Request For Assistance From A Reader -- December 19, 2016

Disclaimer: this is a long note. There are likely to be factual and/or typographical errors. This is my opinion only. It's how I "see" things. I may be completely wrong. If this information is important to you, contact professional assistance.

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Updates

December 20, 2016: see first comment. The reader brings up the issue of communitization. For more on that, one might to start here. But again, if we are getting to this level, one needs professional advice. Again, I would assume a good landman could point folks in the right direction. If not, go to the trust department of one's bank and ask for suggestions. 

Later, 9:30 p.m. Central Time: I think we're working too hard at this. Every well stands on its own. Forget about "overlapping." Forget about other wells, no matter how many wells you have.

Simply take the well you are interested in. Take that well, and take out the lease you signed for that well.

Your royalty for that well = (net mineral acres / spacing unit size) * (bbls of oil produced) * (price per bbl of oil) * (royalty rate).

Your lease will tell

• you how many net mineral acres you have;
• the spacing unit size; and, 
• the royalty rate

The NDIC provides monthly production for every well; and that information is available to everyone free of charge at the NDIC site. The monthly Director's Cut will provide a ballpark figure for the price oil is selling for.

"Mailbox money" for an existing well in a 1280-acre drilling unit will not be affected by a new "overlapping" 2560-acre unit, if that makes sense. Likewise, "mailbox money" for an existing well in one 2560-acre unit will not be affected by a new "overlapping" 2560-acre unit that includes sections in the existing 2560-acre unit. Each well stands on its own; each well is defined by the NDIC permit and by the lease.

Original Post

 

Over at the "Discussion Group" someone asks an interesting question: Can someone point me to some resource that describes how mineral interests are to be handled when two overlapping 2560 acre spacing units are established?

This is an important question because from the graphic below, one can see how the Bakken is covered with 2560-acre spacing units and overlapping 2560-acre units.

I will throw out my two-cents worth to get the discussion going and then open it up to those that have actually had experience.

I don't have any minerals so I am not speaking from experience. But I've followed the Bakken long enough to have a pretty good idea how this works. If I'm wrong, I would definitely appreciate if someone would point out  how I'm wrong.

The most important thing to understand is this: each well stands on its own. It is not affected by neighboring wells or other drilling units from a royalty point of view.

In a 2560-acre unit (overlapping other drilling units or not overlapping other drilling units -- does not matter).

A 2560-acre drilling unit is a four section unit. It can be of several different configurations:

• a square;
• a stand-up (four sections, all in a line, vertically)
• a lay-down (four sections, all in a line, horizontal)
• L-shaped (various orientations)

For simplicity, let's say the 2560-acre unit is comprised of sections 1, 2, 11, and 12.

Four sections = 2560 acres.

If a mineral owner controls any acreage in any of those four sections, that mineral owner will participate in any royalties generated from any well permitted for that 2560-acre drilling unit. It does not matter where the well is sited inside the drilling unit, or even outside the drilling unit.

What counts is the specific acreage permitted in the permit application, generally identified by sections or part of sections.

So, back to the example: sections 1, 2, 11, and 12 in any given township.

If a mineral owner controls ten acres in section 11, the mineral owner will get royalties based on 12 acres of the 2560 acres.

If a mineral owner controls 60 acres in section 12, the mineral owner will get royalties based on 60 acres of the 2560 acres.

Most horizontals in the Bakken are still about two miles long. Therefore, for illustrative purposes, let's say Whiting has a well sited in section 13 (to the south of section 12) and plans to run the horizontal from section 13 (not part of the 1, 2, 11, 12 - overlapping 2560-acre drilling unit) through sections 12 and and 1 to the north. If the royalty owner has 10 acres in section 2, that royalty owner will participate in the Whiting well.

If the well produces 25,600 barrels in the first month, the royalty owner will get royalties on a ratio based on 10/2560 (ten acres controlled by the mineral owner; the well is on a 2560-driling unit).

(10/2560) * 25,600 = 100 bbls.

Let's say the company clears $35 / bbl. Then those 100 bbls netted $3,500.

Go back to the lease one signed with Whiting. If the royalties were 3/8th, then 3/8ths of $3,500 = $1,312. 50.

Bottom line: one can sort this out without worrying about any other wells, any other drilling units, etc.

To repeat:

• identify the 2560-acre drilling unit 
• a mineral owner controlling any acreage -- no matter how small -- any where in that drilling unit, will participate in a well that is spaced in that drilling unit on a proportional basis, based on the number of acres controlled by the mineral owner

If there is another horizontal running through sections 1 and 12 but on the 1280-acre drilling unit comprised of sections 1 and 12, then to participate in that well, one must control / own acreage in section 1 or 12 or both.

It took me a long time to figure this out but once it's figured out, it's really quite straightforward.

Finally, back to the original question by the reader. What about two overlapping 2560-acre units? Doesn't matter. Same thing applies. Simply forget about other wells and other drilling units. Just identify the 2560-acre unit; determine if you have any acres in that 2560-acre unit; if you do, you will participate in the production of any well placed in that spacing unit.

I think this is where the problem lies: if a mineral owner already "has" a well in a 1280-acre unit, let's say, sections 12 and 1; and, then a 2560-acre well is drilled which includes the existing well in section 12 and 1, does the mineral owner collect royalties from that 2560-acre unit from both wells? My hunch is "No." But someone else will have to answer that. I still think that each well "stands on its own merits, on its own permit. If the mineral owner has ten acres in section 12, the mineral owner will collect royalties from the existing well on a 10/1280-ratio; and will collect royalties from the new well on a 10/2560-ratio. 

If I'm correct, it's easy to visualize; hard to articulate. 

If I'm wrong, someone will have to explain to me the way it works. 

My explanation is in line with what an experienced landman has provided in his book Royalties Within Reach.

Forget about other wells.  Pay attention to one well at a time. It does not matter if you have one well "straddling" two overlapping 2560-acre units. Look at the permit and lease.

Royalty = (net mineral acres / spacing unit size) * (bbls of oil produced) * (price per bbl of oil) * (royalty rate).

The usual disclaimer holds: I don't own any mineral acres. I don't have any experience with minerals. It is very likely I am wrong. I am hoping that folks with experience can tell me if I'm wrong, and I'm wrong, how I'm wrong. 

Serious piece of advice I've heard from many, many folks: if you have questions like this, it suggests that you are participating in more than four wells. If one is participating in more than four wells in the Bakken, one is now an "oilman." One needs professional advice by this time. Any good landman can refer you to lawyers in this field.