I'm new to the forum and unfortunately couldn't get my post added to the previously enlightening discussion regarding new "allocation" wells in Texas.
I'm very fortunate to have mineral interest in the Woodbine Haliday field of Leon County. During the past several years, with the help of several dedicated Land Men, I've truly broadened my knowledge of drilling/production/payment of standard horizontal wells. However, "allocation" wells are something totally different to me an apparently a topic with little information available at present.
Given all factors - total acreage in pool/my participating acreage/my royalty/my mineral interest, I've always been able to check my decimal interest for accuracy, as requested by producers when returning division orders. It's been my experience that few producers actually provide enough information to check the decimal without extensive begging and pleading.
Now comes my current predicament. I've just received division orders for my first allocation well. As usual, I've been asked to double check the decimal for accuracy. Provided with the order was a participation calculation that shows a 19.238 % participation by the existing well holding my interest.
I had previously be informed that the owner decimal for an allocation well would remain the same as the decimal from the participating well of my interest. This isn't true and i'm now struggling to figure the math out! Would my new owner decimal for the allocation well be 19.238% of my decimal interest in the participating well?
I don't know the acreage in the new allocation, but know it includes tracts from two previously drilled wells that now form the new well.
Very sorry if there's something obvious that I've missed, but just unsure how to double check the new decimal, and as usual, my calls/emails go unanswered.
Thanks
Ben
Ben,
In situations where a field limits are eventually defined, usually by dry holes, and more than one operator in the field find it advantageous to unitize the field and divide production, and the producing formation is highly permeable, allocations can sometimes be different than % acreage in the unit. It has been common to allocate production on sand thickness or especially acre feet of producing sand as a fair substitute. This seems a fair method of allocation if the operators agree and also anticipate secondary recovery operations from the defined field or unit.
With horizontally drilled wells, some operators have suggested that allocations be made on lineal feet of completed wells rather than acreage in a hypothetical unit. Since the drillers are enhancing permeability with expensive fracing, this seems a fair proposition based n relative costs incurred. However, the geometry of the mineral ownership in the hypothetical unit and the length and location of the frac should be taken into account on an individual basis. I've not seen this type allocation outside of Texas but West Virginia and Penn. will likely follow.
The risk to the mineral owner in a lineal feet of fractured well allocation is the same old story. Will a few feet of well hold a whole lot of acreage forever or will offsets be required to hold acreage?
If you weren't told about the new allocation by your operator in advance, you should have been. It seems to me it should be a regulatory question that protects the correlative rights of all owners.
Gary,
Thank you for the information. As you suggested above, this particular allocation is based on lineal feet, rather than acreage. The two wells from which the allocation was formed are both less than two years old and are currently high performing wells. As to the holding of acreage, I guess time will tell. Luckily at the moment, all of my acreage is held by good production. I know it cant last forever but for now, steady.
The operator did not officially tell of the allocation in advance, but the well site is literally across the fence from our acreage. I was able to pull the applications from the Texas Railroad commission site and it explained the basics. Still not sure how to check the new owner decimal they've calculated for me, but I'll keep on it until I do.
Thanks again,
Ben
Gary L. Hutchinson said:
Ben,
In situations where a field limits are eventually defined, usually by dry holes, and more than one operator in the field find it advantageous to unitize the field and divide production, and the producing formation is highly permeable, allocations can sometimes be different than % acreage in the unit. It has been common to allocate production on sand thickness or especially acre feet of producing sand as a fair substitute. This seems a fair method of allocation if the operators agree and also anticipate secondary recovery operations from the defined field or unit.
With horizontally drilled wells, some operators have suggested that allocations be made on lineal feet of completed wells rather than acreage in a hypothetical unit. Since the drillers are enhancing permeability with expensive fracing, this seems a fair proposition based n relative costs incurred. However, the geometry of the mineral ownership in the hypothetical unit and the length and location of the frac should be taken into account on an individual basis. I've not seen this type allocation outside of Texas but West Virginia and Penn. will likely follow.
The risk to the mineral owner in a lineal feet of fractured well allocation is the same old story. Will a few feet of well hold a whole lot of acreage forever or will offsets be required to hold acreage?
If you weren't told about the new allocation by your operator in advance, you should have been. It seems to me it should be a regulatory question that protects the correlative rights of all owners.
Gary L Hutchinson
Minerals management
Ben,
Since you know how to deal with RRC, get a copy of the completion report or permit and it will tell you where they entered the producing zone and TD. That will be the distance in the formation. The length of your leg can be calculated and become the numerator. Apply your NRI ( undivided interest and royalty) to the dividend and you should be close to your payment decimal. If not ask the operator "Why Not??" Congrats on your success. "Friend me and I'll give you some ideas how to smooth out the revenue. Gary H
Ben Coleman said:
Gary,
Thank you for the information. As you suggested above, this particular allocation is based on lineal feet, rather than acreage. The two wells from which the allocation was formed are both less than two years old and are currently high performing wells. As to the holding of acreage, I guess time will tell. Luckily at the moment, all of my acreage is held by good production. I know it cant last forever but for now, steady.
The operator did not officially tell of the allocation in advance, but the well site is literally across the fence from our acreage. I was able to pull the applications from the Texas Railroad commission site and it explained the basics. Still not sure how to check the new owner decimal they've calculated for me, but I'll keep on it until I do.
Thanks again,
Ben
Gary L. Hutchinson said:
Ben,
In situations where a field limits are eventually defined, usually by dry holes, and more than one operator in the field find it advantageous to unitize the field and divide production, and the producing formation is highly permeable, allocations can sometimes be different than % acreage in the unit. It has been common to allocate production on sand thickness or especially acre feet of producing sand as a fair substitute. This seems a fair method of allocation if the operators agree and also anticipate secondary recovery operations from the defined field or unit.
With horizontally drilled wells, some operators have suggested that allocations be made on lineal feet of completed wells rather than acreage in a hypothetical unit. Since the drillers are enhancing permeability with expensive fracing, this seems a fair proposition based n relative costs incurred. However, the geometry of the mineral ownership in the hypothetical unit and the length and location of the frac should be taken into account on an individual basis. I've not seen this type allocation outside of Texas but West Virginia and Penn. will likely follow.
The risk to the mineral owner in a lineal feet of fractured well allocation is the same old story. Will a few feet of well hold a whole lot of acreage forever or will offsets be required to hold acreage?
If you weren't told about the new allocation by your operator in advance, you should have been. It seems to me it should be a regulatory question that protects the correlative rights of all owners.
Dear Ben
You should have been presented with a Production Sharing Agreement which is the mechanism for the allocation of costs over wells cutting across two or more different, already established units.
Many times the PSA will show first take point to terminus and the lineal amount of feet over each tract. If not, then a little digging will be necessary. The RRC should have a copy of that plat on file. Hard to find, but there. The formula is the essentially the same as a regular unit, just different words, accounting for feet rather than acreage.
For example Tract length/total length (first take point to terminus) x royalty = unit royalty share of production.
Buddy,
Thank you for the information and advise. Although I've heard of he PSA's never saw one. I'll do a bit more digging on the RRC site.
Thanks again,
Ben
Gary,
Thanks for the additional advise. Will Do.
Ben