Payment of royalties confusion


I posted about the topic below in July of last year, and have since come to learn some information that I find quite interesting.

This particular situation concerns the Fladeland 14-26HU well, permit #36559 operated by Whiting Oil & Gas. The well is located in Mountrail County, ND. On the Department of Mineral Resources website it says the spacing unit for this well is 153-91- sections 25, 26, 35, and 36. However, owners in sections 24 and 27 are paid in addition to the owners inside the 2560 acre spacing. Also, the owners in 35 and 36 are paid twice as much as all owners in the other 4 sections.

I recently came to learn that Continental Resources would not pay royalties in the same way Whiting Oil and Gas would in this situation. Continental would pay only owners included in the 4 pooled sections.

Doesn’t it seem like a rather large issue if operators are not in agreement on how to pay royalty and working interest owners? I’ve tried asking the Department of Mineral Resources questions about this, but their response to my first inquiry took more than 6 months.

If you have any additional information concerning this topic, I would be appreciative. So far the only thing I have found on the department of mineral resources website is an explanation that addresses the more straightforward case of two side by side 1280 acre spacing units.

Thank you

First, how do you know Continental and Whiting Oil would pay royalties differently in this situation? Analogy, or has someone in the companies confirmed this?

Second, this is a bit of an odd situation with these wells which makes the royalties split funny (fair, but funny). There are three 1280 units: A, B, and C in the image below. Since the well is within a certain distance of the unit boundary of all of them, the royalties are allocated based on the percent of each unit forming the allocated 4-section unit (highlighted in yellow). This allocated unit is not the same type of unit as the pooled units A, B, & C, but and production is allocated differently in these pseudo-units that are formed just for the purpose of a single well. (maybe an actual landman can step in and explain the exact legal language ND uses for these units, but that’s the basics)

25% of the production would be coming from each units A and B, and since all royalty owners in those units get all royalties for the unit, folks in 27 and 24 would get their equal share of that 25%. Since 50% of unit C forms the unit, those folks would all share 50% of the royalties.


contact the DMR and ask them for the active cases and exhibits for the location of your mineral rights.

it may be a drilling/spacing unit of 2 sections.

and on top of that a pooled drilling/spacing unit of 4 sections.

i think your request will be taken care of within the week, that you will receive the exhibits and they may also send you the audio files of these cases.

when 4 sections (2 drilling/spacing units) are pooled together, they are likely drilling on the boundaries. they may be drilling into 2 or more oil-bearing soil layers. they do not take away from the current drilling/spacing unit. rather, they are able to drill on a border of drilling/spacing units to “avoid waste”. if they did not drilling on the border, that oil would not be accessed and therefore they are arguing that it wastes oil because it is not exploited. when they drill on the border, they will pay all mineral rights owners in the 4 sections.

after you get the docket cases (pooled 4 sections, and your sections), you could ask for a copy of the permits of the wells involved. that tells you depth, etc.

bear in mind that the current way to drill is to establish an ecopad, usually on a border of a drilling spacing unit, which is used for several wells. the laterals may go into other drilling spacing units or the laterals may go into this drilling/spacing unit or mixed because the laterals may go into this drilling/spacing AND the laterals go into another drilling/spacing unit (like along the border or like the drilling/spacing unit just north or just south or just east or just west).

DMR has a map and i think you should look up your mineral rights and keep enlarging it until you isolate your drilling/spacing unit and nearby drilling/spacing units. it’s called GIS. you can click on find section and put in your section, township and range, then 5 miles so that you can see it closely. maybe take a picture of that so you have it to refer to in all of this. the exhibits will contain maps also.

i do not know if you received these mineral rights through homesteading, but this might be fun to research. Home - BLM GLO Records

take search documents tab, click on state of north dakota, county, then township range and section and find the homesteader documents.

then there are these historical maps:

Mountrail County 1917 Atlas Illustrations Additional Content Geocode Informational QualityI Geo. A. Ogle & Co. North Dakota 1917
Mountrail County 1958 Atlas Geocode High QualityH L. Roe Directory Service North Dakota 1958

North Dakota Antique Maps and Historical Atlases - Historic Map Works

the State of ND DMR will want people to be paid one way. you need to discover what is the current method.

there are not 2 ways.

the company that submitted the docket for your 2 section drilling/spacing unit is the oil producer, the majority drilling interest or the significant interest that others agree is the oil producer. that 2 section drilling/spacing unit governs.

from there, they take your acreage/acreage in the drilling/spacing unit. that is your mineral interest.

formula goes: month volume of oil x your mineral interest in this drilling/spacing unit x price of oil (is this an averaged price, probably) in the runs x your royalty%.

in this example, i am supposing you have 160 net mineral acres and your royalty is 18.75%.

you may know your well had 200 barrels of oil per day for 30 days or you may know you had 6,000 barrels of oil for that month. 200 barrels of oil x 30 days=6,000 barrels of oil

as an example, say you had 200 barrels of oil/day x 30 days x (160/1280) x $52 x 0.1875=$7,312.50.

and 160 acres /1280 acres is 0.125

they do the same formula for natural gas but price of natural gas is very low.

runs are what they haul out of there or the volume of oil from your well into the oil pipeline. runs are what is sold.

but with the 4 section drilling/spacing unit, the one that was combined on the border, there is a different formula. the difference is in the mineral interest portion. now they are using 2,560 acres as the drilling/spacing unit for those that are on the border. so i am using everything the same EXCEPT changing the drilling/spacing unit. i assume you have 160 acres again.

200 barrels of oil/day x 30 days x (160/2560) x $52 x royalty 0.1875=$3,656.25

see, 160/2560 is 0.0625 now

and if they put 4 drilling/spacing units together, then you have 5,120 acres in that drilling/spacing unit.

see, 160 acres /5120 acres =

200 barrels of oil/day x 30 days x (160/5120) x $52 x royalty 0.1875=$1,828.13 because i rounded up half a cent.

if you have property in 1 drilling/spacing unit, you get paid on that.

if you have property that is in 2 drilling/spacing units because they are put together and they are drilling on the border of those, you get paid on that.

if you have property that is in 4 drilling/spacing units because they are put together and they are drilling on the border of those, you get paid on that.

so each time they put drilling/spacing units together, they are drilling on borders and that oil money is in addition to the money you get from your original drilling/spacing unit.

it does not matter if you are not getting as much as someone in an adjoining drilling/spacing unit. that is because their well might be newer so the volume of oil coming out of it might be larger than your older well. you can't get their anyway because it is from their drilling/spacing unit. just remember, average amount of oil that comes out of a well is a little north of 1 million barrels total volume, whether the oil came gushing out right at the start or whether the oil just flowed out with a lower but more stable volume. some wells that produced more than 10,000 barrels/day were producing 150-300 barrels/day by the end of the year and might stabilize around 100 barrels/day for a while, declining more slowly.

so yes, you could be included in 3 types of drilling/spacing units that all have different calculations depending on the size of the drilling/spacing unit. putting 2 or 4 or more drilling/spacing units together does not change the original drilling/spacing unit, and only increases your volume for your royalty for those laterals that were drilled on the border between the drilling/spacing units put together.

your lease will be active until all the wells in your drilling/spacing unit become inactive. they have to lose $ on the oil wells in your drilling/spacing unit for the lease to become inactive. that point is usually around 12-20 barrels of oil per day x the average of the price of oil that month to be around breakeven price to operate the well. if all wells get to that point in your drilling/spacing unit, and they drill one more well and it produces, that will still keep your lease alive. this is a likely situation when your wells stop producing as much oil as today.

i am hoping this all makes sense to you.

i would want the exhibits submitted of the docket cases of all of the drilling/spacing units where my mineral rights were located. you might want a copy of the permits so you know the target soil layers of each. the audios of those docket cases would have the expert witnesses for your case, the judge, the DMR person at the hearing, the company engineers.

the audio and docket case information is available in the premium subscription of the DMR. you can ask for the exhibits and audio of a particular drilling/spacing unit and they will send it to you, if you only need a few of the cases. the scouting tickets are available on the basic subscription, which give you a historical record of what they turned in for runs for your wells.

you can contact your landman to explain things to you. this is their job. do not be afraid to ask them questions. they are not your “friend” but they can be helpful.

suzanne hamlet shatto

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“Since the well is within a certain distance of the unit boundary of all of them, the royalties are allocated based on the percent of each unit forming the allocated 4-section unit (highlighted in yellow).”

Do you have a source for the text I quoted? I have not been able to find anything like what you said on the DMR website, or in the ND Century Code.

Continental confirmed to me that they would not pay royalties in the same way as Whiting. Continental would pay only the four pooled sections, while Whiting would pay all 6 sections.

I asked the DMR about Whiting and their division of royalties. The petroleum engineer at the DMR said the royalties were being split this way “by virtue of pooling agreements.” I went to look for those pooling agreements, and they do not exist.

I also explained the situation to Lynn Helms, the Director of the Department of Mineral Resources. Even Mr. Helms was perplexed by the situation. In addition to ND’s top oil official not understanding this, I have explained the situation to about 10 landmen and geologists. Every last one of them is as confused as I am.

May I ask where are you getting the term pseudo-unit? I work as a landman and have never heard this term. Both of these units appear to be real units that were pooled by the oil and gas commission.

I still do not see any logic for sections 24 and 27 being included in the division of royalties. Those sections were left out of the new pooling order. The old pooling order does not seem to have any language that makes it supersede the first order.

I also disagree that 25% of the oil is coming from sections 24 and 27. The oil is coming from the section line area between 35/36 and 25/26. The wellbore is more than a mile from section 27, and travels in the opposite direction of section 24.

Thank you for the input.

I don’t. My statement was based on my understanding of how boundary wells work and ND leasing I have not researched this individual well file yet.

Was Continental the prior operator and they paid differently than Whiting is now paying? I’m still a bit confused as to how you received this confirmation that one company would pay in a different manner than another. I could understand everyone you talk to being perplexed if that were the case (because it’s not up to the company on who gets paid, it’s up to the legal agreements).

So this is what I was referring to when I created the term “pseudo-unit” (out of thin air; it’s just a descriptive term) vs unit. Since this is a public forum generally geared towards the public, most people use the term “unit” to describe a pooling rather than unitization, and in general it’s a confusing topic. I assumed you were not a landman because most people here asking questions are not. “Units” A, B, and C are likely actually pooled. I do not have the documents on hand to prove this, no, just going off how I usually see things. Once the acreage is pooled, it acts as essentially one tract of land. Doesn’t matter where in the pooled acreage it happens, it happens to the whole acreage equally. One drop of oil out of section 26 is owned by all the owners in sections 26 and 27, and vice versa.

The unitization performed to drill the Fladeland 14-26HU included all four sections it touched, or the 2560 acre unit. 25% goes to 26, 25% to 25, 25% to 35, and 25% to 36. 35 & 36 are [likely] pooled together so those owners get 50% of the production to split among the pooled owners. 27 & 26 are also [likely] pooled, so those owners (all the pooled owners in 27 & 26) get 25% of the production to split. Same with 24 & 25.

So no, 25% of the production is not coming from 24 and 27, but with pooling it doesn’t matter. The key would be to find out if those sections are actually pooled, but you did say the DMR told you it was controlled by pooling agreements, so it probably is.

I’m gonna take a wild guess that you have minerals in either section 25 or 26?

I help manage minerals for a client in Section 26, but do not personally own anything in any of these sections. In the document you posted, is there something specifically relevant to these overlapping units? I read through it, but I’m not finding anything that seems to cover this subject.

I talked to a landman at Continental a couple weeks ago, and the landman said they would pay only the four sections. Continental has not operated this, but I was curious about how they would approach a similar matter.

There were the original pooling orders that pooled 35/36 etc as 1280s. Then there is a new order with the exact same language that pools sections 25, 26, 35, and 36 as a new unit. I’m still a bit confused by your ‘out of thin air’ comment. Both units were created through the exact same process. If this is controlled by pooling agreements, I would think people would be able to look at them. Neither the DMR or Whiting can provide them, or direct me to where I might find them.

I also find the logic of Whiting to be inconsistent. The wellbore we are discussing is #36559, which my client is paid for. If you have a moment, please look at permit #36545, which travels north along the township line. This wellbore travels quite close to the wellbore of permit #36559, but my client is not paid. I understand we are not part of the base unit in that case, but our wellbore is affected in the same way that sections 24 and 27 would have been impacted by the first well. Also, when Whiting decides to drill a well on the other side of the section line from the Fladeland 14-26HU well, the owners in 35 and 36 are still going to be paid twice as much as everyone else for a well that isn’t on their property.

There is another instance nearby where four sections were pooled, but then 7 sections shared in the royalties. One section was paid for 33% of the royalties, and others are paid for 11% of the well. This doesn’t strike me as equitable.

Thank you for the input. Just trying to get together as much information as I can, since so little seems to be available publicly when it comes to these more complicated units.

Hi Shaleguy, I’m not able to dive much into this right now (client work, Easter family time, etc… maybe my curiosity will get the best of me though) but my point of including the document was to point out the legal difference between “pooled” acreage and “unitized” acreage, as they are not the same thing and that could be causing some confusion.

Speaking as the geologist in the conversation, the reservoir is also a part of the discussion. Depending upon which zone you are discussing, one well may go into one zone which has been unitized or pooled with one set of parameters and another well may go into a completely different zone which may be larger or smaller in drainage area and will be pooled differently. I have some mineral rights in one section that belong to four different spacing/drainage units and it does drive me nuts as each well is calculated differently. (Visualize a sloppy pile of pancakes that overlap in the middle, but are not stacked straight up- now with bendy straws that poke through at different horizontal levels).

Are you saying one was unitized and the other pooled? Trying to understand the distinction you are making. Maybe I missed it, but the document you linked to didn’t seem to cover overlapping spacing units in depth.

I’m still quite concerned that Continental would not pay royalties in the same manner as Whiting.

Thank you for the reply. However, in this instance, the same formation was pooled, then later was repooled.

I can appreciate your pancake analogy, but this particular case revolves around only one formation. If sections in a particular formation are pooled, then repooled, how does that work?

I also asked the petroleum engineer at the Department of Mineral Resources about this. He told me royalties were split this way ‘by virtue of pooling agreements.’ I asked Whiting Oil and Gas about these pooling agreement, and there are none. Zero.

As a geologist, have you ever heard of one company proposing to pay royalties one way, and another company disagreeing? I visited with a landman at Continental Resources, and they said Continental would not calculate royalties in the same manner as Whiting in this instance.

I have had companies disagree on the decimal amount. Sometimes it was due to a different assumption on actual acreage as a different title opinion was done by another firm and they found different information. Sometimes, they flipped my acreage to someone else and gave me theirs and it took months to unravel.

I am not as familiar with the ND Century Code, so could not comment further.

Your initials may or may not be M.T., but there is a giant detailed response to that person from the NDIC examiner on this issue in the wellfile for that well. Dated Feb 2021.

The response sounds a lot like its written by a dude who is annoyed that somebody has kept writing letters to his boss asking about this issue, so he came up with an 8 page response. :wink:

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You nailed that one. Lynn Helms, the top oil official of ND admitted to me he thought Whiting had this all wrong. Mr. Helms also said that he would talk to his employees at the DMR and get some answers for me, and at a minimum indicated we had more to talk about.

Still have not heard from him, and we had that conversation last June.

Yes, disagreeing with oil companies about a decimal interest is a regular occurrence in my experience, but debating which sections should be paid for a well has never been part of any discussions I have had.

I still can’t figure out why these four sections were pooled. According to their logic, you would just pay all owners of the overlapping units.

The four sections are a spacing unit subject to underlying pooling agreements, not replacing them. From the documents @NMoilboy referenced (nice find! hah), they describe it quite well here. They also reference all the court orders and documents they use to come to this conclusion (which is the same as I laid out above, just in more formal words).


For anyone following along at home, here’s the full response from NDIC. (It’s in the public record, but I redacted your info for privacy, M.T.) Pages from W36559_Redacted.pdf (1.7 MB)

Finally, it’s worth noting they realize the confusion of the terminology.

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I’m not MT, but thank you for the concern. I had hoped to read MT’s original letter for more context. I would think MT’s letter should be in the well file.

Is the language of the new pooling order different from the old pooling order? I am not seeing how one supersedes the other.

I also have not been able to find anything more about pseudo units or base units. Neither term appears to be used the relevant portions of the century code, DMR website, or any other materials I have seen related to this subject.

Why are sections 22 and 23 left out? It seems as though their 2560 is affected by this.

There is a slight problem. There are no pooling agreements. None. You are obviously quoting the letter in the well file.

Additionally, at the bottom of Page 6 “…all pooled interest owners within the base 1280-acre spacing units should receive their equitable share of that oil.” So, how do you define “equitable share”? Since the oil being recovered by the section line well lies along the section line between 25-26 and 35-36 (east-west horizontal leg) and Sections 35 and 36 are being paid for twice as much as 25-26 then how or why is that “equitable”? What about correlative rights? That Correlative Rights Doctrine is a rule that each owner of a common reservoir should be afforded his or her fair share of the recoverable oil or gas beneath his or her land. Shouldn’t 25-26-35-36 each receive the same share?

I talked to a landman from one of the major Bakken operators who said that there is no case law in this matter. That’s what we need - case law.

This same landman said that their company does not necessarily pay royalties on section line wells that same way as this letter states.

Interesting. That would indeed be a problem if there were no pooling orders. So the pooling orders referenced are not actual pooling orders? I didn’t independently verify any specific orders, just how it should theoretically play out.

Either way, I feel an attorney specializing in this topic and this state’s laws would be a better resource for resolution to this particular topic than a free online forum. If it’s beyond the scope of an 8-page formal review, it’s likely beyond the scope of attention I or most any other professional could provide in our spare time. I wish y’all the best of luck though and would love to hear the resolution!

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