Replies to This Discussion

Permalink Reply by Les Bamburg on January 28, 2009 at 17:08

Sesport, that's just my guess as I assume the O&G company needs to confirm the presence of oil or gas in the shallower formation before drilling the vertical. Under my Scenario's 2-4 there is no separate vertical well as all the production occurs via the horizontal HS well. On a side note, EnCana mentioned the shallower potential at some of the pre-hearing meetings for Red River Parish units where there is no current production.

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Permalink Reply by Dion Warr, CPL on January 28, 2009 at 17:42

Sesport:

My thinking along these lines is this:

I have a friend who has an oil and gas bearing sand underlying his property. He has asked me in the past whether 'There is oil and gas down there?', and my answer has been 'Absolutely there is, however, if there is $2 million worth, and it costs someone more than $2 million (and really more like $1.2 million) to get to it, and pipe it to market or collect it in a tank for the pumpers, no one is going to go get it.'

There are many areas that are known to have O&G potential across NW LA (or many other places, for that matter) that have not been explored or produced to any great extent for just such economic reasons. Domestic O&G companies can become really excited when oil and natural gas prices increase because such events can bring (sometimes long) dormant prospects back to life when such operations come into the range of economic viability. In the case of the HS, technological advances coincided with these price increases and increasing NG demand to brew a watershed event in the Arklatex (NW LA in particular). The initial driver is the anticipated EUR in the area has gone up by (a) full order(s) of magnitude 'overnight'. The secondary driver will be in those areas that would not have been explored (or not economically developed in terms of O&G production) without the presence of the HS in the region.

Look at it like this: there are some areas around productive fields, around formerly productive fields, and in other areas that have been wildcatted in the past that could not be economically produced before last year, or ever before. The risks would have simply been too great, the costs simply too high to drill, complete, treat, and bring the product to market (laying of flowlines, placement of gathering systems and compressor stations, pipelines, tie-ins to major trunks, etc.) In those areas underlain by the Bossier and Haynesville Shales in productive conditions, some of these thresholds are (or will soon be) gone. Revenues from this anticipated scale of production can pay for a lot of drilling and infrastructure upgrades that would not have been paid for otherwise. Once it is in place, the 'costs to market' will go down considerably in many of these formerly marginal or 'wildcat' areas, to the point that it may result in some cascade effect in the form of additional E&P at other formations and other fields that were formerly so isolated as to be economically untenable. Of course, this doesn't even take into account the possibilities of recompletion of the HA wells uphole after their productive lives are spent at the HA depth, or using pressure gradient from the HA to assist in enhanced recovery from shallower zones. Think of this additional production as a more or less 'Haynesville Shale multiplier'.

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Permalink Reply by Les Bamburg on January 28, 2009 at 16:44

KB, if ownership (both working interest and royalty interest) is the same in both formation there would not be a need to allocate costs or production.

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Permalink Reply by Dion Warr, CPL on January 28, 2009 at 17:10

KB:

In general, production cannot be commingled from various formations unless ownership in the unit is identical in area and extent. My interpretation of that would be that if a l/o was leased 'top to bottom' (or at least surface to base of HA, or similar), your RI or UMI in the unit would be the same whether at the Hosston or the Haynesville. Therefore, one would receive their proportionate share of all commingled production (being the same proportion at all such given productive intervals).

Similarly, if one were UMI at all depths, the total cost of the well would be applied against the (aggregate) sales of commingled production. I could foresee some sticky points as to how to allocate costs if an O&G were to attempt to apply prorata costs as to each given interval, but as long as royalties or revenues are allocated timely (within the reasonable timeframe for operator to receive net sales), and accruing well costs as they are incurred, there shouldn't be any shortages to the UMI party. The well can only be drilled to TD once. If the hole remains open as the operator recompletes uphole, the costs of setting BP's and reperfing are what they are, which would be much less than paying for a new well from spud to a shallower TD.

At the same time, an open hole over its life would constitute one venture in several stages, not a 'big hole' and several 'discount holes'. Thus, I believe UMI would be unreasonable in believing that the same operator drilling an intial unsuccessful Smackover test to 13,500' would be charged nothing (like an outright dry hole P&A), and suddenly come into pay at a successful rework and Rodessa completion, and only expect their revenue to be offset for the cost of the reworking and perf, or the expected cost of the 5000' Rodessa well.

I guess to answer your question, IMHO, the sum of costs of more or less 'continuous' operations on a well from spud to P&A should be rightly accounted at the time that the costs are incurred, and those costs are not charged on any type of prorated basis or 'per foot' basis for methods of calculation. Those costs are then offsetted against net sales of production as that production occurs.

Costs on productive holes: can be offset against revenue.

No production: no ability to recoup costs against revenue; ergo, total dry hole & P&A = no chargeable costs to the UMI.

However (again, IMO): an unsuccessful initial test does not count as a 'dry hole' if subsequent (continuous) operations result in a successful completion. In this scenario, all costs to that point are chargeable against revenue.

This would seem to fit the criteria set forth in the Zink case.

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Permalink Reply by Les Bamburg on January 28, 2009 at 17:18

Dion, I have had experience in the past with transferring wellbores between units for the purpose of recompletions. Similar in concept to transferring a compressor between different fields or units. Operator(s) just have to assign an appropriate value for transfer. COPAS may even have some guidelines for value determination.

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Permalink Reply by Dion Warr, CPL on January 28, 2009 at 18:02

Les B:

I am in agreement with you insofar as it applies to the 'players' (e.g., working interest partners, either consenting or non-consenting). I'm not sure if the same rules could be applied under the statutory definitions applicable to the UMI owner, if the UMI owner does not become party to the JOA or other 'standard industry contract'.

KB has already brought the sometimes startling implications and differences of the treatment of UMI and WI owners insofar as applicability of well costs (dry hole and successful), indirect well costs usually accounted for under COPAS, and so-called 'field development costs', in light of LASC's rulings in Zink v. Chevron, et al. As far as UMI is concerned, how far afield of what the court would classify any particular invoice, payment, or assigned value as a 'direct well cost' or 'reasonable cost of supervision' would appear to be all-important. As opposed to other states, from a constitutional and public policy standpoint, the UMI functions as a 'protected class' from an E&P perspective in a way unlike any other state, as I have found and/or researched.

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Permalink Reply by Dion Warr, CPL on January 28, 2009 at 18:05

P. S. Les... Your concise answers are beating me to the punch as I compose my (somewhat... ?!) lengthier replies. Glad we're on the same page though... (:-{D>)

--DLW

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Permalink Reply by Dion Warr, CPL on February 5, 2009 at 19:38

KB:

You're making my head hurt. D$#@! hypotheticals...

If you can find a lessee willing to lease a particular strata in the middle of a productive sedimentary column that is commingled, be my guest.

I would think that the landman who tried to lease under those terms would rather stick his head in a oven.

OK, now that that's out of my system. A lease taken from a particular strata in the middle of producing wellbore. Hmmm... Instant mineral trespass by the lessee as soon as the well is perfed at various formations? The problem with such a situation is that it is impossible to determine which fraction of the product is coming from which formation. This is why you're not allowed to commingle unless the ownership is identical in area and extent.

OK, hypothetical... If all formations were more or less equal (instantly violated by shale / non-shale interval), theoretically one could attempt to approximate production coming from each strata by calculating equilibrium and partial pressure across a uniform pressure gradient. But not even the tight sands within each interval are uniform. Differing porosities and permeabilities... let's toss this to a reservoir engineer.

Going back to not being charged on the failed perf. I think all UMI is exempted from is dry hole cost on a non-productive well. If the well produces, UMI is charged for all operations that brought him to a successful completion. I cannot comtemplate the validity of any other analysis; otherwise, all the operator could recover from UMI is the hypothesized well completion cost for a well drilled and completed to the successful interval. This would fly in the face of the 'actual well costs' rule; a well cannot be both a dry hole and a producer. Can you imagine an operator trying to account for this? Well 999999 had downhole problems and sidetracks, but operator could only recover 'idealized' well cost from the UMI?

The issue with Zink (as I remember) was his being charged with the net development costs of the field in which he was located, including dry hole costs, which is expressly disallowed by the Mineral Code. LASC expressly admonished Respondents as to this practice.

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Permalink Reply by sesport on January 28, 2009 at 23:28

graysands - hey I'm here like everyone else just trying to wrap my frozen brain around it all. Ideas & concepts about all this business hit me in the face from time to time, and I like to at least make an attempt to understand. Makes life easier, IMO. And as long as these guys are willing to put up with me, no matter how off-track or out of the box I get, I'm most appreciative. If they ever think I'm out of line, they're most welcome to let me know. I'm coming back later to read and re-read again myself, so I'm off. sesport

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Permalink Reply by Brandy LaField on April 18, 2009 at 18:02

I have a question about KCS. Are they a reputable company to lease with. My mother n law has mineral rights in Texas and KCS sent her paperwork to sign as a lease agreement. THey were suppose to pay her a couple years back pay and monthly residules. They would never give her an exact amount, then later mailed a check for a thousand dollars. She's not going to cash it b/c we read about a scam that once you cash the check you are pretty much screwed. She is now trying to get a hold of them to see what this is about. However, they have 3 well logs on the property and are wanting to drill more in the future. There is like 700 acres. Can anyone give us some insightful info.

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