Replies to This Discussion

Permalink Reply by insomniacnla on December 4, 2008 at 14:46

I had some other language in my lease regarding production but I just added that clause at the end just to try to avoid future problems should a vertical Haynesville well be drilled. I figured that an o/g company probably would not let me out of the lease without a lawsuit anyway. I hope that the need for a suit never comes about and that a horizontal Haynesville will be drilled in my section and will come in with MONSTER production. LOL

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Permalink Reply by Grillin' - MmmMmm on December 4, 2008 at 16:27

I hope you are right. But I still don't see how that clause addresses a vertical vs horizontal well. Given that clause, they can drill a vertical well, establish production at 500 mcf/day and hold your lease for a long time. Am I missing it? It is late!

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Permalink Reply by insomniacnla on December 5, 2008 at 3:37

I was not trying to limit if a company could drill a horizontal versus a vertical but I was thinking of a couple of Camterra wells that were drilled about 3 miles from me that are producing 2,000 mcf per month.

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Permalink Reply by Grillin' - MmmMmm on December 5, 2008 at 10:02

again, still don't see that clause fixing the problem. 2000 mcf per month is revenue of $12,000. That will more than cover operating costs and constitute "Paying Quantities".

I expect a few companies to utilize vertical wells to hold units in a few instances, not widespread. But I think the companies are well within their contractual rights. And as long as they are within the primary lease term, its moot. But others have used this technique successfully in many areas. Really haven't found a way to defend against it or write agreements to fix it.

Permalink Reply by The_Baron on December 5, 2008 at 4:10

There is plenty to argue about in a standard lease.

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Permalink Reply by Grillin' - MmmMmm on December 4, 2008 at 10:46

The cost to drill a well shouldn't factor into the paying quantities calcu. Once the money is spent, its sunk and you only need to cover operating expenses, taxes, etc. with after-royalty revenue.

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Permalink Reply by BirdDawg, plain ole' idiot on December 6, 2008 at 9:23

Mmmarkkk,
You are right, I'm sure, that cost to drill a well should not factor into the paying quantities calculation. But realistically, but maybe not legally, I think that a well that is not producing enough to ever cover total drilling and completion expense, especially when the well was obviously drilled for the purpose of holding leases only, with no expectation of making money, should not be considered paying quantities. I agree with your premise that it is legal and will stand legally, but I think it is an O&G game, and definitly not in the best interest of the mineral owner. And really I do not think it should be allowed by law. But I know it doesn't make any difference what I think.
By the way, I enjoy and appreciate your posts, they are always very informative and helpful.

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Permalink Reply by Grillin' - MmmMmm on December 7, 2008 at 16:31

BirdDawg: you said "But realistically, but maybe not legally,...". Don't quite get that reasoning. If it is legal, it is realistic. If I drill a well and it turns out the well won't recoup the original drilling costs, I can't shut the well in and ask for my money back. So, I just turn it to production and recoup whatever I can from the production. Maybe I get 10% of my costs back, maybe I get 90%. But that really does not matter! All that matters is if the well is making enough gas to recover my current month-to-month 'regular' operating costs.

While we all know that a horizontal well is probably better in the HS than a Vertical well, the operator may not have enough money to drill the horizontal well at this time, particularly if he has hundreds of wells to drill and in today's market. So he will drill lots of vertical wells, and get the gas flowing in paying quantities. He will also gather a lot of good production data across a wide area which will allow him to optimize the future drilling. Then when they go to infill the units to 80 acre spacing, he'll be able to do it with a much improved technical data set and enough production information to make good assessments of the new drilling programs. Does it delay the time when the mineral owner gets big bucks? yes. But he's not violating any law or contract, he's actually optimizing the entire program and probably improving the long term conservation of the reservoir.

Thanks BirdDawg; I try and interject technical and business experience from 30 years around this oil patch. I've been in almost every segment of this business in some form or another and feel that there is a lot that the non-oil/gas person should know. Sites like this are great for getting that information out, even if some people don't believe a lot of it! I'll keep trying! Sometimes I might blast out a not-so-sensitive answer, but usually will apologize at some point...except when we talk politics!!

As for the comments later on about 2 sets of books, you know the government actually forces companies to keep 2 sets of books!!! Financial accounting and cash accounting. But I've heard for 30 years about how oil/gas companies keep the books crooked, etc. and yet, I've never stumbled across any of them while working for a major, buying assets from independents, buying the entire company froma very small company, etc. but believe what you will, I'll never be able to talk anyone out of that belief and I really don't care to.

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Permalink Reply by Grillin' - MmmMmm on December 4, 2008 at 11:06

Thanks Jim. Quite an interesting read. Looks like it affirms that only regularly occurring operating expenses are included in the test of paying quantities and non-regular occurrences, such as workovers or repairs to damage that isn't a common ongoing item is excluded. So you can't include the cost to repair equipment from a lightening strike or a workover/recompletion, etc. So if it costs $1000 to operate on a regular ongoing basis and the well nets $1001, then it is producing in paying quantities! There are lots of other interesting issues brought up in that case and subsequent appeal.

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Permalink Reply by Dion Warr, CPL on December 4, 2008 at 11:46

Is it just my reading, but didn't the court's reasoning also illustrate that the test for paying quantities was not necessarily narrow, such that the test for profitability or 'paying quantities' was still left to judicial determination?

It would seem that although imprecise, the definition of 'paying quantities' is left vague and subject to the reasonable and prudent operator test because of the imprecise nature of oil and gas production and well management. The process does not lend to rigid accounting analysis in a short-term scenario. As an example, what incentive would XYZ Oil company have to drill additional wells if the first well drilled under a lease failed to 'hit the sweet spot", if it feared that it would possibly lose its lease prior to being able to "rig up" on the grounds that the first well was 'not producing in paying quantities'? I know that CW on this site from mineral owners is that HS is 'just there, you just have to go get it', but it is still possible for O&G to not quite get it right.

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Permalink Reply by Dion Warr, CPL on December 5, 2008 at 2:44

Jim:

Perhaps so, but not always. Some of more commonly used printed forms have limits on how long those payments can maintain the lease by the use of shut-in payments, and I am not sure how many of those would allow an operator to attempt to do this with oil (since the intent generally was for gas wells). And understand, I offered the above as just a hypothetical, since in practice most mineral owners would be happy to grant XYZ an extension to drill a second well if XYZ asked for it (sometimes even for no addn'l consideration).

You've been around this business awhile; how many times have you run into operators (generally more of the 'mom and pop' or small closely held variety) that cut a rig loose, only to realize or reevaluate a short time later and figure out that they should drill another well, but the current 'so so' producing well is still holding their lease? Such operators are sometimes willing to operate at a reasonable loss for a few rounds until they can get a rig back, believing that the next operation will bring them to profitability. If one evaluated well profitability (and by extension, paying quantities) based on a fixed and isolated period of time (say, six months or a year) in such a scenario, lessor could force the operator to temp. P&A, lease the property again, then reenter the well and effect their next set of operations (new well, rework, etc.). That would fit neither the reasonable nor prudent tests. For the sake of argument, let's assume that such an operation occurred well after the primary term had lapsed, on a partially depleted reservoir, on a lease without a Pugh clause. Many of the lease forms I deal with specifically limit the shut-in provisions to use no longer than five years past the end of the primary term (and many attorneys limit it further by retooling the language to no more than two consecutive years, and two years past primary term.) I really don't want to get lost in the example, though.

IMHO, the whole point of leaving 'paying quantities' to judicial determination is that the system can be taken advantage of, but there are 'good' operators out there acting in everyone's best interest that will from time to time be willing to take a hit for a little while on a couple of wells while they retool and put together a better program to bring wells and fields to the next level of viability. It's up to the court, on a case-by-case basis, to sort the 'good guys' from the 'rats', and to determine whether the operator is acting with good intentions to bring their well or lease back to viability, or merely establishing a ruse to hold onto a lease (usually because of a situationin which the lease rights are more valuable than the well(s)).

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Permalink Reply by Dion Warr, CPL on December 8, 2008 at 3:33

Yes, however, having the ability to call upon a workover rig and have them on the pad in ninety days somtimes becomes a problem.

Sometimes the source of the problem is one of cash flow. One could stand to lose a few thousand per month on a limited basis rather than incurred many more thousands worth of operations that have to be paid at the time that services is rendered, lest incurring the dreaded M&M lien on your wellbore, due and payable plus legal interest. Granted, these would be unusual circumstances, but I have had to work with clients in some 'unusual circumstances' in the past.

Naturally, as a landman, I would always recommend that the client protect their lease(s) by obtaining ratifications and/or extensions whenever one comes into these sorts of unusual circumstances. And it would be great if all that were in the O&G business simply had the resources available at all times to operate timely and efficiently. Unfortunately, not all can, or do, and I would believe the number of incidences where these sorts of situations come up will increase in the near term due to decreasing revenues from the fall in oil and natural gas prices.

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