Thank you Charles. I have done some further research and I guess I’m going to have to go back at it. XTO is a real pain, but I do have established contacts there.
You should be receiving royalties from the Williams County mineral areas. Looking at the GIS map, your area which is the Grinnell Field, has several wells (laterals) which enter your areas. Looks like XTO operates these wells and it appears they were drilled several years ago. Contact the NDIC for particulars on this matter but you definately need to pursue this matter ASAP.
I have been going through my deceased mother’s papers. I thought all our mineral rights were located in McKenzie County, but found some in Williams County:
It appears that there may be wells located there operated by XTO and Continental. I’ve been going through pure hell for months trying to get XTO to pay what they owe from McKenzie County (seems to be cleared up now) and would like to know if what we have in Williams County is worth the fight. In the 2 years I have been receiving checks, none were from Williams County and I was surprised to come across this new paperwork.
I have a partial mineral ownership in 157 north - range 101 west, section 2. I am receiving a royalty from the Stromme well that runs under my section. Can more than one well run either across or on my section? Any comment will be appreciated. Gene.
You might want to get someone to look over your lease to verify it contains a pugh clause. If it does, you might still be able to lease additional minerals.
The answer to your question is yes. An operator can and possibly will over time drill multiple wells in your spacing unit. These areas where well exists are now held by production so some operators are at the stage of adding additional wells to the unit.
If you are receiving royalties, you are now Held by Production (HBP) and your lease is not up in 2014. It will be held by the terms of the lease as long as there is production. If you are lucky, more wells will be drilled.
Thank you all for your input. I did ask for the pugh clause but I’m not sure where in the lease that I should look to confirm that. Thanks again.
Thanks for your prompt reply. Our lease originally was with PetroHunt and was sold to Halcon of whom I am currently receiving royalty payments from. The lease is up in 2014. Does that mean that it will automatically be renewed by Halcon or will it be open to other companies at that time?
M Barnes is correct and note the terms of your lease. If you had a pugh clause, there might be a chance for additional leasing but if not, you most likely are HBP.
http://www.landmen.net/ClausesForms/ClausesForms.htm look at the wording for the vertical and horizontal Pugh clauses and see if you have one. I put depth clauses in my leases (vertical Pugh clause) , so am able to lease again in certain areas even if held by shallower production. Also depends upon the size of the spacing. Check for spacing units to see if you are held by section next to you.
Laurie, no permits filed on your spacing but there is drilling activity very near you. The wells surrounding you seem fair to good but nothing world shaking.
You did not mention the royalty percentage which is very important. In your area I would consider $2500 to be generous if the royalty was at least 20%, a mediocre offer for 3/16ths a poor offer for 1/6th and a joke in very poor taste if for 12.5% royalty.
If your offer is not $2,500 per acre and 20% I would start looking for offers beyond KOG because someone might want to participate as a minority interest in the well for your acres.
I am sad to say that I don’t see any multi-well units near you, it looks like one (well) and done for the present time so it may be a long wait between the first and second well.
current lease expires
Hello, My very first post:
Our family owns the mineral rights of nearly 600 acres in Williams County. The current least expires in May 2014 - no well drilling to this point.
We want to learn as much as possible about current prices being offered per acre; negotiation the royalty percentage; well drilling in or near our location: sections 3 & 4 at T 159 N, R 102 W; and many other pertinent pieces of data. Thank You Laurene
Newfield Production Co. has a well with a lateral running into section 5 which is located beside your section 4. Don’t know any of the production data for this well. Advice would be to let the lease expire and don’t get in a hurry to lease. Wait and see what offers you receive as the area has had drilling activity. Since you have a sizeable amount of acreage, you should get a decent bonus and terms on a new lease. Also, don’t lease for longer that 3 years and hold tight with a 20% royalty.
Wayde, out of curiosity, how many years would it take, in your opinion to recover a purchase price of $6k per acre from present royalty on your acres? I think that if the answer is 5 or more, the responses you get will be minimal or counter-offers.
I won’t say don’t sell, but you need willing buyers. Have you received offers to buy your mineral interests?
In my opinion, I would collect at least 4 years worth of royalty before I sold because collecting a little royalty will not hurt the sales price and you will have made more per acre total when you do sell. You also have not allowed them alot of time to do any infill drilling.
I can think of alot of things that one could do with the money from a sale that would make sense, getting rid of crippling debt with high interest rates is one.
I hope you leased for a high royalty, the offers people receive for 1/6 seem to be alot lower, more that the difference between 16.67% and 20% would warrant, I guess because they buyers feel they have to reach a certain threshold of profit in a deal to make it worthwhile. Frankly, if it’s a good investment for the knowledgeable buyer, it’s probably an equally good investment for the average mineral owner.
Lease, then sell is probably the worst strategy there is. You sell 80% to 88% to the lessor for the bonus and a promise of royalty (which often doesn’t amount to much) and then sell the remainder, which is all the oil in place and your royalty. The only way you can get the most out of your first deal, the lease is to hold it and collect the royalty to the dregs. You lost 4/5ths of what you had in your first deal, and I think you will lose in the same proportion if not more in a sale of what you have left. Unless they are foolish, they will not pay much if your assessment of the acres is correct.
Good luck, whatever you do.
Sounds like you have made this decision based on extensive research via an attorney, etc. If selling is your desire, the only blank to fill in for now is the $$ amount for these holdings. I would advise advertising in as many sectors as possible including here on the forum, the Mineral Hub, and other sites dedicated to selling. I might even consider a small ad in several oil and gas publications based on the expense. I would advise selling the minerals as a whole and not divide up as this could cause additional worries. Finally, meet with a good tax attorney and learn that end of the deal which won’t be nice. Good luck.
Great advice Charles, I appreciate it. As a business owner in the past with my father, we learned much from asking around. I thank you for contributing to my education Mr. Mallory.
I am seeking to sell Mineral rights in Williams/Divide on 160 net acres. Currently producing and have been for two years are two wells, one on each property. With future increases in well permit production at a minimum in Divide, despite monthly revenue’s, with viable product, including potential for gas, holding the leases for the future is not in my best interest. I have used as many variables as I can, based upon my research for over 3 years, since we have renewed lease’s to seek 6-10k, per net acre. Would the oil company be the first to set my price to, or just place it on “open market”? Over time, I have discovered the little man is “puree” to so many in this highly cut throat industry. With that said, wisdom in business is always a plus, in an industry I am quite ignorant in. I 've done my best, have my attorney, and am not, marketing alone. Any advice? Thank you.
Sarah, you don’t know how far oil is being pulled from. They have done tests to determine if two wells communicated by pumping a marker chemical, chlorine I believe, down one well and check the well next to it to see if they get chloriine out. They didn’t get chlorine out of the well 1 mile away. Surprisingly, they found chlorine from a different well 10 miles away! The oil sits atop a water [ brine ] layer generally that they do not want to frack into as the market is poor for brine, so they try to orient the fractures so they do not go toward the brine but stay in the oil zone. The man made fractures must be relatively short in length because they have little control how the rock breaks 2 miles down. Natural fractures can be 10 miles, man made fractures 100’s of feet, that is why there is a 250 foot setback from section lines. If you have miles long natural fractures, someone else may pull your oil, but if / when you have a well, you will be pulling smeone elses oil too, this is where the rule of capture comes in. The oil was on your land when you captured it or it would not have come out of your well. It’s like hunting deer, you don’t need permission to shoot them on your own land although they may have started out on someone elses land… Oil and deer migrate. I hope this clears things up for you, it’s my best understanding of the situation.