Any information on activity around T160/R103W/Section 21. Just obtained these mineral rights thru an inheritance. Any advice or information would be appreciated.
There is only a single well within 5 miles of you, as the crow flies so your area is an unknown quantity. The were some dry holes drilled in your vicinity but they are old to very old and I think would have little bearing on today. If anything, the traces of gas and oil they encountered (1986) at 7,500 to 7.800 [ total depth ] would be positive. Bakken is around 2,000 feet deeper than they drilled.
Thank you very much for the response. That's very interesting. Any idea what a fair asking price is in today's market for royalties?
Sara, I'm somewhat turned off to leasing because I have only signed one lease that turned out anywhere near the way it was supposed to and that was in Texas. I would rather just take what the state says I get in ND. But I'm not everyone. In your position I would be asking $1500 per acre and 20% roaylty and I would consider only the $ per acre negotiable and I would not move far on that. Other terms in the lease are far more important than lease bonus amount. You don't want to wind up like that poor guy in Pensylvania who has 4 gas wells on his farm and his monthly checks are $0.10 a month. You don't want them to be able to charge anything to your royalty because they get to figure how much, can change the amount whenever they like and there is nothing you can do but sue them, which probably will not be worth it for the legal expense, so get the terms correct from the start because there is no do over.
If you get a decent well in ND and have not leased, you get 16% statutory royalty from the first barrel onward, then in a few years when the well pays off 1.5 times, you become a working interest and receive 100% of production attributed to your acres, less cost of production. Cost of production can be laughably low, I have one well that costs $1.40 a month per acre to operate.
If the well is a dud, you owe nothing out of pocket. Only if it succeeds will you receive bills and since you get more per barrel than the operator because you don't have to pay anyone a royalty because you own your acres, you should be able to pay your bills with 25% to 33% more money than the operator receives. The applicable law is North Dakota Century Code 38-08-08 and it can be found online.
A lease bonus is usually less than 1% of what the lessee expects to make off your minerals. Leasing is the cheapest way for the lessee to get control of and title to your minerals, if there was a cheaper way, the lessees would do that instead.
Wow, this is a lot of great information and I'm trying to digest it as best I can. You obviously know a lot about this business and I have a lot to learn. I should have pointed out in my first entry that my three siblings and I have owned these mineral rights for a few years and we have them leased to a company that my mother leased to back in the 80's, but that lease is going to run out in less than a year. I think we were a bit hasty in signing the lease but three years ago this company was the only one interested in land in Divide County. We settled with them for under $500 an acre and a bit less in royalties than you've suggested with the company promising that they would drill within a few years. To date, nothing has happened.
My interest in finding this blog was to basically plan for the future and find out if we (my siblings and I) did well (or not) in signing this lease. From reading your input, it sounds like we could do much better, but I think things were a little different three years ago. I'm still not real sure about Divide County-it seems to be a good news/bad news journey. I keep hearing about it's "potential" but then I look at production reports and see far lower numbers than Williams, Mckenzie or Montrose Counties. There are also far fewer permits being sought by exploration companies in Divide than these previously mentioned counties. It makes me wonder if there is just less oil in Divide, less exploration that's been done to date, or are the major players just flocking to the known "honey holes" in those three hot counties with the thought being that once they are saturated, they might migrate into Divide and the other counties that don't have much being done in the way of drilling.
At any rate, we are going to do a much better job of researching our options before signing another "deal" with anyone and what you've told me certainly has my attention. There is still much that I don't understand. Are there books you might suggest that would help me understand more about this process? Do owners of mineral rights generally hire an attorney or some other form of adviser when dealing with these matters?
Again, just trying to gather in all the options with the anticipation that our lease is going to lapse without anything being done in the way of drilling. I know some seismic work was done on the property back in the 80's but of course, no results were disclosed to my mother. I thought the NSA was a secretive society-they don't hold a candle to the oil industry.
Thanks, again for taking the time to share your knowledge.
Sara
Sara, the major difference that I can see between the better parts of Williams and McKenzie counties and Divide county is the field pressures, the gas underground. The gas makes the oil move so it can be produced faster and the gas pressure is what makes 10,000 foot laterals work at least somewhat efficiently. The lower the pressure, the less efficient and economic a 10,000 foot lateral is going to be. They are still drilling those 10,000 foot laterals because they do one thing better than a 5,000 foot lateral and that is they hold twice as much acreage with a single well. One day, they will drill efficient wells that differ from todays wells in being shorter because 70% of the oil comes from the first 4,500 feet, they will use more expensive ceramic propant (sand) and because the wells are shorter, a pump will actually be able to exert a significant pull over the greatest part of the wellbore exposed to the productive zone. Right now they are using ordinary silica sand that crushes under the pressures at these depths and clogs the fractures almost as much as it holds them open. For every drop of oil, water and whiff of gas produced close to the pump, it lessens the pull farther down the line until the pull is insignificant. If there not enough natural field pressure, that last mile of wellbore is going to do nothing after what little field pressure there is depletes but hold acreage and double the amount of acres that receive royalty from the well, severly diluting the royalty.
Many people think this is "it". This is not "it", drilling will continue in ND for the next 40 years and probably beyond. Being in a hurry is not going to help you make the most of what you have. Rushing to convey your mineral rights to a company [lease] is like an immediate short sale of a house, you aren't going to get the best price. You might have to hold on to your minerals for another 10 years to get the most out of them, but that is no different than any real property. The oil is not going anywhere, certainly not going anwhere quickly with the inefficient wells they are currently drilling, 6.5 million to 7 million dollar wells, not the 10-12 million dollar wells you are comparing to elsewhere.
I would be more inclined to leasing if the operators were going to drill the most productive well they can, if they were going to get all of my minerals into production within a few years and not a few decades, as a prudent operator is supposed to. As the greatest part of your pay for your lease is to come from royalty, they are cheateing you when they drill an inefficient well, that will leave oil in the ground. Low royalty and bonus is less important than oil never produced because you get nothing from oil never produced by these inefficient wells, that's the biggest cheat of all.
You have the choice, you can lease to them and aid them in their program to produce a minimum of your minerals for decades, for low royalty and your appreciating asset becomes their appreciating asset, or you can retain your appreciating asset. Right now you are the native being asked to sell Manhattan island for $24 worth of beads. Good luck, whatever you do.
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Again, I thank you for taking the time to respond. Your information has certainly opened my eyes to options other than rushing to the table to sign a lease. I'm going to get together with my siblings in the very near future and share this with them and I can certainly tell you that much more information is going to have to be forthcoming from any exploration company (including references) before we are going to lease our rights. I'm sure there are good drillers and bad out there. Is there any way for an owner to know which is which in this highly secretive world they are in? Sara
Sara, you can find out what kind of well they intend to drill. If it's a 6 to 7 million dollar well, no matter how nice they are about it, they would still be bad to me. Drilling of the well, and getting all of your minerals into production is your largest and most important consideration for leasing. They do not intend to get your minerals into full production as a prudent operator is supposed to do.
I have been watching the "one and done" drilling program for years. The operators are putting their interest first, it would be inconvenient to fully develop your minerals in the near future, even though there is a covenant that they do so, while they are trying to hold as much acreage as possible during the land grab.
If their plan is to drill a cheap, low producing well that will leave oil in the ground and at the same time diluting the royalty to half or less what it should be, while they plan to delay getting all of your minerals into production for decades, I consider it a bad deal.
Start with the well. Request an AFE which will be the estimate of what they intend to put into the well. If the well is not first class, I have described the program which will follow. Low productivity, low royalty, severly diluted royalty and no further effort to get your minerals fully into production for a very long time.
Why in the world would the oil companies not get all the oil they could from the well? Seems like the more oil they pump out of the hole, the more they have to sell and the more $ they make. How would I ever find out what, if any well the company that owns our lease intends to drill? They are so secretive about everything. The last time I emailed them and asked if they even intended to drill I got no answer. They were supposed to drill a year ago last December-haven't heard a word since long before that. I was told that the only way an owner can find out anything is to either watch the N.D. website to see if a permit has been issued or when you get your first royalty check in the mail. Sara
Before you sign a lease, ask them to send you an AFE, which is the well proposal for participation with the total and the costs broken down. Why drill 6 to 7 million dollar wells, cheap wells? When you must put a well on leased acres and you have 1,000 spacings to drill in 4 years, are you going to put 12 million dollar wells on all of them or are they going to get cheap wells to hold them until you can decide which will get special treatment?
I surely hope I am right because if what you propose is true, these cheap sand frack wells are all these spacings will ever get and the mineral owners are worse off than I ever imagined.
An EXTRA 5 billion dollars outlay in the next 4 years amounts to quite an outlay to put top notch wells everywhere, whereas once you get the cheap wells everywhere, you have 20 to 40 years to go back and fill in. I think you are thinking like it's just your well, or wells in your township, wells in your county, I don't think you are taking into account the fact that the operator needs to drill wells all over the western half of ND and parts of Montana also in the bargain. Your well is an insignificant speck, or will be.
They are still drilling at breakneck speed. If you as the operator don't get your spacings drilled and held by production, you could lose it, you could have to lease it again for more bonus and higher royalty [millions out the window and you still don't have it drilled] because over the years people have been learning and they rarely sign leases for 1/6 anymore. If you had that much to do and that much to lose, wouldn't you drill a sand frack well, drilled as fast as possible keeping it mostly in the pay zone and move on to secure the next spacing? I often refer to them as cookie cutter wells. The rig is not going to sit there on site for 2 months while they determine the best way to drill and complete the well, not when that well can be drilled in less than 30 days, and there is another well waithing to be drilled with leases running out. From the operator's point of view, they are saving 3 million dollars a well, not losing so much production. Sara, they flare off an amazing amount of gas, they figure it at dry gas price but if you included the natural gas liquids, I believe it would be well over a billion dollars a year, you can check the statistics. The operator is allowed to flare gas for 1 year for each well, then they can petition to flare gas forever because it's not economic to build the gathering line, at least it isn't after a years decline in gas production. That's your royalty going up in smoke. Spending money on gathering lines for wells already drilled and holding acres by production is money you can't spend on more cheap wells to hold acres by production elsewhere. The amount flared and the value lost is an easy search. I believe you will also find someone else complaining about the fact that of course the gathering lines are not economic, since they were not there to capture the first "best" years worth of gas production, yet another case of the operator not being prudent. The NDIC O&G DIVISION whose job it is to prevent waste, it's in their charter, has rationalized that flaring gas is not waste because the oil produced is worth more. It's still waste, they are just lapdogs of the oil companies.
It's not insane to drill fast cheap wells when you are competing with other companies to tie up as much acreage as possible. Think of it this way, once you get a producing well on it and get the spacing proved up, you can get a loan for $50,000 an acre against it. If you had an NDRIN subscription you could look for mortgages. $50,000 per acre in a 1280 equals $64,000,000 worth of collateral on your books so you do well to prove up, hold by production, as many spacings as you can. I said the wells weren't going to pay the lessor much, I never said the wells weren't going to be profitable for the company. ; )
There is huge profit potential in just proving up the acres and sitting on them and allowing them to appreciate. The operator could easily double their investment selling their acres in the future to someone else without ever drilling another well, while your royalty keeps declining. The operator can make money in ways that you as the lessee will not share in. The operator is not really cutting his throat with a poor well. Still wouldn't bode well for the lessors financial future though. This is just a glimpse of the big picture.
You don't even know how cheap those cheap wells are, after deductions, tangible and intangible completion and the depletion allowance, the deductions are awesome, if the well drops below 30 barrels a day average after a couple years, it's classed as a stripper well and taxes are greatly reduced, for the operator and working interests. At one time Sara, I asked myself the same question you did, why wouldn't they drill the best well and get the most oil. The above is part of what I found for an answer.
This is all super interesting stuff indeed! Again, it's a lot for a novice in this field to digest. In an earlier response you mentioned drilling a well at no cost to the owner unless it produces. That sounds like someone is willing to drill a very expensive well on a contingency basis for the owner? Sounds like a pretty big risk for someone. Are there companies out there that do that?
Sara, when you are non-consent in a well, you as the mineral owner risk nothing. The operator "carries" you and it's often called a "carried" interest. The operator drills the well, you as the mineral owner receives the weighted average royalty of all those who did lease or 16%, whichever the operator elects, so you may as well say 16%, from the very first barrel of oil produced.
The other 84% of the proceeds from your oil go to pay for the drilling, completion and operating expenses for your proportionate interest in the well, and a 50% of actual cost of drilling and completing of the well penalty.
The operator does not drill wells to gain the 50% penalty, they are looking for 300% or more, so 50% penalty would be about 1/6 which interestingly enough, is about what they offer many people in royalty to lease their mineral acres. It brings to mind the saying "to flip the script" The operator will make equivalent to mineral owner/lessor money, while the unleased mineral owner will make the operators share.
The cost to drill the well and the penalty can only be recovered from proceeds from PRODUCTION. As the mineral owner, you never owe a dime out of pocket until the well and penalty are paid off and you are receiving 100% less cost of production. Since you don't have to pay anyone a royalty, you are making 25% to 33% more money than the operator per barrel of oil. If you can't pay your proportionate part of the bills, the operator is going to be in a much worse position.
You don't have to lease, it's the law.
All operators in ND do it, if you spent 2 million to 4 million dollars for lease bonus, landman and legal work, as the operator, are you going to walk away from all that because someone who has 50 net mineral acres out of 1,280 net mineral acres won't lease to you? Are you going to give up 20 million dollars profit because it's not going to be 21 million dollars profit? Oh, the operator is not going to be happy, but they are not going to walk away. My operator where I am non consent offered me 30 times the initial bonus offer and another 2% royalty, if I would lease to them. If you won't lease to them, it's impossible for them to make the kind of money they want and expect to make off of acres for drilling a well.
I don't recommend this course for a 1/2 net acre because the effort of administration wouldn't be worthwhile, but for 5 to 50 acres I would recommend it, and not all of the acres have to be in one spacing because it's not much different managing 2 interests than it is managing one.
Because the operator is "carrying" you, there is nothing for you to do but cash checks, just like leasing, until your well and penalty are paid off, at which point you have options. If you wanted you could sell your working interest, for alot more than you could leased acres because you have alot more to sell, possibly 5 times the income potential and actual ownership in the well the "PLANT" (casing, tanks, gathering line, equipment for processing gas) that produces the oil. You could sell your interest in that single well and retain your minerals and interest in any future wells. You could lease your minerals in the future excluding the first well that you have a working interest in. The point is that you have options, many, many options, still. You could take on a partner in a farmout agreement for any future wells and not spend a dime out of pocket and the operator would not even collect the 50% cost of drilling and completing penalty.
My operator in my non-consent spacings still makes the occasional lease offer. Why do you think that is? [Rhetorical question] It's because they can't possibly make the kind of money they want to make if I and my brother will not lease to them.
If you lease you are leased until the lessee is done with you, or you can sell, possibly sell your royalty stream for a period of time, but that's all the options you have in a lease. I like having more options.
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I would definitely agree with you-more options are always better. The problem is with someone like me is getting to know the business well enough to make the best choices and as I've read what you're telling me, it's obvious there is much more to this than just shopping around to see who will make the best offer for a lease. For now at least, my siblings and I are tied up in a lease for the the next 12 months but I'm anticipating nothing is going to happen with that since they've already had three years to drill and haven't done so. It's hard to say if the company that we're leased with is going to attempt to renew it but I would expect they will. They have to drill, as I understand it to automatically renew the lease or do they just have to get a permit?
We have 160 acres of mineral rights in Divide. How many wells can be drilled on that size piece of ground under N. D. law? By the way, I downloaded 38-08-08 earlier today but really haven't had time to sit down and study it. Trying to make all this new info sink in has about put my old brain on overload I fear. Are there any books out that do a good job of teaching the things you have suggested? Sara
Sara, your 160 acres are probably going to be pooled with the remainder of two sections into a 1280 acre spacing/pool. The only real limit on the number of wells is the economics, how many are economically feasable/desirable. If you look at the GIS map, you will notice that most recent wells are tucked away in a corner of a section. This is to allow for more wells in the future and is where the state permits wells to be drilled, unless there is a compelling geological reason for the well to be located elsewhere or oriented in an East-West rather than a North-South direction. The wellbore on one side of the section is probably not going to produce the oil from the opposite side of the section. The state has setback rules of 250 feet from section lines, to protect against significant production from someone elses pool or sections. Thaking that into account, it may eventually take 8 wells to drain your spacing in a single formation. In my opinion it would take decades before the last well were drilled.
I also would not count on them not drilling in the last year, or even the last two months. Operators have established a pattern of drilling just prior to the greatest number of leased acres in a spacing expiring. Usually, pulling a permit will not extend a lease but if you have a continuing operations clause, building a pad, a road or digging a pit could extend your lease for 60, 90, 180 days beyond the anniverasry date of your lease.
Likely, the operator has the right to start pushing dirt on the last day of your lease with a caterpiller, building a road or something and as long as they don't let more than 60, 90, 180 days pass with no work being done, they could extend your lease for another year or more in this manner, legally.
It's very common for drilling to begin in the last months of a lease, so as to keep from having to lease the minerals again. Operators can begin wells with a rig that is not capable of drilling to total depth and request an extension from the NDIC of 90 days to bring in a more capable rig to drill the well to total depth. As far as I know, this request has never been denied.
Luckily, two guys in a pickup truck with a GPS staking out a pad or pulling a permit is generally not considered operations that would extend a lease, if, and it's a big if, some mineral owner complains, spends money on a lawyer to complain. If this is not done, your silence is as good as permission.
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I guess it's a "wait & see" game for the next twelve months. From what I've learned from our discussions, I'm now of an opinion that I hope they don't drill and they let the lease lapse. I would certainly like to pursue some of the options you have outlined as I'm sure my siblings would.
I've come across production records a few times on the N.D Nat. Resources website and it looks to me like a decent well produces about 5 to 6,000 barrels a month. I only saw one well that produced 32,000 barrels in one month. I was once told that a really good well will produce a thousand barrels a month and I also hear about all this oil they're pumping out of the ground in N. Dakota but unless I'm reading the production records wrong, it doesn't look like very many wells there would be considered "good". If we had a well that produced 5,000 barrels a month at 17% royalties, what do you think we could expect for monthly income after that 17% is diluted in a manner like you've noted or are there too many hypotheticals involved at this point? Sara
Sara, it's not as simple as it seems. A well that averages 1,000 barrels a month for 30 years is not bad. An oil well is judged by how much wealth it produces before it's plugged, but it's nice to get a good chunk up front from flush production.
17% royalty 5,000 barrels a month, in a 1280 acre spacing, probably $45 to $50 per net acre at todays oil price. Half that amount in a 2560 acre spacing. Just ballpark.
Don't feel too bad about the 17%, my aunt leased for 15% the landman in turn assigned it to his company for 20% and his company assigned the lease to the operator for 20.625%. It was 200 net mineral acres and she didn't ask anyone. Also she got $200 per acre bonus while I was negotiating upward of $3,000. She remembered the old leases from the 50's at $50 and thought $200 is good money, even called me afterwards so I could get in on it too. Missed stopping her by about a day.
For the difference between 16% statutory royalty and 17% roylaty, I would not even talk to them unless the bonus was extremely high, but as I have said before, the bonus is usually less than 1% of what they expect to make off your minerals.
The "bonus" you've mentioned several times. I suppose I'd better get our contract out and read it again because I guess that's another thing I really don't understand.
The numbers you've hypothetically put out sound nice but at least at this point there's no idea how many people that would be divided up with. It's four ways just in our family. Still, any check to supplement our retirement would be nice. Sara
Sara, the bonus amount is not going to be on your lease. It is basically a different transaction. The inducement to give up 100% of your oil for a 17% royalty interest, that you might not want to do for free, so they bribe you to do it with up front money. If giving title to 100% of your oil for a 17% royalty interest was really in your best interest, would they need to offer you a bribe?
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Good question.Well, I guess it's a waiting game, now. We'll know in about 12 months or less what is going to happen or if a renewal offer is made on the existing lease. Or, we may have a well at least started by then. At any rate, I am going to keep all of this information in a file where I can refer to it and would certainly appreciate the opportunity to speak with you again on this subject in the not too distant future if that's possible (I'll keep you posted on any developments). I'm sure others that read this blog have also benefited from the knowledge you've shared. I can't thank you enough for being so generous with your knowledge and patient with my ignorance. One of the only way's one can learn is to ask questions I guess. Sara