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Oil/Gas/Submitting our own DO for a fixed NPRI

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QUESTION: Hi there, I am one of five siblings who have NPRI royalty interest in Karnes/Wilson County Texas and EOG Resources send us a DO (Division Order) number but that figure was based only on if we agreed to ratify the pool agreement. We have two horizontal wells traversing our tract. One in one unit and another in a second unit because our tract crossed the border of the two established units. Based on the Royalty Deed signed by our grandfather in 1929 it appears to be a fixed NPRI and in it it says "it is understood and agreed that said on-sixteenth (1/16) interest is and shall aways be a royalty interest, and shall not be charged with any of the costs which the Grantee may incur in exploring, drilling, mining, developing and operating wells or mies for the production of oil, gas and otehr minerals.... interest shall be delivered free of costs to the Grantor at the wells or mines r to the credit of Grantor in pile lines or storage provided by the Grantor.
BUT, then it seems to contradict itself by further addition of "It is experesly understood that the Grentee shall never be required... to drill... and that any wells or mines discovered or drilled by the Grantee may be abandoned or operated by him at any time at his election or discretions provided that, before Grantor's royalty shall be calculated and determined, all oil, gas and other minerals used for light, heat and operations by the Grentee and ay taxes against the production shall be first deducted". This was written in 1929.
My question is do we just use the same basic form of the DO EOG sent us and just change the interest percentage? It would be .0125% for each of us since that is 1/5 of 1/16th.
Given these are horizontal wells traversing a total of 10 tracks can we expect a full 100% non diluted percentage? If not, what are companies typically paying fixed NPRI holders when wells do in fact traverse their tract and how is that deteremined?
The DO they gave us includes the description of the entire Units, each over 1000 acres and we have approx. 45 & 5 acres in one of each. Would we need to change that wording to just include our acreage?
Appears each well starts out in Wilson County but ends in Karnes County which is where our tract is.
Is there a standard form out there we should be using? Can you tell me where to find it?
THANK YOU SO VERY VERY MUCH. I hope my questions make sense because all of this is so very confusing! - Karen.

ANSWER: You have asked several questions, so I will answer one at a time, in the order asked. If I am understanding your entire post correctly, I assume that currently there is no valid and existing oil and gas lease covering the mineral rights. If that is incorrect and there IS a current oil and gas lease, as a non-participating royalty owner you have the option to either ratify the current oil and gas lease or to ratify the unit(s) that include all or part of your tract.

If you change the percentage on the D.O. sent to you by EOG it will be rejected. I will circle back around to this question to explain more after I have answered your other questions.

No, you cannot expect a full 100% non-diluted percentage UNLESS you have a horizontal "take point" directly beneath your tract or within 100 feet of the boundary of your tract. A take point is a perforation in the casing through which oil or gas is physically entering the wellbore so it can be produced out. You need a copy of the "as-drilled" well plat to determine the location of the take points in relation to your tract. The as-drilled plat must be submitted to the Texas Railroad Commission in Austin by EOG in order for the TRRC to approve the actual well as meeting all of the state's spacing and other requirements. You can check online on the TRRC website and can get copies of plats and other documents that the TRRC has processed and placed there for public viewing and download. If you can't find the as-drilled plats there, at least note the TRRC Lease number and the API number for each of the two horizontal wells. You can then call the TRRC and give them that information and possibly arrange for them to mail you a copy of the as-drilled plat that was submitted to them by EOG for each of the wells.

If there is not a take point directly beneath your tract or within 100 feet of the boundary of your tract, then you are not due any royalties whatsoever unless you ratify the unit (or ratify the lease if one currently exists).

No, you don't need to change the working of the legal description because it already includes your tract in the Designation of Unit that is probably referenced in the legal description: "as described in Unit Designation recorded in Vol. XXX, Pg. XXX, Karnes County, and Vol. XXX, Pg. XXX, Wilson County, Texas" or something to that effect.

There is a "standard" D.O. form, and you can find it at www.nadoa.org. Click on "Publications" at the top, scroll down to "Model Form DO" and click on the "Model Form" button. It will allow you to download it as a PDF.

Now back to your first question: if the D.O. you received was printed using the Model D.O. form or one containing ONLY the clauses found in the Model D.O. form, then if you do not sign EOG's division order exactly as they have prepared it, they will reject it and you will not receive any revenues until you sign the form. That's because the Texas Statutes say that if EOG uses only the language found in this form, and an owner refuses to sign it "as is", EOG can withhold payment until the owner signs. If you don't have any take-points, you might be wise to ratify the unit as they are requesting, so you can receive revenues.

Please feel free to post a follow-up question if you still have any.


---------- FOLLOW-UP ----------

QUESTION: Thank you SO VERY MUCH for your response. I do have some follow up. You wrote "I assume that currently there is no valid and existing oil and gas lease covering the mineral rights". I'm not sure what you mean here?

Regarding the "take points", I found them on the TX RRC website and while speaking to a RRC employee in mapping. The horizontal wellbore only indicates the penetration point with a "first take point" in the beginning and a "last take point" just before the terminus location.

The gentleman at TX RRC told me that the wellbore from the first to the last take point is producing all the way down but that the oil company is not required to show every other take point down the line.

These wellbores literally cross over 10 separate tracks of land, some only slightly wider than others, with our tract near center so that first and last "take points" aren't on or w/in 100feet of our tract but the wellbore, acc'd to the RRC, is procucing all the way.

Therefore, does that qualify as us having "take points" on our tract so that we are entitled to a full 1/5th of our 1/16th for production of gas and oil?

Because it makes sense there isn't just the first and last take point pulling minerals out of the ground.  The RRC man said there was no more specific map but if you know there is please advise.

Finally, since we are one of 10 seperate tracks and we do have a producing well traversing our tract, would we expect a reduction based on the number of tracts this wellbore crosses? The RRC man said they cannot tell where the majority of the minerals come out of at any given point of the wellbore so how could we know if our tract is producing better or worse than other points?  I know if it were a vertical well we'd be entitled to 100% of our percentage but not so clear on what we should expect given these are horizontal wells?

Any light you can shed is so Greatly Appreciated!! Thank you in advance.

Answer
Based on the additional information you've given me, then as long as the wellbore lateral is passing directly under your tract or within 100' outside any of the boundaries of your tract, then your tract is considered a "drill site tract".  Now that we've settled that, we still have the problem of determining exactly how much royalty you are supposed to receive.

Does the deed or other conveyance document that created the NPRI in the first place state that your royalty is 1/16 "of the lease royalty" or does it only say "1/16 of the [production] produced and saved"?  The language in the deed makes a big difference as to how much you are to get.  If it says "of the lease royalty" then yes, you need to know if there is a valid and existing lease that was signed by whoever owns the executive mineral rights--is it a 1/8 lease or 1/6, 3/16, 1/5 or even a 1/4 royalty-clause lease?  With "of the lease royalty" language you would be entitled to 1/16 times the royalty rate reserved in the lease.

But if you have "of production produced and saved" language, then you are entitled to 1/16 of the total production from the well times the measured distance of the lateral beneath or within 100' of your tract divided by the total length of the lateral measured between the first take point and the last take point, or measured between the penetration point and the terminus, depending on how the operator of the wells is doing it.

Hope this helps clarify a bit more.

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Marsha Breazeale, M.Ed., CDOA, CPLTA

Expertise

All questions regarding division orders; ownership decimal calculations; title ownership and payer record changes (testate/intestate inheritance; deed; assignment; court order); oil and gas lease analysis for record-keeping and purposes of payment by operator or payer; pooling, horizontal wells, horizontal well allocation units; unclaimed property reporting; royalty owner relations questions. All questions concerning administration of surface land contracts and payment questions, such as for Surface Right-of-Way, Sub-Surface Right-of-Way, Easement, Surface Use Agreement. All questions regarding industry-standard and company-specific policies that affect land owners.

Experience

Sr. Staff Division Order Analyst. Certified Division Order Analyst (CDOA, National Association of Division Order Analysts) and Certified Lease Analyst (CPLTA, National Association of Professional Lease and Title Analysts) with 35 years of experience as a combination division order analyst and lease analyst in exploration and production in the oil and gas industry.

Organizations
National Assoc. of Division Order Analysts (NADOA), National Association of Division Order Analysts (NALTA), American Association of Professional Landmen (AAPL), American Society of Trainers and Developers (ASTD)

Publications
"How an Oil & Gas Exploration & Production Company Operates" and "Principles of Oil & Gas Lease Analysis: Standard Clauses", Oil Patch Press; Articles in NADOA Magazine; LandFocus EDU Professional Training Manuals

Education/Credentials
B.A.in Management from Our Lady of the Lake University in San Antonio; M.Ed. in Instructional Design from WGU Texas.

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Past 15 years: GeoSouthern Energy Corporation; Contango Oil Co./Crimson Exploration & Operating Inc.; Apache Corporation; BP America; Marathon Oil; Newfield Exploration

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