Replies to This Discussion

Permalink Reply by Two Dogs, Pirate on February 19, 2009 at 7:06

GD, I heard the same thing. Guess it helps to be in the right place and have the right coaching staff.

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Permalink Reply by Dion Warr, CPL on February 19, 2009 at 10:30

Earl:

You're not so much forcing them to go somewhere else as they O&G can choose not to accept your terms and go somewhere else that is more beneficial, from their perspective. By the time that they make it back to you (or your heirs), Earl Jr. or his kids might want to buy an RV or something.

As to the 'chump change' commentary, isn't that guy's stock down something like 78%?

Permalink Reply by Dorcheated A1 on February 19, 2009 at 10:48

Hell man, I fall asleep every night just hoping to wake up the next morning.

Dorcheated, holdin , nicotine, alcohol, wellbutrin, synthroid, myrapex, gabapentin, cylabrex, and a few others I don't care to name.

Permalink Reply by The_Baron on February 19, 2009 at 10:54

What stock he has left.

Permalink Reply by Dion Warr, CPL on February 19, 2009 at 13:24

KB:

He had to have paid something are put something up to pay for a lot of it, otherwise he wouldn't have had to liquidate so much of it due to a margin call.

Permalink Reply by Grillin' - MmmMmm on February 18, 2009 at 17:43

Most companies use discounted cash flow analysis to determine the viability of drilling a well and the profit to be expected. Pretty standard. They also use Decision and Risk Analysis, probability theory, for help in making these decisions. And then, there's the good ol' gut check method! But generally, the discounted cash flow analysis and modelling is the way most do it. Their discount factors vary from company to company and they don't share that but an industry standard is 10%. Prices are not talked about for fear of anti trust issues. But what a company needs for a threshold return is up to an individual company.

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Permalink Reply by Spring Branch,mineral owner on February 22, 2009 at 18:08

That is incorrect, KB, for much of his stock. He was buying $millions of it on the open market. It is a matter of public record.

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Permalink Reply by Dion Warr, CPL on February 19, 2009 at 2:42

Mmmarkkk:

I am looking at the options from the landowner's standpoint because that's who asked.

The landowner is in this for the lease terms that they can get, and the revenue/royalty stream due them for the life of the well(s) that affect their property, which is located in a specific location. Production modeling is useful to a point, as long as one understands that the well must be drilled for production to occur. If production is not obtained on the property during the life of the lease(s) affecting their property (if they leased, or even if they go UMI), the clock 'resets' as to their property, and this exercise can begin all over again. This event is much more likely if one considers that the E&P life of this field could stretch upwards to 50 - 60 yrs. (Discussed on another thread w/ Les B)

IMO, this is another factor to consider when factoring in a lease offer. You might get paid 'money for nothing' if nothing occurs during the primary term. With 2 -3 million acres under lease, with a lot of virgin territory (non-HBP) in between, at current prices and declining rig counts, this is a real possibility, even with companies attempting to drill single unit wells initially to HBP as much acreage as they can. If someone goes unleased for 10 years prior to production occurring b/c they are holding out for $15K per acre, and then finally succeed in getting their terms met, and another landowner gets $5K per acre three times before leasing yet again prior to said production beginning, who came out ahead? O&G can move around and afford to wait to develop 'your' acreage until its economic and timing criteria are met. The landowner (UMI or not) is grounded to their land.

Speaking of HBPing property, I find reasonable fault with an assumption that O&G will drill an initial well, then drill additional wells in the unit on a routine basis until they've drilled the maximum effective number of wells in an unit. This implies that the life of the unit is more in line with the expected life of the first well, plus a minimal lag time in between such wells. From a revenue perspective, that's fine, but O&G keeps another scorecard called leasehold position which is maximized by drilling one productive well per unit, then move on until the production values decline to a point that another well has to be drilled, or operations must occur, to maintain a lease. Maintaining a longer lag time in between the wells being spudded in a unit maintains the leasehold for a longer period, and still allows for O&G to produce (just from more and/or different units, rather than a select few. For O&G, the same number of wells can be drilled, a similar amount of revenue can be generated, but in so doing O&G can maintain 6 -8 times the leasehold. For the landowner, however, that can mean waiting (additional) decades for their royalty to be finally paid out, rather than the scenario which you suggest.

One other point that many l/o's do not factor into their decisionmaking is that what matters as far as income to the O&G (the reason they drill in the first place) is the revenue stream, and its 'startup cost'. The well cost is more or less constant from well to well, but the lease acquisition costs from unit to unit may not be (as much as prudent O&G attempts to make it so), and the unit NRI differs from unit to unit. No matter how much was paid during the lease-up period, if the NRI in one unit is greater than a second 'equal' unit, or the funds required to 'lease up' the first unit to make the net revenue interest (NRI) acceptable is significantly higher than to lease up the second unit to the same degree of NRI for the company, O&G will lease up and drill the second unit, and leave the first one to languish. The O&G will not explain why they will not take the l/o's counteroffers in the first unit, they'll just move on. This is part of the O&G 'black box' that the individual landowner sees as well. It's just seen as 'they moved on', and leaves the l/o wondering how they could pay X landowner $20K per acre just a few miles away last year, and they won't pay me $Y (where Y could be anything from $1000 more than the offer, up to the $20K that X received).

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Permalink Reply by Grillin' - MmmMmm on February 20, 2009 at 7:28

All good points Dion. Your reference to NRI is really important too! I'll drill 1/8 royalty wells before 25% royalty wells anyday!

And yes, you are right about HBP'ing and how fast the units will be drilled out. As an example, in Oklahoma, Newfield went out and drilled the entire play on 640 spacing. Now they are going back and infilling where the reservoir is best and the terms are most beneficial.

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Permalink Reply by Jay Murrell on February 19, 2009 at 5:22

Eureka !!!

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Permalink Reply by Fierofly on February 19, 2009 at 5:36

I'm in a section that is being drilled now, 19N-13W sec 16. The well was anounced to the public today as boyce pate 16-1. Myself and about 6 others in this section with about 3/4 ac. lots have not signed. Some have not even been approached in about 6 months. Force pooled has not happened YET. My question is should we participate? I'm thinking at a cost of $10,000 Each or freelaod? or take the $750 and 25% that others have taken?

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Permalink Reply by The_Baron on February 19, 2009 at 5:55

This well looks like its just a vert. test or a pilot hole. There is no lateral. They may be trying to HBP the leases they already have.

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