Bonus or Royalty? Both?
I did a little speculation below:
Is the Bonus or Royalty more important ??? Both???
The density of well drilling in the Marcellus appears to be about 1 well for each 40 acres of productive area.
http://www.binghamtonsustainability.org/files/gas/What%20Is%20Diffe...
Although a 20% royalty appears to be optimal and hardly unusual, assume a 15% royalty for making a rough estimate of the first year’s royalty income.
It is likely that the first day production might be 4000 mcf and the first years production might be an average of 3000 mcf/day.
3000 x 365 = 1,095,000 mcf/year x say, $5 = $5,475,000 x 15% = $821,250
First year income for each 40 acres might be $821,250 / 40
= $20,531.25/acre, MORE OR LESS [First year]
It does not matter where the well is located. What counts is how may acres are included in a given pool.
Note all of the numbers above are estimates. For example the $5 wellhead price used has been used by producers but current price is a little over $4 and there are pedictions of $7 or $8 in the near future. The spike of over $16 we had not long ago does not seem likely to return soon. [But then there is the enormous demand for energy in Indisa and China...]
Is the Bonus or Royalty more important ??? Both???
The density of well drilling in the Marcellus appears to be about 1 well for each 40 acres of productive area.
http://www.binghamtonsustainability.org/files/gas/What%20Is%20Diffe...
Although a 20% royalty appears to be optimal and hardly unusual, assume a 15% royalty for making a rough estimate of the first year’s royalty income.
It is likely that the first day production might be 4000 mcf and the first years production might be an average of 3000 mcf/day.
3000 x 365 = 1,095,000 mcf/year x say, $5 = $5,475,000 x 15% = $821,250
First year income for each 40 acres might be $821,250 / 40
= $20,531.25/acre, MORE OR LESS [First year]
It does not matter where the well is located. What counts is how may acres are included in a given pool.
Note all of the numbers above are estimates. For example the $5 wellhead price used has been used by producers but current price is a little over $4 and there are pedictions of $7 or $8 in the near future. The spike of over $16 we had not long ago does not seem likely to return soon. [But then there is the enormous demand for energy in Indisa and China...]
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Replies to This Discussion
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Permalink Reply by Sam Douglass on
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Unit size is not relevant for my calculation. There are many wells in any given unit. Divide the 800 acres by 40 acres to estimate production from the total unit [ie. you would multiply the numbers I gave you by 20.]
A land owner with 80 acres might receive double the amount I mentioned.
A land owner with 120 acres might receive triple the amount I mentioned.
A land owner with 20 acres might receive half the amount I mentioned.
An 800 acre unit seems likely to have 20 wells - clustered 4 or more on a well pad - maybe 3, 4 or 5 well pads.
In a new area wells may be 1 or 2 per pad until geology is verified; It is more efficient to drill all the wells at once and the drillers will do that after they get going. There can be more than 6 wells on a pad. -
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Permalink Reply by Outback on -
We need to get a few things straight. Unit size is very relevant. It determines a landowners share of the royalty pool. For example I can site many as the units are public record and are recorded in the courthouse. However I & my family are members of three different units.
Evanchick/Chancellor 719.43 acres, Morris Otten 942.50 acres & John Barrett 806.39 acres.
Evanchick/Chancellor is permited for 8 wells 2 are drilled and the rig has moved on.Morris Otten is permited for 6 wells 2 are drilled and the rig has moved on. John Barrett is permitted for 6 wells 2 are drilled and the rig has moved on.
Over 1 1/2 years we have received 48 months of royalty checks which @ 15% have averaged 114.93 per acre per month per well.
I agree that it is very inefficient to drill 2 and move on however Chesapeake has explained that pipeline limitations coupled with the decline curve make staggering the wells more reasonable. -
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Permalink Reply by Outback on
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Secondly, and more important those unit declarations included 32,56,&36 landowners. Their leases went from primary to secondary and as long as they are paying royalties then no more "bonus". As leases approach 5 yeares old Chesapeake & others are drilling & setting up units as fast as possible to avoid the "bonus" payout.
rlstore.com is an excellent site and worth the $18 per year fee. They do offer a free look to show what they have. -
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What you say must be right. It sounds like Chesapeake is putting together fairly large units and drilling one or two wells to hold all the leases in the unit. This means pay day will come at some time in the future. Since most leases include all strata from the surface to the center of the earth [not limited to Marcellus] Chesapeake could even drill shallow wells to hold the lease. Possibly it is not drilling the horizontal wells at this time but only vertical wells to get better information before drilling horizontal wells in the future when the infrastructure and market are there. Under normal circumstances each horizontal well should consume about 40 acres with the revenue projected, but revenue is divided proportionally among all the acreage holders in the unit. Thanks for your run down on how Chesapeake is holding its acreage - on the cheap. No dummies there.
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Permalink Reply by Roy Andrews on
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I do not understand these units, I have been told that 640 acres by state law is the maximum per unit?
Roy -
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No limits on the size of Marcellus units. Statute applies to Onondaga and below - unfortunately.
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Permalink Reply by Roy Andrews on
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thanks for the info, my source for the 640 acre limits was two different land men
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Permalink Reply by Carol on
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Williams seems to be limiting their units to 640 acres plus up to 10% for a total of 704 acres, at least in Westmoreland County. They actually put that in their leases. I was told about that limit by landmen also.
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Permalink Reply by Roy Andrews on
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Outback, which county are your leases in ? Chesapeake is pursueing leases here in Butler co, but admit that they have no pipline to get the gas out at this point.
Roy -
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Permalink Reply by May on -
Not only a pipeline. Butler County Marcellus gas is "wet" meaning it has propanes, butanes and ethanes in the gas stream which need to be stripped out in order to sell the gas into a pipeline. Make sure when leasing with a company, they've got a plan to deal with the wet gas.
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No infrastructure - no meaningful operation for awhile, maybe years. current leases are to get leases as cheaply as possible. When things are in place and your land is needed the price will go up. Meanwhile companies will get leases with terms as long as possible. Or they will drill something close to token wells to hold a unit. Bonuses should be large enough to compensate for the wait. Royalties should be at least what is paid to Texans for their Barnett formation. Marcellus is better.
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