Someone I know owns minerals in a county out in West Texas. Their mineral interest is subject to a lease and their is production from a vertical well that has perpetuated it past its primary term. The operator then drilled two allocation wells in 2023. We will call them the 1H and the 2H. The 1H wellbore traverses their tract while the 2H is roughly 120’ off of their tract. They were approached to execute a PSA by the operator.
It laid out their interest in the 1H, as follows:
Productive Lateral Length of Subject Tract = 5,000’
Total Productive Lateral Length = 15,000’
Ratio of Participation based on Lateral Length = 33.33% (5,000’ / 15,000’)
As planned this well does not traverse the subject tract. With no PSA, the interest is 0%
With a PSA, all of the same calculations from the 1H well, but with accounting for the “Horizontal Drainhole Area”, and “Lease-Line Allocation Factor” as defined in the PSA (“Box Rule”). It draws a box around the wellbore (330’ to each side) and determines the portion of the tract within the box. Note that inset B plat I sent on Monday shows this well to be 117’ East of the Eastern Subject Tract Line. Of a 660’ wide box, the Subject Tract would include 213’ of the box. 213’ of a 5,000’ tall tract is 24.449 acres of the subject tract that fall within the Box. 660’ of 5,000’ is the total acreage of the box being 75.7575 acres. So the Box rule ratio is 32.22727% (24.449/75.7575)
Final Interest is 0.00520833 x 0.3222727 = 0.00168087 decimal royalty in the 2H well
They never signed the PSA. They completed the wells and they are not receiving royalties from either well. They are in the process of reaching out to any attorney but I figured I could educate myself here as well. Thanks.
Questions:
Why would they be entitled to production from the 2H well?
I’ll offer some thoughts and details here, in hopes that others with deeper expertise might weigh in as well.
From what I understand, Your Someone would not automatically be entitled to production from the 2H well simply because of the wellbore’s proximity to their tract (even though the PSA’s calculations you recited, almost implies through the box method that the wells offset would drain Your Someone’s mineral estate). However, unless the horizontal wellbore actually traverses the mineral owner’s tract, it seems there is no requirement to be included in shared production.
In this circumstance, Operators often seek to negotiate a Production Sharing Agreement (PSA) which allows for sharing production based on agreed methods, like the length of lateral within each tract or box rule acreage around the wellbore. Operators sometimes aim to have agreements with all parties or at least 65% of mineral or leasehold owners to sign on to a PSA. Without signing the PSA, it sounds like a mineral owner would not receive production from a well that does not actually cross or produce from their tract, such as the 2H in this case. Based on this it sounds like signing the PSA would give Your Someone more rights to production?
Consulting a qualified oil and gas attorney with experience in West Texas allocation wells would be a good call. They can evaluate and advise on the best course of action from here.
If others have insights or corrections, I welcome the discussion. I’m still expanding my understanding of these specifics, options, and how they play out. And I don’t want to downplay the complexity in this scenario, this is some complicated stuff!
This situation demonstrates the importance of responding to operators and well proposals, especially if your minerals are not under lease. Then deciding whether to participate or to protest the well. As a general rule, the wellbore needs to cross a tract for the mineral owners to receive minerals. However, RRC rules require the horizontal wellbore to be located at least 330 feet from the nearest lease line. (As opposed to the end or toe of the wellbore.) This is why the operator proposed the box around the 2H wellbore as a basis for royalty payments. Otherwise the mineral owner could have protested the location. By doing nothing, the mineral owner cannot now protest the well. The mineral owner needs to get in pay, but whether or not he can collect back royalties is not clear. The attorney can provide the best advice and help get this resolved with the oil company.
After 2 years of production, the mineral owner needs to prioritize getting into pay. An attorney can advise whether failure to act previously may constitute consent and what restrictions the statute of limitations may impose. Civil lawsuits are expensive. The RRC will not be involved as its protest deadlines are passed.