Looking at the GIS map this morning, ‘my’ area, 150/101/6, which had a black dot and the drilling line, now has only an orange dot. What does that mean? Probably not that “a check’s in the mail.”
Ed, I missed your post. I wish you’d shook me and woke me up. Your well was spud 10-29 of last year and alot of times the operator does not ask for true confidential status to begin until they reach total depth, probably a month after spud date, meaning it’s proper for your well to be an orange dot right now. Now for the good part, They paid for another permit on 2-21-13, after they had some input from the drillbit from your first well. While I don’t put a great deal of stock in a permit, I do know that they didn’t have to pull one just to mark their territory because they already have a well drilled. I’d be optimistic that they may have found something they liked.
Ed, they may or may not have fracked your well over the winter, I know it’s extra bother to put more additives in the frack gel and use heater trucks to keep the frack juice from freezing so they can pump it. If they fracked it we could see some production numbers in a few months, if they haven’t fracked it til now it will probably be five or possibly 6 months. I hope they don’t let your well sit unfracked for 9 months like they did two of mine, takes alot of the fun out of it.
No problem, Mr. Kennedy. My question as to the meaning of the orange dot was a bad question. I didn’t realize I could turn on the meaning of more symbols on the GIS map. It is awkward being out here in the State of
Washington, when all the fun is going on back there. Have to find a way back to my root place, Alexander, and take a picture of ‘our’ well. Tough being an absentee oil baron! I had wondered about fracking in the winter. I am encouraged by the second permit. It seems like our field is directly under the town of Alexander. We have a nice artesian well in the town park, so I hope it isn’t negatively affected by this work.
Had oil leases that were drilled and producing by Denbury Resources and was notified that XTO Energy had taken over these leases in July 2012.Does anyone recall what XTO paid Denbury for their assets in N.D.? Just curious.
Thanks,Dan
Mr. Smith, I don’t know what I was doing but I missed some messages, Ed Arildson’s and yours. I hate that when the news can be considered good.
Mr. Smith, I don’t think you need worry about leasing those spacings. 150-98 28/33spacing has a well down the middle of it so those sections are held and… you have 3 wellbores in the 32/29 spacing.
28/33 spacings well is the SORENSON 31-28SWH cumulative production of oil 91,874 in 15 months as of Jan and 4,900 bbl in Jan, without pump because it has pretty darn good field pressure producing 10,824 mcf [thousand] cubic ft of gas in Jan, probably rich gas to boot. Mine sells for $6 to $7 per mcf, not a fortune but I’d keep it.
Now for the 32/29 spacing.
SORENSON 34-32NWH cumulative oil of 122,318 bbl for 18 months as of Jan and 5,400bbl in Jan, it’s on pump probably part time, 196,626 cumulative mcf gas.
GV 44-32NEH cumulative oil 31,386 bbl for roughly 3 months as of Jan and 8,583 in January, still flowing. 63,362 cumulative gas 14,161 mcf in Jan.
GV 44-32NH cumulative oil 8,077 for roughly 2 months, already on pump less gas. I wouldn’t give up on this well doing better, but not every well is a home run.
The best news is that while the names of these wells don’t give much away as to which direction the wellbore will go. I think it’s possible that you are getting 2 more wells drilled from section 29 and going south into section 32. There are 4 spudded confidential wells and I don’t think all of them are going north away from your acres.
I’m kicking myself right now, I hate missing a chance to give some good news. I hope you have lots of acres under all that, sorry for the late reply.
Thanks Mr.Kennedy for all of your help.
Dan
In July of 2012,XTO Energy either purchased or took over some assets from Denbury Resources.Included in this transaction were the assets on sections 31,32,33,34,township150n,98w.I was curious if anyone else was having problems with XTO not reconizing and not paying for the product from producing wells.May also include other sections and other counties.Would like to hear from other mineral owners.
Thanks,Dan
Mr. Smith, SM Energy is operator in section 34.
That said, it’s a great area. It would be unconsionable to me if I were in charge to sell such an area…unless there might be something else wrong with it such as a title problem. Might explain the lack of royalty payments. Of course XTO could have suspended all payments until they verified all ownership.
That is alot of very expensive mineral rights. XTO may be in a cash crunch. If I were in charge at XTO and I was offered those acres at an attractive price, I might not buy them knowing I would have to rob peter to pay paul, but I don’t think an oil company would hesitate. About all you can do is reach into your hip pocket to pay a lawyer to send them a letter. If XTO does not respond, or even if they do, you might have to sue. It would be nice if you could get everyone affected signatures, or in my case I would just put 10 signatures on the letter and tell them that the others were omitted for brevity, let them wonder.
If you did sue and win, got paid, recovered attorneys fees, unless the payment of royalty was a condition of your lease, XTO will still own your lease, will continue to make money off of it, it will just be 1% to 2% less profitable over the long haul. The lawsuit could be cheaper than paying loan interest. I would not worry about making them mad, what are they going to do? Not pay you? How would that differ from what is happening now? Welcome to oil & gas.
. My brother and I are PR’s for my father’s estate which includes real property and 75% of the mineral rights under the real property. An error was made in the vesting of title to my parents on a Limited Warranty Deed for 20 acres of mineral rights, which changed the title to tenants in common. The abstract of deed clearly states joint tenants. All of their other property was held in joint tenancy, so when my mom died it just passed on to Dad. He had no reason to suspect that title would be anything other than Joint Tenants because that is what was called out in the Contracts they signed. The Bank will not correct it becasue, according to them, they cannot re-issue a Deed to people that are deceased. We have been told that we will need toSto open another probate for my mom for just those 20 acres of minerals so we can transfer title properly. I’m thinking there must be another way to do this; someway to get the bank to correct the deed? Or can we just file an affidavit of heirship, or something similar? Any suggestions would be greatly appreciated!
I have 160 acres currently under lease T149, R103, Sec. 2. Anyone hear of activity in this area?
Frank, the nearest rig is about 5 miles away. There are 3 permits about a mile north of you. There are a couple of fair to good 1 mile lateral wells withing a couple of miles of you and 2 good Bakken 2 mile lateral wells within 2 to 3 miles of you.
There are no drill permits in your spacing right now. I think it’s inevitable that you will be drilled but I can’t say when. I think the operators consider your area profitable but not exciting. Hang in there.
Is it true that Continental and QEP Resources are offering $50,000.00 per net acre in the bakken? Heard it from a stock broker friend. Just wondering.
Hello folks,can anyone tell me if it is possible to get a list of mineral owners,per section,online.I was interested in sections…31-28 and 34-32.
Thanks,Dan
Dan, the answer would be yes but not necessarily a complete list. A NDRIN subscription would let you look at every recorded document referencing the section, including leases, statements of claim, deeds and probates.
Any thoughts appreciated ; )
Britta, that seems like a good area. The initial production on the well already producing was 1458 barrels oil in one day. The other wells may be better than this. Between your four wells you could recover $5,500 per acre over the next 5-7 years. There is also the possibility that these wells being drilled now are not going to be the last wells drilled because you are probably over another produceable formation and all these wells are Bakken. You could have another 4 to 8 wells in the future. Britta the operator may not be operating your well at it’s maximum safe rate. I think it likely that your buyer intends to make his money back in 5 years and a good profit thereafter for decades. If I didn’t need the money really bad, in your posiion I would not sell because you are going to get a large check within the next year and one years production of all four wells may be half of what you were offered.
Does anyone know how to get copies of the ND Industrial Commission pooling orders? I know how to get them in OK, but can’t figure out the secret to ND. I have a subscription to the NDIC, but what is the magic button? Thanks.
I agree, the thing about tight oil is that it takes time to produce. 25 to 50 barrels of oil per day from a projected 40,000 + wells is diffuse but massive.
There are any number of issues to consider when considering leasing or being force-pooled. One needs to understand that being force-pooled ultimately means that the mineral owner is now a part of the working interest owners’ group and must participate in his/her share of the cost of drilling the well and, if successful, the continuing operating costs. Typically, taking a working interest is a much more expensive way to go so most mineral owners prefer to lease and not have to worry about having to pony up their share of the well costs every month.
In the Bakken, here have been hundreds, perhaps thousands of working interest owners who have been “AFEd” into oblivion. An AFE is an “authorization for expenditure.” Essentially, it is the bill the operator gives the working interest owners every month for well costs. If the mineral owner can’t come up with the money (normally within 15 to 30 days), he/she is considered to have gone “non-consent.” At that point, that mineral owner will not have to pay any future AFEs, but he/she will also be penalized some multiple of the total cost of the well that he/she did not pay before he/she will ever see a cent in royalties.
In certain circumstances, that may be just as well. Working interest owners share in all the costs of a dry hole. In an area where the costs of wells are upwards of $12 million, that’s a pretty severe tax write-off. The non-consent working interest owner is off the hook, however, and is not responsible for any of those costs.
In North Dakota, the statutory penalty for the non-consent working interest owner is 200%. Therefore, if the well is successful, the non-consent owner is liable for twice his share of the costs of the well, and he/she won’t be paid until all the other working interest owners have recovered their initial well cost of $12 million, plus twice the non-consent owner’s share of the costs. If that owner’s unpaid share was $1 million, he/she will lose $1 million in revenue that he/she would otherwise have received had they been paying their share all along.
That’s the simplified version. It’s also why most working interest owners are exceptionally wealthy. If you own a small interest on a large tract of property, it is possible that being force-pooled may effectively cut you out of any revenue whatsoever for a significant length of time.
If you’re not wealthy, the best strategy is almost always to negotiate the highest bonus and royalty you can get from the lessee. Also, if you here that nothing but dry holes are being drilled around you, you may want to consider selling off your mineral rights to someone who’ll give you Bakken prices for minerals that may not ever be drilled. Stranger things have happened.
I hope this helps a bit.
I’d rather be force pooled anytime in ND, but as a practical matter, 5 times nothing is still nothing, so you might as well take the lease bonus unless you are taking the very long view that something, a better formation will turn up.
Multiple wells would be better for force pooling, makes it very likely that after the wells have payed out and have declined to a more steady curve that it would still be worthwhile to be a working interest.
Something that people don’t think about is that you don’t have to be a working interest forever. You can sell your interest in a particular well and retain your rights for any other well or future wells. You might be able to sell a working interest for more than you would receive if you collected royalty for 30 or 40 years, but have your money sooner.
If the well never pays out, you don’t have to worry about the bills.
Worst case, the well pays off and recovers the penalty after a long time and it could possibly cost more to operate than it makes. By law you could assign your interest in that well to the operator and the operator would have to pay you salvage value for your portion of the well equipment, and from the time you assign your interest in the well to the operator, you are no longer responsible for the well’s bills.
If I should live so long (probably won’t) I would surely give my part of the well to the operator when I think it’s time to plug it, so instead of paying for my share of plugging, I get paid for my share of the equipment and walk away.
I know, crazy talk.
I recommend that you read NDCC 38-08-08. The penalty is 50% of actual cost of drilling and completing the well. It’s a penalty and interest does not accrue. When the cost of the well plus penalty are recovered, you have a working interest that pays you 100% less cost of production/operation that can be as low as $2 per acre per month.
If you wanted you could say that the lease has an 80% penalty that is never retired.
The difference between a 20% royalty and the 16% royalty that the operator would most likely have to pay you if you refused to lease is not that great when you consider the possible upside. If someone leases and not everyone gets 20% but we will say they do. The lessor collects 4% more royalty for 3 to 7 years, all is well and good from the lessor side until the well and penalty pay out for the non-consenter who will now catch up and pass the lessor because the difference is no longer 4%, it’s now 60% in the non-consenters favor, more if you count tax deductions.
All wells that keep producing will eventually pay off. If the well is really bad, the operator will plug it. If it never pays out and recovers the penalty, you owe nothing out of pocket.
To me, leasing is saying that for a palty lease bonus and temporarily 4% more royalty, the operator gets 80% of your minerals as long as they get anything out of the ground. I say temporarily because when the well pays out and the penalty is retired, that “4% more” no longer exists.
Awhile back, the CEO of EOG was on Mad Money and said that at $100 oil they were making about $60 per barrel, that was after costs and paying the mineral owners royalty. If you don’t have to pay anyone a royalty, how much are you going to make per barrel? $80 after expenses. If you make 1/3, 33% more money than the operator per barrel of oil and you can’t pay your bills, pity the operator.
If you put 25% of what your working interest pays into a money market account, or pay off your house and open a line of credit, no reason the money can’t be put to work so long as you are liquid if a bill does come up. A $500,000 bill on a 1280 spacing in which I have 5 acres, my part is roughly equivalent to have the transmission rebuilt in my car and I have that covered.