Treating and Gathering Deductions not in the Lease, but being deducted from royalty checks

If treating and gathering are not mentioned in the lease, what tells me that they can deduct it from your royalty checks?   Section 4b of the lease states the following.   


The royalties to be paid by Lessee are: (b) on gas, including casinghead gas, or other gaseous substance produced from said land and sold or used off the premises or for the extraction of gasoline or other products there from, the market value at the well of one-eighth of the gas so sold or used, provided that on gas sold at the wells the royalty shall be one-eighth of the amount realized from such sale; such gas, casinghead gas, residue gas, or gas of any other nature or description whatsoever, as may be disposed of for no consideration to Lessee, either through unavoidable waste or leakage, or in order to recover oil or other liquid hydrocarbons, or returned to the ground, shall not be deemed to have been sold or used either on or off the premises within the meaning of this paragraph 4 hereof; (c ) on all other minerals mined and marketed, one-eighth, either in kind or value at the well or mine, at Lessee's election, except that on sulphur the royalty shall be one dollar ($1.00) per long ton.


I was mislead about the deductions and was not told upfront about these deductions. 
As a landowner,  it appears that they silently wrote it hidden and misunderstood.  Even though there is nothing that states the lessor cost or expenses. 

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My point is that you are implying that there are provisions in the law that provide for automatic interest after 60 days, and that there are statutory limitations on what may be charged to a Royalty Owner.


The only protections I know of are for interests that have been force pooled, as lease basis wells and voluntaery units would be governed by those agreements, contracts and leases.

From RS 30:10

(f)  In the event of a dispute relative to the calculation of unit well costs or depreciated unit well costs, the commissioner shall determine the proper costs after notice to all interested owners and a public hearing thereon.

(g)  Nothing contained herein shall have the effect of enlarging, displacing, varying, altering, or in any way whatsoever modifying or changing the rights and obligations of the parties thereto under any contract between or among owners having a tract or tracts in the unit.


It is clear in the code that the Commisioner has the right to determine proper costs, However, in practice he does not and simply defers his athority in such matters to the court system where the two parties can argue it out.


You shouldn't get so ruffeled up over someone challenging you on your knowledge, I think we all have more to learn and no one knows it all.Th fact that you stated that there is a statute that governs royalty payments and then supplied me with a google result did get me riled up... I do have the ability to use a search engine after all.


I have tried to provide as consise of an opinion as I can in this thread, I make no secret that I am not a lawyer, but do work in the industry and wear many hats in the course of my job.


And while I agree in the basic premise that the courts interpret the law, and anyone in the executive branch is compeled to comply, I have found in practice that the Commisioner enjoys a good deal of latitude when it come to interpreting the mineral code. 


I prefer that things continue basically in the way they are now, where the government regulators stay out of the private contractual relashionship of the Mineral lease as much as possible. I think that people should be more or less left alone to make their own desisions, and hopefully seek out help or education should they not understand what they are getting involved in. Futhermore, I believe that these sites do a good job of opening minds to new questions and posibilities, and hopefully no one would act solely on the advice of a individual on the other end of the ethernet cable.

It serves no purpose for me to discuss Louisiana law with you since I really don't know anything about it.  I would be very surprised if there is not statutory interest owed to royalty owners for late royalty in Louisiana as there is in every other producing state I am aware of.  That is a legitimate intrusion of regulators into private transactions since mineral owners need protection. 


The LA provisions you cite are not pertinent to the issue of mineral owners rights.  The language to the effect that the Commissioner cannot alter or amend the contractual agreement between the parties is standard, although you are correct to point out that it is not always observed.  These specific provisions concern unit wells and disputes between tract owners in such units.  Unit matters frequently get thrown in the lap of the regulators since the Mineral Board must approve units.  I am not aware that the state regulators have jurisdiction to intervene in disputes involving non-unit well costs.  The issue of over charges is primarily for working interest owners to worry about and resolve.  Over charges do not directly affect royalty owners unless those charges are the subject of post-production deductions. 

The best protection we have is when there are non-operating working interest owners in the well.  Those people paying the JIBs have an incentive not to pay too much and they have the provisions of the JOA and COPAS that generally require market prices when products and services are provided by in-house subs.  Otherwise, it is hard for royalty owners to catch wrongdoing, and when we do, recourse is to the courts not the regulators.


1) There is no requirment for an operator to provide a JOA or COPAS for working interest owners intergrated under 30:10. I know this for a fact, we have been forcepooled into several units and gone as a consenting interest. Our requests for a operating agreement have all been denied. The respose has been that we will be governed by the provisions in RS 30:10.  Even if we had the additional protections of a operating agreement, it would probally be usless since the subsidiarys are used to hide or obscure actual costs. Furthermore, the code allows for a resonable charge for supervision, which is obscure at best.


2) the Commisioner of conservation forms unit, not the mineral board. The mineral Board handles the administration of minerals owned by the state or state agencies (Wildlife and Fisheries, Scholl boards, etc) or political subdivisions (cities, towns, parishes). I know this is nit picky, but I beleive it is important to understand the power vested in the Commisioner.


3) I agree that a pure participating royalty interest would most likely  rest in the courts, but I cant help and wonder if any addtional responsibility could be implied from the regulators since the units are force pooled.

Lets be fair here.


The language above was in the lease when it was signed. It was not "sneaked in".

If you did not understand the language, why did you signthe document?


The key language is "of the amount realized from such sale". The amount realized is the amount recived by the purchaser minus the costs of treating the gas and delivering it to the purchaser, ie compression, dewatering, gathering, etc.


The language cited above is part of a standard lease. It has been around for a long time, the idea was to spread the pain of bringing the gas up to the point where it could be sold.


A cost free royalty clause is what the more sofisticated mineral owners have been using for decades. Although the standard cost free clauses are now falling short withthe newer ways the majors are marketing gas.

Did not know about cost free royalty clauses.  Interesting to say the least.  Buy Exco contracts have the standard deductions for gathering, etc....



Can you elaborate on the last paragraph in your post?  What is different now, about marketing gas, relative to in the past?  And, can you suggest what words a mineral owner should include in his Exhibit A to ensure cost-free royalties?  Thanks.



CHk under the guise of Twin Cities among others freely gave what was once a very standard Cost Free Royalty Clause.


The problem I have seen is that CHK  and several other large independents do not sell their gas the way it used to be done. Now they sell their gas to their wholly owned subsidiary, CHesapeake Energy Marketing. CHK is able to sel the gas at a discount, in what is effect themself. This shorts the WI and RI owners. Now they can sell the gas at higher prices, and even hedge the gas as a whole from multiple wells from multiple fields, fetching a far higher price than we will ever see.


It appears to me, that now there is a base price paid by CHK Energy Marketing (let me call them CEM), and deductions are made by CEM to that base price for gathering and treatment. CHK now shows these on their royalty checks, at least this is my understanding of the process, and CHK has no interest in better explaining it to me.


I have seen some good clauses that put limits on deductions and even set prices paid, in a different way if these less than arms lenght transactions occur. However, it may be hard to include these in the lease.


I am seeing a distinct pattern of tracts going unleased, intentionaly by operators. This is a relativly new strategy which I believe is used to prop up short term cash flow. They are able to hold all the revenue from the UMO's, since they are entitled to recoup their proportionate share. This boosts near term cash flow, and then they operate the UMO's to death. I personally believe the costs billed out are a little on the eccessive side (I would not be able to find partners I I charged what they do).

Baron's unleased owner assumption may be right on.

It is not just small acreage or owners that "hold out".  In some recent situations I have seen owners with significant positions whose lease expired in a unit prior to it being produced and the operator either sat on their hands or low balled an offer in. That wasnt the norm in other plays/situations I have experienced.  I think the lack of energy by operators to lease up what is essentially low hanging fruit in their own units is explained very well by Baron to prop up short term cash flow.  Then they can also "pencil whip" the ULMO on payout making short term............longer term.  Not every situation, but some.  


Sometimes the need for leasing or re-leasing in these scenarios is driven by whether they will truly need the surface or not later on.  They don't want to knock on a ULMO's door for some alt. pads when the owner is still trying to track payout on the current well.

"Sometimes the need for leasing or re-leasing in these scenarios is driven by whether they will truly need the surface or not later on.  They don't want to knock on a ULMO's door for some alt. pads when the owner is still trying to track payout on the current well."


I think that is spot on.

To elaborate on what The Baron says, in "the old days" we sold natural gas to a third party at the wellhead.  Nowadays, producers are treating the gas to make it marketable, processing it to take out the liquids, transporting it for a profit, and charging a marketing fee.  Generally the states allow the associated costs to be deducted to the extent they enhance marketability and are profit motivated.  I hope The Baron did not mean to accuse CHK of paying royalty based upon a less than market price by interposing a wholly-owned subsidiary as the first purchaser.  Clearly, that would be illegal and I do not believe CHK is doing that.  However, they lead the pack in involving subsidiaries in the full cycle of exploration and development.  A great example was their announcement last week of formation of an in-house drilling contracting company.  A final note to Roy Austin Smith (was it?).  Please don't assume that when a producer buys a new truck for some local group that reflects corruption or implies that your royalty dollars are being stolen.  The industry is wise to give back to the communities in which it is active, and that is more common than most people appreciate.

I don't think is a coincidence that CHK is routinly pays the lowest price in a field. Henry's data has been quite clear.


I believe, and it is just my opinion, that CHK and other majors use their subsidiaries to work around the traditional cost fre royalty clauses, and hide additional charges for treatment and transportation.


I have seen similar dealing from the drilling and operating side. I find it very interesting how one subsidiary leases drill pipe to another subsidiary for example. It seems to me that CHK is not worried about reducing drilling costs, as it is a second revenue stream for... extracting more revenue from non-consent, consenting WI, and UMO.


I do not believe that they are breaking any laws.


I do believe they are streching things from an ethics point of view.



I agree with you about many things (although my own opinion is that very few operators would intentionally drill under ULMO to improve near-term cash flow).  However, I do not believe CHK uses subsidiaries as a means to hide charges.  Nor is their game to buy gas in the name of a subsidiary that pays less than market price.  That gamit ended with the famous Delhi case.  However, CHK does hedge extensively and as the largest independent gas producer in America, they may not exert as much pressure on purchasers as they otherwise might (because of the hedges).  That is counter intuitive; they should have tremendous leverage to negotiate better prices, but as a CHK royalty owner myself, clearly their prices don't compare favorably with my checks from neighboring properties operated by others.


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