Q1 You need to research from the formation of the NPRI forward to see who has the executive right to lease. Originally, X owned minerals and granted the NPRI out of his interest to B. You will have inherited the NPRI from B down through its various owners. Once you find the original grant and know who X was, then you search forward through the deed records to find who now owns X’s executive rights. This could be multiple people. If X died and his minerals went to his 4 children and they still own the interest, then 1/4 of your NPRI leasing comes through each child. And they may have leased to different companies and over time each lease may have been assigned, in whole or in part, to other companies. This can get complicated. When you research, consider entering data on spreadsheet pages, including the document date and recording data (book and page or document number). Do it a little at a time to not get overwhelmed. Q2. First, the division order will only list wells which the oil company operates. If there are 113 producing wells and 5 operators, then you would need division orders from each operator. Second, the division order would not list plugged wells. Shut-in wells would be included because they can be opened up at any time, assuming that the lease is still in effect. Third, some operators will only send division orders listing one of the wells under the same RRC lease number, but will pay for all of the production, on either an individual well basis or as a whole RRC lease basis. You can match the oil production volume for the lease against the volume on your check detail.
@TennisDaze, thanks for your always thorough and accurate explanations. Much appreciated!
TennisDaze,
Thank you for the informative post. Just to clarify my situation. On the division order I received, of the 55 wells listed, 5 are plugged, 6 are shut-in and 1 is listed as no prod. The plugged wells were plugged at least 2 years before the division order was presented. This led me to believe that all wells physically located on the 4518 acres I have an interest in or are drilled into that area should be listed. Based on your post, it makes sense to me that the plugged wells should not be listed. The 113 wells I am referring to are all listed with the same operator. 55 of those 113 wells appear on my div. ord. presented to me by that operator. 14 producing and 14 shut-in wells in the list of 113 are not included in the 55 wells on my division order. The majority of the not included wells are in lease 21487, but 2 wells from that lease are included. Doesn’t this imply the operator has the information to include all these wells and is not using a single well to represent multiple?
Germania Spraberry Unit is a huge unit with many plugged wells. Unit formed in 1970 by Gulf Oil and covers 4848 acres - sections 31, 33, 40, 41, 42, 43, 44, Block 36, T-1S and N/2 of Section 5, Block 36, T-2S. Per Margro deed, you own in Sections 33, 40 and 41 and not in the other sections. I got the unit sections from the scanned RRC records which shows the 1970 plat for the unit. It is possible that the unit boundaries were changed over the years and you will need to trace that through the deed records for any filings relating to the unit. Your DOI is 100% of the interest in those sections and not based on the unit acreage as that would be a much smaller decimal. Therefore it may be that the operator will pay on 100% of the royalties for the production attributed to the producing wells where you own minerals and no royalties for the producing wells in other sections. You need to go to RRC website to see which wells are producing in your sections and see how that corresponds to your list.
I am somewhat confused by what you are telling me. I inherited from “B” an overriding non-participating royalty interest of .00002766. I have researched the RRC site which shows that the 7 complete sections of land that I own an interest in are described by 9 abstracts - Martin county A-210, Midland county A-1364, A-1380, A-683, A-788, A-126, A-559, A-740, and A-940. In addition, I own rights in some wells drilled horizontally from A-487 into A-126. When I examine those abstracts and verify the Block, Section and Township match my holdings, I find 113 wells operated by the same operator that issued me a division order showing only 55 wells and omitting 14 producing and 14 shut-in wells. Is not the fact that these wells are directly drilled on the parcel in which I have interest or drilled into my parcel sufficient proof that royalties are due (If under production)? I understand that lease 21487 includes wells that are on the property in which I have interest and also wells not on that property. I do not expect royalties from wells not on property I have interest in unless horizontal drilling includes my property. I have not yet researched for that situation.
What do you mean by DOI?
I greatly appreciate your continued posts and assistance.
Some more of my back story: I was contacted by three different parties wanting to purchase my mineral rights (which I did not know I had). I researched TX Unclaimed Property and found and claimed funds escheated in Margro’s name by multiple companies dating back to the 80’s. After successfully claiming that, I set my sites on the company that escheated the bulk of those funds. I, naively, expected the process to be about the same - prove heirship and be put on pay list. Initially I was considering selling my interest, but thought I should try to understand what I held, so I could better evaluate offers. That led me to the RRC research and discovering what I consider significant omissions form the division order. My main goal it to get to a division order that includes all wells to which I am entitled revenue from.
I have considered involving a landman or attorney, and may still do so. My dilemma is that the attorneys I have spoken to so far have quoted prices that would consume all revenue held in suspense and then some. Then there is the question of what expertise do I need to hire. It seems to me that if I am correct about the inaccuracy of the division order and if the company continues to balk after I send new, more precisely worded requests for change via certified mail that I will possibly need a litigator to resolve the issues, but I am not likely to be able to afford that unless they see the situation as a slam dunk and will take the case at least primarily on a contingency basis.
DOI is shorthand for the royalty decimal of interest, which is the decimal which will be appear on the check stub and be multiplied against the gross revenue to determine your net royalty payment. I do find it odd that a single division order lists all those wells. However, if you agree that the decimal is correct for the listed wells, why not return the division order to get into pay on those wells? Then you can continue to pursue getting paid on the missing wells. A normal D.O. does not contain any language that you agree that these are the only wells in which you own an interest, only that the stated decimal (DOI) is correct for the listed wells. You will not get paid interest on the royalties which are being withheld pending return of the D.O. And you will be assessed ad valorem taxes by the counties based on your decimal. You should check the CAD and Tax Assessor websites to see if current or back taxes are due under either your name or that of your predecessor as otherwise the county could foreclose.
Thank you for the clarification on DOI. I sent in a signed division order on 12/9 and after 10 days asked for a confirmation of receipt only to be advised that it had just arrived on the individuals desk the day after I asked for confirmation and since they had advanced payments due to Christmas, she would not implement the DO until after Jan1, which means no payment till almost February. I am not comfortable with the DOIs listed, but have decided to accept recommendations of others to sign and submit. At least I have a paper trail of objecting to the DO. I do not know what the norm on DOs is, but I sure feel like if they are going to list 55 wells, they should list all that I have interest in. Your suggestion about taxes is a good one. Interestingly, I was advised in July that the transfer of ownership from Margro to my SIL and myself occurred on July 1. A thorough search of tax records showed no entries in SIL name, my name or the name under which funds had been escheated. Hovever, since July, 28 tax records have been created in the married name of the original owner - a person who died 22 years ago. I am working with the Midland County Central Appraisal district to try to correct this situation. They advised me this situation would be a direct result of the operator providing them that information.
Just an update and perhaps another question or two. I have now been added to the pay list and received a payment for suspended funds. In addition, the next day, I received a DO addendum adding an additional 8 wells to my DO bringing me to a count of 63 vs 116 now identified on the RRC site. By reviewing the 334 page revenue statement that came with the payment, I have found references to Germania Dean Unit TR2, Germania Sprayberry Unit TR2 and Germania Sprayberry Unit TR3. I am unable to match these entries (with confidence) to entries on the DO.
Should a proper DO list each well or is it appropriate to list a Unit Name to represent multiple wells? If the Unit name is listed, how does one determine which wells are included?
Is a NPRI owner bound by a Unit definition, even if no record can be found of the original NPRI owner agreeing to the Unit?
How does one find the Unit agreement if the original NPRI owner never signed a document agreeing to it?
I really appreciate all the helpful responses I have received.
The Unit Agreement would have been filed in county deed records and signed by operator and working interests. If leases authorized pooling then those mineral owners would not need to ratify or consent. I think that if NPRI ratified the lease and the lease authorized pooling then the NPRI would not need to ratify the unit. If NPRI does not ratify the lease, then payment by mineral tract and not by unit. So you need to look for ratification of the lease(s) and then review the lease terms. However, if the prior owner signed DO for unit and accepted payment, then that might constitute consent to lease and/or unit under case law. Ask your oil and gas attorney. DO commonly list only a unit and not the individual wells.
I have now identified 126 wells in which I have royalty interest. 11 addendums to the div order and responses to certified letters have brought the total accounted for to 95. Discounting plugged wells, I am very close to being in sync between RRC research and the Operator.
I asked for clarification on a list of 22 wells and was told they are in “units”. I have asked them via email (the way they answered my certified letters) to explain what is included in each unit and for an explanation of the “UPF” (unit participation factor) for each unit. So far, I have been ignored. I am getting tired of sending certified letters at $8.35 a pop. Am I out of line in expecting them to explain the way they calculate my pay percentage on these units and confirming which wells are included? I am particularly concerned because the DO shows Germania Sprayberry Unit. However the revenue report does not show that, but does show Germania Spraberry Unit TR2 and Germania Sprayberry Unit TR3. In addition, tax reports I have been shown List each of those units (TR2 & TR3) twice with different values and property ids that do not match any other documents I have found. How does one balance anything?
In the past shallow wells were often drilled on a lease basis. As production declined, it became economic to form a larger unit with some wells converted into injection wells (usually formation saltwater) to “push” the oil toward other wells. Royalties were not just calculated on an acreage basis. Operators took into account the historical production of the wells, the geology which caused oil to migrate toward certain wells and other factors to estimate the relative future productivity of the various tracts. This was translated into unit participation factors for each tract. So if wells on one tract were twice as productive as those on another tract, that tract was given extra weight in calculating the royalty decimal. This tract factor is listed in the original unit agreement which you can purchase from county deed records. Or maybe ask the operator to email a copy. In essence, your unit DOI would be determined by your lease royalty rate, the tract acreage within the unit acreage and the tract participation factor. Some unit operators pay on the unit basis for the unit DOI. Others pay on a tract basis, where then royalty DOI is your tract royalty and it is paid on the production allocated to your tract from the unit. Your tract decimal is larger than your unit decimal, but it is paid on smaller volumes rather than 100% of the unit volumes. So your net royalties are the same either way. The property tax statements from the county are based on a present value engineering valuation based on the future economic life of the well and the average oil and gas prices in the prior year. County will assign its own account number and other ID number, but should reference the RRC lease number on the appraisal. Sometimes separate appraisal values are done for oil and for gas so perhaps that is what you are seeing. Or perhaps you received both a current year tax statement and an unpaid prior year tax statement. As you can see, it takes a long time and a lot of study to absorb everything.
Again, I want to thank all who have responded to this thread with info. I see the thread will close in 3 days, so I am torn as to posting again here or starting other threads.
I understand the concept of multi well leases or units from an injection well perspective. However, when an operator comes in and drills multiple horizontal wells in that area at a later date, do they have any legal right to claim those wells as part of a unit? It seems to me this would be highly disadvantageous to the owner of the rights to the property that the horizontal wells are drilled thru. I notice that newer wells drilled in the same area are not considered part of the unit and are reported as one well per lease. If I am not explaining this well, please look at Martin county abstract A-210. Half the wells in that abstract are claimed to be in the unit and half are listed individually. My royalty rights cover the abstract that all these wells are drilled in, all the abstracts they are drilled under, and the abstract in which the wells terminate. Since the wells are claimed to be part of a unit, I have not found a way to cross check the production with the RRC data.
Is there a way to use RRC data to determine the pool size of a well? How?
I have been working to get tax records in my name and pay appropriate property tax on my mineral interests. I own a very small percentage of the revenue generated from a fairly good number of wells. Property taxes are based on an assessment of 100% of the well value. If the annual property taxes for a well exceed the annual revenue, that is a negative cash flow situation. Would this not mean that the operator is also in a negative cash flow situation and would they not immediately plug the well and cease production changing the tax value to zero?
Analysis of the TX Unclaimed Property records indicate that there were multiple years during the past 20 when no funds were escheated despite no significant change in production. Should I have access to the revenue data for the past 20 years (going back to when I inherited)? How do I obtain that info?
First, it appears to me that there are two RRC Oil Lease ID Numbers in Section 210. Lease name Germania Spraberry Unit, RRC 08-21487, has 45 wells, some of which are vertical and some of which are horizontal. Lease name Germania 45, RRC 08-49324, has 12 wells. So these 12 wells are being reported to RRC together, not individually - but may be reported individually on a check detail. If they are reported individually on your check stub, then you have to add up all the volumes to compare to RRC Lease Reports. An RRC Lease number can contain multiple wells without having the word “unit” in its name. The difference between them is that Germania Spraberry Unit wells are in Spraberry (Trend Area) Field and Germania 45 wells in Spraberry (Trend Area) R 40 EXC Field. You can find Field Rules on RRC website with links to the RRC Orders. Fields can overlap in area and even formations and depths. Second, the property tax valuations are made on 100% of the well or RRC Lease, but your tax is that value multiplied by your royalty decimal. So you only pay tax on your interest. So if Germania 45 RRC Lease is valued at $10,000,000 for all wells and your royalty is 0.00010, then you will pay tax on a value of $1,000. If you are receiving current income and paying current taxes, the taxes will not exceed the income. Should not be more than 3 to 5%. It you are in suspense for revenues but still paying taxes to keep your minerals from being foreclosed, that would be a different situation. When you receive your Appraisal Notices, then you need to look at the listed DOI to make sure it matches your interest in the wells and is not overstated. Third, the permits will outline the acreage and area covered by the wells. For example, the Germania 45 19H permit notes that there are 1312.1 acres.
Once again, TennisDaze, thank you for your informative response. I realize that I made at least one mis-statement in my previous post and I appreciate that you dug far enough into the data to correct my misstatement - there are 2 groups of wells in A-210 and each group is associated with a lease number. What I was trying to question was why one group was reported by well and one group by lease on my DO and revenue statement. Is this type of inconsistency in reporting just the norm?
It is common for newer horizontal wells to be reported separately on your check stub. Sometimes there are different mineral owners or working interests in the various wells so not all the DOI are identical for every well. Operators generally do not change the reporting method for older units from a unit to a well basis. I have seen where one operator reported each well separately and the successor operator decided to report the horizontal wells combined. There was a formal unit declared and all interests were the same.
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