Our attorney pointed out something interesting today. We were offered a gross, no deduction lease for some property in a couple counties. It was gross "at the wellhead". One county is dry gas only (Doddridge) and one county could be either wet or dry (Tyler). The interesting part is that we might want the price at the wellhead, not at the point of sale if it is dry, since the point of sale price might be lower.  If it is a wet gas well, the price would probably be higher at the point of sale after processing. However, if we want that price, they want to take out processing charges. The thing to remember is that just because they offer you a gross, no deduction lease, THAT might not be the best way to go if you had to pick one or the other. Obviously, we all want a no deduction either way, but if you had to choose AND you are in a wet gas area, the choice is not as easy as it looks since you might be better off with the processing fees taken out and getting your money at the point of sale. You need to find out how the company determines wellhead pricing. Also, we have one well in Wetzel which is producing wet gas and another well just a couple hills away which is only dry. Makes the choice that much harder. Any thoughts about this?

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Hi Jim

Where I live we only have dry gas.  I have not prior run into a situation where the value of the (dry) gas at the wellhead is greater than fully pipeline ready (i.e., "finished") gas at point of pipeline entry.  I have not seen even that claim anywhere else.  If, for example, there is insufficient takeaway and/or slack demand, such a hit to price would readily reflect back to the wellhead . . or so it seems to me.

What am I missing?  Under what circumstances would wellhead value of dry gas exceed the value of the same gas in finished form, at point of pipeline entry?  

Frank,

    Remember, Jim's opening sentence was "Our Attorney". Take it for what it's worth. The space left empty below this sentence is what I think it's worth, nothing.

Good point.  I missed that completely.  I have run into situations in the past where an attorney in essence was advocating for the party on the other side of a transaction, and not the party he supposedly was representing.  That happened once to my dad years ago.

In general, though, that's a pretty tough charge and a difficult case to make, and I doubt it happens very often . . . . certainly I hope it does not happen often.

Them there lawyers talk to each other, work out deals amongst themselves. Cant trust any of them. They eventually become politicians, don't they?. Live off our hard earned tax $$$.

Frank. I did a terrible job with that post. Mainly from my very less than 100% knowledge about the pricing which is why I asked for comments. I thought that perhaps the price of gas (dry) at the wellhead might be higher that a possible contract that the company had to sell the gas long term. I am going to post below, the comments from the attorney I received and ask for comments on that. We are waiting for this company to provide information on how they determine wellhead pricing. We need to make a decision on this shortly.

"As regards the proposed gross proceeds clause, the practical problem with that clause that I foresee is determining the wellhead price of the gas on a month-to-month basis. That's going to have to be based on an index of a spot market price. Since this is wet gas, I have to assume that XYZ Company's purpose in proposing this "gross proceeds" clause is to allow it to pay royalties at a lower "wellhead" rate as opposed to the sale price it ultimately receives after transport and processing for the gas and constituents.  Of course, if you want to be paid on the sale price of the constituents, XYZ Company is going to want the right to deduct postproduction costs. So, you're trying to crystal ball which of the two approaches is going to be more beneficial to you. Whichever approach is agreed to, you have to be comfortable that the process by which prices are determined and royalties calculated is transparent and objectively verifiable."

Frank

I did some further checking. There are three types of natural gas pricing: Wellhead, spot and futures. Wellhead prices would be the value of the gas plus liquids and prior to processing or transportation. Spot would usually be Henry Hub and would be the price after processing and transportation were deducted. Futures....whatever. I have no idea how you would compute the value of the gas at the wellhead.

For those of us that live in an area where there are multiple plays, some dry and some wet,available this does present food for thought.

I have never heard of a "well head" price for wet gas.  I'm in two wet gas units here in Forward Township, Butler County, PA.  I get royalties on the sale of the NGLs and the residual gas minus various deductions. I don't think wet gas itself is marketed.

Phil

I would appreciate a lot of discussion about this subject.  My general advice to my clients is that they need gross proceeds because that's the only way they will be able to audit the company.  If the company can deduct costs, they can make up numbers.  My clients will have no method to double check those numbers.

Most of my clients are out of state heirs, and don't have a large net mineral interest.  I could see someone with a 100+ acre farm and all the minerals working out a different agreement.  

In my discussions with Antero, they have defended their Market Enhancement clause by saying that my clients will net more royalty if they also pay for some enhancement of the gas.  My argument in return is that enhancement takes place before sale, and in West Virginia, the oil and gas company is responsible for all costs before sale.  

In my discussions with EQT, they have insisted on being able to deduct costs because they are an integrated company, meaning they own the pipelines and processing plants.  Therefore they don't sell the gas until it is completely processed.  I haven't been able to talk them in to Gross Proceeds yet, but I have spoken with a couple of people who have.  

Most companies are willing to give Gross Proceeds if you're willing to ask a few times.

Any other information on this topic would be greatly appreciated.

Kyle good post.  I think your argument for gross proceeds is strong.  And I take your point about enhanced chance for cheating if any other basis is employed, even though I had not thought about it your way prior.

Setting aside the cheating angle, though, solely for the sake of discussion:

I've long believed the gas companies can make a solid case for wellhead pricing.  After all they can argue, it is their gas once out of the well, and we do not deserve to benefit from the work they alone perform to make ready the gas before it is sold to a third party.  However:

Royalty fraction is set in the lease and agreed to by both parties.  If the gas company makes the wellhead case strongly, I would counter simply by demanding a higher royalty fraction.  So neither case, wellhead or gross proceeds, is or can be made on a stand-alone basis.  To wit:

If they insist on wellhead then I (as landowner) want royalty fraction enlarged.  If they agree to gross proceeds then maybe I can live with a slightly smaller royalty fraction.

But once the lease is signed and terms, one way or another, are agreed to, then messing with payment basis is an abrogation of the deal so struck.  

If you have a Gross Chesapeake lease, take a look at what is done to your royalties at their Revenue Department. Your Royalty Statement shows no deductions but the spreadsheet used to calculate your Royalty shows multiple deductions, take a look at mine which is attached. Also take a look at my explanation of the spreadsheet. I doubt that Buck Well 1H is the exception.

Chesapeake has a long history from Texas to PA of not paying landowners a fair royalty.

If you believe the CHK VP who made the famous quote below, it's a good business practice.

Farm & Dairy Sept. 2013 Chesapeake VP for the Utica & Marcellus Shale Plays:

"It's a good business practice not to pay landowner royalties, then go to court and only pay what the judge orders".  None of the shale play states are protecting the landowners, and you'll find CHK $$$$ in the shale play state politician PAC funds, it's public record.

Here is my explanation, I couldn't attach it so I'll paste it here.

How Chesapeake Energy Is Stealing From Ohio Landowners

 

All Ohioan’s with no deduction leases and ALOV Leases TAKE NOTE!

 

ALOV leases are no deduction leases. Your royalty statement shows no deductions but the negative signs tell a different story. 

 

I have a spreadsheet from Chesapeake Energy’s Revenue Department in response to the lease required notification that I made due to being shorted royalties on Buck Well 1H.

 

There are five columns that explain the theft taking place at CHK wells in Ohio:

 

Column #6, Purchaser:   CEMI (Chesapeake Energy Marketing Inc.), you can bet they are paying below market price to themselves if an actual sale is in fact taking place. An investigation will show whether CEMI is buying our well products or just taking over the inventory from our wells. We should be paid on CEMI's sale of our products on the open market, an Arms Length Transaction/Sale as required by our leases.

 

Column #11, 3rd Party Deductions: These deductions range from $1,000 to $80,000 per product taken from our well. Ohioans are paying for $38 Billion in off book loans/arrangements such as the Kensington, Scio, and Natrium WV processing plants. Chesapeake has admitted that they have $38 Billion in off book loans/agreements in recent news articles dealing with the Department Of Justice Subpoena of Chesapeake’s records due to possible landowner royalty non-payment & irregularities.

 

See Propublica story Unfair Share where PA landowners are paying for Access Midstream pipelines by being overcharged for shipping their products by those pipelines. The Kensington, Scio and Natriuim plants were built as Access Midstream plants, but the ownership names have been changed to prevent landowners from drawing a parallel with what is happening in PA.

 

Column #12, Fuel CHK is using our natural gas at the well head for free and also charging us for Fuel use. This is 2 thefts since our leases don’t allow free use of well products or a deduction to pay for CHKs cost of production fuel use.

 

Column #13, Affiliate Gathering/Compression/Treating: We are paying for the NGLs being processed for CHK and as stated above covering their $38 Billion in off book loans/agreement. The Volume of NGLs processed as reported on our Royalty Statement is greater than the volume of NGLs produced from our well. This means we are paying for the processing of other well NGL production, as well as the facilities that treat NGLs.

 

Column #14, Percentages: This is the percentage of value of each product deducted in col 11,12, and 13. The NGLs (product code 4) deductions are greater than 100% and as high as 176%. This means we are paying CHK to take our NGLs free.  The amount over 100% is being deducted from our oil and gas royalties.

 

Ohio’s NGLs are being stolen due to the fact NGLs are not listed in the Ohio Revised Code as a Severance Taxes product,  and the ODNR doesn’t require documentation of NGLs produced from Ohio’s wells. This is a Perfect Storm of NGL theft in progress.

 

Ohio Revised Code “Theft By Deception” and “A Pattern Of Corruption” laws are being broken with each Royalty Statement received by Buck Well 1H landowners.

 

 

 

Attachments:

I do not understand when gross proceeds occurs.  There seems to be different scenarios for this.  For instance, a company could extract from the well, and sell to a gathering system owned by an independent 3rd party.  Gross proceeds would be recognized at that time.  But, can the producing company receive a kick-back in the future that is not recognized as a gross proceed?  Another example applies to a company that extracts, then places its minerals into its own gathering system, processes the products, then sells to a distributor.  At what point is a gross proceed recognized? What happens when all of these processing and delivery steps are owned by the same parent company?

Another situation with which I am not sure, is when a lease is written as the value at the wellhead based upon the average value of the Henry Hub for the month, for example $2.5.  If the gas is then actually sold at $4.0, is the royalty calculated based upon the $2.5 average price?

I would like to better understand how hedging affects royalty payments.  If a company is hedged to sell dry gas at $4.0, but the Henry Hub (for example) is only $2.5, which value is used for determining the royalty calculation?   Can the producing company consider the gross proceeds to be $2.5, even if it was hedged at $4.0?  It seems this hedging consideration can have very large effects upon royalty owners.  A well hedged company will be motivated to produce at low prices (resulting in a lower royalty payment to mineral owners) because of its large hedging PROFIT.  Similarly, A well hedged company may have no motivation to produce at high prices (resulting in a higher royalty payment to mineral owners) because of its large hedging LOSS.

Just want to be sure I understand the concepts of wellhead values, gross proceeds, 3rd party, subsidiary, and hedging...

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