Oil pricing under different lease royalty clauses

A Texas mineral receivership has distributed to me a partial interest in a lease that a decade ago was executed on behalf of several supposedly “missing” mineral owners, including me. When I learned of the receivership, I filed with the court a claim for my accumulated royalties and ongoing interest, and thus I now hold a partial assignment of the lessor’s (receiver’s) interest in the lease. The lease is what the developer proposed to the court when it filed the receivership action, and it was approved by the court without any negotiations, of course. I have several questions about the lease terms and the royalty statements that are now coming directly to me from the current operator (itself a recent assignee of the lease).

The royalty clause in the receivership lease is drafted as a fraction (3/16) of the “net amount received by Lessee for the sale of the oil” at the time it is taken from the storage tanks. However, in other leases for the same tract, independently granted by some of the other undivided mineral owners (distant family relatives), the royalty clause is based on the “highest posted price” in the “general area posted market price” as of the day it is run into the storage tanks. I read somewhere that the first approach is more typical when the expectation is that a well drilled under the lease will turn out to be primarily a gas well (this well is near Eastland TX; it is producing mostly oil). Is that true? Any insights as to why different clauses were used?

Next, my royalty statement calculates the amount due based upon a single oil price for the month. Is this because once a month the gatherer pulls up his truck and empties the storage tanks, and the market price that particular day is the basis for what the operator (and eventually me) gets paid? How is pricing set in this type of situation?

My suspicion is that the royalties for all of us lessors are computed in the same way, regardless of the different wording in the royalty clauses. Seems to me that the second type of clause should entail daily computations reflecting the ever fluctuating oil prices. How does this really work? In general terms, is one type of clause more advantageous to the lessor or lessee?

In practical terms, what opportunity do I have to confirm or audit what the operator claims to be the monthly price? I can check volume data to see if that matches what the operator reports to the RRC, but it seems like I must take on faith what the operator claims as the revenue he “received.”

Finally, am I stuck with this lease as long as the operator keeps it alive? Any chance to obtain a new lease that is negotiated by me instead of being rubber stamped by the court?

A) In order to get a new lease, I believe you’d need to prove the old lease was incorrectly granted. It will likely be a long and complicated road. I don’t know the precedent or case law for that, but you could consult with a Texas Oil & Gas lawyer to determine if it’d be worth your time based on your potential ability to negotiate a better lease.

B) For the pricing of oil, leases typically uses the wording in your lease (rather than the other language you mention) because of the practicality of tracking pricing. The simplest method is to use the oil run ticket (receipt) the oil hauler (the big tanker trucks) left for the operator on the day the hauler transferred the oil from the wellsite tanks to the truck tank. This is usually where transfer of ownership happens for the operator.

The operator will get a receipt (historically sometimes left in a mason jar on the wellsite, but you can imagine all the digital ways this is replicated now with iPads and such) with the amount of oil removed from the tank and the price. Sometimes the quality of the oil is recorded as well. The operator has either a person or a digital gauge on the well tanks to cross reference the sold amount recorded by the purchaser.

An oil hauler can hold ~190 barrels of oil in his tank, so for efficiency, the operator will call out the hauler when there’s at full load to pick up. For some wells this is 5 times a day, for others this is once a year. Since the operator is usually paid on the price at pick-up, this is generally the price the royalty owners sees (due to the language in most leases). Wells hooked up to pipelines have a LACT meter so it’s more real-time pricing, but that’s more rare (except in the Permian). Your individual pricing is most likely based on which days the well is selling oil. This makes it hard to audit to the penny, but the monthly average pricing should get you close. If your lease has audit rights, you can request all the documents needed to calculate these things, but otherwise you’re at their mercy.

C) The royalties should be calculated based on the unique language in each lease for each lessor. That doesn’t mean mistakes or shortcuts aren’t ever present (because…humans + software…), but the company should be striving for this to be 100% correct.

It sounds like you were force pooled, which is rare enough in Texas that I’ve never personally dug into the logistics but I’ve heard from landmen it is a thing. Sorry I can’t help you more there (more land/legal territory), but the operations and pricing points I can help all you need.


Wow! Thank you Tracy for such a good description of the physical sale process!

Great info—exactly what I was looking for. Thanks!