My relatives have mineral rights on three units that are each HBP by a well spuded in Wilson County, and terminating in Karnes County.
All of their property in the units is in Karnes County and they all received a property tax bill from Karnes County a month or so ago. Then, a couple of weeks ago, they got tax bills from Wilson County on the same wells.
Can anyone guide me through how both counties can tax the value of the oil under property only in one county?
I'm not dreaming or making any of this up. We do in fact appraise the mineral interest in Texas for property tax purposes. A mineral interest is a taxable item of real property per Texas Property Tax Code, Sec. 1.04(2)(F). We use an income approach to value by way of forecasting future income potential as of January 1 and then discounting this future income potential to present worth with a discount rate that takes into account (as best we can) the time cost of money and all aspects of risk (basically, the chance this forecasted future income may not actually happen as forecasted). This is not "valuing an income stream" nor is it a production or income tax which are both based on past actual events.
We determine Fair Market Value (FMV) of the mineral interest per the definition of FMV found in the Texas Property Tax Code, Section 1.04(7). This definition does not limit us to consideration of producing minerals only; however, out of practicality we don't typically assign any value above zero for non-producing interests, whether "proved" or not. We just don't have the wherewithal to get that deep into the analysis of the reservoir and all the behind-pipe "what-ifs" that appraisals for purposes other than property tax do. That's why what we do is called "mass appraisal."
The paper I attached in my previous post addresses in detail the mineral issue you brought up (royalty interest owners can be mineral interest owners who still own minerals upon cessation of a producing lease).
Rodney K. Kret, RPA
Pritchard & Abbott, Inc., Valuation Consultants
,",,,out of practicality we don't typically assign any value above zero for non-producing interests, whether "proved" or not."
I can cite one example where P&A did just that. That is, assigned a value on well(s) that had been drilled but not yet put into production. And I might add, that value was apparently based on expectation of future production.
I did qualify my statement with the word "typically." There are in fact instances where it's appropriate to assign a January 1 fair market value to a mineral interest that's not producing income as of January 1 but in our opinion is reasonably expected to shortly.
Value is always based on reasonable expectation of future production as of January 1, and the future is not limited to just a week or two away, or even a few months. Obviously at some point out, though, the future becomes quite murky to try and determine what the "market" (aka, buyers and sellers) are thinking what would/could/should happen. As Yogi Berra famously said, “It's tough to make predictions, especially about the future.”
The example you cite (a newly drilled well) is one of these instances, but P&A's Engineering Services Dept. is advising our appraisers in our district offices to strongly consider holding off on doing that unless the well has been "completed" (not just drilled) before January 1, which in the Eagle Ford Shale means the frac job has been performed and the well is actually able to be produced and thus income be generated "by the turn of a valve" or some such minor action or event.
The Texas RRC's database protocols have evolved over recent years and have not been kind to appraisers looking for reliable well completion information. What was once universally considered as the official "completion date" of a well was filed by the operators upon successful end of the whole drilling process (drilling the hole and fracking the well) whereas production would start almost immediately thereafter. Nowadays, wells are routinely drilled (say, before January 1) without being completed until some time later (say, after January 1), and it's difficult to know what "completion date" represents on the RRC's records. The operator will initially file completion date with the RRC as the date drilling ended, and then later amend that filing with the date that fracking ended or the date that the well was equipped with a Christmas tree or pumping unit. So we do our best interpreting of this RRC data, with the help of the taxpayers (working and royalty owners), and hope things work out well for everybody.
Rodney K. Kret, RPA
Pritchard & Abbott, Inc., Valuation Consultants
The fact that all of the different scenarios need to be explained away for you guys to do your job just shows how asinine it is to apply a "ad val" tax to a mineral interest.
What you are taxing is a depleting asset as opposed to a home or land which appreciates in value. I'm sure with a high enough discount rate (provided the EURs are not vastly over stated) future uncertainy becomes priced in at little cost to owner but it is still a dubious model to base this whole thing off. Since production is reported on the lease level, how do you allocate production to each well bore? Does your model compensate for operator practices such as shutting in wells while art lift is installed. What about chocking back production to preserve rates through the tail of the curve? Are you given a type curve for a certain operator and then you apply specific engineering to a property within that profile? How can you value an interest with a DUC well for a given year if you do not know at the time when the date of first production will be or how the operator may flow that well?
Just taxing the yearly income stream seems a whole lot simpler to me. But they already do that with sev tax so I guess the counties had find a new way to complicate things.
"in our opinion" "reasonable expectation" "quite murky"
It seems to me that what Rodney is saying is that "we (P&A) can assign any value we want because the law is so nebulous".
Then, if the taxpayer does not agree, he/she can appeal to the Appraisal Review Board. But then the ARB is selected by the Appraisal District, trained by the Appraisal District (and the Comptroller) and paid by the Appraisal District.
This so called "Texas Property Tax Code, Sec. 1.04(2)(F)" sucks and needs to be revised so it does NOT include taxing on potential future income from minerals. Why not tax only the income as it is incurred?
A mineral owner is taxed on what could potentially be at some point. As we have experienced the last couple of years and in the 1980s, 1990s, minerals could stay in the ground until the Saudis allow for it to be extracted by reducing the amount of minerals they produce.
I am for taxing as what is produced and not what could be produced.
What if the government starts a taxing program of college grads based on their skills and what those skills could potentially help them earn in the future.
One could die and never see a dime from the minerals; however, he/she already pays taxes on what could be!
By the way, this is not directed at those evaluating the tax. It is directed at the tax code and those who find ways to take our $$$ even before we earn it.
Just tax it as it is produced!