If you have questions about CRK wells in Harrison, Leon, and Robertson County wells let me know. I am the Division Order Analyst that set up most of the CRK wells in East TX. I am no longer with them and am here just to help with any questions you have. I have more than likely have talked to most of you or have set up your decks and payments. This is just to help answer questions.
thanks
Chris, great to have you here. I have a question, could you go through the math on how royalties for an allocation unit is calculated? Let’s say the unit is 1920 acres (3 x 640), the wellbore is allocated to unit a - 25%, unit b 40 % and unit c 35% and I have a 150 acres in unit a, 75 acres in unit b and 200 acres in unit c all leased at 1/5 royalty. Could you provide us with the formula and then apply the formula to the parameters set out for each unit?
I think I gave you everything but if not, just apply something typical and let us know what you had to add.
I ask this because 100 acres in one of these large allocations dilutes much more than the 640+/- gas units most mineral owners are accustomed to.
Thanks and welcome!
Phil
The main issue is whether or not your minerals are in formal units (as recorded DPU). Almost every operator allocates the percentage of production based on the number of feet of producing wellbore (distance from first to last take-point) within each separate unit or across the non-unit mineral tract. If there are 3 units formed by DPU, then there will not be a combined large unit. If there are 3 formal units - A, B & C - and 1/4 of productive wellbore crosses Unit A and 1/4 cross Unit B and 1/2 crosses Unit C, then the production will be allocated to each unit accordingly. Your DOI will be based on each separate unit DOI and allocated percentage of production. For simplicity, assume your DOI is 0.010 in Unit A; 0.020 in Unit B and 0.010 in Unit C. Then your well DOI will be (0.010 X 1/4) + (0.020 X 1/4) + (0.010 X 1/2) = 0.0125. If instead one mineral tract is crossed and there is no unit (no DPU), then your royalty decimal for that mineral tract will be calculated separately based on the number of feet of productive well bore crossing the mineral tract divided by the total length of productive lateral X your fractional mineral interest X your lease royalty rate. Are you currently in pay on three separate units and a new horizontal well is being drilled across the three units? If there are not three units, then the next question is your fractional interest in the mineral tract - i.e. in Tract A, do you own 150 new mineral acres or do you own 1/10 of 150 gross acres? Keep in mind that there is no real dilution because the longer lateral will have more production than a shorter lateral - so while you may be paid on a lower DOI, you will be paid on much higher volumes.
Phil,
To illustrate I will use the following: Hogue Well in Leon County.
IN the that “allocation well unit” There are 4 units. Each unit is a different size. Depending on the length of the pipe that runs through each unit that is calculated against the tract size and unit size. The total lineal feet of the entire pipeline is allocated to each gas unit. That Allocation Decimal is then applied to what your decimal NRI is. for example
To calculate you would take the Allocation Lateral (feet in the pipeline that goes through that unt) total all of those which would be 11115.9690 above and then divide that by unit feet and that will give you the percentage that is calculated against your decimal in the tract.
You can see in this “as drilled plat” the linear feet used to go through each unit highlighted in the red box
I have attached also a calculation spreadsheet where you just fill in the blanks in yellow of your royalty and your min interests % i.e 25% etc. and it will auto calculate for you.
If you tell me what allocated unit you are in and any other info I can do one for you so you have it for your records.
Hi Chris,
Not sure if it’s just me but I can’t see the images you attached. Would be very helpful to see as I try to follow your written example. And thank you for sharing.
Chis, Thanks for the post but I too cannot see the images or the file you attached.
Could you please re-post?
Regards,
Leon
Chris, where can I find allocations for specific wells? In particular, the Jenson. I’ve looked at the RRC unit plats filed with the permit and I’ve found the individual UDs with plats, but no allocation is mentioned that I can find. Where are the allocation percentages found? Thanks, Phil
Phil,
Are you referencing the Jensen Deep GU? There is a Jensen well and then there is the new Williams JWW 1 H well by Comstock. That has the Jensen Deep GU and the Willingham Deep GU and the Walker Deep GU. 3 units. The only have the well location down right now. It is not set to come online for a while I think. Typically the footage is not given for the pipe till sometimes 2 weeks before it goes to FS. Its the last doc they file. I can ask Travis if he has got the measurements on it yet. Feel free to reach out to me and I can show you the plats etc.
For an allocation well, the final percentages are based on the percentage of productive lateral crossing your tract based on the total productive lateral (length from first takepoint to last takepoint). This can only be measured after the well has been drilled and fraced. You have to look at the completion records. The completion W-1 or G-1 will only state the total productive lateral. The completion plat will break down the number of feet of productive lateral crossing over each tract. The permit plat shows the anticipated horizontal wellbore and that it meets all the RRC requirements.
A friend in one of the allocation units has asked me for assistance in understanding the allocation calculations. This party does not have a DO yet, but they have a nice sized interest in the Jensen Deep leg (the southerly lateral from the drill site) and they’re just trying to get some idea what this means for them. I’ve found allocation numbers on some Comstock plats but I guess that one has not been recorded yet. If there is some information that you can provide, it would be appreciated. Thanks, Phil
I have received the Allocation percentages if you would like them.
Jensen = 24.45%
Willingham = 22.15 %
Walker = 53.40 %
Let me know if you want a copy I can email it to you.
Chris
Hi Chris, I have a couple questions for you. Would it be possible to email you these? If so, could I get your email? If not, I’ll try to put them on the forum but I’m in and out of town so much that email is usually easier.
Chris, that’s great. Thank you! But that’s the north leg. I was really needing the south leg, Jensen, Klaras, Ericson and Nucor units.
Klaras should have the largest allocation, by my judgment.
Thanks, Phil
Any idea why the Jensen WW shows the William Heirs unit in the proposed and final plat but it’s not included in any of the P-12 forms. My family was inside the Williams Heirs unit because we have mineral interest in A-163 Cartmell. We have 6 older vertical wells in that same abstract that Comstock ran these 2 new wells under. It looked like they were going to just copy the lease from those wells for the Jensen WW and Ericson KN wells as our names show up on the original P-12s. We contacted Comstock and they said they would be able to answer our questions after the DO’s going out late July. Any idea how we can find out if we are included in these wells or do we need to just wait and see what happens?
I just talked to them and they said to check back in about 10-14 days as they have not got them ready yet for the Jensen KN 1 H yet
Thanks Chris.
Mr. Borak,
I was BRG’s lead landman in the Jewett/Newby area for several years. With assistance from a few other landmen, I put together titles, leases, curative, paydecks, etc., for the areas that BRG leased & drilled. I am familiar with your name, or possibly your dad’s name, being included in the Klaras GU and the Williams Heirs Gas Unit. I believe that the Williams name of unit filed by Comstock is not the Williams Heirs unit. I don’t see any pooling in the Comstock Klaras Unit Deep filing that includes the Williams Heirs. The Jenson JN includes the Erison, the Jenson, the Klaras and the Nucor unit. The Nucor unit is a collection of leases that Comstock put together because BRG did not form a unit around or under the Nucor acreage. The area Comstock intends to pool in the above named units contains 1,833.1999 acres. I’m just waiting now, as you are, for the allocations to be assigned. As you probably have seen on the RRC map showing the Jenson JN southerly wellbore, the Klaras is crossed from the NBL to the SBL of the Klaras tract, so the Klaras will most likely have the lion’s share of the allocation, but that’s just conjecture. However, I know for a fact that the drillsite is on the Ericson unit lands north of FM 3501. I also know that FM 3501 is the boundary line between the Ericson and the Klaras and I do not have any clue as to how the Jenson GU has any contribution to the southerly wellbore area. – Best Regards, Phil (As clarification, the original Ericson well and the original Jenson well was drilled before I got there, but I was involved in the titles, curative and surface damages for subsequent unit wells in both units.) Corrections below:
I have some corrections to make. Mr. Borak, you are correct, the northerly wellbore permit does include the Williams Heirs GU. But I was correct that it was not affected by the southerly wellbore. It is interesting that the Williams Heirs had no allocation in the northerly leg, which is contrary to their permitting.
The point of penetration was under the Jenson unit at which point the wellbore diverted north and south, so I stand corrected that the Jenson is involved in the southerly lateral.
Phil
Hey Phil, Thanks so much for your awesome response. Very nice that you remembered our name. We will wait and see from here. Thanks again.
Please see the correction at the bottom of my last reply.
Thanks so much for that clarification and thanks for looking at this information. Hopefully we are included in there somewhere. 