the increased density filing (Case # 201902847) at this website: OAP
I’m trying to understand all the pieces to this minerals puzzle. I’ve read many articles as suggested in the topic “Basic Info for Oklahoma Mineral Owners”. But still have questions. And I realize that I’m jumping ahead to something that hasn’t happened yet (and may not happen), but just curious about the process.
(1) If we already receive royalties (and presumably have a lease) for existing wells, does that affect any new drilling by a different company? Would we negotiate a new lease for the new well? Or does an old lease cover all future drilling in the section by any other party? I’ve recently seen the term “held by production” in other topics. What does this mean?
(2) What incentive does an oil company have to negotiate leases with all the many mineral owners? Seems like a lot of work for them. Wouldn’t it be easier (from their perspective) to pool everyone? Does that influence their negotiation tactics?
Thanks as always for your help! This forum is a wonderful resource!
emphasized text(1) If we already receive royalties (and presumably have a lease) for existing wells, does that affect any new drilling by a different company? Almost universally not.
Would we negotiate a new lease for the new well? Typically not. If you have a lease that is restrictive or allows for acreage or depths to be released, you could be unleased. But, not typically.
Or does an old lease cover all future drilling in the section by any other party? Typically yes.
I’ve recently seen the term “held by production” in other topics. What does this mean? An oil and gas lease stays in existence for a limited term and as long thereafter as oil and gas is produced. Held by production means there is production on the leased tract or unit and therefore is still a valid lease.
(2) What incentive does an oil company have to negotiate leases with all the many mineral owners? Seems like a lot of work for them. Wouldn’t it be easier (from their perspective) to pool everyone? Does that influence their negotiation tactics? Typically, the oil company want the acreage and they don’t want a competitor to pick up the leased acreage. Also, the lessee with the most acreage is usually named the operator, and every company wants to be named operator.
Thank you tim_dowd! This is starting to make sense but I’m still a little confused.
In our example, Sanguine is the operator of the current wells in production. Kaiser-Francis filed for increased density. So if K-F actually drills the horizontal well and it begins producing, then our terms would be the same as the Sanguine wells? In other words, we would not have any decisions to make? And Sanguine would be the operator of the K-F well?
We recently received an unsolicited offer to purchase. I believe they were purchasing for an “investor” but my family member did not ask for details. Is it possible they were purchasing for either Sanguine or K-F to ensure they have more acres? Or am I missing your point here?
I guess I finally need to take the advice of many postings and the suggested documentation, which is: get a copy of the lease. That may be tricky if my family cannot locate it in old paperwork. But I’ve read that I can contact the operator and they may provide a copy for me. We are still working to get the inheritance sorted out, so I may have to wait until that is done.
I am hoping that you have the original lease agreement in hand!
In that agreement should be the identified formations for exploration/development. Look for restrictions in that agreement . . . . depths, formations, primary and secondary recovery operations and possibly tertiary recovery operations. "Primary Recovery" is the initial drilling and production operations without any other type of production operations. "Secondary" recovery operations cover "Water Flood Injection operations" for the same formations. "Tertiary" recovery operations usually include CO2 Injection operations and are the last efforts for production.
The most important item one should pay attention to in the lease agreement is "Definition". If there are depth limitations in the agreement, that is a very good thing! If there is not, then other formations "Deeper or Shallower" are included in the agreement and the royalty is the same.
I will use the terms typically or generally. Every section and ogl may be a little different, so there are no absolutes.
Generally, yes, the terms of the now-Sanguine lease will control the payment of royalties, etc. on the Kaiser-Francis well.
Since it is an increased density well, the new well is being drilled in the same formation, so the prior lease is applicable.
You will likely have better success in securing a copy of the ogl, depending on your county, going to okcountyrecords.com, locating the lease and paying for a copy.
the purchaser is very likely not purchasing for Kaiser-francis or Sanguine. In all likelihood, they would tell you that.
A related issue is whether the existing production in a spacing unit (usually 40 acres for oil and 640 acres for gas in OK) is producing in paying quantities. If you have a release of lease, there’s no issue whether your minerals are held by production. If you have substantial mineral acreage in a spacing unit but are receiving only a few dollars per year in royalties, you need to determine if the well(s) in your spacing unit are commercially viable. Look at your royalty check detail printouts, OK Tax Commission’s Public PUN well production data, and the OK Corporation Commission’s well production data to determine the well’s revenue, then attempt to determine the well(s) expenses: the cost to get the minerals to the surface, transportation costs, administrative overhead, etc. Don’t include royalties or costs to drill the well as an expense here. Compare revenue vs expenses. If revenue is substantially less, send a letter to the operator (from your check detail and from the OCC web site) for a release of lease. Many operators will dig their heels in even if they’re clearly wrong–there is no advantage to them in granting you a release of lease. If so, ask he operator for revenue vs expense data. My experience is they will not provide that data. You may have to hire an attorney to write the operator a release of lease demand letter. OK Statute 41-40 states that operators have 30 days in which to file a release of lease in the appropriate county courthouse, without charge to you. The gold standard here is to get the OCC to require the well to be plugged and to be annotated as plugged and abandoned on the OCC web site. For gas wells, if a non-producing well’s casing will pass a pressure test (OCC can require the operator to do this), then the operator is not required to plug that gas well. Obviously, if you have not received a check from your well(s) in a spacing unit for some time and you are not under a “shut in” situation (a temporary shut down of the well), then the well is not commercially viable. The point: clean up your old leases by getting a release of lease on spacing units which are not commercially viable and you won’t have to wonder if the operator will try to hold your lease by production when a new potential lessee knocks on your door.