There is much mystery surrounding proper language to provide protections to the Lessor for

post-production deductions by the Lessee against royalties due. I am aware of the Chesapeake vs. Hyder

ruling, which I believe presumes that an oil and gas company can use the "work back" method of accounting,

to deduct post-production costs, back to the "well head" even though contrary language is present in the lease

stipulating "no costs" shall be deducted. It seems the "magic words" need to be clearly referenced in the lease, or

attached exhibits, and those words are "free and clear" or "cost free" as specifically applying to all royalty proceeds paid, and that great care needs to be taken, to clearly identify, that royalties should be calculated  "at the point of sale"

instead of being calculated "at the well head". Relating to this, I have a Chesapeake lease, where the language reads

that no post production charges, of any type, will be deducted from the Lessor's royalties, period. Though this language, (not verbatim) does not stipulate where, or, how the royalty was to be calculated; neither "at the well head" or "point

of sale" is even referenced. I can only say, that on my past royalty statements,  "post production" costs have never appeared on my statements;  and so am I to conclude that this "no costs" royalty provision is working, or, that Chesapeake had used the "work back" method of accounting, back to the "well head" and  provided no notice of those expenses to the Lessor, as they have interpreted the law, allowing them to do so.

If anyone could put this in layman's terms, it would be greatly appreciated in the negotiating process of developing a good lease.

Shelby

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For those who are interested in a no-cost clause that Chesapeake will honor, I suggest you contact Lake Hearne at Cook, Yancey, King and Galloway in Shreveport. My family settled a lawsuit against Chesapeake with a new lease which contains a no-cost clause *drafted by Chesapeake*, which thus far they have honored. Due to a non-disclosure clause in the settlement, I do not think I should post it here.

Good luck'

Shelby,

I concur with JB.  (Hey JB -- hope you are well.)  Don't try to negotiate this yourself.  Use an attorney who has developed the appropriate language and has found it successful.  

Realize that there are two parts of this that you must get right.  First, and most obvious, is the part that says you won't pay for all the costs for marketing, dehydration, transportation, etc.  

But the second, and equally important part of the language is the part that says where, and for how much, your gas will be sold.  If your gas is sold right out of the ground, it won't be worth nearly as much as if it has already been cleaned up, transported, and marketed.  So you need to make sure the gas is sold to a non-affiliated party (something about "arms length" transaction price) at the place where it enters the large pipeline.  

Get help from a good, experienced attorney.

Even the best of "magic" post production language does not guarantee that an operator will honor it.  Push comes to shove, a lessor must be willing to file suit to enforce the language.

You're welcome.  Sometimes, depending on your specific circumstance, the best course is to negotiate language that allows some deductions but prohibits others.  Our discussions rarely touch on what deductions are actual costs and which are questionable.  If you restrict all deductions, you just might increase your chance of ending up in court.  I generally consider "transportation" costs to be required for any and all production and should not be deducted.  "Treatment" costs are a somewhat different category depending on the composition of the natural gas.  If the gas does not meet pipeline requirements for CO2 and/or H2S, that might be a reasonable cost for deduction purposes.  If you have a more than modest size mineral interest and an experienced O&G attorney, that might be worth discussing.

Skip,

I have had difficulty in researching what percentage transportation costs represent in post production expenses. Is transportation usually considered the most expensive cost associated with sales and marketing expenses. I have spoken with some people who claim that close to a quarter of their royalty proceeds are charged back on their share of royalty expenses. I know this depends on where the gas is purchased in the process of delivery, but, in general does transportation take the "lions share"  of post production costs?

Shelby, I've not tried to break out the the deductions by percentage owing to the fact that the circumstances can vary so widely by production location, sales point and operator.  My comment as to possibly negotiating some of the deduction costs is based on the fact that my O&G attorney has done so for other clients in the past.

Thanks to everyone that replied to this topic. Like everything else, in the oil and gas arena, it's a pretty complicated subject, and even when you get it all right, not everyone plays by the same rules. In working up language for  a "point of sale" approach, where  royalties are calculated, I do  understand the importance of stipulating where that might occur, either once gas reaches a gathering system, or, interstate pipeline. I will have an attorney draft the best language he can, going the "point of sale" route, and be careful with language defining "at the well head" calculations of royalty market value.

 Here is Chesapeake's answer to a no deduction clause. They sell it at the well head to a wholly owned subsidiary  Chesapeake Marketing therefore Chesapeake Energy Marketing is taking the deductions not Chesapeake Appalachia. Here is their verbiage.

 

By way, of background, gas produced from the Lease is in marketable form at the well,
and is sold by Chesapeake to Chesapeake Energy Marketing, Inc. ("CEMI") at this
point. CEMI is a marketing company, which takes title to and possession of gas at the
well, and aggregates it with gas from multiple other wells into a downstream pool,
typically on an interstate pipeline. The volume of natural gas aggregated in this pool is
then sold to many different buyers, at different prices. On a monthly basis, CEMI
determines a weighted average sales price for the gas sold from the pool at the
downstream, value-added points of sale. The weighted average sales price is calculated
by averaging the price received from the individual sales from this pool across the entire
volume contained in the pool. CEMI pays Chesapeake 97% of this weighted average
sales price (CEMI retains a 3% marketing fee which is borne solely by Chesapeake and
is not passed on to you), less the costs CEMI incurs between the point of sale at the
well and the downstream points of sale. The costs incurred by CEMI are commonly
referred to as post-production costs, and are indicated in your royalty statement. Please
note that these are not costs paid by Chesapeake but are shown on your royalty
statement in an effort to be transparent.

Wayne,

Thanks for the feedback on Chesapeake and their marketing affiliate. I assume in the example you

mentioned, that Chesapeake Appalachia is the Lessor; is this example based upon minerals located in

the Marcellus Play? Some of those Northeastern states hold to the "market product" doctrine concerning

royalties, and post production charges that are allowed. My leaseholds are in Texas and Louisiana, states

that I understand have an entirely different approach to definitions about what "at the wellhead" means,

and what costs can be charged back to the royalty owner. We do try now to get "affiliated lessee" interests

restricted in their operations in leases that we enter into now.

Shelby

 Yes, NE Pennsylvania Marcellus. It was originally a lease with East Resources (now Shell) and bought by CHK. They originally honored the no deductions clause for 2 years and told their 3 (Anadarko, Mitsui and Statoil) partners it was a no deduction lease.  When CHK found themselves in the financial bind they started deducting up to 110% (not a typo). They either deducted the amount exceeding royalties from other wells or deducted it next time royalties were positive. The other 3 partners are still not takinf deductions.

Wayne,

Thanks for commenting on the Haynesville Shale site; my wife's family has some mineral interests in Wetzel Cty, WV.  It amazes me the differences in how in the Northern plays, CHK claims  gas is a "marketable product" at the wellhead, and in almost all the other states in the union, gas "is not" considered in a "marketable form" at the wellhead.

Sounds like this is one for the Supreme Court to rule on.

Shelby

Here's a quick question:  Is CEMI and CEMLLC the same Company?

I'm trying to get a better understanding of this process.

TIA.

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