Am I correct in believing that ownership of a producing well includes the operator, mineral interest owners and royalty owners and the total of their interest will equal 100% with the operator typically holding the largest percentage?
Are all owners assessed ad valorem taxes based on their percentage of the total value of the well?
If any owner divides his assessed value by his royalty interest will the resultant number be the total assessed value of the well?
Thanks, in advance, for any confirmation or clarification.
I’ll take a stab at answering your questions, knowing that others more knowledgeable will chime in as needed. The operator’s assessment includes their portion of production (NRI) as dictated by the pooled leases (eg. if all lessors retained a 20% royalty, then the operator portion would be 80% , less any override interests). The decimal interests should total to 100%. But the operator is also assessed upon the value of their equipment, whereas the OR & RI are not. The appraisal district should be able to provide you with the details of a particular well, as it is public information.
In April or May, you will receive a Notice of Appraised Value for the wells. These appraisals are generally calculated by RRC lease number. So if an oil lease has multiple wells with volumes reported jointly to RRC, then they will be assessed together. All gas lease wells are reported singly. The Notice will include a link to the appraisal company (such as Pritchard & Abbott or Capital Appraisal Group) where you can log in to pull down the detailed appraisal data for each lease. You will have 30 days to review the data and file any protest. Be sure to check your royalty decimal listed. Sometimes the operator will have the economic life of the well reduced and that will result in the values reduced for all interests (WI, RI, OR).
I appreciate the clarification posts. Since I just became aware about 2 years ago that I had inherited NPRI, I have been wading through trying to sort out past tax issues without the benefit of being issued an appraisal. I believe the taxes, which I went ahead and paid, are incorrect in a couple of respects. In Midland County, two of the entries seem to be doubled for the same time frame, but different amounts. Since the wells in question are drilled in one section in Martin County, pass through that section and 2 full sections in Midland County and then terminate in a third section if Midland County, I believe the smaller of the “duplicated entries” is actually supposed to be Martin County tax entries. The Martin County tax statement does not include entries for those wells, I am thinking the correct way to address this is to contact Pritchard & Abbot now and not wait till a new appraisal is issued. My belief is that whether a taxable interest is reported by well, lease, or unit, there should never be more than one tax entry per interest. Agree or not?
If it were Martin County tax, then the statement would come from Martin County Tax Assessor. Look at the tax statements - 1) Are the statements for same year? 2) Do the statements have the same taxing entities? Sometimes separate statements are issued by the county and the ISD. Parts of the western part of Ward County is taxed by Ward County, hospital, etc. But the ISD is Pecos-Barstow-Toyah which is located in Reeves County, rather than a school district in Ward County. 3) You are correct to assume that if a horizontal wellbore or unit cross county lines, then percentages of the well are taxed by each each county. The counties are supposed to agree on the split - such as 75% / 25% or 90% / 10%. If the tax statements are for closed years, it may be difficult to download the details from P&A website. Be sure to save the 2023 data in folders on your computer.
The tax statements I am comparing are for 2022 for Midland CAD, Martin County, and Martin CAD. The taxing entities are all different, as they should be - correct? Germania 45 wells appear on all 3 statements, as I believe they should - all different taxing entities (schools, hospitals, etc) and the wells span both counties. My quandary is understanding the Germania Sprayberry unit. The GS unit is listed on my DO, but then not listed on any revenue statement or tax statement I have received. Instead, the 2 revenue statements and one tax statement I have received (from MIdland CAD) refer to GS TR 2, GS TR3, GS TR 2 Dean and GS TR 3 Dean. I know that GS spans multiple abstracts in Midland County and one abstract in Martin county. It is logical they would have to divide the description of GS into multiple references because of the county boundaries. My request for clarification from DO Analyst supervisor has gone unanswered for 3 weeks. I found the legal document that defines GS, but cannot locate any legal document that defines the apparent subdivisions. Nothing related to GS appears on the Martin County or Martin CAD tax statements despite there being a large block of wells drilled in the same fashion as Germania 45. It is my belief that the GS TR 2 and GS TR3 are the correct tax entries for Midland county and the GS TR 2 Dean and GS TR 3 Dean are supposed to be Martin county - I believe these have been mis-reported by the operator to P & A, resulting in the quandary. It is also my belief that whether revenue is reported by well, lease, or unit there should be only a single tax entry in any county for that production. What say ye?
Thank you for the reading material. I read the short article and it is very interesting for background - my first read makes it sound like the RRC initiated the unitization, rather than an oil company. I will read the longer study later today.
I reached out to P & A with my concerns and have received a response I am still trying to digest. They advised that if a horizontal well spans multiple counties the counties agree to a split on the revenue and taxation rights. According to them, Martin county agreed to a 0% split on a portion of the Germania Sprayberry unit.
The operator provided me with a spreadsheet that identifies 3 wells as being Germania Sprayberry Dean TR2 and about 38 wells identified as Germania Sprayberry. None of the revenue or tax statements refer to Germania Sprayberry - only GS TR 2, GS TR 3, GS Dean TR 2 and GS Dean TR 3.
GS Dean TR 3 appears on Midland County tax rolls, but does not appear on my revenue statements leaving the impression that I am paying taxes without receiving the revenue.
When the unitization was started and the only wells were vertical, I could understand a 0% split being based solely on the contribution of the vertical wells in one area (county) vs the rest of the unit.
Looking at the RRC maps, I have a group of 9 wells that are listed as Germania Sprayberry and a group of 12 wells listed as Germania 45. All 22 wells are drilled in abstract A-210, pass from section 33, thru sections 40 and 41 and terminate in section 45. Why would one group of wells in the same physical area be shown as not in Germania Sprayberry and have an apparent revenue taxations split of 17% vs 83% between the counties, while the other group drilled literally right next to the Germania 45 wells, remain in the GS unit and have a 0% vs 100% split?
All references to GS is abbreviation to Germania Spraberry. In my experience, oil companies pay royalties for wells or units which cross county lines on the well or unit basis and do not reference the counties. The counties are prohibited from both taxing 100% of the valuation, as that would double every owner’s taxes. The counties agree to some percentage split of the value of the unit or well as a whole. In your case, it sounds like the counties agreed to differing splits of the tracts, perhaps based on the percentage of the tract in each county or some other agreed basis. It does not adversely affect you as you will still be paying 100% of the taxes owed, because the assessed value is divided between the counties. Many owners pay taxes allocated between two counties, even though their minerals are physically located within only one county. At the same time, they receive a single royalty payment for the well or unit or tract as that is calculated without regard to county lines. Maybe you could compare this to a pro baseball player whose team and residence are in Kansas and who gets one paycheck. At the same time, California will tax him on that percentage of his salary for games played in California. He will have to file state income tax returns for both Kansas and California and allocate his income between the states. Baseball makes it easier by giving him a separate W-2 for each state. Of course, it is really more like 10 states.
Usually, if I at first don’t understand a post, if I go away and come back another day, the meaning will sink in.
How can a set of 9 horizontal wells be considered part of a unit when the wells extend beyond the boundary of the unit? And, the county tax split still be held to an agreement that was based on solely vertical wells, when the production from a horizontal wells obviously has a much different produced area?
It goes to the slicing and dicing of lease rights. Many old leases had no depth severance clauses and so any single producing well holds all the acreage and depths. Suppose shallow wells are drilled at 5,000 feet and then Unit #1 of 500 acres is formed. The unit will be depth restricted to a formation or part of formation, let’s say 4800-5200 feet. Lessee A keeps the leasehold in unit and sells deeper lease rights to Lessee B. Lessee B drills wells in a deeper formation, say 7500-8000 feet. Those well can be only on the lease acreage or Lessee B can form Unit #2 for these depths but this unit is 700 acres and a different shape outline from Unit #1. Surface overlap might be only 300 acres. Lessee B sells deeper rights to Lessee C who drills horizontal wells under part of your lease and an adjacent section which is not in not in either Unit #1 or Unit#2. Lessee C may form Unit #3 for 1200 acres in yet another formation such as Wolfcamp. In each of these cases, your royalty DOI will be different and based on the allocation formula specified in the unit agreements. (Lessee C may have also called its horizontal allocation wells between the 2 sections and base the DOI on percentage of productive horizontal lateral wellbore in each section.). Your ad valorem taxes in each case will be determined by the overall unit or well valuation times your decimal interest. So even if each unit was valued at $ 5,000,000 then your tax value will not be the same because your royalty decimals are different. And the counties will only split the values for the units which are in both counties. So if Unit #1 is in 2 counties, then each will tax you in part. If Unit #2 is only in one county, that county will tax you in whole. You think of your minerals and all production as one lump because you only have one oil and gas lease. The county thinks only of each unit or individual gas well and does not care if you have one or ten oil and gas leases.
Based on the info I received from Pritchard and Abbott, the wells that I have royalty interest in that are described on my DO as Germania Sprayberry (GS) unit are actually divided into 2 tracts in 2 different formations (units) and are being referred to on my revenue and tax statements as GS TR 2 and GS TR 3 and GS Dean TR 2 and GS Dean TR 3. Should my operator list those 4 entities on my DO if they are going to report revenue and taxation on that basis? Obviously, I drew a false conclusion with regards to the unit/tract divisions being done for taxation purposes across multiple counties. Are there any rules operators are required to follow so that a royalty interest owner can track their holdings from DO to revenue statement to tax statement?