Leasing, Pooling, and Covenant to Market

Oklahoma Mineral Rights Hughes County, OK
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Oklahoma being, as I understand it, an “implied covenant to market” state, this means that the lessee (operator) can only charge the lessor (royalty owner) for post-production costs if the lease includes words to that effect. This is why the operators keep trying to put those words in, and owners keep taking them out. OK, I get all that.

But if there is never an agreement to a lease, and they pool, does this mean - in Oklahoma, at least - that they can NOT charge any of those PP / Marketing costs?

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That is a very good question. Not an attorney, but my understanding is that a pooling order is gross proceeds and all of mine acted that way until recently. I have a few that are trying to charge PPC and when I have time, I am going to check into it. If they have the older wording, in my opinion, then they should be gross. Some of the newer ones are getting sneaky and adding in the PPC costs in the pooling.

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Thank you for the response, Martha. I guess it’s “normal business” and we have to watch them like a hawk. :laughing:

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Mainline 13, If you are force Pooled, YES, the Applicant/Operator WILL charge back to you PPC’s including marketing costs unless you address and prevent the PPC’s in either the 1. OGL with your Exhibit OR 2. force the Applicant to include your Cost Free Royalty (CFR) clause in the Final Pooling Order. The Applicant hates the latter because then all other unleased RO’s benefit and ride in on our coattails. Also, the OCC publicly states in conjunction with the O&G Public Assistance Department and the O&G Conservation Division advise, “Your interest will probably be charged post production charges under a pooling order,…” Remember, OK is a marketable product jurisdiction and therefore the Operator has to pay you on a marketable product without any PPC’s being charged back to you UNLESS you waive that right. Remember, in an OGL, everything is negotiable. In many cases, if I can’t get the landman to include my CFR clause with the OGL and my Exhibit, I then don’t lease and wait for Pooling. After the Application is filed, I then prepare a modified Exhibit including my CFR clause and give the Applicant a choice: 1. accept my modified Exhibit to attach to Applicant’s OGL, OR, 2. I file my Protest/Objection in the Pooling proceeding with the OCC and require the Judge (ALJ) to include in the Final Pooling Order my CFR clause. The Judge doesn’t have a choice because the Supreme Court case law which was affirmed last year in the Appellate Court of OK, requires a cost free marketable product for the Royalty Owner (RO). In doing this I guarantee that I get the CFR clause in either of the above options. George Wilson

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1.George, Which Appellate case are you referring to? How did it affect the pooling cases?
Up until a few years ago, all of my force pools were gross proceeds. Only recently have they tried to sneak in PPC’s.

  1. If I am a mineral owner but my minerals are tied up in an LLC or trust do I have to hire an attorney to file the protest or can I do it myself? If I am an individual, can I file a protest under my own name.

  2. I have a quote from the OCC as of Dec 2014. It says "…in 2011, the legislature amended 52 O.S. Section 87.1(e) to provide that implied covenants were to be recognized in the interpretation of the pooling statue and order. The provision regarding implied covenants is quoted and highlighted below: "For the purpose of this section, the owner or owners of oil and gas rights in and under an unleased tract of land shall be regarded as a lessee to the extent of a seven-eights (7/8) interest in and to the rights and a lessor to the extent of the remaining one-eighth (1/8) interest therein, unless and until the owner or owners make an election or are deemed to make an election not to participate under a pooling order issued by the Commission, at which time each such owner shall be considered a lessor, subject to the judicially recognized implied covenant to market found to exist by the courts of this state in oil and gas leases covering lands located in this state, to the extent of the full royalty percentage elected under the pooling order."

How does the comment from the OCC differ from what you are saying? I read that comment above to say that a pooling order does not charge PPCs. Please clarify.

Do you have an example of a Cost Free Royalty clause that has stood their test?

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Mary, and other readers, please understand this information is not to be construed as legal advice:

Bottom line, a RO does NOT have to waive her/his/its case law right to be paid on a marketable product and WITHOUT any PPC’s.

1 Mittelstaedt v Santa Fe, 1998, OK supreme Crt, further confirming that OK is a marketable product jurisdiction, the Operator has to make the product marketable (unless RO waives this case law right, see discussion below) with no PPC’s being charged back to the RO. Mittelstaedt was acknowledged in the Pummill V Hancock, 2018, OK Civil Appeals, with further discussion as to when the raw gas (gas at the mouth of the well, value set at $2 per mcf, estimated) becomes marketable (value set at $3 per mcf, at the tailgate of the existing processing plant) further clarifying how and when the enhancement issue comes into play. The Mittelstaedt case sets forth what must be shown if the product is “enhanced”. Bottom line, does the RO want to be paid $2 / MCF OR $3/ MCF for her/his/it’s gas???

  1. Anyone/entity can represent themselves in any Court including the Court system within the OCC. And yes “you can file a protest under your own name”. Caveat emptor, the procedure can be lengthy and beware of the pleadings, filings, Court hearings and followup.

  2. 52 OS 87 and PPC’s. The statute requires you to look at the “oil and gas lease”. It’s saying the same thing that I’m referring to.

Remember, All terms in the OGL are negotiable. In the largest majority of OGL prepared by the Oil company, the express provision provides that royalty is due “at the well” or “at the wellhead”. This waives your right to a cost free marketable product. From the wellhead, The gas is in a raw form, and the Operator will pay you $2 / mcf. After the gas is processed and turned into a marketable product, it’s worth $3 / mcf. I want to be paid the $3 bucks, not $2 per mcf.

Note, my negotiation for negotiation/dealing in the force Pooling arena differs from the leasing stage dealing with the landman. In the Leasing stage, my clauses necessary for the RO are extensive relative to the RO’s nma’s. But If I “Can’t Work a deal with the landman” and I have to have my CFR clause included, I wait for forced Pooling. I can have my CFR clause included in the Final Order. See my previous Post. The Operator doesn’t like my CFR clause because all other unleased RO’s can then take advantage of my CFR clause if it’s included in the final pooling Order.

$195, that’s my total fee to represent someone to file the Objection, apparel in court and guarantee that the CFR clause is included. You can’t do it yourself for that small Fee.

You then ask, for an example of my CFR clause. Here tis’. Without charge. If anyone sees any improvement, please let us know by calling me or Posting.

My best and I hope this equalizes the playing field between you and the big ole’ Oil Company.

George Wilson

“Cost Free Royalty Payments: Lessee shall pay royalty on the fair market value of the marketable product, which is the price received by the Lessee at the final point of sale, with an arms length transaction, to a bona fide purchaser, without any post-production expenses or charges or any other cost of making the products produced hereunder ready or available for market being prorated back to Lessor. Such post-production expenses or costs are to include, but are not limited to, the cost of producing, gathering, storing, separating, treating, dehydrating, compressing, processing, manufacturing, transporting, and marketing the oil, gas and other products produced hereunder. Royalty will not be paid on a “raw product” as produced at the “mouth of the well” or “wellhead” but will be made on a “marketable product” as described above. However, any such costs which result in enhancing the value of the marketable oil, gas or other products to receive a better price may be deducted from the gross value of which Lessor’s royalty share is calculated as provided under the guidelines established in Mittelstaedt V Santa Fe Minerals, Inc., 954 P 2d 1203 (Okla 1998). If the product is enhanced, Lessor shall be notified in writing.”

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You have some good points in the first half, but your “however” comment at the end opens the door for deductions, so can’t really be categorized as “no cost”.

Here is an alternate (appreciate any comments):

No Deduction: Lessor’s royalty will never bear, either directly or indirectly, any part of the costs or expenses of production, separation, gathering, dehydration, compression, transportation, trucking, processing, treatment, storage or marketing of the oil or gas produced from the leased lands, or any part of the costs of construction, operation or depreciation of any plant or other facilities or equipment used in the handling of oil or gas, regardless of whether the costs or expenses set forth herein are incurred directly by Lessee or Lessee’s purchaser, affiliate, a midstream company or any other third party. For the purposes of this subsection, where any third party (including, but without limitation, any purchaser, affiliate of Lessee or midstream company), receives or retains a portion or percentage of the production (including, but without limitation, oil, gas, residue gas, processed liquids (or natural gas liquids) or any other constituent or component derived from the gas) in exchange for incurring any of the costs or expenses set forth herein, such as under a “percentage-of-proceeds” contract as the term is used in the industry, that portion or percentage received or retained by the third party shall constitute an indirect cost or expense that shall not be assessed against Lessor’s royalty in the same manner as if such cost or expense had been incurred directly by Lessee. In no event shall Lessor receive a price that is less than the price received by Lessee or any Lessee affiliates thereof.

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Martha, several things:

Your CFR clause is for the initial negotiation with the landman for an OGL. (Anything is negotiable) My CFR clause is to be used in the force Pooling hearing after negotiation with the landman has failed. I have to comply with OK case law, the Mittelstaedt case which deals with enhancement. And at least it will be ordered in the Final Order for no PPE’s subject to enhancement, assuming the Lessee hasn’t accepted my simplified Exhibit to attach to its OGL. It’s an automatic win for me.

And regarding enhancements, I’m not aware of any case law affirming enhancements. Why? The difficulty is for the Lessee to show that: 1. the costs enhance the value of an already marketable product, 2. that such costs are reasonable, and 3. the actual royalty revenues increased in proportion with the costs assessed against the mineral owner.

And as shown in the recent Pummill case, gas doesn’t become marketable until the processed gas reaches the tailgate of the gas plant. Has it ever been shown (other than hypothetically) that you can enhance an already marketable gas product?

Also, I like to state that the royalty will not be paid on a “raw product” as produced at the wellhead, but paid on a marketable product. If your OGL states that the Lessee will pay you at the wellhead, your subsequent CFR clause could be argued useless because there are no post production expenses at the as the gas surfaces from the wellhead. The Supreme Court to our South rendered a decision in favor of the Lessee. We need to prevent this argument from raising its ugly head in OK.

As always, my best, and I look forward to seeing you at Barton Creek in July for the NARO TX Conv at Barton Creek. Dinner is on me.

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M Barnes and George,

Well-------after this intellectual exchange I would like to restate what I’ve already said to M Barnes: Quote! “When I grow up :slight_smile: I want to become a GEOLOGIST like M Barnes,” UNQUOTE. Such interesting stuff in this OIL & GAS business,…Leta C. MONTANA (Big Sky and Grizzly Bear Country).

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Excellent points! Yours is for a different purpose. Thank you for the clarification. See you at NARO in July!

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As I understand it, the Mittelstaedt v Santa Fe decision does allow Transportation charges to the nearest market, if there is no “market” or custody-transfer point at the Lease (referencing Johnson v Jernigan, I believe). Since the only charges I’m seeing on my royalties are Transportation and Severance Tax - and no mention of costs in the Lease, one way or the other - I guess I am out of luck, yes?

That said, I think they did mention that the Lessee had to show that the transportation costs were reasonable, paid to a valid 3rd-party, etc. Not sure if that gives me any other options, unless I seriously think they’re padding it.

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Mainline13, first, you need to review your OGL. It will explain what is permitted to be deducted as post product expenses (PPE).
As a striating point, Mittelstaedt states that Oklahoma is a marketable production jurisdiction and as such the operator must make the recovered product, ie gas, marketable and should not charge back to you any of the PPE’s to make the product marketable, unless the operator enhances an already marketable product and may be able to charge for such enhanced expenses under the guidelines as set fort in the Mittelstaedt case. But I believe it’s best to include a Cost Free Royalty (CFR) clause in the OGL to fully clarify no PPE’s.
As for the Severance Tax, you will pay your proportionate share of the tax, unless your OGL and/or attached Exhibit prohibits such deduction. If I can’t get a clear agreement with the landman regarding PPE’s, I wait to be force Pooled, file a protest, and before the OCC Judge I argue that I don’t want to waive my Mittelstaedt case rights and my CFR clause and I win.

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Thanks for the reply and the good advice, George. Unfortunately for me, it’s going to be strictly for future reference. My leases were active when I got the rights signed over to me, and that was 25+ years ago. Not a word about post-production expenses in either of them.

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My understanding (which is always questionable) is that the phrase was used in the findings of an Oklahoma Appeals court. The usage was that a Lease is a covenant, or agreement, for the Operator to get the hydrocarbons out of the ground, and into a marketable condition.

The upshot of that is that if a Lease does not say otherwise, the Operator can’t charge the Royalty Owner for any expenses of making the product marketable. There are some notable exceptions to this, such as transportation costs, when there is no on-site sales point (i.e., “market”).

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From a forced pooling: Is there a typical percentage from gross that an oil company deducts for enhancement?

I was forced pooled in Coal County Oklahoma, December 2018. I am receiving checks from Canyon Creek with either a 2 or 3 percent deduction under the heading “Other DED-1.”

I plan to contact them regarding the charge but first wanted some input from you and Martha.

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I just realized my calculation of 2 or 3 percent in the above question was wrong. The actual percent Canyon Creek is deducting as “Other DED-1” has been 20 percent and 28 percent.

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There is no “typical” deduction percentage for the post production charges. The taxes are set, but the others are not. You can request breakdown of the costs, but you may not be able to get it. Someone with more legal knowledge may need to comment here. In the “old” days, poolings were without post productions charges. More companies are pushing the limits now. You may be able to request the breakdown under a case called Mittelstaedt which has standards that have to be met. The wording of the pooling order is also important.

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Martha, Thanks for the reply. The well began producing 5 months ago. Three of the four months were 20 to 28%, one was negative, and the last month was only 3%.

In reading the pooling order, I didn’t find that it addressed the charges, but I will read it again. I will request a breakdown after reviewing Mittelstaedt.

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Google Mittelstadt v Santa Fe 1998

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Hi Martha, To bring you up-to-date: Canyon Creek continues to charge large deductions from my royalty checks, most recently 44%. After reviewing Mittelstaedt v Santa, I wrote to Canyon Creek requesting specific information:
(1) What specifically are the deductions; (2) Were the deductions associated with the enhancement of a marketable product and, if so, when were the charges assessed (after the product was already marketable or before the product was marketable); (3) Were my royalty revenues actually increased in proportion to the costs assessed against my non-working interest; (4) I requested printed data that would substantiate the substantial deductions. After 30 days of receiving no reply, I sent the same request by certified mail to Luke Essman, President and Chief Executive Officer of Canyon Creek. After an addition 30 days, I am writing to others on the forced pooling to see if they have noticed or inquired about the excessive deductions. Of course, I am not surprised Canyon Creek didn’t respond. Even though my interest is small, I will eventually call an attorney. Canyon Creek has made me mad.
Thanks for reading. Judy

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