Replies to This Discussion

Permalink Reply by AT on October 15, 2011 at 11:50am

Steven, Good points also. Yes, we signed last Saturday with CHK. Waitin' for that bit to hit the ground now so those royalty checks start rollin' in then we can load up the truck and move to Beverly. Hills that is.

Permalink Reply by Utica Shale on October 15, 2011 at 11:53am

James,

  I have a question regarding the drilling of one Vertical well and one horizontal well now and then the driller comes back at a later date and drills a second vertical well and a second horizontal well in the OPPOSITE direction. Lets just say the original Drilling Unit was 320 acres to the NORTH and now the second well is another 320 Acres to the SOUTH.

  Questions ...

 

  Is the "well" now considered TWO seperate 320 Acre Drilling Units - each with its own producing horizontal well or did the original Drilling Unit "grow" from a 320 Acre Drilling Unit to a 640 Acre Drilling Unit with two producing horizontal wells?

 

  Why should any of the landowners from the original North Well now be entitled to royalties from the South Well IF none of their land actually overlays the South Well?

 

  If multiple wells are drilled on one pad will the production from each well be metered independently ?

 

 

 

 

 

 

 

 

 

Permalink Reply by Steven Gardner on October 15, 2011 at 12:36pm

Gregory, I've not seen a permit yet with a north south bore so I don't know. I do believe that each well is permited as a separate entity so you would think they would meter each one independently. As far as why should adjacent landowners be entitled to the other royalties in a unit is because of the pooled production clause in the lease.

Permalink Reply by AT on October 15, 2011 at 12:55pm

Gregory, I believe they will lay out the entire drilling unit prior to drilling the first well on that drilling pad. The drilling unit will include at that point all wells and acreage they intend on drilling from that drilling pad in the future, which in the case of your hypothetical, could be a 640 acre drilling unit, or maybe even 1280 acre drilling unit. I don't believe they can't change a drilling unit's size later on down the road as you fear. I believe they are required by the state to establish the total drilling unit size and the land boundaries of that drilling unit, and record with the state, before the first well is permitted by the state, regardless of how many acres the first well will drain.

Permalink Reply by Utica Shale on October 15, 2011 at 1:53pm

AT,

 I disagree that the Drilling Unit Size can/will include "future" wells. So far every FRAC Well in this area has been a very small Drilling Unit size. Basically,  the Drilling unit size is about 500' (+/-) all around the current Horizontal Well, only. So far, no FRAC well has a Drilling Unit size big enough to accomodate another Horizontal Well in the opposite direction. Not one.

 

 I think that when Chesapeake returns to drill the 2nd Vertical Well and 2nd Horizontal well that it will be treated by ODNR as a whole new well application with a new ODNR Well # and a completely seperate Drilling Unit Size and Dimensions based only on the second well.  And Royalties paid for the second well will be based soley on the 2nd well's location and only those landowner's specifically within that wells Drilling Unit area.

 

 The only thing in common between the second to eighth wells will be the re-use of the same concrete pad.  Therefore, the landowner who has the PAD on his property will be the only landowner guaranteed Royalties from wells #2 - #8. Surrounding landowners will get royalties from one or more wells from that one pad, if and only if, they have property within each well's unique Drilling Unit dimensions.

 

Permalink Reply by AT on October 15, 2011 at 2:31pm

Gregory, 

   So far, everything drilled has only been exploratory wells. There is a new well currently being drilled in Monroe county that is the first well laid out to accomodate future wells from the same pad. That particular drilling unit layout leaves room on each side of the first horizontal leg for parallel horizontal legs.

   Regarding your thoughts on if and how they do the second well, I hope you are right. That would accelerate our lifetime royalties once they unitize us into one of those smaller size single well drilling units. However, you need to remember, they need to tie up all of this land they have leased quickly before the primary term expires. 5 years will go fast. It takes a month to complete each well and they could not possibly keep a rig on each pad that length of time with the limited number of rigs they have and expect to and get all of this land they have leased tied up. I don't think anyone can assume anything based off the few exploratory wells they have drilled to date. They are still "fishing" and no where near ramping this play up to full production.

   Furthermore, the infrastructure for piping and processing is also not in place at this time. It will take years to get the required infrastructure in place to handle all of the production from just one well per pad, let alone multple wells per pad, on all of the leased acreage in eastern Ohio.

   Regarding your last paragraph, I think you're way off the mark. No 6 to 7 acre plot of land upon which a drilling pad is located is going to see royalties 2 to 8 times over surrounding lands.

Permalink Reply by Steven Gardner on October 15, 2011 at 3:13pm

I have been told that the permits will be amended and the Kimbolton well was permited as a 60 ac (min) vert at the beginning now its one horz bore with 129 ac showing 5 more proposed. If they were all going to stay small (160+/- ac) with each bore.. why the need for these 640 ac and larger units? Your acreage % in the unit will get smaller but production will increase with each bore.

The Monroe couty permit is the only one I've seen that shows a complete proposed unit (south) with room for 2 more horz bores.

I've not been able to firgure how they can draw from the area below the pad to where they enter the shale but this area is included in the unit..?

Also wondering about the 500' .. how do they know what one bore can drain ? will this change as they develop data?

BTW.. all speculation as I really do not know.. just watching it as it develops. Interesting discussion.

AT .. I hope they make Jed's hat in my size

Permalink Reply by AT on October 15, 2011 at 4:16pm

Steven,

   Hypothetically, let's use Guernsey Co., Ohio as an example. There are 522 square miles of land in Guernsey Co..

   In a 160 acre drilling unit senario, 160 acres is exactly 1/4 of a square mile which would mean 4 wells per square mile. Therefore, 522 square miles x 4 wells per square mile =  2,088 wells divided by 5 year primary terms = 418 wells per year divided by 52 weeks per year = 8 wells completed per week to get 522 square miles HBP prior to the expiration of the 5 year primary terms. Not going to come close to happening.

   In a 640 acre drilling unit senario, 640 acres is exactly 1 square mile which would mean 1 well would HBP 1 square mile. Therefore, 522 square miles x 1 well per square mile = 522 wells divided by 5 year primary terms = 104 wells per year divided by 52 weeks per year = 2 wells completed per week to get 522 square miles HBP prior to the expiration of the 5 year primary terms. More realistic but probably still improbable.

   Many early leases and even a lot today are being signed with 1280 acre pooling clauses.

    In a 1280 acre drilling unit senario, 1280 acres is exactly 2 square miles which would mean 1 well would HBP 2 square miles. Therefore, 522 square miles x 1 well per every 2 square miles = 261 wells divided by 5 year primary terms = 52 wells per year divided by 52 weeks per year = 1 well completed per week to get 522 square miles HBP prior to the expiration of the 5 year primary terms. Even under a 1280 acre drilling unit, it still seems to me to be a far stretch but is is do-able!

   My point is, when this takes off, you will see none of these 160 + or - acre drilling units they are doing for exploratory purposes. They will be forming as many 1280 acre drilling units as they can and you can bet they will be going around to even those with 640 acre pooling clauses in their leases and asking the lessor for a modification to 1280 acres just like they did in PA. They will form a 640 or 1280 acre drilling unit, punch one hole to HBP all acres in the unit up, and move on to the next unit to punch a hole to HBP all acres in that unit up. They will keep doing this right down the line until they have all, or as much as they can, HBP. Only then will they revisit those prior drilling units to drill subsequent wells. They will have no choice if they wish to avoid paying renewal bonuses to extend leases or avoid losing the investment they made on the 5 year primary term. This could very well be a possibilty on the early leases that they paid out peanuts for signing bonuses. Those would be the ones most likely to extend the term or simply let expire.

   Lastly, I'm sure we could find one of Jed's hats in your size. We all should be wearing one, especially since the landmen and some of the outfits running around eastern Ohio think we are a bunch of unedumacated hilljacks!

   Please note: The above numbers assume the 522 square miles of land in Guernsey Co. was 100% leased on the same date which would create the absolute worse-case senario.

Permalink Reply by Steven Gardner on October 16, 2011 at 12:55am

AT.. I follow your math in the ideal world from a producer prospective. Another cog in the works for them would be the hodepodge of leases out there, its not going to be an easy task to HBP all they have and I'm sure some will have to be extended past the primary term.

I think we will see more permits like the one in Monroe Co and larger. The better leases I've seen restrict the acreage over 640 to the length of the bore and to being centered on the bore line... also they have to have it all under lease. The longest bore I've seen permited was abt 8000' not sure how far they can go. With the bad leases they can do anything they want. This is going to be quite a puzzle to design. I think they will be lucky to HBP half of it.

We are supposed to sign next week so I'm checking my hat size.. I would like mine in "Shale Black"

 

 

Permalink Reply by AT on October 16, 2011 at 2:29am

Steven,

    Since these O&G companies should know that it will be impossible to HBP 100% of what they have leased for various reasons, their intentions of buying up everything they can get their hands on could be to simply create "worth" and attractiveness to potential suitors such as flippers, investors, mergers, aquistions, JV partners, foreign partners, etc.. I can see it becoming a game of hot potato with some of these leases down the road. 

   Shale black is a beautiful thing!

Permalink Reply by James Kerns on October 15, 2011 at 7:51pm

AT, I suppose i should have prefaced the comment with "it could be one strategy to____". i would say that your scenario may be more likely, again but not without said company favoring one location over another for more stategic reasons as in to more accuratley define the perimeter of the formation or other specific geology features of interest or to avoid. Like the Jed Clampett photo by the way, hope we all get to have that experience LOL!

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