Dustin, you are dorrect. That is what I meant by having a position. If you are speculating you don’t need all the acres, you may not want too many if you don’t have intentions of participating and tying up alot of your money for an indeterminate time. If you can’t flip the acres to someone else at a profit, you would probably have to participate and pay for that percentage of the well.
My husband and I are planning a short visit to Scobey at the end of May next spring. If any of you live in the area…it would be our pleasure to buy you a meal so we could learn where our mineral rights are and what might be going on at the time.
Sharlie what was your original date they gave you for payment on your lease. And how did you find out that Shale sent the bank draft back to your bank . This is a little scary for you and all of us who are still waiting to be paid. Please keep us informed
The original pay date according to the bank draft was Nov. 7th. The way I know the bank draft was by my bank calling me. I called Shale in Texas and they assured me they would be sending a check on Dec 14th.
I hate giving a lawyer part of my money but that is probably what I should do.
Ms. Leitner, when I leased to KOG and they didn’t pay me although they recorded my lease twice because the draft was returned to my bank even before the time had expired and my bank submitted the draft again, the draft physically came back to my bank and my bank gave me the draft back the second time. Later when KOG was drilling the well and I was trying to get things straight with them, they maintained for a long time that the lease was valid whether they had paid me or not. KOG did eventually release my lease but only after I told KOG that my lawyer informed me that he had a window of time in which he would not be too busy to start the lawsuit and that it was now or never and I informed KOG it would be now. KOG did record the release and from where they had to scratch out the old dates and insert new ones I could see that the paperwork had been drawn up months before, but nothing would have been done if I hadn’t informed them that the suit would begin immediately. If you give them all the time in the world, they will take all the time in the world because it’s the path of least risk and greatest potential profit because it costs them nothing. If they have established title, they should either accept and pay or not accept, and hopefully tell you why. If they can’t establish title they should tell you so you can fix it. But no, they want to keep you tied up for no money just in case the value of your acres goes up which it easily might in a 6 month period if the recent exploratory well achieves profitable production. They have you send them an executed lease so they have an unpaid option on your acres. It’s no different than if I contracted to buy your house, and won’t pay you unless the value appreciates to more than the agreed price or I find a buyer who will pay me more for it than I agreed to pay you. It’s what most people call a deceptive business practice. I bet you thought you were executing an oil and gas lease contract with a set time for things to happen, when the fact is that right or wrong, your lease is being used as an option and the option will last as long as you allow it or until the value of your lease is more than you were offered. If that first test well turns out to be profitable, speculation will probably make the value of leases rise and I think it likely that you will be paid. It wouldn’t prove all the acres but that is the nature of speculation, if you wait for it all to be proven you would have to pay top dollar for it and there wouldn’t be much profit in assigning it to someone else. The profit margin could be huge if you hold alot of leases for which you have not paid that you could flip for a profit, or if the test well doesn’t do well, you can walk away from the leases without paying, just by recording a release of the leases you recorded and claiming that they failed title. What a beautiful business! I couldn’t do it because I couldn’t stomach it, but for probably less than $50 per lease, postage, printing, cost of recording leases and $100 a month cellphone bill, I could tell people I am leasing and then with enough excuses I could keep them tied up with out paying for a year and worst case I would just have to record a release because title failed or I could say I realized it was outside my target leasing area. I could form my own LLC called Snail Exploration. After I flipped a few properties I could open a storefront. I could post glowing testimonials for myself under different names on this forum. I’m not worrying about giving anyone ideas. It’s more or less happening already and will continue to happen. Please do what you can to protect yourselves and if things don’t work out this leasing round, do not send executed leases to anyone until you are paid. If you must send them the lease, send them a copy of the executed lease boldly marked COPY. I think that is a fair description of a no money down operator. I think a company that could pay but operates this way is even worse.
I meant to say the way I knew the bank draft was returned…
thanks r.w. you are what these forums should be about.
Thanks for all info r.w. You and others have taught us alot.
So close yet so far!!! Think that’s just a stone’s throw from ours.
Dustin, an overlarge spacing will dilute your decimal interest. It’s the cruel mathematics of oil and gas. With a 2 section spacing with you only in one half it spreads the royalty equally over a larger area and even unproductive acres get a full share. The larger the spacing, the greater probability of more unproductive acres. It’s all under pressure down there. When oil flows to the surface pressure lessens and oil from farther away migrates to the wellbore. It seems that the oil doesn’t flow very far in shale wells. The scientific determined set back from the lease boundary line is just a few hundred feet and a section is a mile per side. Lets say the wellbore pulls significant oil from 300 ft from either side or 600 ft total. The mile width of the spacing is 5,280 ft which if you divide by 600 ft goes into it 8.8 times. Likely there are alot of acres whose oil isn’t going to be significantly touched, but everyone in the spacing is going to share equally in the production/royalty. This is a land grab. The operator gets to hold all of the acres in the spacing with small royalty payments from only a small part. Not to say that this couldn’t work in your favor, it might not be your particular acres being produced. Even where it’s you collecting royalty from the production of someone elses acres and I am actually involved with both sides of this equation, I would rather not be held by production from someone elses acres. The mineral acres can appreciate in value, once you are held by production, the acres become the lessees appreciating asset and not yours. The industry people describe the overlarge spacings as a smaller piece of a bigger pie. Sounds good? Not! Your royalty is diluted from the start. The pressure is now off of the operator to drill more wells, the operator can wait til the first well runs dry before they have to drill another to hold the lease. If your royalty has gone for 20 years to hold someone else by production and a new well is then drilled on the formerly largely unproductive acres, it can take another 20 years before you are paid back for that part, and remember there are probably still relatively untouched acres collecting royalty from all wells in the spacing. Dustin, there may not be anything that can be done, you can be heard and protest but the state will give Apache what they want. I just figured you deserve to know what is being done. People are amazed at how small the royalty checks are even for great wells. If you give 80%+ to the lessee in the lease and 80% of what you would have gotten for the 1 well goes to HBP 5X the unproductive acres. People who should have gotten a reasonable royalty check have their checks reduced to lunch money. In other words, the operators 80% plus is not effected because they get that amount in every lease but the mineral owners royalty is diluted. For me the best part is that the state not only knows this, the state actively helps the operator do this to you. I guess you can be thankful you aren’t in a 2560 acre spacing. Cruel math 20% royalty spread out over an overlarge spacing so 20% of 20% = 4% less production and severance taxes, state income tax if any, federal income tax and any deductions the operator can charge against your royalty for making product ready for sale or transport. I wish some industry person would shout me down and say it’s not true. I think the best people can hope for is that the operator will drill at least two wells at the same time, because it saves the operator money to do it that way, to not have to bring the rig back again and to drill the second well off the same pad, even better if they can frack both wells at the same time. Some very lucky people in ND have had their spacings used in experiments where the operator completely drilled them in multiple formations (where multiple formations existed) 6 or 8 wells. Operators are too busy acquiring HBP acres to develop fully what they have, and the mineral owner/lessor loses.
where do you come up with the 300 ft pull down? I think many NE Montana horizontal wells are on 1240 spacing units.
Mr. Humbert, I would guess that even more horizontal wells are on 1280 spacing than 1240 which is what I was talking about and that I think significant amounts of oil are unlikely to come from a half mile or more away from the wellbore. The state determines the setback regulations to make it less likely that one unit will significantly drain another unit and the setbacks are a few hundred feet. If you don’t like my numbers, please tell us yours and how you arrived at them. Until then I will go with what I got, based on state setback regulations which were probably influenced in no small part by the oil industry. I am not saying that no oil whatsoever comes from more than 300 feet away, but that the farther you get from the wellbore the less significant the contribution of oil to total production. I have more bad news for you also, once the natural pressure is gone probably 70% of the production will come from the first mile of wellbore. The pump tries to pull a vacuum on the wellbore but for every drop of production in the first mile it is going to decrease the pull on the second mile. The near 2 mile XXL lateral is inefficient and just part of the land grab. The savings of not having to drill the verticle twice is really very small. Have you ever noticed that it only takes a few days to drill straight down 10,000 ft and the rest of the month to drill the lateral? Ever note that many operators in Texas drill wells with 3/4 mile laterals ? Does this mean the operators in Texas don’t know what they are doing and aren’t smart enough to see how superior the 2 mile lateral must be? The lateral is the expensive part, much of it because of the stimulation, which may only be of use at the further reaches of the 2 mile lateral until the natural pressure goes away in 2 to 4 years, when the well hopefully produces for 30 years or more. It seems to me they aren’t getting the most bang for their buck, except for holding acres by production and that the 2 mile lateral does very well.
My mistake, 1280. When I was reading the hearing notices of the North Dakota oil and gas commission this am. Many of their hearings were on establishing 2560 spacings.
It sounds to me like the only people to win in these situations are the oil companies. Do mineral owners ever wind up on the plus side of this?
Dustin, “how will 1280 effect”… In essence it just doubled your chance of having production (oil under sec 1 or 2), while at the same time it reduced your interest by half.
In other words if you owned all of Sec 1 (640 acres), you’d have a 100% interest under that section, but only a 50% interest (still 640 acres) under the combined sec 1 & 2 (1280 acres). Yet on the other hand, when they drill both sections together they might find production under your neighbor (sec 2) yet you’d still participate in the production from that well.
Bonnie, if you don’t lease and the operator drills a well anyway, you make what the operator would have made off your acres after they subtract the cost of your part of the well from production attributed to your part of the well. Until your part of the well is paid off you will receive 1/8 (12.5%) royalty from the first barrel of oil produced. The operator can only recover the cost of your part of the well from production. If the well is poor you would owe nothing. In the case of a dry well the operator could place a lien against the PRODUCTION of your minerals, but how much good is that going to do them if they couldn’t find anything? Who would lease from you in the future, much less drill a well if with todays tech they could not get production? By not signing the lease you are giving up the bonus money which may be as much as 1% of what the operator expects to make off your acres. You are selling 100% of your oil for possibly 1% of it’s value and a royalty interest in the production. If you sign a lease, you are in business with the lessee and if the lessee does not pay you it is a business dispute and all you can do is sue them, good luck with that. A goodly percentage of people who come here do so because they are not getting paid for their lease. I have wells for which I did not sign a lease and I get paid when the law says I must be paid or before. Why is that? I did not sign a lease. The state is allowing the operator to take my oil without my permission but the state also says I must be paid. When you lease your minerals the lease is totally binding on you. Unless you have 100,000 to sue the lessee the lease from the lessee’s side is completely voluntary, and your lessee knows that the only way you could force them to comply is through a lawsuit. The state regulatory commission will tell you that your lease is a private business matter and will not get involved. There is no law that says you have to lease all your acres. You could lease half and be non-consent in half. You would get the lease bonus for what you leased up front and 25% to 50% more royalty for what you leased compared to your non-consent and when the well recovers cost in a few years your non-consent will pay you 5 times what the acres you leased are paying you, at which point you will probably ask yourself why you leased any of it in the first place, but you could hedge your bets by only leasing half. I once read what someone wrote about people who didn’t want to lease, he thought they were stupid and asked if they had never seen “The Beverly Hillbillies”. This unfortunate person had missed the fact that Jed Clampitt was an owner, not a lessor, Jed’s oil sprang from the ground of it’s own accord, Jed did not have to sign a lease to get a well drilled, Jed just needed to get someone to collect and market his oil. If Jed had $10,000,000 in the bank as owner, 1/8 of that $1,250,000 as lessee, if Jeds royalty were spread among those in a spacing 5 times the size of his farm, Jed now has $250,000. Jed the lessor could still go to Beverly Hills but Mr. Driesdale isn’t going to pay as much attention to them and certainly is not going to assign Ms. Hathaway to keep an eye on them. In the past year there was a fellow who came to this site with the problem that the oil company had been holding royalty for his extended family for a few decades, they were unleased. the company was holding $1.6 million for them. By the time the man came here most of the family members had signed leases. As a group these people cut their earnings from 1.6 million to $285,000 by signing leases. Can you imagine the jubilation in the oil company office? High five, jumping in the air, I’m taking the whole office to lunch! We just made 1.3 millon dollars for nothing kind of happy. You do not have to lease in Montana. It might be better if you didn’t, or you can split the difference and only lease half.
just went by the north of 4-buttes apache well, a new style pump jack is running. didn’t see a separater or a burn off flame. there is 4 holding tanks and a red salt water trailer next to the jack with a frost line about 10 inches above the wheels and fifth-wheel plate. this frost line went up very little since last check 5 hours ago.
just got notice from apache. they want to create a temporary spacing unit comprised of sec 1 & 2 on t36n r47e, daniels co. we have minerals in sec 1 but not 2. how will a 1280 acre spacing affect our family? a december 13 hearing date is set for 8 am at bogc hearing room.
Dustin, call Linda Nielsen of Reserve/dagmar and visit with her. She was and maybe still is the chairman of the State Oil and Gas Commission.
Mr. Humbert, I wouldn’t care at all about the spacing size if the operators would go ahead and fully develop them but except for a few exceedingly rare cases, the operators are not fully developing the spacings.