I understand the benefit "IF" the operating companies come back and drill the infill wells necessary to fully develop these oversized spacing units, but there is NO REQUIREMENT that they actually do so. They can tie up all the unproductive acres for an eternity. Some mineral owners will share production from 8 wells (4 into the Bakken, 4 into the Three forks), while others will share from only one well. How is that giving each and every mineral owner an opportunity to obtain their fair and equitable share of the oil from the common pool? It's unequal, inequitable, and the current spacing practices leave the mineral owner without recourse. The possibility that a company might drill more wells 10 or 20 or 30 years down the road just doesn't cut the mustard and ignores the time value of money.
Eastern MT said:
To Gerald & DG:
DG: I agree dilution in these 1280 and 2560 acre pools is a problem for those of us with small net interests. At times it seems these mega-drilling units are designed to include the maximum amount of acres so a single well can hold it all by production before leases expire. However, the way this has been developing the 1,280 acre pool appear to be the most efficient way to drill the Bakken. In Mountrail and Dunn the "stand up" 1,280 drilling units with north-south drilling (opposed to corner to corner) may ultimately allow for up to four wells targeting the same formation under the 1280 (and possibly more beneath in the Three Forks). So long story short... We (small interest owner) initially receive a diluted amount on well one, yet our return is improved if they eventually drill four wells to produce for our diluted interest under the entire 1280 acres.
Gerald: Typically leasing preceeds the pooling into drilling units. First they decide which Townships (or Sections) may have good prospects then lease everything within their targeted area. Then as they get closer to pursuing drilling they request permission from the state for the "pooling" of lands into these units. This provides for an orderly drilling plan over a wide area (say an entire TWP). Then they decide where to drill first and file with the State for drilling permits...
I've also had a situation where minerals owned in one TWP were leased, while adjacent minerals (though in the next TWP) were ignored. However a year later another company leased them. So depending upon how things develop in your area, your lonesome minerals may have suitors before long.
I disagree, as a mineral owner, that I'm only along for the ride. That's silly! I leased my minerals to get them developed. I had no other reason to want to lease and the company's agents lied to me and told me they were going to drill. I did not consent to any situation wherein my unproductive minerals would be "held by production" from a well placed on someone else's land a half-mile to a mile away. I don't want a miniscule fraction from the production of someone else's oil. Why should they have to give me and dozens like me a share of their oil when there is no guarantee that they will ever get a share of mine?
Gary L. Hutchinson, responding to Eastern MT, said:
Eastern MT,
You are dead on right! At the end of the day, these very expensive wells will be drilled on the operator's best geologic prospect with the highest probability of finding reserves that they have been able to lease. Its the profits from other production that allows them to risk those profits to continue in business. Treat them fairly. If they want to hold resources for future exploitation by filing large drill spacing pooling permit aps, that is good for their future and, correspondingly yours in the long run. The mineral owner is just along for the ride so must protect himself in who and how he determines lease terms. Mineral Economics 101
I have a few questions because I am ignorant of the law in ND.
First, is developing the property as a prudent operator an implied lease covenant in ND?
Second, Can you "opt out" of pooling in the lease, including forced pooling?
Third, has anybody considered a community lease covering perhaps 8 square miles, with a continuous drilling and development clause to maintain acreage?
Fourth, in my state, we get to set the unit sizes in the lease form. In theory, the proration unit is what can be drained by a single well. We can also determine proration unit size in our lease form, subject to being increased to the size prescribed by the RRC for maximum allowable. Is there anything like that in ND?
It is my observation that the oil companies are just being smart and leveraging the landowner because of some really bad laws and likely, lease forms that do not fully protect the mineral owner.
If it were me, I would start a grass roots campaign and get the legislators and the media involved. MORE money will flow in the state because of either (1) increased drilling activity, or (2) more bonus payments because many leases cannot be saved - more money injected into the local communities. Whatever the name is of the conservation commission up there is doing a disservice to the citizens. This result is probably because ND does not a long history of oil development and the mineral owners are less sophisticated. Many states "new" to all of this will see what is done in other states. That is probably what happened. Patterned things after Oklahoma or somebody. With new technology comes new challenges and that requires new thinking.
I wish the state and the mineral owners much luck. You gonna need it.
Absolutely. ND follows the implied covenant requiring the lessee to act as a reasonably prudent operator. However, the law trumps the lease. Operators are applying for 1280 acre (and sometimes much larger) spacing units and the North Dakota Industrial Commission is routinely approving the applications. Some operators will request an order allowing only one well in each unit; some will request an order allowing up to 7 or 8 wells in each unit. The Commission routinely approves the applications.
Even if a lease may have restrictions, the North Dakota Supreme Court ruled that it is not a breach of contract when an operator uses a statutorily authorized procedure. Although a pooling provision in a lease might limit the number of acres that can be pooled, the operator can apply for a larger spacing unit, get a spacing order, and then force pool everyone in the unit. Protections that are negotiated and placed in a lease are easily evaded and the lessee can't be held accountable.
My brother and I have spent months researching the issue and compiling information and supporting data to establish that the North Dakota Industrial Commission is misapplying the law. I'm finishing up my paperwork and will be submitting an application to the NDIC (hopefully next week) to establish proper spacing of wells over the Bakken Pool. I'll share my application once it is filed. I hope lots of mineral owners will join my application and the revolt against oversized spacing units.
Dg:
I totally agree, something needs to be amended.
DG said:
Hi Buddy Cotten:
Absolutely. ND follows the implied covenant requiring the lessee to act as a reasonably prudent operator. However, the law trumps the lease. Operators are applying for 1280 acre (and sometimes much larger) spacing units and the North Dakota Industrial Commission is routinely approving the applications. Some operators will request an order allowing only one well in each unit; some will request an order allowing up to 7 or 8 wells in each unit. The Commission routinely approves the applications.
Even if a lease may have restrictions, the North Dakota Supreme Court ruled that it is not a breach of contract when an operator uses a statutorily authorized procedure. Although a pooling provision in a lease might limit the number of acres that can be pooled, the operator can apply for a larger spacing unit, get a spacing order, and then force pool everyone in the unit. Protections that are negotiated and placed in a lease are easily evaded and the lessee can’t be held accountable.
My brother and I have spent months researching the issue and compiling information and supporting data to establish that the North Dakota Industrial Commission is misapplying the law. I’m finishing up my paperwork and will be submitting an application to the NDIC (hopefully next week) to establish proper spacing of wells over the Bakken Pool. I’ll share my application once it is filed. I hope lots of mineral owners will join my application and the revolt against oversized spacing units.
Your arithmetic may be correct but check the authenticity of 1120 acres and 50% penalty. Also, I don't see where you have accounted for operating costs to the point of your payout. I know it is a complicated decision but at least you are anticipating what your options are. You may have more than you think and you may be able to secure your upside regardless of what happens with the subject well.
Joel, you will receive either a weighted average of whatever everyone else leased for or a 16% cost free royalty, whichever the operator elects, from the very first barrel. Do not believe the threats that you will get nothing. If your minerals were in Wyoming, that would be a different matter. 16% isn’t too bad considering alot of people signed for 1/6 which is 16.67%, and many signed for less. I think if your portion of the minerals were larger you might scare the operator off. Look up forced pooling in the N.D. Century code, that would be better than me telling you. I am unleased on more than a few wells, but I haven’t got it all worked out. My wells are not barn burners. They are good economic wells. Those that have been producing for 40 months are about paid for, but not the penalty. Alot of my oil was pumped at 50 to 60 dollars per barrel though. I think it comes down to a gamble between a 2 or 3% more now or the possibility of alot more later. I think the wells are more expensive now, but they arent drilling them to recover a 50% penalty. Roughly, I think you would be at 100% royalty, less your actual cost of production somewhere between 200k and 250k barrels sold, less if the well is cheaper, but my latest wells have been about 8.9 to 9.4 million, and of course you would have been collecting a royalty [ probably 16% unless the neighboring minerals leased really cheap ] the whole time up to that point, and that amount would not be going toward the cost of the well. At this point I have found nobody who can or will just give you everything you need to know. I know I will need to hire some help, after I reach 100% royalty, or just before. I think it will be worth it, but you have to look into it for yourself. Take no ones word without confirming for yourself. Good luck.
The well was spud earlier this month. I don't know what the current status is. Though the NDIC website already shows the next location (in 143-103) for the rig drilling the Maus 23-22 well.
It seems the "next" location typically isn't listed until the rig is essentially done with the well it's on. So if Maus 23-22 is done this well was drilled rapidly. This may the support the suspicion some of us had this was intended to be a vertical well to gather core data rather than an effort at a horizontal producer. I'd love to see Whiting open up a new find in this area. It will be interesting to see what completion data they eventually post for the well.
Gerald said:
I am very interested in the outcome of this well and any additional intel gathered. I do have some acres leased in T140.
I have heard that if things go right they can drill a long lateral on a 1280 spacing in 23 days from spud to total depth. I think it was taking nearly twice that long 5 years ago.
It will become public record after the well is no longer confidential. They have to report to the state whatever they find. We just have to be patient. Wait for the information to be released.
ND isn't the worst state, thankfully. The oil co's like to keep all the information to themselves, because the kind of deals they make now would be few and far between if everyone could easily find out what they should know. Many people still accept the first offer, because they have no idea how much their minerals could be worth. I have negotiated an offer from $100 an acre and 3/16 to $3,000 an acre and 1/5 royalty. At every step along the way they told me it was a limited time offer of 3 days or so. I was in contact with other co's that lease minerals, and had higher offers within minutes to a couple hours. The operator was really unhappy at the prospect of losing 16 net acres in a 1280 spacing. You have to be very careful, when hiring someone to negotiate for you. Get references, I have heard some real horror stories from people who trusted a lawyer to negotiate for them. Even if you hire someone to negotiate for you, you still need to know enough to ask questions. Watch out for fees and expenses. I have a good example. I signed a lease for which I never received a bonus, and I am working on getting the lease recinded, but I have received checks from the operator, which I have not cashed. My brother with the exact same acreage, carried interest, 16% cost free royalty, whereas I have 19% royalty from a lease. His check is larger than mine!!!!!!!!!!!!!! Good luck, whatever you do.
I would record an affidavit of non payment. If another co will lease from you, pay you and then record a lease, then the lease you were not paid for, which was not recorded will be a dead issue. ND is a race to record state.
I'm not sure if this comment fits this discussion, but don't opperators need large reserves in order to borrow money against them ?? They also use the reserves as a way of showing share holder value to attrack investors. Right? Not saying I like what they do. They get overleveraged, and if oil prices go down too much, they go bankrupt. Not to mention it's just darn right sneaky and deceptive. At least tell the mineral owner what the plan is.
Lori, the operators can lease acreage and get a loan for value greater than the cost to lease. I'm sure the lender would be happier if the operator has a controlling interest in the drill spacing. I like to call it disappearing collateral, if the leases expire the lessee needs to lease the acres again or replace them with suitable collateral elsewhere. I do not think they are borrowing against one drill spacing at a time so there is probably some ebb and flow in the collateral. I have had people tell me that large oil companies do not take out loans against leased acres so they can develop, but if a company is worth several billion dollars, I consider them large and loans of 600 million or more are not pocket change.
What people do not realize is that in the Bakken of a few years ago, you had to lease it or someone else would. You had to put a well on it or your lease would expire and some other operator could lease the acres you lost and drill a well. The cost of drilling and completing wells, I think, brought some companies to the edge and made them really slow payers when it came to royalty, so much so that the state had to pass a law that the operator MUST pay interest if you had marketable title, because operators were trying to skate on the interest even when people requested it. Face it, these oil companies did not have the money to pay, and continue to drill and complete wells. I saw several instances where the operator drilled several wells and did not even appear to be trying to get a frack crew. A pair of those wells were mine and they went unfracked for 9 months when there was only a 6 month backlog for frack crews at worst. My wells were fracked soon after my operator got a loan for 600 million dollars. My operator was drilling wells to extend leases but not completing the wells to produce because the completion cost as much as the drilling of the well. They were spreading their money as far as it would go in anticipation of the loan.
There are some operators that still look like they are on the edge. In my opinion from the complaints of not paying royalty for more than a year after first production added to their recent acquisition of producing and non-producing acreage in good areas that could not have been cheap, XTO is one of those companies spread too thin. If they don't like me saying that, they can pay some mineral/royalty owners and prove me wrong.
Lori, what you've described is largely how the financial game works. In part a company's stock market value is determined by the amount of reserves they hold. Though generally their loans are tied to existing wells. So while indirectly tied again to reserves, the loans are tied to "held by production" lands not lands which are only leased. If you subscribe to the NDRIN website you'll find a number of mortgage agreements between oil companies and lenders which list the borrower's interest in a hundred plus wells backing up the loans. You're also right about some getting overleveraged. Chesapeake was looking very shaky until they unloaded a number of assets for cash. I don't worry too much about the primary players in the Bakken. Mr. Kennedy what you described with XTO, or my experience with EOG, is due more to a company being under staffed and indifferent about getting checks out in a timely fashion. Neither XTO nor EOG are cash strapped. Though if oil were to fall to $30 per barrel again even the largest of them will be in a huge bind. That is my 2 bits.
I do not believe that absolutely nobody in any particular spacing has marketable title. If people have marketable title they should be paid, before the very last 1/10th of an acre has had the title verified, but that is what appears to be happening. As to being short handed, it's the companies own fault and not a valid excuse. Operators could have hired people in the last several years. If you allow the operators to cop out on this there will be no end to it. E MT, you are correct that EOG and XTO are not cash strapped, have you considered that they might be if they paid all the royalty they owed, some of which they are more than a year behind on and may owe interest to boot?
Eastern MT said:
Lori, what you've described is largely how the financial game works. In part a company's stock market value is determined by the amount of reserves they hold. Though generally their loans are tied to existing wells. So while indirectly tied again to reserves, the loans are tied to "held by production" lands not lands which are only leased. If you subscribe to the NDRIN website you'll find a number of mortgage agreements between oil companies and lenders which list the borrower's interest in a hundred plus wells backing up the loans. You're also right about some getting overleveraged. Chesapeake was looking very shaky until they unloaded a number of assets for cash. I don't worry too much about the primary players in the Bakken. Mr. Kennedy what you described with XTO, or my experience with EOG, is due more to a company being under staffed and indifferent about getting checks out in a timely fashion. Neither XTO nor EOG are cash strapped. Though if oil were to fall to $30 per barrel again even the largest of them will be in a huge bind. That is my 2 bits.
Mr Kennedy, don't misunderstand. I am not excusing these companies. They should have hired proper staffing but have not. While I am annoyed by the delay to pay, ultimately I will be compensated with a high rate of interest on the overdue funds owed. That unnecessary expense to the company is a problem for the shareholders more so than the mineral owners. Any company can get into a cash bind. However I am not particularly worried that EOG won't pay (nor would I worry about XTO which is an Exxon subsidiary). Yet if I were a year in arrears with a smaller company such as Kodiak I would be very concerned about it. None the less, nothing is certain until the check has cleared the bank. I'll let you know if this EOG business drags on any further.