Canyon Creek is not the only producer that has ratcheted up deductions. Both Silver Creek and Trinity are now deducting in excess of 50% (inclusive of OK state taxes and production taxes) from total revenue on my monthly royalty checks. Up until January of this year (2020), my deductions never exceeded 30% (inclusive of OK state taxes and production taxes).
My assumption is that the producers have fixed costs that they are trying to recover with increased deductions from the royalty owners. I don’t know if this is legal or not, regardless of what is stated in the lease re deductions. And, I wonder if the deductions will go back to 30% (more or less) after the downturn in natural gas prices rebounds.
Robert, Thanks for replying.
I calculated Canyon Creek’s deductions from my royalty checks for costs only and not for taxes. I have checked the other oil company check details I receive and their costs are either none or small.
I do not receive revenue from either Silver Creek or Trinity.
Robert, I missed that Singer Oil charged 34% toward costs my last revenue check. Singer recently took production on the well (Gilmore 1, Logan County 34-15N-4W). DCP was former producer and did not deduct production costs.
@Judy_Phillips - the questions you asked in your letter are on point and incredibly helpful as I am working on a similar issue for someone right now.
I remember it was becoming a big issue when I was working for an oil and gas operator. From what I remember PPC seems to be handled differently company to company - it seems like quite often it was a “wait to see if someone barks and then settle it as the fire comes up” type of situation. (ie. a business decision based on workload to go back and correct for all owners on all wells or just fix it as a person disputes and correct it in the future)
Would you mind sharing if you were ever able to work it out and get resolution? I appreciate anything that may help in the future!
Thank you to everyone who has commented on this thread. I am new to the process but have been reading many of the posts in this forum as well as listening to podcasts on mineral rights.
I am in the process of negotiating a OGL and am trying to get the lease agreement in my favor before sending it to a oil/gas lawyer to review. The oil/gas company has agreed to provide a cost free royalty and have added the clause that M_Barnes suggested above as an exhibit “A” added to the end of the lease. However, I am concerned that in the beginning of the lease, they still have clear language that define how the royalty will be paid:
“for oil and other liquid hydrocarbons, royalty shall be “?%” of such production, to be delivered at Lessee’s option to Lessor gross proceeds or to Lessor’s credit at the oil purchaser’s transportation facilities, provided that Lessee shall have the continuing right to sell such production to itself or an affiliate gross proceeds market price then prevailing in the same field (or if there is no such price then prevailing in the same field, then in the nearest field in which there is such a prevailing price) for production of similar grade and gravity; b) for gas, royalty shall be “?%” of the proceeds realized by Lessee from the sale thereof, provided that Lessee shall have the continuing right to sell such production to itself or an affiliate at the prevailing wellhead market price paid for production of similar quality in the same field (or if there is no such price then prevailing in the same field, then in the nearest field in which there is such a prevailing price) pursuant to comparable purchase arrangements entered into on the same or nearest preceding date as the date on which Lessee or its affiliate commences its purchases hereunder.”
Doesn’t this language basically negate any “cost free royalty” or “no deduction clause” later in the lease or put in as an exhibit, at least by the current understanding of the law in Texas? Should i push to have that removed and replaced with the cost free royalty clause instead of having the cost free royalty clause added as an exhibit?
In most cases the exhibit overrides the first part of the lease if it says that it does. Best to just give it to the attorney to review so that you do not accidentally contradict yourself. They are use to cleaning up the language.
It is amazing. How topics come back around just when you need them. I know these two questions are really basic. But I just want to make sure I understand.
I have received very many pooling notices in the last few months.
Is this the time to check the post production cost phrasing?
If the original lease allowed post production costs is it possible to change that after pooling?
TiA!
Check your lease offer for any post production charges. Usually, they try to sneak them back in. Always wise to have an attorney review any draft leases. An investment that can add many dollars to your long time royalties.
If you are held by production on a lease, then you are in the secondary term of the lease and no changes are allowed until the lease expires by its own terms.
If you are pooled on a new zone or area outside of the lease, then you are free to either lease before the pooling order response time expires or you can go with pooling. In many cases, I prefer the pooling if I cannot get a good lease with the operator.
Wow, I just found this information! Is this still possible, and does anyone have experience with this recently? I’m really trying to get a cost free royalty(CFR) through my Gross Royalty/No Deductions Clause in my negotiations with the landmen and failing. George_Wilson1, if you’re still on this forum, or M_Barnes if you have experiences utilizing this info and process, I’d love to hear more!
If you are dealing with an operator, it can be difficult. If you are dealing with a third party working interest owner, then it can be easier. The middle ground in OK is a clause with the Mittelstaedt language from a particular court case. There will be some charges but they will be proportional to the value of the enhanced product. Taxes will be taken out according to statute, so you have to pay those.