I’m confused. As Eckard Enterprises explains mineral rights ownership and how revenue is determined, all that’s required to qualify is ownership of some mineral rights within a -section- of land in Oklahoma (forced pooling):
However, in a reply I just received from an EOG rep, my father doesn’t “qualify” for revenue from Laubhan 0409 #5H, because (supposedly) it’s on the “other, western half” of Section 4:
“…the ownership of is within Township 8 North, Range 4 West in McClain County, Oklahoma is within the eastern half of Section 4, which are lands pooled into the Laubhan 0409 #1H, #3H, and #4H wells. The Laubhan 0409 #5H, on the other hand, pools land from the western half of Section 4. Because the ownership is beyond the pooled area for the #5H well, is not credited with an interest in its production.”
What am I missing? Pooling happens by entire Section–not “halves” of a section! The rationale EOG is using here is very different from what Troy from Eckard Enterprises spells out very clearly.
Typically, the unit is an entire section. The vast majority of time the unit is the entire section, but not always. Mr. Eckard talks about sections, but he doesn’t say that 640-acre units are used all the time. emphasized text
In section 4-8n-4w, the spacing is for a 320 acre stand-up unit, meaning it runs north to south. It also only covers the west half of section 4.
Creation of Drilling and Spacing Units: The Applicant requests an Order establishing a standup 320-acre horizontal drilling and spacing unit for production of hydrocarbons from theMississippian, Woodford and Hunton common source of supply underlying W/2 Section 4,Township 8 North, Range 4 West, McClain County, Oklahoma:Common Sourcesof Supplv Classification Depth Unit Size-AcresMississippian Oil 9,000’ 320-Acre StandupWoodford Oil 9,142’ 320-Acre StandupHunton Oil 9,292’ 320-Acre Standup
It’s just that the more I hear about Division Orders (esp. from what Martha Barnes has noted about them), I get the feeling that it’s probably better to shred any DO you get from an oil and gas company, fill out and send the NADOA_Division Order Model Blank Form to them, and if they reject it, then just wait until forced pooling kicks in (no idea how long that would take)?
Either way, it sounds like mineral rights owners get ripped off in the end, unless you’re willing to pay an oil and gas lawyer to rewrite the DO for you and battle it out with the oil company (who, as I understand it, doesn’t have to accept any modified DO you send).
I wish Troy had mentioned that in his video; however, am I right in assuming that if my father had not signed the EOG Division Order, he would have qualified for revenue from Laubhan 0409 #5H due to defaulting to Oklahoma’s /entire section/ forced pooling law?
My point being: if any oil and gas company can–at will, through a simple Division Order–carve out any chunk of land and potentially exclude the mineral rights ownership of half that section (or more), then it’s probably rare that anyone would really want to sign a DO in the first place–unless you get lucky with 1/4 royalty and a definition that includes the entire section?
Do not confuse the Division Order with the Pooling Order. The pooling order is before drilling and will list the area that is to be drained. Many horizontal ones are for a complete ~640 acres , but some are not -in this case. Force pooling is effective as of the date of the order which is before drilling (except in unusual cases). The force pooling is in lieu of a lease in case an owner cannot be found or does not wish to lease. (I would consult an attorney on any lease.)
The Division Order timing is about five months after the drilling and applies to all royalty owners. It is the contract for delivery of royalties to the legitimate royalty owners at the decimal amount specified. You do not have to shred all of them. Many of the operators use the NADOA language. Care should be taken for any DO that does not have that language as it may change the terms of the lease. If using the NADOA language, it does not have to be re-written by an attorney as the National Association of Division Order Analysts have agreed upon the language. The critical items are your contact information, the minimum royalty payment (I set mine to $25) , no changing of the lease language and the correct decimal information. Be sure and return the W-9 with it.
Actually, both the Pooling Order (done by the Oklahoma Corporation Commission) and the Division Order (contract between the Operator and the Royalty owner) are to keep business moving ahead and get operations done in a timely and legal manner.
Following up on what Martha said, the Division Order had nothing to do with your father not being in the unit.
It is the spacing order. The drilling and spacing unit was established for the west half of section 4. It did not encompass the east half. Your father’s only remedy would have been to protest the spacing order if he thought is wasn’t correct. But, to do that, he would have had to have a geological expert to testify at a hearing before the OCC.
Thanks Martha; so (to make sure I understand this correctly): As long as an oil and gas company produces or offers a lease or Division Order, they reserve the right to stipulate–within any section–exactly where and how much land their wells are subject to paying revenue to mineral rights owners?
Yes, as Tim said, it is all related to the spacing order (usually done way before the pooling order) which says how many acres can be drained by a particular well or wells. See the paragraph above that Tim posted regarding the 320 stand up acres. Here is the map exhibit. Some of these orders are just different than the average ones. The east side of the section is covered by a different spacing order.
