We’ve noticed a possible incorrect decimal interest on some older vertical wells we inherited in Martin County, TX. Payments appear to be based on a 1/8 royalty, and our lease is for 3/16. These are legacy wells, so we weren’t planning to push hard on correcting past payments.
However, we’re now seeing new horizontal wells being permitted in the same section and want to make sure the correct royalty rate is applied going forward.
My question is would it be better to:
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Raise the issue with the operator now (and risk going into suspense while they review), or
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Wait for the division orders on the new horizontals—assuming a fresh title opinion will be done—and address any discrepancy at that point if needed?
Curious if others have dealt with something similar. Thank you.
You should get this corrected if it is wrong. Did you sign a division order with that royalty decimal (DOI) and does that match the DOI on the check? Ask the operator for help in how the DOI was calculated. There are multiple factors, besides your royalty rate. You need to know what fractional interest you own in your tract to determine your net mineral acres within the well or unit acreage. Are there any burdens against your minerals, such as was an NPRI reserved in an earlier deed? If so, you will want to get a copy of that deed to see how this will affect your DOI. In some shallow units which were formed by combining multiple wells for waterflood or other secondary recovery, there was a weight factor based on geology and historic well production which went into the DOI calculation. This would be laid out in the unit agreement. Any such weighting factor will be limited to the shallow units wells and not carry over to new horizontal wells. Your interest should not be suspended since you think that you are being underpaid. Usually the suspense is limited to the disputed portion of a decimal and no one is claiming your royalties.
Thank you for taking time to respond.
There is no NPRI and we didn’t sign a DO for these wells but instead signed Transfer Order from my mother in law’s estate to us a couple years ago. At the time we just confirmed the decimal was the same she had been receiving, which it was, and it is the same decimal we are being currently paid on.
The vertical wells cover a N/2 section 320-acre unit and are about 12 thousand feet deep. We own 10/320 acres in that unit and the most recent lease in 2012 was for 3/16 royalty. So I believe decimal should be .005859 but we are getting .003906, which lines up with 1/8 royalty.
This operator operates most of our wells and we want to remain on good terms and want to avoid potential long periods of suspense, which we dealt with when transferring ownership a few years ago. If there is indeed a mistake my mother-in-law could have been underpaid 10’s of thousands of dollars over the years, that we aren’t necessarily trying to recoup. We just want everything to be clear going forward and for new horizontals to get the full royalty.
As you suggested I could just write owner relations and ask how the decimal interest on that section was calculated and to send me the lease they have on file, not mentioning the new wells.
I’m debating having our lawyer reach out as she knows how to speak with operators and is much more concise/effective. Though I also don’t know hearing first from our lawyer about this will put them on the defensive.
Last option I can just wait and see the DOs on the new well and ask them how they calculated the decimal. It was just permitted so could be a while.
Apologies for the long -winded reply, I can never seem to put these scenarios into fewer words.
Any chance the wells are covered by an older lease with 1/8th RI? If RI should be 3/16ths, the sooner you get it corrected the more you can recover from operator since you can go back 4 years before being cut off by the Texas statute of limitations, starting from the date that you notify operator of mistake in writing. And for the Hz wells, better/easier to get it right from the beginning than to mske changes later.
A transfer order is in effect a division order and you confirmed the DOI. If the vertical well was drilled before 2012, it is subject to the lease in effect at that time. Compare the legal description in the earlier lease and the 2012 lease and depths to see the exact acreage and depths. For example, if you own 10/320 in the entire section, the 2012 lease could be all depths in the S/2 and only depths below 12,000 feet in the N/2. If you do not have copies, look on-line and purchase copies of the recorded lease or memorandum of lease which will describe acreage and depths. You need to be proactive to collect all the royalties to which you are entitled. Gather all the records concerning your minerals, including deeds (historical from date of sovereignty is ideal but most people do not do this), leases, unit DPU, division orders, well filings, production data and your check detail. Ask the operator for copies of any leases you cannot find and for the DOI calculation. Contact the oil company yourself and ask a detailed question. Do not wait for the division order for some future horizontal well. If wells go through the existing unit acreage and depths in N/2 (as specified in DPU), then that portion of the royalties will be allocated based on the existing unit and old lease. Only the acreage subject to the new lease will reflect the 3/16 royalty.
There was a lease on this section in 1970 for 1/8 RI but there are no wells producing that date back that far. There were some that were plugged back in 2004, and then nothing again until around 2013-2015 which seems like they should be under our 2012 lease. I think I will check in with our lawyer. Thank you for your reply.
The verticals in this section were drilled between 2013-2015, which should tie them to the 2012 lease. Prior to this there were some wells that were plugged in 2004. Also noting that the horizontals being permitted now in this section are by a different major oil company, which is confusing as vertical operator lease covers the entire section.
There was a prior lease in 1970 signed by my mother-in-law for this and one other section leased at 1/8. But there is no producing well in either section that dates back nearly that far and would hold production, so this 1/8 royalty shouldn’t apply anywhere. There was no depth severance language on either the 1970 or 2012 lease, so all depths would be held by any production.
Could it be that an oil company mistakenly applied 1970 terms and by my mother-in-law accepting payments/signing DO, the old lease was ratified? She was getting up there in years around this time and didn’t track these rights very closely.
To further complicate things, these rights were sold to my in-laws in the 50’s, but the right to sign leases was retained by seller. In the 1960’s, seller deeded the full executory rights so my in-laws could execute leases, however the deed was not recorded until 2015. So we have a situation where a lot of our interests prior to 2015 got swept up in the seller’s leases, and a few were executed by my in-laws.
Due to the convoluted situation I’m leaning towards involving our lawyer. Or maybe this is more a situation to consult with a land man? I know enough to have gotten this far but feel at my limit now. If I write the operator are they required to provide me the lease/factors they are using to calculate the decimal?
Thank you, Tennis, you are always very generous with your time.
No, Division Orders in Texas cannot alter lease terms. You should get it corrected ASAP. Operators will typically show their calculations to arrive at DOI they’re using without having to sue them.
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To sum up - the original mineral deed reserved leasing rights to seller. That means that your minerals would be subject to the seller’s terms, including royalty rate. It is not clear when the 1960’s assignment of executive rights became effective - when signed or when filed. That is a legal question per oil and gas title law. Particularly if your 2012 lease and the original seller’s lease were to different companies as that sets up a conflict between them as to their working interests, in both the current wells and the future horizontal wells. Just a guess, but in 2012 any title opinion would have seen the reservation of executive rights and, as there was no recorded assignment back into the family, would have based the DOI on the seller’s lease. On the other hand, how do you know whether the seller’s lease had a lower royalty rate than 3/16th. Ask the oil company about the lease and DOI calculation to see if they are using your 2012 lease and think that there is a different factor which reduces your DOI. Or have your attorney ask the question.
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