Royalty Decimal Interest


What is a decimal interest percentage based on in relation to sections? We have three wells, each running through 2 sections in various areas of our ranch. Two wells are pooled and one is not. Each pay a different decimal interest. Please help me understand how each could be different.


Lee, I’m a division order analyst with 40 years of experience, so maybe I can help you with your question.

The basic formula for calculating a lease well royalty interest is:

Mineral Interest Share x lease royalty rate = entitlement royalty decimal

This only works if your land fills the entire proration unit area required by the TRC for the well. That’s what’s called a lease well.

The basic formula for calculating a pooled unit well royalty interest is:

Mineral Interest Share X lease royalty rate X gross tract acres / gross pooled unit acres = entitlement royalty decimal

Mineral interest share can be a fraction, percentage, or decimal. The gross tract acres is the gross surface area of land you own that is inside the pooled unit.

Here’s an example of lease well entitlement decimal calculation:

50% mineral interest share X 3/16 lease royalty rate = 0.50 x .1875 = 0.09375 entitlement RI. But now let’s say your lease is now owned by ABC Company and XYZ Company, 50/50, and ABC operates the well. Either ABC will sell 100% of the production from the lease well and pay you 100% of your 0.09375 entitlement decimal (their share plus XYZ’s share), or XYZ will sell their 50% of production to their own sales contract and pay you only their 50% share of your royalty. XYZ should issue you a check that has the entitlement decimal of 0.09375 on it, but might have 0.1875 as the payment decimal if their database system has to inflate your true decimal up to your share of their 50% of sales. ABC would be paying you the other 50% separately, and their payment might be 0.09375 entitlement and payment decimal, or 0.09375 entitlement and 0.1875 payment decimal, depending on their database capability.

For the pooled unit wells, you have to know how much of your leased land is inside the pooled unit, and the size of the pooled unit, but the formula above for pooled units should work. You say the wells were drilled “running through 2 sections,” so the horizontal well was drilled in the one tract but bottomhole is in another tract in the other section. The two (or more) tracts the horizontal lateral travels through don’t have to be pooled. If that’s really the case here, then instead of tract acres / unit acres, you must use “length of producing lateral inside your tract / total length of producing lateral from first take point (FTP) to last take point (LTP)” to arrive at your entitlement share of royalty decimal. Then, of course, you have to know if 100% of your royalty will be paid by the operator (or purchaser on behalf of the operator), or be split between leasehold working interest owners like the example I gave above.

Since the lateral lengths for each horizontal well is different (I’ve never seen two that were identical!), the decimal calculation for each will give a different decimal.


Lee, a quick note: my answer below is predicated on your land being in TEXAS. If it’s not in Texas, it means the “sections” are cadastral. Oklahoma, New Mexico, North Louisiana, etc. If your land is outside Texas, the pooled horizontal wells across two units must be calculated differently than what I gave you. Let me know.



Thank you for the great lesson! I appreciate it. Our property is in Borden County, in Texas.


Wow, what a lot of great information, so many thanks for taking the time to share all that.
I have a question about horizontal wells I cannot seem to get a handle on. If a neighbor drills a horizontal well going thru my lease BUT IS NOT SUCKING OIL FROM MY area does he owe me anything? Same situation, now he is sucking oil ONLY from my section, is that the same royalty as if he had a well directly above my minerals?
Any clarification in language we lurkers can understand would be highly appreciated!


It depends on several factors. Has a unit been formed which includes some or all of your mineral acreage? If so, then royalties will be paid based on the terms of the unit. Or the horizontal well could be a sharing or allocation well and royalties will be allocated among the tracts traversed by the producing portion of the horizontal wellbore. That is the wellbore between the first and last take-points (the length of the fracked wellbore). You can see where the first and last take-points are on the as-drilled plat filed with RRC. If any of the horizontal wellbore is crossing under your minerals, you need to look carefully at this.


You’ve touched on a sensitive subject here, I think, if I’m reading it right. It looks to me that you are asking about what is called “rule of capture.” You attorneys out there, I’m not going to offer legal advice. I’m only going to share what I’ve learned from in-house attorneys to apply to specific situations on my job only. Okay, now that I’ve wasted time & space with a disclaimer, I’ll move on.

If the horizontal lateral (wellbore) is only passing through your land, and you know for certain that there are no perforations (take points) in the section of lateral under your land, then according to what in-house attorneys have told me, neither statutes nor case law exist addressing that.

There is one case, though–I don’t recall the name of it–where the judge ruled that a wellbore simply passing under the surface is not trespassing, just like a plane flying over your land is not trespassing. But according to what in-house attorneys have told me, there are still very valid trespassing issues going on.

For instance, did you know that while the drill bit was passing under your land, the oil company drilling the well was capable of getting data about what is–and is not–under your land? What if they found out, as they were passing through, that you don’t have oil or gas in paying quantities? OR–that you DO, and you don’t have a lease right now? What could either type of information do to the value of your land for oil & gas leasing in the future? And do you agree that in either situation, the oil company would have knowledge superior to yours in the negotiations for an oil and gas lease?

As for the second scenario you give, I defer to the other answer you’ve already gotten on it. I agree with what’s already been said about it.


Thanks again to both of you for explaining this in understandable terms. That was exactly the information I wanted to know - and you gave it!


Our family ranch was sold, but we kept the mineral rights. There are thirteen sections over 8300+ acres. Can you explain this? Within this property, would each section be called a unit and can each unit vary in size?