Would anyone be kind enough to share any information they may have as to leasing in this and adjacent sections? I've got an offer to lease at $4000-1/4 and $4300-3/16 from Prairie. Is that competitive at this time?
Less than 10% difference between 1/4 an 3/16 on the same offer?
I leased in 9N 7W at $5500 an acre, 22% and tough Exhibit A mid 2017.
I got a really good offer in grady. The company is leasing all over grady from my understanding. Can send you info if need be, feel free to add as a friend.
I know. I found that interesting. Makes a choice easier!
I am near you in 9N8W and wonder if other companies are making lease offers to you? I may be willing to entertain competitive and fair lease offers too if any of the companies are interested. Is Prairie your only offer so far?
Reports coming out of that township are bad. Hope you took that offer.
There have been mineral sales of up to $27,000/acre that I am aware of, and most lease offers will start about 1/3 the actual mineral value. Terms in the leases are the problem. Minimize post production expenses and a minimum annual payment required…I see a lot of folks making $15 a year on leases held for 30 years on wells that have produced 8 BCF and there are additional drilling sites not being drilled.
TPR Mid-Continent has a pooling and Horizontal pending in 20-9N-8W. Well to be in 17&20. Still pending. Hearing was supposed to be in July, 2018
What kind of rates are typical for minimum royalty payment? That seems like something I need to be negotiating for. We too have several wells HBP that pay way less that $100 a year.
Duff_B, If you have wells that are HBP, you are bound by the original lease or pooling order and have no negotiating power until they cease production and the lease expires. A lot of us are held by old leases that had 1/8th royalties as that was the “normal” back then.
Depending upon where you are located, you may or may not have horizontal drilling as a future option.
Yes, I understand. I have 9 parcels, 4 counties in two states. Some not leased, some 1 year into a 3 year lease, some HBP for a couple of generations. I meant going forward on new leases I need to add that. That would be Grady and Caddo mostly, though one unleased is in Texas. I guess I could read some filed leases and see what amounts have been signed off on. Any input on what’s been done might be helpful.
M. Barnes - How will this affect 27-9N-8W? Is it close enough for horizontal drilling to it?
Duff, I always try to go for the highest royalty and the lowest bonus as in the long run, the higher royalty usually outweighs the lower bonus. Many lessees only offer 3/16th in their original offer, but they actually have 1/5th or 1/4 if you ask. Best thing is to post your sections in the proper state and county by sec-tnshp-range and folks will answer on the forum. You will not find bonus information in filed leases as it is private. It will have the royalty rate. In OK, the poolings are the only “public” rate information. Post on the forum and you will usually get an answer about the nearby poolings. That gives a ballpark range.
PKD, Continental Resources and others were leasing in 27-9N-8W in 2017 and 2018. So hang in there. Activity in surrounding sections is encouraging.
Marsha…I know all that. Thanks. It doesn’t have anything to do with my question. Terrell posted upthread to include in a lease “minimum annual payment required…I see a lot of folks making $15 a year on leases held for 30 years on wells that have produced 8 BCF and there are additional drilling sites not being drilled.” I looked up verbiage on Minimum Annual Royalty Payment. My question still remains, if a mineral owner adds this in attachment A to keep from being HBP for a couple of bucks a year after a well is played out, what are some examples of how much that minimum royalty might be? If I lease for $5000 1/5, a minimal per acre shut in royalty, BUT have a minimum per acre royalty of $100 an acre? $500 an acre? $1000 an acre? What has been working under what circumstances? Terrel?
I had not heard of this until Terrel posted about it. Here is some info: Minimum Royalties One problem often encountered by landowners is how to deal with a lease that is near the end of its life and is only marginally productive. This is especially a problem when the Lessor is also the owner of the surface estate and the Lessee’s surface operations significantly detract from the value of the land. In order to keep the lease in force, the Lessee’s production must be in “paying quantities,” defined as production sufficient, after royalties, to pay the Lessee’s cost of operating the well. It is often difficult to prove that a well is not producing in paying quantities, even if its rate of production is very low. One possible solution to this problem is to include a minimum royalty provision in the lease. Such a provision states that the royalties paid to the Lessor under the lease for any one-year period, once production is established, will never be less than an agreed amount, usually expressed as a number of dollars per acre. At the end of each year after production is established, the total royalties paid during that year are added up, and if the amount is less than an agreed minimum amount then the Lessee must pay the difference as “minimum royalties.” If the minimum royalty is set high enough, it gives the Lessee an economic incentive to plug a marginal well, since the minimum royalty will increase its cost of operation. For example: suppose that the Lessee has one producing oil well on a 100-acre lease, providing for a 1/5th royalty, and that well produces an average of ten barrels per month. At $50 per barrel, the Lessee’s revenue after royalties is $400 per month, and the royalties are $100 per month. If the lease provides for a minimum royalty of $50 per acre per year, then the minimum royalty is $5000 per year. At the end of the year, the Lessee would owe a minimum royalty payment of $5000 less $1200, or $3800. The Lessee’s revenue, before operating costs, would then be $4800 less $3800, or $1000. As the production continues to decline, the lease will become uneconomical to the Lessee sooner than it would without the minimum royalty, giving the Lessee an incentive to plug the marginal well sooner. From here. It’s a pdf from a texas attorney. https://www.google.com/url?sa=t&rct=j&q=&esrc=s&source=web&cd=1&ved=2ahUKEwj2q-q-i47dAhVFJKwKHWSQCZgQFjAAegQIChAC&url=https%3A%2F%2Fwww.gdhm.com%2Fimages%2Fpdf%2Fjbm-ogleasechecklist.pdf&usg=AOvVaw0osWUQMfqUOn4RjtVLvQG9
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Thanks M Barnes for all you do.
We’re all lucky to have you!
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Thanks.
I have been pondering the minimum royalty question. Interesting concept, but I wonder how many lessees would actually agree to it. The operator would have to abide by it, so I am thinking not many would allow it. There are so many third party lessees to these huge horizontal wells, might be a tough sell.
Hi. This is kind of what I am looking for information on. We got paperwork concerning “pooling” and horizontal drilling in Grady County by TPR Mid-Continent. And the hearing was set for July 2018. Do you know what is happening with that? Someone from the Paladin Group is supposed to contact me tomorrow, 10-20-18. I got involved because my 92 year old father-in-law has land there and I am POA and Representative Payee for him. I am trying to get his affairs figured out and hardly any of the family seems to know much about anything. I’m completely new to all of this so any and all info will be appreciated. Thank you in advance.