Gross Proceeds at Wellhead; Terms, wording, good or bad ?

I am asking for feedback, opinions, recommendations and good or bad experiences with leases or negotiations with involving calculations and compensation based on proceeds at the wellhead.  I have found very little to no information in previous post regarding this type of lease so this would be a very beneficial topic for educating a lot of other members on this topic.

We received a Gross Proceeds Clause in a lease contract as follows:

"Gross Proceeds at Wellhead. It is agreed between the Lessor and Lessee that, notwithstanding any language herein to the contrary, royalties payable on gas and gaseous substances, including casing head gas, shall be based upon the MMBTu value of unprocessed gas at the wellhead, free of all costs, charges or deductions of producing, treating, compressing, transporting and marketing said gas to such purchaser, which royalty, however, shall be subject to such production taxes and severance taxes as are properly allocable thereto."

Questions:

1) How is "Wellhead" gas valued or assigned a value ?

2) How would oil or other liquid substances be valued at the Wellhead ?

3) Is a "Gross Proceeds at Wellhead" an oxymoron being used as there will be no expense for treating, compressing, transporting and marketing.  Also should the production and severance taxes not be allowed on a gross proceeds lease?

Thank you for your replies !

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Permalink Reply by Frank Walker on December 4, 2015 at 4:01am

Briefly, just as a tip for prospective Lessors:

Your lease needs to prohibit wellhead sales.  Yes, I'm well aware natural gas is not sold at the wellhead today.  I stand nevertheless by what I wrote.

Your lease also, obviously, must base royalties on sale price of "finished" gas to a non-affiliated third party.

Most lawyers are already well aware of the latter point.  Many are not aware of the former.

Permalink Reply by Joseph-Ohio on December 4, 2015 at 4:35am
Frank,

You've written that '..........natural gas is not sold at the wellhead today.'

Is that to be taken as not sold by Drillers / Exploration & Production types (to their purchasers) ?

But, can / do they (the Developer / E & P, by leasehold agreement) still purchase / desire to purchase it that way ? ?

Personally I wouldn't be concerned how the Developer E & P sells the production - I as a lessor would only be concerned about being paid for every mmbtu of energy extracted on a 'by constituent' basis (mmbtu gas and mmbtu oil and if separated at the wellhead mmbtu NGL (Natural Gas Liquid) and mmbtu NGC (Natural Gas Condensate)).
Permalink Reply by mark on December 4, 2015 at 7:01am

afternoon folks
having read the posts above andrea very well explained enjoyed your post as  the other folks responding to this discussion joseph maybe there should be a glossary maybe us as members take it upon ourselves to develop one but sadly as you and others have stated they twist and manipulate the language to where it becomes distorted beyond recognition very good read yeah, just when you understand the rules they change the game

Permalink Reply by Andrea Richlin on December 4, 2015 at 10:25am

Thanks , Mark glad you enjoyed the post , When I saw the topic i had to vent and share ,lol

Permalink Reply by mark on December 4, 2015 at 10:53pm

andrea
isn't sad we have people from all around the immediate area with varities of income and background and the stories all kind of tie together at one level or another I hope dusty roads is taking notes IMHO P.S.kudos to keith mauck for this website truly an unsung hero in my opinion 

Permalink Reply by james mcmeechan on December 7, 2015 at 12:26pm

  Let's take this lease a little bit at a time.

  Gross proceeds at well head: I would consider this an archaic term of art, and would not include it in a lease.

  Notwithstanding any language to the contrary....: As I understand it this would not negate language in an addendum, i.e. a market enhancement clause.

  Payable on gas and gaseous substances, including casing head gas: More gibberish. How about, payable on any material of value removed.

  Based on MMBT u value of unprocessed gas at the wellhead: Gas should be valued by its btu content, I would prefer it at the point of final sale.

  Free of all cost, charges or deductions of production...and marketing said gas: This doesn't even have the usual "including, but not limited to". You could well end up responsible for items charged, that are not listed. How about, free of all cost, charges or deductions for any reason whatsoever.

  Production tax and severance taxes: I'm not sure what a production tax is, so I would not sign up for paying them. The liability for a severance tax should be clearly noted as prorated based on interest in the well.

   Questions:

  1,

  Gas is valued by its btu content per a given volume. Although many talk of wellhead price, I doubt you will ever find it on a statement from a producer.

  2,

  Other liquid substances generally increase the btu content and therefore the value of the gas. Oil ,put simply, by its type, and market values. As a curious side note, many leases state the royalty for oil may be taken in kind. I have never heard of anyone taking that option. It would be interesting to see a lessor, who thought he was being cheated, exercise that option.

  3,

  Gross proceeds at wellhead is a term of art. Just like the bank does not trust you to pay your property taxes, the operator is not going to trust you either. As long as the severance tax is prorated to your interest in the well, you are ok.

 

  Some operators took the well head price added the market enhancement clause, and consulted their attorney. They came up with there is no market at the well head so we enhance all the gas. You agreed to pay for enhancement with the marketing amendment. Some leases included the phrase " in no case shall the lessor be paid less than if the gas were not enhanced". It will be interesting if that phrase saves anyone. Without a way to determine a well head price, I not sure how you would know if you were paid less.

  I am not a lawyer, these are just some of the less scary thoughts in my head and meant as food for thought.

Permalink Reply by Frank Walker on December 7, 2015 at 6:17pm

Joseph

It is much more complicated than that and I did not want to get into the detail.  Suffice it to say, natural gas today is not sold to arm's length third parties at the wellhead.  There may be some sales to affiliated parties.  These are, of course, faux sales.

But actual wellhead sales, to legitimate (non-affiliated) entities are not impossible, or prohibited by law for example. That just is not how the industry traditionally has done business.  But unless Lessor prohibits wellhead sales in the lease, that tradition might someday come to an end, to the detriment of Lessor.

Problem for landowners is that gas sold at the wellhead is not, by definition, "finished gas".  If you do not like the term "finished gas", then substitute "pipeline-ready" gas.  Either way, and more important, gas at the wellhead is therefore less valuable than finished gas.  Landowners want, if at all possible, their royalties to be based on natural gas in its most valuable form . . . . and that is not gas just as it emerges from the well. 

Permalink Reply by sldouglass on December 7, 2015 at 1:33pm
Unfortunately, wellhead price assumes there is a cute little nome standing by the wellhead passing out little gold nuggets for each mcf of oil, gas or other stuff thar might come out of a well.
Since that may not be the case, the producer makes up a price that suits it based on whatever logic it can muster.
If you do not like the price, you can sue the b.... And good luck! Sam
Permalink Reply by Christian E. Turak on December 7, 2015 at 8:25pm

Typically, the oil and gas company you signed a lease with will base your royalties on its value at the well.  We all know that there is no "at the well" market--the gas is "raw" and needs to be processed and transported to market.  So how do the oil and gas companies figure out the "at the well" value as stated in the lease?  The oil and gas companies use what is called the "netback method" for calculating the value at the well.  They take the price received for the sale of the gas to an unaffiliated third party and deduct all of the costs it took to make it into a marketable product.  Then you're left with what the value of the raw, "at the well" value is.  For example, Company A produces 10 units of gas.  Company A sells the 10 units of gas to Company B.  Company B processes it, compresses/transports it, markets it, etc. and receives $20 for the 10 units.  Company B sees that it cost them $15 for all of the processing fees, etc. for the 10 units and thus the "at the well" value is $5 for the 10 units.  

But how can the oil and gas company take deductions if the lease says that it cannot?  Well that's easy for the oil and gas companies: the business entity that you signed your lease with isn't the one that is actually taking the deductions.  Therefore, there is no lease violation.  To follow up on the above example, Company A won't be accounting for any deductions.  Only Company B will, but you'll likely never know or never see a breakdown of the costs.  Company B will just give Company A a price, and that's what your royalties are based on.  

The rub with all of this is that when someone says they signed a lease with Chevron or Chesapeake or EQT, they really signed with the production subsidiary of the parent companies.  The production subsidiary (Company A) will produce the gas and sell it to an affiliated midstream subsidiary (Company B).  The midstream subsidiary will either contract out processing, etc. or do it in house.  Take EQT for example.  EQT Corporation is the parent company with an assortment of subsidiaries.  EQT Production is the signatory to the lease.  It produces the gas and sells it "at the well" to EQT Energy.  EQT Energy contracts with EQT Midstream to transport the gas to market where EQT Energy can sell it to a third party in an arms length deal.  EQT Energy will report the price it received (minus the deducts using the netback method) and EQT Production will issue royalties based on that price.  

So, in the end, it's all a fiction designed to allow the parent companies to take deductions while signing landowners to what appear to be leases with gross royalty clauses in them.  This is assuming you don't have what would be considered a true gross proceeds lease and don't have a market enhancement clause which is a whole other can of worms.  

Don't just get an attorney--get an experienced one.  

Permalink Reply by Joseph-Ohio on December 8, 2015 at 2:07am

You've written :

'.............This is assuming you don't have what would be considered a true gross proceeds lease and don't have a market enhancement clause which is a whole other can of worms.'

That 'can of worms' reads to me to be the most interesting.  Could you kindly detail how that works; as on the surface / at 1st utterance it sounds like the way we as lessors would like to go for the Natural Gas part should opportunity present itself.  

We would strive to keep it as simple as possible and simply be paid fairly for production without deduction.

Permalink Reply by Christian E. Turak on December 8, 2015 at 7:01am

Market enhancement clause can and is used as an end run around having a true gross royalty provision in your lease.  In essence, what it does is state that the oil and gas company can deduct for any costs which enhance the value of the gas after it has become a "marketable product."  To understand exactly what this means, we need to take a step back.

WV is a marketable product state.  Basically, this means that the oil and gas company is responsible for all costs to transform the raw gas into a product which can be sold on the market.  However, if the lease states otherwise (that the lessor will share in those costs ie a net proceeds lease) then the company can take deductions.  

This is where the market enhancement clause comes into play.  The oil and gas company will transform the raw gas into a "marketable product" but there will be costs associated with the gas thereafter (transporting, compressing, further processing the "marketable product"). The market enhancement clause allows them to deduct for those costs.  


This may seem straightforward in theory, but in practice it's murky at best.  What is a marketable product?  At what point in the chain of events is the product marketable?  What about NGLs?  Technically, the gas is marketable before they have been separated out.  

FYI, PA is not a marketable product state (it is an "at the well" state) and takes the opposite view.  The lessor shares in all costs to make the gas into a "marketable product" unless the lease says otherwise.  The Supreme Court of OH is going to decide where their state falls any day now.  The case is Lutz v. Chesapeake if interested.  

In my opinion, what it comes down to is how are you going to ever be able to figure it all out?  If you see a processing charge on your royalty statements, how is anyone ever going to know if those costs incurred before or after the gas became a "marketable product."  

I view leases with market enhancement clauses only marginally better than net proceeds leases that allow full deductions.  

Permalink Reply by Joseph-Ohio on December 8, 2015 at 7:38am
Thinking a lease that places all of the associated costs of rendering the Natural Gas a 'Marketable Product' on the Lessee / O & G Production Company and without any 'Market Enhancement' clauses / charges / deductions paid by the Lessor to be the best / simplest way to go should we ever have such opportunity.

Wonder how / if they would attack royalty paid to the Lessor with such a lease / specification ? ?

Probable (as you allude) the point that it becomes 'Marketable' would come into play and that would probably depend on THEIR customer (probably their customer of choice to boot).

Looks to me that it's easy for a Lessor to take a beating no matter what the Lease says.

How do you see it ? ?

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