Replies to This Discussion

Permalink Reply by Joseph-Ohio on December 19, 2013 at 2:01pm

'MARKET ENHANCEMENT: It is agreed between the Lessor and Lessee that, notwithstanding any language herein to the contrary, all oil, gas or other proceeds accruing to the Lessor under this Lease shall be paid without deduction for, directly or indirectly, any post-production costs, including but not limited to, the costs of producing, gathering, storing, separating, treating, dehydrating, compressing, processing, transporting, and marketing the oil, gas and other products produced hereunder to extent such costs are necessarily incurred to transform the product into a marketable form; provided, however, any such costs which result in enhancing the value of already marketable oil, gas or other products may be deducted from Lessor's share of production proceeds so long as such costs are reasonable and do not exceed the value of the enhancement obtained by incurring such costs.'

Sorry, I don't follow / interpret that the clause directly above clearly defines / states that the lessor will receive a greater royalty return after paying costs for MARKET ENHANCEMENT than if the lessor did not.

". . .  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 proportionally deducted from Lessor's share of production so long as they are based on Lessee's actual cost of such enhancements. However, in no event shall Lessor receive a price per unit that is less than the price per unit received by Lessee."

Sorry, I don't follow / interpret that the new clause / provision directly above (in this instance either) clearly defines / states that the lessor will receive a greater royalty return after paying costs for MARKET ENHANCEMENT than if the lessor did not.

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Permalink Reply by Tony Yurina on December 19, 2013 at 4:59pm

Thinking out loud here.

Antero's gas flows into Mark West from the public information I have read.

Let's assume the gas total MMBtu's are quantified at the well pad (well head) processing meter which are marketable to MW.  But the question I don't know the answer to is this.  Is MW actually purchasing the gas from Antero?  Or is the gas flowing to MW, being processed and the higher marketable value of both the liquids processed and the residue gas sold on the transmission line combined value higher when compared to the original marketable gas at the well head or upstream side of the plant? Would then the enhanced liquid and residue gas products be more valuable when sold minus the actual enhancement cost ?

What would you be willing to pay for the gas before processing?  (this gas may be marketable on a lower pressure transmission line, but not a high pressure line due to the gas quality and physical state for each pressure considering gas quality factors)

What would you be willing to pay for the gas after processing ?  (This gas will be trouble free for a high pressure transmission line operator, no free liquids accumulating or hydrate issues)

Bear in mind, a lot of the gas and liquids are sold as future hedges and can sell for significantly more than the NYMEX price posted today.  It can also end up selling for less if conditions change.

Something to think about.

Comments?

Permalink Reply by Joseph-Ohio on December 20, 2013 at 2:51am

Tony Yurina,

A couple of questions come to my mind along the lines of your thoughts.

1) Are landowners / lessors paid royalty for production value measured at the well pad (well head), or on amount 'sold' to Mark West, or on amounts of the various products produced and transported by Mark West ?

2) Is the transaction (or transactions) between Antero and Mark West considered to be of the 'at arm's length' type - or is there a subsidiary / partnering type of relationship / contract arrangement between the two ?

Permalink Reply by Joseph-Ohio on December 20, 2013 at 10:43am

James,
Enhancement of course increases value.
Never wrote that it wouldn't.
Only question in my mind is who gets to enjoy the enhanced value and who pays for the enhancement ? ?

Permalink Reply by Joseph-Ohio on December 20, 2013 at 11:35am

James,

I've conceded nothing.

I've always acknowledged that the value for un-enhanced production was less than enhanced production.

My hypothetical high school math intellectual exercise used $10.00 for un-enhanced value and $12.00 for enhanced value.

I still do not concede that the 'alternate language' will provide a greater return for royalty earned on the account of product enhancements vs. royalty earned based on the sales of un-enhanced product.  Because we still don't know who pays the cost of the enhancements, what % of the cost the landowner lessor pays and if the increased cost per unit overcomes it all and pays the landowner more than if no enhancement costs were levied against the landowner / lessor. The 'alternate language' does not address the consideration and neither does the MWCD language as I read it and in my opinion.  The cost per unit may rise but we do not know if the cost per unit will overcome the cost of the enhancement levied against the landowner / lessor (proportionally deducted or not). To assume otherwise is just that - an assumption. The 'alternate language' still leaves the door open for 100% of the enhancement costs to be proportionally deducted from the landowner / lessor since no percentage of the enhancement cost is mentioned to be paid by the landowner / lessor and no percentage of the enhancement cost is mentioned as to be paid by the lessee.  The MWCD language and the 'alternate language' do not mention the lessee as responsible to pay anything toward enhancement - it just states the landowner / lessor may be burdened with those costs. 

The way I read it / interpret it / and in my very humble landowner / prospective lessor opinion on all of the above.

Permalink Reply by Joseph-Ohio on December 20, 2013 at 1:20pm

James,

Not twisting not turning just reading and trying to understand the language and offering my opinion about what's been posted.

The way I read it, what is undefined is what % of the enhancement costs are paid by landowners / lessors and what % is paid by the lessee.

As I understand what is written; it appears that the landowners / lessors are left open to the argument that they pay 100% of the enhancement costs on the basis of it being 'proportionally deducted from Lessor's share of production'.

It's only my layman's opinion which of course doesn't even matter to those involved in the final analysis. I'm no Lawyer or Judge - just a private Joe contributing to a discussion on a public forum.

Also, to be crystal clear I'm not arguing or favoring Antero's or anyone's position.  Don't even know anyone's position to begin with. As I wrote a few seconds ago, I'm just taking part and offering an opinion on what's been posted on this public forum.

Wish all involved landowners / lessors the best outcome in ironing out any circumstances causing grief.

I'm not going to keep repeating the same things I've offered earlier or within this reply.

I'm going to let this go and move on.

Have a good night James.

J-O

Permalink Reply by Joseph-Ohio on December 20, 2013 at 8:44am

What % of the total cost of the enhancement is paid by the lessor ? ?

Unknown ? ?

And what entity performs the enhancement (i.e.: is it an arms length transaction ? ?

Unknown ? ?

We would opt for a different lessee and a true 'no deductions' agreement ourselves (as landowner / lessors).

Also to exhibit a concern:

Say an unenhanced product would sell for : $10.00

And an enhanced product sells for : $12.00

Enhancement cost say is $1.00

For sake of example lessor earns 20% royalty

So (if lessor pays 100% of enhancement costs) the lessor's net is :

[ (20% x $12.00) - $1.00 ] = $1.40

And if there were no enhancement costs paid by the lessor and no enhancements performed the lessor's net would be :

20% x $10.00 = $2.00

How does a lessor know that's not happening ? ?

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Permalink Reply by Tony Yurina on December 20, 2013 at 6:31pm

Joseph asked two questions.

1) Are landowners / lessors paid royalty for production value measured at the well pad (well head), or on amount 'sold' to Mark West, or on amounts of the various products produced and transported by Mark West ?

2) Is the transaction (or transactions) between Antero and Mark West considered to be of the'at arm's length' type - or is there a subsidiary / partnering type of relationship / contractarrangement between the two ?

Joseph:

I don't know the answer to your two questions.  If I were the MWCD representatives, I would like to have known the answers.

This is a contract arrangement between MW and the production companies, if the information was made available, we could better understand the potential market enhancement costs and what value the enhancement might yield. 

It is clear the enhancement cost is only applicable to the royalty percentage amount.  

Some leases state that the royalty owners share of the oil can be separated and placed into the royalty owners tank, Lessor can then dispose of it at his risk.

Same for the gas, deliver the royalty share to the lessor pipeline for his disposition.

Or the Lessor can designate the Lessee to dispose of the Lessor's royalty percentage of the oil, gas etc.

As an example, assume 10,000MCF gas was produced for the billing period. The 20% royalty (lessors share) is 2,000MCF.

Assuming gas sold for $4.00 after enhancements, and midstream/processing cost was calculated at $1.39 per MCF, the lessor enhancement cost would be 1.39 x 2,000 =$2,780 to gather, compress, dehydrate, process the royalty owner's share. 

Enhanced sell price is $4.00 x 2000 = $8,000. Subtract the Market enhancement cost $8000 - $2,780 = $5,220 royalty after enhancement.

$5,220 / 2,000 MCF = $2.61 per MCF.    

The question becomes, was the gas marketable at $2.61 per MCF or more than $2.61 to anyone upstream of the processing plant?

If the gas value was enhanced and the unit marketable sell price minus the unit enhancement cost is greater and not less than un-enhanced or un-processed gas market price (if there is a market) the royalty owner would benefit from enhancement.

BTW, one large midstream company posted a third quarter processing cost of $1.39 as a public record.

If I recall correctly, this same company realized a $4.51 per MMBTU's for their gas as well during that 3rd quarter.

In this case the company is saying it's cost to enhance the Lessee share is 1.39 per unit and it is costing 1.39 per unit to enhance the Lessor share.  $4.51 - 1.39 =$3.12 per MMBTU's.

Was there a buyer for the gas at $3.12 MMBTU or greater for the gas assuming it was marketable upstream of the plant? If not, Lessor benefits by enhancement.

There is another scenario where the gas is marketed directly into a low pressure gathering or transmission line that is connected to market's, in some cases with minimal costs.  $0.25 to $0.30 per MMBTU's.   This is very reasonable to make the gas marketable and the royalty yield is much better. 

One would think the Antero market enhancement clause language in the lease would be applicable or at minimum arguable and adaptable to both scenarios, enhancement involving a large processing plant and also minimal enhancements to market the gas without the use of a processing plant where the enhancement cost is much less.

Last question.  What if no one wants to buy the gas at the well head, what is it worth?  Unprocessed, no thanks!  Piped to a plant, processed, the product marketability enhanced and the product is sellable at a good price.  

What would you choose to do with your gas? 

These midstream processing companies have millions of dollars invested in pipelines and plants.  They are going to charge the production companies for this infrastructure and maintenance going forward.

If a production company gives a lessor zero enhancement cost lease, then effectively the production company will have to eat the royalty owners share of the enhancement costs, effectively giving the royalty owner more value than the 20% royalty, and the production company would take the hit for processing the royalty share and achieve less than 80% value for their proportionate share.

Comments to the contrary?

 

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Permalink Reply by Tony Yurina on December 21, 2013 at 6:46am

I ran out of the 15 min. editing time late last night. 

My third sentence would better read "It is clear the proportional enhancement cost being debated is only applicable to the royalty percentage amount".  

I took a look at Antero's December operations report. They are reporting a December 1, 2013 hedge position of $5.25 and $5.31 in 2014.  This is for processed gas.

IMO the market enhancement clause would entitle the royalty owner to receive a better enhanced value as compared to marketing the unprocessed gas to another company at the well head.  Only a midstream company doing business for a profit would buy the lower value gas in order to transform the product to a much more desirable marketable form.  What you have to be on guard for is selling unprocessed gas to an affiliate at an unprocessed "marketable" price by which the royalty is based upon and without deductions. This forum's members have reported sell prices as low as $2.00 per unit. 

IMO a smart production company would use a well pad meter to quantify the volume commingled into midstream gathering line, where custody is transferred but not "sold".  Ownership of the gas would remain with the production company to and through the processing plant allowing them to realize a much higher enhanced value sales price to the end user.

There are transmission pipeline and Distribution fees to transport this gas to the final end user who actually purchases the gas.  Quite often the production company retains ownership of the gas to the end user. All other intermediate touch points only have custody of the product, not ownership.

Of course, if the gas is sold as a final sale at the well pad the gas was marketable at a much lower price!  Your royalty would obviously be calculated at this much lower sales price as well.  All gains after this would be the economic gain associated with capitalism. 

It seems to me that the MWCD market enhancement clause protects them from a low price point sale upstream of a processing plant when correlated to the the enhanced sales price for the processed residue gas when the enhanced value minus the cost to enhance that is realized is greater.   

Permalink Reply by Scott T. on December 19, 2013 at 11:07am

One of the main points of this thread was that, if the MWCD with all of their attorneys cannot get it right on the lease wordings, how can any small landowner be expected to do so.  The leverage of the MWCD has to be about as good as it gets.

In this thread alone it is clear, at least in looking at the MWCD's Addendum A to their lease (which is a public doc), that they did not appear to have a 'proportional deducted costs' enhancement wording in their own clause.

This proves a point that these leases can always be fine-tuned in favor of the lessor (landowner).  Do agree with James that you still have to have a willing company or the lease may not get signed at all.

I really think the MWCD lease is a good one to evaluate since there are not many similar size landowners and they have to have a large legal budget to negotiate these leases.  That said even the big boys can miss something.

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Permalink Reply by Joseph-Ohio on December 19, 2013 at 11:17am

Scot T.,

Landowner groups may offer similar or even much larger acreage blocks.

What they promote in a leasehold agreement may present similar / identical concerns.

I also agree that landowners do need a willing lessee to negotiate with.

Said it before and I'll say it again - good luck to all of us (landowners) we need it.

Stay on your toes and cover your 6.

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Permalink Reply by Anastasia on December 20, 2013 at 3:53am

They would sign this because it virtually guarantees their gas will be sold.  There are millions of cubic feet of gas available to go into pipeline on a given day, and there is only so much room.  If a pipeline carries 20MMcf per day, that could come from different wells and different companies, depending on contracts.  That can be negotiated each month - the pipeline company takes 20mcf from Antero, 40mcf from Gulfport, etc.  The pipeline company is going to take the gas from the company with whom they have the most favorable terms, and likewise, the company is going to take production from the wells where they have the most favorable terms with the  landowners.  MWCD will likely be the beneficiary of payments on millions of cubic feet of gas, and it would be to their benefit to make sure that gas is sold, and not shut in or choked down so that gas with better value can be sold.   

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