Replies to This Discussion

Permalink Reply by JeffNParis on October 7, 2009 at 11:55

Jay,
Forgive my ignorance if this is an impossible question to answer, but if EUR's are 4-8 BCF per well, and there are 6-8 wells per section, is there a way to calculate the possible financial outcome per acre for various price points? Parker posted an Excel worksheet with the expected Haynesville decline curve and where you can plug in various factors according to acreage, price, and royalty%. Just wondering how you convert a BCF to work on that sheet. Possible?
JNP

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Permalink Reply by Ian on October 7, 2009 at 15:25

Jay,
This is Ian with Phillips Energy Partners. We are a royalty acquisition company and just had a question regarding the EUR's. I tend to agree with the 4-8 Bcf per well but what do you think about the 6-8 well per section idea. I have heard from several engineers and people in the business that 4 wells may drain the section and some have been rather adamant that 6-8 wells draining a section is purely companies trying to show their investors propoganda to drive their stock up........ whats your thoughts?

Ian

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Permalink Reply by w.r. frank on October 7, 2009 at 16:07

That's what I would think if I was in the royalty acquisition business.

Nobody knows! Not even Arthur Berman.

I would tend to believe a 4 bcf EUR on a $9 to $9.5 MM well doesn't give much PV10 even at $7 NG. Hello Arthur!

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Permalink Reply by JeffNParis on October 7, 2009 at 19:56

Thanks Shale Geo. But how do you convert bcfs into daily average mcfs? The royalty calculator I'm using is an excel worksheet posted by Parker that requires an mcf...not sure if it's possible to calculate using this sheet.
JnP

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Permalink Reply by Henry on October 7, 2009 at 23:54

JeffNParis,

Gas prices are in the units of "dollars per thousand cubic feet." You'll see some number like $3.50 mcfe for the price of gas. This means $3.50 per thousand cubic feet. So, if a well has a total EUR of 5 Bcfe (that's 5 billion cubic feet), then divide 5 Billion by 1000 and multiply by $3.5. That's the total money that would be generated from sales of this well, at that price (in this example, $17.5M).

To get the landowner's share per acre, take that $17.5M, divide by 640 (assuming a normal section of 640 acres), and multiply by the royalty percentage. Say the landowner had a 25% royalty -- then the landowner's share out of that well would be $6835/acre over the life of the well.

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Permalink Reply by JeffNParis on October 8, 2009 at 0:25

Thanks Henry. That's easy enough!
JnP

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Permalink Reply by alleyboy on October 8, 2009 at 3:25

all of these figures make me feel relly dumb. iF ALL i AM EXPECTED TO RECEIVE IN ROYALTIES over the life of a well is 8000.00 why in the world did I receive 17,500.00 for a lease. sec 02/17n/15w from twin cities AKA Chesapeake Makes those who say the royalties are more important than the lease money look kinda wrong.

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Permalink Reply by Skip Peel - Mineral Consultant on October 8, 2009 at 3:37

alleyboy. Do you think the price of natural gas will average $3.50/mcfe over the life of your wells? And do you think you will only get one well? As opposed to 6 to 8? These are variables that have a tremendous impact on projected future earnings. Use the formula or the GHS royalty calculator and plug in whatever variables you care to use. I suggest that you use a well life average price per mcf in the $5.50 to $7.50 range and six wells. And keep in mind the example is for 1 acre.

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Permalink Reply by DJG on October 8, 2009 at 7:32

Skip, What are your thoughts on the conventional thinking that it will currently take 6-8 wells to drain a 640 acre unit. We are currently in lease disscussions for some minerals in East Texas and the landmen for the O&G Co. are talking about less wells and higher total acreage units. They are saying that permiting guidelines in Texas are changing with respect to allow much larger units for horizontal completions (up to 1,000 acres). I then countered that if the units were that large than we could then expect 8 to 10 wells as the unit is filled in with production. Their reply was that it is uncertain at this point, but more likely to be in the 4 -5 range over that 1,000 acres) - which is much fewer wells that I have previously read about over that amount of land. Is it that the fracturing effeciency is increasing dramatically so that they could drain these larger units with fewer wells? I can't imagine that they would be wanting to leave any NG behind.

Similar question would be that as the technology improves to allow fewer wells to get the drainage job done, is it safe to assume that then that each of those corresponding wells would have a proportionally higher EUR's (i.e. fewer wells over the acreage of the unit - but each well then producing higher rate for a longer period than the current 640 acre/6-8 well assumptions)?

Thoughts?

Thanks.

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Permalink Reply by Skip Peel - Mineral Consultant on October 8, 2009 at 7:59

Whoa, D. That's Shalegeo and Grillin' Mmmarkkk territory. LOL! I take a much simpler approach but then again that's the landman in me. Ask yourself if the operator of a unit would intentionally develop in a manner likely to leave otherwise recoverable hydrocarbons behind? In other words, the operator, the lessee (if different) and the mineral owner all have the same interest in maximizing economic production. I doubt seriously that any operator would drill fewer wells and leave more gas behind in an effort to deny mineral owners their full royalty share. If technology advances to the point where fewer wells effectively drain a unit, the operator will likely employ that technology. If they fear that fewer wells drilled differently will have a significant negative impact on the EUR for that unit, they will not employ that technology. Also the LA. Office of Conservation and, in your example, the Texas Railroad Commission are motivated by the state's desire to enable exploration and enhance production as a source of revenue. They will not grant greater spacing regulations if they think it will reduce production. Those entities were established and exist for the purpose of ensuring that hydrocarbons are produced in a manner likely to produce the highest percentage of recovery.

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Permalink Reply by Grillin' - MmmMmm on October 8, 2009 at 10:09

I believe Skip has hit it! The companies will be driven to drill the right number of wells to effeciently drain the reserves, regardless of the unit size. Now, when those wells get drilled is a bigger unknown. In the next few years, maybe only 4 will get drilled but over time the optimum will get drilled.

There are efforts to expand the size of the units that horizontals will "hold". It is a more efficient use of capital from a drillers standpoint. reduces amount of lease expirations and re-leasing that has to be done.

Permalink Reply by Grillin' - MmmMmm on October 8, 2009 at 10:05

There will be more than one well per 640 acres. I can guarantee you that. Say there were 7 more wells. Multiply that number by 7 and you get some good looking money.

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