Replies to This Discussion

Permalink Reply by Geoman on July 8, 2010 at 7:00

The basic calculation is as follows...

(number of acres leased/number of acres in the production unit) X (fractional royalty interest agreed upon in your lease) = decimal mineral interest (which depending on the operator is usually reflected on your monthly royalty payment check.) minus severence taxes and any operating expenses the operator deducts (if your lease is set up that way) Some landowners actually negotiate this out.

So for example...lets say you've leased 10 acres for a 1/4 fractional royalty interest and the production unit is 640 acres (usual standard in LA, although there are exceptions) .

10/640=.015625

.015625X.25=.0039062 decimal mineral interest.

Lets say they drill a Haynesville well and it's initial production is 15million cubic feet per day.

Lets say the current Henry Hub gas price is $4.50 per thousand cubic feet.

12000 per day X 30 days = 360,000 X $4.50 = $1,620,000.00 X .0039062 = $6328.04 minus taxes and your share of any operating & transportation expenses (if your lease is set up that way).

Now I'm not taking into account the decline rate of the well, but this should give you the general idea.

I'm sure other folks will have much more to add...

Hope this helps.

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Permalink Reply by smith1 on July 8, 2010 at 9:26

www.geology.com/royalty
quick and easy site, thanks, even I can figure it out! ha

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Permalink Reply by Two Dogs, Pirate on July 8, 2010 at 11:13

Don't put too much trust in these online calculators.

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Permalink Reply by Marc Stepman on July 8, 2010 at 12:14

Those online calculators get you to the exit on the interstate for the ball park. They do not get you to the parking lot of the ballpark or in it!!

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Permalink Reply by DJG on July 8, 2010 at 11:23

These online calculators tend to heavily OVER-estimate the projected royalty has they do not properly factor in the high decline rate (as high as 80%-90% in the 1st year) for these HA/BO shale wells.

I've attached an excel worksheet that I worked up that tries to account for the high decline rates. I still think that the numbers calculate higher than will likely be reality, but it does take into the account the high decline.

Plug your variables (royalty rate, mineral acres, unit size, any deductions, price of gas) into the yellow fields.

It also ends up, unfortunately, calculating about 50% less projected royalty per acre than the above online calculator.

Use these for entertainment only, as there are just too many variables likely so as to be able to properly project things with any degree of accuracy.

Attachments:

• RevisedHSBORoyaltyEstimator - Feb 5 2010.xls, 4 MB

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Permalink Reply by Marc Stepman on July 8, 2010 at 12:22

When you say minerals owned in unit you have the number 1. Where did that come from? I follow the rest. Looks like an excellent model. I saved it and I appreciate you putting it out here for folks. Can you kinda give a tutorial for it. Thanks a bunch?

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Permalink Reply by DJG on July 8, 2010 at 13:06

Hey Marc,

For those yellow fields add the following info pertaining to your own situation:

A. Total Number of Acres in the Unit: For Louisiana, these generally would be 640 acres. For Texas, however, they can be all over the place. Just add in the number of acres in your particular unit.

B: Minerals Owned: Put in the number of minerals that you own within the unit. I.E. 10 acres, 1 acre, 25.5 acres, 115 acres, etc...

C. Royalty Rate: Put in the Royalty Amount that you have agreed upon per your lease. I.E. 25%, 20%, 18.5%, etc.

D. Discount Rate: If you have any deductions per your lease that you want to account for, you can add that % here. Otherwise leave it at 0%.

E. Initial Production: Plug in the IP report number for the well you are using.

F. Price of Gas: Plug in the NG price that you want to calculate things at. Currently at around $4.50, but over the 20-40 years it will take to fully drain these units it could likely be higher, hopefully...


Go ahead and plug in your specific numbers and see what you come up with.

As always, keep in mind that their are MANY variables that will be difficult to calculate such as:

a. varying production rates between wells in your unit.

b. variance in NG price

c. Shut in periods

d. recompletions periods

e. variance in in-fill time period for you to get those multiple wells.


All of these variables require a crystal ball that is beyond any of our best projections.


Have fun.

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Permalink Reply by Marc Stepman on July 9, 2010 at 3:01

Thanks a bunch. I have been playing with it. I really like it. Variables a,b,c,d, e are always in my mind. I just like the way the model works. Very cool. Thanks for the explanation.

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Permalink Reply by Dion Warr, CPL on July 8, 2010 at 12:47

D. Gaar:

I would have to agree with you assessment of many of the 'standard' calculators. Many of them are based upon a logarithmic decline (which is well applicable to conventional reservoirs) versus hyperbolic decline (which appears to correlate better with the unconventional reservoirs such as the shale).

Also, the calculators assume no reworking or maintenance operations (ie., downtime), infrastructure bottlenecks (restricted output), or anything other than optimal well performance and depletion, which rarely happens in the real world over the long term.

In concert with what you state here and have stated in part elsewhere, attampting to use a royalty calculator (even if properly calibrated to the metrics of the shale) to properly assess what an owner should be paid for a royalty purchase is akin to using the price of apples, the current year's yield, and the ideal productive life of tree to calculate the value of an apple orchard. To attempt to do so is asking for trouble, or at least disappointment, to say the least.

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Permalink Reply by ledlights on July 8, 2010 at 20:45

Based on the offers I have seen for my MIs, I believe that royalty purchase businesses excessively cover themselves beyond any justification from the actuarial tables that could be generated from these shale play wells. Anyone who uses a royalty estimator should be conservative with any input variable that requires estimation. But I think it is still instructive to compare royalty purchase offers with such calculations. I believe many people would be surprised by the degree of divergence between the two.

I am extremely sceptical about the existence of any royalty purchasers who are just "trying to just make a (good) living". Do they exist? I think they are a little more ambitious. Has anyone around here ever gone to the trouble of pitting multiple bidders against each other? Am I incorrect in thinking that the mineral owning folks who seriously consider such offers are either terribly uninformed or they have some need or pressure in their financial situation which would naturally make them less disposed to take the time or risk of trying such bargaining?

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Permalink Reply by Henry on July 9, 2010 at 0:32

ledlights,
I'll suggest that the huge uncertainty facing a royalty purchaser is the problem that he may have no idea when the 2nd through 8th wells may appear in a section. If these wells don't get drilled for decades, then that royalty money is so far out in the future as to be worth very little today. I suspect most royalty offers are based on the premise of only one well per section in the near term.

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Permalink Reply by DJG on July 9, 2010 at 1:52

One way to help with that dilemna for anyone still currently unleased is to really fight for including a "Continuous Production Clause" to be included in the Exhibit A addendum requirements when negotiating your contract.

I.E. - O&G company has the obligation to begin operations on each subsequent well no later than X months/years after the completion of each prior well. If the O&G fails to continue with their in-fill production of your unit, then the lease terminates at the end of it's primary term.

In my mind, this requirement is every bit as important as including a proper depth pugh clause.

The O&G might give some push back to not include this clause, but if they do indeed have all intentions of continuing with the in-fill production then they should ultimately not have a problem with putting that in the conditions of your lease.

This clause can be a huge protection to avoid getting acreage HBP indefinately with only one well

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