Replies to This Discussion

Permalink Reply by Philip Thackray on December 30, 2013 at 9:32am

RB,

 

The deductions track the volumes produced of NGLs and Methane (Residual gas).  So producing more will not help the deduction percentage.  Nor will “drilling efficiencies”.  Only price increases will lower the deduction percentage.  Apply my formula to a typical 1/8 royalty lease 12.5% x 0.2 (20%) = 2.5 percentage point deduction from the original 12.5% royalty.  In other words your royalty is actually 10% of the gross sales.  This is the “2%” reduction in your royalty the land man is talking about (if he even understands what he is saying).  It is not a 2% reduction in your royalty it is a loss of 2.5 percentage points from your royalty.  I have seen the check stubs from Rex and XTO wells.

The deductions are very substantial.  Perhaps they are completely legitimate and that is why people are not bouncing off the wall.  Frankly, most people just cash the check and don’t look at or understand the deductions.  Those who care may simply say “what can  I do about it” and again, just cash the check.

From a tax viewpoint, if you were given the gross amount from the well and had to pay back to the G&O company the costs from well head to point of sales (the deductions) then these would be “deductable expenses”.  But these deductions are taken away from the gross by the G&O company (who gives you the “net”) so they are not deductible expenses for the landowner.  The only tax advantage to the landowner is the 15% depletion allowance.

At the very least, these deductions should be more transparent.  Also, they should be properly explained to landowners during the leasing process.

 

Phil

Permalink Reply by RB on December 30, 2013 at 10:57am

Yes, it is quite underhanded to write a lease with an unknown variable for the leaser with cost of doing business deductions.  From what I have read, the deductions should be transparent, and, that we have the right to audit.  It wouldn't surprise me if they were listed in a manner hard to understand.  Shame on them.  Furthermore, you are stating it is a fixed cost and that this is predetermined in advance, despite the likelihood that these costs could (should) decrease over time.  Chesapeake was caught fudging the deductions to increase their revenues, and reduce their royalty payout.

That is very misleading for him to say.  And I am still trying to figure out the use percentage vs. percentage point.  For anyone who cares, see below:

The term "percentage point" is used to get around an ambiguity in

English when we are comparing two different percentages.  The problem

is that "percent" implicitly refers to a relative change (some

fraction of an original amount, like a salary increase of 10%) rather

than an absolute change (some specified amount, like a salary increase

of $1000).  What do we say when we want to treat a percentage as an

absolute amount?

 

If, for example, the current tax rate were 10% and we increased it to

12%, we might say that we increased it by 2 percent.  But that would

be taken to mean that we increased it by 2% _of the original 10%_

(that is, by 2/100 of 10%, or 0.2%), to 10.2%.  The question is, are

we using "percent" to mean one of the units called percent, or a

percentage of that percentage?

 

To avoid this problem, we say instead that we are increasing the tax

rate by "two percentage points".  This unambiguously refers to the

number 2% itself as a unit, rather than to 2% of something else.

 

On the other hand, if we actually wanted to say that the tax increased

to 10.2%, it would be a good idea to clarify that as well, perhaps by

saying explicitly that it increased by 2% of its old rate, or by

stating the old and new values.  Technically, however, it is correct

to say that it increased by 2%.

Permalink Reply by Philip Thackray on December 30, 2013 at 11:24am

RB,

The various percentage uses are confusing.  I know what I "mean" when I say percentage point subtraction or addition verses percentage decrease or increase but it is easy to lose tract.

That is why I did the full calculation.  There is no confusing language when you state a base Royalty, Gross $, Deduction $ and then calculate actual royalty relative to Gross $.

I think that the deductions are expenses based on out of pocket costs for processing and transporting x # of gallons or cubic feet of gas.  I do not know exactly how these cost are calcuated.  I don't think that there is a 'bricks and mortar" (depreciation of capital equipment) aspect to the deductions and therefore these deductions are only a function of volume and would not "decrease" over time - but I could be wrong.

I'm still working on all of this - believe me I have a lot of questions!!

Phil

 

Permalink Reply by RB on December 30, 2013 at 11:46am

I believe you know what you are talking about. Honestly, I am good at math and still trying to work this backwards to understand the "play on words" and play on math.  I know I knew at one time.  And I figure there is a fixed rate cost on volume for transportation of the "goods", but you would think that overtime, they might find a lessor expensive way of  refining and "selling" it, just as they are enhancing their efficiencies of drilling for it.

I was thinking that the payoff for the O&G firms must be huge, because, if it costs 20% post production, the capital investment and labor for pre-production must be at least twice that, got to be as it is much more involved.  So we are looking at a minimal cost of 60% to extract and sell.  Then pay out royalty of another "up to" 20%.  plus commissions, plus upfront lease signing bonus. Without the commissions, we are looking at 80% costs.  That remaining 20% must be worth an awful lot of money.  There is no way all these firms would invest what they have if the payoff was not good.  So, the question, is the payoff (remaining 20%) a great value?  We could do  the math with a commission stub, unit and productions figures.  OR, are the post production costs inflated??

Another thing to consider, the increase in the firms looking to get into this.  I remember reading about it when it was newly discovered out west.  At the time was unaware or things hadn't started in PA.  Now western PA is a focus.  It is growing and evolving.  Why so?  Basic economics states that as supply increases, prices will decrease.  Unless prices become fixed... umm.  Surely they know that, and yet, it is still a viable venture.

RB

Permalink Reply by Philip Thackray on December 30, 2013 at 12:08pm

Alternate calculation-

Maybe this is a better way to look at the numbers.

Example: 18% royalty with a well whose deductions are 20% of the gross sales amount where you are the entire unit.  That means that you will get 100% - 20% = 80% of the Gross $.  If there are no deductions you would get Gross $ x 18% = 0.18 x Gross$.  With deductions you will get (80% of Gross $) x18% = 0.8 x 0.18 x Gross $ = .144 x Gross $.  So the equivalent royalty relative to Gross $ is 14.4% just as we got in my earlier calculation.

I can’t speak to the future trends of deduction percentages.  Inflation at least will move them in positive directions and hopefully the price of NGLs and methane will follow.

As to supply and demand, there is a lot of new supply but there is a lot of new demand coming as well.  See here:

http://www.rbnenergy.com/golden-years-the-golden-age-of-u.s.-natura...

To calculate the value of a well to the O&G company one would need to do some serious projection of future income.  Normally this information is fed in to a Net Present Value or Internal Rate or Return spread sheet calculation.  These are commonly shown in the Rex and Range presentations.

Phil

Permalink Reply by RB on December 31, 2013 at 6:21am

Phil,

I have been querying around the site and see that it appears that most enhancement charges, regardless of which firm, appear to be charging 20%.  You were the first one to volunteer information on REX.  2% was fine with me but 20% is another story. If it works out at 20%, they will be hearing from me.

I can certainly calculate the basic math.  There all kinds of ways to work the numbers.  You can even offer a higher royalty and offset it with a higher enhancement.  I wonder if the new enhancement charges are a workaround for the drilling firms to get closer to only paying 12.5%. 

Did you stipulate in your lease for a maximum enhancement clause?  It will be interesting to see what the deductions are once production begins. Like big oil oligopolies, price fixing is the name of the game.

If anyone is willing to volunteer their figures, we could probably get a handle on it now.

Permalink Reply by Philip Thackray on December 31, 2013 at 7:38am

RB,

What do you mean by "enhancement charges"?  Is that another phrase for what I have been calling deductions?

XTO uses the phrase YOUR  OTHER WITHHOLDINGS (YOUR OTHER W/H)

Rex uses the term Owner Deductions.

The numbers I have are production numbers.

"If it works out at 20%, they will be hearing from me."

Here is the XTO Interest Owner Relations phone number:

1-866-889-2613

and Rex 1 814 278 7267

Phil

 

Permalink Reply by RB on December 31, 2013 at 7:51am

Phil,

I don't have a copy of the lease to share.  Enhancement charges are charges from the wellhead to point of sale, also considered deductions from royalty check.

RB

Permalink Reply by Philip Thackray on December 31, 2013 at 8:23am

RB,

The phone number thing was kind of a joke.

I can't provide you with the Evans City Sportsman’s Club Rex reports as they belong to the Sportsman’s Club.  I can summarize the information in relative terms and when I get some time I’ll do that.  The copies I have are not good but I can see enough.  These wells have been in production for at least a year.

The XTO stub I have is my first (Oct 2013).  I’d like to see a few months more XTO check stubs before I’m willing to publish a summary of the relative deductions.  I’m not going to publish the actual check stubs as I don’t want to start that.

Phil

Permalink Reply by GM on December 30, 2013 at 11:09am

"Even though the clause lists severance or excise tax as the only deductions, where leases like this one have gone forward into production for “wet wells”, XTO is deducting all expenses between well head and point of sale as described explicitly in their more recent leases.  My lawyer, (an Oil and Gas guy) says that nobody has been able to beat this."

Do you think the attorney is referencing that as a general statement of all leases, or just to the recent leases that actually are not so "vague" ?

Permalink Reply by Philip Thackray on December 30, 2013 at 11:32am

GM,

A lot of people have these old leases applied to wet gas wells and so far no one has "broken through" as far as I know.

The general interpretation is that these old leases are talking about well-head price and if you track the chain of costs backwards from the point of sale, the deductions for processing and transportation yield what the gas is worth at the well-head.

I am working with my lawyer on another Oil and Gas issue but should that get resolved some time soon I would like to return to this issue and the subject of deductions in general.

Phil

Permalink Reply by RB on December 30, 2013 at 11:51am

"if you track the chain of costs backwards from the point of sale, the deductions for processing and transportation yield what the gas is worth at the well-head."

oh, that the deductions totaled the sale value?? or did you mean the numbers added up correctly??

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