to commence in a unit, which of the following would command a greater sales price in a clearinghouse auction: a leased acre with a 25% royalty, or an unleased acre with a 100% working interest? It seems to me that the 100% working interest would.

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Permalink Reply by Les Bamburg on July 18, 2008 at 18:21

Skidmark, you have to include the bonus in your hypothetical case for an apples to apples comparison.

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Permalink Reply by Skidmark on July 18, 2008 at 18:29

Agreed. And if there were never any production, one would be much better off with a leased acre. However, in my hypothetical, I think the value of the 100% working interest would exceed the value of the 25% royalty by much more than the bonus amount.

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